EPA-453/R-94-022
Alternative Control
Techniques Document—
NOX Emissions from
Industrial/Commercial/Institutional
(ICI) Boilers
Emission Standards Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1994
U.S. Envirorr:" -'.! Protection Agency
Region 5, Li:-..: ,, M2J)
77 West Jackic.i SuLiavard, 12th Floor
Chicago, IL 60604-3590
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ALTERNATIVE CONTROL TECHNIQUES DOCUMENT
This report is issued by the Emission Standards Division, Office of Air Quality Planning
and Standards, U.S. Environmental Protection Agency, to provide information to State and local
air pollution control agencies. Mention of trade names and commercial products is not intended
to constitute endorsement or recommendation for use. Copies of this report are available—as
supplies permit—from the Library Services Office (MD-35), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina 27711 ([919] 541-2777) or, for a nominal fee,
from the National Technical Information Services, 5285 Port Royal Road, Springfield, Virginia
22161 ([800] 553-NTIS).
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TABLE OF CONTENTS
Page
INTRODUCTION 1-1
SUMMARY 2-1
2.1 ICI BOILER EQUIPMENT 2-2
2.2 NOX FORMATION AND BASELINE EMISSIONS 2-5
2.3 CONTROL TECHNIQUES AND CONTROLLED NOX
EMISSION LEVELS 2-8
2.3.1 Combustion Modification Controls 2-11
2.3.2 Flue Gas Treatment Controls 2-15
2.4 COST AND COST EFFECTIVENESS OF NOX CONTROL
TECHNIQUES 2-15
2.5 ENERGY AND ENVIRONMENTAL IMPACTS OF NOX
CONTROL TECHNIQUES 2-19
ICI BOILER EQUIPMENT PROFILE 3-1
3.1 BOILER HEAT TRANSFER CONFIGURATIONS 3-3
3.2 COAL-FIRED BOILER EQUIPMENT TYPES 3-7
3.2.1 Coal-fired Watertube Boilers 3-9
3.2.2 Coal-fired Firetube Boilers 3-19
3.2.3 Cast Iron Boilers 3-25
3.3 OIL- AND NATURAL-GAS-FIRED ICI BOILER
EQUIPMENT TYPES 3-25
3.3.1 Oil- and Natural-gas-fired Watertube Boilers 3-26
3.3.2 Oil- and Natural-gas-fired Firetube Boilers 3-27
3.3.3 Oil- and Natural-gas-fired Cast Iron Boilers 3-29'
3.3.4 Other Oil- and Natural-gas-fired Boilers 3-29
3.3.5 Oil Burning Equipment 3-32
3.4 NONFOSSDL-FUEL-FIRED ICI BOILER EQUIPMENT TYPES 3-34
3.4.1 Wood-fired Boilers 3-34
3.4.2 Bagasse-fired Boilers 3-36
3.4.3 Municipal Solid Waste (MSW)-fired Boilers 3-38
3.4.4 Industrial Solid Waste (ISW)-fired Boilers 3-40
3.4.5 Refuse-derived Fuel (RDF)-fired Boilers 3-40
3.5 REFERENCES FOR CHAPTER 3 3-43
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TABLE OF CONTENTS (continued)
Page
BASELINE EMISSION PROFILES 4-1
4.1 FACTORS AFFECTING NOX EMISSIONS FROM ICI
BOILERS 4-2
4.1.1 Boiler Design Type 4-2
4.1.2 Fuel Characteristics 4-3
4.1.3 Boiler Heat Release Rate 4-10
4.1.4 Boiler Operational Factors 4-13
4.2 COMPILED BASELINE EMISSIONS DATA - ICI BOILERS 4-15
4.2.1 Coal-fired Boilers 4-15
4.2.2 Oil-fired Boilers 4-18
4.2.3 Natural-gas-fired Boilers 4-18
4.2.4 Nonfossil-fuel-fired Boilers 4-20
4.2.5 Other ICI Boilers 4-22
4.3 SUMMARY 4-22
4.4 REFERENCES FOR CHAPTER 4 4-25
NOX CONTROL TECHNOLOGY EVALUATION 5-1
5.1 PRINCIPLES OF NOX FORMATION AND COMBUSTION
MODIFICATION NOX CONTROL 5-2
5.2 COMBUSTION MODIFICATION NOX CONTROLS FOR
COAL-FIRED ICI BOILERS 5-9
5.2.1 Combustion Modification NOX Controls for Pulverized Coal
(PC)-fired ICI Boilers 5-10
5.2.2 Combustion Modification NOX Controls for Stoker Coal-
fired ICI Boilers 5-23
5.2.3 Combustion Modification NOX Controls for Coal-fired
Fluidized-bed Combustion (FBC) ICI Boilers 5-30
5.3 COMBUSTION MODIFICATION NOX CONTROLS FOR OIL-
AND NATURAL-GAS-FIRED ICI BOILERS 5-39
5.3.1 Water Injection/Steam Injection (WI/SI) 5-43
5.3.2 Low-NOx Burners (LNBs) in Natural-gas- and Oil-fired ICI
Boilers 5-43'
5.3.3 Flue Gas Recirculation (FGR) in Natural-gas- and Oil-fired
ICI Boilers 5-54
5.3.4 Fuel Induced Recirculation (FIR) 5-56
5.3.5 Staged Combustion Air (SCA) in Natural-gas- and Oil-fired
ICI Boilers 5-56
5.3.6 Combined Combustion Modification NOX Controls for
Natural-gas- and Oil-fired ICI Boilers 5-60
5.3.7 Fuel Switching 5-61
5.3.8 Combustion Modification NOX Controls for Thermally
Enhanced Oil Recovery (TEOR) Steam Generators 5-63
5.3.9 Gas Fuel Flow Modifiers 5-69
VI
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TABLE OF CONTENTS (continued)
Page
5.4 COMBUSTION MODIFICATIONS FOR NONFOSSIL-FUEL-
FIRED ICI BOILERS 5-70
5.5 FLUE GAS TREATMENT NOX CONTROLS FOR ICI
BOILERS 5-71
5.5.1 Selective Noncatalytic Reduction (SNCR) 5-71
5.5.2 Selective Catalytic Reduction (SCR) 5-75
5.6 SUMMARY OF NOX REDUCTION PERFORMANCE 5-78
5.7 REFERENCES FOR CHAPTER 5 5-82
COSTS OF RETROFIT NOX CONTROLS 6-1
6.1 COSTING METHODOLOGY 6-1
6.1.1 Capital Costs of Retrofit NOX Controls 6-2
6.1.2 Annual Operations and Maintenance (O&M) Costs 6-5
6.1.3 Total Annualized Cost and Cost Effectiveness 6-5
6.2 NOX CONTROL COST CASES AND SCALING
METHODOLOGY 6-9
6.3 CAPITAL AND TOTAL ANNUAL COSTS OF NOX
CONTROLS 6-11
6.4 COST EFFECTIVENESS OF NOX CONTROLS 6-15
6.4.1 NOX Control Cost Effectiveness: Coal-fired ICI Boilers 6-15
6.4.2 NOX Control Cost Effectiveness: Natural-gas-fired ICI Boilers ... 6-18
6.4.3 NOX Control Cost Effectiveness: Fuel-oil-fired ICI Boilers 6-25
6.4.4 NOX Control Cost Effectiveness: Nonfossil-fuel-fired ICI Boilers . 6-25
6.4.5 NOX Control Cost Effectiveness: Oil-fired Thermally
Enhanced Oil Recovery (TEOR) Steam Generators 6-30
6.4.6 Cost Effect of Continuous Emissions Monitoring (CEM) System . 6-31
6.5 REFERENCES FOR CHAPTER 6 6-32
ENVIRONMENTAL AND ENERGY IMPACTS 7-1
7.1 AIR POLLUTION 7-1
7.1.1 NOX Reductions 7-1
7.1.2 CO Emissions 7-4
7.1.3 Other Air Pollution Emissions 7-8
7.2 SOLID WASTE DISPOSAL 7-12
7.3 WATER USAGE AND WASTEWATER DISPOSAL 7-13
7.4 ENERGY CONSUMPTION 7-13
7.4.1 Oxygen Trim (OT) 7-14
7.4.2 Water Injection/Steam Injection (WI/SI) 7-16
7.4.3 Staged Combustion Air (SCA) 7-16
7.4.4 Low-NOx Burners (LNBs) 7-16
7.4.5 Flue Gas Recirculation (FGR) 7-18
VII
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TABLE OF CONTENTS (continued)
Page
7.4.6 Selective Noncatalytic Reduction
(SNCR) 7-18
7.4.7 Selective Catalytic Reduction (SCR) 7-19
7.5 REFERENCES FOR CHAPTER 7 7-22
APPENDIX A — ICI BOILER BASELINE EMISSION DATA A-l
APPENDIX B - CONTROLLED NOX EMISSION DATA B-l
APPENDIX C — LOW-NOX INSTALLATION LISTS, COEN COMPANY
AND TAMPELLA POWER CORP C-l
APPENDIX D - SCALED COST EFFECTIVENESS VALUES D-l
APPENDIX E — ANNUAL COSTS OF RETROFIT NOX CONTROLS:
NATURAL-GAS-FIRED ICI BOILERS E-l
APPENDIX F -ANNUAL COSTS OF RETROFIT NOX CONTROLS:
COAL-FniED ICI BOILERS F-l
APPENDIX G -ANNUAL COSTS OF RETROFIT NOX CONTROLS:
NONFOSSIL-FUEL-FIRED ICI BOILERS G-l
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LIST OF FIGURES
Page
Figure 2-1 Cost effectiveness versus boiler capacity, PC wall-fired boilers 2-20
Figure 2-2 Cost effectiveness versus boiler capacity, natural-gas-fired packaged
watertube boilers 2-20
Figure 2-3 Cost effectiveness versus boiler capacity, distillate-oil-fired boiler 2-21
Figure 2-4 Cost effectiveness versus boiler capacity, residual-oil-fired boilers 2-21
Figure 3-1 Occurrence of fuel types and heat transfer configurations by
capacity 3-4
Figure 3-2 Occurrence of ICI boiler equipment types by capacity 3-5
Figure 3-3 Simplified diagram of a watertube boiler 3-6
Figure 3-4 Watertube boiler 3-6
Figure 3-5 Simplified diagram of a firetube boiler 3-8
Figure 3-6 Firetube boiler 3-8
Figure 3-7 Single-retort horizontal-feed underfeed stoker 3-11
Figure 3-8 Multiple-retort gravity-feed underfeed stoker 3-11
Figure 3-9 Overfeed chain-grate stoker 3-12
Figure 3-10 Spreader stoker 3-12
Figure 3-11 Wall firing 3-15
Figure 3-12 Tangential firing 3-15
Figure 3-13 Bubbling FBC schematic 3-18
Figure 3-14 Circulating FBC schematic 3-18
Figure 3-15 Two-pass HRT boiler 3-21
Figure 3-16 Four-pass gas-/oil-fired scotch boiler 3-22
Figure 3-17 Exposed-tube vertical boiler 3-23
ix
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LIST OF FIGURES (continued)
Page
Figure 3-18 Submerged-tube vertical boiler 3-24
Figure 3-19 Watertube design configurations 3-27
Figure 3-20 D-type packaged boiler and watertubes 3-28
Figure 3-21 Vertical tubeless boiler 3-30
Figure 3-22 TEOR steam generator 3-31
Figure 3-23 Effect of temperature on fuel oil viscosity 3-33
Figure 3-24 Ward fuel cell furnace 3-37
Figure 3-25 Large MSW-fired boiler 3-39
Figure 3-26 Modular MSW-fired boiler •. .'. 3-41
Figure 4-1 Conversion of fuel nitrogen : 4-4
Figure 4-2 Fuel oil nitrogen versus sulfur for residual oil 4-6
Figure 4-3 Effect of fuel nitrogen content on total NOX emissions 4-7
Figure 4-4 Fuel NOX formation as a function of coal oxygen/nitrogen ratio
and coal nitrogen content 4-9
Figure 4-5 Effect of burner heat release rate on NOX emissions for coal and
natural gas tueis 4-11
Figure 4-6 Furnace heat release rate versus boiler size 4-12
Figure 4-7 Effect of excess oxygen and preheat on NOX emissions, natural-gas-
fired boilers 4-14
Figure 5-1 Effect of excess O2 on NOX emissions for firetube boilers at baseline
operating conditions, natural gas and oil fuels 5-7
Figure 5-2 Changes in CO and NOX emissions with reduced excess oxygen for
a residual-oil-fired watertube industrial boiler 5-8
Figure 5-3 Effect of BOOS on emissions 5-14
Figure 5-4 Foster Wheeler CF/SF LNB 5-16
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LIST OF FIGURES (continued)
Page
Figure 5-5 Performance of CF/SF LNB 5-16
Figure 5-6 Riley low-NOx CCV burner with secondary air diverter 5-18
Figure 5-7 Riley low-NOx TSV burner with advanced air staging for turbo-
furnace, down-fired and arch-fired installation 5-19
Figure 5-8 Schematic diagram of stoker with FOR 5-27
Figure 5-9 FOR effects on excess O2 5-28
Figure 5-10 NO emission versus excess O2, stoker boiler with FOR 5-28
Figure 5-11 Overfeed stoker with short active combustion zone 5-29
Figure 5-12 Effect of SCA on NOX and CO emissions, Chalmers University 5-33
Figure 5-13 NOX and CO versus bed temperature, pilot-scale BFBC 5-35
Figure 5-14 Effect of bed temperature on NOX and CO, Chalmers University 5-36
Figure 5-15 As the rate of water injection increases, NOX decreases 5-44
Figure 5-16 Staged air LNB 5-46
Figure 5-17 Staged fuel LNB 5-48
Figure 5-18 Low-NOx ASR burner 5-50
Figure 5-19 AFS air- and fuel-staged burner 5-50
Figure 5-20 Riley Stoker STS burner 5-51
Figure 5-21 Pyrocore LNB schematic 5-53
Figure 5-22 FGR system for gas- or oil-fired boiler 5-57
Figure 5-23 Effects of cofiring on NOX emissions 5-62
Figure 5-24 North American LNB on oil field steam generator 5-66
Figure 5-25 Process Combustion Corporation toroidal combustor 5-67
Figure 5-26 The MHI PM burner nozzle 5-68
xi
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LIST OF FIGURES (continued)
Page
Figure 6-1 Elements of total capital investment cost 6-3
Figure 6-2 Elements of total annual O&M cost 6-6
Figure 6-3 Total capital cost reported by Exxon for SNCR-ammonia on a variety of
industrial boilers 6-14
Figure 6-4 Cost effectiveness versus boiler capacity, PC wall-fired boilers 6-17
Figure 6-5 Cost effectiveness versus boiler capacity, natural-gas-fired packaged
watertube boilers 6-21
Figure 6-6 Cost effectiveness versus boiler capacity, natural-gas-fired packaged
watertube boilers using SCR controls 6-23
Figure 6-7 Cost effectiveness versus boiler capacity, distillate-oil-fired boilers 6-28
Figure 6-8 Cost effectiveness versus boiler capacity, residual-oil-fired boilers 6-29
Figure 7-1 Changes in CO and NOX emissions with reduced excess oxygen for
a residual-oil-fired watertube industrial boiler 7-8
Figure 7-2 Pilot-scale test results, conversion of NOX to N,O (NO; = 300
ppm, N/NO = 2.0) ." 7-11
Figure 7-3 Curve showing percent efficiency improvement per every 1 percent
reduction in excess air. Valid for estimating efficiency
improvements on typical natural gas, No. 2 through No. 6 oils,
and coal fuels 7-15
Figure 7-4 Unburned carbon monoxide loss as a function of excess O2 and
carbon monoxide emissions for natural gas fuel 7-17
Figure 7-5 Energy penalty associated with the use of WI or SI for NOX control
in ICI boilers 7-17
Figure 7-6 Estimated energy consumption in FGR use 7-19
Figure 7-7 Estimated increase in energy consumption with SCR pressure drop 7-20
Figure 7-8 Curve showing percent efficiency improvement per every 10 °F
drop in stack temperature. Valid for estimating efficiency
improvements on typical natural gas, No. 2 through No. 6 oils,
and coal fuels 7-21
Xll
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LIST OF TABLES
Page
TABLE 2-1 ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS 2-3
TABLE 2-2 SUMMARY OF BASELINE NOX EMISSIONS 2-7
TABLE 2-3 EXPERIENCE WITH NOX CONTROL TECHNIQUES ON
ICI BOILERS 2-9
TABLE 2-4 SUMMARY OF COMBUSTION MODIFICATION NOX
CONTROL PERFORMANCE ON ICI WATERTUBE
BOILERS 2-12
TABLE 2-5 SUMMARY OF COMBUSTION MODIFICATION NOX
CONTROL PERFORMANCE ON ICI FIRETUBE
BOILERS 2-14
TABLE 2-6 SUMMARY OF FLUE GAS TREATMENT NOX CONTROL
PERFORMANCE ON ICI BOILERS 2-16
TABLE 2-7 ESTIMATED COST AND COST EFFECTIVENESS OF NOX
CONTROLS (1992 DOLLARS) 2-18
TABLE 2-8 EFFECTS OF NOX CONTROLS ON CO EMISSIONS
FROM ICI BOILERS 2-22
TABLE 3-1 ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS 3-2
TABLE 4-1 TYPICAL RANGES IN NITROGEN AND SULFUR
CONTENTS OF FUEL OILS 4-6
TABLE 4-2 COMPARISON OF COMPILED UNCONTROLLED
EMISSIONS DATA WITH AP-42 EMISSION FACTORS,
COAL-FIRED BOILERS 4-16
TABLE 4-3 COMPARISON OF COMPILED UNCONTROLLED
EMISSIONS DATA WITH AP-42 EMISSION FACTORS,
OIL-FIRED BOILERS 4-19
TABLE 4-4 COMPARISON OF COMPILED UNCONTROLLED
EMISSIONS DATA WITH AP-42 EMISSION FACTORS,
NATURAL-GAS-FIRED BOILERS 4-20
TABLE 4-5 AP-42 UNCONTROLLED EMISSION FACTORS FOR
NONFOSSIL-FUEL-FIRED BOILERS 4-21
Xlll
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LIST OF TABLES (continued)
Page
TABLE 4-6 AVERAGE NOX EMISSIONS FROM MUNICIPAL WASTE
COMBUSTORS 4-22
TABLE 4-7 SUMMARY OF BASELINE NOX EMISSIONS 4-23
TABLE 5-1 SUMMARY OF COMBUSTION MODIFICATION NOX
CONTROL APPROACHES 5-4
TABLE 5-2 EXPERIENCE WITH NOX CONTROL TECHNIQUES ON
ICI BOILERS 5-5
TABLE 5-3 COMBUSTION MODIFICATION NOX CONTROLS FOR
FULL-SCALE PC-FIRED INDUSTRIAL BOILERS 5-11
TABLE 5-4 COMBUSTION MODIFICATION NOX CONTROLS FOR
STOKER COAL-FIRED INDUSTRIAL BOILERS 5-24
TABLE 5-5 NOX CONTROL TECHNIQUES FOR FBC BOILERS 5-32
TABLE 5-6 REPORTED CONTROLLED NOX EMISSION LEVELS,
FULL-SCALE, COAL-FIRED FBC BOILERS 5-35
TABLE 5-7 COMBUSTION MODIFICATION NOX CONTROLS FOR
FULL-SCALE NATURAL-GAS-FIRED INDUSTRIAL
BOILERS 5-41
TABLE 5-8 COMBUSTION MODIFICATION NOX CONTROLS FOR
OIL-FIRED INDUSTRIAL BOILERS 5-42
TABLE 5-9 REPORTED NOX LEVELS AND REDUCTION
EFFICIENCIES IN ICI BOILERS WITH LNBs 5-45
TABLE 5-10 EFFECTS OF SWITCHING FROM RESIDUAL OIL TO
DISTILLATE FUEL ON INDUSTRIAL BOILERS 5-63
TABLE 5-11 ESTIMATES OF NOX REDUCTIONS WITH FUEL
SWITCHING 5-64
TABLE 5-12 SNCR NOX CONTROL FOR ICI BOILERS 5-73
TABLE 5-13 SELECTED SCR INSTALLATIONS, CALIFORNIA ICI BOILERS . . 5-77
TABLE 5-14 SCR NOX CONTROLS FOR ICI BOILERS 5-77
xiv
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LIST OF TABLES (continued)
Page
TABLE 5-15 SUMMARY OF NOX REDUCTION PERFORMANCE 5-79
TABLE 6-1 ASSUMPTIONS FOR ESTIMATING CAPITAL AND
ANNUAL O&M COSTS 6-7
TABLE 6-2 BASELINE (UNCONTROLLED) NOX EMISSIONS USED
FOR COST CASES 6-9
TABLE 6-3 NOX REDUCTION EFFICIENCIES USED FOR COST CASES 6-10
TABLE 6-4 NOX CONTROL COST EFFECTIVENESS CASES 6-11
TABLE 6-5 CAPITAL AND TOTAL ANNUAL COSTS OF RETROFIT NOX
CONTROLS FOR ICI BOILERS, 1992 DOLLARS 6-12
TABLE 6-6 SUMMARY OF NOX CONTROL COST EFFECTIVENESS,
COAL-FIRED ICI BOILERS 6-16
TABLE 6-7 SUMMARY OF NOX CONTROL COST EFFECTIVENESS,
NATURAL-GAS-FIRED ICI BOILERS 6-18
TABLE 6-8 SUMMARY OF NOX CONTROL COST EFFECTIVENESS,
DISTILLATE-OIL-FIRED ICI BOILERS 6-26
TABLE 6-9 SUMMARY OF NOX CONTROL COST EFFECTIVENESS,
RESIDUAL-OIL-FIRED ICI BOILERS 6-27
TABLE 6-10 SUMMARY OF NOX CONTROL COST EFFECTIVENESS,
NONFOSSIL-FUEL-FIRED ICI BOILERS 6-30
TABLE 6-11 NOX CONTROL COST EFFECTIVENESS WITHOUT/WITH
CEM SYSTEM, NATURAL-GAS-FIRED ICI BOILERS8 6-31
TABLE 7-1 EXPERIENCE WITH NOX CONTROL TECHNIQUES ON
ICI BOILERS 7-2
TABLE 7-2 NOX EMISSIONS REDUCTION FROM MODEL BOILERS 7-3
TABLE 7-3 CO EMISSION CHANGES WITH NOX CONTROL
RETROFIT - COAL-FIRED BOILERS 7-5
:O EMISSION CHANGES WITH NOX CONTROL
RETROFIT - GAS-FIRED BOILERS 7-6
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LIST OF TABLES (continued)
Page
TABLE 7-5 CO EMISSION CHANGES WITH NOX CONTROL
RETROFIT - OIL-FIRED BOILERS 7-7
TABLE 7-6 AMMONIA EMISSIONS WITH UREA-BASED SNCR
RETROFIT 7-10
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1. INTRODUCTION
Congress, in the Clean Air Act Amendments (CAAA) of 1990, amended Title I of the
Clean Air Act (CAA) to address ozone nonattainment areas. A new Subpart 2 was added to
Part D of Section 103. Section 183(c) of the new Subpart 2 provides that:
[WJithin 3 years after the date of the enactment of the CAAA, the
Administrator shall issue technical documents which identify alternative controls
for all categories of stationary sources of... oxides of nitrogen which emit or
have the potential to emit 25 tons per year or more of such air pollutant.
These documents are to be subsequently revised and updated as determined by the
Administrator.
Industrial, commercial, and institutional (ICI) boilers have been identified as a category
that emits more than 25 tons of oxides of nitrogen (NOX) per year. This alternative control
techniques (ACT) document provides technical information for use by State and local agencies
to develop and implement regulatory programs to control NOX emissions from ICI boilers.
Additional ACT documents are being developed for other stationary source categories.
ICI boilers include steam and hot water generators with heat input capacities from 0.4 to
1,500 MMBtu/hr (0.11 to 440 MWt). These boilers are used in a variety of applications, ranging
from commercial space heating to process steam generation, in all major industrial sectors.
Although coal, oil, and natural gas are the primary fuels, many ICI boilers also burn a variety
of industrial, municipal, and agricultural waste fuels.
It must be recognized that the alternative control techniques and the corresponding
achievable NOX emission levels presented in this document may not be applicable to every ICI
boiler application. The furnace design, method of fuel firing, condition of existing equipment,
operating duty cycle, site conditions, and other site-specific factors must be taken into
consideration to properly evaluate the applicability and performance of any given control
technique. Therefore, the feasibility of a retrofit should be determined on a case-by-case basis.
The information in this ACT document was generated through a literature search and
from information provided by ICI boiler manufacturers, control equipment vendors, ICI boiler
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users, and regulatory agencies. Chapter 2 summarizes the findings of this study. Chapter 3
presents information on the ICI boiler types, fuels, operation, and industry applications.
Chapter 4 discusses NOX formation and uncontrolled NOX emission factors. Chapter 5 covers
alternative control techniques and achievable controlled emission levels. Chapter 6 presents the
cost and cost effectiveness of each control technique. Chapter 7 describes environmental and
energy impacts associated with implementing the NOX control techniques. Finally, Appendices A
through G provide the detailed data used in this study to evaluate uncontrolled and controlled
emissions and the costs of controls for several retrofit scenarios.
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2. SUMMARY
This chapter summarizes the information presented in more detail in Chapters 3
through 7 of this document. Section 2.1 reviews the diversity of equipment and fuels that make
up the ICI boiler population. The purposes of this section are to identify the major categories
of boiler types, and to alert the reader to the important differences that separate the ICI boiler
population from other boiler designs and operating practices. This diversity of combustion
equipment, fuels, and operating practices impacts uncontrolled NOX emission levels from ICI
boilers and the feasibility of control for many units. Section 2.2 reviews baseline NOX emission
reported for many categories of ICI boilers and highlights the often broad ranges in NOX levels
associated with boiler designs, firing methods, and fuels.
The experience in NOX control retrofits is summarized in Section 2.3. This information
was derived from a critical review of the open literature coupled with information from selected
equipment vendors and users of NOX control technologies. The section is divided into a
subsection on combustion controls and another on flue gas treatment controls. As in the utility
boiler experience, retrofit combustion controls for ICI boilers have targeted principally the
replacement of the original burner with a low-NOx design. When cleaner fuels are burned, the
low-NOx burner (LNB) often includes a flue gas recirculation (FGR) system that reduces the
peak flame temperature producing NOX. Where NOX regulations are especially stringent, the
operating experience with natural gas burning ICI boilers also includes more advanced
combustion controls and techniques that can result in high fuel penalties, such as water injection
(WI). As in the case of utility boilers, some boiler designs have shown little adaptability to
combustion controls to reduce NOX. For these units, NOX reductions are often achievable only
with flue gas treatment technologies for which experience varies.
Section 2.4 summarizes the cost of installing NOX controls and operating at lower NOX
levels. The data presented in this document are drawn from the reported experience of
technology users coupled with costs reported by selected technology vendors. This information
is offered only as a guideline because control costs are always greatly influenced by numerous
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site factors that cannot be taken fully into account. Finally, Section 2.5 summarizes the energy
and environmental impacts of low-NOx operation. Combustion controls are often limited in
effectiveness by the onset of other emissions and energy penalties. This section reviews the
emissions of CO, NH3, N2O, soot and paniculate.
2.1 ICI BOILER EQUIPMENT
The family of ICI boilers includes equipment type with heat input capacities in the range
of 0.4 to 1,500 MMBtu/hr (0.11 to 440 MWt). Industrial boilers generally have heat input
capacities ranging from 10 to 250 MMBtu/hr (2.9 to 73 MWt). This range encompasses most
boilers currently in use in the industrial, commercial, and institutional sectors. The leading user
industries of industrial boilers, ranked by aggregate steaming capacity, are the paper products,
chemical, food, and the petroleum industries. Those industrial boilers with heat input greater
than 250 MMBtu/hr (73 MWt) are generally similar to utility boilers. Therefore, many NOX
controls applicable to utility boilers are also candidate control for large industrial units. Boilers
with heat input capacities less than 10 MMBtu/hr (2.9 MWt) are generally classified as
commercial/institutional units. These boilers are used in a wide array of applications, such as
wholesale and retail trade, office buildings, hotels, restaurants, hospitals, schools, museums,
government buildings, airports, primarily providing steam and hot water for space heating.
Boilers used in this sector generally range in size from 0.4 to 12.5 MMBtu (0.11 to 3.7 MWt)
heat input capacity, although some are appreciably larger.
Table 2-1 lists the various equipment and fuel combinations, the range in heat input
capacity, and the typical applications. Passed boiler inventory studies were used to estimate the
relative number and total firing capacity of each boiler-fuel category. Many of these boilers vary
greatly in age and use patterns. Older units have outdated furnace configurations with greater
refractory area and lower heat release rates. Newer designs focus on compact furnaces with
tangent tube configurations for greater heat transfer and higher heat release rates. Newer
furnaces also tend to have fewer burners, because of improvements in combustion control and
better turndown capability, and better economics. This diversity of equipment requires a careful
evaluation of applicable technologies. Many smaller ICI boilers often operate with little
supervision, and are fully automated. Application of NOX controls that would limit this
operational flexibility may prove impractical. They can be found fully enclosed inside commercial
and institutional buildings and in industry steam plants or completely outdoors in several
industrial applications at refineries and chemical plants. The location of these boilers often
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TABLE 2-1. ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS
Heat transfer
configuration
Watertube
Firetube
Cast iron
Tubeless
Design and fuel
type
Pulverized coal
Stoker coal
FBC«coal
Gas/oil
Oil field steamer
Stoker nonfossil
FBC nonfossil
Other nonfossil
HRT coal
Scotch coal
Vertical coal
Firebox coal
HRT gas/oil
Scotch gas/oil
Vertical gas/oil
Firebox gas/oil
HRT nonfossil
Firebox nonfossil
Coal
Gas/oil
Gas/oil
Capacity
range,
MMBtu/hr*
100-1,500+
0.4-550 +f
1.4-1,075
0.4-1,500+
20-62.5
1.5-l,000f
40-345
3-800
0.5-50
0.4-50
<2.5
0.4-15
0.5-50
0.4-50
<2.5
<20
2-50
2-20
< 0.4- 14
< 0.4-14
< 0.4-4
% of ICI
boiler
unitsb'c
a»e
**
**
2.3
NA.h
*»
»*
**
**
**
**
»*
1.5
4.8
1.0
6.5
NA.
NA.
9.9
72
NA.
% of ICI
boiler
capacityb'c
2.5
5.0
**
23.6
NA.
1.1
**
**
**
**
**
**
1.5
4.6
**
48
NA.
NA.
1.3
9.6
NA.
Application*1
PH, CG
SH, PH, CG
PH, CG
SH, PG, CG
PH
SH, PH, CG
PH, CG
SH, PH, CG
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
*To convert to MWt, multiply by 0.293.
blncludes all units used in the ICI sector, regardless of capacity.
C1991 FBC data; other data are from 1977-1978.
dSH = Space heat; PH = Process heat; CG = Cogeneration.
*** indicates less than 1 percent.
fDesign capacities can be higher.
gFBC = fluidized bed combustion.
hNA. = Not available. No data are available.
2-3
-------
influences the feasibility of retrofit for some control technologies because poor access and limited
available space.
ICI boiler equipment is principally distinguished by the method of heat transfer of heat
to the water. The most common ICI boiler types are the watertube and firetube units. Firetube
boilers are generally limited in size to about 50 MMBtu/hr (15 MWt) and steam pressures,
although newer designs tend to increase the firing capacity. All of these firetubes are
prefabricated in the shop, shipped by rail or truck, and are thus referred to as packaged.
Watertube boilers tend to be larger in size than firetube units, although many packaged single
burner designs are well within the firetube capacity range. Larger, multi-burner watertubes tend
to be field erected, especially older units. Newer watertubes also tend to be single burners and
packaged. Steam pressures and temperatures for watertubes are generally higher than firetube
units. Combustion air preheat is never used for firetube boiler configuration. Higher capacity
watertube ICI boilers often use combustion air preheat. This is an important distinction because
air preheat units tend to have higher NO_ levels.
As the type and sizes of ICI boilers are extremely varied, so are the fuel types and
methods of firing. The most commonly used fuels include natural gas, distillate and residual fuel
oils, and coal in both crushed and pulverized form. Natural gas and fuel oil are burned in single
or multiple burner arrangements. Many ICI boilers have dual fuel capability. In smaller units,
the natural gas is normally fed through a ring with holes or nozzles that inject fuel in the air
stream. Fuel oil is atomized with steam or compressed air and fed via a nozzle in the center of
each burner. Heavy fuel oils must be preheated to decrease viscosity and improve atomization.
Crushed coal is burned in stoker and fluidized bed (FBC) boilers. Stoker coal is burned mostly
on a grate (moving or vibrating) and is fed by various means. Most popular are the spreader
and overfeed methods. Crushed coal in FBC boilers burns in suspension in either a stationary
bubbling bed of fuel and bed material or in a circulating fashion. The bed material is often a
mixture of sand and limestone for capturing SO2. Higher fluidizing velocities are necessary for
circulating beds which have become more popular because of higher combustion and SO2 sorbent
efficiencies. Where environmental emissions are strictly controlled and low grade fuels are
economically attractive, FBC boilers have become particularly popular because of
characteristically low NOX and SO2 emissions.
Although the primary fuel types are fossil based, there is a growing percentage of
nonfossil fuels being burned for industrial steam and nonutility power generation. These fuels
2-4
-------
include municipal and agricultural wastes, coal mining wastes, and petroleum coke and special
wastes such as shredded tires, refuse derived fuel (RDF), tree bark and saw dust, and black
liquor from the production of paper. Solid waste fuels are typically burned in stoker or FBC
boilers which provide for mass feed of bulk material with minimal pretreatment and the handling
of large quantities of ash and other inorganic matter. Some industries also supplement their
primary fossil fuels with hazardous organic chemical waste with medium to high heating value.
Some of these wastes can contain large concentrations of organically bound nitrogen that can be
converted to NOX emissions. The practice of burning hazardous wastes in boilers and industrial
furnaces is currently regulated by the EPA under the Resource Conservation and Recovery Act
(RCRA).
22 NOX FORMATION AND BASELINE EMISSIONS
NOX is the high-temperature byproduct of the combustion of fuel and air. When fuel
is burned with air, nitric oxide (NO), the primary form of NOX, is formed mainly from the high
temperature reaction of atmospheric nitrogen and oxygen (thermal NOX) and from the reaction
of organically bound nitrogen in the fuel with oxygen (fuel NOX). A third and less important
source of NO formation is referred to as "prompt NO," which forms from the rapid reaction of
atmospheric nitrogen with hydrocarbon radical to form NOX precursors that are rapidly oxidized
to NO at lower temperatures. Prompt NO is generally minor compared to the overall quantity
of NO generated from combustion. However, as NOX emissions are reduced to extremely low
limits, i.e., with natural gas combustion, the contribution of prompt NO becomes more important.
The mechanisms of NOX formation in combustion are very complex and cannot be
predicted with certainty. Thermal NOX is an exponential function of temperature and varies with
the square root of oxygen concentration. Most of the NOX formed from combustion of natural
gas and high grade fuel oil (e.g., distillate oil or naphtha) is attributable to thermal NOX.
Because of the exponential dependence on temperature, the control of thermal NOX is best
achieved by reducing peak combustion temperature. Fuel NOX results from the oxidation of
fuel-bound nitrogen. Higher concentrations of fuel nitrogen typically lead to higher fuel NOX
and overall NOX levels. Therefore, combustion of residual oil with 0.5 percent fuel-bound
nitrogen, will likely result in higher NOX levels than natural gas or distillate oil. Similarly,
because coal has higher fuel nitrogen content higher baseline NOX levels are generally measured
from coal combustion than either natural gas or oil combustion. This occurs in spite of the fact
that the conversion of fuel nitrogen to fuel NOX typically diminishes with increasing nitrogen
2-5
-------
concentration. Some ICI boilers, however, that operate at lower combustion temperature, as in
the case of an FBC, or with reduced fuel air mixing, as in the case of a stoker, can have low NOX
emissions because of the suppression of the thermal NOX contribution.
Test data were compiled from several sources to arrive at reported ranges and average
NOX emission levels for ICI boilers. Baseline data were compiled from test results on more than
200 ICI boilers described in EPA documents and technical reports. These data, representative
of boiler operation at 70 percent capacity or higher, are detailed in Appendix A. Table 2-2
summarizes the range and average NOX emissions from the various categories of ICI boilers
investigated in this study. On an average basis, coal-fired ICI boilers emit the highest level of
NOX, as anticipated. Among the higher emitters are the wall-fired boilers with burners on one
or two opposing walls of the furnace. Average NOX levels were measured at approximately
0.70 Ib/MMBtu. Next highest emitters are tangential boilers burning pulverized coal (PC). The
burners on these units are located in the corners of the furnace at several levels and firing in a
concentric direction.
Among the stokers, the spreader firing system has the highest NOX levels than either
the overfeed or underfeed designs. This is because a portion of the coal fines burn in suspension
in the spreader design. This method of coal combustion provides for the greatest air-fuel mixing
and consequently higher NOX formation. FBC boilers emit significantly lower NOX emissions
than PC-fired units and are generally more efficient than stokers. The large variations in
baseline NOX levels for the FBC units are generally the result of variations in air distribution
among FBC units. Newer FBC designs incorporate a staged air addition that suppresses NOX
levels. Also the type of bed material and SO2 sorbc-nt influence the level of NOX generated.
FBC units are, on average, the lowest NOX emitters among coal burning ICI equipment.
Large variations in baseline NOX levels are also shown for ICI boilers burning residual
oil. For example, boilers with a capacity of less than 100 MMBtu/hr (29 MWt) can have.
emissions in the range of 0.20 to 0.79 Ib/MMBtu, a factor of nearly 4. This is attributable
predominantly to large variations in fuel nitrogen content of these fuel oils. NOX emissions from
distillate-oil- and natural-gas-fired ICI boilers are significantly lower due by and large to the
burning of cleaner fuel with little or no fuel-bound nitrogen. It is also important to note that
baseline emission levels for the larger boilers tend to be somewhat higher, on average. This is
attributable to the higher heat release rate that generally accompanies the larger units in order
to minimize the size of the furnace and the cost of the boiler. Also, another factor is the use
2-6
-------
TABLE 2-2. SUMMARY OF BASELINE NOX EMISSIONS
Fuel
Pulverized coal
Coal
Residual oil
Distillate oil
Crude oil
Natural gas
Wood
Bagasse
MSW
Boiler type
Wall-fired
Tangential
Cyclone
Spreader stoker
Overfeed stoker
Underfeed stoker
Bubbling FBC
Circulating FBC
Firetube
Watertube:
10 to 100 MMBtu/hr
> 100 MMBtu/hr
Firetube
Watertube:
10 to 100 MMBtu/hr
> 100 MMBtu/hr
TEOR steam generator
Firetube
Watertube:
< 100 MMBtu/hr
> 100 MMBtu/hr
TEOR steam generator
<70 MMBtu/hr
^70 MMBtu/hr
Mass burn
Modular
Uncontrolled
NOX range,
Ib/MMBtu
0.46-0.89
0.53-0.68
1.12a
0.35-0.77
0.19-0.44
0.31-0.48
0.11-0.81
0.14-0.60
0.21-0.39
0.20-0.79
0.31-0.60
0.11-0.25
0.08-0.16
0.18-0.23
0.30-0.52
0.07-0.13
0.06-0.31
0.11-0.45
0.09-0.13
0.010-0.050
0.17-0.30
0.15b
0.40b
0.49b
Average,
Ib/MMBtu
0.69
0.61
1.12
0.53
0.29
0.39
0.32
0.31
0.31
0.36
0.38
0.17
0.13
0.21
0.46
0.10
0.14
0.26
0.12
0.022
0.24
0.15
0.40
0.49
aSingle data point.
bAP-42 emission factor.
2-7
-------
of preheated combustion air with the larger boilers. Higher heat release rate and preheated
combustion air increase the peak temperature of the flame and contribute to higher baseline
NOX levels. The AP-42 emission factors were used for some of the ICI boilers for which little
or no data were available in this study.
23 CONTROL TECHNIQUES AND CONTROLLED NOX EMISSION LEVELS
The reduction of NOX emissions from ICI boilers can be accomplished with combustion
modification and flue gas treatment techniques or a combination of these. The application of
a specific technique will depend on the type of boiler, the characteristic of its primary fuel, and
method of firing. Some controls have seen limited application, whereas certain boilers have little
or no flexibility for modification of combustion conditions because of method of firing, size, or
operating practices. Table 2-3 lists the applicability of candidate NOX control techniques for ICI
boiler retrofit. Each "X" marks the applicability of that control to the specific boiler/fuel
combination. Although applicable, some techniques have seen limited use because of cost,
energy and operational impacts, and other factors.
NOX emissions can be controlled by suppressing both thermal and fuel NOX. When
natural gas or distillate oil is burned, thermal NOX is the only component that can be practically
controlled due to the low levels of fuel N2 in the distillate oil. The combustion modification
techniques that are most effective in reducing thermal NOX are particularly those that reduce
peak temperature of the flame. This is accomplished by quenching the combustion with water
or steam injection (WI/SI), recirculating a portion of the flue gas to the burner zone (FOR), and
reducing air preheat temperature (RAP) when preheated combustion air is used. The use of
WI/SI has thus far been limited to small gas-fired boiler applications in Southern California to
meet very stringent NOX standards. Although very effective in reducing thermal NOX, this
technique has not been widely applied because of its potential for large thermal efficiency
penalties, safety, and burner control problems. FOR, on the other hand, has a wide experience
base. The technique is implemented by itself or in combination with LNB retrofits. In fact,
many LNB designs for natural-gas-fired ICI boilers incorporate FGR. LNB controls are
available from several ICI equipment vendors. RAP is not a practicable technique because of
severe energy penalties associated with its use, and for this reason it was not considered further
in this document.
Thermal NOX can also be reduced to some extent by minimizing the amount of excess
oxygen, delaying the mixing of fuel and air, and reducing the firing capacity of the boiler. The
2-8
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first technique is often referred to as oxygen trim (OT) or low excess air (LEA) and can be
attained by optimizing the operation of the burner(s) for minimum excess air without excessive
increase in combustible emissions. The effect of lower oxygen concentration on NOX is partially
offset by some increase in thermal NOX because of higher peak temperature with lower gas
volume. OT and LEA are often impractical on packaged watertube and firetube boilers due to
increased flame lengths and CO, and can lead to rear wall flame impingement, especially when
fuel oil is fired. The second technique reduces flame temperature and oxygen availability by
staging the amount of combustion air that is introduced in the burner zone. Staged combustion
air (SCA) can be accomplished by several means. For multiple burner boiler, the most practical
approach is to take certain burners out of service (BOOS) or biasing the fuel flow to selected
burners to obtain a similar air staging effect. The third technique involves reducing the boiler
firing rate to lower the peak temperature in the furnace. This approach is not often considered
because it involves reducing steam generation capacity that must be replaced elsewhere. Also,
with some fuels, gains in reduction of thermal NOX are in part negated by increases in fuel NOX
that result by increases in excess air at reduced boiler load.
The reduction of fuel NOX with combustion modifications is most effectively achieved
with the staging of combustion air. By suppressing the amount of air below that required for
complete combustion (stoichiometric conditions), the conversion of fuel nitrogen to NOX can be
minimized. This SCA technique is particularly effective on high nitrogen fuels such as coal and
residual oil fired boilers, which may have high baseline emissions and would result in high
reduction efficiencies. For PC, BOOS for NOX reduction is not practical. Therefore, SCA is
usually accomplished with the retrofit of internally air staged burner or eve .fire air ports. The
installation of low-NOx burners for PC- and residual-oil-fired boilers is a particularly effective
technique because it involves minimal furnace modifications and retained firing capacity. Staged
fuel burners in some packaged watertube boilers without membrane convective side furnace
wall(s) may cause an increase in CO emissions at the stack, due to short circuiting of incomplete
combustion products to the convective section. The installation of OFA ports for some boilers
is not practicable. These boilers are principally firetube and watertube packaged designs and
most PC-fired units. Large field-erected gas- and low-sulfur oil-fired ICI boilers are the best
candidates for the application of OFA because these fuels are least susceptible to the adverse
effects of combustion staging, such as furnace corrosion and unburned fuel emissions.
2-10
-------
Another combustion modification technique involves the staging of fuel, rather than
combustion air. By injecting a portion of the total fuel input downstream of the main
combustion zone, hydrocarbon radicals created by the reburning fuel will reduce NOX emission
emitted by the primary fuel. This reburning technique is best accomplished when the reburning
fuel is natural gas. Natural gas reburning (NGR) and cofiring have been investigated primarily
for utility boilers, especially coal-fired units that are not good candidates for traditional
combustion modifications such as LNB. Examples of these boilers are cyclones and stoker fired
furnaces. Application of these techniques on ICI boilers has been limited to some municipal
solid waste (MSW) and coal-fired stokers.
NOX control experience for ICI boilers with flue gas treatment controls has been limited
to the selective noncatalytic and catalytic reduction techniques (SNCR and SCR). Both
techniques involve the injection of ammonia or urea in a temperature window of the boiler
where NOX reduction occurs by the selective reaction of NH2 radicals with NO to form water
and nitrogen. The reaction for the SNCR process must occur at elevated temperatures, typically
between 870 and 1,090°C (1,600 and 2,000°F) because the reduction proceeds without a catalyst.
At much lower flue gas temperatures, typically in the range of 300 to 400°C (550 to 750°F), the
reaction requires the presence of a catalyst. SNCR is particularly effective when the mixing of
injected reagent and flue gas is maximized and the residence time of the gas within the reaction
temperature is also maximized. These favorable conditions are often encountered in retrofit
applications of SNCR on FBC boilers. The reagent is injected at the outlet of the furnace (inlet
to the hot cyclone), where mixing is promoted while flue gas temperature remains relatively
constant. Other applications of SNCR on stoker boilers burning a variety of fuels and waste
fuels have also shown promise. SCR retrofit ICI applications in this country have been limited
to a few boilers in California, although the technology is widely used abroad and several vendors
are currently marketing several systems.
23.1 Combustion Modification Controls
Table 2-4 summarizes control efficiency and NOX levels achieved with the retrofit of
combustion modification techniques for watertube ICI boilers. The data base includes primarily
commercial facilities that were retrofit to meet regulated NOX limits. In addition, the data base
also includes result obtained from controls installed for research and development of specific
techniques. Details and references for this data base can be found in Appendices B and C of
this document.
2-11
-------
TABLE 2-4. SUMMARY OF COMBUSTION MODIFICATION NOX CONTROL
PERFORMANCE ON ICI WATERTUBE BOILERS
ICI boiler
and fuel
PC, wall-
fired
PC, T-fired
Spreader
stoker
Coal-fired
BFBC
Circulating
coal-fired
FBC
Residual-
oil-fired
Distillate-
oil-fired
Natural-
gas-fired
NOV control
SCA
LNB
NGR
LNB + SCA
SCA
LNB
NGR
LNB + SCA
SCA
FGR + SCA
RAP
Gas cofiring
SCA
SCA
SCA + FGR
LNB
FGR
SCA
LNB + FGR
LNB + SCA
LNB
FGR
SCA
LNB + FGR
LNB + SCA
SCA
LNB
FGR
LNB + FGR
LNB + SCA
Percent
NOX
reduction
15-39
49-67
NA.a
42-66
25
18
30
55
-1-35
0-60
32
20-25
40-67
NA.
NA.
30-60
4-30
5-40
NA.
NA.
NA.
20-68
30
NA.
NA.
17-46
39-71
53-74
55-84
NA.
Controlled
NOX level,
Ib/MMBtu
0.33-0.93
0.26-0.50
0.23-0.52
0.24-0.49
0.29-038
036
0.23
0.20
0.22-0.52
0.19-0.47
0.30
0.18-0.20
0.10-0.14
0.05-0.45
0.12-0.16
0.09-0.23
0.12-0.25
0.22-0.74
0.23
O.?n-0.40
0.06-033
0.04-0.15
0.09-0.12
0.03-0.13
0.20
0.06-0.24
0.03-0.17
0.02-0.10
0.02-0.09
0.10-0.20
Comments
Limited applicability because of potential side effects.
Technology transfer from utility applications.
Limited experience. Technology transfer from utility
applications.
Technology transfer from utility applications.
Effective technique. Technology transfer from utility
applications.
LNCFSb utility firing system design with closed coupled
OFA.
Limited experience.
LNCFS utility firing system design. Technology transfer
from utility applications.
Potential grate problems and high CO emissions.
Limited applicability.
Limited applicability.
Only recent exploratory tests. NOX reduction via lower
0,.
SCA often incorporated in new designs.
SCA often incorporated in new designs.
Limited application for FGR.
Staged air could result in operational problems.
Limited effectiveness because of fuel NOX contribution.
Techniques include BOOS0 and OFA. Efficiency function
of degree of staging.
Combinations are not additive in effectiveness.
Combinations are not additive in effectiveness.
Low-excess air burner designs.
Widely used technique because of effectiveness.
Limited applications except BOOSC, Bias and selected
OFA for large watertube.
Most common technique. Many LNB include FGR.
SCA also included in many LNB designs.
Technique includes BOOSC and OFA. Many LNB include
SCA technique.
Popular technique. Many designs and vendors available.
Popular technique together with LNB.
Most popular technique for clean fuels.
Some LNB designs include internal staging.
*NA. = Not available. No data are available to determine control efficiency. See Appendix B for detailed
individual test data.
bLNCFS = Low-NOx Concentric Firing System by ABB-Combustion Engineering.
CBOOS is not applicable to single-burner packaged boilers and some multibumer units.
2-12
-------
The most effective NOX control techniques for PC-fired ICI boilers are LNB, NGR, and
LNB + SCA. The average reduction achieved with the retrofit of LNB on seven ICI boilers was
55 percent with a controlled level of 0.35 Ib/MMBtu. A combination of LNB plus overfire air
(OFA) also achieved an average of 0.35 Ib/MMBtu on eight ICI boilers. Lower NOX emissions
were achieved for tangentially fired boilers. Evaluation of retrofit combustion controls for coal-
fired stokers revealed control efficiencies in the range of 0 to 60 percent. This wide range in
control efficiency is attributed to the degree of staging implemented and method of staging.
Typically, existing OFA ports on stokers are not ideal for effective NOX staging. Furthermore,
the long term effectiveness of these controls for stokers was not evaluated in these exploratory
tests. The average NOX reduction for eight stokers with enhanced air staging was 18 percent
with a corresponding controlled NOX level of 0.38 Ib/MMBtu. Largest NOX reductions were
accompanied by large increases in CO emissions. Gas cofiring in coal-fired stokers, only recently
explored, achieves NOX reductions in the 20 to 25 percent range only by being able to operate
at lower excess air.
Air staging in coal-fired FBC boilers is very effective in reducing NOX from these units.
FBCs are inherently low NOX emitters because low furnace combustion temperatures preclude
the formation of thermal NOX. Furthermore, the in-bed chemistry between coal particles, CO,
and bed materials (including SO2 sorbents) maintains fuel nitrogen conversion to NO at a
minimum. The control of NOX is further enhanced by operating these boilers with some air
staging. In fact, many new FBC designs, including circulating FBCs, come equipped with air
staging capability especially for low NOX emissions. Excessive substoichiometric conditions in
the dense portion of the fluidized bed can result in premature corros'on of immersed watertubes
used in bubbling bed design. Circulating FBC boilers are better suited for deep staging because
these units do not use in-bed watertubes.
NOX reductions and controlled levels for residual oil combustion are influenced by the
nitrogen content of the oil, the degree of staging implemented, and other fuel oil physical and
chemical characteristics. Because of these factors, NOX control performance on this fuel is likely
to vary, as shown in Table 2-4. Data on LNB for residual-oil-fired ICI boilers were obtained
primarily from foreign applications. The average controlled NOX level reported with LNB for
residual-oil-fired ICI boilers is 0.19 Ib/MMBtu based on 17 Japanese installations and one
domestic unit equipped with Babcock and Wilcox (B&W) XCL-FM burner for industrial boilers.
2-13
-------
The data base for distillate-oil- and natural-gas-fired boilers is much larger than that for
residual-oil-fired units. This is because many of the distillate-oil- and natural-gas-fired
applications are in California, where current regulations have imposed NOX reductions from such
units. Among the controls more widely used are LNB, FOR, and LNB with FOR. Many LNB
designs also incorporate low excess air and FOR, internal to the burner or external in a more
conventional application. The average NOX reduction for FOR on natural-gas-fired boilers is
approximately 60 percent from many industrial boilers, nearly all located in California. The
average controlled NOX level for FGR-controlled ICI watertube boilers is 0.05 Ib/MMBtu or
approximately 40 ppm corrected to 3 percent O2. For distillate oil, the average FGR-controlled
level from watertube boilers is 0.08 Ib/MMBtu or approximately 65 ppm corrected to 3 percent
O2. Average NOX emissions controlled with LNB plus FOR are slightly lower than these levels.
Table 2-5 summarizes results of controls for firetube units. Controlled NOX levels
achieved on these boiler types are generally slightly lower than levels achieved on watertube
TABLE 2-5. SUMMARY OF COMBUSTION MODIFICATION NOX CONTROL
PERFORMANCE ON ICI FIRETUBE BOILERS
Fuel type
Residual-
oil-fired
Ohtillate-
oil-fired
Natural-
gas-fired
NOX control
LNB
SCA
LNB
FOR
SCA
LNB
FOR
LNB + FOR
Radiant LNB
Percent
NO,
reduction
30-60
49
15
N-A."
5
32-78
55-76
NA.
53-82
Controlled
NOX level,
Ib/MMBtu
0.09-0.25
0.11
0.15
0.04-0.16
0.08
0.02-0.08
0.02-0.08
0.02-0.04
0.01-0.04 '
Comments
Staged air could result in operational problems.
Technique generally not practical unless incorporated
in new burner design.
Several LNB designs are available. Most operate on
low excess air.
Effective technique for clean fuels.
Technique not practical unless incorporated in new
burner design.
Several LNB designs are available. Some include FGR
or internal staging.
Effective technique. Used in many applications in
California.
. Most popular technique for very low NOX levels.
Some LNB designs include FGR.
Commercial experience limited to small firetubes.
*NA. = Not available. No data are available to determine control efficiency. See Appendix B for detailed
individual test data.
2-14
-------
units. For example, LNB + FGR recorded an average of about 0.033 Ib/MMBtu or approximately
35 ppm corrected to 3 percent O2. FGR by itself is also capable to achieve these low NOX levels
when burning natural gas. In addition to these combustion controls, both OT and WI have been
retrofitted in combination on selected packaged industrial boilers in California to meet very low
NOX levels. These controls offer the potential for economic NOX control because of low initial
capital investment compared to either FGR or LNB. NOX reduction efficiencies and controlled
levels have been reported in the range of about 55 to 75 percent depending on the amount of
water injected and the level of boiler efficiency loss acceptable to the facility.
232 Flue Gas Treatment Controls
Application of flue gas treatment controls in the United States is generally sparse.
Table 2-6 summarizes the range in NOX reduction performance and controlled NOX levels
achieved with the application of SNCR and SCR. The data base assembled to produce these
results includes both domestic and foreign installation whose results have been reported in the
Literature or were available from selected technology vendors. References and details are
available in Appendix B.
The NOX reduction efficiency of SNCR for PC-fired boilers is based on results from four
boilers, one a small utility unit. For these boilers, NOX reductions ranged from 30 to 83 percent
and averaged 60 percent, with controlled NOX levels in the range of 0.15 to 0.40 Ib/MMBtu.
SNCR performance is known to vary with boiler load because of the shifting temperature
window. SNCR has been reported to be quite more effective for FBC and stoker boilers. In
circulating FBC boilers in California, SNCR with either urea or ammonia injection, achieved an
average NOX reduction and controlled level of nearly 75 percent and 0.08 Ib/MMBtu,
respectively. SNCR results for 13 coal-fired stokers ranged from 40 to 74 percent reduction, with
controlled NOX levels between 0.14 and 0.28 Ib/MMBtu. For stokers burning primarily waste
fuels, including MSW mass burning equipment, several applications of SNCR resulted in NOX
reductions in the range of 25 to 80 percent, averaging about 60 percent, with controlled levels
in the range of 0.035 to 0.31 Ib/MMBtu.
2.4 COST AND COST EFFECTIVENESS OF NOX CONTROL TECHNIQUES
A simplified costing methodology, based primarily on the U.S. EPA's Office of Air
Quality Planning and Standards (OAQPS) Control Cost Manual, was developed for this study.
The capital control costs were based on costs reported by vendors and users of the NOX control
technologies and from data available in the open literature. The total capital investment was
2-15
-------
TABLE 2-6. SUMMARY OF FLUE GAS TREATMENT NOX CONTROL PERFORMANCE
ON ICI BOILERS
ICI boiler and
fuel
PC, wall-fired
Coal-fired E8C
Coal-Stoker
Coal-Stoker
Wood-fired stoker
MSW stokers and
mass burn
Coal-fired FBC
Wood-fired FBC
Wood-fired
Watertube
Natural-gas- and
distillate-oil-fired
watertube
NOX control
SNCR-Urea
SCR
SNCR-Ammonia
SNCR-Urea
SNCR-Ammonia
SNCR-Urea
SNCR-Ammonia
SNCR-Urea
SCR
SNCR-Ammonia
SNCR-Urea
SNCR-Ammonia
SNCR-Urea
SNCR-Urea
SCR
SNCR-Ammonia
SNCR-Urea
SCR
Percent
NOX
reduction
30-83
53-63
50-66
40-74
50-80
25-78
45-79
41-75
53
76-80
57-88
44-80
60-70
50-52
80
30-72
50-60
53-91
Controlled
NOX level,
Ib/MMBtu
0.15-0.40
0.10-0.15
0.15-0.18
0.14-0.28
0.04-0.23
0.09-0.17
0.07-031
0.06-030
0.05
0.04-0.09
0.03-0.14
0.03-0.20
0.06-0.07
0.14-0.26
0.22
0.03-0.20
0.05-0.10
0.01-0.05
Comments
Experience relies primarily on utility
retrofits. Because of relatively higher
NOX, higher control efficiency is
frequently achieved.
Limited applications to few foreign
installations. No domestic experience.
Control levels achieved in combination
with OFA controls.
Control levels achieved in combination
with OFA controls.
Vendors of technology report good
efficiency for stoker applications
irrespective of fuels.
Vendors of technology report good
efficiency for stokers applications,
irrespective of fuels.
Experience limited to one foreign
installation.
Technique is particularly effective for FBC
boilers. Applications limited to California
sites.
Technique is particularly effective for FBC
boilers irrespective of fuel type.
Applications limited to California sites.
Limited application and experience.
Only two known installations in the
United States.
Limited application and experience.
Experience principally based on foreign
and some southern California installations.
2-16
-------
annualized using a 10-percent interest rate and an amortization period of 10 years. Cost
effectiveness was calculated by dividing the total annualized cost by an NOX reduction for each
retrofit cost case using boiler capacity factors in the range of 0.33 to 0.80.
Table 2-7 summarizes the total investment cost and cost effectiveness of several retrofit
scenarios. Overall, the total investment of controls varies from a minimum of about
$100/MMBtu/hr for oxygen trim with operation of the boiler with BOOS for multi-burner
watertubes, to an estimated $20,000/MMBtu/hr for the installation of SCR on a 400 MMBtu/hr
(120 MWt) PC-fired boiler. The high costs of SCR retrofit were derived from estimates
developed for small utility boilers, and are meant to be estimates because no domestic
application of this technology was available at the time of this printing. Furthermore, costs of
SCR systems have recently shown a downward trend because of improvements in the technology,
increased number of applications, and competitiveness in the NOX retrofit market.
Control techniques with the lowest investment cost are those that require minimum
equipment modification or replacement. For example, the installation of an OT system coupled
with WI for ga.s-fired firetubes and packaged watertube is typically much less than $35,000. Also
the application of BOOS in multi-burner units may be a relatively low investment cost approach
in reducing NOX. These costs, however, do not consider the installation of emission monitoring
instrumentation. The cost of CEM systems can easily outweigh the cost of NOX controls for
these packaged boilers. The cost effectiveness of WI controls for packaged boilers is anticipated
to be low in spite of the associated efficiency losses. This is because an efficiency improvement
was credited with the combined application of oxygen trim controls that can compensate for
some of the losses of WI.
The installation of FOR, LNB, and LNB with FOR controls for both packaged and
multi-burner field erected boilers burning natural gas or oil was estimated to range between
$650/MMBtu/hr and $4,700/MMBtu/hr with cost effectiveness as low as $240/ton to as high
as $6,300/ton, depending on fuel type and boiler capacity. The cost of SNCR is based on
estimates provided by two vendors of the technology. For a 400 MMBtu/hr boiler, the
investment cost can be as low as $l,100/MMBtu/hr for a stoker boiler burning coal, to
$3,300/MMBtu/hr for an MSW unit burning stoker. The cost effectiveness of SNCR was
calculated to range from as low as $l,010/ton to $2,400/ton depending on fuel and boiler type.
SNCR costs are not likely to vary with type of reagent used (aqueous ammonia or urea).
2-17
-------
TABLE 2-7. ESTIMATED COST AND
(1992 DOLLARS)
Fuel type
Pulverized
coal
Coal
Natural gas
Distillate oil
Residual oil
Wood waste
MSW
Boiler type
and size,
MMBtu/hr
Watertube
(400)
FBC (400)
S. Stoker (400)
Single burner
packaged watertube
(50)
Packaged firetube
(10.5)
Multiburner field-
erected watertube
(300)
Single burner
packaged watertube
(50)
Packaged firetube
(10.5)
Multiburner
watertube
(300)
Single burner
packaged watertube
(50)
Firetubc
(10.5)
Multiburner
watertube
(300)
Stoker
(150)
FBC
(400)
Stoker
(500)
NOX control
technique
LNB
SNCR
SCR
SNCR
SNCR
OT+WI
LNB
LNB + FOR
SCR
OT+WI
OT+FGR
OT+SCAb
LNB
LNB
LNB+FGR
SCR
OT+FGR
LNB
LNB
LNB+FGR
SCR
LNB
LNB
SNCR
SNCR
SNCR
COST EFFECTIVENESS OF NOX CONTROLS
Estimated
NOX
control level,
Ib/MMBtu*
0.35
039
0.14
0.08
0.22
0.06
0.08
0.06
0.02
0.04
0.07
0.15
0.12
0.10
0.07
0.03
0.12
0.10
0.19
0.15
0.06
0.17
0.19
0.11
0.11
0.18
NOX
reduction,
tons/yr
310
270
490
210
270
5.8
43
5.8
8.7
13
0.65
53
60
33
6.6
25
1.6
72
19
23
33
4.6
120
43
61
240
Total capital
investment,
$/MMBtu/hr
5300
1,600-2,100
20,000
1,600
1,100
530
650-2300
2,100-4,700
2,400-6,900
2,400
5300
190
5,100-8300
2300
2,100-4,700
2,400-6,900
5,400
5,100-8,300
2,300
2,100-4,700
2,400-6,900
5,400
5,100-8300
2,100-2,500
970
.2,100-3300
Cost
effectiveness,
$/ton of NOV
1,170-1,530
1,010-1,400
3,400-4,200
890-1,030
1300-1,500
710-820
570-2,400
1,600-4,400
4,800-6,900
3,100-3,700
8,000-11,000
210-240
2,100-4,200
460-1,900
1,000-3,300
3,900-5,500
4,500-6,200
3,100-6,300
240-1,000
760-2,000
2,000-2,900
2,700-3,600
1,600-3,300
1300-2,400
1,500-1,600
1,500-2,100
'Average levels calculated from the data base available to this study. Average levels do not necessarily represent
what can be achieved in all cases.
bSCA is burners out of service.
Notes: Boiler capacity factor between 0.50 and 0.66. See Appendices D, £, F, and G for details of costing.
Costs do not include installation of continuous emission monitoring (CEM) system. Annual NOX
reduction based on 0.50 capacity factor. Total capital investment from Appendices E through G.
2-18
-------
Figures 2-1 through 2-4 illustrate how the cost effectiveness of these controls varies with
boiler capacity. As anticipated, the larger the boiler size the more cost effective is the control.
Also, costs increase much more rapidly for boilers below 50 MMBtu/hr in size.
2J5 ENERGY AND ENVIRONMENTAL IMPACTS OF NOX CONTROL TECHNIQUES
Combustion modification controls to reduce NOX emissions from ICI boilers can result
in either increase or decreases in the emissions of other pollutants, principally CO emissions.
The actual effect will depend on the operating conditions of the boiler's existing equipment and
the sophistication of burner management system. As discussed earlier, many of these boilers
especially the smaller packaged units are operated relatively with little supervision and with
combustion safety margin which includes excessive amounts of combustion air to ensure efficient
combustion. For these boilers, the installation of burner controls to reduce excess oxygen is
likely to reduce NOX emissions with some increase in CO emissions. For those boilers, that have
poor air distribution to the active burners, a program of burner tuning with oxygen trim is likely
to achieve both some reduction in NOX and CO as well.
Table 2-8 lists CO emissions changes that were recorded with the application of
combustion modification controls. The information shows that high CO emission are more
prevalent when burning coal, especially with combustion controls such as LNB and SCA. Highest
CO levels were recorded from the application of SCA for FBC boilers. CO emissions from
combustion modifications for natural-gas- and oil-fired boilers are usually less than 200 ppm.
Higher CO levels are likely to be recorded with the attainment of strict NOX emission levels.
In recognition of this, the South Coast Air Quality Management District (SCAQMD) in
California permits 400-ppm CO levels for low NOX permits under its Rule 1146. Also, the
.American Boiler Manufacturers Association (ABMA) recommends 400-ppm CO levels when
NOX emissions from ICI boilers are lowered. Increases in paniculate emissions and unburned
carbon are other potential impacts of combustion modification NOX control retrofits on oil- and
coal-fired ICI boilers. Insufficient data are available to quantify these potential impacts,
however.
Other potential environmental impacts can result from the application of SNCR and
SCR control techniques. Both techniques can have ammonia emissions released to the
atmosphere from the boiler's stack. Ammonia-based SNCR or SCR can result in ammonia
releases from the transport, storage, and handling of the chemical reagent. Data from
technology vendors show that the level of unreacted ammonia emitted from the boiler's stack
2-19
-------
6,000
IT 5,000
O
c
& 4,000
3,000
I
2,000
UJ
to
O 1-0
0 -SCR COST EFFECTIVENESS RANGE
D • LN8 COST EFFECTIVENESS RANGE
• -SNCH AMMONIA COST EFFECTIVENESS
A -SNCR UREA COST EFFECTIVENESS
200 300 400 500 600 700 800
Boiler Capacity (MMBtu/hr)
Boiler capacity factor - 0.50 to 0 66
Figure 2-1. Cost effectiveness versus boiler capacity, PC wall-fired hoilers.
c
O
10,000
8,000
OT 6,000
;B 4,000
u
O
2.000
Boiler capacity factor = 0.50 to 0.66
0 50 100 . 150 200 250 300
Boiler Capacity (MMBtu/hr)
SCR LNB & FGR LNB Wl w/ 02 trim
—*— O —B— — A---
Figure 2-2. Cost effectiveness versus boiler capacity, natural-gas-fired packaged watertube
boilers.
2-20
-------
:o,oco
Boiler ccpocity factor = 0.50 to 0.66
50 100 150 200 250 300
Boiler Capacity (IvIMBtu/hr)
SCR LNB & FGR L\3
Figure 2-3. Cost effectiveness versus boiler capacity, distillate-oil-fired boilers.
5,000
x
O
in
(Tl
4,000
3,000
2,000
u
CO
O
O
Boiler ccpocity foctor = 0.50 to 0.66
0.
LJ 1,000 - • •••$-- -Q
: -O
D
-&
'-••Q Q-
50
100
150
200
250
300
Boiler Capacity (MMBtu/hr)
SCR LNB & FGR LNB
Figure 2-4. Cost effectiveness versus boiler capacity, residual-oil-fired boilers.
2-21
-------
TABLE 2-8. EFFECTS OF NOY CONTROLS ON CO EMISSIONS FROM ICI BOILERS
Boiler and fuel type
Coal-fired watertube
Coal-fired stoker
Coal-fired FBC
Gas-fired packaged
firetube
Gas-fired packaged
watertube
Distillate oil packaged
watertube
*
Distillate oil packaged
firetube
Residual oil watertube
NOX control
LNB
LNB+SCA
SCA
SCA
FGR
LNB
FGR
LNB + FGR
FGR
LNB
FGR
SCA
NOX
reduction,
%
67
66
31
67
59-74
32-82
53-78
55
20-68
15
4-30
8-40
CO emissions impact
Emissions at
low NOX, ppm
13-430
60-166
429
550-1,100
3-192
0-30
20-205
2
24-46
13
20-145
20-100
Average
change, %
+ 800
+ 215
+ 80
+ 86
- 93 - -6.3
-100 - -53
-70 - +450
-98
+ 20- +1,000
+ 120
0 - + 1,400
N.A.a
aN.A, = Not available.
when either urea and ammonia-based processes are used is less than 40 ppm. The actual level
of ammonia breakthrough will depend on how well the reagent feedrate is controlled with
variable boiler loads and on the optimization of injection location and mixing of reagent with the
flue gas. For some retrofits, especially packaged boilers, the injection of reagents at SNCR
temperatures and the retrofit of SNCR reactors are difficult if not completely impractical.
Increased energy consumption will result from the retrofit of most NOX control
techniques. For example, the injection of water or steam to chill the flame and reduce thermal
NOX will reduce the thermal efficiency of the boiler by 0.5 to 2 percent depending on the
quantity of water used. Increases in CO emissions that can result form the application of certain
controls such as WI, SCA, and LNB will also translate to increased fuel consumption. The
application of FGR will require auxiliary power to operate the flue gas recirculation fan. Both
2-22
-------
SNCR and SCR have auxiliary power requirements to operate reagent feed and circulating
pumps. Also, anhydrous ammonia-based SNCR and SCR require auxiliary power to operate
vaporizers and for increased combustion air fan power to overcome higher pressure drop across
catalysts. Additionally, increases in flue gas temperatures, often necessary to maintain the SCR
reactor temperature constant over the boiler load, can translate into large boiler thermal
efficiency losses. Oxygen trim and burner tuning will, on the other end, often result in an
efficiency improvement for the boiler. This is because lower oxygen content in the flue gas
translates to lower latent heat loss at the stack. Estimates of increases and potential decreases
in energy consumption are presented in Chapter 7.
2-23
-------
3. ICI BOILER EQUIPMENT PROFILE
ICI boilers span a broad range of equipment designs, fuels, and heat input capacities.
The feasibility of retrofitting existing ICI boilers with NOX controls, and the effectiveness and
costs of these controls, depend on many boiler design characteristics such as heat transfer
configuration, furnace size, burner configuration, and heat input capacity. Many of these design
characteristics are influenced by the type of fuel used such as natural gas, fuel oil, pulverized and
stoker coal, and solid waste fuels. Uncontrolled NOX emissions also vary significantly among the
various fuels and boiler design types. Combustion modifications are the most common approach
to reducing NOX, but experience with many ICI boiler types is limited. FGT controls can
substitute for combustion modifications or can provide additive NOX reductions from controlled-
combustion levels.
This chapter presents an overview of ICI boiler equipment to aid in the assessment of
NOX control technologies. A boiler is defined here as a combustion device, fired with fossil or
nonfossil fuels, used to produce steam or to heat water. In most ICI boiler applications, the
steam is used for process heating, electrical or mechanical power generation, space heating, or
a combination of these. Smaller ICI boilers produce hot water or steam primarily for «pace
heating. The complete boiler system includes the furnace and combustion system, the heat
exchange medium where combustion heat is transferred to the water, and the exhaust system.
There are roughly 54,000 industrial boilers currently in operation in the United States today, with
new units being added at the rate of about 200 per year. Of these new units, nearly 80 percent
are sold as replacement units, thus the nation's industrial boiler population is growing only
slightly. The leading user industries, ranked on the basis of aggregate steaming capacity, are the
paper products industry, the chemical products industry, the food industry, and the petroleum
industry.1
As a whole, ICI boilers span the range of heat input capacities from 0.4 to
1,500 MMBtu/hr (0.11 to 440 MWt). Table 3-1 gives the distribution of the major ICI boiler
3-1
-------
TABLE 3-1. ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS
Heat transfer
configuration
Watertube
Firetube
Cast iron
Tubeless
Design and
fuel type
Pulverized coal
Stoker coal
FBC«coal
Gas/oil
Oil field steamer
Stoker nonfossil
FBC nonfossil
Other nonfossil
HRT coal
Scotch coal
Vertical coal
Firebox coal
HRT gas/oil
Scotch gas/oil
Vertical gas/oil
Firebox gas/oil
HRT nonfossil
Firebox nonfossil
Coal
Gas/oil
Gas/oil
Capacity
range,
MMBtu/hr11
100-1,500+
0.4-550 +e
1.4-1,075
0.4-1,500+
20-62.5
1.5-l,000e
40-345
3-800
0.5-50
0.4-50
<2.5
0.4-25
0.5-50
0.4-50
<2.5
<20
2-50
2-20
< 0.4-14
< 0.4-14
< 0.4-4
% of ICI
boiler
unitsb'c
»*
**f
**
2.3
NA.h
»*
«*
**
**
**
**
**
1.5
4.8
1.0
6.5
N.A.
NA.
9.9
72
NA.
% of ICI
boiler
capacityb>c
2.5
5.0
*»
23.6
NA.
1.1
»«
*»
**
**
**
**
1.5
4.6
**
48
NA.
NA.
1.3
9.6
NA.
Application*1
PH, CG
SH, PH, CG
PH, CG
SH, PH, CG
PH
SH, PH, CG
PH, CG
SH, PH, CG
SH, PH
SH, PH
SH, PH
' SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
SH, PH
•To convert to MWt, multiply by 0.293.
'includes all units used in the ICI sector, regardless of capacity.
C1991 FBC data2; other data are from 1977-1978.3'4
''SH = Space heat; PH = Process heat; CG = cogeneration.
*Design capacities can be higher.
f** indicates less than 1 percent.
8FBC = fluidized bed combustion
hNA. - Not available. No data are available.
3-2
-------
types currently in use. Figures 3-1 and 3-2 illustrate the range of heat input capacities applicable
to various fuels, heat transfer configurations, and equipment types. Industrial boilers generally
have heat input capacities ranging from 10 to 250 MMBtu/hr (2.9 to 73 MWt). This range
encompasses most boilers currently in use in the industrial, commercial, and institutional sectors.
Those industrial boilers with heat input capacities greater than 250 MMBtu/hr (73 MWt) are
generally similar to utility boilers.5 Therefore, many of the NOX controls applicable to utility
boilers are also candidate controls for large industrial boilers.
Boilers with heat input capacities less than 10 MMBtu/hr are generally classified as
commercial/institutional units. These boilers are used in a wide array of applications, such as
wholesale and retail trade, office buildings, hotels, restaurants, hospitals, schools, museums, and
government facilities, primarily providing steam and hot water for space heating.3 Boilers used
in this sector generally range in size from 0.4 to 12.5 MMBtu/hr (0.11 to 3.7 MWt) heat input
capacity, although some are appreciably larger.6
As the types and sizes of ICI boilers are extremely varied, so too are the fuel types
burned in these units. The most commonly used fuels include natural gas, distillate and residual
fuel oils, and coal in both crushed and pulverized form. Although the primary fuel types used
are fossil based, there is a growing percentage of nonfossil fuels being burned for industrial
steam and nonutility power generation. The fuels' physical and chemical composition greatly
influence the quantity and type of emissions produced, and the feasibility of certain types of NOX
controls, as will be discussed in Chapters 4 and 5.
The following sections describe the main characteristics of ICI boiler types used in the
United States. Section 3.1 describes the three roam heat transfer configurations of boilers.
Section 3.2 addresses those units primarily fueled by coal. Section 3.3 discusses oil- and natural-
gas-fired boilers. Finally, Section 3.4 describes nonfossil-fueled boilers.
3.1 BOILER HEAT TRANSFER CONFIGURATIONS
An important way of classifying boilers is by heat transfer configuration. The four major
configurations are watertube, firetube, cast iron, and tubeless. In a watertube boiler (Figures 3-3
and 3-4), combustion heat is transferred to water flowing through tubes lining the furnace walls
and boiler passes. The furnace watertubes absorb primarily radiative heat, while the watertubes
in the boiler passes gain heat by convective heat transfer. ICI watertube boilers span the entire
range of ICI boiler capacities: 0.4 to 1,500 MMBtu/hr (0.11 to 440 MWt) heat input capacity.7'8
They can be either packaged or field-erected, depending on their size. In general, most units
3-3
-------
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3-5
-------
TO
ATMOSPHERE
STEAM
BOILER
Figure 3-3. Simplified diagram of a watertube boiler.9
Figure 3-4. Watertube boiler.10
3-6
-------
greater than 200 MMBtu/hr heat input capacity are field-erected. Field-erected units are
assembled onsite; these include all large multi-burner gas- and oil-fired boilers and most PC and
stoker units. Packaged boilers are shipped by rail or flatbed truck as complete units. New gas-
and oil-fired boilers as large as 150 MMBtu/hr (44 MWt) heat input capacity are typically shop-
assembled and shipped as packaged units. Demand for packaged boilers peaked in the 1970s,
when premium fuel restrictions and the rapidly escalating prices of oil and gas caused their
decline. However, with government's repeal of its premium fuel use restrictions, and with
greater availability and lowered prices of oil and gas, the packaged boiler is becoming
increasingly popular.11
In a firetube boiler (Figures 3-5 and 3-6), the hot combustion gases flow through tubes
immersed in the boiler water, transferring heat to the water. The firebox itself is also often
immersed in the water. At high pressures, and when subjected to large variations in steam
demand, firetube units are more susceptible to structural failure than watertube boilers, since,
in the firetube units, the high-pressure steam is contained by the boiler walls rather than by
multiple small diameter watertubes, which are inherently stronger.6 As a consequence, ICI
firetube boilers are typically small, with heat input capacities limited to less than 50 MMBtu/hr
(15 MWt)12, and steam pressures limited to 300 psig, although high-end steam pressures of
150 psig are more common. Firetubes are used primarily where loads are relatively constant.
Nearly all firetube boilers are sold as packaged units because of their relatively small size.
In a cast iron boiler, combustion gases rise through a vertical heat exchanger and out
through an exhaust duct. Water in the heat exchanger tubes is heated as it moves upward
through the tubes. Cast iron boilers produce low-pressure steam or hoi water, and generally
burn oil or natural gas.13 They are used primarily in the residential and commercial sectors, and
have heat input capacities up to 14 MMBtu/hr (4.1 MWt).14
The tubeless design incorporates nested pressure vessels with water in between the
shells. Combustion gases are fired into the inner pressure vessel and are then sometimes
recirculated outside the second vessel.
32 COAL-FIRED BOILER EQUIPMENT TYPES
In 1977,12 percent of all ICI boilers in the United States were coal-fired.3 Coal has not
been utilized in ICI boilers as extensively as oil or natural gas, chiefly due to cost-effectiveness
considerations for the smaller units. Although the majority of coal-fired ICI boilers are smaller
cast iron units, coal-fired firetube or cast iron boilers are not as common as oil- or natural-gas-
3-7
-------
TO
ATMOSPHERE
STEAM OUT
"
Figure 3-5. Simplified diagram of a firetube boiler.15
Figure 3-6. Firetube boiler.16
3-8
-------
fired firetube units. As discussed above, this is because firetube boilers are usually limited to
50 MMBtu/hr (15 MWt) heat input capacity. For smaller industrial and commercial units below
this capacity, coal has not been a popular fuel because of the high capital cost of coal handling
equipment relative to the costs of the boilers. Thus, most ICI boilers are fueled with oil or
natural gas.
Nevertheless, there has been a market percentage increase in coal-fired boilers since the
early 1970s. Of the total industrial boiler units purchased in 1971, only 0.5 percent were
designed primarily for coal use. By 1980, coal-fired boilers claimed 13.7 percent of the new
boiler market. With regards to the application of these coal-fired boilers, five industry groups
consumed 66 percent of the total industrial coal used in 1980. These groups included the
chemical products industry, the paper products industry, the food and kindred products industry,
the primary metals industry, and the transportation equipment industry.17
32.1 Coal-fired Watertube Boilers
Coal-fired watertube boilers made up less than 1 percent of the total United States ICI
boiler population in 1977, the last time an industrial boiler inventory was taken. Yet, due to
\ Q
their larger capacities, these units accounted for 14 percent of the total operating capacity.
Coal-fired watertube ICI boilers can be classified into three major categories: stokers, PC-fired
units, and FBC boilers. The following subsections describe these types of boilers.
32.1.1 Stoker-firing Watertube Boilers
Stoker-firing systems account for approximately 90 percent of coal-fired watertube ICI
boilers.19 Stoker systems can be divided into three groups: underfeed stokers, overfeed stokers,
and spreader stokers. These systc-.ms differ in how fuel is supplied to either a moving or
stationary grate for burning. One important similarity among all stokers is that all design types
use underfeed air to combust the coal char on the grate, combined with one or more levels of
overfire air introduced above the grate. This helps ensure complete combustion of volatiles and
low combustion emissions. Most stokers also utilize flyash reinjection to minimize the unburned
carbon content in the flyash. Underfeed stokers were once the primary stoker type used in
industrial and utility steam generation, but the high costs of maintenance and these units' slow
response to varying loads have made them less competitive in the present market. Spreader
stokers, however, are extremely popular in industry today, due in part to their wide fuel
capability, discussed further below.20
3-9
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Underfeed stokers are generally of two types: the horizontal-feed, side-ash-discharge
type, shown in Figure 3-7; and the gravity-feed, rear-ash-discharge type, shown in Figure 3-8.
The horizontal-feed, side-ash-discharge type of stoker is used primarily in small boilers supplying
relatively constant steam loads of less than 30,000 Ib/hr (~30 MMBtu/hr input).21 As shown
in Figure 3-7, coal is supplied from below the air-admitting surface of the grate into the bottom
of a fuel bed, usually via a longitudinal channel called a retort. As additional coal is fed into the
boiler with a ram or screw, the coal is forced to the top of the retort, where it spills onto a grate
located on either side. Combustion air is supplied through tuyeres at the side grates, where
combustion is completed. Overfire air is often supplied to the flame zone above the bed to
provide more combustion air and turbulence for more complete combustion.22 These smaller
underfeed stokers typically have one or two retorts. Maximum allowable burning rates are
typically 425,000 Btu/hr per square foot of grate area.21 Allowable burning rates determine the
size of the grate area for a given heat input rate. The higher the burning rate the higher the
intensity of combustion and thickness of the burning bed. The gravity-feed, rear-ash-discharge
underfeed stoker often has multiple retorts. Typically, this type of stoker has a maximum
500 MMBtu/hr (146 MWt) heat input capacity.21 In this type of stoker, coal is introduced
through a coal hopper and is ram-fed to the inclined retorts and grates. The retorts and grates
are typically inclined 20 to 25°. Maximum allowable fuel burning rates are 600,000 Btu/ft2-hr.21
An overfeed stoker, shown in Figure 3-9, uses a moving grate assembly. Coal is fed
from a hopper onto a continuous grate that conveys the coal into the furnace. As coal moves
through the furnace on the grate, it passes over several air zones for staged burning. The air
serves a dual purpose; it is used for combustion as well as for cooling the fuel bed and grate,
preventing fusing of the coal. At the far end of the moving grate, combustion is completed and
ash discharged to the bottom of the furnace. An adjustable gate at the coal feed point allows
regulation of the depth of the fuel bed.23'24 The three types of grates used with overfeed coal
stokers are the chain, travelling, and water-cooled vibrating grates. These overfeed stoker
systems are often referred to by the type of grate employed. Overfeed coal-fired systems
typically range up to 350 MMBtu/hr (100 MWt) heat input capacity. Maximum fuel burning
rates for overfeed stokers are roughly 500,000 Btu/ft2-hr.21
In a spreader stoker, mechanical or pneumatic feeders distribute coal uniformly over the
surface of a moving grate. In a typical spreader stoker boiler, shown in Figure 3-10, primary air
is admitted evenly throughout the active grate area, providing some fuel bed cooling, while above
3-10
-------
Coal Ram
Figure 3-7. Single-retort horizontal-feed underfeed stoker.21
Tuyeres
Coal Hopper
I r Coal
Rams
Ash Discharge Plate
Fuel Distributors
Figure 3-8. Multiple-retort gravity-feed underfeed stoker.21
3-11
-------
Coal Hopper
Drive
Linkage
Drive
Sprocket
Sittings
Hopper
Return
Bend
Sittings Dump
Mechanism
Air Seals Air Compartments Drag Frame
Figure 3-9. Overfeed chain-grate stoker.21
Coal Hopper
Feeder
Stoker
Chain
Figure 3-10. Spreader stoker.21
3-12
-------
the grate an overfire air system provides secondary air and turbulence. The injection of the fuel
into the furnace and onto the grate combines suspension burning with a thin, fast-burning fuel
bed. The amount of fuel burned in suspension depends primarily on fuel size and composition,
among other factors. Generally, the finer the fuel and/or the higher its volatile matter content,
the more energy released in suspension; the higher the moisture content, the more energy
released on the grate.24 Many spreader stoker units incorporate a flyash recirculation system,
whereby unburned solids in the flyash are collected and recirculated back into the primary
combustion chamber. Heat input capacities of spreader stokers typically range from 5 to
550 MMBtu/hr (1.5 to 160 MWt), although there are a few units of 1,500 MMBtu/hr (440 MWt)
or more.18 Maximum fuel burning rates are highest for this stoker design, often reaching a
maximum of 750,000 Btu/ft2-hr.21
In general, stoker coal is fed crushed with a nominal size less than 2 inches. Overfeed
and spreader stokers can be used to burn almost any type of coal or solid fuel, including wood,
wood waste, and bagasse. Coking bituminous coals, however, are not used in overfeed stokers
to avoid matting and restricting the airflow through the grate. Coking has little effect on the
performance of spreader stokers.8 Most packaged stoker units designed for coal firing are less
than 100 MMBtu/hr (29 MWt) capacity.25 Larger units are typically field-erected.
32.12 PC-fired Watertube Boilers
PC-fired boilers account for a small percentage of the ICI watertube boiler population.
In 1977, they accounted for less than l/10th of 1 percent of all installed ICI boiler units.
However, they accounted for approximately 2.5 percent of total ICI boiler capacity.18 This
disparity is due to the fact that PC-fired boilers are alrr/os'. entirely limited to sizes larger than
100 MMBtu/hr (29.3 MWt) heat input capacity. Below this level, the required coal-handling and
pulverizing equipment can increase the capital cost of PC-fired units to as high as 10 times that
of an oil- or natural-gas-fired industrial boiler of the same size.26 Thus, when coal is the fuel
of choice, stoker firing dominates in units below about 150 MMBtu/hr (44 MWt) heat input
capacity. PC firing and FBC are usually the choices for larger boilers.27 PC-fired ICI boilers
are nearly all of watertube configuration, and the majority are field-erected.26
Combustion in PC-fired units takes place almost entirely while the coal is suspended,
unlike in stoker units, in which most, if not all, of the coal burns on a grate. Finely ground coal
(70 percent through 200 mesh) is typically mixed with primary combustion air and fed to the
burner or burners, whereupon it is ignited and mixed with secondary combustion air. Depending
3-13
-------
upon the location of the burners and the direction of coal injection into the furnace, PC-fired
boilers can be classified into three different firing types
• Single- and opposed-wall, also known as face firing
• Tangential, also known as corner firing
• Cyclone
Of these types, wall and tangential configurations are the most common.26
Figure 3-11 shows a schematic of a single-wall-fired boiler. Wall-fired boilers can be
either single-wall-fired, with burners on only one wall of the furnace firing horizontally, or
opposed-wall-fired, with burners mounted on two opposing walls. However, opposed-wall boilers
are usually much larger than 250 MMBtu/hr heat input capacity, and are much more common
in utility rather than in industrial applications.26
Figure 3-12 shows a plan view of a tangential-firing configuration, with the burners
mounted in the corners of the furnace. The fuel and air are injected toward the center of the
furnace to create a vortex that enhances air/fuel mixing. Larger flame volumes and flame
interaction contribute to characteristically lower NOX levels from tangential firing. Tangential
boilers, like opposed-wall boilers, are commonly used in utility applications.26
Cyclone furnaces are often categorized as PC-fired systems even though the coal burned
in cyclones is crushed and not pulverized. These furnaces burn low-fusion-temperature coal
crushed to a maximum particle size of about 4.75 mm (95 percent through 1/4 inch mesh).8 The
coal is fed tangentially, with primary air, into a horizontal cylindrical furnace. Smaller coal
particles are burned in suspension, while larger particles adhere to a molten layer of slag on the
combustion chamber wall. The larger particles remain in the slag until they are burned. Because
of their intense furnace heat release rates, cyclones emit high levels of NOX, and are generally
more difficult to control with combustion modifications. Cyclone furnaces are not as widely used
in the industrial sector as wall, tangential, or stoker systems.8
PC-fired boilers are also classified as either dry bottom or wet bottom, depending on
whether the ash is removed in solid or molten state. This is an important differentiation with
respect to NOX emissions, as wet-bottom boilers generally operate at higher furnace
temperatures and subsequently emit greater amounts of NOX. Boiler designs in wet- and dry-
bottom furnaces hinge on coal quality and ash fusion properties. Wet-bottom furnaces are also
referred to as slag tap furnaces. In the ICI sectors, dry-bottom PC-fired boilers are much more
widely used than wet-bottom boilers.6'8
3-14
-------
Figure 3-11. Wall firing.26
Figure 3-12. Tangential firing.2
3-15
PRIHARY AIR
AND
FUEL
-------
32.13 FBC Watertube Boilers
FBC boilers, while not constituting a large percentage of the total ICI boiler population,
have nonetheless gained popularity in the last decade, due primarily to their capabilities to burn
a wide range of solid fuels and to use combined NOX/SOX controls within the furnace. FBC
units generate steam for ICI facilities, cogenerators, independent power producers, and utilities.
In the United States, FBCs in use in the industrial sector account for less than 10 percent of the
total installed FBC generating capacity.28
There are two major categories of FBC systems: (1) atmospheric, operating at a slight
negative draft, and (2) pressurized, operating at from 4 to 30 atmospheres (60 to 450 psig).
Pressurized FBC (PFBC) systems are being demonstrated at two utility sites in the United
States. No PFBC units are currently in operation in the ICI sector, and it is unlikely that such
systems will be used for industrial applications in the near future, due to the developmental
status of this technology. A recent market assessment report concluded that PFBCs are several
years away from full commercialization in .the utility industry, and that near-term opportunities
for large industrial applications rest with atmospheric FBC technology.28 Currently, only
atmospheric FBC systems are used in the ICI sector.29 Therefore, the remainder of this section
describes atmospheric FBCs.
In a typical FBC boiler, solid, liquid, or gaseous fuel or fuels, together with a mixture
of inert material (e.g., sand, silica, ash) and/or a sorbent such as limestone, are kept suspended
by a steady upward flow of primary air through the fuel bed. This fuel bed fluidization promotes
turbulence, which improves mixing of fuel and air, allowing the FBC to combust solid fuel at a
substantially lower and more uniformly distributed temperature—typically 815 to 870 °C (1,500
to 1,600 °F) — compared to stoker or PC-fired boilers, where furnace temperatures can peak at
1,590°C (2,900°F).
This lower temperature range provides two of the three main advantages of FBCs over
conventional boiler units:
• Lower combustion temperatures result in less formation of thermal NOX and allow
use of sorbent to reduce SO2 emissions
• Lower combustion temperatures are generally below the ash fusion temperatures
of most fuels, resulting in less slagging and fouling of heat transfer surfaces
• FBCs are able to burn many types of fuels besides coal, including low-grade fuels
such as petroleum coke, waste coal, municipal waste, and biomass materials
3-16
-------
Flexible-fuel capability is inherent in FBC design, and the ability to efficiently burn low-grade
fuels would generally be impractical without FBC technology. High combustion efficiencies are
generally due to the long retention times of solids in the fluidized beds.30
FBCs are primarily watertube boilers, especially among the larger units, although
firetube units are also available. In some FBCs — bubbling bed units, described below —
additional watertubes are located within the fuel bed itself, oriented either horizontally or
vertically. Steam output is controlled by manipulating the primary bed parameters of height,
temperature, fuel input, and fluidization velocity—the velocity of the primary air through the bed.
Firetube FBC boilers are also available and in use. However, of the more than 50 FBC
manufacturers worldwide, only 12 offer firetube designs in addition to the more conventional
watertube systems.31 This indicates the relative popularity of watertube FBC systems as
compared to the less common firetube units.
Figures 3-13 and 3-14 show the two principal types of atmospheric FBC boilers, the
bubbling bed and the circulating bed. The fundamental distinguishing feature between these
types is the fluidization velocity. In the bubbling-bed design, the fluidization velocity is relatively
slow, ranging between 5 and 12 ft/s, the idea being to minimize solid carryover into the
convective passes of the boiler. In some units, relatively slow fluidization velocities allow
watertubes to be placed within the bed itself, as long as tube erosion is not a problem.
Circulating FBCs, however, employ fluidization velocities as high as 30 ft/s and actually promote
the carryover or circulation of solids—fuel and bed material. Solids leaving the primary
combustion zone are trapped by high-temperature cyclones and recirculated back to the primary
combustion chamber. In some circulating-bed designs, a secondary combustion chamber is used
to complete combustion of the fuel. The circulating FBC maintains a continuous, high-volume
recycle rate that increases the fuel residence time compared to the bubbling-bed design. Because
of this, circulating FBCs often achieve higher combustion efficiencies and better sorbent
utilization in the control of SO2 emissions than bubbling-bed units.33 This is one reason why the
bubbling bed FBC, still favored for small-scale boilers, is not as favored for large-scale industrial
and utility applications.33 Circulating FBCs have their heat exchange tubes downstream of the
recirculating cyclone.
Of atmospheric FBCs currently in use in all sectors, including industrial, utility,
independent power production, and cogeneration applications, coal is the primary fuel used,
followed in descending order by biomass, coal waste, and municipal waste. Coal waste and
3-17
-------
Figure 3-13. Bubbling FBC schematic.32
Figure 3-14. Circulating FBC schematic.32
3-18
-------
municipal waste are not significant fuel types for larger FBC plants.33 Of 157 non-utility FBC
boilers in operation in the United States in 1991, 116 were of heat input capacities below
250 MMBtu/hr (73 MWt or 37 MWe), and of these, 51 burned coal exclusively.2 Another 18
units burned coal in combination with wood, sludge, coke, or biomass. The coal-burning FBCs
ranged between 8.4 and 235 MMBtu/hr heat input capacity (2.5 to 69 MWt, or 1.25 to 35 MWe
output), and accounted for a relatively small amount of the total capacity of coal-fired ICI
boilers. The largest coal-fired FBC unit in non-utility application in the United States has
an approximate heat input capacity of 1,070 MMBtu/hr (315 MWt), generating 160 MWe
of electric power at a cogeneration facility.2
From an economic standpoint, ICI FBC boilers that burn coal do not compete strongly
with gas-fired units. For example, in the 200- to 600-MMBtu/hr (59- to 175-MWt or 30- to 90-
MWe) size range, the capital costs of a coal-fired FBC boiler are 2 to 3 times higher than a
conventional natural-gas-fired unit. The use of lower cost opportunity fuels, such as coke,
biomass, wood waste, and low-grade coals, can provide sufficient economic incentive to offset
higher initial capital costs. When used in electric power generating applications, FBC coal-fired
power plants produce electricity at 1.5 to 3 times the cost of gas-based power generation.34
Future growth in the ICI FBC boiler market is expected to occur mainly among units that burn
fuels other than coal, such as waste fuels like wood and manure.
322 Coal-fired Firetube Boilers
Coal-fired firetube boilers represent a small portion of the ICI boiler population. In
1977, coal-fired firetube boilers accounted for only 10 percent of the industrial and commercial
firetube boiler population in the United States, and only 1.5 percent of all ICI boilers.35 The
four most common types of firetube boilers used with coal are the horizontal return tubular
(HRT), Scotch, vertical, and the firebox; however, the HRT boiler is generally used with gas or
oil instead of coal. Virtually all coal-fired firetube boilers are packaged units. The following
sections discuss these boiler types as well as other less common firetube boilers.
322.1 HRT Firetube Boilers
In a typical HRT boiler, the firetubes are horizontal and self-contained, with the
combustion chamber separate. When solid fuel such as coal is used, it is fed through a feed
chute onto grates in the primary combustion chamber. The combustion gases then pass through
the firetubes of the boiler.
3-19
-------
Most coal- and other solid-fuel-fired HRT boilers are two-pass designs. In a two-pass
HRT boiler, shown in Figure 3-15, primary and secondary combustion chambers are located
beneath the boiler tank. The combustion gases flow over the bridge wall towards the rear of the
boiler, heating the outer shell of the tank. At the rear of the boiler, the combustion gases then
enter the firetubes. The gases flow through the firetubes, transferring additional heat to the
water, and are then exhausted through the boiler stack.
HRT boilers come in various sizes, ranging from 0.5 to 50 MMBtu/hr (0.15 to 15 MWt)
heat input capacity, with pressures of 15 to 250 psig. Some larger units are available that supply
saturated steam at 300 psig. Firing of coal in HRT boilers is not as common as firing liquid or
gaseous fuels, due to the possibility of scaling or slagging.
3222 Scotch Firetube Boilers
A Scotch, or shell, boiler differs from the HRT boiler in that the boiler and furnace are
contained in the same shell. In a two-pass unit, combustion occurs in the lower half, with the
flue gases passing beneath the bottom of the water basin occupying the upper half. The gases
then pass through the firetubes running through the basin. Scotch boilers also come in three-
or four-pass configurations. The capacity of Scotch boilers ranges up to 50 MMBtu/hr (15 MWt)
heat input, with pressures up to 300 psig, although more typical pressures are approximately
200 psig. Like HRT boilers, coal is not as commonly used in Scotch boilers due to slagging and
scaling.36 More common gas- and oil-fired Scotch units are shown in Figures 3-6 and 3-16.
3223 Vertical Firetube Boilers
Another common firetube design is the vertical boiler. A vertical firetube boiler is a
single-pass unit in which the firetubes come straight up from the w^ter-cooled combustion
chamber located at the bottom of the unit. Figure 3-17 depicts an exposed-tube vertical boiler
in which the firetubes extend from the top of the furnace into the steam space. This causes the
steam to be superheated and reduces carryover of moisture.3
Figure 3-18 shows a submerged-tube vertical boiler in which the firetubes extend from
the furnace to the tube sheet, which is below the water level. This design prevents the ends of
the firetubes from overheating. A conical flue gas collector directs the flue gases to an exhaust
stack. The submerged-tube boiler has essentially been discontinued, however, because the
collector is difficult to build and tends to leak.37
Vertical boilers are small, with heat input capacities under 2.5 MMBtu/hr (0.73 MWt).
However, they are capable of burning all types of fuels, including coal.
3-20
-------
,
I
3-21
-------
Figure 3-16. Four-pass gas-/oil-flred scotch boiler.39
3-22
-------
SAFETY
VALVE
INJECTOR
Figure 3-17. Exposed-tube vertical boiler.37
3-23
-------
WATER
COLUMN
CROWN SHEET
FURNACE
STEAM
OUTLET
W BOLTS
Figure 3-18. Submerged-tube vertical boiler.37
3-24
-------
3.2.2.4 Firebox Firetube Boilers
Another type of firetube boiler is the firebox boiler. These units are constructed with
an internal steel-encased, water-jacketed firebox. Firebox boilers are compact and employ, at
most, three passes of combustion gases. Firebox firetube boilers are also referred to as
locomotive, short firebox, and compact firebox boilers. A locomotive boiler is a single-pass
horizontal firetube boiler; a short firebox boiler is a two-pass horizontal firetube unit; and a
compact firebox boiler is a three-pass horizontal unit.37
Currently available coal-fired firebox units either employ mechanical underfeed stokers,
or are capable of being hand-fired. They are generally limited in size to below 25 MMBtu/hr
(7.3 MWt) heat input capacity.40
323 Cast Iron Boilers
Commercial cast iron boilers consist of several vertical sections of heat exchange tubes
mounted above a firebox. Water enters each section at the bottom, and is heated or converted
to steam as it passes upward through the heat exchange tubes. The capacity of a commercial
cast iron boiler is determined by the number of heat exchange sections in the boiler.
In 1977, only 12 percent of the 1.5 million cast iron boilers in the United States were
coal fired, and of these, 37 percent had heat input capacities of 0.4 MMBtu/hr (0.1 MWt) or
higher.41 The majority of cast iron boilers are below 0.4 MMBtu/hr (0.1 MWt) heat input
capacity and are fueled by natural gas or fuel oil. All cast iron boilers are packaged units, as
they are usually no greater than 14 MMBtu/hr (4.1 MWt) in heat input capacity, and, hence, are
relatively small.
3.3 OIL- AND NATURAL-GAS-FIRED ICI BOILER EQUIPMENT TYPES
Oil- and natural-gas-fired ICI boilers accounted for 88 percent of the ICI boiler
population in 1977.3 These boilers are generally similar to coal-fired units, with the exception
of stoker systems, which are not used to burn liquid or gaseous fuels. However, some boilers
are designed with oil/gas burners and a solid fuel stoker system, to allow use of the most
economically available fuel. Oil- and natural-gas-fired ICI boilers are similar; in fact, many are
capable of firing both fuels either separately or in combination.
In smaller packaged units, single burners are usually employed, while larger field-erected
boilers often have multiple burners. In older boilers, multiple-burner arrangements provided a
means of controlling heat input in lieu of burner turndown capability. With advances in burner
control and turndown capability—most new burners can maintain stable flames as low as
3-25
-------
10 percent of capacity—the use of multiple burners in smaller units has declined. Most newer
units smaller than 200 MMBtu/hr (59 MWt) heat input capacity have only one burner. Oil- and
natural-gas-fired boiler types can be categorized as watertube, firetube, cast iron, or tubeless, and
as either packaged or field-erected. Watertube boilers can either be shop-assembled (packaged)
or field-erected. Firetube and cast iron boilers are nearly all packaged because of their smaller
sizes.
In the smaller sizes and most commercial applications of ICI boilers, the packaged
gas/oil fired Scotch firetube boiler predominates.42 Almost all of these applications are for
heating where loads do not fluctuate quickly. Boilers designed for low temperature (250 °F or
less) and low pressure (15 psig and less) steam are the most widely used in residential,
apartment, and commercial construction.42
3 J.I Oil- and Natural-gas-fired Watertube Boilers
Oil- and natural-gas-fired watertube boilers come in a wide range of capacities, from
small commercial units of 0.4 MMBtu/hr (0.1 MWt) heat input capacity, to very large industrial
boilers of 1,500 MMBtu/hr (440 MWt) or heat input capacity or higher. However, in the ICI
sector, most are smaller than 250 MMBtu/hr (73 MWt). Larger oil- and natural-gas-fired
watertube boilers that are field-erected are similar to PC-fired units in firing configuration, but
with smaller furnace volumes (higher heat release rate per unit volume or waterwall surface
area). Units with heat input capacities greater than 150 MMBtu/hr (44 MWt) are typically wall-
fired or tangential-fired with multiple burners. Field-erected watertube boilers strictly designed
for oil firing are more compact than coal-fired boilers with the same heat input, because of the
more rapid combustion characteristics of fuel oil. Field-erected watertube boilers fired by
natural gas are even more compact due to the rapid combustion rate of the gaseous fuel, the low
flame luminosity, and the ash-free content of natural gas.43
In general, field-erected watertube boilers are much more common than packaged units
in the boiler size category above 100 MMBtu/hr (29 MWt) heat input capacity, whereas below
this capacity, watertube boilers are usually packaged. There are, however, packaged watertube
units as large as 250 MMBtu/hr (73 MWt) heat input capacity.
The major type of watertube design used in packaged oil/natural-gas-fired ICI boilers
is the horizontal bent tube, classified by the number of drums, headers, and tube configuration,
with the latter being the most distinguishing factor. Figure 3-19 shows the three most common
tube configurations used in packaged units. The "A" type has two small lower drums, or headers,
3-26
-------
A-type has two small lower drums
or headers. Upper drum Is larger
to permit separation of water and
steam. Most steam production
occurs 1n center furnace-wall
tubes entering drum.
D-type allows much
flexibility. Here
the more active
steaming risers enter
drum near water line.
Burners may be lo-
cated in end walls or
between tubes in
buckle of the D, right
angles to drum.
0-type is also a com-
pact steamer. Trans-
portation limits
height of furnace, so,
for equal capacity,
longer boiler is
often required.
Floors of D and 0
types are generally
tile-covered.
Figure 3-19. Watertube design configurations.44
and a large upper drum for steam and water separation. Most steam production occurs in the
center furnace wall tubes entering the drum. The "D" type, the most flexible design and the most
widespread, has two drums and a large-volume combustion chamber that is easy to outfit with
a superheater or economizer. The "O" configuration's symmetry exposes the least amount of
tube surface to radiant heat.11 Figure 3-20 depicts a typical D-type packaged boiler, and its
watertubes, equipped with a single oil/natural gas burner at the end.
332 Oil- and Natural-gas-fired Firetube Boilers
The most common types of firetube boilers used for oil and natural gas firing are the
Scotch, the HRT, the vertical, and the firebox boilers. Available units range from 0.4 MMBtu/hr
(0.1 MWt) to 50 MMBtu/hr (15 MWt) heat input capacity, although most in use in the ICI
sector have capacities below 25 MMBtu/hr (73 MWt).35 These Cretube boilers almost always
employ a single burner rather than multiple burners, and nearly all are packaged units.
Of these four types of firetube designs, the Scotch firetube boiler is the most common.
In a four-pass Scotch boiler, such as that shown in Figure 3-16, the burner is located at the end
of the unit. Combustion gases pass first through the furnace tube, which is an extension of the
3-27
-------
vV_"
i
t
•e
n
,2
w
ee
Cu
3-28
-------
combustion chamber, to the end of the boiler, and then enter firetubes at the bottom of the unit.
The flue gases then flow back toward the front of the unit, and then enter two more systems of
firetubes located above the combustion chamber, before finally exhausting through the stack.
A two-pass Scotch boiler is shown in Figure 3-6; this type of unit ranges from 1 MMBtu/hr to
30 MMBtu/hr (0.3 to 9 MWt) heat input capacity.
Oil- and natural-gas-fired HRT, vertical, and firetube boilers are similar in designs and
capacities to the coal-fired units discussed earlier. They are essentially the same as the coal-fired
firetube units, but differ in that burners rather than stoker systems are used.
33 3 Oil- and Natural-gas-fired Cast Iron Boilers
Although approximately 70 percent of ICI boilers are oil- or natural-gas-fired cast iron
units, these systems comprise only about 10 percent of the total United States ICI boiler
capacity. Two-thirds of these boilers are rated below 0.4 MMBtu/hr (0.1 MWt) heat input
capacity. Most of them are used in the commercial and institutional sectors to provide low-
pressure steam or hot water. Cast iron boilers using oil or natural gas are similar in design to
those described in Section 3.2.3.
3.3.4 Other Oil- and Natural-gas-fired Boilers
Another oil- and natural-gas-fired boiler currently in use is the three-pass vertical
tubeless boiler, shown in Figure 3-21. This boiler consists of a vertical, rigid steel pressure vessel
enclosed inside another pressure vessel, with water in between. This assembly is itself enclosed
within an insulated outer shell. The burner is mounted horizontally at the bottom of the boiler
assembly, firing into the inner pressure vessel, which serves as a large primary radiant furnace.
Flue gases pass up through the inner vessel, and then make second and third passes over
convection fins mounted on the outside of the outer pressure vessel. Heat is transferred to the
water located between the two pressure vessels. This type of boiler is packaged and is available
in heat input capacities ranging from 0.25 to 4.2 MMBtu/hr (0.07 to 1.23 MWt). The largest
units are roughly 6 feet in diameter and 9 feet in height.46
Boilers used in thermally enhanced oil recovery (TEOR) operations are referred to as
TEOR steam generators. These units are typically packaged watertube boilers with heat input
capacities from about 20 to 62.5 MMBtu/hr (5.9 to 18.3 MWt). Steam generators are typically
cylindrical in shape and horizontally oriented, with watertubes arranged in a coil-like design. For
a given size, there is little variability in the design or configuration of oil field steam
generators.47 Figure 3-22 shows a typical oil field steam generator.
3-29
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Figure 3-21. Vertical tubeless boiler.46
3-30
-------
2
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3-31
-------
FBC boilers rely on coal, biomass, wood, and other solid fuels. Natural gas or oil is used
primarily as either a startup fuel to preheat the fluidized bed, or as an auxiliary fuel when
additional heat is required.31'48
3.3.5 Oil Burning Equipment
Natural-gas- and oil-fired boilers often use similar combustion equipment, and in fact,
many units are capable of firing either fuel. The use of fuel oil, however, generally requires
special equipment to "atomize" the fuel before combustion. In some installations, this
atomization equipment may play a key role in the combustion performance of the boiler unit.
To burn fuel oil at the high rates required in most ICI boiler applications, it is necessary that
the oil be atomized or dispersed into the furnace as a fine mist. This exposes a larger amount
of oil particle surface for contact with the combustion air, assuring prompt ignition and rapid
combustion.50 The most common types of atomizers are steam and mechanical atomizers.
Steam atomizers, which may also be used with moisture-free compressed air, are the
most widely used.50 These types of atomizers produce a steam-fuel emulsion which, when
released into a furnace, atomizes the oil through rapid expansion of the steam. Steam atomizers
are available in sizes up to 300 MMBtu/hr (88 MWt) input. The steam and oil pressure
required are dependent on the design of the steam atomizer, although maximum oil pressures
can be as high as 300 psi and maximum steam pressures as much as 150 psi.50 Oil pressures are
much lower than for mechanical atomizers. The steam atomizer performs more efficiently over
a wider load range than do mechanical atomizers.
In mechanical atomizers the pressure of the fuel oil itself is used as the means for
atomization. The oil pressure required at the atomizer for maximum capacity typically ranges
from 600 to 1,000 psi, depending on capacity, load range, and fuel grade.50 Mechanical
atomizers are available in sizes up to 180 MMBtu/hr (53 MWt) input.
The viscosity of the oil is the most important property affecting atomization in
mechanical atomizers.51 As viscosity increases, larger viscous forces must be overcome by the
energy supplied to the nozzle. This detracts from the energy available for droplet breakup,
resulting in coarser atomization and possible adverse affects on combustion efficiency.51 Thus,
for proper atomization and combustion, oil of grades higher than No. 2 must usually be heated
to reduce its viscosity to 135 to 150 Saybolt Universal Seconds.50 Figure 3-23 shows the effect
of temperature on viscosity for No. 2 (distillate) through No. 6 (residual) fuel oils.
3-32
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3-33
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3.4 NONFOSSIL-FUEL-FIRED ICI BOILER EQUIPMENT TYPES
Nonfossil-fuel-fired boilers are commonly used in industries that generate combustible
wastes from their industrial processes. In general, nonfossil-fuel-fired boilers include any boiler
used in the production of steam or hot water from biomass, including wood wastes and bagasse,
and general solid waste, including MSW, industrial solid waste (ISW), and RDF. The following
subsections briefly describe the types of fuels burned and the most common types of nonfossil-
fuel-fired boilers currently in use.
3.4.1 Wood-fired Boilers
Wood wastes are typically burned in boilers used in the paper and allied products
industry, the forest products industry, and the furniture industry. Types of wood wastes are
sawdust, sanderdust, wood chips, slats, and bark. Other sources of wood for fuel include
discarded packing crates, wood pallets, and wood waste from construction or demolition
activities.52 Wood is often cofired with an auxiliary fossil fuel in larger boilers.
Stokers are the most common type of wood-firing systems in the United States. There
are three types, of wood-fired stokers: spreader, overfeed, and underfeed. In design, they are
similar to the coal-fired stokers described earlier, and range from 1.5 MMBtu/hr (0.44 MWt)
to greater than 1,430 MMBtu/hr (420 MWt) heat input capacity. Of larger wood-fired units of
150 MMBtu/hr (44 MWt) heat input capacity or greater, spreader stokers are the most
widespread.53 As in the coal-fired spreader stoker described earlier, fuel enters the furnace
through a chute and is spread pneumatically or mechanically across the furnace, where part of
the wood burns in suspension. The remainder of the fuel lands on a stationary or moving grate,
where it is burned in a thin, even bed. A portion of the combustion air is injected under the
grate to drive off the volatiles and burn the char, while the remainder is fed above the grate to
complete combustion. Most stoker units are equipped with a flyash reinjection system.
Other methods used to fire wood are overfeed and underfeed stoker firing, gasification,
pyrolysis, fuel cell firing, suspension firing, and FBC, though to a lesser degree than spreader
stoker firing. Another type of boiler combustion system, the Dutch oven, is also in use, but has
been essentially discontinued from new construction due to its low efficiency, high construction
costs, and inability to follow load swings.53 The overfeed stoker is the second most common
method of wood firing after the spreader stoker.
Gasification is a method of firing wood waste or other biomass whereby the fuel is
partially combusted to generate a combustible fuel gas rich in carbon monoxide and hydrogen,
3-34
-------
which is then burned. Heat to sustain the process is derived from exothermic chemical reactions,
while the combustible components of the resulting gas are generated by endothermic reactions.54
In essence, a gasification system behaves as a type of biomass burner. One manufacturer offers
flyash gasification systems ranging from 4.2 to 33.5 MMBtu/hr (1.2 to 9.8 MWt) heat input
capacity.
In pyrolysis, an organic fuel is introduced into a high-temperature environment with little
oxygen. Thermal cracking of the fuel occurs, producing combustible gases that are then burned.
One system uses a moving variable-speed grate to introduce the waste fuel to the pyrolytic
gasification chamber, where the fuel is thermally cracked between 1,500 °F and 1,850 °F. The
resulting combustible gases are then fired in an afterburner and the flue gases directed to the
boiler passes. This system is available in heat input capacities from 14 to 57 MMBtu/hr (4.1 to
16.7 MWt).
In a fuel cell boiler, wood is piled on a stationary grate in a refractory-lined cell. Forced
draft air is supplied to drive off the volatiles in the wood and burn the carbon. The volatiles are
mixed with secondary and tertiary combustion air and pass into a second chamber where
combustion is completed.53 Fuel cell boilers range in heat input capacity from 3 MMBtu/hr
(0.9 MWt) to 60 MMBtu/hr (17.6 MWt).
In suspension firing boilers, small-sized wood fuel, such as sanderdust, is typically blown
into the furnace and combusted in mid-air. The small-sized fuels required by these boilers are
typically cleaner and drier than other wood wastes, which can result in increased combustion
efficiency and less ash entering the furnace. However, most of the ash that does enter the
furnace is usually entrained in the flue gas. Most newer boilers utilize a flyash reinjection system
to minimize the amount of unburned carbon in the flyash.
Wood is also fired in FBC boilers, which are detailed in Section 3.2.1.3. In 1991, 10
nonutility FBC boilers below 250 MMBtu/hr (73 MWt) heat input capacity and exclusively firing
wood wastes were in use in the United States.2 These ranged from a 40-MMBtu/hr (12-MWt
or 6-MWe) boiler, at a timber company's cogeneration plant, to a 180-MMBtu/hr (53-MWt or
27-MWe) unit, used by an independent power producer. In an additional 29 units below
250 MMBtu/hr (73 MWt) heat input capacity, wood was fired in combination with other fuels,
such as coal, oil, plastic, and other agricultural wastes. The largest single wood-fired FBC boiler
had an electrical generating capacity of 220 MWe, roughly equivalent to 1,500 MMBtu/hr
(440 MWt) heat input capacity. This unit was operated by an independent power producer, and
3-35
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is atypical in size. The next largest wood-fired FBC in the ICI sector was 345 MMBtu/hr
(100 MWt or 51 MWe) heat input capacity. This is more typical of the ICI wood-fired FBC
boiler range.2
It is fairly common practice to use an auxiliary fuel, particularly fossil fuel, in all types
of wood-fired boilers. Approximately 50 percent of wood-fired boilers have some type of fossil
fuel firing capability.53 Fossil fuels are fired during startup operation, as an augmentation fuel,
or alone when wood fuel is unavailable. Fossil fuels are used more frequently in larger wood-
fired boilers than in smaller boilers below 100 MMBtu/hr (29 MWt) heat input capacity.
Wood-fired boilers are available in both firetube and watertube designs, and are
packaged or field-erected. Typical firetube boilers used in wood firing are the HRT and the
firebox. Wood-fired HRT boilers are usually no larger than 40 MMBtu/hr (12 MWt) heat input
capacity, although some as large as 50 MMBtu/hr (15 MWt) have been built. Wood-fired
firebox units generally range between 2 and 20 MMBtu/hr (0.6 to 6 MWt) heat input capacity.
The firing methods discussed above are used with both firetube and watertube boilers.
Packaged watertube boilers are the most difficult of all boilers to fire with wood waste.
This is because the furnaces of these boilers are relatively cold, with water walls on all sides, and
because the furnaces are very narrow due to shipping requirements. Because of this cold
environment, it is essential that the dry wood particles be small enough to burn out completely
during the time it takes the particles to pass through the furnace. For most packaged watertube
units, the particles should be no larger than 1/64 to 1/32 of an inch, depending upon the heat
release rate.55
3.4.2 Bagasse-Fired Boilers
Bagasse, an agricultural waste, is the fibrous residue left after processing sugar cane.
It is used in sugar industry boilers in Hawaii, Florida, Louisiana, Texas, and Puerto Rico. This
fuel is available on a seasonal basis. Other agricultural wastes include nut hulls, rice hulls, corn-
cobs, olive pits, and sunflower seed hulls.
The earliest type of bagasse-burning furnace was the Dutch oven with flat grates. In this
type of furnace, the bagasse was burned in a pile on a refractory hearth and combustion air
admitted to the pile around its circumference through tuyeres. However, this type of furnace
resulted in high maintenance costs and was essentially discontinued from new installation. A
more commonly used pile burning boiler is the fuel cell, described earlier. In one type of fuel
cell boiler system, the Ward furnace, shown in Figure 3-24, bagasse is gravity-fed through chutes
3-36
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Figure 3-24. Ward fiiel cell furnace.56
into individual cells, where it is burned from the surface of the pile with air injected into the
sides of the pile. Additional heat is radiated to the pile from hot refractory, and corrbustion is
completed in a secondary furnace. This type of design is considered one of the most reliable,
flexible, and simple methods of burning bagasse.56
Recent trends in bagasse firing have been toward using spreader stoker systems.
Bagasse spreader stoker boilers are similar in design to wood-fired spreader stokers, except that
flyash reinjection is not normally used.57 Spreader stokers require bagasse with a high
percentage of fines and a moisture content not over 50 percent.56
Like most other waste-fueled boilers, bagasse-fired units typically use auxiliary fuels such
as natural gas or fuel oil during startup or when additional capacity is required. Most operators
minimize the amount of auxiliary fuel used, and typically less than 15 percent of the total annual
3-37
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fuel heat input to bagasse boilers comes from fossil fuels.57 Bagasse-fired boilers range from
13 to 800 MMBtu/hr (3.8 to 230 MWt) heat input capacity.
3.4.3 Municipal Solid Waste (MSW)-fired Boilers
General solid waste consists of refuse and garbage from municipalities and industries.
Boilers that fire general solid waste are found in manufacturing plants, district heating plants,
municipal heating plants, and electric utilities. As mentioned earlier, general solid waste can be
further classified as MSW, ISW, or as RDF.
MSW is made up of food wastes, rubbish, demolition and construction wastes, treatment
plant wastes, and other special wastes. Combustible rubbish consists of material such as paper,
cardboard, plastics, textiles, rubber, leather, wood, furniture, and garden trimmings. Treatment
plant waste consists of sludge from water, wastewater, and industrial wastewater treatment
facilities. Special wastes are roadside litter, dead animals, and abandoned vehicles. The exact
makeup of MSW varies both seasonally and geographically. For example, more organic material
is usually contained in MSW during the fall, especially in areas such as the northeast where many
trees are deciduous. Typically, over one third of MSW in the United States is paper, with the
next most abundant constituents being food wastes and garden trimmings.58 "
MSW-fired boilers can be categorized by heat input capacity as either small modular
units or large mass-burning facilities. Small modular MSW-fired boilers range from
4.5 MMBtu/hr (1.3 MWt) to 38 MMBtu/hr (11 MWt) heat input capacity, while mass-burning
units are as large as 290 MMBtu/hr (85 MWt).59 Modular units have been in operation in the
United States since the late 1960s, while most existing mass-burning facilities have been
constructed since 1970.
A typical large mass-burning facility rated at 150 MMBtu/hr (44 MWt) heat input
capacity and MSW throughput of 15 tons per hour is shown in Figure 3-25. The facility includes
a waterwall furnace and an overfeed stoker system. MSW is loaded by overhead crane into the
feed chute, which deposits the waste onto the first grate, known as the "dry-out" grate. Ignition
starts at the bottom of the dry-out grate and is continued on a second "combustion" grate.
A third grate, the "burn-out" grate, provides final combustion of the waste before dumping the
ash into the ash pit. Typical thermal efficiencies for this size of mass-burning boiler range
between 60 and 70 percent.60'61 Other variations of mass burn systems besides the waterwall
furnace type are controlled air (pyrolysis) and refractory furnaces. Controlled-air MSW units
3-38
-------
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3-39
-------
received much developmental attention during the 1970s. Many of these units, however, were
subsequently shut down due to operational or economic problems.62
Small modular' units differ from the mass-burning boilers in that they are typically
hopper- and ram-fed instead of crane-fed. These units are packaged and designed to allow
installation of additional units as the need for further capacity increases. A typical modular
boiler, shown in Figure 3-26, utilizes a furnace with a primary and secondary combustion
chamber. MSW is fired at approximately 820CC (1,500°F) in the primary chamber and at
1,040 °C (1,900 °F) in the secondary chamber. An auxiliary burner is used in the secondary
chamber whenever additional heat is required. This particular type of unit is an example of a
controlled-air or "starved-air" boiler, as the air in the primary combustion chamber is below
stoichiometric levels to reduce ash and fuel entrainment.63
3.4.4 Industrial Solid Waste (ISW)-flred Boilers
ISW is composed of those wastes, typically paper, cardboard, plastic, rubber, textiles,
wood, agricultural waste, and trash, arising from industrial processes. The composition of ISW
fuel at any one site is usually relatively constant because the industrial activities that generate
the waste are usually well regulated. The average heating value of ISW is higher than MSW,
about 17,000 kJ/kg (7,100 Btu/lb) compared to 11,000 kJ/kg (4,875 Btu/lb) as fired, and the ash
content is less.64
ISW is fired in the same type of boiler systems as the modular units described above.
These units encompass the same capacity range of the modular MSW-fired boilers, but can also
be as large as 60 MMBtu/hr (17.6 MWt) heat input capacity. Large-mass burning boilers are
not commonly used at industrial facilities; thus, ISW is usually only fired in mass-burning boilers
when it is collected as part of MSW.64
3.4.5 Refuse-derived Fuel (RDF)-fired Boilers
RDF is fuel processed from general solid waste. Unlike MSW and ISW fuels, which are
burned in the same form as they are received at the boiler site, RDF is generated by the sorting
and processing of the general solid waste. Usually, noncombustibles, such as glass and metal, are
removed and recycled, and the remainder of the refuse processed into pelletized or powdered
form. RDF can be burned alone or in combination with coal or oil.54 The most common use
of RDF is as a substitute for part of the coal used in coal-fired stoker and PC boilers. However,
a few stoker units burn RDF alone; these units are similar to standard coal-fired boilers.64
3-40
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and Stack Losses
1.3 HU
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Stack
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5
>ir)
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t
i
b
i ,
I
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i
J
i
Uncontrolled Emissions
PM: 1.4 kg/hr
(3.0 Ibs/hr)
NO-. 1.4 kg/hr
x (3.1 Ibs/hr)
SO.: 2.2 kg/hr
* (4.9 Ibs/hr)f
Steam Output
1.6 HW
(5.5 x 10° Btu/hr)
By-pass Stack
Damper Control'
By-pass Stack
— Damper
MSW Fuel
Heat Input
2.9 MW
(10 x 10° Btu/hr)
Mass Flow Stream
Energy Flow Stream-i- —
Combustion Air
6,530 kg/hr
(14,400 Ibs/hr)
AUXILIARY •UMNCII —
MSW Fuel
Mass Input
930 kg/hr
(2,050 Ibs/hr)
SECONDARY
COMBUSTION
CHAMBER
PRIMARY
COMBUSTION
CHAMBER
Bottom
Ash
279 kg/hr
(615 Ib/hr)
Figure 3-26. Modular MSW-fired boiler.63
3-41
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Both RDF-firing and mass burn systems were commonly used in early U.S. resource
recovery plants. Currently, the majority of U.S. MSW firing units utilize mass burn and not RDF
firing, due in part to the successful experience of mass burn plants in Germany, Switzerland,
Japan, and a number of U.S. locations. Based on the number of plants in operation and the
number being planned in the near future, mass burn is the MSW-firing system of choice,
although RDF firing is still considered a viable technique, especially when refuse throughput is
low to moderate, on the order of a few thousand tons per day.62*65
3-42
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3.5 REFERENCES FOR CHAPTER 3
1. CIBO NOX RACT Guidance Document. Council of Industrial Boiler Owners. Burke,
VA. January 1993. p. 5.
2. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed Combustion Boilers Market
Assessment. Prepared for the Gas Research Institute. Chicago, IL. August 1991.
Appendix A.
3. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. 10.
4. Nonfossil Fuel Fired Industrial Boilers—Background Information. Publication No. EPA-
450/3-82-007. U.S. Environmental Protection Agency. Emission Standards and
Engineering Division. Research Triangle Park, NC. March 1982.
5. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boiler Combustion
Modification NOX Controls, Volume 1: Environmental Assessment. Publication No.
EPA-600/7-81-126a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981. p. 2-1.
6. Surprenant, N. F., et al. (GCA Corp.). Emissions Assessment of Conventional
Stationary Combustion Systems, Volume IV: Commercial/Institutional Combustion
Sources. Publication No. EPA-600/7-81-003b. Prepared for the U.S. Environmental
Protection Agency. Research Triangle Park, NC. January 1981.
7. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. pp. A-l to A-5.
8. Surprenant, N. F., et al. (GCA Corp.). Emissions Assessment of Conventional
Stationary Combustion Systems, Volume V: Industrial Combustion Sources.
Publication No. EPA-600/781-003c. Prepared for the U.S. Environmental Protection
Agency. Research Triangle Park, NC. April 1981.
9. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. A-4.
10. Steam-39th Edition. Babcock &. Wilcox. New York, NY. 1978. p. 25-6.
11. Boilers and Auxiliary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY.
June 1988. p. B-52.
3-43
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12. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. A-12.
13. Ibid. p.A-24.
14. Ibid. pp. A-2toA-3.
15. Ibid. p.A-15.
16. Pacemaker IL Bulletin No. F2350 Rl. Industrial Boiler Co., Inc. Thomasville, GA.
December 1987.
17. The Fabric Filter Manual. The McDvaine Company. Northbrook, IL. May 1985.
Chapter IX. p. 10.01.
18. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. 13.
19. Urn, K. J., et al. (Acurex Environmental Corp.). Industrial Boiler Combustion
Modification NOX Controls, Volume 1: Environmental Assessment. Publication No.
EPA-600/7-81-126a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981. p. 2-4.
20. The Fabric Filter Manual. The Mcllvaine Company. Northbrook, IL. May 1985.
Chapter IX. p. 10.03.
21. Steam-39th Edition. Babcock & Wilcox. New York, NY. 1978. pp. 11-1 to 11-6.
22. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. A-6.
23. Ibid. p.A-8.
24. Boilers and Auxiliary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY.
June 1988. pp. B-28 to B-32.
25. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. 25.
3-44
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26. Lim, K. J., et al. (Acurex Environmental Corp.)- Industrial Boiler Combustion
Modification NOX Controls, Volume 1: Environmental Assessment. Publication No.
EPA-600/7-81-126a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981. pp. 2-11 to 2-13.
27. Boilers and Auxiliary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY.
June 1988. p. B-54.
28. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed Combustion Boilers Market
Assessment. Prepared for the Gas Research Institute. Chicago, IL. August 1991.
pp. 6 to 8.
29. Scott, R. L. Fluidized Bed Combustion: Pressurized Systems. U.S. Department of
Energy. Morgantown, WV.
30. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed Combustion Boilers Market
Assessment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. p.
13.
31. Makansi, J., and R. Schwieger. Fluidized-bed Boilers. Power Magazine. McGraw-Hill,
Inc. New York, NY. May 1987.
32. Gaglia, B. N. and A. Hall (Gilbert/Commonwealth, Inc.). Comparison of Bubbling and
Circulating Fluidized Bed Industrial Steam Generation. Proceedings of the 1987
International Conference on Fluidized Bed Combustion. The American Society of
Mechanical Engineers/Electric Power Research Institute/Tennessee Valley Authority.
New York, NY. 1987.
33. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed Combustion Boilers Market
Assessment. Prepared for the Gas Research Institute. Chicago, IL. August 1991.
pp. 3 to 6.
34. Ibid. p. 21.
35. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. 14.
36. Ibid. p.A-18.
37. Ibid. pp. A-21 to A-24.
38. Fusion Welded Horizontal Return Tubular Boiler To ASME Code. Bulletin No. F3350.
Industrial Boiler Co., Inc. Thomasville, GA.
3-45
-------
39. CB Packaged Boilers. Bulletin No. CBF-178 Rll. Cleaver Brooks. Milwaukee, WI.
December 1986.
40. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boiler Combustion
Modification NOX Controls, Volume 1: Environmental Assessment. Publication No.
EPA-600/7-81-126a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981. p. 2-3.
41. Devitt, T., et aL (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979. p. 15.
42. Govan, F. A. and D. R. Bahnfleth. Boilers and Burners: An Industry in Transition.
Heating/Piping/Air Conditioning Magazine. August 1992. pp. 31-33.
43. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boiler Combustion
Modification NOX Controls, Volume 1: Environmental Assessment. Publication No.
EPA-600/7-81-126a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981. p. 2-38.
44. Ibid. p. 2-26.
45. Packaged Watertube Steam Boilers. Bulletin No. CBW-227 R9. Cleaver Brooks.
Milwaukee, WI. July 1987.
46. Three-pass Vertical Tubeless Boilers. Bulletin No. F2050 990-3.0. Industrial Boiler Co.,
Inc. Thomasville, GA.
47. NOX Emission Control for Boilers and Process Heaters—Training Manual. Southern
California Edison. Rosemead, CA. April 1991.
48. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidizetl Bed Combustion Boilers Market
Assessment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. p.
26.
49. Nutcher, P. B. High Technology Low NOX Burner Systems for Fired Heaters and Steam
Generators. Process Combustion Corporation. Pittsburgh, PA. Presented at the Pacific
Coast Oil Show and Conference. Los Angeles, CA. November 1982.
50. Steam-39th Edition. Babcock & Wilcox. New York, NY. 1978. pp. 7-3 to 7-4.
51. Setter, J. G. Fuel Oil Atomization for Boilers. Report No. 10-173. KVB, Inc. Tustin,
CA. June 1974. pp. 5 to 8.
3-46
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52. Nonfossil Fuel Fired Industrial Boilers—Background Information. Publication No. EPA-
450/3-82-007. U.S. Environmental Protection Agency. Emission Standards and
Engineering Division. Research Triangle Park, NC. March 1982. p. 3-2.
53. Ibid. pp. 3-10 to 3-24.
54. Peavy, H. S., et al. Environmental Engineering. McGraw-Hill Publishing Co. New
York, NY. 1985. p. 671.
55. Wood Waste Burning Systems. Bulletin No. WW-74. Coen Company. Burlingame, CA.
56. Steam—39th Edition. Babcock & Wilcox. New York, NY. 1978. pp. 27-3 to 27-4.
57. Nonfossil Fuel Fired Industrial Boilers—Background Information. Publication No. EPA-
450/3-82-007. U.S. Environmental Protection Agency. Emission Standards and
Engineering Division. Research Triangle Park, NC. March 1982. pp. 3-30 to 3-35.
58. Ibid. p. 577.
59. Ibid. pp. 3-6 to 3-9.
60. Ibid. pp. 3-37 to 3-38.
61. .Ibid. p. 674.
62. The Fabric Filter Manual. The Mcllvaine Company. Northbrook, IL. May 1985.
pp. 325.03 to 325.05.
63. Nonfossil Fuel Fired Industrial Boilers—Background Information. Publication No. EPA-
450/3-82-007. U.S. Environmental Protection Agency. Emission Standards and
Engineering Division. Research Triangle Park, NC. March 1982. pp. 3-43 to 3-44.
64. Ibid. pp. 3-48 to 3-49.
65. Boilers and Auxiliary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY.
June 1988. p. B-57.
3-47
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4. BASELINE EMISSION PROFILES
NOX is a high-temperature byproduct of the combustion of fuels with air. NOX
formation in flames has two principal sources. Thermal NOX is that fraction of total NOX that
results from the high-temperature reaction between the nitrogen and oxygen in the combustion
air. The rate of thermal NOX formation varies exponentially with peak combustion temperature
and oxygen concentration. Fuel NOX is that fraction of total NOX that results from the
conversion of organic-bound nitrogen in the fuel to NOX via a high-temperature reaction with
oxygen in the air. The amount of nitrogen in the fuel, peak combustion temperature, oxygen
concentration, and mixing rate of fuel and air influence the amount of fuel NOX formed. When
low-nitrogen fuels such as natural gas, higher grade fuel oils, and some nonfossil fuels are used,
nearly all the NOX generated is thermal NOX. When coal, low-grade fuel oils, and some organic
wastes are burned, fuel NOX generally becomes more of a factor because of the higher levels of
fuel-bound nitrogen available.
Aside from the physical and chemical characteristics of the fuels, many boiler design and
operating parameters influence the formation of NOX because they impact peak flame
temperatures, fuel-air mixing rates, and oxygen concentrations. Principal among these are the
heat release rates and absorption profiles in the furnace, fuel feed mechanisms, combustion air
distribution, and boiler operating loads. For example, steam pressure and temperature
requirements may mandate a certain heat release rate and heat absorption profile in the furnace
which changes with the load of the boiler. Solid fuels can be introduced into the furnace in
several ways, each influencing the rate of mixing with combustion air and the peak combustion
temperature. These parameters are very unit specific and vary according to the design type and
application of each individual boiler. As described in Chapter 3, ICI boilers include a broad
range of furnace types operating in a variety of applications and burning a variety of fuels
ranging from clean burning natural gas to several types of nonfossil and waste fuels. Thus, NOX
emissions from ICI boilers tend to be highly variable.
4-1
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This chapter discusses the primary factors influencing baseline NOX levels and
summarizes the baseline (uncontrolled) NOX emission levels measured from a variety of ICI
boiler and fuel combinations. Parameters affecting NOX emissions from ICI boilers are discussed
in Section 4.1, while compiled baseline emissions for ICI boilers are presented in Section 4.2 on
the basis of boiler fuel type. Section 4.3 presents a summary of the information presented in this
chapter.
4.1 FACTORS AFFECTING NOX EMISSIONS FROM ICI BOILERS
The ranges in baseline NOX emissions for ICI boilers are due to several factors including
boiler design, fuel type, and boiler operation. These factors usually influence baseline NOX in
combination with each other, and often to different degrees depending on the particular ICI
boiler unit. Thus, wide variations among ICI boiler NOX emissions are common, even among
similar boiler designs or fuel types. These factors are discussed in the following subsections.
4.1.1 Boiler Design Type
The firing type of the boiler influences the overall NOX emission level. For example,
for a given fuel, tangential field-erected units typically have a baseline level less than wall-fired
boilers because of their inherent staging of fuel and air in a concentric fireball: This trend has
been documented for utility-sized boilers.1 Conversely, cyclone units generally have higher NOX
levels than wall-fired units due to their inherent turbulent, high-temperature combustion process,
which is conducive to NOX formation.2 Even within a particular type of boiler, other design
details may influence baseline NOX. For example, in field erected PC wall-fired units, NOX may
vary depending upon whether a wet bottom or dry bottom furnace is used. Wet bottom furnaces
have higher furnace temperatures to maintain the slag in a molten state, leading to greater
thermal NOX formation.3
In comparison, coal stokers have lower NOX emissions than PC-fired units since the
stokers inherently operate in a "staged combustion" configuration.4 Staged combustion, which
is discussed in greater detail in Chapter 5, relies on the reduction of the peak flame zone oxygen
level to reduce formation of fuel NOX, and is achieved by delaying — or staging — the addition
of combustion air. Higher NOX levels reported for spreader stokers are due to a portion of the
fuel burning in suspension with more effective fuel/air mixing and higher combustion
temperatures. In comparison, overfeed and underfeed stokers combust more of the coal on a
grate where combustion is naturally staged, with a fuel rich zone close to the grate and a more
fully mixed zone above the grate. Additionally, underfeed and overfeed units tend to have larger
4-2
-------
fireboxes and, consequently, lower heat release rates, resulting in lower peak temperatures and
lower levels of thermal NOX formation.5
The other major design type of solid-fuel-fired units, FBC boilers, report lower baseline
NOX emissions than similarly-sized wall-, tangential-, or cyclone-fired units, due mostly to the
lower combustion temperatures used in FBCs. In FBC boilers, NOX formation generally peaks
in the lower part of the furnace and is reduced in the freeboard zone, where heterogeneous
reducing reactions between char and NOX occur.6 Also, newer FBC designs are incorporating
combustion air staging in their original configuration to achieve low emissions for permitting in
strict environmental areas. In staged configurations, the lower part of the fluidized bed and
furnace are kept at or below stoichiometry. The staged addition of combustion air results in
lower NOX levels compared to unstaged designs.
Regarding smaller packaged natural-gas- or oil-fired boilers, NOX emissions generally
depend more on fuel, heat release rate and capacity characteristics. In general, ICI boilers with
higher heat release rates and higher capacities tend to have higher levels of NOX. This is
discussed in more detail in Section 4.1.3. For a given heat release rate and fuel type, however,
there is no strong correlation between NOX emissions and whether a packaged boiler is a
firetube or a watertube design.
4.12 Fuel Characteristics
ICI boiler baseline NOX emissions are highly influenced by the properties of the fuels
burned. NOX and other emissions will vary depending on whether natural gas, oil, coal, or
nonfossil fuels are used. Additionally, among each of these fuel types, emissions will depend on
highly variable factors such as fuel grade and fuel source. In particular, studies have shov/n that
fuel nitrogen content — and for coal the oxygen content and the ratio of fixed carbon to volatile
matter — are key factors influencing NOX formation.3'7"9
Much attention has been given to the role of fuel-bound nitrogen in NOX formation.
For any given fuel, only a portion of the available fuel nitrogen is converted during combustion
to fuel NOX. Published data indicate that for coal burning, anywhere from 5 to 60 percent of the
nitrogen is converted, whereas for other fuels as much as 80 percent of the fuel bound nitrogen
is routinely converted.10'11 In general, higher nitrogen fuels such as coal and residual oil have
lower conversion rates, as shown in Figure 4-1, but higher overall NOX rates than lower nitrogen
fuels such as distillate oil.3 The nitrogen content of bituminous coals can vary from as low as
0.8 to as high as 3.5 percent by weight. Fuel oil is normally divided into distillate oil and residual
4-3
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oil. Distillate oil represents the lighter fraction of the distillation process, including No. 2 oil and
diesel oil normally used in residential and commercial heating, internal combustion engines, and
sometimes in larger boilers strictly regulated for SO2 and NOX emissions. Residual oil consists
of the higher temperature fractions and still bottoms from the distillation process, including
No. 4, 5, and 6 fuel oils often used in industrial and some commercial boilers.
Table 4-1 lists the range and average concentrations of nitrogen and sulfur in distillate,
residual, and crude oils. The data were compiled from various sources, including emission test
reports, to illustrate the variability of these fuel properties. Many areas will have oils with
different values, these depending on many factors such as the type of crude, refinery processes
(e.g., hydrodesulfurization), and blending. Clearly, the lighter oils contain much lower levels of
fuel nitrogen and sulfur, thereby contributing significantly lower NOX and SO2 emissions.
Distillate oil normally has less than 0.01-percent nitrogen content, whereas the fuel nitrogen
content of residual oils typically ranges from 0.1 to 0.8 percent by weight, with an average of
0.36 percent based on the data used to compile Table 4-1.
Sulfur content is typically specified when residual oil is purchased. This is done to meet
environmental regulations and to safeguard boiler equipment from acid corrosion. Although
lower sulfur content generally means lower nitrogen, there is no apparent direct relationship
between these two fuel oil parameters, as illustrated in Figure 4-2. Because the deliberate
denitrification of fuel oil is not a refinery practice, significant swings in the nitrogen content of
residual oil occur even when sulfur content is limited to low levels.
The nitrogen content of natural gas can vary over a wide range, from zero to as high as
12.9 percent, depending on the source of the ga?. Nitrogen in natural gas, however, does not
contribute as much to the production of fuel NOX as with liquid or solid fuels, the reason being
that the nitrogen in natural gas is in its molecular form (N2), as in the combustion air. In
contrast, nitrogen in liquid or solid fuels is released in its atomic form (N) and reacts at
relatively low temperatures with oxygen to form fuel NOX.12
Figure 4-3 shows the effect of fuel nitrogen content on total NOX emissions for 26 oil-
fired and 15 coal-fired industrial boiler tests. For the oil-fired tests, in which both residual and
distillate oils were burned, a clear correlation was seen between nitrogen content and NOX, with
higher NOX levels reported for the higher nitrogen content oils. The field tests of coal-fired
units, however, showed no direct correlation between total NOX emissions and coal fuel nitrogen
content, per se.9 Similar results were also reported in a study comparing the use of low-sulfur
4-5
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TABLE 4-1. TYPICAL RANGES IN NITROGEN AND SULFUR CONTENTS OF
FUEL OILS3
Average
Low
High
Standard deviation
Reference
Distillate oil
Nitrogen
<0.01
< 0.001
0.01
0.005
13-15
(No. 2)
Sulfur
0.72
0.20
0.70
0.20
Residual oil (No. 6)
Nitrogen
0.36
0.10
0.80
0.17
9,14,
Sulfur
1.3
0.10
3.5
0.90
16-20
aAll concentrations are percent by weight.
O)
0.8
0.6
O
CD
C 0.4
0)
D)
O
0.2
CD
D
D
D
hD D
D
D
1234
Fuel Sulfur (percent by weight)
Figure 4-2. Fuel oil nitrogen versus sulfur for residual oil. (Data from several
EPA- and EPRI-sponsored tests; see Table 4-1.)
4-6
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1000
900
700
115
EPA PhA»« I Aad 11 46% FVM!
Hitroqen Conversions + 105 opts
TtMZBAl HOX
.6 .8 1.0 1.2
FUEL mi'MJUU CQNTZIir> %
Figure 4-3. Effect of fuel nitrogen content on total NOX emissions.9
4-7
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western coal to the use of eastern bituminous coal in ICI boilers.8 It is believed that while
nitrogen content does play a key role in NOX formation, as was seen in the oil tests, other coal
fuel factors such as oxygen content also influence NOX formation concurrently, masking any
obvious correlation between coal fuel nitrogen and NOX.
This was suggested by test results showing a possible linkage between the ratio of coal
oxygen to coal nitrogen and the amount of NOX formed. Figure 4-4 shows the results of a study
of the effects of the coal oxygen/nitrogen ratio on fuel NOX formation in tangential PC-fired
boilers. The figure shows the relationship between fuel NOX, coal nitrogen content, and the coal
oxygen/nitrogen ratio. The data indicate slightly higher NOX emissions for western sub-
bituminous coal due to the higher coal oxygen/nitrogen ratio, despite the coal's lower fuel
nitrogen content. On a broader scale, coal property data show that coals with high
oxygen/nitrogen ratios generally have lower nitrogen contents. Thus, the two influences — higher
NOX due to higher oxygen content, and lower NOX due to lower nitrogen content — would tend
to balance one another resulting in reasonably similar fuel NOX emissions for a variety of coal
types.7'21
Another major coal factor influencing baseline NOX formation is the fuel ratio, defined
as the ratio of a coal's fixed carbon to volatile matter. Typically, under unstaged combustion
conditions, lower fuel ratios (i.e. higher volatile content of the coal) correlate to higher levels of
NOX, because with higher volatile content coals, greater amounts of volatile nitrogen are released
in the high temperature zone of the flame where sufficient oxygen is present to form NOX.3
Thus, considered by itself, higher volatile coal firing will tend to result in higher baseline NOX
levels.22 It has been shown, however, that firing coal with high volatile content and lower fixed
carbon generally results in less solid carbon to be burned out in the post-flame gases, meaning
* a
that the coal can be fired at lower excess air before combustible losses became a problem. As
discussed in Section 4.1.4, lower excess air requirements generally result in lower NOX emissions.
Thus, the higher NOX levels associated with higher volatile coals may be balanced to a certain
degree by the lower excess air capability provided.
The difference between average NOX emission levels reported among various fuel oil
types (i.e., residual versus distillate) lies primarily in the fact that residual oils are produced from
the residue left after lighter fractions (gasoline, kerosene, and distillate oils) have been removed
from crude oil. Residual oils thus contain high quantities of nitrogen, sulfur, and other
impurities. As discussed, fuels with high nitrogen contents generally produce higher levels of
4-8
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0.6 K
0.5
CO
^ 0.4
i1
£ 0.3
ox
5 °'2
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30 20 15
COAL OXYGEN
COAL NITROCEN
10
NORMAL OPERATION
20% EXCESS AIR
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8
COAL NITROGEN CONTENT. LBS N/106 BTU
2.0
Figure 4-4. Fuel NOX formation as a function of coal oxygen/nitrogen ratio and
coal nitrogen content:
21
fuel-bound NOX than fuels with low nitrogen contents. Thus, with residual oil in particular, fuel
NOX makes up a greater portion of the total NOX emitted. For any particular class of boilers,
the range in NOX emissions for residual oil is often wider than the range of emissions for
distillate oil. The larger amount and variation of fuel nitrogen in the residual oil accounts for
this.23 Even within one type of fuel oil, large variations in NOX emissions can be recorded due
to the other factors discussed in this chapter. The variability in NOX emissions between the
boilers listed in Appendix A burning the same type of oil is chiefly due to variations in boiler
heat release rates and operating conditions.
Besides distillate oil, many nonfossil fuel types are low-nitrogen-content fuels. Thus,
NOX emissions from ICI boilers fired on these fuels and on natural gas are almost entirely
thermal NOX, and the major factors which influence their NOX levels are furnace heat release
rate (related to capacity and operating load) and excess air level, both of which are discussed
below.24 While most wood burning boilers are stokers and are similar in design to coal-fired
4-9
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units, the relatively low nitrogen content of wood contributes to much lower fuel-bound NOX
formation than with coal. In general, with wood wastes the generation of particulates and other
unburned combustibles is more of a concern than NOX formation. The wood moisture content
and wood fuel size are the two most important fuel quality factors influencing those emissions.25
Moisture content also plays an important role in the formation of uncombustible
emissions in MSW firing. By its nature, MSW composition is highly dependent on the net waste
contributions of residential and commercial waste producers, and on seasonal factors which may
impact the amount and type of organic waste produced. For example, a period of high rainfall
can result in increased moisture content in the MSW, with larger quantities of yard waste. These
variables result in wide ranges in MSW composition and corresponding fuel properties. Studies
have shown that the non-combustible content of MSW can range from 5 to 30 percent, the
moisture content from 5 to 50 percent, and the heating value from about 7,000 to 15,000 kJ/kg
(3,000 to 6,500 Btu/lb).26 Nitrogen contents, too, are often highly variable depending on the
source of MSW. Ultimate analyses of MSW from different parts of the United States have
shown nitrogen contents ranging between 0.2 and 1.0 percent.27"31 Thus, emissions from MSW-
fired boilers will also tend to be highly variable.
4.1 J Boiler Heat Release Rate
Boiler heat release rate per furnace area is another influential variable affecting NOX
formation. As heat release rate increases, so does peak furnace temperature and NOX
formation, as illustrated in Figure 4-5. Boiler heat release rate varies primarily with the boiler
firing type, the primary fuel burned, and the operating load.3 Additionally, boiler heat release
rate pei unit volume is often related to boiler capacity, as illustrated in Figure 4-6. For example,
among coal-fired boilers, PC-fired units are typically the largest in capacity. The data in
Appendix A include PC-fired units from 111 to 640 MMBtu/hr (32.5 to 188 MWt) heat input
capacity, whereas the coal stokers listed in Appendix A are generally smaller, ranging in size'
from 3 to 444 MMBtu/hr (0.88 to 130 MWt), with the vast majority being below 200 MMBtu/hr
(59 MWt) capacity. These ranges are fairly representative of the capacity ranges discussed in
Chapter 3. Compared to other coal-fired boiler designs, PC-fired units tend to have larger
capacities, heat release rates, and, as shown by the data in Appendix A, generally higher baseline
NOX levels.
Among stoker units, the largest capacity stokers are spreader stokers as reflected in the
Appendix A data. The majority of spreader stoker data came from units greater than
4-10
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800
Numerals within Symbols
are Test Numbers.
\Gas Fuel
Preheated Air
50 100 150 200 250
Rated Burner Heat Release, MBtu/hr/Burner
Figure 4-5. Effect of burner heat release rate on NOX emissions for coal and natural gas
fuels.16
4-11
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100 MMBtu/hr (29 MWt) in capacity, while the other two stoker types were usually less than
100 MMBtu/hr (29 MWt). While some large underfeed and overfeed stokers are in use in the
ICI sector, these types of stokers commonly have lower heat input capacities, and, as indicated
earlier, tend to have larger fireboxes. Consequently, overfeed and underfeed stokers generally
have lower heat release rates per unit area, resulting in lower peak temperatures and lower levels
of thermal NOX formation than spreaders.5
Because packaged natural-gas- or oil-fired watertube boilers are available in higher
capacities and heat release rates than Cretubes, the high end of the ranges of reported baseline
NOX tends to be greater for the watertube designs. However, as noted in Section 4.1.1, there
is no obvious correlation per se between NOX emissions and whether a boiler is a firetube or a
watertube.
4.1.4 Boiler Operational Factors
In addition to boiler design and fuel factors, the conditions under which a unit is
operated also influence baseline NOX levels. Chief among these operational factors are the
amount of excess oxygen in the flue gases and the combustion air temperature. Excess oxygen
refers to the oxygen concentration in the stack gases, and is dependent on the amount of excess
air provided to the boiler for combustion.33 Combustion air temperature, meanwhile, is
dependent on the degree of air preheat used before the air is introduced into the furnace or
burner. Air preheat is usually used to increase furnace thermal efficiency.
Numerous sources have discussed the typical relationship of excess oxygen levels and
NOX, wherein as excess oxygen increases, so does NO^34"37 This relationship is shown in
Figure 4-7, which presents data for natural-gas-fired watertube and firetube boilers. The thermal
efficiency advantages of operating boilers at low excess oxygen levels have long been known, as
long as the boiler is operated with a certain margin of excess air above the minimum level
required to avoid excessive combustible emissions formation (CO, paniculate). Operation on
low excess oxygen or air is therefore considered a fundamental part of good combustion
management of boilers. However, many ICI boilers are typically fired with excess oxygen levels
which are more than adequate to assure complete combustion and provide a margin of safety
to the operator.38 Thus, these units often are operated at unnecessarily high excess oxygen levels
that result in unnecessarily high NOX emissions and losses in efficiency. Utility boilers, on the
other hand, are typically fired with a smaller safety margin of excess air, but these units are more
4-13
-------
0.4
0.3
0.2
0.1
/
Uatertube boilers with
air preheater
V
Uatertube
boilers
without
air
preheater
Firetube boilers'
I I I
I I I I
01 234 5 6 7 8 9 10 11 12 13
Excess oxygen, percent
Figure 4-7. Effect of excess oxygen and preheat on NOX emissions, natural-gas-fired boilers.
4-14
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closely monitored by operating personnel and are not as subject to such wide variations in load
as ICI boilers.38
Figure 4-7 also shows the effect of using combustion air preheat. As shown, use of air
preheat generally results in higher levels of NOX. The level of combustion air preheat has a
direct effect on the temperatures in the combustion zone, which, in turn, has a direct impact on
the amount of thermal NOX formed. More specifically, the greater degree that the air is
preheated, the higher the peak combustion temperature and the higher the thermal NO^40
Because the air preheat temperature primarily affects thermal NOX formation, the use of air
preheat has its greatest NOX impact on fuels such as natural gas and distillate oils.40'41 Boilers
with combustion air preheat systems are usually larger than 50 MMBtu/hr in capacity, with
preheat temperatures in the range of 120 to 340 °C (250° to 650 °F).41 In particular, many stoker
boilers are equipped with air preheat.
42 COMPILED BASELINE EMISSIONS DATA — ICI BOILERS
This section presents compiled uncontrolled NOX emissions data for ICI boilers. Where
data were available, CO and total unburned hydrocarbon (THC) emissions are also reported.
These baseline data were compiled from test results on more than 200 boilers described in EPA
documents and technical reports. These data are detailed in Appendix A. Emission tests on
these boilers were performed at greater than 70-percent boiler load in most cases.
42.1 Coal-fired Boilers
Table 4-2 summarizes reported baseline NOX, CO, and THC emission ranges for coal-
fired boilers, and lists current AP-42 emission factors for comparison.42"45 Industrial PC-fired
boilers were among the highest emitters of NOX. The emission level from a wet bottom cyclone
fired industrial boiler was recorded at 1.12 Ib/MMBtu. The data for dry-bottom boilers compiled
for this study show a range in NOX emissions from 0.46 to 0.89 Ib/MMBtu. In comparison, AP-
42 shows NOX emissions for dry-bottom boilers in the range of 0.58 to 0.81 Ib/MMBtu.
However, the AP-42 factors include several utility boilers as no distinction is made among
application for this class of boilers. For wet-bottom industrial PC-fired boilers, only one data
point was obtained in this study.
Spreader stoker units averaged 0.60 Ib/MMBtu (450 ppm) NOX from a range of 0.40
to 1.08 Ib/MMBtu (300 to 800 ppm). The other two stoker types, overfeed and underfeed,
averaged 0.29 and 0.36 Ib/MMBtu respectively (215 and 265 ppm). Emission data for spreader
4-15
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4-16
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stokers compiled for this study show generally higher emission levels than suggested by current
AP-42 emission factors.
FBC boilers are typically low NOX emitters compared to PC-fired boilers and most
spreader stokers, as the data indicate. This is due to several reasons, one of which is the lower
combustion temperatures, as discussed in Chapter 3, and the use of staged combustion, as
discussed in Section 4.1. As shown in Appendix A, available industrial coal-fired FBC data
indicate an average NOX emission level of 0.27 Ib/MMBtu (200 ppm), for bubbling bed units,
and 0.32 Ib/MMBtu (240 ppm), for circulating FBC boilers. NOX emissions ranged from 0.11
to 0.81 Ib/MMBtu (80 to 600 ppm), for bubbling bed FBC units, and from 0.14 to
0.60 Ib/MMBtu (105 to 445 ppm), for circulating FBC units. No AP-42 factors are currently
available for industrial FBC boilers.
CO and THC emission data for all types of coal-fired boilers are highly variable.
Average CO emission levels for PC wall-fired and spreader stoker units were generally in
agreement with the AP-42 factors. For PC wall-fired units, CO ranged between 0 and
0.05 Ib/MMBtu (0 to 60 ppm), while for spreader stokers, CO ranged between 0 and
0.53 Ib/MMBtu (0 to 645 ppm). However, the measured CO emission levels for overfeed and
underfeed stokers encompassed much wider ranges than reported in AP-42, ranging from 0 to
1.65 Ib/MMBtu (0 to 2,000 ppm). Likewise, the THC emissions for overfeed stokers also
differed greatly from the AP-42 values, averaging roughly 0.023 Ib/MMBtu (50 ppm). Overfeed
stoker THC data were available for only two units, however. This and the wide range of
reported emission values indicates that available baseline CO and THC data from overfeed and
underfeed stokers are generally inadequate. Circulating FBC boilers tend to have lower CO
emissions than bubbling bed units, ranging from 0.02 to 0.25 Ib/MMBtu (24 to 300 ppm). The
bubbling bed units' CO levels were higher at 0.17 to 0.49 Ib/MMBtu (205 to 595 ppm). The
higher fluidization velocities and recirculation used in the circulating FBC units generally
increase air/fuel mixing and combustion efficiency.
PC-fired boilers tend to emit less CO than stoker units. The data in Table 4-2 show CO
emissions from PC wall-fired and tangential boilers ranging from 0 to 0.14 Ib/MMBtu (0 to
170 ppm). CO emissions from the stoker units listed were higher, ranging from 0 to
1.65 Ib/MMBtu (0 to 2,000 ppm). The use of pulverized coal allows better air/fuel mixing,
increasing the combustion efficiency in the furnace which is evidenced by lower CO. In stoker
units, however, coal combustion takes place on grates, and the combustion air supplied to the
4-17
-------
fuel bed generally does not allow as high combustion efficiencies. Spreader stokers, which burn
some fuel in suspension and the remainder on grates, generally emit less CO than overfeed and
underfeed stokers, although the CO data in Appendix A for underfeed stokers is suspect, as
mentioned above. The combustion temperatures in stokers are also lower than in PC-fired units,
contributing to higher levels of CO.
422 Oil-fired Boilers
Table 4-3 gives baseline emission data for oil-fired ICI boilers, categorized by type of
oil, boiler capacity, and heat transfer configuration. Residual-oil-fired boilers averaged
approximately 0.36 Ib/MMBtu (280 ppm) of NOX, regardless of capacity, with NOX ranging from
0.20 to 0.79 Ib/MMBtu (160 to 625 ppm). Average baseline NOX levels for distillate-oil-fired
units were lower at approximately 0.15 Ib/MMBtu (120 ppm). NOX from the distillate-oil-fired
units ranged from 0.08 to 0.25 Ib/MMBtu (63 to 200 ppm). These data are in general agreement
with AP-42 emission factors.
Reported CO emission levels for residual oil boilers were low, with the majority of units
reporting CO levels below 0.030 Ib/MMBtu (40 ppm). The baseline CO data for distillate-oil-
fired watertube boilers, however, show wide variability, with units in the large capacity (greater
than 100 MMBtu/hr) category emitting anywhere from 0 to 0.84 Ib/MMBtu (0 to 1,090 ppm),
while in the 10 to 100 MMBtu/hr capacity range, units emitted between 0 and 1.18 Ib/MMBtu
(0 and 1,530 ppm). CO emissions from distillate-oil-fired firetube units were low, under
0.015 Ib/MMBtu (20 ppm). High levels of CO emissions from industrial boilers indicate, in part,
poor burner tuning and maintenance levels for many of these units, which are often operated
with little supervision and required maintenance
Reported unburned THC emissions for residual-oil-fired boilers ranged from 0 to
0.031 Ib/MMBtu (0 to 70 ppm), while for distillate-oil-fired units the range was between 0 and
0.022 Ib/MMBtu (0 to 50 ppm). These are in general agreement with current AP-42 THC
emission factors.
423 Narural-gas-fired Boilers
The data base compiled for this study indicated that baseline NOX emission levels for
natural-gas-fired firetube boilers ranged from 0.07 to 0.13 Ib/MMBtu (58 to 109 ppm). For
watertube units, NOX ranged from 0.06 to 0.31 Ib/MMBtu (50 to 260 ppm) for units less than
or equal to 100 MMBtu/hr capacity, and from 0.11 to 0.45 Ib/MMBtu (95 to 375 ppm) for units
greater than 100 MMBtu/hr capacity. As shown in Table 4-4, the low end of the emission range
4-18
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4-19
-------
TABLE 4-4. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH
AP-42 EMISSION FACTORS, NATURAL-GAS-FIRED BOILERS
NO,,
Ib/MMBtu'
Boiler type and
capacity
Firetube units
Watertube units:
<£ 100 MMBtu/hr
> 100 MMBtu/hr
Compiled
data'
0.07-0.13
0.06-0.31
0.11-0.45
AP-42
0.095
0.13
0.26-0.52
CO,
Ib/MMBtu'
Compiled
data
0.0-0.784
0.0-1.449
0.0-0.233
AP-42
0.019
0.033
0.038
THC,
Ib/MMBtu'
Compiled
data
0.004-0.117
0.0-0.023
0.0-0.051
AP-42
0.0076
0.0055
0.0016
To convert to ppm @ 3% O2, multiply by the following: NOX, 835; CO, 1,370; THC, 2,400.
bSee Appendix A for compiled data.
is well below the current AP-42 emission factors. This is due in part to emissions data obtained
at reduced boiler load and emissions from smaller capacity boilers. As illustrated in Appendix A,
NOX emissions from natural-gas-fired boilers tend to increase with increasing boiler capacity.
Baseline CO emission levels show wide variability, ranging from 0 to 1.45 Ib/MMBtu (0
to 1,990 ppm). The data indicate that for natural-gas-fired boilers less than or equal to 100
MMBtu/hr in capacity, CO emissions are often higher than in the current AP-42 emission
factors. THC emissions ranged from 0 to 0.117 Ib/MMBtu (0 to 280 ppm).
4.2.4 Nonfossil-fuel-fired Boilers
Table 4-5 shows AP-42 uncontrolled emission factors for wood waste-, bagasse-, and
general solid waste-fired boilers. AP-42 NOX emission factors for wood-fired units are
' 0.27 Ib/MMBtu (190 ppm), for larger boilers, and 0.065 Ib/MMBtu (50 ppm), for smaller units.
The limited emissions data for wood-fired boilers in Appendix A show an NOX range of 0.010 to
0.30 Ib/MMBtu (7 to 220 ppm corrected to 3 percent O2). Many of these boilers operate
inefficiently with very high excess air levels, at times greater than 5 times the amount required
for complete combustion. Bagasse-fired boilers generally emit low levels of NOX, roughly
0.15 Ib/MMBtu (105 ppm).
Boilers that burn general solid waste typically show higher NOX levels than biomass-
fueled units. The current AP-42 NOX emission factors for MSW-fired units and RDF-fueled
units are 0.4 to 0.49 Ib/MMBtu (280 to 350 ppm) and 0.36 Ib/MMBtu (250 ppm), respectively.
4-20
-------
TABLE 4-5. AP-42 UNCONTROLLED EMISSION FACTORS FOR NONFOSSIL-
FUEL-FIRED BOILERS
NO,, CO, THC,
Fuel and equipment type Ib/MMBtu Ib/MMBtu Ib/MMBtu
Wood Waste:
Units with 50,000 to 400,000 Ib/hr steam
output (-70 to 580 MMBtu/hr heat input)
Units with less than 50,000 Ib/hr steam
output (<70 MMBtu/hr heat input)
Bagasse
General Solid Waste:
Mass burn municipal solid waste
Modular municipal solid waste
Refuse derived fuel
0.27
(0.17-0.30)"
0.022
(0.010-0.050)'
0.15
0.4
0.49
0.36
0.38-4.52
0.38-4.52
NA.b
0.24
0.38
0.26
0.16
0.16
NA.
0.012
NA.
NA.
"Compiled data range, Appendix A.
"NA. = Not available. No data available.
Uncontrolled CO emissions from these boilers are relatively high, 0.24 to 0.38 Ib/MMBtu (280
to 440 ppm). Table 4-6 presents a detailed breakdown of NOX emissions for municipal waste
combustors (MWCs) by major .equipment types. The data come from 52 combustion sources,
each tested over a period of 1 to 3 hours. The average NOX level of 210 ppm corrected to
7 percent O2 translates into approximately 0.4 Ib/MMBtu.
Nonfossil-fuel-fired FBC boilers burning wood waste, manure, and other agricultural
waste byproducts had NOX emissions ranging from 0.10 to 0.42 Ib/MMBtu (70 to 300 ppm). This
is lower than the coal-fired FBC emission levels because of the lower nitrogen contents of the
nonfossil fuels.
AP-42 CO emission factors for all wood-fired boilers span a wide range, from 0.38 to
4.52 Ib/MMBtu (440 to 5,200 ppm), due to several factors, including wood composition and
boiler design type. Unburned THC emissions are significantly higher than levels measured in
fossil-fuel-fired boilers. Reported AP-42 levels are 0.16 Ib/MMBtu (327 ppm), on average.
4-21
-------
TABLE 4-6. AVERAGE NOX EMISSIONS FROM MUNICIPAL WASTE COMBUSTORS2
Combustor type
Mass burn/refractory
Mass burn/rotary waterwall
Mass burn/waterwall
Refuse derived fuel (RDF)
Modular, excess air
Modular, starved air
All types
Capacity
(tons/day)
56-375
100-165
100-1,000
300-1,000
50-120
36-90
36-1,000
Uncontrolled NOX
ppm @ 7%
Range
59-240
146-165
68-370
195-345
105-280
86-280
59-370
emissions,
02
Average
155
156
243
270
140
215
210
aSource of data: Reference 20.
423 Other ICI Boilers
There are limited baseline NOX emissions data for small commercial and institutional
boilers such as cast iron and tubeless units. This is due in part to the virtual lack of regulations
on boilers in the capacity range below 10 MMBtu/hr (2.9 MWt), with the exception of recent
rules adopted in Southern California in 1988 and 1990. Natural gas is the predominant fuel in
this area for these combustion sources. Units of this capacity range, while numerous, have not
historically been regulated due to their size; hence, little testing has been done to characterize
their emissions.
Uncontrolled NOX emissions from natural-gas-fired TEOR steam generators range
between 0.09 and 0.13 Ib/MMBtu (75 and 110 ppm), while for crude-oil-fired steam generators^
baseline NOX emissions generally range from 0.30 to 0.52 Ib/MMBtu (240 to 400 ppm),
depending on the nitrogen content of the crude oil.46'47 Because there is less variability in the
designs and configurations of TEOR steam generators, their NOX emissions, for a given fuel, are
usually less variable than other boilers.
4J SUMMARY
Table 4-7 summarizes baseline NOX emissions for the major ICI boiler equipment
categories discussed in Chapter 3. Coal-fired cyclone boilers generally emit the highest levels
4-22
-------
TABLE 4-7. SUMMARY OF BASELINE NOX EMISSIONS
Fuel
Pulverized coal
Coal
Residual oil
Distillate oil
Crude oil
Natural gas
Wood
Bagasse
MSW
Boiler type
Wall-fired
Tangential
Cyclone
Spreader stoker
Overfeed stoker
Underfeed stoker
Bubbling FBC
Circulating FBC
Firetube
Watertube:
10 to 100 MMBtu/hr.
> 100 MMBtu/hr
Firetube
Watertube:
10 to 100 MMBtu/hr
> 100 MMBtu/hr
TEOR steam generator
Firetube
Watertube:
< 100 MMBtu/hr
> 100 MMBtu/hr
TEOR steam generator
<70 MMBtu/hr
^70 MMBtu/hr
Mass burn
Modular
Uncontrolled
NOX range,
Ib/MMBtu
0.46-0.89
0.53-0.68
1.12a
0.35-0.77
0.19-0.44
0.31-0.48
0.11-0.81
0.14-0.60
0.21-0.39
0.20-0.79
0.31-0.60
0.11-0.25
0.08-0.16
0.18-0.23
0.30-0.52
0.07-0.13
0.06-0.31
0.11-0.45
0.09-0.13
0.010-0.050
0.17-0.30
0.15b
0.40b
0.49b
Average,
Ib/MMBtu
0.69
0.61
1.12
0.53
0.29
0.39
0.32
0.31
0.31
0.36
0.38
0.17
0.13
0.21
0.46
0.10
0.14
0.26
0.12
0.022
0.24
0.15
0.40
0.49
"Single data point.
bAP-42 emission factor.
4-23
-------
of NOX, followed by PC wall-fired units, PC tangential boilers, coal-fired stokers, MSW-burning
units, and crude-oil-fired TEOR steam generators. The lowest NOX emissions are from boilers
fired on natural gas, distillate oil, and wood fuels. NOX emissions from coal-fired FBC and
stoker boilers are generally lower than from PC-fired boiler types. In general, few data are
available for ICI boilers less than 10 MMBtu/hr (2.9 MWt) in thermal capacity, which includes
many fossil- and nonfossil-fuel-fired firetube units, cast iron units, and tubeless types.
With the exception of distillate-oil-fired units, the data show that for a given fuel, NOX
emissions from firetube boilers are lower than from watertube boilers. This is likely due to the
fact that most watertube boilers have larger capacities than firetube units. As discussed above,
as boiler capacity increases, NOX emissions also increase in most cases.
Actual emissions from individual boilers vary widely by boiler heat release rate, fuel
quality and type, boiler design type, and operating factors such as excess air level or load. Fuel
type is a major factor influencing baseline NOX levels. Listed in descending order of NOX
emissions, the fuels are pulverized coal, stoker coal, MSW, crude oil, residual oil, distillate oil,
natural gas, wood, and bagasse. It is important to recognize that large variations in baseline
(uncontrolled) NOX levels are possible due to several boiler design and operational factors,
including variations in the chemical makeup of the fuel. The most important fuel property that
influences NOX is the fuel nitrogen content, which determines to a large degree the amount of
fuel NOX that may be formed during combustion.
4-24
-------
4.4 REFERENCES FOR CHAPTER 4
1. Evaluation and Costing of NOX Controls for Existing Utility Boilers in the NESCAUM
Region. Publication No. EPA-453/R-92-010. U.S. Environmental Protection Agency.
Research Triangle Park, NC. December 1992. pp. 3-5 to 3-6.
2. Yagiela, A. S., et al. (Babcock & Wilcox). Update on Coal Reburning Technology for
Reducing NOX in Cyclone Boilers. Presented at the 1991 Joint Symposium on
Stationary Combustion NOX Control. Washington, D.C. March 1991.
3. Evaluation and Costing of NOX Controls for Existing Utility Boilers in the NESCAUM
Region. Publication No. EPA 453/R-92-010. U.S. Environmental Protection Agency.
Research Triangle Park, NC. December 1992. p. 3-1.
4. Systems Evaluation of the Use of Low-Sulfur Western Coal in Existing Small and
Intermediate-Sized Boilers. Publication No. EPA-600/7-78-153a. U.S. Environmental
Protection Agency. Research Triangle Park, NC. July 1978. p. 30.
5. Fossil Fuel-Fired Industrial Boilers — Background Information. Publication No. EPA-
450/3-82-006a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
March 1982. p. 3-39.
6. State of the Art Analysis of NOX/N2O Control for Fluidized Bed Combustion Power
Plants. Acurex Report No. 90-102/ESD. Prepared by Acurex Corporation for the
Electric Power Research Institute. Palo Alto, CA. July 1990. pp. 3-4 to 3-5.
7. Fossil Fuel-Fired Industrial Boilers — Background Information. Publication No. EPA-
450/3-82-006a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
March 1982. p. 4-127.
8. Systems Evaluation of the Use of Low-Sulfur Western Coal in Existing Small and
Intermediate-Sized Boilers. Publication No. EPA-600/7-78-153a. U.S. Environmental
Protection Agency. Research Triangle Park, NC. July 1978. pp. 16 to 19.
9. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers — Phase II. Publication No. EPA-600/2-76-086a. U.S.
Environmental Protection Agency. Research Triangle Park, NC. April 1976. pp. 164 to
169.
10. Industrial Boiler Combustion Modification NOX Controls, Volume I: Environmental
Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. July 1981. p. 3-4.
11. Evaluation and Costing of NOX Controls for Existing Utility Boilers in the NESCAUM
Region. Publication No. EPA-453/R-92-010. U.S. Environmental Protection Agency.
Research Triangle Park, NC. December 1992. pp. 3-1 to 3-2.
4-25
-------
12. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers — Phase H. Publication No. EPA-600/2-76-086a. U.S.
Environmental Protection Agency. Research Triangle Park, NC. April 1976. p. 218.
13. Field Testing: Application of Combustion Modifications to Control NOX Emissions
from Utility Boilers. Publication No. EPA-650/2-74-066. U.S. Environmental Protection
Agency. Research Triangle Park, NC. June 1974.
14. Emission Reduction on Two Industrial Boilers with Major Combustion Modifications.
Publication No. EPA-600/7-78-099a. U.S. Environmental Protection Agency. Research
Triangle Park, NC. June 1978.
15. Fuel Oil Manual. Industrial Press, Inc. New York, NY. 1969. p. 23.
16. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers — Phase I. Publication No. EPA-650/2-74-078a. U.S.
Environmental Protection Agency. Research Triangle Park, NC. October 1974. p. 136.
17. Thirty-Day Field Tests of Industrial Boilers: Site 2 — Residual Oil-Fired Boiler.
Publication No. EPA-600/7-80-085. U.S. Environmental Protection Agency. Research
Triangle Park, NC. April 1980.
18. The Development of a Low NOX Burner Suitable for High Nitrogen Liquid Fuels.
Prepared by Energy and Environmental Research Corporation under EPA Contract 68-
02-3125. February 1981.
19. Urban, D. L., S. P. Huey, and F. L. Dryer. Evaluation of the Coke Formation Potential
of Residual Fuel Oils. Paper No. 24-543. Presented at the 24th International
Symposium on Combustion. Australia. 1992.
20. Municipal Waste Combustors — Background Information for Proposed Standards:
Control of NOX Emissions. Publication No. EPA-450/3-89-27a. U.S. Environmental
Protection Agency. Research Triangle Park, NC. August 1989. p. 2-1.
21. Fossil Fuel-Fired Industrial Boilers — Background Information. Publication No.
EPA-450/3-82-006a. U.S. Environmental Protection Agency. Research Triangle Park,
NC. March 1982. p. 4-128.
22. Technology Assessment Report for Industrial Boiler Applications: NOX Combustion
Modification. Publication No. EPA-600/7-79-178f. U.S. Environmental Protection
Agency. Research Triangle Park, NC. December 1979.
23. Industrial Boiler Combustion Modification NOX Controls, Volume I: Environmental
Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. July 1981. p. 3-33.
24. Ibid. p. 3-2.
4-26
-------
25. Nonfossil Fuel-Fired Industrial Boilers — Background Information. Publication No.
EPA-450/3-82-007. U.S. Environmental Protection Agency. Research Triangle Park,
NC. March 1982. p. 3-21.
26. Johnson, N. H. and D. C. Reschly (Detroit Stoker Co.). MSW and RDF — An
Examination of the Combustion Process. Publication No. 86-JPGC-Pwr-20. American
Society of Mechanical Engineers. New York, NY. October 1986. p. 5.
27. Peavy, H. S., et al. Environmental Engineering. McGraw-Hill Publishing Company.
New York, NY. 1985. p. 583.
28. Nonfossil Fuel-Fired Industrial Boilers — Background Information. Publication No.
EPA-450/3-82-007. U.S. Environmental Protection Agency. Research Triangle Park,
NC. March 1982. p. 3-39.
29. Municipal Waste Combustion Study. Publication No. EPA/530-SW-87-021c. U.S.
Environmental Protection Agency. Washington D.C. June 1987. p. 3-4.
30. Dennis, C. B., et al. Analysis of External Combustion of Municipal Solid Waste.
Publication No. ANL/CNSW-53. Argonne National Laboratory. Argonne, IL.
December 1986. p. 12.
31. Composition and Properties of Municipal Solid Waste and its Components. Publication
No. DOE/SF/11724-T1. U.S. Department of Energy. Oakland, CA. May 1984. p. 11.
32. Technical Support Document for a Suggested Control Measure for the Control of
Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial Boilers,
Steam Generators and Process Heaters. Statewide Technical Review Group. California
Air Resources Board. Sacramento, CA. April 1987. p. 36.
33. Guidelines for Industrial Boiler Performance Improvement. Publication No. EPA-
600/8-77-003a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
January 1977. pp. 6 to 7.
34. Industrial Boiler Combustion Modification NOX Controls, Volume I: Environmental
Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. July 1981. pp. 3-13 to 3-68.
35. Fossil Fuel-Fired Industrial Boilers — Background Information. Publication No. EPA-
450/3-82-006a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
March 1982. pp. 4-127 to 4-137.
36. Guidelines for Industrial Boiler Performance Improvement. Publication No. EPA-
600/8-77-003a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
January 1977. pp. 38 to 40.
4-27
-------
37. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers — Phase II. Publication No. EPA-600/2-76-086a. U.S.
Environmental Protection Agency. Research Triangle Park, NC. April 1976. pp. 91
to 99.
38. Ibid. p. 91.
39. Industrial Boiler Combustion Modification NOX Controls, Volume I: Environmental
Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. July 1981. p. 3-68.
40. Fossil Fuel-Fired Industrial Boilers — Background Information. Publication No. EPA-
450/3-82-006a. U.S. Environmental Protection Agency. Research Triangle Park, NC.
March 1982. p. 4-117.
41. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers — Phase H Publication No. EPA-600/2-76-086a. U.S.
Environmental Protection Agency. Research Triangle Park, NC. April 1976. p. 146.
42. Compilation of Air Pollutant Emission Factors, Supplement A. Publication No. AP-42.
U.S. Environmental Protection Agency. Research Triangle Park, NC. October 1986.
43. Compilation of Air Pollutant Emission Factors, Supplement B. Publication No. AP-42.
U.S. Environmental Protection Agency. Research Triangle Park, NC. September 1988.
44. Compilation of Air Pollutant Emission Factors, Supplement C. Publication No. AP-42.
U.S. Environmental Protection Agency. Research Triangle Park, NC. September 1990.
45. Compilation of Air Pollutant Emission Factors, Supplement D. Publication No. AP-42.
U.S. Environmental Protection Agency. Research Triangle Park, NC. September 1991.
46. Hunter, S. C. and S. S. Cherry (KVB, Inc.). NOX Emissions from Petroleum Industry
Operations. Publication No. 4311. Prepared for the American Petroleum Institute.
Washington, D.C. October 1979.
47. Technical Support Document for a Suggested Control Measure for the Control of.
Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial Boilers,
Steam Generators and Process Heaters. Statewide Technical Review Group. California
Air Resources Board. Sacramento, CA. April 1987. p. 45.
4-28
-------
5. NOX CONTROL TECHNOLOGY EVALUATION
This chapter presents a survey of applicable control technologies to reduce NOX
emissions from ICI boilers. A review of current knowledge on the effectiveness, applicability,
and limitations of specific control techniques is presented for each major fuel/equipment
category discussed in Chapter 3. These categories are as follows:
• Coal-fired:
— PC, field-erected watertube
— Stoker coal, packaged and field-erected
- FBC
•• Oil-fired:
— Residual oil, packaged and field-erected watertube
— Residual oil, packaged firetube
— Distillate oil, packaged and field-erected watertube
— Distillate oil, packaged firetube
— Crude oil, TEOR steam generator
• Natural-gas-fired:
— Packaged and field-erected watertube
— Packaged firetube
• Nonfossil-fuel-fired:
— Stoker-fed
- FBC
NOX emissions data from more than 200 boilers were compiled from technical reports,
NOX control equipment manufacturer literature, and compliance and rule development records
available at California's South Coast Air Quality Management District (SCAQMD). These data
are tabulated in Appendix B. Most of the data were obtained from boilers operating in the ICI
sectors. However, some small utility boilers were included in the data base of Appendix B
5-1
-------
because their heat input capacities are characteristic of large industrial boilers. The largest unit
for which data are listed is a 1,250 MMBtu/hr PC-fired boiler. However, more than 90 percent
of the units listed in Appendix B have heat capacities less than 400 MMBtu/hr. Most of the
emissions data were obtained during short-term tests. Where noted, test data were collected
from long-term tests based on 30-day continuous monitoring.
The control of NOX emissions from existing ICI boilers can be accomplished either
through combustion modification controls, flue gas treatment controls, or a combination of these
technologies. Combustion modification NOX controls such as SCA, LNB, and FGR modify the
conditions under which combustion occurs to reduce NOX formation. Flue gas treatment
controls—principally SNCR and SCR — are applied downstream of the combustion chamber and
are based upon chemical reduction of already formed NOX in the flue gas. Other gas treatment
controls, besides SNCR and SCR, that combine NOX and SO2 reduction are being developed.
However, these controls are generally expensive and are currently targeted primarily for coal-
fired utility boilers. Several demonstrations of these technologies are underway at electrical
power plants under the U.S. Department of Energy (DOE) Clean Coal Technology (CCT)
demonstration program and other programs sponsored by industry. With the exception of
reburning and SCR-based technologies, these advanced controls are not discussed here because
they are not likely to be applied to the ICI boiler population in the foreseeable future.
In this section, the main discussion of NOX controls for ICI boilers is preceded by
Section 5.1, which presents a brief overview of NOX formation and basic concepts for its
reduction by combustion modifications. Sections 5.2, 5.3, and 5.4 discuss combustion
modification NOX controls for coal-fired boilers, oil- and natural-gas-fired units, and nonfossil-
fuel-fired boilers, respectively. Section 5.5 discusses flue gas treatment controls for ICI boilers.
5.1 PRINCIPLES OF NOX FORMATION AND COMBUSTION MODIFICATION NOX
CONTROL
NOX is formed primarily from the thermal fixation of atmospheric nitrogen in the
combustion air (thermal NOjJ or from the conversion of chemically bound nitrogen in the fuel
(fuel NOX). Additionally, a third type of NOX, known as prompt NO, is often present, though
to a lesser degree than fuel or thermal NOX. For natural gas, distillate oil, and nonfossil fuel
firing, nearly all NOX emissions result from thermal fixation. With coal, residual oil, and crude
oil firing, the proportion of fuel NOX can be significant and, under certain boiler operating
conditions, may be predominant.
5-2
-------
The actual mechanisms for NOX formation in a specific situation are dependent on the
quantity of fuel bound nitrogen, if any, and the temperature and stoichiometry of the flame zone.
Although the NOX formation mechanisms are different, both thermal and fuel NOX are promoted
by rapid mixing of fuel and combustion air. This rate of mixing may itself depend on fuel
characteristics such as the atomization quality of liquid fuels or the particle fineness of solid
fuels.1 Additionally, thermal NOX is greatly increased by increased residence time at high
temperature, as mentioned earlier. Thus, primary combustion modification controls for both
thermal and fuel NOX typically rely on the following control strategies:
• Decrease primary flame zone O2 level:
— Decreased overall O2 level
— Controlled (delayed) mixing of fuel and air
— Use of fuel-rich primary flame zone
• Decrease residence time at high temperature:
— Decreased peak flame temperature:
• Decreased adiabatic flame temperature through dilution
• Decreased combustion intensity
• Increased flame cooling
• Controlled mixing of fuel and air
• Use of fuel-rich primary flame zone
— Decreased primary flame zone residence time
Table 5-1 shows the relationship between these control strategies and currently available
combustion modification NOX control techniques, which are categorized as either operational
adjustments, hardware modifications, or techniques requiring major boiler redesign. The use of
a secondary NOX reduction combustion zone is also included in the table. This strategy is based
on a secondary low oxygen reducing zone where NOX is reduced to N2. This is accomplished
with secondary injection of fuel downstream of the primary combustion zone. This control
technique is referred to as fuel staging, or reburning, and is discussed in greater detail in the
following subsections. Additionally, fuel switching is also considered a viable combustion control
because of the reduction or elimination of fuel NOX with the burning or cofiring of cleaner fuels.
Table 5-2 identifies combinations of NOX controls and major boiler fuel type categories for which
retrofit experience is available and documented.
5-3
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Typically, the simplest boiler operational adjustments rely on the reduction of excess
oxygen used in combustion, often referred to as BT/OT. Figure 5-1 shows the results of several
tests to determine the effect of excess air levels on NOX emissions from natural-gas and oil-fired
firetube boilers.2 These test results show that NOX emissions can be reduced 10 to 15 percent
when the stack excess oxygen concentration is lowered from 5 to 3 percent, measured in the flue
gas on a dry basis. The actual amount of NOX reduced by decreasing excess air varies
significantly based on fuel and burner conditions. These reductions are due mainly to lower
oxygen concentration in the flame, where NOX formation is highest.
Although LEA operation can produce measurable reductions in NOX, in this study, LEA
will not be considered a separate control technology but a part of other retrofit technologies,
since it accompanies the application of low NOX combustion hardware such as low NOX burners.
Additionally, boiler operation with LEA is considered an integral part of good combustion air
management that minimizes dry gas heat loss and maximizes boiler efficiency.3 Therefore, most
boilers should be operated on LEA regardless of whether NOX reduction is an issue. However,
excessive reduction in excess air can be accompanied by significant increases in CO. As
illustrated in Figure 5-2, when excess air is reduced below a certain level, CO emissions increase
exponentially. This rapid increase in CO is indicative of reduced mixing of fuel and air that
results in a loss in combustion efficiency. Each boiler type has its own characteristic "knee" in
the CO versus excess oxygen depending on several factors such as fuel type and burner
maintenance. In general, along with LEA, the application of combustion modifications that
reduce NOX often result in reduced combustion efficiency (manifested by increased CO).
Another operational adjustment listed in Table 5-1, load reduction, when implemented,
decreases the combustion intensity, which, in turn, decreases the peak flame temperature and
the amount of thermal NOX formed. However, test results have shown that with industrial
boilers, there is only slight NOX reduction available from this technique as the NOX reduction
effect of lowering the load is often tempered by the increase in excess air required at reduced
load.4 Higher excess air levels are often required with older single-burner units because high
burner velocity promotes internal gas recirculation and stable combustion. Multiple-burner
boilers generally provide a greater load turndown capability. Operating at reduced load is often
infeasible for many ICI boilers because steam load is dictated by process steam demands and
cannot be controlled independently. Reduced load on one boiler must be compensated for by
increased load on another boiler, unless energy conservation measures permit a net reduction
5-6
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oil-fired watertube industrial boiler.5
in fuel consumption. Therefore, reduced load operation is not considered as a viable retrofit
NOX control technology and will not be discussed further in this report.
Although the formations of fuel and thermal NOX are generally predominant, a tlurd
type of NOX, known as prompt NO, has also been reported. Prompt NO is so termed because
of its early formation in the flame zone where the fuel and air first react, at temperatures too
low to produce thermal NOX. C^ and CH radicals present in hydrocarbon flames are believed
to be the primary sources of prompt NO because they react with atmospheric nitrogen to form
precursors such as HCN and NH3, which are rapidly oxidized to NO. The formation of prompt
NO is greater in fuel-rich flames, and decreases with the increase in local O2 concentrations.
Like fuel and thermal NOX formation, prompt NO formation has been shown to be a function
of flame temperature and stoichiometry. Prompt NO, however, generally accounts for smaller
levels of NOX than are due to thermal or fuel NOX. For example, in utility boiler systems,
prompt NO is assumed to be less than 50 ppm, while the thermal NOX contribution can be as
5-8
-------
high as 125 to 200 ppm.6 In ICI boilers, prompt NO is believed to account for the first 15 to
20 ppm of NOX formed during combustion.7 The control of prompt NO is not typically targeted
because of prompt NO's minor combustion to total NOX. However, as NOX limits for ICI boilers
grow stricter, especially in areas such as the South Coast Air Basin of Southern California, the
control of prompt NO is gaining more importance as evidenced by the development of new
techniques, such as fuel induced recirculation, as discussed in Section 5.5.
The following sections discuss retrofit NOX controls that are commercially available and
the documented experience in NOX reduction performance for each major ICI boiler and fuel
category mentioned earlier.
52 COMBUSTION MODIFICATION NOX CONTROLS FOR COAL-FIRED ICI BOILERS
Coal rank plays an important role in the NOX reduction performance of combustion
control technologies. Typically, controlled limits for low volatile bituminous coal differ from
those attainable when burning high volatile subbituminous coal or lignites. However, the data
available on coal-fired ICI boilers are insufficient to warrant a breakdown of achievable control
levels based on coal type. Nearly all data compiled in this study were for boilers fired on
bituminous coal. In comparison with ICI boilers fired on natural gas or oil, discussed in
Section 5.3, there are relatively few reported emissions data for ICI coal-fired units operating
with NOX controls. This section includes data from 18 field operating PC-fired units, 11 stoker
units, and 10 field operating FBC boilers. Large PC-fired industrial boilers are similar in design
to utility boilers.8 Thus, control techniques applicable to many utility boilers can often be
applied to large industrial boilers as well. Data from three pilot-scale PC-fired facilities are also
included in Appendix B, because their firing capacities are in the ICI boiler range and test results
are considered indicative of the ICI boiler population. Additionally, combustion modification
tests for bubbling bed FBC (BFBC) units include results obtained at pilot-scale facilities. Pilot-
scale research on retrofit combustion modification NOX control for FBC far exceeds published
data on full-scale FBC installations. This is because commercial FBC boilers are relatively new,
the majority having been installed after 1985, and many new units come already equipped with
these controls. Little research on full-scale NOX control retrofit technologies has been
undertaken. Pilot-scale research provides an in-depth view into the mechanisms of NOX
formation and control in FBC. These data are used in this study to support conclusions with
respect to NOX reduction efficiencies and controlled limits.
5-9
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Sections 5.2.1 through 5.2.3 summarize the combustion modification techniques
applicable to the three major coal-fired industrial boiler types: PC, stokers, and FBC units.
52.1 Combustion Modification NOX Controls for Pulverized Coal (PC)-fired ICI Boilers
Table 5-3 summarizes test results of combustion modification techniques applicable to
ICI PC-fired boilers. The table provides the ranges of percent NOX reduction and the controlled
NOX levels achieved in these tests. More detailed data are contained in Appendix B. The
following are brief discussions of each applicable control, the attained NOX reduction efficiency
attained and potential operational limits and impacts of retrofit on existing ICI boilers.
52.1.1 SCA
One approach to reducing NOX, discussed in Section 5.1, is to decrease the primary
flame zone oxygen level. The intent of SCA controls is to achieve a primary fuel-rich flame
zone, where both fuel and thermal NO formations are suppressed, followed by an air-rich
secondary zone where fuel combustion is completed. This is done by injecting air into the
combustion zone in stages, rather than injecting all of it with the fuel through the burner. As
a result, the primary flame zone becomes fuel-rich. SCA for PC-fired boilers includes two main
techniques—OFA and BOOS.
OFA in PC-fired boilers typically involves the injection of secondary air into the furnace
through OFA ports above the top burner level, coupled with a reduction in primary combustion
airflow to the burners. OFA is applicable to both wall-fired and tangential-fired units. OFA is
not applicable to cyclone boilers and other slagging furnaces because combustion staging
significantly alters the heat release profile which changes the slagging rates and properties of the
slag.9 Additional duct work, furnace wall penetration or replacement, and extra fan capacity may
be required when retrofitting boilers with OFA. To retrofit an existing PC-fired boiler with OFA
involves installing OFA ports in the wall of the furnace and extending the burner windbox.
Data for two PC-fired boilers operating with and without OFA were obtained during this
study. Using OFA, a 25 percent reduction in NOX was achieved at the first unit, a tangential-
fired unit at the Kerr-McGee Chemical Corporation facility in Trona, California. This unit was
retrofitted with a separated OFA system in conjunction with an LNB system. Separated OFA
refers to the use of a separate OFA windbox mounted above but not an integral part of the main
windbox, as opposed to "close coupled" OFA which is injected within the main windbox just
above the top elevation of fuel. Controlled NOX emissions from this unit ranged from 211 to
5-10
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280 ppma (0.29 to 0.38 Ib/MMBtu); this unit was also LNB-equipped. The second unit, a
325 MMBtu/hr wall-fired boiler, achieved 15 percent NOX reduction using OFA. Controlled
NOX emissions from this unit were 690 ppm (0.93 Ib/MMBtu). The NOX reduction efficiencies
of these two units are in agreement with OFA performance estimates for PC-fired utility boilers,
which range between 15 and 30 percent NOX reduction.9'10
Two principal design requirements for the installation of OFA ports in an existing PC-
fired boiler must be met in order for the technology to effectively reduce NOX without adversely
affecting operation and equipment integrity. First, there must be sufficient height between the
top row of burners and the furnace exit, not only to physically accommodate the OFA ports but
also to provide adequate residence time for the primary stage NO to reduce to N2, and adequate
residence time for the second stage gases to achieve carbon burnout before exiting the furnace.
In order to maximize NOX reduction, previous studies have shown that the optimum location for
OFA injection is 0.8 seconds (residence time of primary gas before OFA injection) above the
top burner row.11 Additionally, these studies have shown that to achieve carbon burnout, a
minimum of 0.5 seconds residence time is required above the OFA ports.
The second design consideration for OFA retrofit is that good mixing of OFA with the
primary combustion products must be achieved in order to ensure complete combustion and
maximize NOX reduction. Some important parameters affecting the mixing of OFA and first
stage gases are OFA injection velocity, OFA port size, number, shape, and location; and degree
of staging.11 Thus, OFA port design is critical in determining the effectiveness of OFA in
reducing NOX. Additionally, OFA port design must, take into account the effects of port
installation on the sti uctural integrity of the boiler walls. Structural loads may be transferred
from the firing walls to the side walls of the furnace, and OFA port shapes may be designed to
minimize structural modifications. Given the magnitude of retrofitting PC-fired boilers with
OFA and the moderate NOX reduction efficiencies of 15 to 30 percent, OFA does not appear
to be a primary retrofit technology for industrial sized PC-fired boilers. In general, the use of
OFA is considered more feasible for new boilers than for retrofit applications.
The second major technique of staging combustion is BOOS, in which ideally all of the
fuel flow is diverted from a selected number of burners to the remaining firing burners, keeping
firing capacity constant. For maximum effectiveness, it is often the case that the top row of
aAU ppm values in this study are referenced to 3 percent O2.
5-12
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burners be set on air only, mimicking the operation of OFA discussed above (Figure 5-3). For
PC-fired boilers, this means shutting down the pulverizer (mill), as fuel flow cannot be shut off
at the individual burners as can be done with oil- and gas-fired units. This sometimes presents
a problem when pulverizers serve burners located on two separate levels. With PC-firing, BOOS
is commonly considered more of an operating practice for pulverizer maintenance than for NOX
control, as pulverizers are routinely taken out of service because of maintenance requirements.
The ability of boilers to operate units with one less pulverizer is generally very limited. For this
reason, BOOS is not a popular control option for PC-fired units.
Data for two wall-fired units operating with one pulverizer out of service show NOX
reduction efficiencies of 27 and 39 percent. For one 230 MMBtu/hr boiler, NOX was reduced
from 340 ppm to 250 ppm (0.46 to 0.34 Ib/MMBtu), while for a 260 MMBtu/hr unit, NOX was
reduced from 1,065 ppm to 651 ppm (1.44 to 0.88 Ib/MMBtu).12 However, in order to achieve
the 39 percent reduction rate with the larger boiler, it was necessary for that particular boiler
to be operated at 50 percent load reduction. Additionally, airflow could not be easily controlled
to the individual burners so that burner swirl and coal air mixing were affected.12 Operating at
reduced load when using BOOS is often required for industrial sized units due to the limited
number of burners and pulverizers.
In summary, data from three wall-fired boilers operating with SCA techniques of OFA
and BOOS showed NOX reduction ranges of 15 to 39 percent, while the single tangential-fired
boiler with SCA showed 25 percent reduction (see Table 5-3). Although the two units operated
with BOOS accounted for the higher NOX reduction efficiencies of 27 and 39 percent, both had
to be operated at significantly reduced load. Because industrial units have fewer burners and
typically have more limited pulverizer-burner arrangements, BOOS is not considered a widely
applicable control technique.
52.12 LNBs for PC-fired Boilers
LNBs, principally designed for utility boiler applications, have also been retrofitted to
several large industrial boilers over the past decade. All major manufacturers of utility type
boilers offer LNB for PC firing. Some of the larger manufacturers are ABB-Combustion
Engineering, Babcock & Wilcox, Foster Wheeler, and Riley Stoker. In order to achieve low NOX
levels, LNBs basically incorporate into their design combustion techniques such as LEA, SCA,
or recycling of combustion products. One of the most common types of LNB is the staged air
burner.
5-13
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Figure 5-3. Effect of BOOS on emissions.
5-14
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Air staging in this type of LNB is accomplished by dividing the combustion air into two
or more streams within the burner, delaying the mixing of fuel and air. A portion of the air is
used to create a fuel-rich primary combustion zone where the fuel is only partially combusted.
Secondary combustion of this unburned fuel occurs downstream of the primary burnout zone,
where the remainder of burner air is injected. Peak combustion temperatures are also lower
with the staged air burner because flames are elongated and some heat from the primary
combustion stage is transferred to the boiler tubes prior to the completion of combustion. As
discussed in Section 5.1, NOX formation is reduced due to the lowering of the peak flame
temperature, the delayed air/fuel mixing, and the low oxygen primary zone, where volatile fuel
bound nitrogen compounds reduce to form N2. Thus, both thermal and fuel NOX are reduced.
One example of a staged air LNB is Foster Wheeler's Controlled Flow/Split Flame
(CF/SF) LNB, which has been retrofitted to at least two industrial units. The CF/SF burner,
shown in Figure 5-4, is an internally staged dual register burner. The outer register, where
secondary air is injected, controls the overall flame shape while the inner register controls
ignition at the burner throat and the air/fuel mixture in the primary substoichiometric region
of the flame.13 The newer version of the CF/SF burner also incorporates a split flame nozzle
that forms four distinct coal streams. The result is that volatiles are driven off and are burned
under more reducing conditions than would occur without the split flame nozzle.9 CF/SF
burners have been retrofitted to a 110,000 Ib (steam)/hr (about 140 MMBtu/hr heat input)
single wall-fired boiler at a Dupont chemical plant in Martinsville, Virginia. This unit, fired on
bituminous coal, utilizes four CF/SF burners. Nearly 50 percent NOX reduction was achieved,
with average post-retrofit NOX emissions of 280 ppm (0.38 Ib/MMBtu). Post-retrofit CO
emissions were 25 ppm. CF/SF burners were also retrofitted to a 125,000 Ib/hr (about
150 MMBtu/hr heat input) four-burner, wall-fired steam boiler, where 65 percent NOX reduction
from baseline was achieved. Post-retrofit NOX emissions at this site averaged 220 ppm
(0.30 Ib/MMBtu).10 Figure 5-5 shows the NOX reduction performance of these two
units—labeled as numbers 4 and 5 in the figure—as well as several utility sized boilers.
Babcock & Wilcox's DRB-XCL burner also utilizes dual registers to achieve internal
staged combustion. The major elements of this burner are its use of a conical diffuser to
disperse the fuel, which produces a fuel-rich ring near the walls of the nozzle and a fuel-lean
core. Reducing species are formed by partial oxidation of coal volatiles from primary air and
limited secondary air. The reducing zone created in the fuel-lean core prevents NOX formation
5-15
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IGNITOR
FLAME
SCANNER
TANGENTIAL
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Figure 5-4. Foster Wheeler CF/SF LNB.9
(1) 800 MW Four Corners #4
(2) 626 MW Pleasants #2
0 275 MW Front Wall Fired
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1.2r
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(7) 500 MW Opposed Fired
Single Wall Fired Units^
Fired Units
CF/SF Low NOx Burner
so
CF/SF * Advanced OFA
100 150 200 250 300 350 400 450
BURNER ZONE LIBERATION RATE
(10 3 Btu/Hr-Ft 2)
Feittr wn«tl*r Energy C»ip.
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Figure 5-5. Performance of CF/SF LNB.
5-16
10
-------
during devolatilization, and the reducing species generated by oxidation decompose the formed
NOX as combustion continues.14 In a DRB-XCL burner retrofit program to a 220,000 Ib/hr
(about 275 MMBtu/hr heat input) wall-fired boiler at the Neil Simpson Power Station in
Wyoming, average NOX emissions were reduced approximately 67 percent, when operating at
the same excess air level. Controlled NOX emissions for this unit ranged between 190 and
255 ppm (0.26 and 0.34 lb/MMBtu).15
Riley Stoker also manufactures a LNB for PC wall-fired units, known as the Controlled
Combustion venturi (CCV™) burner. Figure 5-6 depicts this burner, which uses a single register,
unlike the dual register burners already discussed. The key element of this burner design is a
patented venturi coal nozzle and low swirl coal spreader located in the center of the burner. The
venturi nozzle concentrates fuel and air in the center of the coal nozzle, creating a fuel-rich zone.
As in the CF/SF LNB, the coal/air mixture is divided into four distinct streams which then enter
the furnace in a helical pattern. This produces very slow mixing of the coal with secondary air,
which is injected through the single register. Devolatilization of the coal in the fuel-rich mixture
occurs at the burner exit in a substoichiometric primary combustion zone, resulting in lower fuel
NOX formation. Thermal NOX formation is suppressed by the reduction- of peak flame
temperature which results from the staged combustion.16
Riley's Tertiary Staged Venturi (TSV) burner is similar to the CCV burner but uses
additional tertiary air and an advanced air staging (OFA) system for reducing NOX emissions.
This burner was developed for use on Riley's TURBO furnaces as well as downfired and arch
fired boilers. These boilers are characterized by downward tilted burner firing, which lengthens
the residence time of combustion products in the furnace. As such, the inherently long furnace
retention time combined with gradual or distributed air/fuel mixing typically results in lower NOX
emissions than a conventional wall-fired unit operating at similar conditions with identical fuel.16
TURBO furnaces are commonly used to burn low volatile coals such as anthracite, which require
longer residence time for complete combustion. Figure 5-7 shows a schematic of a TURBO
furnace and the TSV LNB. Six TSV burners, in conjunction with OFA, were used in a
400,000 Ib/hr (about 470 MMBtu/hr heat input) industrial TURBO furnace at a paper
manufacturing facility in the Midwest. Firing bituminous coals, controlled NOX emissions ranged
between 220 and 370 ppm (0.30 and 0.50 lb/MMBtu).17
A different type of LNB has been developed for tangential-firing PC boilers,
incorporated into the LNCFS system. The burner itself, manufactured by ABB Combustion
5-17
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5-18
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5-19
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Engineering, is referred to as the Concentric Firing System (CFS). The CFS creates local
staging by diverting a portion of secondary air horizontally away from the coal stream toward
the furnace waterwall tabes. This delays the mixing of secondary air with the coal during the
initial coal devolatilization stage of the combustion process, the stage when significant amounts
of fuel nitrogen are typically released. Early ignition and devolatilization are achieved by using
flame attachment coal nozzle tips. This early ignition and flame attachment feature provides
greater control over volatile matter flame stoichiometry while enhancing flame stability and
turndown.18 The boiler at Kerr-McGee Chemical, mentioned in the above discussion on OFA,
has been retrofitted with the LNCFS. Operating with the CFS LNB only, 18 percent NOX
reduction was achieved, to 269 ppm (0.36 Ib/MMBtu). When the full LNCFS was used
(CFS -I- OFA), NOX reduction improved to 55 percent, with NOX at 148 ppm or 0.20 Ib/MMBtu.18
The LNBs discussed were originally designed for use on utility boilers. However, as
evidenced by the above industrial experiences, in most cases the burners are also applicable to
larger industrial PC-fired boilers. In some cases, as with the Neil Simpson unit retrofitted with
B&W DRB-XCL burners, modifications to the burner walls were necessary to accommodate the
larger LNBs. Furnace wall openings of the Neil Simpson unit were enlarged by replacing two
furnace wall tube panels, each containing two burner throats.15 In general, however, because
there are already existing burner ports, LNB retrofits to PC-fired units do not require as much
rework of the furnace walls as does installation of new OFA ports. However, significant
modifications may be required for the windbox in order to improve air distribution with changes
in the fuel ducting. Consideration must also be given to LNB flame characteristics such as shape
and length to avoid flame impingement on the furnace walls. Because flames from staged
combustion burners are often longer than from conventional burners, this may be a particularly
important issue to small-volume furnaces.
NOX emissions data for PC-fired units with LNB are summarized in Table 5-3. For four
wall-fired units, NOX reductions ranged between 49 and 67 percent, with controlled NOX
emissions of 190 to 370 ppm (0.26 to 0.50 Ib/MMBtu). One tangential-fired unit experienced
18 percent reduction efficiency, with an NOX level of 269 ppm (0.36 Ib/MMBtu). Again, the
minimum long-term NOX level that can be reached with LNB retrofit depends on several factors,
principally coal type, furnace dimension, boiler load, combustion air control, and boiler operating
practice.
5-20
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5.2.13 Reburn (Fuel Staging) with SCA, PC-fired Boilers
Reburning, also known as fuel staging, involves injecting a supplemental fuel into the
main furnace above the primary combustion zone to produce a secondary combustion zone
where a reducing atmosphere exists. The general idea is to provide a chemical path for the
primary zone NO to convert to N2 rather than NO2. Hydrocarbon radicals formed during
secondary combustion provide this chemical path; hence, some of the NOX created in the
primary combustion zone is reduced to molecular nitrogen. OFA is utilized in conjunction with
reburning to complete combustion of supplemental fuel. Domestic experience in the ICI sector
is nonexistent.
Reburning has been chiefly developed and applied to larger industrial boilers in Japan.
Mitsubishi Heavy Industries (MHI) has developed the Mitsubishi Advanced Combustion
Technology (MACT) process utilizing oil as the reburn fuel. Use of MACT in a 700,000 Ib/hr
(about 825 MMBtu/hr heat input) tangential-fired boiler at Taio Paper Company in Japan
resulted in a 30-percent NOX reduction to a level of 167 ppm (0.23 Ib/MMBtu), during
bituminous coal firing.19 MACT has been used in at least eight other wall or tangential coal-
fired industrial boilers in Japan, with capacities ranging between 170 and 200 MMBtu/hr. In the
United States, except for several utility demonstration projects and pilot scale test programs,
reburning has not been applied to any commercial facility.20 The results from one pilot-scale
test are included in Appendix B—a test conducted at the 6 MMBtu/hr B&W Small Boiler
Simulator facility.
This test analyzed the NOX reduction efficiencies of reburning in a cyclone furnace with
three types of fuel—bituminous coal, residual oil, and natural gas. With the main burners of the
furnace firing bituminous coal, NOX reduction efficiencies of 54 to 65 percent were achieved.21
Results showed that reburning with natural gas produced the best NOX reduction and the lowest
average NOX emissions, between 235 and 420 ppm (0.32 and 0.57 Ib/MMBtu). This was due to
the low nitrogen content of natural gas. Use of natural gas as the reburning fuel also brings the
added benefit of reducing SO2 emissions. The use of coal as a reburn fuel resulted in the lowest
NOX removal efficiency. In general, the data suggest that the cleaner the reburn fuel, the more
efficient the reburn process.
Prior to this pilot test, B&W had conducted a feasibility study of applying natural gas
reburn technology to cyclone-fired boilers. Cyclone boilers are currently being used in both the
utility and industrial sectors. Because cyclone boilers have a unique configuration that prevents
5-21
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the application of standard low-NOx burner technology—combustion occurs within a water-cooled
horizontally-tilted cylinder attached to the outside of the furnace—this study sought to assess the
feasibility of retrofitting existing cyclone furnaces with reburn controls. Reburning technology
prior to the pilot scale test had never been applied to cyclone-equipped boilers. From an
industrial boiler standpoint, the most important result of this study was the conclusion that in
general, it is unfeasible to retrofit cyclone boilers below 80 MWe capacity with natural gas reburn
controls, which essentially excludes all but the largest industrial cyclones.16 The reason for this
is that cyclone units below this size range generally have insufficient furnace height to allow
sufficient residence time for reburn and OFA to work effectively. For a 41 MWe boiler, it was
determined that the furnace would have to be extended by over 50 percent, which is
impractical.16 From this study, it appears that gas reburn is most applicable to larger existing
cyclone boilers.
Thus, reburn technology is generally not applicable for retrofit to smaller cyclone boilers
in the ICI sector because of insufficient furnace heights. For wall-fired and tangential-fired units,
however, natural gas or coal reburn may emerge as a viable NOX control technique for industrial
PC-fired units as indicated by utility demonstrations.
52.1A LNBwithSCA
The use of LNBs with SCA (OFA) in PC-fired boilers combines the effects of staged
burner combustion and staged furnace combustion. ABB-CE, B&W, and Foster Wheeler offer
OFA with LNB systems for retrofit. OFA is an integral part of ABB-CE's LNCFS NOX
reduction package for tangential-fired boilers, and in fact is responsible for the majority of NOX
reduction achieved.18 As mentioned earlier, in the Kerr-McGee boiler in Califorria, 55 percent
NOX reduction was achieved with the LNCFS, combining OFA and the CFS LNB. Note that
the NOX reduction efficiencies for combined control techniques are not additive.
Emissions data for seven wall-fired units using LNB and SCA controls show NOX
reductions in the range of 42 to 66 percent (see Table 5-3). No baseline data were reported,
however, for one of the seven units. This reduction range reflects LNB and SCA performance
for six boilers. The 66 percent reduction efficiency was obtained on an industrial size
250 MMBtu/hr unit at Western Illinois Power Cooperative's (WIPCO) Pearl Station. Field tests
showed that under normal operation, 50 percent reduction of NOX was typically achieved while
under carefully controlled conditions, the 66 percent NOX reduction level was possible. Retrofit
of four distributed mixing burners with tertiary air ports required replacement of the front wall,
5-22
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modifications to the windbox, replacement of the burner management system, and provision of
an alternative support structure for the hopper.22 Because of the extensive boiler modification
required for this particular LNB + SCA system, it is generally intended for use in new boiler
designs rather than in retrofit applications.
Controlled NOX levels for these wall-fired units ranged between 180 and 370 ppm
(0.24 and 0.50 Ib/MMBtu). Generally, on utility boilers, NOX reduction performance for this
combination of controls can reach as high as 65 or 70 percent.23 Thus, for large (greater than
250 MMBtu/hr) industrial boilers, this may be the maximum reduction achievable as well.
However, insufficient data for PC-fired ICI boilers using LNB and SCA precludes reaching any
definitive conclusions.
522 Combustion Modification NOX Controls for Stoker Coal-fired ICI Boilers
The two most commonly used combustion modification NOX controls for stoker coal-
fired ICI boilers are SCA and FOR. A third combustion modification, RAP, has not been
utilized as often. Gas cofiring with burners above the grate is under active evaluation. Table 5-4
summarizes the data compiled for stoker coal-fired ICI boilers with combustion modification
NOX controls. Available data are limited to 12 stoker units. The data show wide variability in
NOX control efficiency, ranging from -1 to 60 percent reduction. Controlled NOX levels for
spreader stokers with SCA ranged from 230 to 387 ppm (0.31 to 0.52 Ib/MMBtu), while for
spreaders with FGR+SCA, NOX ranged from 140 to 350 ppm (0.19 to 0.47 Ib/MMBtu). Data
were available for only one spreader unit with RAP. This unit had a controlled NOX level of
219 ppm (0.30 Ib/MMBtu).
522.1 SCA
Stoker units naturally operate with a form of staged combustion due to their design. As
the coal is fed onto the grate, volatile matter is driven from the fuel bed and burned above the
bed level. The coal solids remaining are subsequently burned on a bed with lower combustion
intensity. Because of this natural staging, NOX emissions from stoker units are generally lower
than those from PC-fired units of the same size.24 As presented in Appendix A, uncontrolled
NOX emissions ranged from 341 to 659 ppm (0.46 to 30.89 Ib/MMBtu) during nine tests of PC
wall- and tangential-fired units ranging in size from 100 to 200 MMBtu/hr. For eight tests of
similarly sized stoker units, uncontrolled NOX levels ranged from 158 to 443 ppm (0.21 to
0.60 Ib/MMBtu).
5-23
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The availability of existing OFA ports offers the opportunity for increased air staging.
Additional staging can be achieved by injecting more overfire air above the fuel bed while
reducing the undergrate airflow. Using OFA, the boilers for which data were collected show a
NOX reduction range of zero to 35 percent, averaging 17 percent reduction. In two boilers, OFA
did not affect NOX. Controlled NOX emissions ranged from 230 to 400 ppm (0.31 and
0.54 Ib/MMBtu) for the spreader stokers tested and 166 to 202 ppm (0.22 to 0.27 Ib/MMBtu)
for the overfeed stokers. No data were collected for underfeed stoker type boilers in this study.
Many older stokers incorporate OFA ports as smoke control devices. Therefore, these
OFA ports may not be optimally located for NOX control purposes. For example, in one test,
injection of OFA through oil burner ports high above the grate reduced NOX by 25 percent.
When OFA was injected through the actual OFA ports located closer to the grate, only
10 percent reduction was achieved.25
Because the use of SCA in stoker boilers requires reduced undergrate air flow for
staging, there are certain operational limitations involved. First, with the exception of a water-
cooled vibrating grate, the only grate cooling mechanism used in stoker units is the flow of
combustion air under the grate. During SCA operation, if undergrate air is lowered too much,
the grate can overheat. There is also the possibility of creating local reducing zones with low
oxygen which may form harmful corrosion products.25 Still another problem that may arise from
reduced undergrate air firing is the formation of clinkers. For coals with low ash fusion
temperatures, significant clinker formation can be caused by the excessively high bed
temperatures resulting from combustion with insufficient amounts of excess air.26 Thus, a
minimum amount of undergrate air must be used to provide adequate mixing and cooling. As
such, there is a limit to the degree of OFA used in stoker boilers and consequently achievable
NOX reduction.
5222 FGR with SCA
The requirements of mixing and cooling when using SCA can be met to a certain degree
by recirculating a portion of the flue gas to the furnace and mixing it with the fresh combustion
air. One effect of FGR in stoker units is that recirculated flue gas dilutes the oxygen
concentration of the combustion air, allowing boiler operators to lower the overall excess air level
which consequently reduces formation of NOX. FGR is primarily considered a thermal NOX
control technique, reducing NOX by lowering the peak furnace temperature. Because
5-25
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temperatures in ICI stoker units are lower than in PC-fired units, thermal NOX control has not
been as high a priority for stoker coal-fired boilers.
Figure 5-8 depicts a schematic of a stoker boiler equipped with FGR. Flue gas is drawn
from the entrance of the stack and mixed with the undergrate combustion air. This type of FGR
system was used in a 100,000 Ib/hr (125 MMBtu/hr heat input) spreader stoker fired on
bituminous coal. Test results from this boiler illustrate the effect of FGR on allowable excess
oxygen and consequently, its effects on NOX. In this unit, minimum excess oxygen levels and
boiler load were restricted by opacity. To prevent opacity from reaching unacceptable levels,
pre-retrofit load was limited to 80 percent of capacity and the boiler was operated at minimum
stack excess oxygen of 8 percent. Figure 5-9 illustrates the effect of adding FGR to the boiler
on allowable excess oxygen. After retrofit, boiler operators could lower excess oxygen levels to
as low as 3 percent, keeping opacity the same as pre-retrofit levels. Not only does this represent
a significant increase in boiler efficiency, but because NOX is dependent on the excess oxygen
used, lower emission levels were achieved, as shown in Figure 5-10. Thus, at a constant load of
80 percent, using FGR allowed the excess oxygen level to be reduced from 8 percent to
approximately 3.5 percent, resulting in a reduction of NOX by as much as -60 percent. A
controlled emission level of 140 ppm (0.19 Ib/MMBtu) was measured.27 Another spreader
stoker unit also displayed similar characteristics when operated with FGR, experiencing
13 percent NOX reduction. Less reduction was achieved in this unit because excess air was not
reduced as much.26 In a third spreader stoker, however, no NOX reduction was achieved using
FGR, since initial excess oxygen levels were already quite low at 4 percent. FGR did not allow
the boiler operators to reduce oxygen concentration, thus resulting in no measurable change in
NOX emissions.26
FGR was also applied to an overfeed stoker, but test results showed the use of FGR on
this boiler to be unsatisfactory. Unlike spreader stokers which utilize the entire length of the
grate for primary combustion, overfeed stoker units often have shorter active grate combustion
zones depending on the location of the furnace wall arch over the grate, as shown in Figure 5-11.
The particular boiler tested had a very short active combustion zone limited to the front half of
the grate, due to the location of its furnace arch. The lowering of excess oxygen in the
combustion air with FGR caused the active combustion zone to lengthen beyond the furnace
arch, resulting in flame quenching and impingement on the arch. Also, FGR caused unstable
combustion at the front portion of the active combustion zone.2 In contrast with overfeed
5-26
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Figure 5-8. Schematic diagram of stoker with FGR.27
5-27
-------
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Figure 5-9. FGR effects on excess O2
27
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MODIFIED
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Figure 5-10. NO emission versus excess O2, stoker boiler with FGR.
5-28
12
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Figure 5-11. Overfeed stoker with short active combustion zone.26
5-29
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stokers, FGR's effect of lengthening the active combustion zone in spreader stokers is of little
consequence because the length required for the coal to burn out is much shorter than the length
of the fuel bed.27
In summary, the use of FOR in stoker coal-fired ICI boilers has been demonstrated
successfully in a limited number of boilers. NOX reduction on two of the spreader stokers ranged
from 13 to 60 percent. For the overfeed stoker unit, FOR caused unsatisfactory combustion
conditions including flame quenching, flame impingement, and unstable combustion. The
primary effect of FGR is to allow reduction of the excess oxygen level of the boiler, thereby
reducing NOX emissions and increasing boiler efficiency. FGR has also been shown to be
beneficial in dealing with grate overheating.
5223 RAP
RAP is limited to stokers equipped with combustion air preheaters. Usually only larger
stokers with heat input capacities greater than 100 MMBtu/hr tend to have air preheaters.28
RAP is not commonly used in such boilers because significant losses in boiler efficiency occur
when the flue gas bypasses the air preheaters. In bypassing the preheaters, recoverable heat
from the flue gas is not utilized and the temperature of the flue gas leaving the stack is increased
unless major equipment modifications are made to the heat transfer surfaces. Available
emissions data for RAP is limited to one spreader stoker boiler. Reduction of preheated
combustion air temperature reduced NOX by 32 percent.28 Because of its limited applicability
and negative effects on boiler efficiency, RAP is not considered a primary NOX control method
for stoker coal-fired ICI boilers.
522.4 Natural Gas Cofiring
Gas cofiring for stokers has only recently been investigated for improving boiler
operation and reducing emissions. The technique involves burning a fraction of the total fuel,
typically 5 to 15 percent, as natural gas above the grate. The cofiring improves boiler efficiency'
through reduced excess air, lower LOI in ash, and reduced flue gas exit temperature. The
reduced excess air lowers NOX levels. Recent tests on a spreader stoker have shown that NOX
emissions can be reduced by 20 to 25 percent.29 More tests are planned.
523 Combustion Modification NOX Controls for Coal-fired Fluidized-bed Combustion (FBC)
ICI Boilers
In FBC boilers, the fuel is burned at low combustion temperatures, 790 to 900 °C (1,450
to 1,650 °F). At these low temperatures, NOX formation is limited to the conversion of fuel
nitrogen (fuel NOx). At these low combustion temperatures, studies have shown little correlation
5-30
-------
between temperature and NOX emission, thus combustion modification NOX controls for FBC
boilers focus on the control of fuel NOX.30>31 The principal combustion modification controls
used for NOX reduction in FBC boilers are staged combustion, control of bed temperature, and
FGR. Table 5-5 summarizes the performance and process requirements of these three
techniques. Each of these control approaches is discussed in the following subsections. Process
variables that impact NOX formation are also discussed. As indicated earlier, most combustion
modification research for FBC has been conducted on pilot scale facilities. Available data from
full-scale units are limited; thus, the pilot-scale data offer the greatest insights into the control
mechanisms and NOX reduction potential of these controls.
5.2.3.1 SCA in Coal-fired FBC Boilers
SCA is widely accepted as the most effective combustion modification control for
reducing NOX from FBC boilers. Nearly all new commercial FBC units come equipped with
overfire air ports along the freeboard section of the combustor to inject secondary and
sometimes tertiary combustion air.32 The primary objective of using SCA in an FBC boiler is
to reduce NOX formation by operating the fluidized bed of a bubbling FBC (BFBC) boiler, or
the lower portion of a circulating FBC (CFBC) boiler under substoichiometric conditions.
Additionally, secondary air injection at high levels in the furnace help ensure good carbon, CO,
and hydrocarbon burnout.33
SCA is generally more effective for high to medium volatile coals than for low volatile
fuels such as anthracite. High-volatile-content fuels, also described as high-reactivity fuels
(reactivity being defined as the ratio of volatile matter to fixed carbon), contain larger amounts
of fuel nitrogen in the volatile matter. When introduced *o the combustor, these fuels undergo
thermal decomposition and quickly release the organically bound nitrogen in the volatile matter,
whereupon it combines to form NO in the presence of oxygen. By using SCA, which lowers the
excess oxygen level in the dense portion of the fluidized bed, this conversion of volatile nitrogen
to NO is suppressed. For lower volatile fuels, the amount of fuel nitrogen in the volatile fraction
is also lower. For these fuels, conversion of char nitrogen to NOX dominates the overall fuel
NOX, and nitrogen is released at a much slower rate which is a function of the char combustion
rate. Thus, SCA has less of a NOX reducing effect for these lower reactivity fuels.33
NOX reductions due to SCA in coal-fired FBC boilers have been reported on the order
of 40 percent for full scale units in the ICI sector.34 For example, Figure 5-12 shows the effects
of SCA on NOX and CO emissions for a 16 MWe BFBC boiler firing bituminous coal at
5-31
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Chalmers University in Sweden. Keeping the total excess air between 20 and 23 percent, NOX
was reduced 40 percent from 125 to 75 ppm (0.17 to 0.10 Ib/MMBtu) when 20 percent of the
total air supply was injected through OFA ports. When the proportion of air injected as
secondary air was increased to 25 percent, NOX reduction from baseline was only slightly more
than 40 percent. Meanwhile, CO emissions more than doubled from a baseline level of 270 ppm
to 565 ppm.34 NOX reduction efficiencies of as high as 60 to 70 percent have also been reported
in several pilot-scale tests.32 For instance, at the TNO Research facility in Sweden, tests
conducted on a 14 MMBtu/hr BFBC unit with SCA showed 67 percent NOX reduction.35 Pilot-
scale tests, however, generally involve much higher amounts of staging—i.e., lower primary zone
stoichiometries—than are practically achieved in full scale units, due to concerns over combustion
efficiency, corrosion of watertubes, and refractory integrity.
Besides the amount of SCA used and fuel type, the location of the OFA ports can also
have a significant impact on NOX reduction. Several tests have shown that the greater the
distance to the secondary air ports, the greater is the NO suppression.36"38 This is due to the
5-33
-------
increased residence time between the primary and secondary air injection stages. However,
there are practical limits on how high in the freeboard the OFA can be introduced without
affecting combustion efficiency, corrosion, and steam temperature control. Additionally, because
of the different rates of fuel nitrogen conversion for low- or high-reactivity coals mentioned
earlier, in order to maximize NOX reduction the optimal secondary air location must be
specifically designed for each type of fuel used, as well as for fuel with different size
distributions.
Reported NOX emission levels for FBC units with SCA have been highly variable
depending on the capacity, fuel type, OFA port location, and design type (i.e., CFBC or BFBC)
of the boilers. For instance, controlled NOX emissions from a 222 MMBtu/hr CFBC unit fired
on bituminous coal ranged from 51 to 335 ppm (0.07 to 0.45 Ib/MMBtu), while an identical unit
fired on brown coal emitted 103 to 155 ppm (0.14 to 0.21 Ib/MMBtu) of NOX.33 Another CFBC
unit,' rated at 140 MMBtu/hr and firing bituminous coal, emitted 280 ppm (0.38 Ib/MMBtu)
NOX.39 Data obtained for full-scale units showed controlled NOX emissions ranging from 39 to
335 ppm for five CFBC boilers, and 75 to 100 ppm for two BFBC units. These data are
tabulated in Table 5-6. Other sources have reported practical NOX limits achieved with SCA to
be between 80 and 130 ppm (0.11 and 0.18 Ib/MMBtu) for CFBC and 100 to 200 ppm (0.14 to
0.27 Ib/MMBtu) for BFBC boilers.32
5232 Bed Temperature Control
The temperature within FBC boilers is determined primarily by the combustion
requirements of the coal and the temperature required to maximize sulfur capture. The
optimum temperature range for sulfur capture is 800 and 850°C (1,470 to 1,560°F).40 In this
range, the sulfur capture can be as high as 98 percent depending on the Ca/S ratio, sorbent
reactivity and size, residence time, and ash recirculation rate.
Low bed combustion temperature lowers the formation of thermal NOX. The effects of
bed temperature on NOX formation for a pilot-scale BFBC was reported to be about 2 to 3 ppm
NOX reduction for every 10°C in temperature drop.41 Figure 5-13 shows this effect, as well as
the bed temperature's effect on CO emissions, which increase as temperature is lowered. The
effects of bed temperature on NOX and CO are shown in Figure 5-14 for the full-scale 16 MWe
BFBC test unit at Chalmers University, showing 54 percent NOX reduction when bed
temperature was lowered from 880 to 780°C (1,620 to 1,440°F). This equates to 13 ppm NOX
reduction per 10 °C temperature drop, a greater effect than was experienced with the pilot-scale
5-34
-------
TABLE 5-6. REPORTED CONTROLLED NOX EMISSION LEVELS, FULL-SCALE,
COAL-FIRED FBC BOILERS
Control technique FBC boiler type
Controlled NOX level,
ppm @ 3% O2,
Ib/MMBtu
SCA
FGR+SCA
Circulating
Circulating
Circulating
Circulating
Circulating
Bubbling bed
Dual bubbling bed
Circulating
Circulating
39-245 (0.05-0.33)
51-335 (0.07-0.45)
100 (0.14)
103-155 (0.14-0.21)
280 (0.38)
75 (0.10)
100 (0.14)
90-116 (0.12-0.16)
100-115 (0.14-0.16)
200
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S
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S
S
Key Odenotes NOx, Key A denotes CO.
800
900 1000 1100
Mean Temperature of Fluidized Bed (X)
2000
1000
1200
Figure 5-13. NOX and CO versus bed temperature, pilot-scale BFBC.'
41
5-35
-------
NOx (ppm @ 3% 02)
250
200
150
100
50
CO (ppm @ 3% O2)
600
500
400
300
200
100
1620F 1530 F
Bed Temperature
S Nitrogen Oxide O Carbon Monoxide
1520 F
Figure 5-14. Effect of bed temperature on NOX and CO, Chalmers University.34
unit. The difference in temperature dependence is most likely due to differences in furnace
geometry and the type of coal used. Unlike the pilot-scale results shown in Figure 5-13, CO
emissions at Chalmers did not increase with lowered bed temperature, remaining fairly constant
at 270 ppm.34 For a CFBC pilot unit, the effect of bed temperature on NOX reduction was
8 ppm reduction per 10°C.42 Similarly, tests conducted at the former 110 MWe CFBC Nuclear
Power Station showed roughly 10 ppm NOX reduction per 10°C temperature drop in the bed.4
Although lowering bed temperature has shown measurable reductions in NOX, the
lowering of bed and freeboard gas temperatures is not considered a primary NOX control
method. Steam temperature control, sulfur capture, and combustion efficiency usually do not
allow bed and freeboard temperatures much lower than 815°C (1,500°F).40 Under staged
combustion, lower bed and freeboard temperatures are not generally desired since temperature
affects the rate of gas-solid catalytic reactions intended to reduce NOX.
5-36
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5233 FGR in Coal-fired FBC Boilers
FOR through the air distribution plate in a FBC boiler is not a widely accepted NOX
control technology, or one that has received much research effort to date.40 In general, FGR
allows operation with reduced combustion oxygen levels in the dense portion of the bed,
contributing to NOX reduction. To some extent, FGR also reduces thermal NOX by lowering the
peak combustion temperature. When FGR is used in combination with SCA, the primary
mechanism that results in NOX reduction is the gas temperature drop in the lower portion of the
bed combined with a localized reduction in the oxygen concentration. However, thermal NOX
reduction in FBC is not as high a priority as the control of fuel NOX. FGR application in FBC
has been limited for the most part to pilot scale research. However, test results reported for two
full scale CFBC units with SCA and FGR show a marked NOX reduction efficiency of nearly
70 percent for FGR rates in excess of 30 percent. Controlled NOX emissions ranged from 90 to
116 ppm (0.12 to 0.16 lb/MMBtu).33 These data are listed in Table 5-6 and in Appendix B.
Several disadvantages of applying FGR to CFBC units have been identified33:
• Combustion efficiency and sulfur retention are generally lowered
• Larger combustor, backpassing boiler chamber, greater baghouse capacity, and fan
size are required
• Greater power consumption is required for additional equipment
• Boiler capital and operating costs are increased
Because of these potential adverse side effects, FGR is generally not considered a viable NOX
control technology for FBC boilers.40
52.3.4 Other Process Variables Aflectin£ NOX
The actual NOX levels achieved by combustion modification or other controls will
depend on several process variables which can influence NOX emissions in FBC boilers. These
variables can be grouped into three major categories: chemical and physical coal properties,
chemical and physical properties of sorbent and bed material, and FBC operational variables.
Coal Properties
Two important coal properties are the reactivity and size. Lower reactivity coals emit
lower levels of NOX under both staged and unstaged conditions, due to the catalytic properties
of char in reducing formed NO, and because of the rapid oxidation of volatile nitrogen to NO.
However, coals with low reactivity, and, hence, lower volatile content, are generally burned less
efficiently in FBC boilers than high reactivity coals. Also, SCA is not as effective in reducing
5-37
-------
NOX when low reactivity coals are burned, as discussed in Section 5.2.3.1. Generally, an increase
in coal size tends to reduce NOX and improve thermal efficiency. NOX is reduced due to the
reduced surface area of the char which acts as a catalyst in NH3 oxidation to NO in the presence
of excess oxygen.44 Thermal efficiency tends to improve as a result of the lower levels of
elutriated coal leaving the bed.44
NOX emissions also depend on the nitrogen content of the volatile fraction of the coal
being used, generally increasing as this nitrogen content increases. Under staged combustion,
fuel nitrogen conversion is significantly reduced from typically 6 to 7 percent to as low as 1.5 to
2.5 percent, depending on the degree of staging. Thus, the effect of nitrogen content on NOX
emissions will tend to be less under staged conditions than for unstaged combustion.
The sulfur content of the coal does not in itself have any effect on NOX emissions.
Indirectly, however, the use of high-sulfur coals requires more limestone sorbent to suppress SO2
emissions, which will likely increase NOX unless the FBC boiler is operated with some degree
of air staging. This is because under oxygen rich conditions, excessive calcined limestone (CaO)
acts as a catalyst in the oxidation of NH3 to NO, increasing the conversion rate of volatile
nitrogen to NO.44 With combustion staging, CO levels in the dense portion of the bed reduces
formed NO over char and CaO surfaces.
Sorbent/Bed Material
NOX emissions are also affected by the chemical and physical properties of the bed
material and sorbent used for sulfur capture. An increase in Ca/S ratio for improved sulfur
capture, for example, will increase NOX, especially under unstaged combustion conditions, as
discussed earlier. CFBC boilers utilize lower Ca/S levels than do BFPC units, and thus tend to
emit less NOX. With staged combustion, however, the effect of Ca/S ratio on NO formation is
reduced due to the catalytic effect of CaO and CaS on NOX reduction in the presence of high
concentrations of CO.
Operational Variables
Several operational variables have been reported to affect NOX formation, including ash
recirculation, coal distribution in the bed, and fluidization velocity. Of these, ash recirculation
has the most effect. When CaO concentrations in the ash are low and char and CaSO4
concentrations are high, a net reduction in NOX is achieved with increased ash recycle. The
CaSO4 acts as a catalyst in oxidation of NH3 and reduction in NO in the freeboard section of
the furnace, according to localized temperature and concentration of NH3 and O2.45 This was
5-38
-------
demonstrated in a 125 MMBtu/hr BFBC boiler in Japan, where the use of ash reinjection
resulted in a 67 percent NOX reduction, from 90 to 30 ppm (0.12 to 0.04 lb/MMBtu).41
Data on the effect of coal distribution in the bed are generally sparse and inconclusive.
In small pilot-scale combustors, improved bed uniformity has been shown to increase NOX.
However, under staged conditions, it is likely that better distribution of the coal and increasing
the bed depth will offer improved NOX control and more efficient operation, although the
reduction is anticipated to be small.46
The effect of fluidization velocity on NOX emissions from FBC boilers is generally small.
At constant high excess air levels, an increase in fluidizing velocity has shown a small effect on
NOX. When overall excess air is kept low, the effect is relatively insignificant.46
In summary, NOX emissions from FBC boilers are influenced by several design and
process parameters to such an extent that NOX levels can vary significantly from one unit to the
next. For a given type of FBC design, coal properties such as nitrogen content and reactivity;
and FBC operating conditions such as bed temperature, ash recirculation, and coal distribution;
are principal variables affecting NOX. Additionally, the sulfur content of the coal together with
the required amount of sulfur capture determine the amount of sorbent used, which in turn
influences NOX. Sorbent reactivity and size distribution also play important roles in NOX
emissions since they affect calcium utilization in the fuel bed. Of the combustion modification
NOX control techniques examined in this section, SCA is the most widely applicable and cost-
effective method.
53 COMBUSTION MODIFICATION NOX CONTROLS FOR OIL- AND NATURAL-GAS-
FIRED ICI BOILERS
Combustion modification NOX controls for full-scale oil- and natural-gas-fired ICI boilers
have been implemented primarily in California. Most of the retrofit activity has been in
response to local air districts' rules restricting NOX emissions from boilers and process heaters.
For example, SCAQMD Rules 1146 and 1146.1 regulate NOX emissions from boilers as small
as 2 MMBtu/hr in capacity. Rule 1146 restricts NOX emissions from ICI boilers with heat input
capacities of 5 MMBtu/hr or more to 40 ppm (0.05 lb/MMBtu), unless the unit is greater than
or equal to 40 MMBtu/hr capacity and" has more than a 25 percent annual capacity factor, in
which case NOX emissions are limited' to 30 ppm. Rule 1146.1 mandates a 30 ppm
(0.04 lb/MMBtu) limit for ICI boilers of at least 2 MMBtu/hr capacity but less than
5 MMBtu/hr. Additionally, several districts restrict NOX from boilers used in the petroleum
refining industry. It should be noted that these limits are possible in Southern California only
5-39
-------
because of the reliance on clean burning natural gas and light distillate oil. Applicable controls
include WI/SI; FOR; LNB; SCA, including BOOS and OFA; and a combination of these.
The control of NOX from fuel oil combustion relies on the suppression of both fuel and
thermal NOX, while with natural gas combustion, NOX control focuses primarily on thermal NOX
only. In order to achieve this suppression, control methods involve combustion staging or
reduction of peak flame temperature. Applicable combustion modification control techniques
are SCA, including BOOS and OFA; use of LNBs; FOR; and combinations of these techniques.
As explained earlier in this chapter, load reduction, reduced air preheat, and low excess air firing
are not considered independent or viable control technologies. Fuel switching has traditionally
not been viewed as a control technology. However, the switching from coal to oil or gas and
from high-nitrogen residual oil to lighter oil fractions or gas have come under increased
consideration in regional and seasonal NOX compliance options. Fuel switching is discussed in
this section along with more traditional combustion modification controls.
Tables 5-7 and 5-8 summarize the information available on the performance and
applicability of these techniques for natural-gas-fired and oil-fired ICI boilers, respectively. For
natural-gas-fired boilers, more data were available for watertube units equipped with LNB or
combined LNB and FGR. Controlled NOX levels for these units ranged from as low as 13 ppm
(0.02 Ib/MMBtu) to as high as 170 ppm (0.20 Ib/MMBtu). The limited data available for gas-
fired watertube units with SCA show controlled NOX levels of 50 to 200 ppm (0.06 to
0.24 Ib/MMBtu). Controlled NOX emissions from gas-fired firetube units, most equipped with
FGR, ranged from 15 to 68 ppm (0.02 to 0.08 Ib/MMBtu).
The data presented in Table 5-8 also show wide variability in controlled NOX levels. For
example, units fired on distillate oil with LNB showed NOX ranging from 60 to 260 ppm (0.08
to 0.33 Ib/MMBtu). With combined LNB and FGR, NOX ranged from 30 to 200 ppm (0.04 to
0.25 Ib/MMBtu).
The following subsections, 5.3.1 through 5.3.7, describe each of these methods as they
are applied to both oil and natural gas combustion. Although differences in fuel type are
acknowledged and affect NOX emission levels, in general the control equipment and techniques
used for oil and natural gas firing are similar. In fact, a large percentage of industrial boilers
are capable of burning gas and oil individually or in combination.47 All data collected for this
section are contained in Appendix B. Additionally, data provided by Coen Company and
5-40
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Tampella Power Corporation are contained in Appendix C. These data include emission levels
based on vendor guarantees, and actual recorded emissions.
SJ.l Water Injection/Steam Injection (WI/SI)
WI/SI are effective control techniques for reducing thermal NOX in natural-gas-fired ICI
boilers. When water or steam are injected in the flame, they reduce the peak flame temperature
and the oxygen concentration. The quenching of the flame reduces the NOX by as much as
75 percent, depending on the amount of water or steam injected. Less water than steam is
needed to achieve the same quenching effect because of the heat of vaporization required to
change water into steam.
WI has seen very limited application in Southern California, where NOX emission
regulations are the most stringent. Because of low initial cost, the technique is considered
particularly effective for small single-burner packaged boilers operated infrequently.48 In these
applications, the oil gun positioned in the center of the natural gas ring burner is used to inject
the water at high pressure. The amount of water injected normally varies between 25 and
75 percent of the natural gas feedrate, on a mass basis. Figure 5-15 illustrates the general trend
of NOX reduction with water injection rate. However, the technique has some important
environmental and energy impacts. For example, CO emissions increase because of the
quenching effect on combustion, and the thermal efficiency of the boiler decreases because the
moisture content of the flue gas increases, contributing to greater thermal losses at the stack.
Another concern related to the technique is its potential for unsafe combustion conditions that
can result from poor feedrate control.
532 Low-NOx Burners (LNBs) in Natural-gas- and Oil-fired ICI Boilers
LNBs for natural-gas- and oil-fired ICI units are becoming more widespread as the
technology has been commercialized and improved, and as regulatory requirements become
stricter. LNBs in the ICI sector have been applied primarily to packaged watertube ICI boilers,
and to a lesser extent, to packaged Cretube and field erected watertube boilers. Most of the
available data are from gas-fired boilers located in California. Some of the principal types of
LNB available are staged combustion burners, relying on either staged air or staged fuel, LNB
with FGR, and ceramic fiber burners. Additionally, another type of burner known as the cyclonic
combustion burner has recently been introduced. Major manufacturers of staged combustion
burners for ICI sized boilers include Coen Company, Inc., Faber Burner (Tampella Power), Todd
Combustion, Peabody, Riley Stoker, Industrial Combustion, and the John Zink Company. Alzeta
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02 04 0.6 08 1 1.2 1.4
DIMENSiONLESS WATER INJECTION
Ib H20/lb fuel
Figure 5-15. As the rate of water injection increases, NOX decreases.'
48
Corporation has developed the radiant ceramic burner, while York-Shipley has recently
introduced the cyclonic burner, both of which are for use primarily in smaller packaged firetube
boilers.
There are also burners known as LEA burners, which reduce NOX formation by
operating at low oxygen concentrations. An added benefit of LEA burners is improved thermal
efficiency. When compared to conventional burners, however, these burners provide moderate
reductions in NOX, reportedly on the order of 10 to 25 percent reduction.49 The primary
benefits of LEA burners are their increased efficiency and fuel saving characteristics. Because
of the greater difficulty in achieving equal air distribution in multiple burner systems, LEA
burners are generally more applicable to single burner systems.
The data in Tables 5-7 and 5-8 indicate that ICI boiler LNB experience includes the
reported NOX levels and reduction efficiencies shown in Table 5-9, exclusive of LNB vendor data
from Appendix C. There are many factors that affect the level of NOX achieved with these
burners. The nitrogen content of residual oil, the heat release rate, and the amount of
combustion air preheat combined with level of FOR used for gas fuel are among the more
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TABLE 5-9. REPORTED NOX LEVELS AND REDUCTION
EFFICIENCIES IN ICI BOILERS WITH LNBs
Fuel Performance levels
Residual oil 30-60%
0.09-0.60 Ib/MMBtu
Distillate oil N.A.a
0.08-0.33 Ib/MMBtu
Natural gas conventional burners 32-71%
0.03-0.20 Ib/MMBtu
Natural gas radiant burners 53-82%
0.01-0.036 Ib/MMBtu
*N.A. = Not available.
critical factors contributing to the wide range in controlled NOX levels. The following subsections
highlight the principal design features of LNB types.
5.3.2.1 Staged Combustion Burners
Staged combustion burners, the most common type of LNB, achieve lower NOX
emissions by staging the injection of either air or fuel in the near burner region. Hence, staged
combustion burners may be further classified as either staged air burners or staged fuel burners.
Staged air burners have been applied to watertube boilers since 1979.50 Figure 5-16 is a
schematic of a typical staged air burner, in which primary, secondary, and tertiary (denoted as
staged air in the figure) air are injected into the burner. As the figure notes, the division of
combustion air reduces the oxygen concentration in the primary burner combustion zone,
lowering the amount of NO formed and increasing the amount of NO reducing agents.
Secondary and tertiary air complete the combustion downstream of the primary zone, lowering
the peak temperature and reducing thermal NOX formation. Besides the basic staged air burner
shown, there are variations on staged air burners which incorporate internal recirculation of
combustion products to aid in NOX reduction.
Due to the staging effect of staged air burners, flame lengths tend to be longer than
those of conventional burners.51 This is" of particular concern for packaged units because there
is the possibility that flame impingement will occur on the furnace walls, resulting in tube failure
and corrosion. Additionally, staged air burners are often wider and longer than conventional
burners, requiring significant modifications to existing waterwalls and windboxes. Burner size
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STAGED AIR IS MIXED
WITH THE COMBUSTION
PRODUCTS FROM THE
PRIMARY ZONE. THIS
LOWERS THE PEAK FLAME
TEMPERATURE WHICH
LIMITS THE FORMATION
OF NO.
STAGED AIR
SECONDARY AIR
SUB-STOICHIOMETRIC
CONDITIONS IN PRIMARY ZONE
INCREASE THE AMOUNT OF
REDUCING AGENTS (H2 & CO).
PRIMARY AIR
Figure 5-16. Staged air LNB.53
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may also be an important factor when assessing the feasibility of retrofitting boilers located in
restricted spaces.
Staged fuel burners are a slightly more recent development in staged combustion LNBs.
These burners were originally developed for use on process heaters in the refining and
petrochemical industries, and hence have been applied primarily to process heaters rather than
boilers. Figure 5-17 is a schematic of a staged fuel burner, manufactured by the John Zink
Company. Here, combustion air is introduced without separation and instead the fuel is divided
into primary and secondary streams. Despite the high oxygen concentration in the primary
combustion zone, thermal NOX formation is limited by low peak flame temperatures which result
from the fuel-lean combustion. Quenching of the flame by the high excess air levels also occurs,
further limiting the peak flame temperatures and providing active reducing agents for NOX
reduction.52 Inerts from the primary zone then reduce peak flame temperatures and localized
oxygen concentration in the secondary combustion zone, thereby reducing NOX formation. An
advantage of staged fuel burners over staged air burners is that they tend to have shorter flame
lengths, decreasing the likelihood of flame impingement.54
Data collected on natural-gas- and oil-fired ICI boilers with staged air LNBs show a wide
range in performance and emission levels. For natural gas firing, NOX reductions of 39 to
71 percent were reported for three existing and one new watertube boiler. Controlled NOX levels
for these and 10 other gas-fired watertube boilers, five of which were existing units retrofitted
with LNBs, ranged from 25 ppm (0.03 Ib/MMBtu), for a 10 MMBtu/hr boiler in Taiwan, to
140 ppm (0.17 Ib/MMBtu), for a 100 MMBtu/hr floor firing unit in Germany. This range is
quite wide due to differences in boiler design, capacity, and burner type. An example of the
levels of performance achievable with different burners is that when a different LNB was tested
in the German boiler mentioned above, the controlled NOX level was 112 ppm (0.13 Ib/MMBtu)
instead of 140 ppm (0.17 Ib/MMBtu).55
All but one of the above 14 units were packaged. The only field-erected unit, a
380 MMBtu/hr dual burner unit at Luz-Segs n in California, reported a controlled NOX level
of 80 ppm (0.10 Ib/MMBtu) when retrofitted with an LNB.56 Test results from one gas-fired
firetube unit at Fort Knox retrofitted with a staged air burner showed a 32 percent reduction in
NOX, from 100 ppm down to 68 ppm (0.12 to 0.08 Ib/MMBtu). No other data are available for
firetube units with staged air LNB.
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SECONDARY COMBUSTION
HIGH AIR TO FUEL
RATIO IN PRIMARY ZONE
SECONDARY FUEL
COMBUSTION
AIRS
SECONDARY FUEL
CONNECTION
PRIMARY FUEL
CONNECTION
Figure 5-17. Staged fuel LNB.
5-48
52
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Additional data supplied by Coen Company (see Appendix C) for 177 natural-gas-fired
LNB installations showed guaranteed or actual NOX levels typically between 30 and 170 ppm
(0.04 to 0.20 Ib/MMBtu) with LNB.57 These data include emissions levels for boilers of various
types and sizes, ranging from packaged to field erected units producing 25,000 to 520,000 Ib/hr
of steam (approximately 30 to 600 MMBtu/hr heat input). All units used Coen DAF LNBs.
Appendix C also contains a list of 23 Tampella Power Corp. Faber LNB installations that
reportedly emit 40 ppm NOX (0.05 Ib/MMBtu) or less when firing natural gas. All of these
boilers are packaged units ranging from 9,000 to 100,000 Ib/hr steam capacity.58
For smaller industrial gas-/oil-fired boilers, Riley Stoker has also introduced the Axial
Staged Return (ASR™) flow burner, the Axial Flame Staged (AFS™) burner, and the Swirl
Tertiary Staged (STS™) burner. The ASR burner is based on patented Deutsche Babcock
technology that uses axial staging of primary and secondary air streams and internal recirculation
of self-aspirated hot furnace gases. The burner, illustrated in Figure 5-18, has a maximum design
capacity of 275 MMBtu/hr, with controlled NOX levels in the 20 to 30 ppm (0.025 to 0.035
Ib/MMBtu) range when firing natural gas with 12 to 30 percent FOR assistance.59 The AFS
burner incorporates axial staging of primary and secondary air and staged fuel addition. The
burner, illustrated in Figure 5-19, has a firing capacity in the 20 to 40 MMBtu/hr range.59 With
FOR addition, NOX emissions in the 30 to 40 ppm (0.035 to 0.048 Ib/MMBtu) range have been
reported in full-scale retrofits.59 The STS burner, illustrated in Figure 5-20, is designed for
retrofit on multiple burner wall-fired boilers with 500°F air preheat. In one full-scale STS burner
retrofit at a paper mill, reported NOX emissions ranged from 90 to 110 ppm (about 0.1 to
0.13 Ib/MMBtu) with high air preheat and heat release rate and without FGR.59
In summary, LNB NOX reduction efficiencies for natural-gas-fired boilers including one
firetube boiler and five watertube units range from 32 to 71 percent, in agreement with
previously reported performance levels for natural gas firing. LNB reduction efficiencies for
13 additional watertube units listed in Appendix B could not be computed because of a lack of
baseline (uncontrolled) emissions data. Controlled NOX emissions for the 18 watertube units
ranged from 25 to 30 ppm (0.03 to 0.04 Ib/MMBtu), for the smaller units (10 to 31 MMBtu/hr
input), and from 58 to 140 ppm (0.07 to 0.17 Ib/MMBtu), for the remaining boilers, which
ranged in size from 45 to 380 MMBtu/hr input. Controlled NOX emissions reported by two LNB
manufacturers for nearly 200 units ranged between 30 and 170 ppm (0.04 to 0.20 Ib/MMBtu).
Some burner manufacturers have reported NOX reduction efficiencies of anywhere from 50 to
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OIL GUN
\ \ \ \
INNER RETURN FLOW PRIMARY FLAME
Figure 5-18. Low-NOx ASR burner.59
OPPOSED
LOUVER
^=fe DAMPER
INTERNAL
GAS LANCE
EXTERNAL
GAS LANCE
BARREL MATI IRAi
ADJUSTER -
Figure 5-19. ATS air- and fuel-staged burner.59
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Shroud Actuotorj
Primory Air Shroud
Secondory Air Shroud
Burner Front Plole
Register Turning Vones
Furnoce Woterwoll
Oil Gun With DiHuser
Cos Cones
Figure 5-20. Riley Stoker STS burner.59
90 percent. In fact, several manufacturers guarantee NOX emissions below 40 ppm
(0.05 Ib/MMBtu) when firing natural gas in smaller industrial packaged boilers, primarily in
response to the SCAQMD regulations in California. For example, Faber, a division of Tampella
Power, guarantees less than 40 ppm NOX on any burner system and will guarantee less than
30 ppm (0.04 Ib/MMBtu) of NOX on a case-by-case basis.60 Similarly, Coen Company states that
less than 30 ppm of NOX will be emitted from its Micro-NOx® LNB.61 Performance levels of
less than 20 ppm are achievable on a case-by-case basis.
For oil firing with staged air LNBs, data were collected for 84 boilers firing distillate oil
and 46 boilers firing residual oil. The distillate-fuel-fired boilers with staged air LNBs showed
controlled NOX levels of 60 to 260 ppm (0.08 to 0.33 Ib/MMBtu). The 25 domestic units fired
on No. 6 residual oil (fuel nitrogen contents of 0.14 to 0.3 percent) had controlled emissions of
80 to 475 ppm (0.10 to 0.60 Ib/MMBtu). Due to a lack of baseline uncontrolled emissions data
for these domestic units, it was not possible to calculate NOX reduction efficiencies for the
boilers. Additionally, overall performance results of 17 firetube and watertube boilers in Japan
firing residual oil have been reported. Foi these units, which ranged in size from 5 to
40 MMBtu/hr, test results showed NOX reductions between 30 and 60 percent, with controlled
emissions between 69 and 185 ppm (0.09 and 0.23 Ib/MMBtu).62
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The retrofit of LNBs usually involves removing the original burner and bolting the LNB
in. Most LNBs for ICI boilers are designed as self-contained units to allow easy bolt-on retrofit
without boiler tube wall modifications. For applications where new fan or ducting equipment
are desired, some manufacturers offer complete packaged burner units, in which the retrofit
burner is combined with combustion controls, flame safeguard equipment, fuel piping, and a
combustion air fan. These are sold together as factory assembled, self-contained packages.
5322 Ceramic Fiber Burners
Alzeta Corporation has developed a ceramic fiber burner known as the Pyrocore®
burner, applicable for use in gas-fired packaged boilers of up to 10 MMBtu/hr input. Although
applicable to both watertube and firetube units, the Pyrocore burner has been demonstrated
primarily in firetube boilers and process heaters. This burner, depicted in Figure 5-21, is a gas-
fired infrared (IR) burner. An IR burner uses energy released from the fuel to elevate the
temperature of the radiant surface of the burner, which in turn emits energy in the form of IR
radiation. In the Pyrocore burner, fuel gas is premixed with combustion air before entering the
burner. The mixture passes through a porous burner material and is ignited, establishing a thin
combustion layer in contact with the surface. Because the surface material is cooled by the
incoming air/fuel mixture and the material has a low thermal conductivity, radiant temperatures
of 1,700 to 2,000 °F occur only on the outer surface.63 The low combustion temperature limits
thermal NOX formation.
Field tests of this burner retrofitted to a 3.3 MMBtu/hr firetube boiler at Hall Chemical
in Ohio showed NOX reduction of 78 percent, with controlled emission levels of 15 ppm
(0.02 Ib/MMBtu). Another field test conducted on an 8 MMBtu/hr boiler retrofitted with the
Pyrocore burner showed 53 percent reduction in NOX, to a controlled level of 24 ppm
(0.03 Ib/MMBtu), while a third test on a 2 MMBtu/hr unit resulted in a controlled emission
level of 17 ppm. On the average, results from five field tests and one laboratory test showed that'
NOX was reduced by 71 percent and CO by 94 percent.64 To date, most burners supplied by
Alzeta have been designed to achieve less than 30 ppm NOX at full rated load, although the
actual emissions for many are reported to be below 20 ppm. Currently, the single-burner
applications of this burner are limited to small packaged boilers of less than 20 MMBtu/hr
because of physical limits on the size of the radiant burner. Structural issues are the major
concern with larger applications. Further research and tests are being conducted to extend the
5-52
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Radiant and
Convective
Energy Flux
Combustion Zone
Ceramic Fiber Layer
Support
Fuel/Air ln!&t
Figure 5-21. Pyrocore LNB schematic.63
5-53
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Pyrocore burner's applicability to larger firetube and watertube boilers, including the use of
multiple burners.
Additional research is currently focusing on the use of lower surface firing rates,
moderate temperature environments, and modest excess air to attain ultra-low NOX levels of
9 ppm and below. Alzeta Corporation and Zurn Industries have recently commissioned an ultra-
low-NOx boiler, the Radiant Cell Boiler™, that utilizes the Alzeta flameless Pyrocore radiant
burners and has a reported capability of 9 ppm of NOX and less than 50 ppm of CO.65
53.23 Other LNBs
An LNB type known as a cyclonic burner has recently been developed by York-Shipley
for packaged firetube boilers. The burners are available up to 16.6 MMBtu/hr heat input. In
cyclonic combustion, high tangential velocities are used in the burner to create a swirling flame
pattern in the furnace. This causes intense internal mixing as well as recirculation of combustion
gases, diluting the temperature of the near-stoichiometric flame and lowering thermal NOX
formation. The tangential flame causes close contact between combustion gases and the furnace
wall, adding a convective component to the radiant heat transfer within the furnace. The
increased heat transfer and low excess air operation of the cyclonic burner result in increased
boiler efficiency.
To achieve ultra-low NOX levels, a small quantity of low-pressure steam is injected into
the burner, which further reduces the local flame temperature and NOX formation. Testing
revealed that NOX emissions during natural gas firing could be reduced from 70 ppm to less than
20 ppm without affecting burner stability, low excess air operation, or turndown performance.
However, the use of steam did result in a boiler heat efficiency loss of roughly 5 percent.66 The
cyclonic burner is available as a stand-alone retrofit burner with a bolt-on feature. However, no
retrofit emissions data were obtained during this study.
533 Flue Gas Recirculation (FGR) in Natural-gas- and Oil-fired ICI Boilers
FOR involves recycling a portion of the combustion gases from the stack to the boiler
windbox. These low oxygen combustion products, when mixed with combustion air, lower the
overall excess oxygen concentration and act as a heat sink to lower the peak flame temperature
and the residence time at peak flame temperature. These effects result in reduced thermal NOX
formation. However, there is little effect on fuel NOX emissions. The amount of NOX reduction
achievable depends primarily on the fuel nitrogen content and amount of FGR used. Other
thermal NOX control concepts similar to FGR are such control techniques as WI and SI, in which
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water, rather than recirculated flue gas, is used as an inert substance to lower the peak flame
temperature. FGR is much more commonly used, however.
FGR is currently being used on a number of watertube and firetube boilers firing natural
gas. Only limited NOX reduction efficiency data are available, however, as baseline
(uncontrolled) NOX data for most units are unreported. Data for four natural-gas-fired
watertube boilers equipped with FGR show a range in NOX reduction of 53 to 74 percent, while
for 10 gas-fired firetube units with FGR, NOX reduction efficiency ranged from 64 to 76 percent.
In all, controlled NOX emission data were collected for a total of 33 gas-fired watertube and
57 gas-fired firetube units operating with FGR. Four of the watertube units and 26 of the
firetube units were identified as retrofit applications. Controlled NOX levels ranged from 20 to
85 ppm (0.02 to 0.10 Ib/MMBtu) for the watertube units and 16 to 37 ppm (0.02 to
0.04 Ib/MMBtu) for the firetube boilers. FGR rates were typically on the order of 20 percent
during these tests. However, one firetube unit—which achieved 68 percent reduction—was run
on 30 percent FGR during the emissions test. Boilers are usually not operated with more than
20 percent FGR due to flame stability considerations.67
NOX reduction efficiency data for oil-fired units with FGR are also very-limited. In one
test program, a single boiler was fired on both residual oil and distillate oil, using FGR and
keeping all other variables constant. NOX was reduced by 68 percent for distillate oil firing, yet
was only reduced by 11 percent when residual oil was used. These data illustrate that FGR is
more effective when used with low nitrogen content fuels such as natural gas or distillate oil,
since FGR is more effective in controlling thermal NOX rather than fuel NOX. The 68 percent
reduction was obtained with a relatively high FGR rate of 28 percent. Another boiler f;ring
distillate oil reported NOX reduction of only 20 percent, using 10 percent FGR. Available data
are too limited to estimate typical NOX reduction efficiencies for oil-firing boilers with FGR.
In general, however, thermal NOX reductions from distillate-oil-fired boilers with FGR are
somewhat less than from natural-gas-fired units.68 This is due to the greater potential for flame
instability and emissions of unburned combustibles from distillate-oil-fired units, which limits the
practical rate of FGR that can be used. Controlled NOX emissions for distillate oil firing with
FGR were between 28 and 240 ppm (0.04 to 0.30 Ib/MMBtu) for 19 boilers. For three units
firing residual oil, controlled NOX levels ranged from 125 to 275 ppm (0.16 to 0.35 Ib/MMBtu).
When compared to the number of LNB or combined LNB and FGR installations listed
in Tables 5-7 and 5-8, the number of watertube boilers equipped only with FGR is relatively
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small. In general, for retrofit cases to existing packaged watertube ICI boilers, FGR is rarely
applied without the installation of a new LNB as well. This is because the performance of many
older burner systems tend to be adversely affected when an inert such as fuel gas is injected into
the combustion zone.57 Oxygen trim systems have been installed to allow use of an existing
burner with FGR and LNB together. Thus, the most common combustion modification NOX
controls for packaged watertube boilers are either LNB or combined LNB and FGR. FGR
systems have been applied more commonly to smaller firetube units. A typical FGR system is
shown in Figure 5-22. In order to retrofit a boiler with FGR, the major additional equipment
needed are a gas recirculation fan and ducting. Major companies that supply FGR equipment
for packaged gas- and oil-fired boilers are Cleaver Brooks, Coen Company, Industrial
Combustion, Keeler (Tampella Power), and Todd Combustion.
53.4 Fuel Induced Recirculation (FIR)
Fuel induced recirculation (FIR) is a control technology for natural-gas-fired boilers
recently introduced by the John Zink and Holman Boiler Companies. FIR involves the
recirculation of a portion of the boiler flue gas and mixing it with the gas fuel at some point
upstream of the burner. Although FIR has not yet been widely applied, it has been
demonstrated commercially in an industrial unit in California, achieving NOX emission readings
as low as 17 ppm with little adverse affect on CO emissions.69
The primary difference between FIR and FGR is that in FIR the flue gas is mixed with
the fuel stream, whereas in FGR the flue gas is recirculated into the combustion air. By diluting
the fuel prior to combustion, which lowers the volatility of the fuel mixture, FIR reduces the
concentration of hydrocarbon radicals that produce prompt NO.6 Additionally, FIR reduces
thermal NOX in the same manner as FGR, by acting as a thermal diluent. Thus, one of the main
benefits of FIR technology is that it impacts both prompt NO and thermal NOX formation in gas-
fired boilers.
A second fundamental feature of FIR is that flue gas recirculation is induced using the
natural gas dynamics of the burner flow streams, without additional equipment such as
recirculation fans. According to the manufacturer, FIR tends to be self-adjusting at various firing
rates, as natural gas introduction is dependent on the mass and pressure of the fuel.70
5.3.5 Staged Combustion Air (SCA) in Natural-gas- and Oil-fired ICI Boilers
Staged combustion for oil- and natural-gas-fired boilers in the ICI sector consists of
injecting a portion of the total combustion air downstream of the fuel-rich primary combustion
5-56
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UN/SERIES
First U.L. Listed Flue Gas Recirculation System
H""! COMBUSTION *"«
I l COMBUSTION riur GAS
C7 1 nccmcuiAico'iuc c»
Figure 5-22. FGR system for gas- or oil-fired boiler.71
zone. Staged combustion can be accomplished using secondary OFA or side-fired air ports, or
by using the BOOS technique. The applicability of OFA, side-fired air, or BOOS (collectively
grouped under the term SCA) depends primarily on the type of furnace design involved — i.e.,
watertube or firetube — and the size of the boiler. Generally, SCA is not considered viable for
retrofit to packaged boiler units due to installation difficulties. The following subsections
summarize the performance, applicability, and availability of the various methods of
implementing SCA on the major types of natural-gas- or oil-fired ICI boilers.
53.5.1 Firetube Boilers
SCA is not considered a primary NOX control method for existing firetube boilers
because of the major modifications required to retrofit staged air to these boilers.72 BOOS is
not applicable because these units rarely have more than one burner. Side-fired air application
is difficult as retrofit requires penetration of the firetube boiler water shell. Performance data
are available only for one experimental application of side-fired air to a 12 MMBtu/hr firetube
5-57
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boiler fired on residual oil and natural gas. In this test program, sponsored by the U.S. EPA,
secondary air was injected at the rear of the furnace opposite the burner through eight pipes
connected to a forced-draft fan. In this way the secondary air was independent of the primary
burner air. Test results for residual oil firing showed that NOX was reduced from 177 ppm to
90 ppm (0.22 to 0.11 Ib/MMBtu), a 49 percent reduction in NOX. During these residual oil
combustion tests, the burner was operated at 76 percent of stoichiometric conditions, and the
overall excess oxygen level was 4 percent.73 However, boiler load was reduced to 50 percent due
to combustion instabilities at high loads.
Tests conducted on the same boiler but firing natural gas at 71 percent load had almost
no effect on NOX, showing only 5 percent NOX reduction, from 70 to 67 ppm (0.084 to
0.080 Ib/MMBtu). NOX reduction for gas-firing may not have been as high as the residual oil-
firing case because of the slightly higher test load and because the burner oxygen level was
higher, at 90 percent stoichiometry. Also, because natural gas combustion emits lower levels of
NOX than residual oil firing to begin with, it is generally more difficult to achieve as
much percentage NOX reduction with natural gas.
5352 Packaged Watertube Boilers
Packaged watertube boilers generally use only one burner, so BOOS is not applicable
as a means of achieving staged combustion. As was the case with firetube boilers, retrofit of
SCA to smaller packaged watertube units is generally not considered a primary NOX control
option due to the difficulty of retrofitting SCA hardware. Hence, experience on these units has
been limited. Data are available for two experimental retrofit applications of SCA in single-
burner oil- and gas-fired packaged watertube units. The first application, in a 22 MMBtu/hr unit
(Location 19), involved the injection of secondary air through four steel lances which were
inserted through the windbox and the refractory firing face. At 83 percent load, NOX emissions
were reduced by 29 percent (controlled NOX = 157 ppm or 0.20 Ib/MMBtu) when residual oil.
was fired, by 30 percent (controlled NOX = 77 ppm or 0.10 Ib/MMBtu) when distillate oil was
fired, and by 46 percent (controlled NOX = 50 ppm or 0.07 Ib/MMBtu) when natural gas was
fired.74
At the second site, identified as "Location 38," secondary air was injected into a
56 MMBtu/hr boiler through any of 10 SFA ports. This unit was equipped with combustion air
preheating, which could vary the temperature from roughly 65 to 176°C (150 to 350°F). At
operating conditions of 89 percent load, 2.3 percent excess oxygen, and 14 percent SCA flow,
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NOX was reduced by 42 percent from the baseline, when residual oil was fired. During natural
gas firing, staged combustion resulted in a reduction of 32 percent from the baseline conditions
at 2.4 percent excess oxygen and 14 percent SCA.74 Results from these two applications showed
that in order to maximize NOX reduction using SCA in packaged watertube units, it is necessary
to operate the burner at substoichiometric levels, and secondary air must be injected sufficiently
downstream of the burner exit to allow for cooling of combustion gases. These types of SCA
retrofits on full-scale packaged watertube boilers are generally not considered practical from
installation and operational standpoints.
5.3.5.3 Field-erected Watertube Boilers
For field-erected watertube boilers equipped with more than one burner, staged
combustion can be achieved by using OF A, BOOS, or biased burner firing. Biased burner firing
consists of firing certain burners fuel-rich while other burners are fired fuel-lean. This may be
accomplished by maintaining normal air distribution to the burners while adjusting fuel flow so
that more fuel is sent to desired burners. Usually, the upper row of burners is fired fuel-lean,
but this varies from boiler to boiler.
BOOS is more applicable as an NOX control technique for natural-gas- and oil-fired
boilers than it is for coal-fired units. As mentioned previously, with PC-fired ICI boilers the mill-
burner arrangement usually determines which burners can be taken out of service. For this
reason, BOOS is more often used as a maintenance operation than a direct NOX control method.
In contrast, with oil or natural gas firing, burners can be shut off individually or fuel flow
adjusted to achieve optimum biased burner firing or BOOS operation.
For large -vall-fired units, BOOS or biased firing are attractive first level retrofit NOX
control techniques because few equipment modifications are required. For natural gas firing,
data compiled for three industrial boilers with BOOS showed NOX reductions ranging from 17
to 44 percent, with an average of 29 percent reduction from uncontrolled NOX levels. Controlled
NOX emissions from these units, ranging in size from 60 to 120 MMBtu/hr, were between 117
and 200 ppm (0.14 and 0.27 lb/MMBtu).75 For residual oil firing, data from nine boilers using
BOOS showed NOX reduction efficiencies of 5 to 40 percent.
The wide range in control efficiencies is attributed to several factors, including the
burner arrangement, the percentage of burners taken out of service, and the overall excess air.
Some burner arrangements are more effective in reducing NOX with BOOS. For example, a
5-59
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square burner matrix is more effective than an arrangement in which all of the burners are
located at the same level. Another controlling factor is stoichiometry of the active burners.
Although operation with BOOS can measurably reduce NOX, the operating performance
of the boiler can be somewhat degraded because of the need to increase excess air in order to
control CO, hydrocarbon, and smoke emissions.76 Adjustments to the airflow controls, such as
burner registers, may be required to achieve the desired burner stoichiometry without increasing
these emissions. Also, operation with BOOS usually requires that the unit be derated unless
modification to the fuel delivery system is made.77
Data on NOX reductions from field-erected oil- or gas-fired ICI boilers using OFA are
very limited. Controlled emissions from two units firing residual oil were from 160 to 180 ppm
(0.20 to 0.23 lb/MMBtu).57 Application of the technique to utility boilers in California has
reportedly resulted in average NOX reductions of 24 percent for oil and nearly 60 percent for
gas.78 Generally, OFA is applicable only to large furnaces with sufficient volume above the
burners to allow complete combustion and steam temperature control. Because of required
hardware modifications, OFA for large gas and oil wall-fired units is often not a preferred
retrofit control as BOOS can offer similar reduction efficiency at less cost.79 -
53.6 Combined Combustion Modification NOX Controls for Natural-gas- and Oil-fired ICI
Boilers
Many retrofits have utilized combinations of the above combustion modification
methods. The most demonstrated combination is the use of LNB with FOR. As mentioned
earlier, retrofit of combined LNB and FGR controls to existing packaged boilers is often more
feasible than using FGR alone. Also, combined retrofit of FGR and LNB to ICI boilers is
considered by some to be a way of meeting stringent NOX control regulations without using flue
'gas treatment controls.80 Data have been collected for 101 natural-gas-fired units, 44 distillate-
oil-fired boilers, and 13 residual-oil-fired boilers (see Appendices B and C). All were watertube
boilers, the majority located in California. Many of the California boilers were existing units
retrofitted with LNB/FGR controls.
NOX reduction efficiencies of 55 to 84 percent were reported for five units firing natural
gas. No baseline uncontrolled NOX data were available for the other boilers; thus, reduction
efficiencies could not be calculated. Nearly all California units reported controlled NOX
emissions at or below 40 ppm (0.05 lb/MMBtu), while the non-California units reported NOX
levels between 40 and 170 ppm (0.05 to 0.20 lb/MMBtu). For the distillate-oil-firing units,
baseline uncontrolled NOX levels were not available; thus, NOX reduction efficiencies could not
5-60
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be determined. Controlled emissions ranged from 30 to 200 ppm (0.04 to 0.25 Ib/MMBtu). For
the residual-oii-firing units, controlled NOX levels were between 80 and 435 ppm (0.10 to
0.55 Ib/MMBtu).
While some experience has been obtained in combining SCA with LNB or FOR, these
have involved new or experimental test units. In general, applications of SCA with LNB or FGR
are limited to new units because of the costs involved in installing SCA in existing units,
especially in packaged boilers. The use of SCA with an LNB in a new 140 MMBtu/hr natural-
gas-fired watertube boiler resulted in controlled NOX emissions of 64 ppm (0.08 Ib/MMBtu),
while in a new 150 MMBtu/hr residual-oil-fired boiler the controlled NOX level was 175 ppm
(0.22 Ib/MMBtu).81 Coen Company reports controlled NOX emissions from 85 to 170 ppm (0.10
to 0.20 Ib/MMBtu) for nine boilers with LNB and SCA, firing natural gas or distillate oil. For
11 units firing residual oil, NOX ranged from 160 to 315 ppm (0.20 to 0.40 Ib/MMBtu).57 In
general, however, the retrofit of SCA is applicable mainly to large industrial boilers.
5.3.7 Fuel Switching
Because fuel-bound nitrogen plays such an important role in total NOX emissions from
fuel combustion in boilers, switching from high-nitrogen fuels, such as coal or-residual oil, to
lower nitrogen fuels, such as distillate oil or natural gas, is a strategy that can be as effective in
reducing NOX as any other combustion control. Low-nitrogen fuels, such as distillate oil and
natural gas, can be used to displace a fraction of the coal or residual oil, or replace them
entirely. In either case, significant NOX reductions are possible. For example, the cofiring of
natural gas with coal in utility boilers has reduced NOX emissions by a minimum of 10 to
CO JTTIH
30 percent, depending on the boiler, coal, cofiring configuration, and amount of gas firing. The
use of 33 percent natural gas in a gas cofiring configuration in the top row of burners of a
PC-fired boiler (representing a more strategic way to maximize NOX reduction efficiency with
reburning techniques) can result in larger NOX reductions reaching 35 to 60 percent from
uncontrolled levels.82 Figure 5-23 illustrates NOX reduction as a function of gas cofiring rate,
expressed as a percentage of total heat input, measured during six full-scale utility boiler cofiring
field tests. These results are applicable, in theory, to large PC-fired industrial boilers.
The replacement of high-nitrogen residual oil with a lower nitrogen fuel or natural gas
is also very effective in reducing NOX. To illustrate, the data shown in Table 5-10 were obtained
from industrial boilers firing a residual oil first, and then switching to a distillate fuel.2 NOX
reductions ranged from about 50 to 80 percent for reductions in fuel oil nitrogen of
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TABLE 5-10. EFFECTS OF SWITCHING FROM RESIDUAL OIL
TO DISTILLATE FUEL ON INDUSTRIAL BOILERS
Fuel type
Residual oil
Distillate oil
Residual oil
Distillate oil
Residual oil
Distillate oil
Residual oil
Distillate oil
Fuel nitrogen,
% weight
0.44
0.006
0.27
0.015
0.20
0.014
0.20
0.008
NOX emissions
@ 3% O2
350
65
298
127
186
84
220
114
Source: Reference 2.
approximately 0.19 to 0.436 percent by weight. If all the recorded NOX reduction is attributed
to the drop in fuel nitrogen, about 55 to 65 ppm reduction in NOX results from each
0.1 percentage point reduction in the nitrogen content of the oil. Table 5-11 lists estimates of
NOX reductions attainable from ICI boilers cofiring or switching to a cleaner fuel.
In addition to natural gas and low-nitrogen fuel oil, the Shell Oil Company is marketing
a proprietary liquid fuel for industrial boilers. This proprietary fuel is similar to distillate oil in
thermal energy and physical properties, but contrary to distillate oil it contains essentially no
fuel-bound nitrogen (3 to 9 ppm). Therefore, its NOX emissions are similar to those achievable
with natural gas.83 Short-term performance with this proprietary fuel show FGR-controlled
emissions in the range of 18 to 35 ppm corrected to 3 percent O2 (0.022 to 0.042 Ib/MMBtu).
It is used as a standby liquid fuel for many boilers in Southern California in cases where natural
gas is curtailed.
53.8 Combustion Modification NOX Controls for Thermally Enhanced Oil Recovery (TEOR)
Steam Generators
NOX controls for TEOR steam generators have also been implemented primarily in
California, due to stringent NOX emission regulations. For instance, in Kern County, California,
over 2,000 oil field steam generators are in use, the majority fired on crude oil.84'85 Other fuels
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TABLE 5-11. ESTIMATES OF NOX REDUCTIONS WITH FUEL SWITCHING
Base fuel
PC
Residual oil
with 0.6% N
Replacement
fuel
Natural gas
Natural gas
Distillate oil
Residual oil
with 0.3% N
Quantity used,
%
10-20
10-20 (returning zone)
100
100
100
100
Estimated NOX reduction,
%
10-30
30-60
60-70
50-80
50-80
30-40
Note: All emissions data were obtained from short-term tests.
used in these boilers include natural gas and refinery gas. Nearly all units in Kern County utilize
some form of combustion modification NOX control, including OT systems, LNB, or FOR.84
5.3.8.1 OT Systems
OT systems or controllers limit the excess oxygen during combustion to reduce the
formation of NOX. It has been reported that these devices typically reduce the formation of NOX
from small steam generators (<35 MMBtu/hr input capacity) by 15 to 25 percent.86 Controlled
NOX emissions from 71 tests conducted on small crude-oil-fired steam generators in Kern County
ranged from 166 to 398 ppm (0.21 to 0.50 lb/MMBtu).87 For larger units greater than
35 MMBtu/hr (most 62.5 MMBtu/hr), Kern County data from 326 lests showed controlled NOX
levels ranging between 174 and 340 ppm (0.22 and 0.43 lb/MMBtu). No uncontrolled data were
reported for these units; thus, it was not possible to report actual NOX reduction efficiencies.
However, assuming a typical uncontrolled NOX level of 300 ppm (0.38 lb/MMBtu), as reported
in References 49 and 88 for large TEOR units in Kern County, average NOX reduction on the
order of 17 percent was achieved. It should be remembered that this is only an average value,
based on average emission levels and average reported baseline levels. Actual NOX reduction
efficiencies may have been significantly higher or lower depending on the fuel characteristics,
combustion conditions, and design type of each unit. The average levels are illustrative to a
certain degree, however, as most TEOR steam generators are similar in design and all of the
units tested fired Kern County crude.84
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53.8.2 LNBs with SCA and OT
LNB systems, which generally are used with O2 controllers, have been applied primarily
to large (35 to 62.5 MMBtu/hr) crude oil-fired steam generators. The most effective and widely
used LNB systems also incorporate SCA, usually using sidefire air injection. In fact with TEOR
steam generators it is common to describe a combined LNB+SCA system as either an LNB or
an SCA system.86'87'89 Figure 5-24 depicts one type of LNB+SCA system, manufactured by the
North American Company, the principal vendor of LNB systems for TEOR steamers. This
burner system is being used on over 100 crude oil-fired generators in Kern County. Minor
modifications are made to a standard burner and secondary air injection nozzles are inserted
around the circumference of the furnace at various locations in the radiant heat transfer section.
In a 62.5 MMBtu/hr steam generator, 28 secondary air injection ports are used, positioned 17
to 27 feet downstream of the burner. In most applications of this burner system, O2 controllers
are used to keep excess oxygen at the stack below 2 percent. NOX emission levels of 100 to
160 ppm (0.13 to 0.20 Ib/MMBtu) have been reported when crude oil is fired, representing 50
to 70 percent NOX reduction when compared to unstaged conventional North American
burners.89
Another type of LNB system applicable for retrofit to TEOR steam generators is the
single toroidal combustor, developed by Process Combustion Corporation (Figure 5-25). The
single toroidal combustor is a two-stage burner in which approximately one-third of the fuel is
combusted under highly reducing, turbulent conditions inside a precombustion chamber. The
remaining two-thirds of the fuel is combusted in a secondary burnout zone at the entrance to the
sieim generator. The second stage is arranged so that the addition and mixing of 5 io
10 percent secondary excess air takes place in the high-velocity jet of flame emitted from the
chamber throat inside the firebox.90 The vigorous internal recirculation and mixing within the
fuel-rich precombustion chamber aids in NOX reduction, while combustion gases are entrained
into the high-velocity flame of the secondary combustion zone, lowering the peak flame
temperature. Results of 50 separate field tests using this burner showed average NOX reductions
of 60 percent, with average emissions of 125 ppm (0.16 Ib/MMBtu) for 62.5 MMBtu/hr sized
units and 150 ppm (0.19 Ib/MMBtu) for 25 to 30 MMBtu/hr units. Controlled NOX levels
ranged from 90 to 225 ppm (0.11 to 0.28 Ib/MMBtu).91
A third type of LNB for TEOR steam generators utilizes a split flame arrangement,
whereby an inner fuel-rich diffusion flame is separated from and outer fuel-lean premix flame
5-65
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90
by a blanket of recirculated flue gas. This burner, the MHI PM low-NOx burner, illustrated
schematically in Figure 5-26, was retrofitted to a 62.5 MMBtu/hr crude-oil-fired steam generator
as part of an EPA-sponsored test program on a demonstration unit. No additional TEOR
steamers have been retrofitted with this burner. Full-load NOX emissions of HOppm
(0.14 Ib/MMBtu) were obtained with what were deemed "acceptable" smoke and CO emissions
(<100ppm CO). This compares to emissions of approximately 300 ppm (0.38 Ib/MMBtu)
measured from an identical generator equipped with a conventional burner.93 Thus, NOX was
reduced by 63 percent.
Most LNB retrofit experiences have been with crude-oil-fired units larger than
35 MMBtu/hr. Results from 134 tests conducted on such units in Kern County show controlled
NOX levels of 87 to 232 ppm (0.11 to 0.29 Ib/MMBtu). Because no baseline data were available,
it was impossible to calculate NOX reduction efficiencies for these tests. However, these
controlled emissions may be compared to the generally accepted average baseline of 300 ppm
for Kern County crude oil firing.84'88 For illustrative purposes, comparing average controlled
emissions to this average baseline, 59 percent NOX reduction was achieved with LNB systems.
Again, however, it must be remembered that actual efficiencies may have varied significantly
from unit to unit. Limited test data are available for natural gas fired units equipped with LNB.
Data for two 62.5 MMBtu/hr gas-fired generators showed NOX reductions of 8 and 28 percent.
5-67
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Premix
Flame
Recir.'
Gas Blanket
Diffusion
Flame
Premix
Air Nozzle
Flue Gas
Recycle
Nozzle
Diffusion
Nozzle
Flue Gas
Recycle
Nozzle
Premix
Air Nozzle
Figure 5-26. The MHI PM burner nozzle.93
5-68
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Because of the limited data, however, no conclusions can be drawn about typical reduction
efficiencies for LNB gas firing.
LNB systems have also been applied on a very limited basis to steam generators smaller
than 35 MMBtu/hr. Reported NOX emission reductions range from 30 to 60 percent for these
units.86 The limited application of LNB to small generators is due to the longer and wider flame
produced by the LNB and the geometry of small steam generators. Because the radiant section
in small generators is shorter in length and diameter than the radiant section in large generators,
flame impingement is more of a problem.86 Thus, LNB retrofits are primarily applicable to
TEOR steam generators larger than 35 MMBtu/hr.
53.83 FGRandOT
FOR systems have been applied to TEOR steam generators on a more limited basis
than LNB systems. Results from Kern County tests of 36 crude-oil-fired steam generators with
FGR and O2 trim showed controlled NOX levels similar to those obtained with LNB systems,
ranging from 79 to 264 ppm (0.10 to 0.33 lb/MMBtu).87 Thus, for crude oil firing, FGR controls
appear as effective as LNB systems in reducing NOX. For natural gas firing, tests of three large
units using FGR in combination with LNB measured controlled emission levels of 25 to 35 ppm
(0.03 to 0.04 lb/MMBtu). NOX reduction for two of these units ranged from 50 to 68 percent.
For these particular units, these reductions in NOX represent significant improvement over NOX
reduction efficiencies obtained using LNB alone.56'88 Data are too limited, however, to
characterize the performance of FGR controls used with natural-gas-fired TEOR steam
generators.
53.9 Gas Fuel Flaw Modifiers
In addition to the combustion techniques discussed thus far, a device known as a gas
turbulator has been demonstrated to reduce NOX formation in natural-gas-fired packaged boilers.
Originally designed to produce savings in fuel consumption, the turbulator is a small stainless
steel venturi incorporating strategically placed fins. The turbulator is inserted in the gas pipe
directly upstream of the burner, creating highly turbulent fuel flow. This turbulence facilitates
the bonding of hydrocarbon particles with the oxygen molecules of the combustion air, resulting
in increased combustion efficiency.94 Fuel savings typically range between 2 and 10 percent, but
have been as high as 35 percent.95
From an NOX standpoint, the more efficient turbulent mixing of the fuel and air results
in lower excess air requirements for efficient combustion, producing lower levels of NOX. '
5-69
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The only turbulator-related NOX emissions data available to date are for a 33.5 MMBtu/hr
natural-gas-fired firetube boiler at Duncan Boiler Service, Inc., in Kenner, Louisiana. At this
site, the use of a turbulator raised full-load boiler efficiency by 3 percent, and the improved
air/fuel mixing reduced the required excess oxygen by 27 percent. Consequently, NOX emissions
were reduced from 58 to 35 ppm at 3-percent oxygen, a 40-percent decrease.96
5.4 COMBUSTION MODIFICATIONS FOR NONFOSSIL-FUEL-FIRED ICI BOILERS
Application of combustion modification NOX controls to nonfossil-fuel-fired ICI boilers
is very limited. Many waste-fuel-fired boilers are not easily modified to reduce NOX without
compromising combustion efficiency and byproduct emissions. Furthermore, nonfossil fuels
include a variety of waste fuels with varying combustion characteristics and pollutant profiles.
Consequently, adaptation of conventional combustion controls can be difficult and very site-
specific. Currently, more attention has focused on the application of flue gas treatment controls
to nonfossil-fuel-fired ICI boilers, especially in California, where flue gas treatment controls have
been applied to at least 17 units fired on wood or MSW. These applications are discussed in
Section 5.3.
Combustion modification retrofit experience has been limited to the use-of SCA. In one
wood-/natural-gas-fired overfeed stoker unit, equipped with four gas burners as well as a
traveling grate for wood firing, staged combustion was achieved by removing one of the four gas
burners from service. Although 20 percent NOX reduction was achieved, it should be noted that
combustion modification was applied to the gas burners without any change to the wood-firing
stoker system. This control approach would not be possible on boilers without supplemental gas
firing. Difficulties were experienced with fluctuating bark flows, resulting in unsteady combustion
conditions.74
Applications of combustion modifications to new nonfossil-fuel-fired units involve MSW-
fired boilers equipped with FGR and natural gas reburn controls. Gas reburn for MSW boilers
is being developed by Riley Stoker and Takuma Company, for NOX control purposes and to
suppress the formation of air toxic organics and combustible emissions.97 In a 45 MMBtu/hr
overfeed stoker MSW facility in Minnesota, NOX emissions were reduced by 40 percent using
FGR. When natural gas reburn was used in combination with FGR, NOX was reduced by
60 percent, to a controlled level below 50 ppm. CO emissions were also decreased by 50 percent,
to levels below 25 ppm. Natural gas reburn represented 12 to 15 percent of the total heat input,
and FGR rates during these tests were roughly 8 percent.97 Test results from a pilot-scale
5-70
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MSW-fired stoker boiler equipped with FGR and natural gas reburn showed 49 percent NOX
reduction efficiency, utilizing 17 percent FGR.98>" Because of the limited documented
experiences regarding the retrofit of combustion modifications to existing nonfossil-fuel-fired
boilers, no meaningful conclusions can be reached as far as NOX control effectiveness or
feasibility.
S3 FLUE GAS TREATMENT NOX CONTROLS FOR ICI BOILERS
NOX control with flue gas treatment involves the reduction of NOX in the flue gas by
injecting a chemical reducing agent into the post-combustion region of a combustion unit. The
reducing agents, primarily ammonia and urea, convert the NO in the flue gas to molecular
nitrogen at high temperatures, between 870 and 1,100°C (1,600 and 2,000°F), without a catalyst.
When a catalyst is used, this conversion takes place at a lower temperature range, roughly
300 and 425°C (575 to 800°F). Flue gas treatment methods without a catalyst are SNCR, while
those with a catalyst are termed SCR. These methods are discussed in the following subsections.
Retrofitting these technologies to boilers typically involves installation of reagent
injection nozzles, reagent storage and control equipment, and, in the case of SCR, catalytic
reactors. Because flue gas treatment NOX reduction efficiency depends in large part on flue gas
temperature, injection nozzle placement is limited to those locations where acceptable process
temperatures are present. Generally, in packaged ICI boilers, available locations for reagent
injection and catalyst placement are further limited by space considerations. These units may
also operate with wide ranges in boiler steam load that cause flue gas temperature shifts outside
the optimum temperature window. Injection of reagents outside the optimum reaction
temperature window results in lowered NOX reduction efficiency and emisfiors of unreacted
ammonia. SNCR and SCR controls have been applied primarily to larger boilers or new
packaged boilers because these applications offer better control of temperature window and
steady load demands.
5.5.1 Selective Noncatalytic Reduction (SNCR)
Two primary types of SNCR control technologies are currently available for retrofit to
ICI boilers. The first is based on the use of ammonia (NH3) as the reducing agent, while the
second, more recently introduced, is based on the use of urea (NH2CONH2). Several urea-based
systems have been patented and are commercially offered by several domestic vendors. The
following subsections briefly describe the experience to date using these controls on ICI boilers.
Available data for SNCR application to industrial boilers are contained in Appendix B and
5-71
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summarized in Table 5-12. Generally, similar NOX reduction efficiencies were obtained whether
ammonia or urea was used. For ammonia injection, NOX reduction ranged from 50 to
80 percent, depending on fuel type. For urea-based systems, most reported NOX reduction
efficiencies also fell within this range, although some were as low as 25 percent and as high as
88 percent. Experience with SNCR on smaller capacity boilers is minimal. Low-load operation
and frequent load changes on such boilers pose additional complexities on the retrofit of SNCR
for these boilers.
5.5.1.1 Ammonia-based SNCR
Exxon Research and Engineering Company developed and patented an ammonia-based
SNCR process known as Thermal DeNOx«. The Thermal DeNOx process is based on a gas
phase homogeneous reaction between NOX and ammonia which produces molecular nitrogen and
water at high temperature. In this process, aqueous or anhydrous ammonia is vaporized and
injected into the flue gas through wall-mounted nozzles at a location selected for optimum
reaction temperature and residence time. The optimum reaction temperature range for this
process is 870 to 1,100°C (1,600 to 2,000°F), although this can be lowered to 700°C (1,300°F)
with additional injection of gaseous hydrogen.100 At temperatures above 1,1QO°C (2,000°F),
ammonia injection becomes counterproductive, resulting in additional NO formation. Below
870°C (1,600°F), the reaction rate drops and undesired amounts of ammonia are carried out in
the flue gas. Unreacted ammonia is commonly referred to as ammonia slip, breakthrough, or
carryover.101 The amount of ammonia slip also depends in part on the amount of ammonia
injected. Although the chemical reaction requires one mole of NH3 for each mole of NO, the
NH3/NOX ratio used is usually greater than 1 to avoid an undesired reaction which results in
formation of NO.100 NH3/NOX ratios of 4 to 1 have been reported in fluidized bed
applications.102 Ratios used are usually greater than 1 due to competing reactions at the
temperatures involved.
The Thermal DeNOx process has been applied to a number of boilers firing both fossil
and nonfossil fuels. In the U.S., most Thermal DeNOx applications have been on new units,
many located in California. At least two retrofit applications on wood-fired industrial boilers
have also been reported, one to a 375 MMBtu/hr wood-fired stoker unit and one to a
210 MMBtu/hr boiler, also a wood-fired stoker.100 Both retrofits resulted in 50 percent NOX
reduction, with controlled emissions of 45 and 50 ppm (0.06 and 0.07 Ib/MMBtu).
5-72
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Overall, experience with ammonia-based SNCR on both new and existing units has
shown the following results, listed in Table 5-12. NOX reduction ranged from 50 to 80 percent
for 10 wood-firing stokers and between 44 and 80 percent for eight wood-firing FBC units. For
13 MSW-fired units, NOX reduction ranged from 45 to 79 percent, while for four coal-fired FBC
units, 76 to 80 percent reductions were achieved. Several natural-gas-fired furnaces experienced
30 to 72 percent NOX reduction. In addition to these applications, it has been reported that
ammonia-based SNCR has been used on over 100 TEOR steam generators burning crude oil in
Kern County, achieving reductions of approximately 70 percent.103 Thus, for all applications,
ammonia-based DeNOx reduced NOX by roughly 30 to 80 percent. The upper range of NOX
reduction efficiency range is more characteristic of boilers operating at steady load such as
cogeneration FBC units.
Achievable NOX reductions for an individual boiler depend on the flue gas temperature,
the residence time at that temperature, the initial NOX concentration, the NH3/NOX ratio, the
excess oxygen level, and the degree of ammonia/flue gas mixing. Also, stratification of both
temperature and NOX in the flue gas can affect the performance of the SNCR control.104 The
optimum placement of SNCR injectors requires a detailed mapping of the temperature profile
in the convective passes of the boiler, because of the narrow temperature window. According
to Exxon, the Thermal DeNOx process has no measurable effect on CO, CO-,, or SOX
emissions.100
The feasibility of retrofitting an existing boiler with SNCR often hinges on the ability
to accommodate injection nozzles at a location where flue gas temperatures and residence time
are optimum for the reaction to take place. In field-erected boiler^, the ammonia is usually
injected into either a superheater tube bank or between a superheater tube bank and the steam
generator tube bank,103 while, for a typical wood-fired stoker boiler, injectors are usually located
before the first superheater coil. In a coal or wood-fired CFBC boiler, ammonia injectors are
usually located after the cyclone to avoid high solids and NH3 recirculation.100 Smaller units,
especially packaged watertube and firetube boilers, have limited space and access for the
injection nozzles.
5.5.1.2 Urea-based SNCR
Originally developed by the Electric Power Research Institute (EPRI), a newer SNCR
technology for flue gas treatment NOX control utilizes urea as a reagent rather than ammonia.
One urea-based SNCR process, known by the trade name of NOxOUT®, is offered by Nalco
5-74
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Fuel Tech, Inc., and its licensees (Foster Wheeler, Wheelabrator Air Pollution Control, Research
Cottrell, Todd Combustion, RJM Corporation, and several others internationally). Other
vendors, such as Applied Utility Systems and Noell, Inc., have also developed and installed urea-
based SNCR processes. In the NOxOUT process, an aqueous solution containing urea and
chemical enhancers is injected into the furnace or boiler at one or more locations, depending on
the boiler type and size. The urea reacts with NOX in the flue gas to produce nitrogen, carbon
dioxide, and water. The main advantage of urea injection over ammonia injection is that urea
is a nontoxic liquid that can be safely stored and handled.
Like ammonia injection, NOxOUT is effective only within a certain temperature range.
Without the use of chemical enhancers, urea injection effectively reduces NOX at temperatures
between 900 and 1,150°C (1,650 and 2,100°F). Residence time at temperature of interest is
important. By using proprietary enhancers and adjusting concentrations, greater NOX reduction
efficiency can be achieved over a wider temperature window. If the urea is released at too high
a temperature, the chemical species can actually be oxidized to form NOX. Below this
temperature, urea reacts with NOX to form undesired amounts of ammonia. Table 5-12 lists
NOX reduction efficiencies of 25 to 88 percent, reported for different types of-boilers burning
coal, oil, MSW, and wood which have been retrofitted with urea injection. As with Thermal
DeNOx, actual reduction performance is highly dependent on temperature, amount of reagent
used, and level of reagent/NOX mixing.105 Most of the commercial experience includes MSW-,
wood-, and coal-fired stokers, and gas-fired boilers and incinerators. These applications have
been on new and existing units. Successful demonstrations are documented on oil- and coal-fired
boilers in the utility industry. NOX reductions of as low as 10 percent to as high as 76 percent
have been recorded for utility boilers. An average NOX reduction performance of 45 percent
is estimated for PC-fired boilers.106 Due to residence time and temperature constraints, small
packaged watertube and firetube boilers with fluctuating steam loads are difficult applications,
and require case-by-case determinations for cost and performance levels.
552 Selective Catalytic Reduction (SCR)
The SCR process takes advantage of the selectivity of ammonia to reduce NOX to
nitrogen and water at lower temperature in the presence of a catalytic surface. Two catalyst
formulations are denoted "base metal," this category including oxides of titanium, molybdenum,
tungsten, and vanadium, and zeolites, which are alumina-silicate-based. These formulations may
include other components that impart structural stability. Catalysts come in various shapes and
5-75
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sizes, according to the particular application. Gaseous ammonia is injected with a carrier gas,
typically steam or compressed air, into the flue gas upstream of the catalyst. The ammonia/flue
gas mixture enters the catalyst, where it is distributed through the catalytic bed. The flue gas
then leaves the catalytic reactor and continues to the exit stack or air preheater. SCR technology
is capable of achieving similar NOX reductions as Thermal DeNOx SNCR using a much smaller
amount of ammonia, due to the positive effects of the lower reaction temperature and the
selective catalyst.101 Because of this, ammonia slip tends to be less with SCR than with SNCR.
SCR operates most efficiently at temperatures between 300 and 425 °C (575 and 800°F)
and when the flue gas is relatively free of particulate matter, which tends to contaminate or
"poison" the catalytic surfaces.101'107 Recent catalyst formulations can resist poisoning and
abrasion in flue gas environments with high ash loading and trace metals, while maintaining NOX
reduction performance. Typically, the catalytic reactor is located ahead of the air heater, to take
advantage of the temperature regime. Sometimes, however, the reactor may be placed just
ahead of the stack and downstream of particulate collection devices, avoiding catalyst
contamination. In most cases, however, such placement requires reheating of the flue gas to
meet temperature requirements, impacting the cost of the system. To avoid reheat
requirements, some manufacturers are currently developing or have already developed special
low-temperature catalysts which can be used at temperatures as low as 200°C (400°F).107
SCR has seen very limited application on domestic ICI boilers. Table 5-13 shows a
selected list of SCR applications on industrial boilers in California. A more complete list of SCR
installations on ICI boilers is included in Appendix B. Most of the industrial applications of this
control technology have been in Jap^n, where much of the original SCR technology development
took place. Within the industrial sector, SCR has been applied primarily to gas- or oil-fired
units, as well as a few PC-fired units or coal-fired BFBCs. SCR has not yet been demonstrated
in CFBC units or stoker coal-fired boilers. However, it was recently announced that SCR will
be incorporated into the design of a 220 MWe stoker coal-fired power plant in Virginia, as well
as a 125 MWe CFBC in Sweden.108'109 Major suppliers of SCR catalysts include MHI, Babcock
Hitachi, Cormetech, Engelhard, Johnson Matthey, and Norton.
Table 5-14 summarizes performance data for SCR applications to boilers in the ICI
sector. Data from Japanese oil-fired industrial boilers retrofitted with SCR show NOX reductions
ranging from 85 to 90 percent. These units had controlled NOX levels between 17 and 25 ppm
(0.02 and 0.03 Ib/MMBtu), operating with flue gas treatment temperatures of 300 to 370°C (575
5-76
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TABLE 5-13. SELECTED SCR INSTALLATIONS, CALIFORNIA ICI BOILERS
Controlled NO, emissions
Boiler ID
Darling-Delaware
Fletcher Oil and Refining
Lockheed
Kalkan Foods, Inc.
Ultramar Refinery
Southern California
Edison
Boiler type
PKG-WT
Unknown
PKG-WT
PKG-WT
PKG-WT
Unknown
uapaciiy,
MMBtu/br
110
49
NA.b
78.6
RA.
107 MWe
Fuel used
Natural gas/
propane
Distillate oil
Natural gas/
distillate oil
Natural gas/
methanol
Refinery gas
Natural gas
ppm @ 3% O2
9
20
9
9
11
20
Ib/MMBtu
0.011
0.025
0.011
0.011
0.011
0.024
•PKG-WT = Packaged watertube boiler.
bNA. = Not available.
TABLE 5-14. SCR NOX CONTROLS FOR ICI BOILERS
Description of
technique
Injection of ammonia
into flue gas to
chemically reduce
NOX
Number of
industrial
Fuel type boilers testei
Oil
Natural Gas
Coal
Ref. gas
MSW
Wood waste
7
3
2
4
1
2
Controlled levels
ftNO,
d reduction
85-90
53-80
53-63
83-94
53
80
ppm @ 3%
O2 Ib/MMBtu Comments
17-25
9-46
72-110
9-11
36
154
0.022-0.032 Temperature window
between 300 and 42i"C
0.011-0.055 (575 and 800°F).
0.097-0.15
0.011-0.013
0.051
0.22
5-77
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to 700°F).109 Specific information was not available on the types of oil fired in these boilers or
on boiler operating conditions; therefore, these reported NOX levels should not be used to
extrapolate controlled NOX levels for all oil-fired boilers.
Similar reduction efficiencies of 83 and 94 percent were obtained on units firing refinery
gas.110 One of these units was located in Japan, the others at a California refinery. Results
from tests conducted on three natural-gas- and two coal-fired boilers with SCR showed more
moderate reduction efficiencies of 53 to 80 percent. Likewise, a single MSW-fired unit
experienced 53 percent NOX reduction with SCR.101 In summary, NOX reduction efficiencies
with SCR have been reported in the range between 53 and 90 percent. Available data are too
limited, however, to allow any correlations between fuel type, boiler type, and SCR effectiveness
to be made.
The retrofit of SCR to an existing boiler requires far more extensive modifications than
does SNCR, as the SCR reactor must be placed in the existing flue gas path where the
temperature is sufficiently high for efficient NOX control. This is in addition to the required
installation of reagent injectors and storage and control equipment. The difficulty in retrofitting
SCR to existing boilers was reflected in the compliance plans put forth by petroleum refiners in
California's South Coast Air Basin, in response to the SCAQMD Rule 1109. Rather than
retrofit existing boilers with SCR, many refiners instead opted to replace their old boilers with
new units already incorporating SCR.111 Because catalysts lose their effectiveness over time due
to contamination or clogging of catalyst pores, they must be replaced periodically. On large
boilers, it has been reported that catalyst replacement may be necessary every 1 to 5 years,
depending on the application and the level of contaminants in the fuel.112
5.6 SUMMARY OF NOX REDUCTION PERFORMANCE
Table 5-15 summarizes the reduction efficiencies and controlled NOX levels for each
boiler, fuel, and control combination investigated in this report. Arithmetic average
performances are listed, but care must be used in interpreting them. Because these are averages,
the data do not represent the NOX control performance attainable in all cases. Actual
performance will be influenced by several factors, including fuel type, degree of control applied,
and the boiler's design and operating condition. Because coal and residual oil can vary in
nitrogen content and other properties, the actual NOX level achieved with these fuels will be very
much a function of these fuel properties. Certainly, the degree of FGR and air staging applied,
5-78
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TABLE 5-15. SUMMARY OF NOX REDUCTION PERFORMANCE
Boiler and fuel
PC-fired boilers:
all firing types
with wall or corner
burners
Coal-fired stokers
Coal-fired FBC
Gas-fired firetube
Gas-fired SEWT^
NO, control
SCA
LNB
Reburn+OFA
LNB+SCA
SNCR
SCA
FOR + SCA
SNCR
SCA
FGR+SCA
SNCR
SCR
LNB
Radiant LNB
FOR
LNB+FGR
WI
FOR
LNB
LNB : FOR
SCR
Range in
Reduction
efficiency, %
15-39
18-67
30-65
42-66
30-83
-1-35
0-60
40-74
40-67
NA.e
57-88
53-63
32-78
53-82
55-76
NA.
50-77
53-74
46-71
55-84
80-91
performance
Controlled NO*
Ib/MMBtu
033-0.93
0.26-0.50
023-0.52
024-0.49
0.15-0.40
022-052
0.19-0.47
0.14-028
0.05-0.45
0.12-0.16
0.03-0.14
0.10-0.15
0.02-0.08
0.011-0.036
0.02-0.08
0.02-0.04
0.04-0.056
0.02-0.08
0.03-0.11
0.018-0.09
0.011-0.06
Average
Reduction
efficiency, %
27
55
52
60
45"
18
24
58
58
NA.
74
60
50
71
65
NA.
64
64
58
76
85
performance*
Controlled NO,,
Ib/MMBtu
0.62
0.35
034
038
039
038
054
0.22
0.18
0.14
0.08
0.12
0.03
0.02
0.07
0.03
0.05
0.05
0.08
0.06
0.024
"Arithmetic averages of reported control efficiency NOX levels with specified controls. Values
do not necessarily reflect emission targets that can be achieved in all cases.
bAverage NO, reduction is based on utility boiler PC experience.
°NA. = Not available.
"SBWT = Single-burner watertube. Also referred to as packaged watertube (PKG-WT).
'Data for gas- and oil-fired watertube boilers are limited to performance reported in
Appendix B, exclusive of equipment vendor data reported in Appendix C.
(continued)
5-79
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TABLE 5-15. (continued)
Boiler and fuel
Gas-fired MEWr'
Distillate firetube
Distillate SBWT"
Residual oil
firetube
Residual oil
SBWT"-1
Residual oil
MEWr'
Wood-fired stoker
Wood-fired FBC
MSW-fired stoker
NO, control
SCA (BOOS)
LNB«
SNCR
SCR"
LNB+SCA
LNBh
FOR
LNB
FOR
LNB+FGR
SCR"
LNBj
LNB
FOR
LNB + FOR"
SCA
LNB'
LNB+SCAk
SCR'
SNCR
SNCR
SNCR
Range in
Reduction
efficiency, %
17-46
39-52
50-72
NA.C
NA.
15
NA.
NA.
20-68
NA.
NA.
30-60'
30-60
4-30
NA.
5-40
30-60
NA.
58-90
25-80
44-80
41-79
performance
Controlled NO,,
Ib/MMBtu
0.06-0.24
0.10-0.17
0.03-0.19
0.024
0.10-0.20
0.15
0.04-0.16
0.08-033
0.04-0.15
0.03-0.13
0.011
0.09-0.25
0.09-0.23
0.12-0.25
0.23
0.22-0.74
0.09-0.23
0.22
0.025-0.15
0.04-0.23
0.035-0.20
0.06-0.31
Average
Reduction
efficiency, %
31
46
58
NA.
NA.
15
NA.
NA.
44
NA.
NA.
40
40
15
NA.
20
40
NA.
85
58
64
60
performance*
Controlled NO,,
Ib/MMBtu
0.15
0.12
0.10
0.024
0.15
0.15
0.12
0.10
0.08
0.07
0.011
0.17
0.19
0.17
0.23
034
0.19
0.22
0.045
0.13
0.09
0.18
•Arithmetic averages of reported control efficiency NO, levels with specified controls. Values do not
necessarily reflect emission targets that can be achieved in all cases.
"NA. = Not available.
"SBWT = Single-burner watertube. Also referred to as packaged watertube (PKG-WT).
"Data for gas- and oil-fired watertube boilers are limited to performance reported in Appendix B, exclusive
of equipment vendor data reported in Appendix C.
'MBWT = Multi-burner watertube. Also referred to as field-erected watertube (FE-WT).
'Most LNB applications include FGR.
hOnly one data point available.
'Experience relies primarily on Japanese industrial installations.
'No data available. NO, levels assumed to be on the same order as those reported for single-burner
packaged watertubes.
5-80
-------
or the amount of ammonia or urea reagent used, will influence the percent reduction efficiency
and the NOX level achieved.
NOX from pulverized coal combustion in industrial boilers with LNB controls was shown
to be controlled to levels ranging from 0.26 to 0.50 Ib/MMBtu. These data include results for
both tangential- and wall-fired boilers. The average, 0.35 Ib/MMBtu, is lower than reported
average control levels for utility boilers.113 Therefore, this average efficiency should be used
cautiously, considering the limited data available to this study. Other data show SNCR to be
quite effective in reducing NOX from coal- and waste-fuel-fired FBC and stoker boilers. Average
levels for these sources controlled with either ammonia or urea range from 0.08 to 0.22
Ib/MMBtu. For gas- and distillate-oil-fired ICI boilers, FOR and LNB controls operating alone
or in combination can attain NOX levels averaging 0.02 to 0.15 Ib/MMBtu. Data on residual oil
are somewhat more sparse. NOX control levels from residual-oil-fired boilers are largely
influenced by the nitrogen content of the fuel. Combustion controls for these boilers show
average controlled levels ranging from 0.17 to 0.34 Ib/MMBtu.
5-81
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February 1993. p. 100.
49. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 48.
50. Ibid. p. 51.
51. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 53.
52. Waibel, R., et al. (John Zink Co.). Fuel Staging Burners for NOX Control. ASM
International. Metals Park, OH. April 1986.
5-86
-------
53. Southern California Edison. NOX Emission Control for Boilers and Process Heaters—A
Training Manual. Southern California Edison. Rosemead, CA. April 1991.
54. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987, p. 61.
55. Oppenberg, R. Primary Measures Reducing NOX Levels in Oil- and Gas-Fired Water
Tube Boilers. Report No. 176. Deutsche-Babcock. Germany. September 1986.
56. Londerville, S. B., and J. H. White (Coen Company). Coen Company Overview and
Burner Design developments for NOX Control. Proceedings: Third Annual NOX
Control Conference. Council of Industrial Boiler Owners. Burke, VA. February 1990.
57. Personal communication with Brizzolara, L., A. H. Merrill & Associates, Inc. Coen
Company Low NOX Installation List. June 22, 1992.
58. Tampella Power. Faber Burner-LNB Projects List. Tampella Power Corporation.
Williamsport, PA. 1992.
59. Lisauskas, R. A., and Green, R. W. Recent Low-NOx Gas and Oil Burner Applications.
Proceedings: 1993 Joint Symposium on Stationary Combustion NOX Control. U.S.
Environmental Protection Agency/Electric Power Research Institute. May 1993.
60. Nationwide Boiler, Inc. Faber Low NOX Burner Summary. Nationwide Boiler Inc.
Tustin, CA. 1989.
61. Micro-NOx Low NOX Burners. Publication No. Micro-NOx/11-89. Coen Co., Inc.
Stockton, CA. November 1989.
62. Suzuki, T., et al (Kobe Steel). Development of Low-NOx Combustion for Industrial
Application. Proceedings: 1985 Symposium on Stationary Combustion NOX Control.
Publication No. EPRICS-4360. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. January 1986.
63. Alzeta Corp. Commercial Status of the Radiant Pyrocore Burner in Process Heaters
and Boilers. Alzeta Corp. Santa Clara, CA. May 1988.
64. Gas Research Institute. Field Test Update: Ceramic Fiber Burner for Firetube Boilers.
Gas Research Institute. Chicago, IL. August 1987.
65. Letter and attachments from Moreno, F. E., Alzeta Corporation, to Castaldini, C,
Acurex Environmental Corporation. July 26, 1993.
5-87
-------
66. Chojnacki, D., et al. (Donlee Technologies, Inc.). Developments in Ultra-Low NOX
Burner/Boilers. Proceedings of the 1992 International Gas Research Conference. 1992.
p. 352.
67. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 63.
68. Ibid. p. 65.
69. Low-NOx Burner Design Achieves Near SCR Levels. Publication No. PS-4446. John
Zink Company. April 1993. P. 4.
70. Ibid. p. 5.
71. Ln/Series-Low NOX Flue Gas Recirculation. Brochure 34. Industrial Combustion.
Monroe, WI. October 1989.
72. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustion Modification NOX
Controls — Volume I, Environmental Assessment. Publication No. EPA-600/ 7-81-126a.
U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981. pp.
3-69.
73. Ibid. p. 3-39.
74. Hunter, S. C, et al. Application of Combustion Modifications to Industrial Combustion
Equipment. KVB, Inc. Irvine, CA. 1977.
75. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustion Modification NOX
Controls—Volume I, Environmental Assessment. Publication No. EPA-600/ 7-81-126a.
U.S. Environmental Protection Agency. P>.esearch Triangle Park, NC. July 1981.
p. 7-39.
76. Castaldini, C. Evaluation and Costing of NOX Controls for Existing Utility Boilers in
the NESCAUM Region. Publication No. EPA 453/R-92-010. U.S. Environmental
Protection Agency. Research Triangle Park, NC. December 1992. p. 4-26.
77. Lim, K J., et al. (Acurex Corp.) Industrial Boiler Combustion Modification NOX
Controls — Volume I, Environmental Assessment. Publication No. EPA-600/ 7-81-126a.
U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981.
p. 3-43.
78. Environmental Assessment of Utility Boiler Combustion Modification NOX Controls.
Publication No. EPA-600/7-80-075a and b. U.S. Environmental Protection Agency.
Research Triangle Park, NC. April 1980.
5-88
-------
79. Castaldini, C. Evaluation and Costing of NOX Controls for Existing Utility Boilers in
the NESCAUM Region. Publication No. EPA 453/R-92-010. U.S. Environmental
Protection Agency. Research Triangle Park, NC. December 1992. p. 4-27.
80. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 75.
81. Letter and attachments from DeHaan, T., Coen Co., Inc, to Seu, S., Acurex
Environmental Corporation. Low NOX Retrofits. February 6, 1992.
82. Folsom, B. A., et al. Preliminary Guidelines for Gas Cofiring in Coal-Designed Boilers.
Gas Research Institute Report prepared under GRI Contract No. 5091-254-2368.
September 1992. p. 3-9.
83. Letter and attachments from Chant, P., the FReMCo Corporation, Inc., to Neuffer,
B. J., U.S. Environmental Protection Agency. October 13, 1993.
84. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 45.
85. Nutcher, P., and H. Shelton. NOX Reduction Technologies for the Oil Patch. Process
Combustion Corporation. Presented at the Pacific Coast Oil Show and Conference.
Bakersfield, CA. November 1985.
86. Collins, J. (Radian Corp.). Technology Study of NOX Controls for "Small" Oil Field
Steam Generators. Document No. 87-243-101-02. Prepared for Western Oil and Gas
Association. Bakersfield, CA. January 1987.
87. Kern County Air Pollution Control District. 1986 Pollutant Survey (TEOR steam
generators). November 1986.
88. Nutcher, P. High Temperature Low NOX Burner Systems for Fired Heaters and Steam
Generator. Process Combustion Corp. Presented at the Pacific Coast Oil Show and
Conference. Los Angeles, CA. November 1982.
89. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. pp. 53-56.
5-89
-------
90. Letter and attachments from Nutcher, P. B.,- Process Combustion Corporation, to
Votlucka, P., South Coast Air Quality Management District. Description of a Single
Toroidal Combustor Low-NOx Burner used in TEOR Steam Generators. July 1987.
91. Nutcher, P. B. High Technology Low NOX Burner Systems for Fired Heaters and Steam
Generators. Process Combustion Corp. Pittsburgh, PA. Presented at the Pacific Coast
Oil Show and Conference. Los Angeles, CA. November 1982. p. 14.
92. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 55.
93. Castaldini, C, et al. Environmental Assessment of an Enhanced Oil Recovery Steam
Generator Equipped with a Low NOX Burner. Acurex Report No. TR-84-161/EE.
Acurex Corporation. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. January 1985.
94. Swientek, R. J. Turbulence Device Cuts Gas Consumption. Food Processing Magazine.
May 1992. p. 201.
95. Summary of Meeting Between Neuffer, W., U.S. Environmental Protection Agency, and
Rosborne, J., Utilicon Associates, Inc. GASPROFLO™ Fuel Turbulator Information.
April 1993.
96. Flow Modifier Ups Efficiency in Gas-Fired Boilers. Power Magazine. January 1992.
p. 101.
97. Abbasi, H., and F. J. Zone. Emission Reduction from MSW Combustion Systems Using
Natural Gas. Gas Research Institute Report No. 92/0370. Institute of Gas Technology
and Riley Stoker Corporation. Chicago, IL. December 1992.
98. Penterson, C.A., et al. (Riley Stoker Corporation). Reduction of NOX Emissions From
MSW Combustion Using Gas Reburning. Proceedings: 1989 Symposium on Stationary
Combustion NOX Control. Publication No. EPRI GS-6423. U.S. Environmental
Protection Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
99. Usauskas, R. A., et al. (Riley Stoker Corporation). Status of NOX Control Technology
at Riley Stoker. Proceedings: 1989 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. July 1989.
100. Haas, G. Selective Non-Catalytic Reduction (SNCR): Experience with the Exxon
Thermal DeNOx Process. Exxon Research and Engineering Co. Presented at the Fifth
NOX Control Conference Council of Industrial Boiler Owners. Long Beach, CA.
February 1992.
5-90
-------
101. Clarke, M. (Environmental Research and Education). Technologies for Minimizing the
Emission of NOX from MSW Incineration. Technical Paper No. 89-167.4. Air and
Waste Management Association. Pittsburgh, PA. June 1989.
102. Hurst, B. E., et al. Exxon Thermal DeNOx Effectiveness Demonstrated in a
Wood-Fired Boiler. Exxon Research and Engineering Company. Florham Park, NJ.
Presented at the 13th National Waste Processing Conference and Exhibit. May 1-4,
1988.
103. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 70.
104. Mason, H. NOX Control by Non-Catalytic Reduction. Acurex Corp. Presented at the
Second NOX Control Conference, Council of Industrial Boiler Owners. City of Industry,
CA. February 1989.
105. Epperly, W. R., et al. Control of Nitrogen Oxides Emissions from Stationary Sources.
Fuel Tech, Inc. Presented at the Annual Meeting of the American Power Conference.
Illinois. April 1988.
106. Alternative Control Techniques Document—NOX Emissions from Utility Boilers.
Publication No. EPA-453/R-94-023. U.S. Environmental Protection Agency. Office of
Air Quality Planning and Standards. Research Triangle Park, NC. March 1994.
107. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 72.
108. Cogentrix Eyes SCR for 220-MW Coal Plant; To Seek Permits Before Power Sales Deal.
Utility Environment Report. January 24, 1992.
109. Sweden Gets SCR for CFBs. Coal and Synfuels Technology. Volume 13, No. 12.
March 23, 1992.
110. Letter and attachments from confidential company to Votlucka, P., South Coast Air
Quality Management District. Industrial SCR Experience. October 1988.
111. Statewide Technical Review Group. Technical Support Document for Suggested
Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial,
Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.
California Air Resources Board and the South Coast Air Quality Management District.
Sacramento, CA. April 29, 1987. p. 73.
5-91
-------
112. Makansi, J. Reducing NOX Emission. Power Magazine. September 1988.
113. Castaldini, C. Evaluation and Costing of NOX Controls for Existing Utility Boilers in
the NESCAUM Region. Publication No. EPA 453/R-92-010. U.S. Environmental
Protection Agency. Research Triangle Park, NC. December 1992. pp. 1-12, 13.
5-92
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6. COSTS OF RETROFIT NOX CONTROLS
This chapter evaluates the economic impacts of controlling NOX from existing ICI
boilers. Costing methodologies and assumptions are discussed in Section 6.1. Section 6.2
presents the costs calculated for various NOX controls retrofitted to ICI boilers. Section 6.3
discussed the capital and total annual costs of NOX controls. Section 6.4 presents the cost
effectiveness of NOX controls. Supporting documentation, including costing spreadsheets, are
included as appendices. Appendix D contains cost effectiveness data for the boilers and control
systems analyzed, scaled from annual cost data of Appendices E, F, and G. The latter
appendices contain detailed cost analysis spreadsheets developed from actual data provided by
vendors, boiler owners, and regulatory agencies.
Whenever possible, cost data from actual retrofit projects were used to develop the cost
effectiveness figures presented in Section 6.4. When key cost figures from actual projects were
unavailable or not accounted for, however, the cost algorithms and assumptions described in
Section 6.1 were used to supplement the available cost data.
6.1 COSTING METHODOLOGY
The costing methodology used in this study is based primarily on the U.S. EPA's
OAQPS Control Cost Manual,1 although certain cost components have been modified specifically
for this study, based on conventional costing practice and actual cost data. Costs of retrofit NOX
controls for ICI boilers can be divided into two major cost categories — capital investment costs
and annual operations and maintenance (O&M) costs. Capital costs are the total investment
necessary to purchase, construct, and make operational a control system. O&M costs are the
total annual costs necessary to operate and maintain the control system, above what was required
to operate the pre-retrofit boiler without NOX control. Each of these cost categories can be
further subdivided into individual cost components. Section 6.1.1 discusses capital cost
components, Section 6.1.2 discusses elements of O&M costs, and Section 6.1.3 describes the
methodology for evaluating a control technology's overall cost effectiveness based on these
capital and O&M costs.
6-1
-------
6.1.1 Capital Costs of Retrofit NOX Controls
Capital costs of NOX controls include both direct and indirect cost components. Direct
capital costs are expenses required to purchase equipment for the control system, referred to as
purchased equipment costs, as well as those expenses required for installing the equipment in
the existing boiler, known as direct installation costs. Indirect capital costs are costs entailed in
the development of the overall control system, but not attributable to a specific equipment item.
These costs are also referred to as indirect installation costs. In addition to direct and indirect
components of capital investment costs, contingency costs are also added to account for
unpredictable expenses. Figure 6-1 illustrates these principal elements of total capital investment
and lists common sub-elements which comprise them. The major capital cost elements are
described in detail below.
All costs in this chapter and the appendices are presented in 1992 dollars. When
available cost data were referenced to other years, the Chemical Engineering Plant Cost Index
was used to convert costs to 1992 dollars.2"4
6.1.1.1 Purchased Equipment Costs
Purchased equipment costs include the costs of primary control equipment, such as
low-NOx burners, FOR fans, or catalytic converters; auxiliary control equipment;
instrumentation; and applicable sales taxes and shipping charges. When data were provided, the
cost of CEM equipment was also included in the purchased equipment cost. For this study,
instrumentation, tax, and freight charges were estimated as being 18 percent of the total primary
and auxiliary equipment costs.1
6.1.12 Direct Installation Costs
The second major component of direct capital costs, direct installation costs include both
labor and materials costs for foundations, supporting structures, piping, insulation, painting,
handling and erection, and electrical work. Direct installation costs vary considerably from site
to site and depend on such factors as availability of space, the amount of boiler modification that
must be done to accommodate the control system, and existing facilities. Although direct
installation costs may vary widely, they were estimated as 30 percent of purchased equipment
cost in this study, unless an actual cost figure was provided. This is towards the low end of
reported ranges for direct installation cost.1'5 When direct installation cost data for new boiler
applications were provided by vendors, the figures were doubled to account for additional retrofit
6-2
-------
• Primary Control
Derice
• Auxiliary Equipment
(including ductwork)
• Instrumentation8
• Sales Taxes*
• Freight"
• Foundations
and
Supports
• Handling
and Erection
• Electrical
• Piping
• Insulation
• Painting
|
Site
• Engineering
• Construction and
Field Expenses
• Contractor Fees
• Start-up
• Performance Test
• Contingencies
Purchased Direct Prepara"tione
-------
expenses.1*6 Costs of research and development and the cost of lost production during
installation and startup were not included in direct installation cost.
6.1.13 Indirect Installation Costs
Indirect installation costs consist of engineering costs, construction and field expenses,
construction fees, and expenses associated with startup, performance tests, and permitting.
When actual cost data were unavailable, these costs were estimated to be approximately
33 percent of the purchased equipment cost.1 For SCR retrofits, indirect installation was
estimated as 66 percent of purchased equipment cost to account for additional engineering and
construction requirements.
6.1.1.4 Contingencies
Contingency costs were added to capital cost estimates to account for additional
expenses due to such things as price changes, small design changes, errors in estimation, strikes,
or adverse weather conditions. These are unpredictable costs likely to occur.5 In the cost
spreadsheets of Appendices E, F, and G, contingency costs were estimated primarily as
20 percent of the total direct and indirect capital cost.7'8 Cost estimates obtained from selected
control vendors already included contingencies. To avoid double accounting, no additional
contingency costs were added.
6.1.1.5 Other Capital Costs
Other costs which may be included as capital costs are expenditures for site preparation,
buildings, land, and working capital. Site preparation costs are sometimes accounted for in direct
installation costs, and in most cases are unreported. Additional buildings are usually not
required for retrofit NOX control systems for ICI boilers, except in cases where existing facilities
are absolutely unable to accommodate additional equipment installation. For the purposes of
this study, site preparation and building costs were listed in the cost spreadsheets, but were only
used if sources provided costs for these items.
Working capital is a fund set aside to cover the initial O&M costs of labor, fuel,
chemicals, and other materials for a given time, usually on the order of 90 days.7 This fund is
primarily used in cost analyses for large systems which require significant amounts of utilities,
O&M labor, and materials.1 Because most of the control systems considered in this study do
not require large amounts of utilities, O&M labor and materials, working capital costs were not
included in this study. Costs of additional land were also not included since most retrofit control
systems do not require much space. These, omissions are consistent with U.S. EPA OAQPS
costing methodologies.1
6-4
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6.12 Annual Operations and Maintenance (O&M) Costs
Annual O&M costs of NOX control systems are classified as either direct or indirect
annual costs. For this study, O&M costs were considered to be costs resulting from the use of
the NOX control equipment only, and are separate from the annual O&M costs of the existing
boiler. Figure 6-2 displays common elements of annual O&M costs. Included as direct annual
O&M costs are expenses for labor and maintenance materials, utilities such as electricity or
steam, fuel or chemicals which may be required for the control system, and waste disposal which
may be required with SCR system catalysts. With FGR NOX control systems, boiler fuel
consumption may actually decrease due to increased boiler efficiency, resulting in an overall fuel
savings. Two sources estimated fuel savings of 1 to 2 percent when FGR was retrofitted.9'10
In the cost calculations of Appendices E, F, and G, fuel savings of 1 percent were included for
all FGR systems.
Prices for fuels and electricity in the U.S. were obtained from Energy User News.11 The
cost of electricity was estimated as $0.05/kWh, while the cost per MMBtu for natural gas,
distillate oil, and residual oil were estimated as $3.63, $4.83, and $2.35, respectively. The price
of bulk anhydrous ammonia used for ammonia injection systems was estimated-at $250 per ton,
while the price of bulk urea was estimated at $220 per ton.12
Indirect annual O&M costs include overhead, administrative charges, property taxes, and
insurance. Following the cost methodology developed by OAQPS, overhead charges were
estimated as 60 percent of the annual labor and maintenance materials costs, while
administrative, property tax, and insurance costs were estimated as 4 percent of the total capital
investment cost described in Section 6.1.1.1
Table 6-1 summarizes the assumptions made for estimating capital and O&M costs for
retrofit NOX control systems. When developing a NOX control cost spreadsheet based on data
from a particular reference source, these estimates were used whenever data were not provided
by the source.
6.13 Total Annualized Cost and Cost Effectiveness
Total capital investment and total annual O&M costs may be combined to give a total
annualized cost. Total capital investment is converted into uniform annual capital recovery costs
which represent the payments necessary to repay the capital investment over a given time period
at a given interest rate. This is done by multiplying the total capital investment cost by a capital
recovery factor. For this analysis, a 10-percent interest rate and an amortization period of 10
6-5
-------
• Raw materials
• Utilities
- Electricity
- Fuel
- Steam
- Water
- Compressed air
• Waste treatment/
disposal
Labor
- Operating
— Supervisory
.- Maintenance
Maintenance materi-
als
Replacement parts
Variable
Semi variable ——'
Direct
Costs
• Overhead
• Property taxes
• Insurance
• Administrative
charges
• Capital recovery
Indirect
Costs
• Materials
• Energy
Recovery
Credits
Total
Annual
Cost
Figure 6-2. Elements of total annual O&M cost.1
6-6
-------
TABLE 6-1. ASSUMPTIONS FOR ESTIMATING CAPITAL AND ANNUAL O&M COSTS
Cost element
Cost assumption
Direct capital costs
NOX control equipment
Instrumentation
Sales taxes
Total = Purchased Equipment Cost (PEC)
Direct installation cost
Site preparation
Buildings
Indirect capital costs
Engineering
Construction and field expenses
Construction fee
Startup
Performance test
Contingency
O&M costs
FOR fuel savings
Overhead
Administrative
Property tax
Insurance
Given
10% of equipment cost
3% of equipment cost
5% of equipment cost
30% of PEC
0 unless given
0 unless given
10% of PEC*
10% of PEC*
10% of PEC*
2% of PEC3
1% of PEC8
20% of direct and indirect capital costs
1% of boiler fuel cost
60% of labor and maintenance material cost
2% of total capital cost
1% of total capital cost
1% of total capital cost
"Increased by a factor of 2 for SCR installations.
years was assumed for the NOX control systems, which results in a capital recovery factor of
0.1627.13 The interest rate of 10 percent was selected as a typical constant dollar rate of return
on investment to provide a basis for calculation of annualized capital investment cost. Although
10 years was chosen as the capital amortization period, other periods could have been selected
if desired, as long as the same amortization period is used when comparing costs of different
control systems. When the annualized capital cost is added to the total annual O&M costs
discussed in Section 6.1.2, the resulting figure is the total annualized cost of the NOX control
system.
In order to compare the cost effectiveness of different controls on a given boiler, the
total annualized cost of each control system was divided by the amount of NOX removed by the
6-7
-------
system over 1 year. The amount of NOX removed from a boiler is a function of the achievable
NOX reduction of the control system and of the annual capacity of that unit. An annual capacity
factor represents the ratio of the amount of heat input a unit uses in a year to the amount it
could have used if it was operated at full rated capacity 24 hours a day, 365 days per year. For
the purposes of this study, it was assumed that all boilers, when operated, ran at full rated
capacity, as opposed to being run at half load, for example. However, the annual capacity factors
of all boilers were assumed to be less than 1.
The actual amount of boiler operating time over a year typically depends on the boiler
size and application. For example, smaller capacity boilers used in commercial or institutional
sectors are often operated intermittently, providing power for daily needs of office buildings,
schools, etc. as needed. On the other hand, larger units located in large manufacturing facilities
may operate almost continuously during the workweek. To illustrate the effect of capacity factor
on NOX control cost effectiveness, cost effectiveness was calculated for each boiler test case at
capacity factors of 0.33, 0.5, 0.66, and 0.8. While data for the complete range of capacity factors
are presented in the appendices, the summary tables in this chapter show cost effectiveness
calculated for the mid-range capacity factors of 0.5 and 0.66 only.
To estimate the amount of NOX removed by a control system per year, pre-retrofit and
post-retrofit NOX emission levels must be known, in addition to the boiler capacity factor and
heat input capacity rating. Assumed baseline NOX levels were selected for each fuel and boiler
type based on data contained in Appendices A and B and summarized in Table 4-7 of Chapter 4.
Table 6-2 lists the average baseline NOX levels assumed for the purposes of calculating cost
effectiveness. For natural-gas-flred watertube boilers, five boiler size categories were considered
in the retrofit cost analyses. Average baseline NOX emissions increase with boiler size because
of the higher heat release rate and greater thermal NOX formation. NOX reduction efficiencies
for each type of control were selected based on data contained in Chapter 5 and Appendix B,
and are listed in Table 6-3. These NOX reduction efficiencies are assumed levels only; actual
NOX reduction performance of particular control systems may vary depending on boiler, fuel, and
operating characteristics, as discussed in Chapter 5.
Total annualized costs are divided by the amount of NOX emission reduction per year
to obtain the cost effectiveness in terms of dollars per ton of NOX reduced. As stated earlier,
all costs in this analysis are expressed in terms of 1992 dollars.
6-8
-------
TABLE 6-2. BASELINE (UNCONTROLLED) NOX EMISSIONS USED FOR COST CASES
Baseline NO.,
Fuel
Natural gas
Distillate oil
Residual oil
Pulverized coal
Coal
Coal
Wood
Wood
Wood/natural gas
Paper
MSW
Boiler type
Firetube
Watertube
10 to <75 MMBtu/hr
75 to 150 MMBtu/hr
>150 to <350 MMBtu/hr
350 to <750 MMBtu/hr
£750 MMBtu/hr
All
All
Wall-fired
Spreader stoker
FBC
Stoker
FBC
Stoker
Packaged watertube
Stoker
Ib/MMBtu^
0.12
0.16
0.18
0.24
0.30
0.40
0.20
0.38
0.70
0.53
0.32
0.25
0.25
0.20
0.50
0.40
aTo convert to ppm at 3 percent CK multiply by the following factors: natural
gas, 835; distillate oil, 790; residual oil, 790; coal, 740; wood, 710; paper, 710;
MSW, 705 (approximate).
TABLE 6-3. NOX REDUCTION EFFICIENCIES USED FOR COST CASES
NOV control technology Applicable boiler equipment NOV reduction efficiency, %a
BT/OT PKG-WT and FT 15
BT/OT and WI PKG-WT and FT 65
BOOS with OT FE-WT 50
BOOS/WI with OT FE-WT 75
LNB PC: wall-fired 50
Nat. gas/oil: PKG-WT, FE-WTb 50
FOR Nat. gas/oil: PKG-FT0 40
LNB and FOR Nat. gas/oil: PKG-WT 60
SNCR PC: wall-fired 45
Coal: FBC 75
Coal: Stoker 58
Nonfossil: stoker, PKG-WT, FBC 55
SCR PC: wall-fired 80
Nat, gas/oil: PKG-WT 85
aSee Chapter 5 and Appendix B.
bPKG-WT = packaged watertube; FE-WT = field-erected watertube.
°PKG-FT = packaged firetube.
6-9
-------
62 NOX CONTROL COST CASES AND SCALING METHODOLOGY
NOX control cost cases were selected based on the prevalence of control system
applications to specific types and sizes of boilers and on the availability of cost data. Table 6-4
lists the cost cases analyzed and data sources from which various cost figures, principally capital
and annual costs, were obtained. Cost data were compiled primarily from published reports and
communications with selected boiler operators and control system manufacturers. Cost data for
PC-fired boilers were limited to LNB, SNCR, and SCR control technologies. Capital and O&M
costs for LNB and SCR were provided by the Council of Industrial Boiler Owners (CEBO)14, and
recent costs were developed for small utility PC-fired boilers.15 Cost estimates for SNCR with
urea and ammonia reagents were provided by vendors of these technologies. Experience with
NOX controls for ICI PC-fired boilers is generally very sparse; therefore, these cost estimates
should be used with caution. Data on NOX controls for FBC boilers were limited to SNCR, since
combustion staging is usually integrated into the original FBC boiler design and operation. For
firetube boilers, data were also limited primarily to FOR only. Cost estimates of WI + OT for
firetube boilers were based on the data reported for packaged watertube boilers.
Raw data from the referenced sources listed were used to calculate-the annual cost
effectiveness figures presented in Appendices E, F, and G. Cost effectiveness estimates for each
of the NOX control cost cases were then obtained from these values, using the logarithmic scaling
law known as the "six-tenths power rule," to account for differences in boiler capacity size. Cost
effectiveness was calculated for each cost case, using each applicable source of raw cost data.
For example, the cost effectiveness of LNB used in 10 to 250 MMBtu/hr (2.9 to 73 MWt)
natural-gar-fLed packaged watertube units was calculated using annual costs derived from
References 6 and 14, each of which provided data on more than one LNB retrofit project. Each
individual retrofit project was used to calculate a cost effectiveness value. Results obtained for
each cost case from each source are contained in Appendix D. The ranges in cost effectiveness
obtained from all sources are summarized in the following subsections. In all, cost data for 42
different boiler/NOX control configurations were used to develop these ranges, varying in boiler
type, size, fuel, and NOX control technology.
Most of the data obtained were for natural-gas-fired units, in part because of boiler
retrofit activity in California's South Coast Air Basin, where natural gas is the primary fuel used.
Cost effectiveness figures for distillate- and residual-oil-fired units were estimated using the
annual costs for natural-gas-fired units. Appropriate baseline NOX levels for fuel oil firing were
6-10
-------
TABLE 6-4. NOX CONTROL COST EFFECTIVENESS CASES
Fuel type
PC
Coal
Natural gas/distillate
oil/residual oil
Nonfossil fuel
Boiler type
Wall-fired
FBC
Spreader stoker
Packaged watertube
Packaged watertube
Packaged firetube
Packaged firetube
Packaged firetube
Packaged watertube
Packaged watertube
Packaged watertube
Field-erected
wall-fired
Stoker
Packaged watertube
FBC
Boiler
capacity,
MMBtu/hr
250-750
250-750
250-750
250-750
250-750
250-750
10-250
10-250
3-34
3-34
3-34
10-250
10-250
10-250
250-750
50-500
10-250
250-750
NOX control
technology
LNB
SNCR-ammonia
SNCR-urea
SCR
SNCR-urea
SNCR-urea
OT
OT+WI
OT
OT+WI
FOR
LNB
LNB + FOR
SCR
LNB -
SNCR-urea
SNCR-urea
SNCR-ammonia
Cost data
reference
14
16
17
15
18
17
19
19
19
19
20
6,14
6,14,21
9,22
14
16
16
23
used to calculate annual NOX reduction. For FOR, fuel oil prices were used to estimate the
annual fuel savings.
63
CAPITAL AND TOTAL ANNUAL COSTS OF NOX CONTROLS
Table 6-5 summarizes the capital and total annualized costs of retrofit controls on
selected "model" size boilers. The table also lists the anticipated NOX control levels applicable
to each control technology and model boiler. This information corresponds to data presented
in Chapter 5. The total annualized cost includes the payments for the initial investment and the
recurring direct and indirect O&M costs. The references indicate the sources of the capital cost
data, and, in some cases, the O&M cost data, used in the analysis. As indicated earlier, when
the reference cost data were for a different year or size of boiler, the capital costs were first
updated to 1992 base year and then adjusted for boiler size using the "six-tenths" power law.
That is:
6-11
-------
TABLE 6-5. CAPITAL AND TOTAL ANNUAL COSTS OF RETROFIT NOX CONTROLS FOR
ICI BOILERS, 1992 DOLLARS
Boiler type, size, and fuel
400 MMBtu/hr PC-fired
wall-fired watenube
400 MMBtu/hr FBC
400 MMBtu/hr stoker
10.5 MMBtu/hr oil/gas
firetube
50 MMBtu/hr oil/gas
packaged watenube
•
300 MMBtu/hr oil/gas
field-erected watertube
150 MMBtu/hr wood-
fired stoker
400 MMBtu/hr wood-
fired FBC
500 MMBtu/hr MSW
stoker
NOX control
LNB
SNCR
SCR
SNCR
SNCR
OT+WI
OT+FGR
OT+WI
LNB
LNB+FGR
SCR
OT+SCA
(BOOS)
LNB
SNCR
SNCR
SNCR
Controlled NOX>
lb/MMBtua
035
0.28
0.14
0.08
0.22
0.04 (Gas)
0.07 (Gas)
0.12 (No. 2 oil)
0.06 (Gas)
0.08 (Gas)
0.10 (No. 2 oil)
0.19 (No. 6 oil)
0.06 (Gas)
0.07 (No. 2 oil)
0.15 (No. 6 oil)
0.02 (Gas)
0.03 (No. 2 oil)
0.06 (No. 6 oil)
0.15 (Gas)
0.12 (Gas)
0.10 (No. 2 oil)
0.19 (No. 6 oil)
0.11
0.11
0.18
Capital cost,
$/MMBtu/hr
5300
1,600-2,100
20,000
1,600
1,100
2,400
5,400
530
650-2300
2,10(M,700
2,400-6,900
190
5,100-8300
2,100-2,500
970
2,100-3300
Total annual cost,
$/yr/MMBtu/hrb
1,220
950-1,200
5,800
680
1,200
690
1,100
210
340-420
430-890
1,500-1,900
96
990-1,500
500-800
590
940-1,100
Reference
14
16,17
15
18
17
19
20
19
6,14
6,14,21
9,22
19
14
16
23
15
"Arithmetic average of reported NOX control performance. Not indicative of levels achievable in all cases.
bCalculated based on 0.66 capacity factor or 5,460 operating hours per year at the boiler capacity.
Note: All estimates are rounded to two significant figures.
6-12
-------
Capital cost. =
(MMBtulhr),}*6 ., ..
21 Capital co^ (6-1)
(MMBtulhr\\
The ranges in both capital and operating costs indicate that the references provided more than
one cost case from which data could be extrapolated to the model boilers.
The reported capital cost of retrofit NOX controls has been found to vary by two orders
of magnitude, from the low cost of BOOS ($190/MMBtu) and WI ($530/MMBtu), on small- to
medium-sized gas-fired boilers, to the high estimate for SCR retrofit ($20,000/MMBtu/hr), on
PC-fired boilers. As shown, even the cost of SCR shows some large variations. Estimates from
vendors and installers of the technology indicated that SCR can cost as little as $2,400 to
$6,900/MMBtu for a relatively small gas-fired industrial boiler of 50 MMBtu/hr capacity (about
24 MWt), compared to an estimate of $20,000/MMBtu based on estimates from a comparable-
sized utility boiler.15 However, because of the lack of experience with SCR on coal-fired
industrial boilers, it is difficult to draw any definitive conclusions with respect to the actual
retrofit cost of SCR on these boiler types. Recent experience with utility boilers indicates that
the cost of SCR has lowered due to technology improvements and market competition. These
benefits are likely to transfer into the industrial boiler sector.
Where applicable, the capital cost of SNCR has been found to be in the same range as
the capital costs of such combustion controls as LNB and FOR. Both SNCR-urea and SNCR-
ammonia estimates were based on costs provided by vendors, and escalated to account for boiler
size differences. For example, for a PC-fired 800 MMBtu/hr (234 MWt) boiler, the capital cost
for SNCR-ammonia was estimated by Exxon to be about $900/MMBtu/hr.16 For an
812 MMBtu/hr (238 MWt) tangential boiler, the capital cost for SNCR-urea was estimated by
Nalco Fuel Tech to be about $600/MMBtu/hr.17, while a smaller, 400 MMBtu/hr boiler will.
require an investment of $830,000.17 Figure 6-3 plots the actual or estimated capital cost for the
Thermal DeNOx process for several boiler types. These costs were prepared by Exxon Research
and Engineering (ER&E) for new and retrofit installations on large, >250 MMBtu/hr (73 MWt),
industrial and utility boilers burning a variety of fuels, including waste fuels.24'25 These data
show the exponential increase in capital cost with decreasing boiler size (boiler capacity is plotted
on a logarithmic scale).
6-13
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6-14
-------
6.4 COST EFFECTIVENESS OF NOX CONTROLS
This section presents the cost effectiveness of various NOX controls retrofitted to a range
of ICI boilers, using the costing methodology and assumptions discussed earlier. Section 6.4.1
describes the boiler NOX control cases analyzed, and Sections 6.4.2 through 6.4.6 discuss the cost
analyses results.
6.4.1 NOX Control Cost Effectiveness: Coal-fired ICI Boilers
Table 6-6 summarizes the results obtained for coal-fired ICI boilers retrofitted with
various NOX controls. The cost effectiveness values presented here and in all subsequent tables
and figures in this chapter were calculated using capacity factors of 0.50 to 0.66. These capacity
factors were chosen as mid-range capacity levels for this analysis, although it is likely that small
ICI boilers such as packaged firetube units will have capacity factors less than 0.50.7 In all cost
cases, costs per ton of NOX control were higher as the capacity factor decreased, due to the
reduced amount of NOX removed. Thus, costs for boilers with capacity factors such as 0.33 will
be higher than those presented in this section. See Appendix D for calculated cost effectiveness
values for capacity factors of 0.33 and 0.80.
Figure 6-4 graphically shows the relationship of cost effectiveness and boiler capacity for
NOX controls retrofitted to PC wall-fired boilers. The cost estimates depicted are based on data
from a detailed cost study for a 766 MMBtu/hr (224 MWt) PC wall-fired unit.14 Cost estimates
for other boiler sizes were extrapolated using the 0.6 power law for capital cost and a
proportional dependence for O&M cost. The data show reduced costs per ton of NOX removed
as boiler capacity increases, due to greater amounts of NOX removed and economies of scale.
SNCR controls were the most cost effective per ton of NOX removed, with costs ranging from
a low of $950 per ton of NOX removed, for a 750 MMBtu/hr (220 MWt) unit, to a high of $ 1,340
per ton, for a smaller, 250 MMBtu/hr (73 MWt) unit. The difference in cost effectiveness
between SNCR with urea and SNCR with ammonia is well within the margin of error for this
cost analysis.
LNB controls required greater expenditures for equivalent NOX removal, ranging from
$980 to $ 1,760 per ton of NOX removed. LNB costs were developed based on estimates provided
by CD3O.14 SCR has the highest costs per ton of NOX removal, ranging from $4,610 to $7,810
per ton of NOX. These estimates were also developed from EPA cost estimates for a 100 MWe
utility boiler.15 Recent trends in SCR applications have shown significant decreases in capital
investment for this technology. However, due to the lack of experience in SCR application on
6-15
-------
TABLE 6-6. SUMMARY OF NOX CONTROL COST EFFECTIVENESS, COAL-FIRED
ICI BOILERS
Cost effectiveness,
$/ton NO
removed*'"
Boiler type
Boiler capacity,
MMBtu/hr
NOX control
Controlled NO,,
technology level, Ib/MMBtu
PC wall-fired
CFBC
Spreader
stoker
250
400
500
750
250
400
500
750
250
400
500
750
250
400
500
750
250
400
500
750
250
400
500
750
LNB
LNB
LNB
LNB
SNCR-ammonia
SNCR-ammonia
SNCR-ammonia
SNCR-ammonia
SNCR-urea
SNCR-urea
SNCR-ufea
SNCR-urea
SCR
SCR
SCR
SCR
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
0.35
0.35
0.35
0.35
0.39
0.39
0.39
0.39
0.39
0.39
0.39
0.39
0.14
0.14
0.14
0.14
0.08
0.08
0.08
0.08
0.22
0.22
0.22
0.22
1,340-1,760
1,170-1,530
1,090-1,430
980-1,280
1,360-1,450
1,310-1,400
1,300-1,370
1,270-1,330
1,120-1,340
1,040-1,240
1,010-1,190
960-1,130
3,800-4,800
3,400-4,200
3,200-4,000
3,000-3,700
960-1,130
890-1,030
860-980
810-920
1,360-1,440
1,320-1,380
1,300-1,360
1,280-1,320
aCapacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year
capital amortization.
b!992 dollars.
PC-fired boilers, the actual cost of this control option is speculative at this stage. Overall, on a
per-ton of NOX removed basis of comparison, SNCR controls were the most cost effective for
PC wall-fired boilers.
It should be noted that the controlled NOX levels achieved using LNB were higher than
those achieved using SNCR or SCR. This lower reduction efficiency, coupled with higher capital
costs, results in higher cost effectiveness for LNB technology. For SCR controls, the most
6-16
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expensive cost elements were purchased equipment -cost and annual chemical or catalyst
replacement costs. SCR catalyst replacement was based on a 4-year catalyst life. Both capital
and O&M SCR costs are in line with EPA estimates for small PC-fired utility boilers. In
general, costs per ton of NOX control for tangential-fired PC boilers may be expected to be
slightly higher than those estimated for the PC wall-fired units, since baseline NOX levels are
generally lower for tangential firing, and, hence, the amount of NOX removed will be slightly
lower.
6.4.2 NOX Control Cost Effectiveness: Natural-gas-flred ICI Boilers
Cost effectiveness estimates were made for packaged watertube, packaged firetube, and
field-erected wall-fired units firing natural gas, and are summarized in Table 6-7. Cost data for
26 different boilers were used to derive these estimates. Section 6.4.2.1 describes the results
obtained for packaged watertube units equipped with WI+OT, LNB, LNB + FGR, and SCR.
Section 6.4.2.2 presents cost effectiveness estimates for packaged firetube units retrofitted with
WI+OT, and FGR controls, and Section 6.4.2.3 discusses field erected wall-fired units retrofitted
with LNB. These estimates do not include the cost of purchasing and maintaining a fully
instrumented CEM system to monitor compliance with an emission limit. The impact of CEMs
on these costs is discussed in Section 6.4.6.
TABLE 6-7. SUMMARY OF NOX CONTROL COST EFFECTIVENESS, NATURAL-
GAS-FIRED ICI BOILERS
Boiler type
Packaged watertube
(single-burner)
Boiler
capacity,
MMBtu/hr
10
25
50
100
150
250
10
25
50
100
150
250
Controlled
NOX control NOX level, Cost effectiveness,
technology Ib/MMBru $/ton NOV removed8'"
WI+OT
WI+OT
WI+OT
WI + OT
WI+OT
WI+OT
LNB
LNB
LNB
LNB
LNB
LNB
0.06
0.06
0.06
0.06
0.06
0.08
0.08
0.08
0.08
0.09
0.09
0.12
960-1,160
800-940
710-820
570-650
540-610
380-430
990-4,300
720-3,070
570-2,390
410-1,670
360-1,450
240-920
aCapacity factor: 0.50-0.66. Costs based on 10-percent interest rate and
10-year capital amortization.
b!992 dollars.
(continued)
6-18
-------
TABLE 6-7. (continued)
Boiler type
Packaged
watertube
(single-burner)
(continued)
Packaged
firetube
Field-erected
wall-fired
(multiple-
burner)
Boiler
capacity,
MMBtu/hr
10
25
50
100
150
250
10
25
50
100
150
250
2.9
5.2
10.5
20.9
33.5
2.9
5.2
10.5
20.9
33.5
•100
250
400
500
750
100
250
400
500
750
250
400
500
750
NOX control
technology
LNB+FGR
LNB+FGR
LNB+FGR
LNB+FGR
LNB+FGR
LNB+FGR
SCR
SCR
SCR
SCR
SCR
SCR
WI+OT
WI+OT
WI+OT
WI+OT
WI+OT
FGR+OT
FGR+OT
FGR+OT
FGR+OT
FGR+OT
BOOS + OT
BOOS + OT
BOOS + OT
BOOS + OT
BOOS+OT
BOOS + WI+OT
BOOS + WI+OT
BOOS + WI+OT
BOOS+WI+OT
BOOS+WI+OT
LNB
LNB
LNB
LNB
Controlled
NOX level,
Ib/MMBtu
0.06
0.06
0.06
0.07
0.07
0.10
0.02
0.02
0.02
0.03
0.03
0.04
0.04
0.04
0.04
0.04
0.04
0.07
0.07
0.07
0.07
0.07
0.09
0.12
0.15
0.15
0.20
0.05
0.06
0.08
0.08
0.10
0.12
0.15
0.15
0.20
Cost effectiveness,
$/ton NOV removed8'1*
2,630-7,630
1,930-5,510
1,540-4,350
1,110-3,090
990-2,730
650-1,760
7,400-10,090
5,730-8,010
4,830-6,880
3,040-5,350
2,690-4,990
1,810-3,460
4,190-5,240
3,600-4,450
3,050-3,720
2,640-3,180
2,410-2,890
26,570-35,410
15,160-20,380
7,970-10,830
4,520-6,100
3,000-4,080
440-510
280-330
210-240
210-240
150-170
750-820
530-570
410-440
400-430
300-310
3,030-6,210
2,070-4,210
1,920-3,900
1,690-3,400
aCapacity factor: 0.50-0.66. Costs based on 10-percent interest rate and
10-year capital amortization.
b!992 dollars.
6-19
-------
6.42.1 Natural-gas-fired Packaged Watertube Boilers
NOX control cost data for natural-gas-fired packaged (single-burner) watertube boilers
are more available than for other boiler and fuel types, primarily due to retrofit activity in
California. Cost data from four boilers were used to estimate costs of WI and LNB retrofit,
while data from six units were used to estimate combined LNB and FGR retrofit costs. SCR
retrofit cost estimates were based on data supplied by a major manufacturer of SCR systems,
with experience installing SCR systems on packaged boilers rated as small as 66,000 Ib steam/hr
(8.3 kg/s).
As tabulated in Table 6-7 and shown in Figure 6-5, cost effectiveness estimates for
packaged watertube units fired by natural gas were highest for SCR NOX control and lowest for
LNB and Wl-f OT, with LNB+FGR falling in between. WI+OT is considered cost-competitive
with LNB because of its low initial capital investment. In spite of the thermal efficiency loss of
0.5 to 1.0 percent associated with WI, this technique can be cost effective especially for small
boilers with a low capacity factor.
As was the case with coal-fired units, costs per ton of NOX reduction decreased with
increased boiler capacity, due to the increased amount of NOX removed from the larger units
and general economies of scale. For packaged watertube units, the effect of boiler capacity on
cost effectiveness becomes significant below about 50 MMBtu/hr (15 MWt) capacity. For units
smaller than this capacity, costs of NOX control increase rapidly as capacity decreases, especially
when SCR is used. The costs per ton of NOX control for a 250 MMBtu/hr (73 MWt)
single-burner packaged boiler with LNB are much lower than those estimated for a
multiple-burner field-erected unit of similar size. Some of the discrepancy between the figures
can be attributed to the different data sources; however, the principal reason lies in the number
of burners to be retrofitted. A. field-erected unit with four or more burners, for example, will
tend to require capital equipment and installation costs several times higher than a single-burner
unit.
On average, LNB+FGR control costs per ton of NOX removed were twice as high as
for LNB and WI+OT, while SCR control costs per ton of NOX removed were 3 times higher.
Cost effectiveness of WI+OT ranged from $380 to $1,160 per ton of NOX removed. Cost
effectiveness for LNB controls ranged from $240 to $4,300 per ton of NOX removed, across the
capacity range of 10 to 250 MMBtu/hr (2.9 to 73 MWt). LNB+FGR cost effectiveness ranged
from about $650 to $7,630/ton, while SCR had the highest range in cost per ton of NOX
6-20
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removed, approximately $1,810 to $10,090/ton. The high-end costs of these ranges were for the
smallest, 10 MMBtu/hr (2.9 MWt) units at a 0.50 capacity factor. Because it is likely that many
units this small are operated at even lower capacity factors, actual costs of NOX control may be
much higher than these estimates. For these lower capacity factor boilers, controls with a high
initial capital investment, such as SCR, LNB, and LNB + FGR, are particularly penalized when
compared on a cost-effectiveness basis.
Figure 6-5 illustrates the overall trend of cost effectiveness with boiler capacity. The
enclosed areas reflect the ranges in cost and are representative of the uncertainty in these
estimates. Cost-effectiveness ranges for LNB and for LNB+FGR overlap, due to the wide range
of cost effectiveness values obtained. These cost-effectiveness data illustrate the potential
variability in the costs of retrofitting boilers with NOX controls, which are highly dependent on
site-specific installation and operating factors. Figure 6-6 illustrates the variability of the cost
effectiveness of SCR controls, assuming various catalyst lifetimes. As catalyst life increases, cost
effectiveness slowly decreases.
6.422 Natural-gas-fired Firetube Boilers
Cost data were obtained for retrofitting WI+OT and FGR+OT controls to packaged
firetube units ranging in size from approximately 3 to 34 MMBtu/hr (0.9 to 10 MWt) capacity.
The data for FGR+OT controls were obtained from a distributor of industrial boilers and NOX
control systems, and are based on experiences with nearly 20 units operating with FGR.20 Costs
for WI+OT are based on recently reported NOX retrofit experiences in Southern California.19
FGR+OT is one of the most common retrofit NOX control strategies for natural-
gas-fired firetube units, besides LNB or combined LNB and FGR. Costs per ton of NOX
removed for these units firing natural gas were relatively high, ranging from $3,000 to $35,410,
with the highest costs being for units 5 MMBtu/hr (1.5 MWt) and smaller. The most significant
cost components for these cost cases were equipment and installation costs. The costs of NOX
control for a 10 MMBtu/hr (2.9 MWt) firetube unit retrofitted with FGR+OT are relatively
similar to the high-end costs estimated for a 10 MMBtu/hr (2.9 MWt) watertube unit retrofitted
with LNB and FGR, as discussed above. Although no cost estimates were made for firetube
units retrofitted with LNB or LNB+FGR controls, it is likely that cost effectiveness for these
control cases will be comparable to those estimated for packaged watertube units of similar
capacity.
6-22
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The estimated costs for WI + OT for these firetube boilers are based on a retrofit
investment of $35,000, irrespective of boiler size, and an efficiency penalty of 1.0 percent. It is
difficult to predict the actual thermal efficiency impact in a retrofit situation. The actual impact
will depend on current unit operating practices; given a poor operating condition with high excess
air combustion, the retrofit of this control may, in some cases, result in an improvement.
However, it was considered prudent to associate an efficiency loss with the use of WI in spite
of potential gains with an OT control. As shown in Table 6-7, the estimated cost for this control
strategy is similar to that for LNB retrofit, but still slightly higher than comparable controls for
watertube units. This is due to lower baseline NOX levels for firetube boilers compared with
watertube units (see Table 6-2).
6.4.2.3 Natural-gas-fired Field-erected Wall-fired Boilers
The implementation of BOOS or biased firing and WI on large multi-burner gas-fired
boilers will depend on the number of burners available and the load requirements of the boiler.
Units with several burners with small heat input ratings per burner offer the greater opportunity
for implementation of these effective control techniques. Where possible, the retrofit of BOOS
and BOOS-I-WI+OT is likely to be the more cost effective options in spite of thermal
efficiencies, here assumed to range between 0.25 and 1.0 percent. The lower the capacity factor
of these boilers, the more cost-competitive these controls may prove to be. Estimates in this
study range between about $150 and $510 per ton for BOOS + OT, and between $300 and $820
per ton for BOOS + WI+OT.
Cost estimates per ton of NOX removed for natural-gas-fired field-erected units with
LNB, listed in Table 6-7, range from $1,690 to $6,210 per ton of NOX removed for boilers
ranging in size from 250 to 750 MMBtu/hr (73 to 220 MWt). The costs per ton of NOX control
for a multiple-burner field-erected 250 MMBtu/hr (73 MWt) unit are much higher than the costs
estimated for a single-burner packaged unit due to greater capital equipment and installation
costs as discussed in Section 6.4.2.1. Although the listed cost effectiveness ranges are for a
capacity factor as low as 0.50, most field-erected units have factors closer to 0.66.7 The high end
of the cost effectiveness ranges listed in Table 6-7 represent a 0.50 capacity factor. If considering
a 0.66 capacity factor only, the high-end cost effectiveness estimates are roughly 25 percent
lower. The estimates presented are based on capital cost data supplied for two boilers retrofitted
with LNB.14
6-24
-------
6.4J NOX Control Cost Effectiveness: Fuel-oU-fired ICI BoUers
As discussed earlier, NOX control cost effectiveness estimates for fuel-oil-firing units
were made based on cost data for natural-gas-fired boilers,'using appropriate baseline NOX
emission levels and fuel oil prices. Tables 6-8 and 6-9 summarize these estimates, and
Figures 6-7 and 6-8 graphically show the results for packaged watertube boilers. NOX controls
that use water injection were not considered for oil-fired units because of lack of experience and
greater operational and environmental impacts that are likely with these fuels compared with
natural gas. Comparative cost results for the different NOX control technologies are similar to
those obtained for natural-gas-fired units, as expected, with SCR showing the highest costs per
ton of NOX removed and LNB showing the lowest. Like the cost estimates for natural gas firing,
LNB+FGR control costs were, on average, twice as high as the costs of LNB controls, while
SCR controls were 3 times as high.
Overall costs of NOX control per ton removed are lower for fuel oil firing than for
natural gas firing due to higher baseline NOX emission levels, and, hence, greater amounts of
NOX removal per MMBtu heat input. As discussed for natural gas-fired boilers, the cost
effectiveness discrepancy between a 250 MMBtu/hr (73 MWt) packaged boiler and a
250 MMBtu/hr (73 MWt) field-erected unit equipped with LNB is primarily due to the greater
capital equipment and installation costs associated with retrofitting multiple burners rather than
a single burner. Multiple-burner field-erected boilers are likely to benefit from selected BOOS.
Where applicable, this technique can result in considerable NOX reduction at much lower cost
than LNB retrofit.
6.4.4 NOX Control Cost Effectiveness: Nonfossil-fuel-fired ICI Boilers
Limited cost data were available for nonfossil-fuel-fired boilers retrofitted with NOX
controls. For this reason, cost estimates could only be made for the application of SNCR
controls to several types of nonfossil-fuel-fired boilers. Data were obtained directly from leading
SNCR system manufacturers, and reflect cost experiences for nine different installations. NOX
control performance and cost are considered the same regardless of the reagent used. Typical
applications use either ammonia or urea in aqueous solution. Table 6-10 summarizes the cost
effectiveness ranges for these boilers. Cost effectiveness estimates made for wood-fired stokers
with urea injection are comparable to those calculated for wood-fired FBC boilers with ammonia
injection, ranging between $890 and $2,130 per ton of NOX removed for boilers 250 to
500 MMBtu/hr (73 to 146 MWt). The range in cost effectiveness for MSW-fired stokers of the
6-25
-------
TABLE 6-8. SUMMARY OF NOX CONTROL COST EFFECTIVENESS, DISTILLATE-
OIL-FIRED ICI BOILERS
Boiler type
Packaged watertube
(single burner)
Packaged firetube
Field-erected
wall-fired
(multiple burner)
BoUer
capacity,
MMBtu/hr
10
25
50
100
150
250
10
25
50
100
150
250
10
25
50
100
150
250
2.9
5.2
10.5
20.9
33.5
250
400
500
750
NOX control
technology
LNB
LNB
LNB
LNB
LNB
LNB
LNB + FOR
LNB+FGR
LNB + FOR
LNB+FGR
LNB+FGR
LNB + FOR
SCR
SCR
SCR
SCR
SCR
SCR
FGR+OT
FGR+OT
FGR+OT
FGR+OT
FGR+OT
LNB
LNB
LNB
LNB
Controlled
NOX level,
Ib/MMBtu
0.10
0.10
0.10
0.10
0.10
0.10
0.08
0.08
0.08
0.08
0.08
0.08
0.03
0.03
0.03
0.03
0.03
0.03
0.12
0.12
0.12
0.12
0.12
0.10
0.10
0.10
0.10
Cost effectiveness,
$/ton NO
removed8'"
790-3,440
580-2,450
460-1,910
370-1,500
330-1,310
280-1,110
1,900-5,900
1,340-4,210
1,030-3,280
800-2,580
690-2,250
580-1,910
5,920-8,070
4,590-6,410
3,860-5,500
2,740-4,820
2,420-4,490
2,170-4,150
15,640-20,940
8,800-11,930
4,490-6,200
2,410-3,360
1,500-2,150
3,630-7,450
3,100-6,320
2,880-5,850
2,530-5,100
aCapacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year
capital amortization.
b!992 dollars.
6-26
-------
TABLE 6-9. SUMMARY OF NOX CONTROL COST EFFECTIVENESS, RESIDUAL-
OIL-FIRED ICI BOILERS
Boiler type
Packaged watertube
(single burner)
Packaged firetube
Field-erected
wall-fired
(multiple burner)
Boiler
capacity,
MMBtu/hr
10
25
50
100
150
250
10
25
50
100
150
250
10
25
50
100
150
250
2.9
5.2
10.5
20.9
33.5
250
400
500
750
NOX control
technology
LNB
LNB
LNB
LNB
LNB
LNB
LNB + FOR
LNB+FGR
LNB + FOR
LNB + FOR
LNB+FGR
LNB + FOR
SCR
SCR
SCR
SCR
SCR
SCR
FGR+OT
FGR+OT
FGR+OT
FGR+OT
FGR+OT
LNB
LNB
LNB
LNB
Controlled
NOX level,
Ib/MMBtu
0.19
0.19
0.19
0.19
0.19
0.19
0.23
0.23
0.23
0.23
0.23
0.23
0.06
0.06
0.06
0.06
0.06
0.06
0.23
0.23
0.23
0.23
0.23
0.19
0.19
0.19
0.19
Cost effectiveness,
$/ton NO
removed*'
420-1,810
300-1,290
240-1,010
190-790
170-690
150-580
1,220-3,320
920-2,430
760-1,950
640-1,580
580-1,400
520-1,220
3,110-4,240
2,420-3,370
2,030-2,900
L440-2.530
1,270-2,360
1,140-2,190
8,560-11,350
4,960-6,600
2,690-3,590
1,600-2,100
1,120-1,460
1,910-3,920
1,630-3,330
1,520-3,080
1,330-2,680
aCapacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year
capital amortization.
b!992 dollars.
6-27
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6-29
-------
TABLE 6-10. SUMMARY OF NOX CONTROL COST EFFECTIVENESS, NONFOSSIL-
FUEL-FIRED ICI BOILERS
Boiler
type Fuel type
Stoker Wood
MSW
Packaged Paper
wafertube
•
BFBC Wood
Boiler
capacity,
MMBtu/hr
50
150
250
350
500
50
150
250
350
500
10
25
50
100
150
250
250
350
400
500
750
NOX control
technology
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
. SNCR-urea
SNCR-urea
SNCR-urea
SNCR-urea
SNCR-ammonia
SNCR-ammonia
SNCR-ammonia
SNCR-ammonia
SNCR-ammonia
Controlled
NOX level,
Ib/MMBtu
0.11
0.11
0.11
0.11
0.11
0.18
0.18
0.18
0.18
0.18
0.23
0.23
0.23
0.23
0.23
0.23
0.11
0.11
0.11
0.11
0.11
Cost effectiveness,
$/ton NO
removed3'
1,810-3,130
1,270-2,380
1,080-2,130
980-2,000
890-1,870
3,390-3,800
1,890-2,790
1,690-2,450
1,580-2,270
1,470-2,090
2,220-3,520
1,780-2,710
1,550-2,270
1,370-1,930
1,280-1,770
1,190-1,610
1,560-1,750
1,480-1,650
1,450-1,600
1,390-1,530
1,110-1,310
*Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year capital
amortization.
b!992 dollars.
same capacity retrofit with urea injection is $1,470 and $2,450 per ton of NOX removed. For
wood- or MSW-fired boilers smaller than 250 MMBtu/hr (73 MWt) but at least 50 MMBtu/hr
(15 MWt), SNCR control costs ranged from approximately $1,270 to $3,800 per ton of NOX
removed. Cost estimates for similarly sized paper-fired units were lower, ranging from $1,280
to roughly $2,270 per ton of NOX removed.
6.4.5 NOX Control Cost Effectiveness: Oil-fired Thermally Enhanced Oil Recovery (TEOR)
Steam Generators
No cost analyses were performed for NOX controls for TEOR steam generators.
However, it has been estimated that for a 25 MMBtu/hr (7.3 MWt) crude-oil-fired TEOR unit,
annual costs would be $52,000 for LNB retrofit, $88,000 for SNCR, and $400,000 for SCR.26
6-30
-------
Based on these estimates, and assuming a baseline NOX emission level of 0.38 Ib/MMBtu (see
Chapter 4) and the NOX reduction efficiencies listed in Table 6-3, cost effectiveness is $3,790 per
ton of NOX removed for LNB at 0.66 capacity factor, $8,000/ton for SNCR, and $19,400/ton for
SCR.
6.4.6 Cost Effect of Continuous Emissions Monitoring (CEM) System
Addition of a CEM system to an NOX control retrofit package can increase the costs of
NOX control. For example, Table 6-11 shows the cost effect of adding a CEM system to a
natural-gas-fired packaged watertube boiler, equipped with LNB or with LNB and FGR. The
cost estimates are based on data from one source, for a 265 MMBtu/hr (77.7 MWt) unit, that
showed a total CEM system capital cost of roughly $200,000, including installation.14 Average
cost increased by roughly 65 percent when a CEM system was included. While it is not possible
to draw conclusions from one source about the extent to which CEM systems will increase costs,
the data nevertheless show that CEM cost impact is considerable. For small-capacity boilers, in
particular, the additional cost of CEM may be disproportionately large when compared to the
overall cost of the boiler itself. At least one California air district requires CEM systems only
for boilers that are 40 MMBtu/hr (12 MWt) or greater in capacity.27
TABLE 6-11.
Boiler type
Packaged
watertube
NOX CONTROL COST EFFECTIVENESS WITHOUT/WITH CEM SYSTEM,
NATURAL-GAS-FIRED ICI BOILERS*
Boiler
capacity,
MMBtu/hr
10
25
50
100
150
250
10
25
50
100
150
250
NO, control
technology
LNB
LNB
LNB
LNB
LNB
LNB
LNB + FGR
LNB + FGR
LNB + FGR
LNB + FGR
LNB + FGR
LNB + FGR
Controlled
NO, level,
Ib/MMBtu
008
0.08
0.08
0.09
0.09
0.12
0.06
0.06
0.06
0.07
0.07
0.10
Cost effectiveness
without CEM,
$/ton NO,
removed'1'1
3,260-4,300
2^20-3,070
1,810-2,390
L260-1.670
1,100-1,450
700-920
3,700-5,000
2^30-3,460
1,900-2,620
L260-L760
1,050-1,500
630-910
Cost effectiveness
with CEM,
$/ton NO,
removedk>c
5,410-7,140
3,850-5,080
3,000-3,960
2,090-2,760
1,830-2,410
1.160-L530
5,480-7,360
3,800-5,140
2,890-3,930
1,950-2,680
1,660-2,290
1,020-1,420
'Based on data contained in Reference 19, for a 265 MMBtu/hr (7.7 MWt) natural-gas-fired unit.
bCapacity factor. 0.50-0.66. Costs based on 10-percent interest rate and 10-year capital amortization.
1992 dollars.
6-31
-------
6.5 REFERENCES FOR CHAPTER 6
1. OAQPS Control Cost Manual — Fourth Edition. Publication No. EPA-450/3-90-006.
U.S. Environmental Protection Agency. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. January 1990.
2. Economic Indicators — CE Plant Cost Index. Chemical Engineering. March 19, 1984.
3. Economic Indicators — CE Plant Cost Index. Chemical Engineering. January 16,1989.
4. Economic Indicators — CE Plant Cost Index. Chemical Engineering. December 1993.
5. Peters, M. and K. Timmerhaus. Plant Design and Economics for Chemical Engineers.
McGraw-Hill Book Company. New York, NY. 1980.
6. Technical Support Document for a Suggested Control Measure for the Control of
Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial Boilers,
Steam Generators, and Process Heaters. (California ARE, 1987) Statewide Technical
Review Group. California Air Resources Board. Sacramento, CA. April 1987.
7. Devitt, T., et al (PEDCo Environmental, Inc.). Population and Characteristics of
Industrial/Commercial Boilers in the U.S. Publication No. EPA-600/7-79-178a.
Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC.
August 1979.
8. Bowen, M. and M. Jennings. (Radian Corp.). Costs of Sulfur Dioxide, Paniculate
Matter, and Nitrogen Oxide Controls on Fossil Fuel Fired Industrial Boilers.
Publication No. EPA-450/3-82-021. Prepared for the U.S. Environmental Protection
Agency. Research Triangle Park, NC. August 1982.
9. Damon, J., et al. (United Engineers and Constructors). Updated Technical and
Economic Review of Selective Catalytic NOX Reduction Systems. Proceedings: 1987
Symposium on Stationary Combustion NOX Control. Publication No. EPRI CS-5361.
U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto,
CA. August 1987.
10. Letter and attachments from Dean, H., Hugh Dean & Co., Inc., to Votlucka, P., South
Coast Air Quality Management District. Cost Analyses of FGR Retrofit to Natural-
gas-fired Firetube Boilers. January 15, 1988.
11. Current Prices Estimated. Energy User News. April 1991.
12. Makansi, J. Ammonia: It's Coming to a Plant Near You. Power. May 1992.
13. Grant, E., et al. Principles of Engineering Economy. John Wiley & Sons. New York,
NY. 1982.
14. Letter and Attachments from Marx, W., CIBO, to Seu, S., Acurex Environmental
Corporation. NOX Control Technology Costs. June 12, 1992.
6-32
-------
15. Alternative Control Techniques Document—NOX Emissions from Utility Boilers.
Publication No. EPA-453/R-94-023. U.S. Environmental Protection Agency. Office of
Air Quality Planning and Standards. Research Triangle Park, NC. March 1994.
16. Letter and attachments from Shaneberger, D., Exxon Research and Engineering
Company, to Castaldini, C., Acurex Environmental Corporation. Thermal DeNOx
Costs. December 3, 1993.
17. Letter and attachments from Pickens, R., Nalco Fuel Tech, to Castaldini, C., Acurex
Environmental Corporation. NOX Control Technology Costs. March 15, 1994.
18. Letter and Attachments from Pickens, R., Nalco Fuel Tech, to Castaldini, C., Acurex
Environmental Corporation. SNCR-urea (NOxOUT) Control Costs. June 9, 1992.
19. Colannino, J. Low-Cost Techniques-Reduce Boiler NOX. Chemical Engineering.
February 1993. p. 100.
20. Letter and Attachments from Dean, H., Hugh Dean & Co., Inc., to Votlucka, P., South
Coast Air Quality Management District. Cost Effectiveness of FOR NOX Control for
Firetube Boilers. January 12, 1988.
21. University of California at Riverside Central Utility Plant Boiler System Study. Impell
Corporation. Walnut Creek, CA. June 1989.
22. Letter and Attachments from Burlage, P., Peerless Mfg. Co., to Brizzolara, L., A.H.
Merrill & Associates. SCR Equipment and Installation Costs. June 22, 1992.
23. Hurst, B., et al. (Exxon Research and Engineering Co.). Exxon Thermal DeNOx
Effectiveness Demonstrated in a Wood-Fired Boiler. Presented at the 13th National
Waste Processing Conference and Exhibit. May 1988.
24. Letter and attachments from G. A. Haas, Exxon Research and Engineering Company,
to B. Jordan, U.S. EPA, OAQPS, Durham, NC. NOX Control Technologies
Questionnaire. February 18, 1993.
25. Bodylski, J. A. and G. A. Haas. The Selective Non-Catalytic Reduction (SNCR)
Process: Experience with Exxon Thermal DeNOx Process at Two Circulating Fluidized
Bed Boiler Commercial Applications. Presented at the American Flame Research
Committee 1992 Fall International Symposium on Emission Reduction and Energy
Conservation: Progress in Combustion Technology. Cambridge, MA. October 1992.
26. Collins, J. (Radian Corp.). Technology Study of NOX Controls for "Small" Oil-Fired
Steam Generators. Prepared for the Western Oil and Gas Association. Bakersfield,
CA. January 6, 1987.
27. Rule 1146 — Emissions of Oxides of Nitrogen from Industrial, Institutional, and
Commercial Boilers, Steam Generators, and Process Heaters. South Coast Air Quality
Management District. El Monte, CA. January 1989.
6-33
-------
7. ENVIRONMENTAL AND ENERGY IMPACTS
This chapter presents environmental and energy impacts for the NOX emissions control
techniques described in Chapter 5. These control techniques are specific to certain boiler and
fuel equipment, as shown in Table 7-1. For example, LNB is not applicable to stoker and FBC
boilers. WI and FGR are rarely considered when burning coal in any type of industrial
combustion equipment. Similarly, among ICI boilers reburning with natural gas has only limited
application potential to boilers burning municipal solid waste or stoker coal. Flue gas treatment
controls have limited application experience, especially for SCR, on small boilers and boilers
burning fuels other than natural gas. SNCR, instead, is generally limited to application on larger
boilers with the greatest performance success recorded on FBC boilers.
This chapter is organized in four major sections. Section 7.1 presents the air pollution
impacts, Section 7.2 the solid waste disposal impacts, Section 7.3 the water pollution impacts, and
Section 7.4 the energy impacts.
7.1 AIR POLLUTION
7.1.1 NOX Reductions
Control techniques presented in this document can result in significant NOX reductions
for selected ICI boilers. The actual NOX reduction that can be achieved at each site will depend
on many factors including the extent of the equipment upgrade, the degree of control applied,
and the boilers current configuration such as furnace size, number of burners and burner matrix.
For example, the amount of flue gas recirculated has a strong influence on the percent NOX
reduction. Also, the amount that can be safely recirculated will depend on the optimization of
the burner design in order to maintain safe flame conditions, and low emissions of other
pollutants such as CO. In another example, the amount of SCR catalyst that can be retrofit may
depend on site accessibility. Many ICI boilers are often located inside buildings making access
for large retrofit difficult at best.
Table 7-2 lists the anticipated NOX reductions that can be achieved on a yearly basis
with the retrofit of candidate control techniques. These estimates are based on "model size"
7-1
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[GR = Natural gas reburning
NCR = Selective noncatalytic
CR = Selective catalytic redui
[SW = Municipal solid waste
CQ!>c/)i-]lLiZ.GOc/2l<
•o
CO
c
s
VI
I
.
1
5°
11
0 TJ
8|
**-°
7-2
-------
TABLE 7-2. NOY EMISSIONS REDUCTION FROM MODEL BOILERS
Boiler type and
MMBtn/hr
PC
Stoker coal
FBCcoal
FE-WT gas
FE-WT No. 2 oil
FE-WT No. 6 oil
PK-WTgas
PK-WT No. 2 oil
PK-WT No. 6 oil
FT gas
FT No. 2 oil
FT No. 6 oil
Stoker nonfossil
FBC nonfossil
MassMSW
size,
400
250
400
300
300
300
50
50
50
15
15
15
150
200
500
Baseline NOT
Tons/yr
Ib/MMBru (0.50 Ct*)
0.70 610
0.53 290
032 280
0.26 150
0.21 140
0.38 250
0.14 15
0.13 14
036 39
0.10 33
0.17 5.6
031 10
0.24 79
0.25 110
0.40 440
NOX control
technique
BT/OT
LNB
NOR
SNCR
SCR
SCA
SNCR
SCA
SNCR
BT/OT
SCA
LNB
LNB+FGR
SNCR
SCR
BT/OT
SCA
LNB
LNB+FGR
SNCR
SCR
BT/OT
SCA
LNB
FOR
LNB+FGR
SCR
BT/OT
WI/SI
LNB
LNB+FGR
SNCR
SCR
BT/OT
LNB
FOR
BT/OT
LNB
LNB+FGR
SCR
BT/OT
WI/SI
LNB
FGR
LNB+FGR
BT/OT
LNB
FGR
BT/OT
LNB
SNCR
SNCR
NCR
SNCR
Control
N0r level,
Ib/MMBtu
0.62
035
0.28
039
0.14
0.42
0.29
0.19
0.13
0.20
0.15
0.12
0.10
0.10
0.04
0.18
0.13
0.10
0.08
0.10
0.03
0.32
0.29
0.19
0.34
0.15
0.08
0.12
0.06
0.08
0.06
0.07
0.02
0.11
0.10
0.07
0.31
0.19
0.15
0.06
0.09
0.04
0.08
0.07
0.03
0.15
0.09
0.12
0.26
0.17
0.11
0.11
0.16
0.18
'%
15
50
60
45
85
20
45
40
75
15
35
55
60
60
85
15
40
50
60
50
80
15
25
50
10
60
80
15
55
45
57
50
85
15
25
45
15
45
60
85
15
65
20
30
70
15
50
30
15
45
55
55
60
55
NOT
Tons/yr
(033 CF)
46
200
240
180
320
40
86
75
110
13
35
60
69
69
95
13
35
48
56
48
78
26
39
82
17
100
130
1.4
5.8
4.3
5.8
5.1
8.7
1.4
2.2
4.3
3.6
12
15
22
0.22
1.3
0.43
0.65
1.5
0.43
1.7
1.1
1.1
3.0
28
40
170
160
reduction
Tons/yr
(0.50 CF)
70
310
370
270
490
60
130
110
170
20
53
92
110
110
140
20
53
72
85
72
120
34
59
J20
26
150
200
2.2
8.8
6.6
8.8
7.7
13
2.2
3.3
6.6
55
19
23
33
0.33
2.0
0.66
1.0
2.3
0.66
2.6
1.6
1.6
4.6
43
61
260
240
Tons/yr
(0.6« CF)
93
400
490
360
650
79
170
150
220
26
69
120
140
140
190
26
69
95
110
95
160
52
78
160
35
200
260
2.8
12
8.7
12
10
17
2.8
4.3
8.6
7.2
25
30
43
0.44
2.6
0.87
1.3
3
0.86
35
2.2
2.2
6.1
56
80
350
320
*CF = capacity factor.
7-3
-------
boilers, baseline emissions presented in Chapter 4, and NOX reduction potentials presented in
Chapter 5. Thus, a 400 MMBtu/hr (73 MWt) circulating FBC boiler burning coal with a
baseline level of 0.32 Ib/MMBtu could successfully employ SNCR to reduce emission levels to
approximately 0.10 Ib/MMBtu, corresponding to 210 tons/yr NOX reduction at a capacity factor
of 0.50.
1.12 CO Emissions
The CO emissions from ICI boilers are normally near zero, with the exception of a few
boilers that have poor combustion air control or burner problems.1 In an extensive study of
industrial boilers' emissions, oil-fired units were found to have the lowest baseline CO emissions
than either coal- or gas-fired units. This was attributed to higher excess air levels typically used
to avoid visible smoke emissions when oil is burned.1 CO emissions are generally caused by
poor fuel-air mixing, flame quenching, and low. residence time at elevated temperatures.
Additionally, in some ICI furnace designs, CO emissions can also occur because of furnace gas
leaks between furnace tubes.
The modification of combustion conditions aimed at reducing NOX formation can result
in increases in emissions of CO and hydrocarbons. This is because controls that reduce peak
flame temperature and delay the mixing of fuel and air for NOX reduction can cause some
incomplete combustion of the fuel. However, the actual impact of NOX control retrofits often
depends on the operating conditions of the ICI boiler and the extent of improvements made to
the combustion control system. In some cases, combustion NOX control can also result in lower
emissions of CO and other unburned fuel emissions.
Tables 7-3 through 7-5 list changes in emissions of CO measured following ths retrofit
of selected controls. These data can also be found in Appendix A of this document. As shown
in Table 7-3, LNB, SCA and NOR controls achieved NOX reductions in the range of 10 to
67 percent, with lowest reductions reported for the spreader stoker. Emissions of CO increased'
in nearly all cases, except for the retrofit of NGR on the cyclone boiler and one minor
application of OFA for 10 percent reduction in NOX in the spreader stoker. The implementation
of staged air will typically result in increased CO emissions.
Data on the effect of NOX controls on CO emissions from natural gas-fired ICI boilers
were limited to the retrofit of FOR, LNB and FOR+LNB controls. Bulk dilution of combustion
mixtures with FOR is limited by flame instability and reduced flammability. Slightly higher
7-4
-------
TABLE 7-3. CO EMISSION CHANGES WITH NOX CONTROL RETROFIT —
COAL-FIRED BOILERS
Boiler type
WT
Cyclone
Spreader stoker
FBC
NOX control
LNB
LNB+SCA
NGR
SCA (OFA)
SCA
NOX
reduction,
67
66
65
31
10
26
67
CO emissions impact
Baseline/low
NO,,
ppm
20-27/13-420
35/60-166
30/30
231-252/429
313/300
0/49
387-500/550-1,100
Average
change,
+ 800
+215
0
+ 80
-4
NAa
+ 86
Reference
2
3
4
5
6
1
7
aNA = Not applicable.
7-5
-------
TABLE 7-4. CO EMISSION CHANGES WITH
BOILERS
NOX CONTROL RETROFIT — GAS-FIRED
Boiler type NOX control
PKG-FT FOR
FOR
FOR
FOR
FOR
FOR
FOR
FOR
FOR
FOR
LNB
LNB
LNB
LNB
LNB
LNB
LNB
PKG-WT FOR
FOR
FOR
FOR
FOR
FOR
LNB + FOR
NO, -
reduction,
%
59
73
71
64
74
67
73 '
76
69
73
82
53
32
78
NAa
NA
NA
74
62
78
53
.73
56 .
55
CO emissions
Baseline/
lowNOp
ppm
16/13
205/77
205/192
205/103
205/84
23/3
105/7
205/67
205/49
51/12
9/9
51/24
39/8
. 856/30
342/30
205/0
9/9
205/62
20/20
10/55
205/205
14/22
132/77
60-125/2
imoact
Average
change,
%
-18
-62
-6.3
-50
-59
-87
-93
-67
-76
-76
0
-53
-80
-97
-91
-100
0
-70
0
+450
0
+ 57
-42
-98
Reference
8
9
9
9
9
8
8
9
9
10
11
12
13
11
11
11
12
9
14
14
9
10
10
15
*NA = Not applicable.
7-6
-------
TABLE 7-5. CO EMISSION CHANGES WITH NOX CONTROL RETROFIT — OIL-FIRED
BOILERS
Oil/boiler
type
Distillate/WT
Distillate/FT
Residual/WT
NOX control
FOR
FOR
LNB
FOR
FOR
SCA (BOOS)
SCA (BOOS)
NOX
reduction,
%
68
20
15
4
30
8
40
CO emissions impact
Baseline/low
NO,,,
ppm
4/46
20/24
6/13
20/20
10/145
0/100
0/20
Average
change,
%
+ 1,000
+20
+ 120
0
+ 1,400
NAa
NA
Reference
16
14
13
14
14
1
1
aNA = Not applicable.
excess air levels at high rates of FGR (typically 15 to 20 percent) coupled with improved burner
settings often can result in decreased CO emissions in addition to lower NOX.
The data in Table 7-4 suggest that baseline CO emission levels from these units ranged
from 9 to 856 ppm, and that the application of these controls, along with an increase in excess
air, resulted in a reduction of CO in most cases. The average CO reduction for these retrofits
was nearly 70 percent. One of the boilers with an initial low CO level, 10 ppi.i, showed an
increase in CO to 55 ppm when FGR was implemented. In another application, the CO level
in the low-NOx configuration increased to only 22 ppm. Excess air is an important operational
parameter that determines the level of CO emissions following the retrofit of NOX controls. As
suggested above, most of the reductions in CO levels from these gas-fired boilers resulted from
increases in excess air. Low-NOx firing with LNB typically causes an increase in CO at
equivalent excess air levels. Also, there is the possibility of CO emissions occurring due to gas
leaks between tubes from furnace to convective section.
Figure 7-1 illustrates the dependence of CO emissions on excess air. The rapid increase
in CO is indicative of reduced fuel and air mixing that often accompanies low-NOx combustion
controls such as LNB and SCA. Each boiler type has its own characteristic "knee" in CO versus
7-7
-------
180
160
140
' 120
100
0 123?.) ng/J CO
Modertte control level _
Intermediate control level —«
Stringent control level _»
© NO
0 CO
160
140
120 1
«J
k
100 I
1
80 g*
60
468
Excess oxygen (X)
Figure 7-1. Changes in CO and NOX emissions with reduced excess oxygen
for a residual-oil-fired watertube industrial boiler.17
excess oxygen, depending on several factors such as fuel type and burner maintenance.
California's SCAQMD permits CO levels up to 400 ppm from ICI boilers when NOX emissions
are reduced to c'rict levels.18 Also, the ABMA recommends an equivalent permitted level for
CO for ICI boilers retrofitted with combustion controls.19
As shown in Table 7-5, the limited data base on fuel oil-fired ICI boilers indicates that
baseline CO emission levels for these selected boilers were below 20 ppm. When NOX controls
such as LNB, FOR, and BOOS were applied, the CO emission levels increased in nearly all
cases. The increase in CO, however, did not result in emission levels greater than 200 ppm,
considered a safe limit for boiler operation.
7.1.3 Other Ah- Pollution Emissions
Other air pollution emissions that are a concern when NOX controls are applied to ICI
boilers are: ammonia (NH3) and nitrous oxide (N2O), unburned hydrocarbon (HC), particulate
matter (PM), and air toxic emissions. Ammonia and N2O emissions are associated with the use
7-8
-------
of the SNCR process, primarily, and with SCR to a lesser extent. With either urea or ammonia
hydroxide, unreacted ammonia emissions escape the SNCR temperature window resulting in
direct emissions to the atmosphere. When sulfur-bearing fuels are burned, these emissions also
pose an operational concern because of cold end corrosion and reduced heat transfer due to
ammonium sulfate deposits. N2O emissions are often a byproduct of the SNCR reaction, and,
because of this, some N2O emissions are likely with the process. In fact, the emissions have
been reported with all reagents, particularly with urea reagents.20 Some urea-based SNCR
processes offer proprietary additives to minimize N2O and NH3 emissions.
SNCR vendors have paid particular attention to minimizing the breakthrough of
unreacted ammonia considering the potentially negative impacts on the operation of the boiler.
This is typically accomplished by careful selection of the injection location, method of injection
to maximize mixing and residence time, and by careful control of reagent use with boiler load
and operating conditions. Table 7-6 lists NH3 slip levels reported for several retrofit
installations. Boilers best suited for retrofit of SNCR are FBC, bubbling and circulating designs.
Stokers and mass burning equipment have also been targets for application of SNCR because
combustion modifications have traditionally been limited and ineffective. In spite of large NOX
reductions achieved in the units with the retrofit of SNCR, typically in the range of 50 to 70
percent, NH3 slip levels have been reported mostly in the range of less than 30 ppm, and often
less than 20 ppm. Monitoring of NH3 emissions is often difficult because direct on line
measurement methods are only now being introduced into the market place and are often very
expensive, therefore not a part of the monitoring system at these facilities.
Pilot-scale and field tests have cleruiy shown that a portion of the NOX reduced by the
SNCR process is merely transformed into N2O emissions. Figure 7-2 illustrates the amount of
N2O produced in relation to the amount of NOX reduction with three types of SNCR chemicals:
cyanuric acid, urea, and ammonia. These test results obtained in a pilot-scale facility, show that
nearly 30 percent of the NOX reduced can actually be transformed to N2O with urea, less when
using ammonia. Cyanuric acid is not a preferred chemical because of its obvious disadvantage
in N2O formation compared with the other two more popular SNCR chemicals. In addition,
cyanuric acid is 6 to 8 times more expensive than urea.
Increases in HC, PM and air toxic emissions are primarily of concern with the
application of combustion modification controls. Information on HC and air toxic emissions is
sparse at best. However, the limited data suggest that HC emissions do not change when NOX
7-9
-------
TABLE 7-6. AMMONIA EMISSIONS WITH UREA-BASED
SNCR RETROFIT11
Fuel/boiler type
Coal/CFBC
Wood/stoker
MSW/mass
Paper/PKG-WT
Fiber/PKG-WT
NOX reduction,
%
57
70
30
50
60
25
47
35
50
52
69
48
60
75
70
41
60
60
60
50
58
50
50
Ammonia emission level,
ppm
<18
<10
<5
<40
<27
<21
<10
<21
<40
<30
<25
<10
<10
22
17
<5
<7
12
<15
<21
22
<10
<10
Reference
21
21
21
21
21
21
21
21
21
21
21
"21
21
22
21
21
21
22
21
21
22
21
21
*Test data are included in Appendix A.
7-10
-------
0.50
0.40 •
•=• 0.30 •
0.20 •
0.10 -
0.00
H Ammonia (g)
0 Urea(s)
D Cyanuric Acid (s)
877 927 977
Temperature (C)
1097
Figure 7-2. Pilot-scale test results, conversion of NOX to N,O
(NOj = 300 ppm, N/NO = 2.0)20
control^ are implemented. HC emissions are the result of poor combustion conditions such as
inefficient fuel-air mixing, low temperatures, and short residence time. These emissions are most
often preceded by large increases in CO, soot, and unburned carbon content. Thus, by limiting
CO, smoke and unburned carbon in the flyash, HC emissions are also suppressed, and changes
with retrofit of NOX controls become imperceptible.
A comprehensive test program in the mid-1970s reported on the effect of combustion
modification controls for industrial boilers. The results of this program revealed the following
trends with respect to filterable PM23:
• LEA reduced PM emissions on the order of 30 percent
• SCA, including BOOS, increased PM by 20 to 95 percent
7-11
-------
• Burner adjustments and tuning had no effect on PM. However, the lower CO
emission levels generally achieved with these adjustments would tend to lower PM
as well.
• FGR resulted in an increase in PM from oil-fired packaged boilers by 15 percent
over baseline levels
Information on the effects of LNB on PM is unavailable. However, newer burner designs have
improved combustion air control and distribution. These features tend to compensate for the
potential increase in PM from oil- and coal-burning equipment due to delayed mixing and lower
peak temperatures that are needed to suppress NOX formation.
12 SOLID WASTE DISPOSAL
NOX reduction techniques that have a potential impact on the disposal of solid waste
are combustion controls for PC-fired boilers and flue gas treatment systems for all applicable
boilers. Combustion controls for PC-fired boilers are principally LNB and LNB + OFA. These
controls can result in an increase in the carbon content of flyash that can preclude its use in
cement manufacturing. Although primarily a practice of coal-fired power plants, the use of flyash
for cement manufacturing reduces the ash disposal requirements. The impact of increased
carbon content in the flyash from ICI boilers can result in an ash disposal requirement where
one did not exist before. The environmental and economic impact of this requirement cannot
be easily quantified.
An increase in flyash disposal can also occur with the use of flue gas treatment NOX
controls such as SNCR and SCR on coal-fired boilers. Both of these control options use
ammonia-based reagents to reduce NO to N2 and water. Excessive use of reagent can result in
ammonia slip emissions, as discussed in Section 7.1.3. This excessive ammonia condenses on the
flyash and, when present in quantities exceeding the odor threshold, would preclude its use as
a cement additive. The likelihood or extent of this potential problem is not known because there
is little experience in this country with the use of either SNCR or SCR for coal-fired boilers,
especially PC-fired industrial boilers.
Finally, one potential solid waste impact is the result of catalyst replacement when the
SCR process is used. With continuous use, the catalyst material will become less active. That
is, the efficiency of the catalyst in reducing NOX will gradually deteriorate. When this happens,
the catalyst material must be replaced. This is often accomplished by replacing layers of
individual modules starting with the most exposed layer (at the inlet), until all the catalyst
7-12
-------
material is finally replaced. Performance guarantees for SCR catalysts are often set at 3 years,
or 24,000 hours, for natural-gas-fired applications, and 2 years, or 16,000 hours, for oil and coal
applications. However, some catalysts have shown longer life, 8 to 10 years, when applied on
clean-burning fuel.24
The disposal of spent catalyst can present a potential environmental impact because
some of the catalyst formulations are potentially toxic and subject to hazardous waste disposal
regulations under RCRA and its amendments. For example, vanadia and titania catalysts are
considered hazardous material. However, recent industry trends have shown that these material
are readily regenerable. In fact, many catalyst vendors recycle this material thus avoiding any
disposal problem for the user. Some of the catalysts, especially those that use rare earth
material such as zeolites, are not hazardous and their disposal does not present an adverse
environmental impact.
7.3 WATER USAGE AND WASTEWATER DISPOSAL
The only increase in water use is associated with the use of WI or SI and potentially
with the use of flue gas treatment NOX controls, especially SNCR. The use associated with WI
or SI injection is an obvious one. The amount of water used does often not exceed 50 percent
of the total fuel input on a weight basis. This is because excessive use of flame quenching with
water can result in high emissions of CO and high thermal efficiency loss. Therefore, a
50 MMBtu/hr (15 MWt) boiler would use approximately 600,000 gal (2.2 million L) of water per
year when operating with a 50 percent capacity factor.
An increase in water use and wastewater disposal requirement could result from the use
of SNCR techniques, either urea or ammonia based. This is because ammonia slip when
combined with SO3 in the flue gas will form corrosive salts that deposit on heat transfer surfaces
such as air heaters. These deposits must be removed to minimize pressure drop and material
corrosion. Air heater acid washing could become more frequent. This practice would result in
greater generation of wastewater requiring treatment and disposal. However, urea-based SNCR
can actually use wastewater as reagent dilution water prior to injection, thus minimizing the
amount of wastewater generated. Increased air heater washing has not been reported in the
more than 80 combustion sources equipped with SNCR in the United States.
7.4 ENERGY CONSUMPTION
This section discusses the energy consumption associated with NOX control techniques
for ICI boilers. Energy consumption can come in various forms: a boiler fuel consumption
7-13
-------
penalty caused by reduced thermal or combustion efficiency; an increase in electrical power to
operate fans and pumps; an increase in fuel consumption due to reheat of flue gas; an increase
in energy for treatment and disposal of solid or liquid wastes generated by the control
technology. Some controls offer the potential for a reduction in energy consumption. Trimming
the excess oxygen necessary to assure complete combustion is the most noted of these energy
savings techniques. Others include the installation of economizers and air preheaters to recover
waste heat in some older and smaller boilers. However, contrary to oxygen trim, these other
techniques do not offer a potential for NOX reduction as well.
7.4.1 Oxygen Trim (OT)
ICI boilers are operated at various excess air levels, ranging from about 10 to over
100 percent of the theoretical amount of air needed to complete combustion. Some amount of
excess air is required regardless of fuel burned and method of burning because fuel and air do
not perfectly mix and the residence time in the combustion chamber is not infinite. This
additional air provides a safe method to increase flame turbulence and assure near complete
combustion of fuel. The type of fuel burned and the method of burning determines the
minimum amount of excess air required for safe and near complete combustion. For example,
the following minimum excess O2 levels are considered typical for these fuels25:
• Natural gas, 0.5 to 3.0 percent
• Oil fuels, 2.0 to 4.0 percent
• Pulverized coal, 3.0 to 6.0 percent
• Coal stoker, 4.0 to 8.0 percent
Generally, excessive combustion air are found in poorly maintained, unattended boilers. Tliif
added air provides some measure of safety for burning all the fuel, especially when the operation
of boilers is poorly supervised. In many such instances, burner tuning and combustion control
adjustments and equipment improvements can be readily made that reduce the amount of excess
air resulting in a thermal efficiency improvement and reduced NOX emissions without
compromising the safety of the operation of the unit. Qualified boiler and burner engineers and
consultants can upgrade key components of the combustion air control system, including the
installation of monitors for O2 and CO levels in the stack.
Figure 7-3 illustrates the efficiency improvement that can be obtained by reducing excess
combustion air in ICI boilers. For example, a 10-percent reduction in excess air (say, from O2
of 3.5 to 2.0 percent) would result in an efficiency improvement of approximately 0.6 percent
7-14
-------
.10
.09
.08
.07
.06
.05
.04
.03
.02
.01
——— j
M
/
200
300 400 500
STACK TEMPERATURE, °F
600
Figure 7-3. Curve showing percent efficiency improvement per every 1 percent reduction in
excess air. Valid for estimating efficiency improvements on typical natural
gas, No. 2 through No. 6 oils, and coal fuels.
when the stack temperature is at 200°C (400°F). For a natural-gas-fired boiler with a capacity
of 150 MMBtu/hr and a capacity factor of 0.5, this improvement will result in fuel savings of
about 3.7 million ft3 of natural gas per year or about $13,600/yr savings. Algebraically, the
relationship between boiler efficiency and excess air can be expressed as follows26:
AE
(T - 70)
63.1
%EA
89.5
(7-1)
Where:
T * stack temperature in °F
% EA = the change in percent excess air
The reduction in excess air, however, can result in some increase in unburned fuel
primarily in the form of CO emissions, when gas or fuel oil is burned, and in unburned carbon
in the flyash, when coal is burned. Increased emissions of CO have a detrimental effect on the
7-15
-------
efficiency, as illustrated in Figure 7-4. For example, the example boiler describe above operating
at 2.0 percent oxygen might have an increase in CO to about 350 ppm, measured on a dry basis
in the flue gas. This amount of CO would reduce the efficiency gain of 0.6 percent described
above by about 0.1 percent. Besides this efficiency loss, the air quality impact of increased CO
must be considered. The objective of boiler/burner tuning, however, is to reduce excess air
without increasing CO emissions or unburned carbon, as discussed in Chapter 5. Algebraically,
the relationship between boiler efficiency and CO can be expressed as follows26:
P-2)
J,oo2 I oy.5 I
Where:
T = stack temperature in °F
% EA - the change in percent excess air
1A2 Water Injection/Steam Injection (WI/SI)
The injection of water or steam in the burner zone to reduce peak flame temperature
and NOX will have a detrimental impact on the efficiency of the boiler. Figure 7-5 illustrates the
relationship between the amount of water or steam injected and the reduction in the thermal
efficiency of the boiler. The data were developed using standard American Society of
Mechanical Engineers (ASME) boiler efficiency calculation procedures.27 The amount of water
injected is typically in the range of 20 to 50 percent of the fuel input on a weight basis. Higher
injection levels can cause large increases in CO and HC emissions. The corresponding loss in
thermal efficiency when using water is in the range of about 1 to 2.5 percent. The efficiency loss
when using an equivalent amount of steam is lower. However, the NOX reduction efficiency is
also lower.
7.43 Staged Combustion Air (SCA)
The operation of an ICI boiler with staged combustion air, whether BOOS or OFA, will
likely not require additional energy. Taking selected burners out of service will not influence the
air distribution. Also any increase in fan power associated with the operation of OFA ports will
likely be compensated, for the most part, with reduction of air flow at the original burners.
7.4.4 Low-NOx Burners (LNBs)
Minor or no increases in energy consumption are anticipated with the retrofit of LNB
technology. This is because newer LNB designs operate at lower excess air levels, thus requiring
lower fan power. Some increases in windbox pressures are likely with some retrofits because of
7-16
-------
I .«
*>
I I I
CM Composition (« Vol)
IIXV
0.22 1.4* H.U 4.1? 0.*) O.U j.Ol 1055 »tu/ft /
Suck txmi 0 , * (dry)
1000
»00
700
too
$00
300
200
100
Figure 7-4. Unbumed carbon monoxide loss as a function of excess O2
and carbon monoxide emissions for natural gas fuel.
28
2.5
(0
(0
u
0)
o
I
1.5
0.5
Water Injection Steam Injection
steam injected at 150 psig and 360 F
i i
0
10 20 30 40
Percent of water in fuel
50
60
Figure 7-5. Energy penalty associated with the use of WI or SI for NOX
control in ICI boilers.
7-17
-------
higher gas velocities and more register control. This increase in pressure drop will tend to
increase fan power somewhat, or compensate for the reduction in energy consumption at lower
combustion air levels.
7.4.5 Flue Gas Recirculation (FGR)
The retrofit of FGR requires the installation of a fan to recirculate a portion of the hot
flue gas back to the burner(s). The operation of the fan will result in an increase in energy
consumption. Figure 7-6 illustrates the calculated power requirements with the use of FGR.
The relationship between power consumption and FGR rate is based on the following equation:
- (0.5) (8,760 hr/yr) (0.0013558 kW/ft-lb) (FGR ft3 /s) (AP lb/ft2) (7-3)
r
Where:
0.5 = The capacity factor
AP = Assumed to be 10 inches of water to account for efficiency loss
Some additional energy penalty will also be incurred with an increase in pressure drop in the
windbox. However, any additional penalty is minor compare to the energy consumption for the
FGR fan.
7.4.6 Selective Noncatalytic Reduction (SNCR)
Energy consumption in the SNCR process is related to pretreatment and injection of
ammonia-based reagents and their carrier gas or liquids. Liquid ammonia or urea are injected
in liquid form at high pressures to ensure efficient droplet atomization and dispersion. In some
Thermal DeNOx installations, anhydrous ammonia is stored in liquid form under pressure. The
liquid ammonia must be vaporized with some heat, mixed with carrier gas (air or steam) and
then injected for adequate mixing. The amount of electricity used depends on whether the
process uses air or steam for carrier gas. If steam is used, less electricity is needed but power
consumption must take into consideration the amount of steam used.
Data supplied by Exxon suggest that the amount of electricity needed for the Thermal
DeNOx Process is on the order of 1.0 to 1.5 kW for each MWt of boiler capacity (or 0.29 to
0.44 kW/MMBtu/hr) when using compressed air as the carrier medium.29 The actual amount
of electricity will depend on the baseline NOX emission level, the NH3/NO ratio used, and the
NOX reduction target. Therefore, a 250 MMBtu/hr (73 MWt) boiler operating with a capacity
factor of 0.5 will use approximately:
7-18
-------
^ 100,000
c
_g
Q. 80,000
E
(0
O 60,000
O
>.
S>
0) 40,000
C
0)
15
20,000
10 MMBtu/hr
50 MMBtu/hr :
100 MMBtu/hr
<_i
150 MMBtu/hr
»k
250 MMBtu/hr
--*"
5 10 15 20 25
Flue gas recirculation rate (percent)
30
Windbox pressure 10 inches H2O
FGR gas temperature 540 F
Boiler primary fuel = natural gas
Figure 7-6. Estimated energy consumption in FGR use.
0.29 kW/MMBtu/hr x 250 MMBtu/hr x 0.5 x 8,760 hr/yr = 319,740 kWh (7-4)
which corresponds to about $16,000/yr electricity cost. For steam-assisted ammonia injection,
electricity use reduces to about 0.2 to 0.3 kW/MWt or 0.05 to 0.08 kW/MMBtu/hr boiler
capacity. The amount of steam used is on the order of 25 to 75 Ib/hr/MWt. In general,
ammonia is most economically injected using compressed air rather than steam. Data supplied
by Nalco Fuel Tech suggest that the urea-based SNCR process uses much lower levels of
electricity than either ammonia-based SNCR or SCR. Typical auxiliary power requirements for
an ICI boiler using urea-based SNCR ranges from 20 to 60 kW.30
7.4.7 Selective Catalytic Reduction (SCR)
Energy consumption for the use pf SCR systems consists of three principal areas: (1)
the energy needed to store, pretreat and inject the chemical reagent ammonia or ammonia
hydroxide; (2) the increased fan power to overcome the added pressure drop of the catalyst
reactor in the flue gas; and (3) the thermal efficiency loss associated with maintaining the
7-19
-------
catalyst reactor temperature within the specifications foroptimum performance at variable boiler
load. The energy to store, pretreat, and inject the reagent is equivalent to that of an SNCR
system. Estimates of increased pressure drop across the catalyst vary with the various catalyst
vendors and applications, primarily fuel. Typically, the pressure drop across a catalyst is on the
order of 3 to 6 inches of water. Figure 7-7 illustrates the energy consumption associated with
the additional pressure drop. The relationship between energy consumption and pressure drop
across the catalyst is based on the following equation:
^- = (AF in H20) 0.0361 — in H2O
in
144
in'
0.85
8.760
Where:
AP = Pressure drop across catalyst, in inches of water
Q - Flue gas flowrate in actual ft3/s
300,000
f! 250,000
C
.o
Q. 200,000
|
CO
O 150,000
O
CD 100,000
C
co
50,000 —
10 MMBtu/hr
B
50 MMBtu/hr
A
100 MMBtu/hr
- O
150 MMBtu/hr
250 MMBtu/hr
Flue gas temperature = 540 F
Fan efficiency 85 percent
Primary fuel «= natural gas
23456
Pressure drop across the SCR reactor
Figure 7-7. Estimated increase in energy consumption with SCR pressure drop.
7-20
-------
Finally, the third potentially large source of energy consumption is the result of
increased flue gas temperature at the stack at low boiler loads. This increase in stack
temperature is associated with the bypass of heat exchange areas or increased fuel consumption
to maintain the catalyst at optimum reaction temperature. Figure 7-8 illustrates the loss in boiler
thermal efficiency as stack temperature increases. For example, at 20 percent excess air level
the thermal efficiency loss is approximately 1.2 percent for an increase in flue gas temperature
of 50CF. From an efficiency effect standpoint, each 10°F increase in stack temperature is
equivalent to a 583-ppm increase in CO emissions. Whether a facility will incur in this energy
penalty will depend on the retrofit configuration, the boiler's load cycle, and the operating
temperature window of the catalyst.
r EFFICIENCY IMPROVEMENT PER 10*F STACK TEMPERATURE RED
3OOOOOOOOC
MK>K)(OWUtt">U>U>*
•O*kO\O3C>N)**O^a)C
K 0.20
/
'
/
s
/
'
,
/
/
/
J
'
/
/
10 20 30 40 50 60 70
BOILER EXCESS AIR, PERCENT
80
90
100
Figure 7-8. Curve showing percent efficiency improvement per every 10°F drop
in stack temperature. Valid for estimating efficiency improvements
on typical natural gas, No. 2 through No. 6 oils, and coal fuels
25
7-21
-------
7.5 REFERENCES FOR CHAPTER 7
1. Cato, G. A., et al. (KVB, Inc). Field Testing: Application of Combustion Modifications
to Control Pollutant Emissions from Industrial Boilers—Phase II. Publication No.
EPA-600/2-72-086a. Prepared for the U.S. Environmental Protection Agency.
Research Triangle Park, NC. April 1976.
2. Schild, V., et al. (Black Hills Power and Light Co.). Western Coal-Fired Boiler Retrofit
for Emissions Control and Efficiency Improvement. Technical Paper No. 91-JPGC-
FACT-7. American Society of Mechanical Engineers. New York, NY. 1991.
3. Folsom, B., et al. (Energy and Environmental Research Corporation). Field Evaluation
of the Distributed Mixing Burner. Proceedings: 1985 Symposium on Stationary
Combustion NOX Control. Publication No. EPRI CS-4360. U.S. Environmental
Protection Agency/Electric Power Research Institute. Palo Alto, CA. 1989.
4. Farzan, H., et al. (Hitachi Zosen Corporation). Three Stage Pulverized Coal
Combustion System for In-Furnace NOX Reduction. Proceedings: 1985 Symposium on
Stationary Combustion NOX Control. Publication No. EPRI CS-5361. U.S.
Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA.
January 1986.
5. Langsjoen, J. E., et al. (KVB, Inc.). Field Testing of Industrial Stoker Coal-Fired
Boilers for Emissions Control and Efficiency Improvement—Site F. -Publication No.
EPA-600/7-80-065a. Prepared for the U.S. Environmental Protection Agency, U.S.
Department of Energy, and the American Boiler Manufacturers Association.
Washington, D.C. November 1979.
6. Goldberg, P. M., and E. H. Higginbotham. Field Testing of an Industrial Stoker Coal-
Fired Boiler—Effects of Combustion Modification NOX Control on Emissions—Site A.
Report No. TR-79-25/EE. Acurex Corporation. Mountain View, CA. August 1979.
7. Bijvoet, U. H. C, et al. (TNO Organization for Applied Scientific Research). The
Characterization of Coal and Staged Combustion in the TNO 4-MWth AFBB Research
Facility. Proceedings of the 1989 International Conference on Fluidized Bed
Combustion. The American Society of Mechanical Engineers/Electric Power Research
Institute/ Tennessee Valley Authority. New York, NY. 1989.
8. Dean, H. G. (Hugh Dean and Company, Inc.). Flue Gas Recirculation. Presented to
South Coast Air Quality Management District. March 23, 1989. pp. 15-16.
9. Letter from Coffey, A., Cleaver Brooks, to Herbert, E. L. & Conway, Inc. Cleaver
Brooks FGR Experience. September 14, 1992.
10. Letter and attachments from Stoll, F. R., Hugh Dean & Co., Inc., to Briggs, A., Acurex
Environmental Corporation. Cleaver-Brooks FGR. April 5, 1993.
11. Kesselring, J. P., and W. V. Krill (Alzeta Corporation). A Low-NOx Burner for Gas-
Fired Firetube Boilers. Proceedings: 1985 Symposium on Stationary Combustion NOX
7-22
-------
Control. Publication No. EPRI CS-4360. U.S. Environmental Protection
Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
12. Field Tests Update: Ceramic Filter Burner for Firetube Boilers. Gas Research
Institute. Chicago, IL. August 1987.
13. Potts, N. L., and M. J. Savoie (U.S. Army Construction Engineering Research
Laboratory). Low NOX Burner Retrofits: Case Studies. Technical Paper No. 91-10.22.
Air and Waste Management Association. Pittsburgh, PA. June 1991.
14. Office of Air Quality Planing and Standards. Overview of the Regulatory Baseline,
Technical Basis, and Alternative Control Levek for Nitrogen Oxides (NOX) Emissions
Standards for Small Steam Generating Units. Publication No. EPA-450/3-89-13. U.S.
Environmental Protection Agency. Research Triangle Park, NC. May 1989.
15. Roman, V. (KVB, Inc.). Compliance Test Report: Oxides of Nitrogen and Carbon
Monoxide Emissions from Primary Boiler—Source Location: Miller Brewing Company,
Irwingdale, CA. Submitted to the South Coast Air Quality Management District, El
Monte, CA. August 13, 1990.
16. Hunter, S. C, et al. Application of Combustion Modifications to industrial combustion
equipment. KVB, Inc., Irvine, CA. 1977.
17. Heap, M. P., et al. Reduction of Nitrogen Oxide Emissions from Package Boilers.
Publication No. EPA-600/2-77-025, NTIS-PB 269 277. January 1977.
18. Technical Review Group, State of California. A Suggested Control Measure for the
Control of Emissions of Oxides of Nitrogen from Industrial Institutional & Commercial
Boilers, Steam Generators & Process Heaters. April 29, 1987. p. 18.
19. American Boiler Manufacturers Association (ABMA). Guidelines on Carbon Monoxide
Emissions for Oil- and Gas-Fired Industrial Boilers. 1991. p. 4.
20. Muzio, L. J., et al. (Fossil Energy Research Corporation). N2O Formation in Selective
Non-Catalytic NOX Reduction Processes. Proceedings: 1991 Joint Symposium on
Stationary Combustion NOX Control — EPA/EPRI. March 1992.
21. Letter and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C., Acurex
Environmental Corporation. NOxOUT Urea-Based SNCR Performance. June 9,1992.
22. Hofmann, J. E., et al. (Nalco Fuel Tech). NOX Control for Municipal Solid Waste
Combustors. Technical Paper No. 90-25-2. Air and Waste Management Association.
Pittsburgh, PA. June 1990.
23. Cato, G. A., et al. (KVB Engineering Inc.). Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions From Industrial Boilers — Phase n.
Publication No. EPA-600/2-76-086a. April 1976. p. 192.
7-23
-------
24. Smith J. C, Response to U.S. Questionnaire on SCR, NSCR, and CO/HC Catalysts.
Institute of Clean Air Companies. Washington, D.C. May 14, 1992. p. 2.
25. McElroy, M. W. and D. E. Shore. Guidelines for Industrial Boiler Performance
Improvement. Publication No. EPA-600/8-77-003a. January 1977. p. 44.
26. Coen Company. Sales Meeting Proceedings of 1991.
27. Performance Test Codes (ASME). Boiler Efficiency. PTC 4.la. 1964.
28. Payne, W. F. Efficient Boiler Operations Sourcebook. Fairmont Press, Atlanta, GA.
May 1985. p. 61.
29. Letter and attachments from Haas, G. A., Exxon Research and Engineering Company,
to Jordan, B., U.S. EPA, Office of Air Quality Planning and Standards, Durham, NC.
NOX Control Technologies Questionnaire. February 18, 1993.
30. Letter and attachments from Pickens, R. D., Nalco Fuel Tech, to Neuffer, W. J., U.S.
EPA, Office of Air Quality Planning and Standards, Durham, NC. Comments on Draft
Alternative Control Techniques Document. October 27, 1993. p. 5.
7-24
-------
APPENDIX A. ICI BOILER BASELINE EMISSION DATA
This appendix lists baseline NOX, CO, and unburned THC data for more than 200 ICI
boilers. The data were obtained primarily from published technical papers and EPA documents
summarizing data from numerous test programs. Boiler data are listed by fuel type, with the
exception of FBC boilers which are listed separately. More detailed data may be obtained by
referring directly to the individual references.
A-l
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UNCONTROLLED EMISSIONS.
BUBBLING BED FBC BOILERS
FBC ID
B&W Pilot
Canadian Forces Base.
P. Edward Is.. Canada
Col mac, CA
CCRL Pilot, Canada
Dong Chang Paper. Korea
HBCM Le Bee, France
Mesquite Lk, CA
Mitsui Toatsu, Japan
Saarbruecken, Germany
Sakito Salt. Japan
SOHIO Refinery. OH
Sumitomo Power. Japan
Sumitomo Metal. Japan
TNO
TVA Pilot. KY
MAXIMUM PRIMARY
CAPACITY FUEL NOx NOx CO CO
(MMBtu/hr) TYPE (Ib/MMBtu) (pp-n 93X02) (Ib/MHBtu) (ppm 93X02) REFERENCE
50
330
3.4
55
6.8
160
75
289
145
97
245
150
14
134
coal
RDF
coal
biomass
rice hulls
coal
coal
cow manure
coal
coal
coal
coal
coal
coal
coal
coal
0.81
0.44
0.62
0.10
0.20
0.17
0.11
0.42
0.46
0.12
0.23
0.56
0.27
0.30
0.28
0.17
600
315
460
70
140
125
80
294
340
90
170
415
200
220
210
125
0.49 600 14
4.68 5523
0.37 453 4
0.15 173 15
3.10 3655 7
16
0.49 600 17
0.38 437 18
16
0.17 204 19
16
4
16
16
0.30 365 20
0.41 495 21
RDF: REFUSE DERIVED FUEL
A-ll
-------
UNCONTROLLED EMISSIONS,
CIRCULATING FBC BOILERS
FBC ID
ADM. Cedar Rapids. I A
A.E. Staley
Ansaldo/Studovik
Archbald Cogen
BF Goodrich
Energieversorgung. Germany
Ft. Howard Co.
Foster Wheeler
GM-Ft. Wayne. IN
Idenritsu. Japan
lone Cogen. , CA
Kerry Coop. Ireland
Kuk Dong Oi 1 , Korea
Kuraray. Japan
Lauoff Grain, IL
Montana One
Paper mill. U.S.
Pyropower Corp.
Scott Paper
Sun Kyong Fibers, Korea
Thyssen Industrie, Germany
Ultra Systems, CA
U. of Iowa
U. of Missouri
Wheel abrator Energy
MAXIMUM PRIMARY
CAPACITY FUEL NOx NOx CO CO
(MMBtu/nr) TYPE (Ib/MMBtu) (ppm 03%02) (Ib/MMBtu) (ppm 83X02)
500
394
8.5
210
130
250
362
400
157
693
155
122
280
162
250
476
340
683
300
84
280
179
210
430
coal
coal
coal
culm
coal
coal
coal
culm
coal
coal
coal
coal/peat/ww
petroleum coke
coal
coal
coal waste
coal
coal
petroleum coke
culm
coal
coal
wood
coal
coal
coal
0.30
0.60
0.20
0.25
0.34
0.22
0.16
0.16
0.20
0.40
0.18
0.14
0.09
0.34
0.20
0.20
0.28
0.49
0.27
0.12
0.60
0.27
0.18
0.21
0.40
0.50
0.50
222
444
150
180
252
164
118
118
140
296
133
101
65
250
148
150
200
362
200
90
430
200
135
150
296
370
370
0.02
0.17
0.17
0.03
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REFERENCE
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UW: WOOD WASTE
A-12
-------
REFERENCES FOR APPENDIX A
1. Emissions Assessment of Conventional Stationary Combustion Systems, Volume V:
Industrial Combustion Sources. Publication No. EPA-600/7-81-003c. U.S. Environmental
Protection Agency. Research Triangle Park, NC. 1981.
2. Technology Assessment Report for Industrial Boiler Applications: NOX Combustion
Modification. Publication No. EPA-600/7-79-178f. U.S. Environmental Protection Agency.
Research Triangle Park, NC. December 1979.
3. Emissions Assessment of Conventional Stationary Combustion Systems, Volume IV:
Commercial/Institutional Combustion Sources. Publication No. EPA-600/7-71-003c.
Prepared by TRW, Inc., for the U.S. Environmental Protection Agency. Research Triangle
Park, NC. January 1981.
4. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control Levels for
Nitrogen Oxides Emission Standards for Small Steam Generating Units. Publication No.
EPA-450/3-89-13. Office of Air Quality Planning and Standards. U.S. Environmental
.Protection Agency. Research Triangle Park, NC. May 1989.
5. Field Tests of Industrial Stoker Coal-Fired Boilers for Emission Control and Efficiency
Improvement—Site E. Publication No. EPA-600/7-80-064a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. March 1980.
6. Field Tests of Industrial Stoker Coal-Fired Boilers for Emission Control and Efficiency
Improvement—Site H. Publication No. EPA-600/7-80-112a. U.S. Environmental Protection
Agency. Research Triangle Park, NC. May 1980.
7. Industrial Boiler Combustion Modification NOX Controls, Volume I: Environmental
Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmental Protection Agency.
Research Triangle Park, NC. July 1981.
8. Letter from LeBlanc, B., Riley Stoker Corp., to Sanderlord, E., MRI. NOX Emissions from
Utility and Industrial Boilers. April 15, 1992.
9. Letter from Coffey, A., Cleaver Brooks, to Herbert, E. L., Herbert & Conway, Inc. Cleaver
Brooks FOR Experience. September 14, 1992.
10. Letter from Eichamer, P., Exxon Chemical Co., to Snyder, R., MRI. ACT NOX Data. July
10, 1992.
11. Cleaver Brooks System 20 FOR. Cleaver Brooks Co. 1993.
12. NOX Emission Factors for Wood-Fired Boilers. Publication No. EPA-600/7-79-219. U.S.
Environmental Protection Agency. Research Triangle Park, NC. September 1979.
13. Letter and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C, Acurex
Environmental Corp. NOxOUT Urea-Based SNCR Performance. June 9, 1992.
A-13
-------
14. McGavin, C. R., et al. FBC Testing of Coal/RDF Mixtures. Presented at the 10th
International Conference on Fluidized Bed Combustion. San Francisco, CA. May 1989.
15. Dahl, J. Agricultural Waste Fueled Energy Projects. • Presented at the Second CIBO
Alternate Fuels Conference. Arlington, VA. May 1989.
16. Makansi, J. and R. Schwieger. Fluidized Bed Boilers. Power Magazine. May 1987.
17. Marlair, G., et al. The Lardet-Babcock/Cerchar 2.5 MWt Package Fluidized Bed Boiler.
Presented at the 9th International Conference on Fluidized Bed Combustion. Boston, MA.
May 1987.
18. Cooke, R. C. Mesquite Lake Resource Recovery Project, a Case History. Presented at the
Second CIBO Alternate Fuels Conference. Arlington, VA. May 1989.
19. Tigges, K. D. and D. Kestner. Experience with the Commissioned Operation of the
Saarbruecken Circofluid Boiler. Presented at the 10th International Conference on
Fluidized Bed Combustion. San Francisco, CA. May 1989.
20. Bijvoet, U. H. C., et al. Characterization of Coal and Staged Combustion in the TNO 4
MWt AFBB Research Facility. , Presented at the 10th International Conference on
Fluidized Bed Combustion. San Francisco, CA. May 1989.
21. Tavoulareas, S., et al. EPRI's Research on AFBC By-Product Management. Presented at
the 9th International Conference on Fluidized Bed Combustion. Boston, MA. May 1987.
22. Lombardi, C. Tampella-Keeler Operating Experience with CFB Boilers. Presented at the
Fifth Annual CIBO Fluidized Bed Conference. Sacramento, CA. December 1989.
23. Place, W. J. CFBC via Multi Solid Fluidized Beds in the Industrial Sector. Presented at
the 9th International Conference on Fluidized Bed Combustion. Boston, MA. May 1987.
24. Adams, C., et al. Full Load Firing of Coal, Oil, and Gas in a Circulating Fluidized Bed
Combustor. Presented at the 10th International Conference on Fluidized Bed Combustion.
San Francisco, CA. May 1989.
25. Hutchinson, B. The Pyroflow Boiler at B.F. Goodrich Co.—The First 18 Months of
Steaming at Henry, IL. Presented at the 9th International Conference on Fluidized Bed
Combustion. Boston, MA. May 1987.
26. Worldwide List of Fluid Bed Boiler Installations. Council of Industrial Boiler Owners
(CIBO). Burke, VA. 1990.
27. Abdulally, I. F. and D. Parham. Design and Operating Experience of a Foster Wheeler
CFB Boiler. Presented at the 10th International Conference on Fluidized Bed Combustion.
San Francisco, CA. May 1989.
A-14
-------
28. Studley, B. and D. Parham. Foster Wheeler Mf. Carmel Anthracite Culm-Fired CFB
Steam Generation Experience. Presented at the Sixth Annual CIBO Fluidized Bed
Conference. Harrisburg, PA. December 1990.
29. Bashar, M. and T. S. Czarnecki. Design and Operation of a Lignite Fired CFB Boiler
Plant. Presented at the 10th International Conference on Fluidized Bed Combustion. San
Francisco, CA. May 1989.
30. Belin, F., et al. Lauhoff Grain Coal-Fired CFB Boiler—Design, Startup, and Operation.
Presented at the Sixth Annual CIBO Fluidized Bed Conference. Harrisburg, PA.
December 1990.
31. Syngle, P. V. and B. T. Sinn. Case History of the Montana One CFB Project. Presented
at the Sixth Annual CIBO Fluidized Bed Conference. Harrisburg, PA. December 1990.
32. Abdually, I. F. and D. Parham. Operating Experience of a CFB Boiler Designed by Foster
Wheeler. Presented at the Fifth Annual CIBO Fluidized Bed Conference. Sacramento,
CA. December 1989.
33. Tang, J. and F. Engstrom. Technical Assessment on the Anlstrom Pyroflow Circulating and
Conventional Bubbling FBC System. Presented at the 9th International Conference on
Fluidized Bed Combustion. Boston, MA. May 1987.
34. Darling, S. L., et al. Design of the Scott Paper CFB. Presented at the 9th International
Conference on Fluidized Bed Combustion. Boston, MA. May 1987.
35. Geisler, O. J., et al. 40 MW FBC Boiler for the Combustion of High Sulfur Lignite.
Presented at the 10th International Conference on Fluidized Bed Combustion. San
Francisco, CA. May 1989.
36. Emissions and Efficiency Performance of Industrial Coal Stoker Fired Boilers. Publication
No. EPA-600/7-81-llla. July 1981.
A-15
-------
APPENDIX B. CONTROLLED NOX EMISSION DATA
This appendix lists controlled emissions data for boilers used in the ICI sector. Where
appropriate, data for small utility boilers and representative pilot-scale units are also included.
The data were compiled primarily from technical reports, EPA documents, compliance records,
and manufacturers' literature, as listed in the references at the end of this appendix. Additional
low-NOx performance data specific to low-NOx burners (LNB) marketed by Coen Company, of
California, and Tampella Power Corporation, Faber Burner Division, of Pennsylvania, are in
Appendix C. Boiler emissions data are listed by fuel type and whether the NOX control method
used was a combustion modification or a flue gas treatment method.
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REFERENCES FOR APPENDIX B
1. Vatsky, J. (Foster Wheeler Energy Corporation). NOX Control: The Foster Wheeler
Approach. Proceedings: 1989 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/ Electric Power
Research Institute. Palo Alto, CA. July 1989.
2. Vatsky, J., and E. S. Schindler (Foster Wheeler Energy Corporation). Industrial and Utility
Boiler Low NOX Control Update. Proceedings: 1987 Symposium on Stationary
Combustion NOX Control. Publication No. EPRI CS-5361. U.S. Environmental Protection
Agency/Electric Power Research Institute. Palo Alto, CA. August 1987.
3. Vatsky, J., and T. W. Sweeney. Development of an Ultra-Low NOX Pulverized Coal Burner.
Foster Wheeler Energy Corporation. Clinton, NJ. Presented at the 1991 Joint Symposium
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4. Buchs, RA., et al. (Kerr-McGee Chemical Corporation). Results From a Commercial
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5. Schild, V., et al. (Black Hills Power and Light Co.). Western Coal-Fired Boiler Retrofit for
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6. Letter for Leblanc, B., Riley Stoker Corp., to Sanderford, E., MRI. NOX Emissions from
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9. Narita, T., et al. (Babcock Hitachi K.K.). Development of the Low NOX Burner For the
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10. Penterson, CA. (Riley Stoker Corp.) Controlling NOX Emissions to Meet the 1990 Clean
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B-24
-------
11. Folsom, B., et al. (Energy and Environmental Research Corporation). Field Evaluation of
the Distributed Mixing Burner. Proceedings: 1985 Symposium on Stationary Combustion
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12. Farzan, H., et al. (Babcock & Wilcox Company). Pilot Evaluation of Reburning for Cyclone
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B-25
-------
20. Maloney, K. L., et al (KVB, Inc.). Low-sulfur Western Coal Use in Existing Small and
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Research Institute. Palo Alto, CA. January 1986.
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Bed Boilers. Ahlstrom Pyropower Corp. Finland.
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Research Institute/Tennessee Valley Authority. New York, NY. 1989.
B-26
-------
30. Letter from Coffey, A., Cleaver Brooks, to Herbert, E. L., Herbert & Conway, Inc. Cleaver
Brooks FOR Experience. September 14, 1992.
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California Low-NOx Applications. Attachment 4. February 18, 1992.
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File/Rule 1146. Proposed Rule 1146—Trip to Beverly Hills Hilton to Inspect the Boiler
Room. February 1987.
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California Low-NOx Applications. Attachment 6. February 18, 1992.
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Measure for the Control of Emissions of Oxides of Nitrogen from Industrial, Institutional,
and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources
Board and the South Coast Air Quality Management District. Sacramento, CA. April 29,
1987.
35. Letter from Cluer, A. L., Clayton Industries, to Votlucka, P., South Coast Air Quality
Management District. Results from Boiler Manufacturer's Test of a Gas-Fired Boiler With
and Without FGR. October 14, 1987.
36. Cleaver Brooks Division. NOX versus Recirculation Rate—200 hp Gas Firing—R&D Lab
Tests. December 1987.
37. Cleaver Brooks Division. NOX versus Recirculation Rate—350 hp Gas Firing—R&D Lab
Tests. December 1987.
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39. Letter and attachments from Stoll, F. R., Hugh Dean & Co., Inc., to Briggs, A., Acurex
Environmental. Cleaver-Brooks FGR. April 5, 1993.
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Firetube Boilers. Proceedings: 1985 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. January 1986.
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Monoxide Emissions from Primary Boiler—Source Location: Armstrong World Industries
South Gate, CA. Submitted to the South Coast Air Quality Management District, El
Monte, CA. September 28, 1990.
B-27
-------
42. LaRue, A. (Babcock & Wilcox). The XCL Burner—Latest Developments and Operating
Experience. Proceedings: 1989 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. July 1989.
43. Field Test Update: Ceramic Fiber Burner for Firetube Boilers. Gas Research Institute.
Chicago, IL. August 1987.
44. Yang, S. C., et al. Development of Low NOX Gas Burners. Energy and Resources
Laboratories (ERL), Industrial Technology Research Institute. Taiwan. Presented at the
1991 Joint Symposium on Stationary Combustion NOX Control—EPA/EPRI. Washington,
D.C. March 25-28, 1991.
45. Potts, N. L., and M. J. Savoie (U.S. Army Construction Engineering Research Laboratory).
Low NOX Burner Retrofits: Case Studies. Technical Paper No. 91-10.22. Air and Waste
Management Association. Pittsburgh, PA. June 1991.
46. Buening, H. J. (KVB, Inc.). Testing pf Low-NOx Combustion Retrofit—Boiler No. 3.
Report No. KVB71-60451-2008. Prepared for IBM, Inc., San Jose, CA. January 1985.
47. Larsen, L. L., and W. A. Carter (KVB, Inc.). Testing of Low-NOx Combustion
Retrofit-Boiler No. 6. Report No. KVB71-60412-2067. Prepared for IBM, Inc., San Jose,
CA. August 1983.
48. Londerville, S. B., and J. H. White (Coen Company). Coen Company Overview and Burner
Design developments for NOX Control. Proceedings: Third Annual NOX Control
Conference. Council of Industrial Boiler Owners. Burke, VA. February 1990.
49. Technical memorandum from Woodward, R., Hague International. Results of Emissions
Testing of Low-NOx Burner Installed in Hospital Boiler. January 1988.
50. Buening, H. J. (KVB, Inc.). Testing of Low-NOx Combustion Retrofit—VA Hospital-
Los Angeles Boiler No. 4. Report No. KVB71-72760-2130. Prepared for Keeler-Dorr-
Oliver. Williamsport, PA. May 1987.
51. Letter and attachments from DeHaan, T., Coen Co., Inc., to Seu, S., Acurex Environmental
Corp., Low-NOx Retrofits. February 6, 1992.
52. Roman, V. (KVB, Inc.). Compliance Test Report: Oxides of Nitrogen and Carbon
Monoxide Emissions from Primary Boiler—Source Location: Miller Brewing Company,
Irwindale, CA. Submitted to the South Coast Air Quality Management District, El Monte,
CA. August 13, 1990.
53. County of Orange Central Utility Facility NOX and CO Emission Results. Coen Company.
Distributed at the Fifth Annual CffiO NOX Control Conference. Long Beach, CA.
February 10, 1992.
B-28
-------
54. Letter and attachments for Marx, W., CIBO, to Seu; S., Acurex Environmental Corporation.
NOX Control Technology Survey. June 12, 1992.
55. Hunter, S. C., et al. Application of Combustion Modifications to Industrial Combustion
Equipment. KVB, Inc., Irvine, CA. 1977.
56. Oppenberg, R. Primary Measures Reducing NOX Levels in Oil- and Gas-Fired Water Tube
Boilers. Report No. 176. Deutsche-Babcock. Germany. September 1986.
57. Suzuki, T., et al. (Kobe Steel). Development of Low-NOx Combustion for Industrial
Application. Proceedings: 1985 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. January 1986.
58. Castaldini, C., et al. (Acurex Corp.). Environmental Assessment of an Enhanced Oil
Recovery Steam Generator Equipped with a Low NOX Burner. Acurex Report
No. TR-84-161/EE. Prepared for the U.S. Environmental Protection Agency. Research
Triangle Park, NC. January 1985.
59. McDannel, M. D., and T. D. Guth (KVB, Inc.). NOX Control Technology Applicable to Oil
Field Steam Generators. Report No. KVB71 42000-1694. Prepared for Getty Oil
Company. Bakersfield, CA. March 1983.
60. Steiner, J., et al. Oil Field Steam Generator Emission Testing, Taft, California—Baseline
Tests: Section 26-C, Unit 50-1. Report No. TR-79-175. Acurex Corporation. Mountain
View, CA. May 1979.
61. Steiner, J., and R. Pape. Oil Field Steam Generator Emission Testing, Taft,
California—Prototype Low NOX Burner Tests: Section 26-C, Unit 50-1. Report No. TR-79-
26/EE. Acurex Corporation. Mountain View, CA. September 1979.
62. Anderson, D. F., and T. Szytel (Grace Petroleum Corp.). NOX Reduction Methods for
California Steam Generators by Applied Technology. Paper No. SPE 12772. Sociely of
Petroleum Engineers. Dallas, TX. April 1984.
63. Brinkmann, P. E., and M. K. Poe (Mobil Exploration and Producing U.S., Inc.). NOX
Emission Reduction from Gas Fired Steam Generators. Technical Paper No. 89-19.6. Air
and Waste Management Association. Pittsburgh, PA. June 1989.
64. Nutcher, P. High Temperature Low NOX Burner Systems for Fired Heaters and Steam
Generator. Process Combustion Corp. Presented at the Pacific Coast Oil Show and
Conference. Los Angeles, CA. November 1982.
65. 1986 Pollutant Survey (TEOR steam generators). Kern County Air Pollution Control
District. November 1986.
B-29
-------
66. Abbasi, H., et al. Use of Natural Gas for NOX Control in Municipal Waste Combustion.
Institute of Gas Technology. Chicago, IL. Presented at the 1991 Joint Symposium on
Stationary Combustion NOX Control—EPA/EPRI. Washington, D.C. March 25-28, 1991.
67. Penterson, CA., et al. (Riley Stoker Corporation). Reduction of NOX Emissions From
MSW Combustion Using Gas Reburning. Proceedings: 1989 Symposium on Stationary
Combustion NOX Control. Publication No. EPRIGS-6423. U.S. Environmental Protection
Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
68. Lisauskas, R. A., et al. (Riley Stoker Corporation). Status of NOX Control Technology at
Riley Stoker. Proceedings: 1989 Symposium on Stationary Combustion NOX Control.
Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric Power
Research Institute. Palo Alto, CA. July 1989.
69. Letter and attachments from Haas, G. A., Exxon Research and Engineering Co., to Jordan,
B. C, U.S. EPA. NOX Control Technologies Questionnaire. February 18, 1993.
70. Karas, J., and D. Goalwin (Bay Area Air Quality Management District). NOX Emissions
from Refinery and Industrial Boilers and Heaters. Technical Paper No. 84-42.6. Air and
Waste Management Association. Pittsburgh, PA. June 1984.
71. Hofmann, J. E. (Nalco Fuel Tech). The NOxOUT Process for Control of Nitrogen Oxides.
Proceedings: Third Annual NOX Control Conference. Council of Industrial Boiler Owners.
Burke, VA. February 1990.
72. Tang, J. T. (Pyropower Corporation). NOX Control in Ahlstrom Pyroflow Boiler.
Proceedings: Second Annual NOX Control Conference. Council of Industrial Boiler Owners.
Burke, VA. February 1989.
73. Letter and attachments from Haas, G., Exxon Research and Engineering Company, to Seu,
S., Acurex Environmental Corporation. Thermal DeNOx Operating Experience
Information. March 1992.
74. Letter and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C., Acurex
Environmental Corporation. NOxOUT Urea-Based SNCR Performance. June 9, 1992.
75. Bodylski, J. A., and Haas, G. A. The Selective Noncatalytic Reduction Process: Experience
with the Exxon Thermal DeNOx Process at Two Circulating Fluidized Bed Boiler
Commercial Applications. Presented at the American Flame Research Committee's 1992
Fall International Symposium on Emissions Reductions and Energy Conservation.
Cambridge, MA. October 1992. pp. 3-5.
76. Letter and attachments from Valentine, J., Fuel Tech Inc., to Torbov, S., Acurex
Corporation. Summary of Urea NOxOUT Demonstration. January 1989.
77. SNCR NOX Control Demonstration. Wisconsin Electric Power Company, Valley Power
Plant Unit #4. March 1992.
B-30
-------
78. Hurst, B. E., et al. Exxon Thermal DeNOx Effectiveness Demonstrated in a Wood-Fired
Boiler. Exxon Research and Engineering Company. Florham Park, NJ. Presented at the
13th National Waste Processing Conference and Exhibit. May 1-4, 1988.
79. Jones, D. G., et al. (Emcotek Corporation). Two-Stage DeNOx Process Test Data for 300
TPD MSW Incineration Plant. Technical Paper No. 89-23B.7. Air and Waste Management
Association. Pittsburgh, PA. June 1989.
80. Clarke, M. (Environmental Research and Education). Technologies for Minimizing the
Emission of NOX From MSW Incineration. Technical Paper No. 89-167.4. Air and Waste
Management Association. Pittsburgh, PA. June 1989.
81. City of Commerce MSW Plant. Proceedings: Second Annual NOX Control Conference.
Council of Industrial Boiler Owners. Burke, VA. February 1989.
82. Hofmann, J. E., et al. (Nalco Fuel Tech). NOX Control for Municipal Solid Waste
Combustors. Technical Paper No. 90-25.2. Air and Waste Management Association.
Pittsburgh, PA. June 1990.
83. Letter and attachments from confidential company to Votlucka, P., South Coast Air Quality
Management District. Industrial SCR Experience. October 1988.
84. Behrens. E. S., et al. SCR Operating Experience on Coal Fired Boilers and Recent
Progress. Joy Environmental Equipment Company. Monrovia, CA. Presented at the 1991
Joint Symposium on Stationary Combustion NOX Control—EPA/EPRI. Washington, D.C.
March 25-28, 1991.
85. Furuya, K. (Electric Power Development Company). EPDC's Fluidized Bed Combustion
RD&D: a Progress Report on Wakamatsu 50 MW Demonstration Test and the World's
Largest FBC Retrofit Project. Proceedings of the 1989 International Conference on
Fluidized Bed Combustion. The American Society of Mechanical Engineers/Electric Power
Research Institute/Tennessess Valley Authority. New York, NY. 1989.
86. Christian, A. W. (M. C. Patten & Company). State of the Art NOX Control in Package
Boilers. Proceedings: Fourth Annual NOX Control Conference. Council of Industrial
Boiler Owners. Burke, VA. February 1991.
87. Kuroda, H., et al. (Kure Works of Babcock-Hitachi K.K.). Recent Developments in the
SCR System and its Operational Experiences. Proceedings of the 1989 International
Conference on Fluidized Bed Combustion. The American Society of Mechanical
Engineers/Electric Power Research Institute/Tennessess Valley Authority. New York, NY.
1989.
88. Donais, R. E., et al. (Combustion Engineering, Inc.). 1989 Update on NOX Emission
Control Technologies at Combustion Engineering. Proceedings: 1989 Symposium on
Stationary Combustion NOX Control. Publication No. EPRIGS-6423. U.S. Environmental
Protection Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
B-31
-------
89. Letter and attachments from Shaneberger, D. E., Exxon Research and Engineering Co.
NOX Emissions
September 1993.
NOX Emissions Data: ICI Boilers with Flue Gas Treatment NOX Controls — SNCR.
90. Letter and attachments from Wax, M. J., Institute of Clean Air Companies. NC-300
Catalyst Installations. September 16, 1993.
91. Letter and attachments from Pickens, R., Nalco Fuel Tech. Inc. NOxOUT Process
Experience List. October 27, 1993.
92. Energy Systems Associates. Characterization of Gas Cofiring in a Stoker-Fired Boiler.
Publication No. GRI-93/0385. Gas Research Institute. Chicago, IL. November 1993. p. 6.
B-32
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APPENDIX C. LOW-NOX INSTALLATION LISTS,
COEN COMPANY AND TAMPELLA POWER CORP.
(Note: NOX levels reported in the Coen list are not
necessarily those achieved with the Coen low-NOx
burner, but often represent NOX guarantees. Actual
levels may be lower.)
C-l
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•H 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 1
JOB NO.
0-2023-1
0-2019-1
0-2019-2
0-2019-3
0-2009-1
0-2008-1
0-2007-1
0-2005-1
0-2003-1
D-1 999-1
>1 999-2
;-1 995-3
J9S-1
D-1 996-1
9-1987-1
J--SE7-2
D-19S2-1
>1 967-1
3-1966-1
>1 960-2
>1 960-1
5-1 954-1
9-1945-1
>1945-2
3-1942-1
>37-1
INSTALLATION
Bergan Mercy Med.
0«ha, NE
Rancho Los Amgos
Downey, CA
StUlviter UtU.
EriUvater, OK
Wright Patterson AFB
Oeyton, OH
Neenah Paper
"ee~eh, W!
Smurf it
Venezuela
Merck £ Co.
West Point, PA
Janes River
Berlin, NH
Champion Int't
Cantounent, FL
Si the Energies
Scriba, NY
Nationwide
Fremont, CA
Marion Merrell
Cincinnati, OH
Contadina Foods
Hanford, CA
CITSO
Lake Charles, u
Cargill
Lake Charles, LA
Cargitt
Eddyville, IA
Heublin Vines
Madera, CA
Chevron USA
Perth Amboy, NJ
So. Peru Copper
I lo, Peru
Wabash
Wheeling, IL
TYPE OF BOILER
NBC
NS-C-53
Nebraska
NS-B-38-ECON
Erie
IBU
0-Txpe
Nebraska
NS-G-80-ECON
8SJ
FM1 17-97
B&U
FK1 20-97
C.E.
VU
CE
34VP18/60
C.E.
38A14/48
B&U
FM 227-97
Nebraska
N2S-4A-67
Nebraska
NS-F-84-ECON
Zurn
Keystone
B&U
FM 120-97
B&U
FM 120-97
Nebraksa
NS-F-81-ECON
Nebraska
WS-E-67
CE
39VP22/54"
Nebraska
N2S-8/S-116SH
(NO. OF UNITS)
CAPACITY
(1) 40,000 PPH
(3) 24,000 PPH
(1) 150,000 PPH
(2) 80,000 PPH
(1) 120,000 PPH
(1) 150,000 PPH
(1) 140,000 PPH
(8) 100,000 PPH
(1) 350,000 PPH
(1) 385,000 PPH
(1) 200,000 PPH
(1) 210,000 PPH
(2) 150,000 PPH
(1) 60,000 PPH
<2> 100,000 PPH
(2) 250,000 PPH
(1) 165,000 PPH
(1) 150,000 PPH
(2) 100,000 PPH
(1) 82,300 PPH
(1) 68,500 PPH
(2) 400,000 PPH
(1) 250,000 PPH
FUEL TYPE
Natural Gas
No. 2 OU
No. 6 OU
Natural Gas
LOW Nit. OU
Natural Gas
No. 2 oU
Natural Eas
No. 1 oil
Natural Eas
No. 2 ou
Natural Css
No. 6 ou
Natural Gas
No. 2 ou
No. 6 ou
Natural Gas
Natural Gas
No. 2 01;
Natural Eas
No. 2 oU
No. 6 01 i
Natural G:s
No. 2 on
Natural Gas
No. 2 oil
Refinery Gas
Natural Gas
Natural Gas
Natural Gas
Propane/Air
Natural Cas
Refinery Gas
No. 6 ou
No. 2 on
No. 60-:
AND/OR ACTUAL BURNERS/ METHOD OF
NOx LEVELS BOILER NOX REDUCTION
40 PPM 1 DAF-22
56 PPM U/FGR
271 PPM
25 PPH
40 PPM
0.1 LBS/MMBTU
.10 LBS/MMBTU
.12 LBS/MMBTU
.16 LBS/MMBTU
.20 LBS/MMBTU
.20 LBS/MMBTU
.52 LBS/MMBTU
.05 LBS/MMBTU
.52 LBS/HMBTU
.28 LBS/MMBTU
.048 LBS/MMBTU
.20 LBS/MMBTU
30 PPH
.012 LES/MM8TU
.17 LBS/MMBTU
30 PPM
.06 LBS/MMBTU
.10 LBS/MMBTU
.07 L6S/MMBTU
30 PPM
.05 LBS/MMBTU
.05 LBS/MMBTU
.50 LBS/MMBTU
.20 LBS/MMBTU
.40 LBS/HMBTU
1
4
1
1
1
1
1
2
2
1
1
1
1
1
1
1
1
1
1
SDAF-17
U/FGR
OAF-28
U/FGR
DAF-28
W/FGR
OAF-34
OAF-36
OAF-39
OAF-30
U/FGR
DAF-45
U/FGR
DAF-42
U/FGR
OAF-36
U/FGR
OAF-28
OAF-32
W/FGR
OAF-36
U/FGR
OAF-39
U/FGR
OAF-36
U/FGR
OAF-32
U/FGR
OAF-30
U/FGR
OAF-45
DAF-48
W/FGR
C-3
-------
•H 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 2
JOB NO.
3-"1 930-1
5-1 923-1
V 91 9-1
3-1915-1
5-1891-1
0-1889-1
S-18S9-2
"»_"HO*_^
0-1867-1
>-!S7-2
J-1 854-1
,51-1
5-1S30-1
5-1 823-1
5--1 81 5-2
J-1815-1
0-1812-1
0-1803-1
J-1794-1
5-1778-1
5-1777-1
5-1773-1
62-1
INSTALLATION
Mi Mi University
Oxford, OH
Henkel Corp.
Los Angeles, CA
Appleton Piper
Combined Locks, VI
Central Soya
Sellevue, OH
City of Virginia
Virginia, MN
Indeck
Wheeling, IL
Indecie
Wheeling, IL
Chief Ethenot Fuels
Hastings, NE
Occidental Chen.
?asadena, TX
Weyerhaeuser Co.
Eugene, OR
General Motors
rt Wayne, IN
Passaic Valley Sewer
Newark, NJ
Kansas City Power
Kansas City, KS
Kansas City Power
Kansas City, KS
Ultra Systems
Weldon, NC
Texaco Inc.
Montebello, CA
ALCOA
Lafayette, IN
Nationwide Boiler
Fremont, CA
Hercules Aerospace
Maggna, UT
Ross Labs
Columbus, OH
Toray Industries
No. Kingstown, HI
TYPE OF BOILER
Nebraska
N2S-7-93-ECON
BSU
FM10-798
CE
40A16/48
Boiler Eng
OS35-112R
Zurn
Keystone
Zurn
16M
Zurn
Keystone 250S
foster wheeler
AG-5175B
Nebraska
N2S-8/S-103SH
Zurn
Keystone
RHey
HH
BSU
FM 10-70
A8CO
D-Type
ABCO
0-Type
Volcano
D-Type
BSU
FM-D-9-34
Nebraska
NS-E-63
BIW
FN 117-88C
Nebraska
NS-C-48-ECON
Nebraska
NS-F-65-ECON
Nebraska
NS-C-46-ECON
s
No. 2 OH
AND/OR ACTUAL BURNERS/ METHOD Cr
NOx LEVELS BOILER NOX REDUCTION
.1 LBS/HftBTU 1 BAF-34
W/FGR
30 PPM 1
.05 LBS/MMBTU 1
.10 LBS/MMBTU
.18 LBS/NftBTU 1
.10 LBS/MMBTU 1
.12 LBS/MMBTU 1
.055 LBS/MMBTU
.15 LBS/BHBTU 1
.20 LBS/MMBTU 1
.05 LBS/MMBTU 1
.146 LBS/MMBTU 1
.35 LBS/KMBTU
.098 LBS/MMBTU 1
.13 LBS/HMBTU
.05 LBS/MMBTU 1
.20 LBS/HMBTU 1
.20 LBS/MMBTU 1
.10 LBS/MMBTU 1
30 PPM 1
.13 LBS/MMBTU 1
30 PPM 1
.048 LBS/MMBTU 1
.075 LBS/MMBTU
.10 LBS/MMBTU 1
.165 LBS/MNBTU
.08 LBS/MMBTU 1
.11 LBS/MMBTU
OAF-28
W/FGR
OAF-45
W/FGR
OAF-30
OAF-45
U/FGR
OAF-32
W/FGR
DAF-45
U/FGR
OAF-42
OAF-39
W/FGR
DAF-45
W/FGR
DAF-42
W/FGR
DAF-26
W/FGR
DAF-42
W/FGR
DAF-42
W/FGR
DAF-18
W/FGR
OAF-16.5
U/fGR
OAP-28
U/FGR
OAF-34
W/FGR
DAF-22
U/FGR
DAF-28
DAF-20
C-4
-------
>CH 26, 1993
COEN COMPANY INCORPORATE:
LOU NOx INSTALLATION LIST
Page 3
JOB NO.
3-1757-2
3-1755-1
3-1755-2
3-1754-5
3-1754-4
3-1754-3
3-1754-2
3-1754-1
r-1746-1
3-1740-1
.739-1
3-1 729-1
>1726-1
3-1721-1
2-1719-2
:-1719-1
3-1715-1
3-1712-1
3-1708-1
3-1704-1
3-1703-1
INSTALLATION
Boise Cascade
^uaford, Hi
Norton Salt
Hutehinson, KS
Kalanazoo Psy.
Kalanazoo Psy.
Kalanazoo Psy.
Kalanazoo Psy.
-------
«">CH 26, 1993
COEN COMPANY INCORPORATED
LOW NOx INSTALLATION LIST
Page 4
JOB NO.
;-i702-i
0-1701-1
5-1 694-1
0-1680-1
>167S-1
J-1675-1
0-1674-1
3-1 670-1
0-1663-1
. .o61-3
D-1661-2
5-1661-1
.-16XM
0-1659-1
D-1632-2
5-1632-1
0-1631-1
0-1630-2
5-1630-1
D-1623-1
19-1
INSTALLATION
United Distilers
Louisville, KY
Ford Motor Co.
Sterling Heights, Ml
Ross Labs
Chicago, IL
3N Coapany
Middlevay, UV
General Hills
Cedar Rapids, 1A
Chambers works
Carneys Point, NJ
Monitor Sugar
Bay City, MI
General Mills
So. Chicago, IL
Shintech
F.-eeport, TX
Univ of Calif.
Irvine, CA
Univ of Calif.
Irvine, CA
Univ of Calif.
Irvine, CA
Ohio State Univ.
Athens, Ohio
Gangi Brothers
Riverbanlc, CA
Uayside Honor Rancho
Saugus, CA
Uayside Honor Rancho
Saugus, CA
LA County Mens Jail
Los Angeles, CA
LA County Hens Jail
Los Angeles, CA
LA County Mens Jail
Los Angeles, CA
Marathon Petroleua
SaryviUe, LA
Oupont
Corpus Christi, TX
TYPE OF BOILER
NBC
NS-F-77
uicks
ROP
NBC
NS-F-65
Nebraksa
NS-C-54
Nebraska
NS-C-53
Volcano
UN- 700
Nebraska
NS-G-96-ECON
Nebraska
NS-E-57
Nebraska
NS-E-S7-ECON
Trane
MCF2-38
Nebraska
NS-C-51
B&U
fH-9-57
Keeler
Nebraska
N2S-7-95-ECON
Keeler
OS-10-13
Keeler
OS-10-13
Murray
MCF1-59
Murray
C-18
Murray
C-18
Zurn
Special Keystone
Erie City
Keystone 20M
(NO. Of UNITS)
CAPACITY
(1) 100,000 PPH
(1) 120,000 PPH
<1> 80,000 PPH
(2) 40,000 PPH
CD 40,000 PPH
(1) 72,000 PPH
(2) 150,000 PPH
(1) 60,000 PPH
C2) 60,000 PPH
(1) 30,300 PPH
CD 28,100 PPH
C2> 26,500 PPH
CD 70,000 PPH
CD 150,000 PPH
(1) 50,000 PPH
(1) 50,000 PPH
CD 30,600 PPH
CD 27,500 PPH
CD 27,500 PPH
CD 250,000 PPH
CD 130,000 PPH
FUEL TYPE
Natural Gas
No. 2 oil
No. 6 oil
Natural Gas
No. 2 oil
Natural Sis
No. 2 oil
Natural Gas
No. 2 oil
Natural Gas
No. 2 on
No. 2 oil
Natural Gas
No. 2 oi I
Natural Gas
No. 2 oil
No. 6 oil
Natural Gas
No. 2 oil
Natural Gas
Propane-Air
Natural Gas
Propane-Air
Natural Gas
Propane-Air
Natural Gas
Natural Gas
Propane-Air
Natural Gai
No. 2 oil
Natural Gas
No. 2 oil
Natural Gas
No. 2 oil
Natural Gas
No. 2 oil
Natural Gas
No. 2 oil
Natural Gas
Refinery Gas
Natural Gas
AND/OR ACTUAL
NOx LEVELS
.15 LBS/MMBTU
.20 LBS/MMBTU
.37 LBS/MMBTU
.14 LBS/HMBTU
.14 LBS/KMBTU
.10 LBS/HOBTU
.165 LBS/MMBTU
77 PPM
92 PPM
.171BS/MM8TU
0.10 LBS/MHBTU
.155 LBS/MMBTU
0.10 LBS/MMBTU
0.155 LBS/MMBTU
0.41 LBS/MMBTU
0.06 LBS/MMBTU
.13 LBS/MMBTU
40 PPM
40 PPM
40 PPM
.072 LBS/MMBTU
30 PPM
30 PPM
40 PPM
40 PPM
40 PPM
.123 LBS/MMBTU
0.06 LBS/MMBTU
BURNERS/
BOILER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
METHOD OF
NOX REDUCTION
DAF-32
OAF-28
U/FGR
DAF-28
OAF-22
U/FGR
DAF-22
DAF-30
W/FGR
OAF -36
U/FGR
OAF-26
U/FGR
DAF-26
U/fGR
DAF-20
U/FGR
OAF-20
DAF-18
U/FGR
OAF-28
OAF-39
U/FGR
OAF-26
U/FGR
DAF-26
U/FGR
OAF-20
U/FGR
OAF-20
U/FGR
OAF-20
U/FGR
DAF-36
U/FGR
DAF-36
U/FGR
C-6
-------
-H 26, 1993
COEN COHPANY INCORPORATES
LOU NOx 1NSTALUTJON LIST
Page 5
JOB NO. INSTALLATION
3-1615-1 BASF
Greenville, CM
:-"614-1 Univ. of North Dakota
Grand Forts, NO
3-1613-1 Indeck
Uheeling, IL
?-"612-1 Indeck
wheeling, IL
5-1611-1 Indeck
Wheeling, IL
?--.f!C-i. j-aeci;
Wheeling, IL
D-1609-1 Indeck
Uheeling, IL
5-1608-1 Indeck
wheeling, IL
3-1607-1 Indeck
Wheeling, IL
;-159»-1 Cannoell Souo Co.
Naxten, NC
D-15S6-1 Lockheed
Paltoale, CA
0-1585-1 Harine Corp.
Logistics Base
Sarstov, CA
D-15B4-1 Contadina Foods
Woodland, CA
D-1 578-1 Patton state Hospital
San Bernardino, CA
0-1577-1 Boise Cascade
International Falls, HN
D-1571-1 GUF Hanford Cojen
Hanford, CA
9-1563-1 Indeck Power
Wheeling, IL
0-1562-1 Indect Power
Wheeling, IL
TYPE OF BOILER
BSU
FH 10-66
Nebraska
NS-E-57
Zurn
N2S-7-95
Zurn
Keystone 23H
Zurn
Keystone 22M
Zurn
Keystone 16H
Zurn
Keystone 16H
Zurn
Keystone 16H
Zurn
Keystone 16
Keeler
OS10-22
Nebraska
NS-E-6i -ECON
IBU
TJU-C-25
Nebraska
NS2-7-95-ECON
Nebraska
NSC 42
C.E.
12F48A16
Nebraska
NS-E-65-ECON
Zurn
24H
Zurn
24H
(NO. OF UNITS)
CAPACITY
CO 50,000 PPH
(2) 60,000 PPH
(1) 150,000 PPH
;i) 140,000 PPH
r.) 150,000 PPH
;:,- 95,000 PPH
(1) 95,000 PPH
(1) 95,000 PPH
(1) 95,000 PPH
(1) 100,000 PPH
(1) 75,000 PPH
(3) 25,000 PPH
(1) 150,000 PPH
(1) 30,000 PPH
(2) 250,000 PPH
(1) 68,000 PPH
(1) 250,000 PPH
(1) 250,000 PPH
FUEL TYPE
Natural Gas/
NO. 2 011 cr
uaste Gas/
No. 6 on
Natural Gas
No. 2 on
Natural £is
No. 2 oil
Natural £as
Hydrogen
Natural Sai
No. 2 oil
Natural Gas
No. 2 cu
No. 6 ou
Natural Ga>
No. 2 oil
No. 6 oil
Natural Gas
No. 2 ou
No. 6 oil
Natural Gai
No. 2 oil
Natural Hit
No. 6 oil
Natural Sit
No. 2 oil
Natural Gil
No. 2 ou
Natural ass
Propane-Air
Butane-Air
Natural Gas
Natural Gas
Natural Gas
Natural Gas
No. 2 oil
No. 6 oil
Natural Gas
No. 2 oil
•JA at -^ i
GUARANTEED NO. OF
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.10 LBS/MHBTU 1
0.10 LBS/HHBTU
0.12 LBS/MMBTU 1
0.16 LBS/HHBTU
0.1 LBS/MNBTU 1
0.10 L8S/HMBTU 1
0.1 LBS/HHBTU 1
0.1 LBS/HHBTU 1
0.16 LBS/MMBTU
0.1 LBS/HHBTU 1
0.16 LBS/HHBTU
0.1 LBS/HHBTU 1
0.16 LBS/tlHBTU
0.1 LBS/HHBTU 1
0.147 LB/WMBTU
0.30 LBS/KMSTU 1
0.10 LBS/HHBTU
.048 LBS/MMBTU 1
.076 LBS/MHBTU
40 PPH 1
200 PPH
40 PPH 1
55 PPH
39.4 PPM 1
0.05 LBS/HHBTU 2
30 PPM 1
0.10 LBS/HHBTU 1
0.28 LBS/MHBTU
0.40 LBS/NHBTU
0.10 LBS/NHBTU 1
0.28 LBS/MMBTU
COEN
METHOD OF
NOX REDUCTION
DAF-24
U/FGR
OAF-26
DAF-36
V/FGR
DAF-36
U/FGR
DAF-36
U/FGR
OAF-32
U/FGR
OAF-32
U/FGR
DAF-32
U/FGR
DAF-32
U/FGR
DAF-32
DAF-32
U/FGR
DAF-20
U/FGR
OAF-39
U/FGR
DAF-20
u/ten
OAF-36
U/fSR
OAF-38
U/FGR
DAF-45
U/FGR
DAF-45
U/FGR
C-7
-------
•H 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 6
JOB NO.
D-1 559-1
8-1545-1
3-1545-2
0-1544-1
3-1540-1
3-1540-2
D-1 539-1
5-1538-1
5-1538-2
5-1527-1
D-1525-1
3-1522-1
D-1 520-1
D-1 508-1
9-1498-1
9-1496-1
9-1478-1
INSTALLATION
3M
St. Paul, MN
BYU
Prove, UT
BYU
Prove, UT
Newark Bay Cogen
Newark, NJ
Spreckles Sugar
Hanteca, CA
Spreckles Sugar
Manteca, CA
ASP Tea Company
Columbus, OH
Union Co. Court House
Elizabeth, NJ
Union Co. Court House
Elizabeth, NJ
E.I. Dupont
Sabine, TX
UCLA
Uestwood, CA
Washington Univ.
St. Louis, HO
Okeelanta Sugar
South Bay, FL
Savannah Electric
Power Co.
Savannah, GA
Cedar Sinai Medical Ctr
Los Angeles, CA
Lunday-Thagard Co.
South Gate, CA
Henkel Corporation
Los Angeles, CA
TYPE OF BOILER
Nebraska
N2S-8/S-93-ECON
Volcano
TJU-C-150
Volcano
TJU-C-50
B&U
UIU
NH
CE
25VP12
Uicks
RB
B&U
FM9-43
B&U
FM9-39
CE
VU60
Zurn
keystone
Zurn
Keystone
B&U
FM128-97
ABB Combustion
40AF16/42
MIU
MCF 4-49
BlU
FM1061B
BlU
FM 1061A
(NO. OF UNITS)
CAPACITY
(1) 180,000 PPH
(2) 150,000 HKB
(1) 50,000 MKB
(1) 140,000 PPH
(1) 120,000 PPH
CD 1CO,000 PPH
(1) 65,000 PPH
(D 30,000 PPH
(D 26,000 PPH
(D 260,000 PPH
(1) 160,000 PPH
(D 70,000 PPH
(D 150,000 PPH/
100,000 PPH
(2) 200,000 PPH
(3) 50,000 PPH
(D 48,000 PPH
(1> 40,000 PPH
FUEL TYP;
Natural Gis
NO. 2 Oil
(.017% FEN)
Natural Gas
No. 2 o:.
(0.02% F=N)
Natural Gss
No. 2 oil
(0.02% F=N:
Natural Gis
No. 2 on
Natural £as
No. 2 on
No. 6 on
Natural Gas
No. 2 on
No. 6 01 1
Natural Gss
Landfielo Gas
Natural Gas
No. 6 oil
Natural Gas
No. 6 on
Natural G:s
Natur»'. Css
No. i 11
(.00001% ?=N)
Natural Gas
No. 2 on
No. 2 Oil
(0.1% FES)
Natural Gas
Natural Gas
No. 2 0-:.
(O.OOn ?=.N)
Natural Gas
No. 2 On
Propane/Air
(0.003% ?=N)
Natural Gas
No. 2 on
AND/OR ACTUAL
0.05 LBS/MMBTU
0.11 LBS/MHBTU
0.11 LBS/MMBTU
0.20 LBS/MHBTU
0.09 LBS/MHBTU
0.16 LBS/HHBTU
45 PPM
.0829 LBS/MMBTU
0.30 LBS/MMBTU
0.75 LBS/MMBTU
.082 LBS/HHBTU
0.30 LBS/MMBTU
0.75 LBS/HHBTU
.11 LBS/HHBTU
0.23 LBS/HMBTU
BURNERS/
BOILER
1
1
1
1
1
1 .
1
1
1
i
0.055 LBS/MMBTU 1
0.084 LBS/MMBTU
0.15 LBS/MMBTU
0.2 LBS/MMBTU
0.21 LBS/MMBTU
0.07 LBS/MMBTU
40 PPM
400 PPH
39.9 f PH
30 PPM
33 PPH
30 PPM
400 PPM
1
1
1
1
1
1
METHOD OF
NOX REDUCTION
OAF-42
W/FGR SCROLL
DAF-39
DAF-24
DAF-39
U/FGR
OAF-42
U/FGR
OAF-39
U/FGR
DAF-26
DAF-18
DAF-18
DAF-32
DAF-45
U/FGR
DAF-28
DAF-42
U/FGR
DAF-45
U/FGR
OAF-26
U/FGR
DAF-22
W/FGR
DAF-24
U/FGR
n -=N>
C-8
-------
'.ARCH 26, 1993
COEN COMPANY INCORPORATES
LOU NOx INSTALLATION LIST
Page 7
.06 NO.
3-1469-1
3-1463-1
3-1452-1
3-1437-1
5-1436-1
3-1434-1
3-1425-1
3-1420-1
3-1419-1
3-1399-1
3-1398-1
.03-1
3-1402-1
3-1384-1
3-1376-1
3-1373-1
:-1372-1
3-1365-1
3-1366-1
3-1364-1
>1363-1
3-1362-1
3-1361-1
3-1354-1
INSTALLATION
Santa Monica Hospital
Santa Monica, CA
Campbell Soup Company
Maxton, NC
Shell Western
N. Teerebone, LA
BP Oil
Lima, OH
Metrohealth Med Center
Cleveland, OH
Hunt ing ton Mem. Hosp.
Pasadena, CA
Univ. of Cincinnati
Cincinnati, OH
Uabash Power Equip.
Rental Unit
Uabash Power Equip.
Rental Unit
Old Dominion Electric
Clover, VA
McDonnell Douglas
Long Beach, CA
Hoechst Celane»e
Carlisle, CA
Global Octane
Deer Park, TX
Holman Boiler Works
Rental Unit
Holman Boiler works
Rental Unit
Canners Steam Comoany
Terminal Island, CA
TYPE Of BOILER
Murrey
MCF-2-42
Union Boi ler
"A" MH
Holman
HH
CE
12F40A16/54
Nebraska
NS-E-51-ECON
Bros
U3-35
NBC
N2S-7-107 ECON
CE
35-A-14
NBC
N2S-7-89
CE
34A13
IBU
LFU-20
NBC
NS-E-57
Abco
0 Type
Zurn
Keystone
CE
33A14
UIU
Type H
(NO. OF UNITS)
CAPACITY
(2) 30,000 PPH
CD 100,000 PPH
(1) 85,000 PPH
(1) 225,000 PPH
(1) 50,000 PPH
(3) 28,000 PPH
(2) 150,000 PPH
(4) 150,000 PPH
(3)
(2) 150,000 PPH
(1) 140,000 PPH
(2) 32,000 PPH
(1) 60,000 PPH
(1) 25,000 PPH
(1) 200,000 PPH
(5) 155,000 PPH
C2> 100,000 PPH
fUEL TYPS
Natural Gss
NO. 2 on
(0.001X ?=•.;
Natural Gti
No. 6 Oil
Natural £11
Refinery Gls
Future 0' .
Natural Hit
No. 2 OU
Natural G«s
No. 2 OU
(0.001X fiV
Nature', G»i
No. 2 OU
Natural Hit
No. 2 OU
(OX FBN)
NO. 6 OU
(.25X FBN;
Natural Gas
No. 2 Oil
(OX FBN)
No. 6 OU
C.25Z FE*;
No. 2 OU
Natural Gas
Natural Ess
No. 6 OU
Natural in
Natural Gas
No. 2 Oil
(OX FEN)
(to. 6 Oil
(.25X FBN:
Natural Sis
No. 2 Oil
OX FBN)
No. 6 OU
(.255 FEN!
Natural Gas
No. 6 01.
GUARANTEED NO. OF
AND/OR ACTUAL BURNERS/
NOX LEVELS BOILER
40 PPM 1
40 PPM
1
83.5 PPM 1
.1 LBS/HMBTU 2
0.1 LBS/MMBTU 1
0.2 LBS/HMBTU
40 PPM 1
0.20 LBS/MMBTU 1
(.02% FBN)
0.19 LBS/MMBTU 1
0.20 LBS/MMBTU
0.39 LBS/MMBTU
0.19 LBS/NMBTU 1
0.20 LBS/MMBTU
0.39 LBS/MMBTU
0.23 LB/NMBTU 1
0.048 LB/KMBTU 1
0.10 LB/MMBTU
0.35 LB/MMBTU 1
(0.28 UT X FBN)
0.08 LB/MMBTU 1
0.19 LBS/MHBTU 1
0.20 L8S/NJ1BTU
0.39 LBS/MMBTU
0.19 LBS/MMBTU 1
0.20 LBS/HMBTU
0.39 LBS/MMBTU
0.048 LB/NMBTU 4
(Up to 80,000 PPH)
COEN
METHOD OF
NOX REDUCTION
OAF-22
U/FGR
DAF-32
OAF-34
U/FGR
OAF-36
U/FGR
DAF-24
OAF-20
U/FGR
OAF-36
DAF-42
DAF-42
DAF-42
OAF-J;
U/FGR
OAF-26
OAF-20
U/FGR
DAF-45
U/FGR
OAF-39
U/FGR
OAF-20
C-9
-------
'CH 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 8
.'OS NO.
D-1351-1
5-"35C-1
0-13U-1
0-1343-1
5-1343-2
5-1338-1
5-36-1
5-1333-1
D-1332-2
332-1
0-1331-1
5-1325-1
5-1320-1
5-1J16-1
0-1310-1
5-1305-1
5-1303-1
D-1295-1
INSTALLATION
Procter t Gamble
Oxnard, CA
Monsanto Company
Long Beach, CA
St. Mary's Hospital
Rochester, MN
Mobile Refinery
Sara land, AL
Anitec Cogeneration
Singhanton, NY
Dixie Chemicals
Pasadena, TX
General Electric
Uaterford, NY
Orange County
Santa Ana, CA
Orange County
Santa Ana, CA
E.I. DuPont
Newark, OE
Cape Industries
Uilaington, NC
Uitco Chemical
Oildale, CA
Rohm t Haas
Louisville, KY
Luz Engineering
Boron, CA
Geneva Steel
Ores, UT
Mohawk Rubber
Salem, VA
Indeck Power Rental
TYPE OF BOILER
B&U
FHD-103-B8
BSU
FH9-52
NBC
NS-F-86
Cleaver Brooks
OL-52
Abco
0 Type
NBC
NS-E-57
Zurn
Keystone
Keeler
DS-10-10
NBC
NS-G-70
NBC
NTC-61
B&U
FM 220
Zurn
15M
C.E.
35A14
G.C. Broach
Heater
Zurn
21 M
ABCO
D Type
ZURN
(NO. OF UNITS)
CAPACITY
(1) 80,000 PPH
<1> 25,000 PPH
(3) 80,000 PPH
(2) 40,000 PPH
(1) 104,000 PPH
(1) 60,000 PPH
(1) 250,000 PPH
(1) 38,000 PPH
(1) 70,000 PPH
(1) 40,000 PPH
(1) 205,000 PPH
(1) 80,000 PPH
(2) 180,000 PPH
(12) 53.00 MHBTUH
(2) 100,000 PPH
(1) 65,000 PPH
<3> 250,000 PPH
FUEL TYPE
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Natural Gas
No. 2 OH
Refinery Gas
Natural Gas
No. 2 OU
Natural Gas
Natural Gas
No. 2 OH
No. 6 OU
Natural Gas
No. 2 OH
(0.001% FBN)
Natural Gas
No. 2 OU
Natural Gas
Natural Gas
No. 6 OU
Natural Gas
Propane/Air
Natural Gas
*2 Oil
Haste OU
Natural Gas
Natural Gas
No. 6 Oi I
Coke Oven Gas
Natural Gas
No. 2 OU
Natural Gas
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.05 LB/MMBTU 1
0.048 LB/MNBTU
0.10 LB/MMBTU
(0.01X FBN)
0.15 LB/MMBTU
0.05 LB/MHBTU
0.14 LB/MMBTU
(0.0487. FBN)
0.06 LB/MMBTU
0.10 LB/MMBTU
0.15 LB/MMBTU
0.30 LB/MMBTU
0.04 LB/MMBTU
0.05 LB/MMBTU
0.04 LB/MMBTU
0.05 LB/HMBTU
(0.001% FBN)
0.10 LB/NMBTU
0.20 LB/MMBTU
0.10 LB/MMBTU
0.28 LB/MMBTU
0.20 LB/MMBTU
0.20 LB/MMBTU
0.03 LB/NMBTU
0.1 LB/MMBTU
0.43 LB/MMBTU
0.50 LB/MMBTU
0.20 LB/MHBTU
0.30 LB/NMBTU
0.15 LB/NNBTU
1
1
1
1
1
1
1
1
1
2
1
1
1
1
1
1
METHOD OF
NOX REDUCTION
DAF-32
U/FGR
DAF-28
U/FGR
OAF-32
U/FGR
DAF-24
DAF-34
U/FGR
OAF-26
U/FGR
OAF-45
U/FGR
OAF-22
U/FGR
OAF-30
U/FGR
DAF-24
DAF-32
DAF-30
DAF-42
U/FGR
DAF-30
U/FGR
DAF-32
OAF-26
OAF-45
9-1294-1 24 M
0-1293-1
5-1288-1 Ford Notor Cotpany NBC
Uixom, MI NS-C-43
'286-1 Raneho Loi Amigos H.C. Murray
286-2 Downey, CA H-64E275
(1) .30,000 PPH Natural Gas 0.08 LB/MMBTU 1
OAF-20
(2) 30,000 PPH Natural Gas 0.05 LB/NMBTU 1 OAF-22
No. 2 Oil 0.05 LB/NNBTU U/FGR
(0.001X FBN)
C-10
-------
"•M 26, 1993
COEN COMPANY INCORPORATED
LOU NOX INSTALUTION LIST
Page 9
JOB NO.
0-1284-1
0-1265-2
I-126S-1
0-1255-1
0-1254-1
0-1253-1
0-1252-1
3-1251-1
0-1227-1
0-1226-1
- "»5-i
u i211-1
0-1211-2
0-1210-1
0-1200-1
3-1197-1
S-1 194-1
D-1 183-1
D-1183-2
0-1179-1
0-1178-1
D-1173-1
D-1172-1
0-1171-1
INSTALLATION
University of Iowa
Iowa City, 1A
Ashland Oil
Catlettsburg,
-------
"CH 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 10
JOB NO.
9-1143-1
0-1142-1
0-1141-1
9-1140-1
9-1139-1
5-1131-1
5-1121-1
3-1113-1
3-1112-1
9-1111-1
- '109-1
5-1107-1
5-1100-1
3-1099-1
S-1 090-1
5-1085-4
9-1085-3
9-1085-2
0-1085-1
83-1
INSTALLATION
Indeck Power
(Mobile Unit)
Nabisco Foods
Oxnard, CA
I/N Kote
New Carlise, IN
Univ. of Minnesota
St. Paul HN
San Francisco Int'l
Airport
San Francisco, CA
Ultra Systeas
Alta Vista, VA
Ultra Systems
Southampton, VA
Ashland Oil
Catlettsburg, KY
Ross Laboratories
Columbus, OH
Fulton Cogen
Fulton, NY
Rockwell Int'l
Rocketdyne Division
Canoga Park, CA
NL Cheaieals
Lake Charles, LA
Bunker Hill
Los Angeles, CA
McDonnell Douglas
Hunt ing ton Beach, CA
Century City
Lea Angeles, CA
Bunker Hill
Los Angeles, CA
Boeing Coapany
Auourn, UA
TYPE OF BOILER
NBC
NOS-2-52(S)
ESU
FM 10-79
NBC
NS-E-57
NBC
NS-F-77
IBU
TJU-C-50
NSC
NS-G-88
NBC
NS-E-59
NBC
NS-G-85-ECON
KSC
NS-F-85-ECON
Zurn
13M
Keeler
CS-20
ABCO
D Type
IBU
HTUG
MIU
0 Type
MIU
D Type
IBU
HTUG
Union Riley
A Type
(NO. OF UNITS)
CAPACITY
(4) 75,000 PPH
(D 60,000 PPH
(D 58,400 PPH
CD 79,000 PPH
CD' 50 MMBTUH
CD 122,000 PPH
(D 72,000 PPH
(D 150,000 PPH
(D 80,000 PPH
(2) 62,000 PPH
(D 20,000 PPH
< ) 75,000 PPH
(1) 30 MMBTUH
(1) 25,000 PPH
(1) 112,000 PPH
(1) 30 HHBTU/HR
(1) 140,000 PPH
FUEL TYPE
Natural Gas
No. 2 Oil
Natural Gas
No. 2 Oil
No. 6 OU
Natural Gas
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Tall OH
No. 2 OU
Refi.nery Gas
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Natural Gas
Natural Gas
NO. 2 Oil
Natural Gas
No. 2 Oil
Natural Gas
No. 2 Oil
Natural Gas
No. 2 Oil
Natural Gas
GUARANTEED NO. OF
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.10 LB/NMBTU 1
0.20 LB/HMBTU
(0.01X FBN)
0.05 LB/MMBTU 1
0.046 LB/MMBTU 1
0.075 LB/MMBTU 1
0.14 LB/MMBTU
C0.01X)
0.05 LB/HMBTU 1
0.065 LB/MMBTU 1 "
0.20 LB/MMBTU
0.65 LB/MMBTU 1
0.10 LB/MMBTU
C0.4X FBN)
0.14 LB/MMBTU 1
0.10 LB/MMBTU 1
0.165 LB/HMBTU
(0.01X FBN)
0.168 LB/MMBTU 1
0.183 LB/MMBTU
0.05 LB/MMBTU 1
0.05 LB/MMBTU
(0.001X FBN)
0.10 LB/MMBTU 1
0.05 LB/MMBTU 1
0.05 LB/HHBTU
(0.001X FBN)
0.05 LB/HMBTU 1
0.05 LB/HHBTU
(0.001X FBN)
0.04 LB/MMBTU 1
0.04 LB/MMBTU
C0.001X FBN)
0.05 LB/HHBTU 1
0.05 LB/HHBTU
(0.001Z FBN)
0.10 LB/MMBTU 1
COEN
METHOD OF
NOX REDUCTION
OAF-28
DAF-26
U/FGR
DAF-28
V/FGR
DAF-28
OAF-24
U/FGR
OAF-34
U/FGR
OAF-30
U/FGR
OAF-36
DAF-28
DAF-26
U/FGR
OAF-16.5
U/FGR
OAF-30
OAF-20
U/FGR
OAF-22
U/FGR
OAF-36
U/FGR
OAF-18
U/FGR
OAF-36
C-12
-------
"•-fH 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 11
JOB NO. INSTALLATION
S-1072-1 Metropolitan Airport
D-1072-2 Minneaoolis, UN
3-1069-'1 Chevron
Si. Janes, LA
^•"OM-I NASA Johnion Center
Houston, Texas
:-"!OS9-1 Monitor sugar
Bay City, HI
3-1057-1 General Tire 1 Rubber
Hayfield, KY
r-'OSS-1 Ciba Geigy Corp.
Kclntosh, AL
3-1054-1 Indeck Power
(Rental Unit)
3-1019-1 Shell Offshore Inc.
3-«0/io-2 Hon LOUIS, AL
08-1 Chrysler Corporation
No. Jefferson, MI
;-1007-1 Uellesley College
Uellesley, MA
:-*006-1 Norenco Corporation
ninneaoolis, MM
5-*M5-1 Norenco Cc"»ration
Minneapolis, MN
D-1000-1 J.M. Huber
Etovah, TN
D-0998-1 Indecfc Power
>0997-1 (Mobile units)
0-0996-1
0-0995-1
0-0994-1
5-0993-1
9-0991-1 Occidental Chaaiical
Corpus Christ i, TX
0-0987-1 Cvrtainteed Corp.
Riverside, CA
9-0985-1 General Electric
Ht. Vernon, IN
^-"984-2 Glendale Adventiat
Medical Center
TYPE OF BOILER
BROS
P2-60
CE
25A15
NBC
NS-E-68
NBC
NS-F-88
Murray
MCF6X-94
NBC
NS-E-63 ECON
Zurn
17M
NBC
NS-C-53
IBW
TJU-C-75
NBC
NS-C-56
NBC
NOS-1A-53S
MIU
MCF-5-85
NBC
NS-F-69
Zurn
23M
Zurn
Wicket
A Type
Hi lay Stoker
m
eu
FMG-39
(NO. OF UNITS)
CAPACITY
(3) 40,000 FFH
(3) 150,000 PPH
(1) 80,000 PPH
(1) 120,000 PPH
(1) 125,000 PPH
(1) 70,000 PPH
(1) 90,000 PPH
(2) 40,000 PPH
(3) 87,500 PPH
(1) 45,000 PPH
(1) 36,000 PPH
(1) 115,000 PPH
(1) 88,000 PPH
(6) 150,000 PPH
(1) 190,000 PPH
(1) 35,000 PPH
(1) 150,000 PPH
(1) 23,500 PPH
FUEL TYPE
Natural Gas
No. 6 Oil
Natural Gas
Uaate Oil
Natural Gas
Natural Cas
No. 2 Oil
Natural Gas
NO. 2 Oil
(0.01Z FEN)
Natural Ges
No. 2 on
Natural Gas
Natural Gas
Natural G«s
No. 2 Oil
Natural Gas
No. 6 Oil
Natural Gas
Natural Gas
Natural Gas
No. 2 Oil
Natural Gas
No. 6 Oil
Natural Gas
HydroQCft t NG
Natural Gas
nethanol
Natural Gas
No. 6 Oil
Natural Gas
No. 2 Oil
AND/OR ACTUAL
NOx LEVELS
0.08 LB/NHBTU
0.60 LB/NMBTU
0.06 LB/HMBTU
0.10 LB/MMBTU
0.10 LB/NMBTU
0.10 LB/NHBTU
0.20 LB/MMBTU
C.028X FBN)
0.10 LB/MMBTU
0.24 LB/MMBTU
0.10 LB/MMBTU
0.17 LB/MMBTU
C.01X FBN)
40 PPM
0.10 LB/MHBTU
40 PPM
0.10 LB/MMBTU
0.10 LB/MHBTU
0.10 LB/MHBTU
0.20 LB/NMBTU
0.10 LB/MNBTU
0.12 LB/IMBTU
0.12 LB/HNBTU
BURNERS/
BOILER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.05 HNBTU 1
to max HNBTU
0.10 LB/MHBTU
0.39 LB/MHSTU
C.1SX FBN)
O.OS MMBTU
1
1
METHOD OF
NOX REOUCTION
OAF-22
OAF-39
U/FGR
OAF-28
OAF-34
OAF-36
OAF-28
CAF-30
DAF-22
OAF-28
U/FGR
OAF-24
U/NOX Ports
OAF-20
OAF-34
OAF-28
OAF-36
OAF-4S
U/FGR
BAF-22
1U/FGR
OAF-39
OAF-18
U/FGR
Glanoala, CA
C-13
-------
"'.•« 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page 12
JOB NO.
0-0980-1
0-0979-1
0-0978-1
0-0970-1
0-0969-1
5-0968-1
5-0963-1
0-0962-1
0-0960-1
0-0959-1
0-0958-1
0-0957-1
5-0956-1
9-0955-1
0-0950-1
. J948-3
0-0948-4
5-0941-1
0-0940-1
5-0931-1
0-0926-1
0-0924-1
»-091B-1
9-0916-1
&-0902-1
0-0901-1
INSTALLATION
Quality Assured Packing
Stockton, CA
Kal Kan
Coluabus, OH
Takeda Cheancal
uiliington, NC
Shintech
Freeoort, TX
Great Lakes Steel
Zug Island, MI
Great Lakes Steel
Zug Island, MI
Indeck Power
(Rental Units)
Consolidated Paper
Biron, UI
E.R. Squibb
UwrencevUle, NJ
Eridgestone Tire
La Vergne, TN
SCM Cheaicals
Ashtabula, OH
Pacific Coast Pro.
Lodi, CA
Gay lord Container
Boos lull, LA
IBM
Nanassas, VA
Riley Stoker
Stock Unit
Siapson Paper
Tacoaa, UA
Uabash Power Equip.
Rental Unit
TYPE OF BOILER
NBC
NSE-65
CB
OL-68E
CB
0-34
NBC
NS-E-57
Zurn
23M
Zurn
21M
Zurn
Keystone
B&U
Stirling
B&U
FM 103-70
BSU
FM-10-57
NBC
NS-F-77
BSU
FH106-88
BSU
FM 130-97
IBU
TJU-C-62.5
Riley
MHU
Riley
2 Dru»;
Field Erected
CE
3SA14
(NO. OF UNITS)
CAPACITY
(1) 75,000 PPH
(1) 50,000 PPH
(1) 13,500 PPH
(3) 60,000 PPH
(1) 135,000 PPH
(1) 115,000 PPH
(6) 150,000 PPH
(3) 60,000 PPH
(2) 70,000 PPH
(1) 65,000 PPH
d) ioc,:ro PPH
(1) 120,000 PPH
(1) 165,000 PPH
(1) 62.5 HHBTU
(1) 200,000 MHBTU
(2) 300 HMBTU Gas
290 HHBTU 01 1
(2) 150,000 PPH
FUEL TYPE
Natural Gas
Natural Gas
12 Oil
«6 OU
Natural Gai
Natural (Us
Natural Gai
Natural Gai
Natural Ges
Kerosene
Natural Gas
Natural Gas
No. 2 OU
Natural Gas
No. 2 OU
Natural Gas
No. 6 Oil
Natural Gas
Natural Gas
Natural Gas
No. 2 CU
No. 6 Oil
Natural Gas
No. 2 OU
(OX FBN)
No. 6 On
(.25X FBN)
ANO/OR ACTUAL
NOX LEVELS
40 PPM
0.065 LB/MNBTU
85 Tons/Year
(.35X FBN)
0.09 LB/MMBTU
0.10 LB/MMBTU
0.10 LB/MMBTU
0.10 LB/HMBTU
0.10 LB/MMBTU
0.11 LB/MMBTU
0.068 LB/MMBTU
0.10 LB/MMBTU
0.03 LB/MMBTU
0.25 LB/MMBTU
(.032 FBN)
0.05 LB/MMBTU
0.29 LB/MMBTU
C.15X FBN)
0.12 LB/MMBTU
BACT
0.20 LB/MMBTU
0.10 LB/MMBTU
0.19 LBS/MMBTU
0.20 LBS /HHBTU
0.39 LBS/MMBTU
BURNERS/
BOILER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
METHOD OF
NOX REDUCTION
OAF-28
OAF-24
OAF-15
U/NOx Ports
OAF-26
OAF-36
OAF-34
DAF-36
OAF-2B
DAF-28
DAF-26
OAF-34
U/FGR
OAF-36
U/FGR
OAF-39
OAF-26
OAF-42
OAF-39
OAF-42
C-14
-------
"-CH 26, 1993
COEN COMPANY INCORPORATED
LOU NOx INSTALLATION LIST
Page
JOB NO. INSTALLATION
D-0900-1 Desert Hospital
Palm Springs, CA
9-0892-1 E.R. Squibb ( Sons
New Brunswick, NJ
3-0886-1 Minnesota Power Corp.
0-0874-1 Louisiana State Univ.
Baton Rouge, LA
5-0867-1 Gangi Bros.
aiverbank, CA
0-0866-1 Holun Boiler works
S-0865-1 Rental Unit
5-0862-1 »rito Lay
Nodeato, CA
9-0857-1 Nekoosa Paoer
Ashdown, AR
. j349-1 Spreckels Sugar
Mendota, CA
0-0846-1 Uabash Power
0-0841-1 Rental Unit
D-08AO-1 Indeck Power
D-0839-1 Rental Unit
S-0838-1
0-0837-1
0-0836-1 Indeek Power
9-0832-1 Rental Unit
0-0831-1
0-0829-1 Coluefcia Nitrogen
Augusta, 6A
0-0825-1 Holman Boiler
Rental Unit
n-iS20-1 Soltex polymers
Deer Park, TX
TYPE OF BOILER
Trane/Murray
0-Type
NBC
NS F 13-ECON
CE
12F40A16
NBC
NS-F-77-ECON
NBC
NSE-65
CE
35A14
NBC
NSB-41
CE
*3 Bark/Gas Power
Boiler
CE
VU60
NBC
N2S-7-89
NBC
NOS-1A-53S
Zurn
Keystone
Zurn
Keystone 23M
NBC
N25-7-95
NBC
NS-F-77
(NO. OF UNITS)
CAPACITY
(1) 30,000 PPH
(2) 95,000 PPH
(2) 250,000 PPH
<1) 100,000 PPH
(2) 75,000 PPH
12) 150,000 PPH
(1> 25,000 PPH
<1) 520,000 PPH
(1) 250,000 PPH
(1) 150,000 PPH
(4) 40,000 PPH
(3) 150,000 PPH
Derated
(1) 150,000 PPH
<1> 150,000 PPH
(1) 100,000 PPH
fUEL TYPE
Natural Gas
Oil
Natural Gas
NO. 2 on
No. 6 OH
Natural Gas
Natural Gas
Natural Gai
Natural Gas
No. 2 OU
No. t OU
Natural Gas
Natural Gas
Gas
NO. 2 on
NO. 6 on
Natural Gas
No. 2 Oil
No. 6 Oil
Natural Gas
No. 2 Oil
No. 6 Oil
Natural Gas
No. 6 Oil
Natural Gas
No. 6 Oil
Natural Gas
No. 2 Oil
No. 6 Oil
Natural Gas
ANO/OR ACTUAL
NOx LEVELS
40 PPM
0.10 L8/IW8TU
0.30 LB/MMBTU
(.IX FBN)
0.05 IB/NM8TU
0.12 LB/MMBTU
30 PPM
0.20 LB/MHBTU
0.20 LB/MMBTU
(0.01X FBN)
0.40 LB/MMBTU
(0.2SX FBN)
40 PPM
0.10 LB/MMBTU
0.085 LB/MMBTU
0.25 LB/MMBTU
0.55 LB/nMBTU
0.20 LBS';-.MBrj
0.20 LBS/w:?VU
(0.01X FBN)
0.4 LBS/MHBTU
(0.2X FBN)
0.10 LBS/HMBTU
0.20 LBS/HMBTU
(0.01X FBN)
0.40 LBS/HMBTU
(0.20X FBN)
0.05 LB/HHBTU
0.20 LB/HMBTU
0.20 LB/MMBTU
0.30 LB/MMBTU
(0.2X FBN)
0.10 LBS/HHBTU
BURNERS/
BOILER
1
1
2
1
1
1
1
4
4
1
1
1
1
1
1
METHOD OF
NOX REDUCTION
OAF-20
U/FGR
OAF-30
OAF-36
OAF-32
DAF-2S
W/FGR
DAF-39
OAF-18
DAF-36
OAF-30
U/FGR
DAF-42
OAF-22
DAF-36
W/FGR
OAF-36
OAF-39
Front Will
NOx Ports
OAF-32
C-15
-------
—'CM 26, 1993
COEN COMPANY INCORPORATED
LOW NOx INSTALLATION LIST
Page 14
JOB NO.
S-0804-1
1-0799-1
S-0791-1
9-0785-1
J-0779-1
5-0768-2
J-0768-1
9-0766-1
5-0765-1
9-0764-1
•52-1
. J751-1
S-074S-1
9-0747- *
0-0745-1
0-0721-1
9-0715-1
9-0700-1
0-0700-2
INSTALLATION
Caafaria Cog«n. Fac.
Ebenataurg, PA
San Diego 6as I Etect.
San Diego, CA
Areo Alaska, Inc.
Prudhoe Bay, AK
A.E. Staley
Decatur, IL
3H Coapany
Hutchinson, UN
Ogden Martin Systeas
Laurence, MA
Ogden Martin Systems
Lawrence, HA
Ho loan Boiler
Indeek Power
1
£.1. Dupont
New Johnsonvi lie, TN
O'Brien Energy Systems
Par I in, NJ
Aooco Chemical
Clute, TX
Indeek Power
Boiaa Caaeade Corp.
Int. Falls, MN
Union Texas Petroleua
Union Texas Petraleusi
TYPE OF BOILER
NBC
NSE-65
BSV
FK10-70B
Breach
Heater
Riley
RX
NBC
NS-E-68
B&U
F22 SPLAH15
CE
30VP-12
CE
35A14
Zurn
24*
asu
FH120-97
ABCO
Special
OPF
Cabin Heater
Zurn
23M
Zurn-
Keystone
Vogt
OT-113-105
CE
27VP14
(NO. OF UNITS)
CAPACITY
CD 78,000 PPH
C2) 50,000 PPH
CD 35,000 NNBTU
(1) 125,000 PPH
CD 80,000 PPH
CD 100,000 PPH
:D 115,000 PPH
(3) 150,000 PPH
(2) 250,000 PPH
CD 150,000 PPH
!D 177,000 PPH
(D 30. ANN BTU/HR
.".) 150,000 PPH
C2> 180,000 PPH
(1) 100,000 PPH
'
(1) 150,000 PPH
•
FUEL TYPE
Natural 6tt
Natural Gas
No. 2 Oil
Gas
Natural Gas
Natural Ges
No. 6 OH
Natural Gas
No. 6 Oil
Natural Ges
No. 6 Oi i
Natural Gss
No. 2 Oil
No. 6 OU
Natural Gas
No. 2 OU
No. 6 OU
Natural G:s
No. 2 Oil
Natural Gas
No. 2 OU
Natural Gas
Natural Gas
No. 2 OU
No. 6 Oil
Natural Gat
Natural Gas
Off Gas
Mixture
Natural Gas
Off Gas
Mixture
MO /OR ACTUAL BURNERS/
NOX LEVELS BOILER
0.10 LB/HM8TU 1
0.10 LBS/MMBTU 1
0.08 LB/HMBTU 1
0.10 LBS/MMBTU 1
0.20 LB/MKBTU 1
0.40 LB/JfMBTU
(.3* FBN)
BACT 1
BACT 1
"
0.20 L8S/MHBTU 1
0.20 LBS/MNBTU
(0.01Z FBN)
0.30 LBS/MHBTU
(0.2X FBN)
0.10 LBS/MMBTU 1
0.28 LBS/MNBTU
C0.01Z FBN)
0.40 LBS/MMBTU
(0.14X FBN)
0.08 LB/MNBTU 1
0.20 LB/NMBTU
C.01X FBN)
0.20 LBS/HMBTU 1
0.20 LBS/MNBTU
(0.01X FBN)
0.08 LB/NMBTU 1
0.10 LB/MMBTU 1
0.20 LB/MMBTU
CO. 011 FBN)
0.40 LB/MMBTU
CO. 302 FBN)
0.05 LBS/NHBTU 1
0.08 LBS/HMBTU 1
0.12 LB/MMBTU
0.10 LBS/NMBTU
0.08 LBS/MMBTU 1
0.12 LB/MMBTU
0.10 LBS/HNBTU
METHOD OF
NOX REDUCTION
DAF-28
CAF-24
DAF-22
DAF-32
OAF-30
OAF-36
DAF-36
OAF-39
OAF-45S
DAF-39
OAF-39
DAF-18
DAF-36
DAF-42
U/FGR
DAF-34
OAF-39
C-16
-------
MUCH 26, 1993
COEN COMPANY INCORPORATE:
LOU NOx INSTALLATION LlS"
Page 15
JOB NO.
0-0698-1
0-0688-1
D-0687-1
0-0681-1
0-0679-1
0-0674-1
0-0673-1
0-0672-1
0-0671-1
0-0668-1
0-O661-1
.458-1
0-0657-1
0-0639-1
0-0638-1
0-0637-1
0-0636-1
0-0635-1
0-0634-1
0-0631-1
0-0630-1
0-0627-1
0-0626-1
INSTALLATION
Boeing - Plant II
Seattle, UA
Kal Kan
Vernon, CA
Vickaburg Chemical
vieksburg, HS
Indeck Power
Uhiteman AFB
Knob Noster, MO
Indeck Power
Union Texas Petroleum
Geisur, LA
Willamette Industries
Bennett svi lie, SC
Salinas Supply Corp.
Salinas, CA
Folgers Coffee Co.
Sherun, TX
uabash
Indeck Power
Darling Delaware
Vernon, Calif.
Shell Sarnia
Ontario, Canada
Indeck Power
Chevron
St. JIMS, LA
Monsanto Envir. Chen
Brademon, FL
TYPE OF BOILER
CB
OL094E
B&U
FM1 01-88
FU
AG51SOB
Nebraska
NOS-2-67
NBC
NS-E-58
Nebraska
NOS-2-67
2urn
Keystone
CE
12F33A/B
NBC
NS-E-68-SH
CE
25-A-12
CE
35AU
Nebraska
NOS-2-52(S)
Nebraska
N2S-6-69
CE
35A14
Nebraska
NOS-2-52CS)
CE
12F35A16/42"
BSU
FM1 17-88
(NO
(2,
(1)
(1)
C,)
(1)
;i)
(D
(1)
(1)
(1)
(2)
(3!
CD
(D
CD
CD
(1)
. CF UNITS)
OPACITY
80,000 PPH
75,000 PPH
'.53,000 PPH
75,000 PPH
60,000 PPH
75,000 PPH
2:0,000 PPH
221,500 PPH
65,000 PPH
75,000 PPH
150,000 PPH
75,000 PPH
53,000 PPH
150,000 PPH
75,000 PPH
250,000 PPH
120,000 PPH
FUEL '"=
Natura.
No. 6 I'
Nature;
Propane
Nature.
Nature;
No. c Z-
No. 2 :•
Nature.
Nature.
No. 2 :•
Nature.
Off Ces
Nature;
Nature.
Nature;
Natura;
No. 2 :•
No. 6 C-
Nature.
No. 2 C-
Nature.
Nature;
No. 2 C:
No. 6 C-.
Nature;
No. 2 :•
Natura.
Process
Nature.
No. 2 C-
in
in
in
3es
3as
-•es
in
in
in
in
in
in
in
in
itt
3is
JSS
in
:"
AND/OR ACTUAL
0.10 LB/MHBTU
0.30 LB/HMBTU
(0.15% FBN)
0.05 LBS/MHBTU
0.07 LBS/MMBTU
0.20 LBS/KHBTU
0.10 LBS/HHBTU
0.20 LBS/MMBTU
(o.on FBN)
0.12 LBS/MHBTU
(0.01% FBN)
0.14 LBS MHBTU
0 10 LBS/MNBTU
0.20 LBS/MMBTU
(0.01% FBN)
0.10 LB/MMBTU
0.10 LB/MMBTU
0.20 LB/HHBTU
0.065 LB/MHBTU
0.10 LBS/HHBTU
0.19 LBS/MMBTU
0.20 LBS/HnBTU
(0.01% FBN)
0.40 LBS/HMBTU
(0.25% FBN)
0.10 LBS/HMBTU
0.20 LBS/MMBTU
(0.01% FBN)
40 PPM
0.20 LBS/MMBTU
0.20 LBS/MBBTU
(0.01% FBN)
0.40 LBS/HMBTU
(0.25% FBN)
0.10 LBS/WBTU
0.20 LBS/MHBTU
(0.01X FBN)
0.099 LB/HMBTU
0.05 LBS/HHBTU
0.10 LBS/NMBTU
(.05% FBN)
BURNERS/
BOILER
1
1
1
1
1
1
1
2
1
1
1
1
•
1
1
2
1
METHOD OF
NOX REDUCTION
OAF-30
OAF -26
U/FGR
OAF-42
OAF-28
DAF-26
DAF-28
DAF-45
DAF-34
DAF-26
OAF-28
DAF-42
DAF-28
DAF-30
OAF-42
DAF-28
OAF-36
U/FGR
DAF-39
C-17
-------
•«H 26, 1993
COEN COMPANY INCORPORATE
LOU NOx INSTALLATION Lli~
Page 16
JOB NO.
D-0620-1
5-0615-1
5-0603-1
5-0599-1
3-0595-1
5-0591-1
3-0589-1
S-0589-2
.,-0588-1
:-OSB8-2
5-0585-1
5-0581-1
ft-0577-1
6-0573-1
:-0571-1
9-0569-1
5-0566-1
0-0564-1
5-0564-2
'62-1
INSTALUTION
E.I. oupont
Delisle, HS
Arizona Chetrical Co.
?anaaa City, FL
Dow Cheat ca I
Midland, HI
Peru Municipal util.
Peru, IL
Royal Tallow
San Francisco, CA
Ashland Petroleun
St. Paul, HH
City of MuntsvHle
Huntsville, AL
City of Hunisville
Hunt »vi tie, AL
Hopeuell Cogeneration
Hopevell, VA
New England Submarine
Base
Groton, CT
S.O. Warren
HinHey, HE
Consolidated Paper
Stevens Point, UI
McClellan AFB
Sacraaento, CA
Harter Packing
Yuba City, CA
McDonnell Douglas
Ontario, Canada
Quwmm Ethyltne
Deer-park, TX
U.S. Aroy
Military Ac«de«y
Uest Point, NY
Occidental Clinical
lake Charles, LA
TYPE OF BOILER
B&U
FH 120-97
ce
35A14
NSC
NS-i-58
Zurn
FIELD ERECTED
NBC
NS-E-52
Vertical
Heater
NBC
NSF-84SH
NBC
NS-F-84SH
BSU
Special FH
!3U
VSG 36.5
BSU
FH 10-79
CE
33A13/48"
NBC
NS-B-44
NBC
NSE 68
NBC
N2S-7-89
CE
34VP14/48"
Keeler
Zurn
(NO. OF UNITS)
CAPACITY
(1) 180,000 PPH
(1) 125,000 PPH
(2) 60,000 PPH
(1) 105,000 PPH '
CD 50,000 PPH
CD 120 HHBTU
(2) 100,000 PPH
C2) 100,000 PPH
(2) 180,000 PPH
(1) 84,150 PPH
(1) 60,000 PPH
CD 140,000 PPH
(3) 25,000 PPH
(D 80,000 PPH
(1) 150,000 PPH
(2) 160,000 PPH
(2) 200,000 PPH
(1) 245 HMBTU
FUEL TY°:
Natural J;i
No. 2 0-.
Natural -";:
Pitcn Te-:t-es
Natural :;•
Natural ;•: =
No. I 0- .
Natural 2:5
No. I S- .
H2 Uzste
Llghl/hej. .
OH
Natural 2is
No. i C-.
Natural J*i
LanafU: :>i
No. 2 0:.
Natural 2:s
No. 2 0-..
No. 50-.
Ho. 2 01.
Natural :•.'.
Natural :n
No. 2 a- .
No. 50-.
Natural :ss
No. 6 0-..
Natural 3is
No. c 0:.
Natural ;:;
No. 6 0:.
Natural 3i:
Tall gas
SUARANTEED NO. OF
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.086 LB/HHBTU 1
0.20 LS/nHBTU
(.005% FBN)
1
0.07 LB/nMBTU 1
0.10 LB/HHBTU 2
0.20 L5/HHBTU
40 PPM 1
Various 1
0.10 LB/HHBTU 1
0.10 LB/HHBTU
(0.01X FBN)
0.10 LB/HHBTU 1
0.10 LB/HHBTU
0.10 LB/HHBTU
(O.OW FBN)
0.10 LB/HHBTU 1
0.10 L8/HHBTU
(0.02X FBI)
0.20 LB/HHBTU 2
(0.3% f6N)
0.148 LB/HHBTU 1
(.04% FBN)
0.10 LB/HHBTU 1
40 PPH 1
115 PPH
(0.102 FBN)
40 PPH 1
0.20 LB/HHBTU 1
0.20 LE/HHBTU
co.on FBN)
0.10 LB/MHBTU 1
0.30 LB/HHBTU 4
(0.35% FBN)
0.10 LB/HHBTU 1
0.10 LB/HHBTU
COEN
METHOD OF
NOX REDUCTION
DAF-42
OAF-36
DAF-24
DAF-26
OAF-26
W/FGR
DAF-32
DAF-36
U/FGR
DAF-36
U/FGR
DAF-42
U/FGR
DAF-22
u/Front wall
NOx Ports
DAF-24
OAF-36
DAF-18
U/FGR
OAF-30
U/FGR
OAF-42
DAF-45
DA2-25 U/
Floor NOx
Ports
CAF-45
U/FGR
C-18
-------
1ARCH 26, 1993
COIN COMPANY INCORPORATE:
LOU NOx INSTALLATION L1S"
Page 17
JOB NO. INSTALLATION
5-0560-1 Stauffer Cheecial
Doiinguez, CA
5-0557-1 Ragu Foods
Stockton, CA
3-0550-1 Canners Steal Company
Terminal Island, CA
5-0530-1 Standard Rendering
Houston, TX
5-0521-1 General Electric
Mt. vemon, IN
5-0513-1 L.A. County Landfill
SPAORA Project
J-0478-1 Siopson Papaer
,'-0478-2 Pasaoena, TX
5-0475-1 Janes River Paper
Hilfore, KJ
;-043T-1 Arco
Crane, TX
X23-1 (.uz-SESS 11
Saggett, CA
5-0397-1 San Joaguin Hi Ik Prod.
Turloct, CA
5-0389-1 Mobil 011 Corp.
HcKittricic, CA
5-0384-1 Indiana University
alooiington, IN
3-0376-1 Coluabia university
5-0375-1 New rork, NY
5-0374-1
3-0367-2 Inland Steel
New Carlisle, IN
: -0367-1 inland Steel
New Carlisle, IN
5-0358-2 Harrison Radiator
Dayton, OH
5-0358-1 Harrison Radiator
Dayton, OH
'46-1 General Electric
Burkville, AL
TYPE OF BOILER
Zurn
NBC
N2S-7-89-ECON
Union Iron
Uorks
NBC
NS-0-54
NBC
N2S-S-114
Zurn
Keystone
Zurn
23M
NBC
N2S-7-97SH
Wickes
90-3K-8
CE/Mitsubishi
NBC
NSC-61 ECON
Struthers
Thereof lood Htr.
UIU
Field Erected
BSU
FH103-88
ERI/N8C
Waste Heat Blr.
NBC
NSE-57
C.E. "A" Type
33-7ICT-10
C.E. "A" Type
96-4KT-S
Nebraska
N2S-109
(NO. OF UNITS)
CAPACITY
CD 40 PPH
CD 150,000 PPH
CD 100 K PPH
(1) 50,000 PPM
CD 200,000 PPH
(1) 110 MMBTU
(2) 150,000 PPH
CD 120,000 PPH
C2) 100,000 PPH
CD 190 HMBTU
Per Burner
C2) 50,000 PPH
CD 62.5 MNBTJ
CD 75,000 PPH
(3) 88,000 PPH
CD 124.3 MHBTU
CD 58,400 PPH
(1) 200,000 PPH
C2> 120,000 PPH
CD 200,000 PPH
FUEl **»=
Natural 3as
Natural £33
Natural 5«
Ho. t C-.
Natural Hi
No. 2 C-. .
Nature, ^ss
Ural:'.: in
Natural in
Natural in
NO. £ ;• .
Natural Us
Natural ;ss
Uaste C-.
CO. 03': ?=•.;
Natural 2it
No. 2 ::.
No. 5 Ci.
Natural 3as
Nature. 3ss
NO. 2 :-.
Natural 3:s
NO. t -• .
Natural ::s
Natural :::
Natural Sit
NO. 2 :• .
Natural :-as
No. 2 C:.
Nature1. :n
GUARANTEED NO. OF
AND /OR ACTUAL BURNERS/
NOx LEVELS BOILER
70 PPH 1
40 PPH 1
40 PPH «,
0.12 LB/MHBTU 1
0.16 LB/MHBTU
C0.01Z FBN)
0.20 LB/MBBTU 1
24 PPH 1
0.10 LB/HMBTU 1
33.3 PPM 1
31.9 PPM
CO. 04* FBN)
0.20 LB/HNBTU 1
80 PPH 2
70 PPM 1
84 PPM
C0.045X FBN)
1
0.10 LB/MMBTU 2
0.10 LB/W1BTU
C.05% FBN)
0.10 LB/HNBTU 1
0.30 LB/HNBTU
C0.3X FBN)
0.05 LB/HHBTU 1
40 PPH 1
0.20 LB/HHBTU 1
0.30 LB/HHBTU
C0.05X FBN)
0.20 LB/HHBTU 1
0.30 LB/HMBTU
C0.05X FBN)
0.20 LB/HHBTU 1
COEN
HETHOD OF
NOX REDUCTION
DAF-24
DAF-36
U/FGR
BAF-20
U/ FGR
OAF-25
OAF -42
OAF-36
U/FGR
DAF-36
DAF-36
OAF-36
DAF-39
DAF-24
DAF-24
U/FGR
DAF-28
DAF-26
U/Front uall
NOx Ports
OAF-32
OAF-2S
DAF-39
DAF-36
DAF-42
C-19
-------
"ARCH 26, 1993
MEN COMPANY INCORPORATE:
LOU NOx INSTALLATION US'
Page 18
JOB NO.
0-0345-1
0-0342-1
0-0332-1
0-0324-4
0-0324-3
C-0324-2
S-0324-1
>94-1
0-0286-2
0-0286-1
5-0284-1
5-0283-1
0-0282-1
D-0281-1
B-0280-1
INSTALLATION
General Electric
Burkville, AL
Ueatinghouse electric
Sunnyvale, CA
E t J Gallo Uinery
Modesto, CA
Sun Oil Comoany
Yabucoa, Puerto Rico
Sun Oi I Ccooany
Yabucoa, Puerto Rico
Sun Oil Company
Yabucoa, Puerto Rico
Sun Oil Comoany
Yabucoa, Puerto Rico
SOHIO oil Company
Toledo, OH
Mobil Oil Co.
Torrance, CA
Mobil oil Co.
Torrance, CA
Holman Boiler Uorks
Dallas, TX
(Rental)
Ho lean Boiler Uorks
(Rental)
Holian Boiler Works
(Rental)
Ho lean Boiler Works
(Rental)
TYPE OF BOILER
Nebraska
NS-E-68
Zurn
Field Erected
Boiler
Nebraska
NSF-84
Zurn
20M
B&U
FM 117-97
B&U
FH 106-79
Nebraska
NSF-82
B&U
CO Boiler
ECIU
BSU
PFI-3161
Zurn
19M
UIU
"A"
Nebraska
N2S-7-113SH
Nebraska
N2S-7-95
(NO
CD
CD
(1)
CD
CD
CD
CD
CD
180
CD
565
CD
460
(1)
(1)
(1)
12)
. OF UNITS)
CAPACITY
85,500 PPH
300,000
115,000
115,000
150,000
100,000
100,000
450,000
•F Air
200,000
*F Air
220,000
'F Air
100,000
100,000
150,000
150,000
PPH
PPH
PPH
PPH
PPH
PPH
PPH
PPH •
PPH
PPH
PPH
PPH
PPH
FUEL TY°:
Natural its
No. 2 0-.
Natural fas
Natural Its
No. 6 0-..
Refinery Sis
Pitch
Refinery 3es
Pitcfl
Refinery Jjs
Pitch
Refinery Sss
Pitch
Refinery cis
Refinery :-sj/
No. 6 0-.
Natural/
Refinery 3as
Natural/
Refinery «a$
Natural JM
No. 2 Oi.
No. 6 0-.
Natural :ss
No. 2 Ci.
No. 6 0-..
Natural GM
No. 2 0-..
No. 6 Oi.
Natural jjs
No. 2 0-..
No. 6 Oi.
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.20 LB/MMBTU 1
0.20 LB/MMBTU
CO. 01X FBN)
40 PPM
0.10 LB/MMBTU
0.20 XB/MMBTU
CO. 22 FBN)
0.43 LB/MMBTU
(1.08% FBN)
0.43 LB/MMBTU
0.082 FBN)
0.43 LB/MMBTU
C1.08% FBN)
0.43 LB/MMBTU
(1.08% FBN)
0.10 LB/NMBTU
0.157 LB/MMBTU
CO. 35% FBN)
0.095 LB/MMBTU
0.12 LB/MMBTU
0.20 L/MMBTU
0.20 LB/MMBTU
0.30 LB/HMBTU
CO. 22 FBN)
0.20 LB/NMBTU
0.20 LB/NMBTU
0.30 LB/NMBTU
CO. 22 FBN)
0.20 LB/MMBTU
0.20 LB/MMBTU
0.30 LB/NMBTU
(0.2% FBN)
0.20 LB/MMBTU
0.20 LB/MMBTU
0.30 LB/HM8TU
CO. 22 FBN)
2
1
1
1
1
1
6
4
3
1
1
1
1
METHOD OF
NOX REDUCTION
OAF-30
OAF-39
U/FSR
DAF-30
U/Front Uall
NOx Ports
DAF-34
U/Front Uali
NOx Ports
OAF-36
U/Front Wall
NOx Ports
OAF-30
U/Front Uall
NOx Ports
OAF-30
U/Front Uall
NOx Ports
OAF-30
OAF-28
OAF-26
OAF-32
U/Front Uall
NOx Ports
OAF-36
u/Front uall
NOx Ports
OAF-39
u/Front Uall
NOx Ports
OAF-39
u/Front Uall
NOx Ports
0-0274-1 Ponderay Newsprint Nebraska
usk, UA N2S-7-112
(1) 180,000 PPH
Propane
0.20 LBS/MMBTU
OAF-36
C-20
-------
*«RCH 26, 1993
COEN COMPANY INCORPORATE:
LOU NOX INSTALLATION L:S~
Page 15
JOB NO.
3-0268-1
•3-0267-2
3-0267-1
0-0243-2
:-0243-1
3-0226-1
"- 1225-1
D-0207-1
S-0161-1
D-0123-1
3-0121-1
5-0064-1
3-0036-1
3-9995-1
3-9961-2
>«S61-1
INSTALLATION
Quality Assured
Packing
Stockton, CA
Hoffman La Roche
Belvidere, NJ
Hoffman La Roche
Belvidere, NJ
Newsorint Soutn
Grenaoa, MS
Newsorint South
Grenada, MS
Takeae Chemical Co.
uilmington, NC
Takeda Chemical Co.
Wilmington, NC
Kolman Boiler Uorks
Dallas, TX
Georgia Pacific
Port Hudson, LA
Aner. 1 Co-Gen Project
King City, CA
Caaobell Soup Company
f.axton, NC
Reynolds Metals
Gregory, TX
Union Oil Company
Wilmington, CA
Detroit Editon
Detroit, MI
Pantex Power Plant
Amarillo, TX
Pentex Power Plant
Amarillo, TX
TYPE 0« BOILER
B&U
FM 10-52A
B&U
FM 117-576
CE
A Type
S&U F-1-1 17-88
Keen-
MMETU Steam
Generator
Nebraska
NS-E-25
Nebraska
NS-F-67
lurn
23-M
C.E.
35A14
Nebraska
NSF-E7
Nebraska
FU
Zurn
B&U
FM 120-971
B&U
FM 9-39
B&U
FM 10-66
(NO. OF UNITS)
CAPACITY
(1) 30,000 PPH
(1) 142,000 PPH
6CO'.= Air
!1) 70,000 PPH
350'F Air
(1) 135,000 PPH
(V, 200,000 PPH
;") '3,500 PPH
(1) 90,000 PPH
(1) '.50,000 PPH
(1) 150,000 PPH
(2) 136.5 MMBTU
132.2 MMBTU
(1) 150,000 PPH
(1) 360,000 PPH
(1) 150,000 PPH
(1! "50,000 PPH
(2) 25,000 PPH
1
(2) 50,000 PPH
FUEL ~VB?
Natural ;ss
No. 2 :•;
Natural Sas
OH
Natural Gas
No. 6 Oil
Natural 3as
Natural 32s
No. 6 C-.
No. 6 Oil
Natural 32s
*2/*6 Oi .
Natural 3:s
Natural 5is
No. 2 Oi.
Natural Jss
No. 2 Oi.
No. 6 0-..
T.E.G.
Refinery Sas
Natural Jss
Gas ana
No. 2 C-.
Gas ano
No. 2 0-.
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILED
40 PPM 1
70 PPM
(0.012 FBN)
0.68 LB/MMBTU 1
0.90 LB/MMBTU
(0.3% FBN)
0.28 LB/HMBTU 1
0.52 LB/MMBTU
(0.3% FBN))
0.20 LB/MMBTU 1
0.20 LBS/MMBTU 2
at 135,000 PPH
85 Tons/Year 1
sasea upon
average load of
85 MMBTU/HR,
both boi lers
operating
continuously
85 Tons/Year 1
based upon
average loao of
85 MMBTU/HR,
both boi lers
operating
continuously
0.20 LB/MMBTU 1
0.40 LB/MMBTU
(0.25X FBN)
0.10 LBS/MMBTU 1
40 PPM 1
69 PPM
0.20 LB/MMBTU 1
0.20 LB/MMBTU
0.40 LB/HMBTU
0.06 LBS/MMBTU 6
(50 PPM)
0.10 LBS/MMBTU 1
0.10 LBS/MMBTU 1
0.12 LBS/MMBTU 1
0.12 LBS/MMBTU 1
METHOD OF
NOX REDUCTION
OAF-20
OAF-36
DAF-J6
OAF-36
OAF-36
OAF-15
OAF-26
U/Front uall
NOx Ports
DAF-42
OAF-35
U/FGR
OAF-34
U/FGS
DAF-34
u/Sioe wall
NOx Pc-tS
DAF-3''
FGR
DAF-42
OAF-18
OAF-24
C-21
-------
MARCH 26, 1993
COEN COflPANY INCORPORATE:
LOU NOx INSTALLATION LIST
Page 20
JOB NO.
0-9958-1
0-9915-1
0-9915-2
0-9912-1
0-9912-2
0-9911-1
0-9879-1
0-9851-1
0-9834-1
0-9821-1
-798-1
0-9792-1
0-9728-1
0-9716-1
0-9706-1
0-9697-1
0-9645-3
0-9645-2
0-9645-1
0-9591-2
0-9570-1
61-1
INSTALLATION
New York Hospital
New York, NY
CamarUlo Hospital
Camarillo, CA
Chino Cogeneration
Chino, CA
V.A. Hospital
Kansas City, HO
Union 01 1 Company
Of California
Uilmngton, CA
V.A. Medical Center
Cincinnati, OH
Minnesota Power and
Light Company
Ouluth, MN
Chevron U.S.A.
El Segundo, CA
Tinker Air Force Base
Oklahoma City, OK
Coyote Canyon
LFS Project
Orange County, CA
Shell Western
Sharadon, TX
Newport Naval
Newport, RI
Gi Iroy Foods
Gilroy, CA
L.A. County
Sanitation District
Carson, CA
U.C. Berkeley
Berkeley, CA
U.C. Berkeley
Berkeley, CA
Shepard Oil
Jennings, LA
Commonwealth Edison
Chicago, IL
Boise Cascade
Deridder, LA
TYPE OF BOILER
MU
FN 117-97B
B&U
FN10-52
B&U
FH10-52
C.E.
6 (VU1C016A
C.E.
35A15
Titusville
3 Drum
Zurn
Field Erectea
C.E.
12F40A16
Nebraska
N2T-7-93
Zurn
Zurn
23M Keystone
Nebraska
NS-F-87-SHCS)
Nebraska
NSE-68
B&U
FM-10-57
Union Iron works
Zurn
Nebraska Boiler
N2S789
Nebraska Boiler
NS-F-82
Babcock I uilcox
FM-1 20-97
(NO. OF UNITS)
CAPACITY
CD
(2)
(2)
C2>
(1)
C3>
CD
CD
CD
CD
CD
CD
C2>
CD
CD
(1>
CD
CD
C2>
125,000 PPH
25,000 PPH
25,000 PPH
15,500 PPH
•200,030 PPH
24,000 PPH
120 HMBTU
381.2 MMSTU
114,000 PPH
255.86 MflBTU
150,000 PPH
90,000 PPH
86,890 PPH
44,000 PPH
65 NMBTuY
Per Burner
43.3 MH8TU/
Per Burner
150,000 PPH
110,000 PPH
165,000 PPH
No. 6 0-..
Natural Gas
No. 2 01.
Natural Gas
No. 2 On
Natural G2S
No. 2 Oi.
Refinerv Ges
No. 6 01 L
Natural Gas
No. i ov.
Gas
Natural Gas
Refinery Gas
Gas ana
No. 2 OiL
Landfill Sa
Natural Ges
Gas ana
No. 5 OiL
Natural Gi>
No. 2 Oil
Gas
(Oil Eack.c,
Gas ana C- .
Gas and 0' .
No. 6 Oi.
No. 2 Oil
Natural Gss
Natural Gas
GUARANTEED NO. OF
AND/OR ACTUAL BURNERS/
NOx LEVELS BOILER
0.40 LBS/NN8TU 1
(0.5% FBN)
40 PPM 1
115 PPM
(0.06X FBN)
40 PPH 1
115 PPM
(0.06% FBN)
0.10 LBS/MMBTU 1
0.30 LBS/HMBTU
0.12 LBS/MMBTU 1
0.35 LBS/MMBTU
C0.25X FBN)
0.10 LBS/MMBTU 1
0.3 LBS/MMBTU
0.20 LBS/HMBTU 4
0.10 LBS/MMBTU 2
0.10 LBS/MMBTU 1
48 PPM (Vol. 2
Dry Ref, 3X 02)
0.10 LBS/MMBTU 1
0.10 LBS/MMBTJ 1
0.30 LBS/MHBTU
C0.23X FBN)
40 PPM (Vol. 1
Dry Ref. 3X 02)
45 PPM (Vol. 1
Sry Ref. 3X 02)
SACT 2
SACT 3
0.10 LBS/NHBTU 1
No Requirements
79 PPM (Vol. 1
Dry Ref. 3Z 02)
83 PPM (Vol. 1
Ory Ref. 3X 02)
COEN
METHOD OF
NOX REDUCTION
OAF-30
U/Side wall
NOx Ports
OAF-18
OAF-18
FGR
FOR
FOR
DAF-34
FGR
FGR
FGR
FGR
FGR
FGR
FGR
OAF-26
DAF-22
OAF-36
U/FGR
FGR
FGR
C-22
-------
-•ARCH 26, 1993
COEN CCIPANY INCORPORATE:
LOU NO* INSTALLATION LIST
rage 21
JOB NO. INSTALLATION
9-9425-1 Los Angeles Sanitation
District
0-9351-1 Occidental Petroleum
Lake Charles, LA
D-9293-1 Integrated Protein
Corona, CA
5-9279-1 Paladale A.F.B.
Paladale, CA
5-9252-1 Frito Lay
Bakersfield, CA
D-9203-1 ISM
San Jose, CA
D-9140-1 Stanislaus* Foods
Modesto, CA
D-9002-1 Union Oil
Santa Maria, CA
:-S943 Pfizer
Groton, CT
5-8879 Leetronelt
Longview, TX
5-8811 City o-f Hope
Durante, CA
0-8795 Murphy Oil
Meraux, LA
9-8523 Mobil oil
Joliet, '.'-
0-8439 Arco
North Slope, AK
5-8365 uillaaette Industries
Port Huenegte, CA
0-8327 !nd. Valley Energy Co.
Bakersfield, CA
9-8233 Shell Oil
uoodriver, IL
9-7829 University of Wyoaing
Laraiie, UY
3-6348 Texas A and M
College Station, TX
D-4935 Phillips Petroleum
Kansas City, KS
•XPORT Electricite De France
Paris, France
-vor Of BOILER
Zjrn Keystone
Type '0'
:.E.
33-A-16
Nebraska
NS-C-42
:sw TJU
(HTHW)
BaDcock fi Ui Icox
=1-10-79
Cleaver Brooks
B-60
•Jesraska
NS-G-101
\eoraska
NSF-91
Ssbcock £ Uilcox
'."-140-97
\eoraska
NS-C-49
Nebraska
\S-E-75SH
Nebraska
KS-E-64
C.H. VU-60
'.'•tertube
G.C. Broach
(Giycol Heater)
Nebraska
«-E-555H
teccock & Ui Icox
FW-9-57B
Si ley Stoker
Field Erected
-atertube
ZS'J Cross Orui
batertube
Vect CL-VS-P
uatertube
Vogt CL-VS-P
uatertube
Sabcock & Ui Icox
Watertube
(HO. OF UNITS;
CSPACIT^
(2) 264,000 P=H
(330 MMSTJ)
C2! 180,000 fPH
(268 MKSTU)
(2) 30,000 fSH
(36 MMSTV)
(2) 23 MMBT.'
(Input)
(1) 62,000 »=-
(78 MMET.;
(1) 36,000 e=-
(45 MMSTl)
(1) '00,000 «•>
(162 Mrs-J)
C13 100,000 F=-
(127 MH5TU)
(1) '95,000 ?=u
(250 HKBTU)
<1> 30,000 P»H
(39 MHSTU)
(1) 55,000 f=H
C70 MH5TU)
(1) 80,000 P="
(100 fl«ETJ)
(1) 400,000 M"
(576 MKBTiJ)
(2) 73.7 MMBTU
(1) 68,200 P=-
(99 HMBTj;
(1) 20,000 PPH
(26 MMBTU)
(1) 250,000 PPH
(384 MMBTU)
(3) Natural Gas
C77 MMBTU)
(1) 300,000 PPH
C42S MMBTU)
(1) 300,000 PPH
(425 MflBTU)
(1) 528,000 F?H
Land Fit. in
(420BTU/F7'
Natural dss
Natural Gas
NO. 2 on
Natural GSJ
No. 2 On
Natural C:s
Future ;2 C-.
Natural <3is
No. 2 0-.
Natural :*s
No. 6 Oil
Natural Ges
No. 2 Oi.
No. 6 0:.
Natural G;s
No. 2 On
Natural in
NO. 2 On
Refinery 5ss
Natural Gas
Refinery ces
No. 6 01.
Natural Gss
Natural Sis
No. 2 0:.
Refinery In
Natural C:s
Refinery 3ss
No. 6 Oi.
Ref. »•«-.
Oil
Refinery c
-------
FABER BURNER — LOW-NOX BURNER PROJECTS
40 ppm OR LESS — FIRING NATURAL GAS
Tampella Power
Williamsport, PA
International Business Machines
San Jose, CA
Formosa Plastics Co.
Point Comfort, TX
Miller Brewing Co.
Irwindale, CA
Veterans Administration Medical Center
Sheridan, WY
Veterans Administration Medical Center
Los Angeles, CA
Veterans Administration Medical Center
Des Moines, IA
General Motors Proving Grounds
Milford, MI
Armstrong World Industries
South Gate, CA
Nationwide Boiler Co.
Fremont, CA
Canadian Forces Base
Halifax, Nova Scotia
Hershey Chocolate
Hershey, PA
Kimberly Clark
Fullerton, CA
Farmer John
Vernon, CA
3M Corporation
Camarillo, CA
Georgia Pacific
Buena Park, CA
Medical Center Co.
Cleveland, OH
Sunkist Growers
Ontario, CA
Luzerne County
Wilkes-Barre, PA
Quantity
1
1
2
3
4
1
1
1
2
2
1
2
1
3
1
3
2
1
1
1
3
Boiler
capacity
17,500 pph
36,000 pph
35,000 pph
55,000 pph
50,000 pph
12,500 pph
45,000 pph
20,000 pph
15,000 pph
50,000 pph
9,000 pph
75,000 pph
60,000 pph
(No. 6 oil)
40,000 pph
40,000 pph
23,000 pph
12,000 pph
30,000 pph
22,000 pph
30,000 pph
100,000 pph
40,000 pph
17,500 pph
Boiler manufacturer
TP — Package
TP — Package
TP — Package
TP — Package
TP —CP
B&W - Package
B&W — Package
(1) B&W - Package
(1) TP — Package
TP —CP
Nebraska — Package
TP — Package
TP — Package
B&W — Package
(1) CE — Marine
(2) B&W - Package
Nebraska — Package
Trane — Package
TP — Package
Nebraska — Package
B&W — Package
TP — Package
C-24
-------
APPENDIX D. SCALED COST EFFECTIVENESS VALUES
The following tables present cost effectiveness figures for the cost cases analyzed in
Chapter 6 and listed in Table 6-4. These costs are based on the annual costs calculated in
Appendices E, F, and G for 46 different boiler, fuel, and NOX control combinations. To estimate
cost effectiveness for the boiler capacities listed in this appendix, which in most cases differ from
the actual capacities of the 42 boilers cases, the logarithmic relationship known as the "six-tenths"
power rule was used (Reference 5 of Chapter 6). Cost estimates for distillate- and residual
oil-firing were based on the annual costs of natural gas-fired boilers calculated in Appendix E, using
appropriate baseline NOX emission values and fuel prices.
This appendix contains the following tables:
Cost Case Page
Natural-gas-fired:
Packaged watertube, 45 MMBtu/hr, with WI and O2 trim D-3
Packaged firetube, 10.5 MMBtu/hr, with WI and O2 trim . D-3
Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB D-4
Packaged watertube, 265 MMBtu/hr, with LNB and CEM D-5
Packaged watertube, 17.7 and 41.3 MMBtu/hr, with LNB and FOR D-5
Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FOR D-6
Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FOR, and CEM D-7
Packaged firetube, 2.9-33.5 MMBtu/hr, with FOR and O2 trim D-8
Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-9
Field-erected wall-fired, 75 MMBtu/hr, with BOOS and O2 trim D-10
Field-erected wall-fired, 75 MMBtu/hr, with BOOS, WI, and O2 trim D-10
Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB * D-ll
Distillate-oil-fired:
Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB D-12
Packaged watertube, 265 MMBtu/hr, with LNB and CEM D-13
Packaged watertube, 17.7 and 41.3 MMBtu/hr, with LNB and FOR D-13
Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FOR D-14
Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FOR, and CEM D-15
Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-16
Packaged firetube, 2.9-335 MMBtu/hr, with FOR and O2 trim D-17
Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-17
D-l
-------
Cost Case Page
Residual-oil-fired:
Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB D-18
Packaged watertube, 265 MMBtu/hr, with LNB and CEM D-19
Packaged watertube, 17.7 and 41.3 MMBtu/hr, with LNB and FOR D-19
Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FOR D-20
Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FOR, and CEM D-21
Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-22
Packaged firetube, 2.9-33.5 MMBtu/hr, with FOR and O2 trim D-23
Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-23
Coal-fired:
Field-erected wall-fired, 766 MMBtu/hr, with LNB D-24
Circulating FBC, 460 MMBtu/hr, with urea-based SNCR D-24
Tangentially-fired, with SCR D-25
Field-erected wall-fired, 800 MMBtu/hr, with ammonia-based SNCR D-25
Wall-fired, 400 MMBtu/hr, with SNCR D-26
Spreader stoker, 303 MMBtu/hr, with urea-based SNCR D-26
Wood-fired:
Stoker, 190, 225, and 300 MMBtu/hr, with urea-based SNCR D-27
Stoker, 395 and 500 MMBtu/hr, with urea-based SNCR D-28
Bubbling FBC, 250 MMBtu/hr, with ammonia-based SNCR ' D-28
Paper-fired:
Packaged watertube, 72 and 172 MMBtu/hr, with urea-based SNCR D-29
MSW-fired:
Stoker, 108, 121, and 325 MMBtu/hr, with urea-based SNCR D-30
D-2
-------
SCALED COST EFFECTIVENESS, S/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube( single burner)
NOx CONTROL: WATER INJECTION WITH OXYGEN TRIM
REFERENCE COST BASE: COLANNINO, 1993; 45 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$855
$718
$642
$520
$496
$354
0.66
$963
$797
$705
$565
$536
$380
0.5
$1,161
$941
$820
$648
$610
$427
0.33
$1,581
$1,247
$1,064
$823
$765
$529
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged firetube
NOx CONTROL: WATER INJECTION WITH OXYGEN TRIM
REFERENCE COST BASE: COLANNINO, 1993; 10.5MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
2.9
5.2
10.5
20.9
33.5
CAPACITY FACTOR
0.8
$3,620
$3,130
$2,674
<2,335
$2,152
0.66
$4,192
$3,598
$3,045
$2,635
$2,413
0.5
$5,238
$4,454
$3,724
$3,183
$2,889
0.33
$7,461
$6,274
$5,168
$4,348
$3,903
D-3
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: California ARB, 1987; 51 MMBtu/hr
c8|M?Y
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$816
$594
$473
$338
$300
$195
0.66
$989
$720
$573
$410
$364
$236
0.5
$1,306
$950
$756
$541
$480
$312
0.33
$1,978
$1,440
$1,146
$820
$727
$472
SCALED COST EFFECTIVENESS/ $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: California ARB, 1987; 75 MMBtu/hr
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
6.8
$2,126
$1,538
$1,217
$865
$763
$493
0.66
$2,577
$1,865
$1,475
$1,048
$925
$597
0.5
$3,402
$2,461
$1,947
$1,384
$1,221
$788
0.33
$5,154
$3,729
$2,950
$2,097
$1,851
$1,194
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas | BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
dHfflr
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,690
$1,916
$1,493
$1,041
$908
$576
0.66
$3,261
$2,322
$1,809
$1,262
$1,100
$698
0.5
$4,304
$3,066
$2,388
$1,666
$1,452
$921
0.33
$6,522
$4,645
$3,618
$2,525
$2,201
$1,395
D-4
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged water-tube
NOx CONTROL: LNB with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$4,462
$3,178
$2,475
$1,727
$1,506
$955
0.66
$5,408
$3,852
$3,000
$2,094
$1,825
$1,157
0.5
$7,139
$5,084
$3,961
$2,764
$2,409
$1,527
0.33
$10,816
$7,703
$6,001
$4,187
$3,650
$2,314
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 17.7 MMBtu/hr
£»
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,101
$1,523
$1,208
$861
$761
$492
0.66
$2,625
$1,925
$1,542
$1,112
$992
$649
0.5
$3,582
$2,658
$2,153
$1,573
$1,413
$934
0.33
$5,617
$4,217
$3,451
$2,552
$2,310
$1,542
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas | BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: Impell Corp., 1989; 41.3 MMBtu/hr
xftkO^* 4 •» *
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$4,624
$3,302
$2,575
$1,805
$1,576
$1,002
0.66
$5,686
$4,083
$3,206
$2,259
$1,982
$1,269
0.5
$7,627
$5,511
$4,354
$3,090
$2,725
$1,756
0.33
$11,752
$8,546
$6,792
$4,856
$4,302
$2,791
D-5
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged water-tube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 45 MMBtu/hr
C»Y
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,895
$2,041
51,574
$1,085
$937
$587
0.66
$3,586
$2,552
$1,986
$1,384
$1,205
$763
0.5
$4,852
$3,486
$2,739
$1,931
$1,696
$1,086
0.33
$7,541
$5,471
$4,339
$3,095
$2,737
$1,772
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas | BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 55 MMBtu/hr
BOILER
ateci!Y
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$4,560
$3,238
$2,516
$1,749
$1,521
$961
0.66
$5,605
$4,003
$3,127
$2,190
$1,913
$1,217
0.5
$7,516
$5,402
$4,246
$2,995
$2,630
$1,685
0.33
$11,577
$8,374
$6,622
$4,706
$4,153
$2,680
SCALED COST EFFECTIVENESS, S/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
CAPACITY
UUD + 1 1 7 L* M
HnBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,985
$2,024
$1,499
$978
$812
$479
0.66
$3,696
$2,531
$1,895
$1,255
$1,054
$632
0.5
$4,996
$3,459
$2,619
$1,761
$1,496
$913
0.33
$7,759
$5,431
$4,157
$2,837
$2,435
$1,510
D-6
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: Impell Corp., 1989; 81.3 MMBtu/hr
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$5,455
$3,852
$2,975
$2,053
$1,776
$1,114
0.66
$6,692
$4,748
$3,685
$2,559
$2,223
$1,403
0.5
$8,953
$6,387
$4,984
$3,484
$3,041
$1,932
0.33
$13,758
$9,870
$7,743
$5,451
$4,779
$3,056
SCALED COST EFFECTIVENESS, S/TON NOx REMOVED
FUEL: natural gas | BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 91 MMBtu/hr
eBttHr
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$11,804
$8,515
$6,717
$4,759
$4,191
$2,696
0.66
$14,386
$10,400
$8,219
$5,837
$5,14P
$3,320
0.5
$19,107
$13,845
$10,967
$7,810
$6,902
$4,461
0.33
$29,139
$21,167
$16,807
$12,002
$10,625
$6,886
SCALED COST EFFECTIVENESS, 5/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$4,459
$3,074
$2,317
$1,549
$1,310
$794
0.66
$5,483
$3,804
$2,886
$1,947
$1,657
$1,015
0.5
$7,355
$5,140
$3,928
$2,675
$2,292
$1,418
0.33
$11,334
$7,977
$6,140
$4,221
$3,641
$2,275
D-7
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged firetube
NOx CONTROL: FGR with oxygen trim
REFERENCE COST BASE: Hugh Dean, 1988; 2.9-33.5 MMBtu/hr
cffitffr
MMBtu/hr
2.9
5.2
10.5
20.9
33.5
CAPACITY FACTOR
0.8
$21,741
$12,304
$6,410
$3,651
$2,404
0.66
$26,572
$15,159
$7,974
$4,518
$2,998
0.5
$35,406
$20,380
$10,834
$6,103
$4,083
0.33
$54,179
$31,475
$16,912
$9,471
$6,390
D-8
-------
SCALED COST EFFECTIVENESS, J/TON NOx REMOVED
FUEL: natural gas (BOILER: packaged water-tube
NOx CONTROL: SCR
REFERENCE COST BASE: Peerless, 1992; 50-250 MMBtu/hr
BOILER
riPflrlTY
kflrnLl 1 T
MMBtu/hr
10
25
50
100
150
200
250
CAPACITY FACTOR
0.8
$6,112
$4,741
$3,991
$2,516
$2,223
$1,563
$1,498
0.66
$7,396
$5,734
$4,825
$3,040
$2,686
$1,888
$1,810
0.5
$9,744
$7,551
$6,351
$3,999
$3,531
$2,483
$2,380
0.33
$14,734
$11,410
$9,592
$6,037
$5,329
$3,746
$3,590
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas | BOILER: packaged watertube
NOx CONTROL: SCR
REFERENCE COST BASE: Damon, 1987; 100 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$6,303
$5,007
$4,299
$3,344
$3,120
$2,164
0.66
$7,640
$6,070
$5,210
$4,053
$3,782
$2,623
0.5
$10,085
$8,012
$6,878
$5,350
$4,992
$3,462
0.33
$15,280
$12,139
$10,421
$8,105
$7,563
$5,245
D-9
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas |BOILER: field erected wall fired
NOx CONTROL: BOOS WITH OXYGEN TRIM
REFERENCE COST BASE: COLANNINO, 1993; 75 MMBtu/hr
BOILER
MMBtu/hr
100
250
400
500
750
CAPACITY FACTOR
0.8
$394
$260
$197
$193
$139
0.66
$435
$284
$214
$209
$150
0.5
$510
$327
$244
$237
$169
0.33
$670
$418
$308
$297
$210
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas [BOILER: field erected wall fired
NOx CONTROL: BOOS AND WATER INJECTION WITH OXYGEN TRIM
REFERENCE COST BASE: COLANNINO, 1993; 75 MMBtu/hr
BOILER
rAPAfTTY
MMBtu/hr
100
250
400
500
750
CAPACITY FACTOR
0.8
$714
$503
$392
$388
$286
0.66
$753
$525
$408
$403
$296
0.5
$823
$565
$436
$429
$314
0.33
$972
$650
$495
$485
$352
D-10
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas (BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 590 MMBtu/hr
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$2,498
$1,707
$1,586
$1,393
0.66
$3,028
$2,069
$1,923
$1,689
0.5
$3,996
$2,730
$2,538
$2,229
0.33
$6,055
$4,137
$3,845
$3,377
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: natural gas |BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 1300 MMBtu/hr
£»
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
.0.8
$3,880
$2,632
$2,437
$2,125
0.66
$4,703
$3,190
$2,954
$2,575
0.5
$6,208
$4,211
$3,899
$3,399
0.33
$9,406
$6,381
$5,908
$5,151
D-ll
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged water-tube
NOx CONTROL: LNB
REFERENCE COST BASE: California ARB, 1987; 51 MMBtu/hr
dP*S»
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$653
$475
$378
$304
$270
$234
0.66
$791
$576
$458
$369
$327
$283
0.5
$1,044
$760
$605
$457
$432
$374
0.33
$1,582
$1,152
$917
$738
$655
$567
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: California ARB, 1987; 75 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,701
$1,231
$973
$778
$687
$591
0.66
$2,062
$1,492
$1,180
$944
$833
$717
0.5
$2,721
$1,969
$1,557
$1,245
$1,099
$946
0.33
$4,123
$2,983
$2,360
$1,887
$1,666
$1,433
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
£6SACiIY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,152
$1,533
$1,194
$937
$817
$691
0.66
$2,609
$1,858
$1,447
$1,136
$990
$837
0.5
$3,443
$2,452
$1,910
$1,500
$1,307
$1,105
0.33
$5,217
$3,716
$2,895
$2,272
$1,981
$1,674
D-12
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged water-tube
NOx CONTROL: LNB with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MHBtu/hr
c)ffi?Y
m&Hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$3,569
$2,542
$1,980
$1,554
$1,355
$1,146
0.66
$4,326
$3,081
$2,400
$1,884
$1,642
$1,389
0.5
$5,711
$4,067
$3,168
$2,487
$2,168
$1,833
0.33
$8,653
$6,163
$4,801
$3,768
$3,285
$2,777
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged water-tube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 17.7 MMBtu/hr
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,481
$1,019
$766
$574
$485
$391
0.66
$1,900
$1,340
$1,033
$801
$692
$578
0.5
$2,666
$1,927
$1,522
$1,216
$1,072
$921
0.33
$4,294
$3,174
$2,561
$2,097
$1,879
$1,651
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: Impel! Corp, 1989; 41.3 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
0.8
$3,500
$2,442
$1,863
$1,424
$1,219
$1,003
0.66
$4,349
$3,066
$2,365
$1,833
$1,584
$1,323
0.5
$5,902
$4,209
$3,283
$2,581
$2,252
$1,907
0.33
$9,202
$6,637
$5,234
$4,170
$3,672
$3,149
D-13
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil | BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 45 HMBtu/hr
BOILER
CAPACITY
HMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,116
$1,433
$1,059
$776
$643
$504
0.66
$2,669
$1,841
$1,389
$1,046
$885
$716
0.5
$3,681
$2,589
$1,991
$1,538
$1,326
$1,103
0.33
$5,833
$4,177
$3,272
$2,585
$2,264
$1,926
SCALED COST EFFECTIVENESS, 5/TON NOx REROVED
FUEL: distillate oil IBOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 55 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$3,448
$2,391
$1,813
$1,374
$1,169
$954
0.66
$4,284
$3,003
$2,302
$1,771
$1,522
$1,261
0.5
$5,813
$4,122
$3,197
$2,496
$2,157
$1,822
0.33
$9,062
$6,499
$5,098
$4,036
$3,538
$3,016
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,188
$1,419
$999
$680
$531
$374
0.66
$2,757
• $1,825
$1,316
$930
$749
$559
0.5
$3,797
$2,567
$1,895
$1,385
$1,146
$896
0.33
$6,007
$4,144
$3,126
$2,353
$1,991
$1,612
D-14
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LN6 and FGR with CEM system
REFERENCE COST BASE: Impell Corp., 1989; 81.3 MMBtu/hr
BOILER
NK$&
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$4,164
$2,881
$2,180
$1,648
$1,399
$1,137
0.66
$5,154
$3,598
$2,748
$2,103
$1,801
$1,484
0.5
$6,962
$4,910
$3,787
$2,936
$2,537
$2,119
0.33
$16,806
$7,696
$5,995
$4,706
$4,101
$3,467
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 91 MMBtu/hr
cPf?Y
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$9,243
$6,612
$5,173
$4,083
$3,572
$3,036
0.66
$11,309
$8,120
$6,376
$5,054
$4,434
$3,784
0.5
$15,086
$10,876
$8,574
$6,829
$6,011
$5,153
0.33
$23,111
$16,734
$13,245
$10,602
$9,363
$8,063
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
»
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$3,367
$2,259
$1,653
$1,194
$979
$753
0.66
$4,187
$2,844
$2,109
. $1,552
$1,291
$1,018
0.5
$5,684
$3,912
$2,942
$2,207
$1,863
$1,501
0.33
$8,867
$6,181
$4,712
$3,599
$3,077
$2,530
D-15
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil (BOILER: packaged watertube
NOx CONTROL: SCR
REFERENCE COST BASE: Peerless, 1992; 50-250 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
200
250
CAPACITY FACTOR
0.8
$4,890
$3,793
$3,193
$2,265
$2,001
$1,876
$1,798
0.66
$5,917
$4,588
$3,860
$2,736
$2,417
$2,266
. $2,172
0.5
$7,795
$6,041
$5,081
$3,599
$3,178
$2,979
$2,855
0.33
$11,787
$9,128
$7,674
$5,433
$4,796
$4,495
$4,308
.SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil
BOILER: packaged watertube
NOx CONTROL: SCR
REFERENCE COST BASE: Damon, 1987; 100 MMBtu/hr
cMv
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$5,043
$4,006
$3,439
$3,009
$2,808
$2,596
0.66
$6,112
$4,856
$4,168
$3,647
$3,403
$3,147
0.5
$8,068
$6,409
$5,502
$4,815
$4,492
$4,154
0.33
$12,224
$9,711
$8,337
$7,295
$6,807
$6,294
D-16
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil | BOILER: packaged firetube
NOx CONTROL: FGR with oxygen trim
REFERENCE COST BASE: Hugh Dean, 1988; 2.9-33.5 MMBtu/hr
m
2.9
5.2
10.5
20.9
33.5
CAPACITY FACTOR
0.8
$12,744
$7,083
$3,546
$1,891
$1,143
0.66
$15,643
$8,796
$4,485
$2,411
$1,499
0.5
$20,944
$11,928
$6,201
$3,362
$2,150
0.33
$32,207
$18,585
$9,847
$5,383
$3,534
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: distillate oil |BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 590 MMBtu/hr
BOILER
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$2,997
$2,560
$2,379
$2,090
0.66
$3,633
$3,103
$2,884
$2,533
0.5
$4,796
$4,096
$3,807
$3,343
0.33
$7,266
$6,206
$5,768
$5,066
SCALED COST EFFECTIVENESS, $/TON NOx RFKOVED
FUEL: distillate oil (BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 1300 MMBtu/hr
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$4,656
$3,948
$3,656
$3,187
0.66
$5,644
$4,785
$4,431
$3,863
0.5
$7,450
$6,317
$5,849
$5,099
0.33 .
$11,287
$9,571
$8,862
$7,726
D-17
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil | BOILER: packaged water-tube
NOx CONTROL: LNB
REFERENCE COST BASE: California ARB, 1987; 51 MMBtu/hr
BOILER
SfiE^m
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$344
$250
$199
$160
$142
$123
0.66
$416
$303
$241
$194
$172
$149
0.5
$550
$400
$318
$256
$227
$197
0.33
$833
$606
$482
$388
$344
$298
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE:. California ARB, 1987; 75 MMBtu/hr
sEsJ^Jv
MMBtu/nr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$895
$648
$512
$410
$362
$311
0.66
$1,085
$785
$621
$497
$438
$377
0.5
$1,432
$1,036
$820
$656
$579
$498
0.33
$2,170
$1,570
$1,242
$993
$877
$754
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil | BOILER: packaged watertube
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
S»
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,133
$807
$628
$493
$430
$364
0.66
$1,373
$978
$762
$598
$521
$441
0.5
$1,812
$1,291
$1,005
$789
$688
$582
0.33
$2,746
$1,956
$1,523
$1,196
$1,042
$881
D-18
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,879
$1,338
$1,042
$818
$713
$603
0.66
$2,277
$1,622
$1,263
$992
.$864
$731
0.5
$3,006
$2,141
$1,668
$1,309
$1,141
$965
0.33
$4,554
$3,244
$2,527
$1,983
$1,729
$1,462
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 17.7 MMBtu/hr
£»
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$997
$754
$621
$520
$473
$423
0.66
$1,217
$923
$761
$639
$582
$522
0.5
$1,621
$1,231
$1,019
$857
$782
$702
0.33
$2,477
$1,888
$1,565
$1,321
$1,206
$1,086
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: Impel! Corp., 1989; 41.3 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,059
$1,503
$1,198
$967
$859
$745
0.66
$2,506
$1,831
$1,462
$1,182
$1,051
$914
0.5
$3,324
$2,433
$1,945
$1,576
$1,403
$1,221
0.33
$5,060
$3,710
$2,972
$2,412
$2,150
$1,875
D-19
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 45 HMBtu/hr
sW
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,331
$972
$775
$626
$556
$483
0.66
$1,622
$1,187
$948
$768
$683
$594
0.5
$2,155
$1,580
$1,266
$1,027
$915
$798
0.33
$3,287
$2,416
$1,939
$1,578
$1,409
$1,231
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: California ARB, 1987; 55 MMBtu/hr
BOILER
£ftSAcl!Y
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,032
$1,476
$1,172
$941
$833
$719
0.66
$2,472
$1,798
$1,429
$1,150
$1,C?9
$881
0.5
$3,277
$2,387
$1,900
$1,531
$1,358
$1,177
0.33
$4,987
$3,638
$2,901
$2,342
$2,080
$1,805
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
Sfi&RJY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,369
$965
$743
$576
$497
$415
0.66
$1,668
$1,178
$910
$707
$612
$512
0.5
$2,216
$1,569-
$1,215
$947
$821
$689
0.33
$3,379
$2,399
$1,863
$1,456
$1,266
$1,066
D-20
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: Impel! Corp., 1989; 81.3 MMBtu/hr
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,409
$1,734
$1,365
$1,085
$954
$816
0.66
$2,930
$2,111
$1,664
$1,324
$1,166
$999
0.5
$3,882
$2,802
$2,211
$1,763
$1,553
$1,333
0.33
$5,905
$4,268
$3,373
$2,694
$2,376
$2,042
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 91 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$5,082
$3,698
$2,940
$2,366
$2,097
$1,815
0.66
$6,169
$4,491
$3,573
$2,877
$2,551
$2,209
0.5
$8,157
$5,942
$4,730
$3,812
$3,381
$2,930
0.33
$12,381
$9,025
$7,189
$5,797
$5,145
$4,461
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: LNB and FGR with CEM system
REFERENCE COST BASE: CIBO, 1992; 265 MMBtu/hr
BOILER
mfa
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,990.
$1,407
$1,088
$846
$733
$614
0.66
$2,421
$1,714
$1,328
$1,035
$897
$753
0.5
$3,209
$2,276
$1,766
$1,379
$1,198
$1,008
0.33
$4,885
$3,471
$2,698
$2,112
$1,837
$1,549
D-21
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: SCR
REFERENCE COST BASE: Peerless, 1992; 50-250 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
200
250
CAPACITY FACTOR
0.8
$2,574
$1,996
$1,681
$1,192
$1,053
$987
$946
0.66
$3,114
$2,415
$2,032
$1,440
$1,272
$1,193
, $1,143
0.5
$4,103
$3,179
$2,674
$1,894
$1,673
$1,568
$1,503
0.33
$6,204
$4,804
$4,039
$2,860
$2,524
$2,366
$2,267
. SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged watertube
NOx CONTROL: SCR
REFERENCE COST BASE: Damon, 1987; 100 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,654
$2,108
$1,810
$1,584
$1,478
$1,367
0.66
$3,217
$2,556
$2,194
$1,920
$1,791
$1,656
0.5
$4,246
$3,373
$2,896
$2,534
$2,364
$2,186
0.33
$6,434
$5,111
$4,388
$3,839
$3,583
$3,313
D-22
-------
SCALElTCOsf EFFECTIVENESS, I/TON NOx REMOVED
FUEL: residual oil (BOILER: packaged flretube
NOx CONTROL: FGR with oxygen trim
REFERENCE COST BASE: Hugh Dean, 1988; 2.9-33.5 MMBtu/hr
?QIUR
rfiPSrTTY
KMBt£/hr
2.9
5.2
10.5
20.9
33.5
CAPACITY FACTOR
0.8
$7,034
$4,054
$2,193
$1,321
$928
0.66
$8,560
$4,956
$2,687
$1,595
$1,115
0.5
$11,349
$6,604
$3,590
$2,096
$1,458
0.33
$17,277
$10,108
$5,509
$3,159
$2,186
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 590 MMBtu/hr
cXMtffy
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$1,578
$1,347
$1,252
$1,100
0.66
$1,912
$1,633
$1,518
$1,333
0.5
$2,524
$2,156
$2,004
$1,760
0.33
$3,824
$3,266
$3,036
$2,666
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: residual oil (BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 1300 MMBtu/hr
effiftff*
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$2,451
$2,078
$1,924
$1,677
0.66
$2,970
$2,519
$2,332
$2,033
0.5
$3,921
$3,325
$3,079
$2,684
0.33
$5,941
$5,037
$4,664
$4,066
D-23
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: coal (BOILER: field erected wall fired
NOx CONTROL: LNB
REFERENCE COST BASE: CIBO, 1992; 766 MMBtu/hr
cfflffir
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$1,112
$968
$908
$813
0.66
$1,340
$1,165
$1,093
$977
0.5
$1,758
$1,527
$1,432
$1,279
0.33
$2,645
$2,295
$2,151
$1,919
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: coal |BOILER: circulating FBC
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 460 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$875
$813
$787
$745
0.66
$964
$888
$856
$806
0.5
$1,125
$1,025
$984
$917
0.33
$1,468
$1,316
$1,254
$1,153
D-24
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: Pulverized coal (BOILER: Tangentially-fired
NOx CONTROL: SCR
REFERENCE COST BASE: Utility Boiler ACT (EPA-453/R-94-023)
BOILER
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$3,304
$2,968
$2,828
$2,605
0.66
$3,923
$3,415
$3,246
$2,976
0.50
$4,772
$4,233
$4,011
$3,654
0.33
$6,789
$5,972
$5,635
$5,094
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: Coal |BOILER: Field Erected Wall Fired
NOx CONTROL: SNCR - ammonia
REFERENCE COST BASE: EXXON, 1990; 800 MMBtu/hr boiler
BOILER
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$1,306
$1,270
$1,255
$1,231
0.66
$1,358
$1,314
$1,296
$1,267
0.50
$1,453
$1,395
$1,371
$1,332
0.33
$1,655
$1,567
$1,531
$1,472
D-25
-------
SCALED COST EFFECTIVENESS, S/TON NOx REMOVED
FUEL: Pulverized coal |BOILER: wall -fired
NOx CONTROL: SNCR
REFERENCE COST BASE: Nalco Fuel Tech, 1994; 400 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$1,100
$1,036
$1,010
$968
0.66
$1,121
' $1,044
$1,012
$961
0.50
$1,337
$1,235
$1,193
$1,126
0.33
$1,662
$1,508
$1,444
$1,342
-
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: Coal (BOILER: Spreader Stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech; 1992; 303 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
250
400
500
750
CAPACITY FACTOR
0.8
$1,318
$1,285
$1,271
$1,249
0.66
$1,359
$1,319
$1,302
$1,276
0.50
$1,435
$1,382
$1,360
$1,324
0.33
$1,595
$1,514
$1,481
$1,427
D-26
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: wood (BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 190 MMBtu/hr
BOILER
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,144
$1,687
$1,533
$1,448
$1,370
0.66
$2,445
$1,891
$1,705
$1,602
$1,507
0.5
$2,996
$2,264
$2,019
$1,883
$1,757
0.33
$4,166
$3,057
$2,686
$2,480
$2,289
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: wood (BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 225 MMBtu/hr
BOILER
TAPArtTY
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,266
$1,800
$1,644
$1,558
$1,478
0.66
$2,571
$2,006
$1,817
$1,712
$1,615
0.5
$3,128
$2,383
$2,133
$1,995
$1,867
0.33
$4,312
$3,183
$2,805
$2,595
$2,401
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: wood (BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 300 MMBtu/hr
J9IL.ER
CAPACITY
fiflRyfr
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,119
$1,630
$1,467
$1,376
$1,292
0.66
$2,435
$1,843
$1,645
$1,535
$1,434
0.5
$3,014
$2,233
$1,971
$1,826
$1,692
0.33
$4,243
$3,060
$2,663
$2,443
$2,240
D-27
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: wood (BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 395 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$1,519
$1,073
$923
$840
$764
0.66
$1,806
$1,265
$1,084
$983
$890
0.5
$2,330
$1,616
$1,377
$1,244
$1,122
0.33
$3,444
$2,363
$2,000
$1,799
$1,614
SCALED COST EFFECTIVENESS, -S/TON NOx REMOVED
FUEL: wood [BOILER: stoker
NOx CONTROL : SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 500 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$1,661
$1,269
$1,138
$1,065
$997
0.66
$1,912
$1,436
$1,277
$1,189
$1,107
0.5
$2,370
$1,742
$1,532
$1,415
$1,308
0.33
$3,343
$2,392
$2,074
$1,897
$1,734
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: wood (BOILER: bubbling FBC
NOx CONTROL: SNCR - ammonia based
REFERENCE COST BASE: Hurst, 1988; 250 MMBtu/hr
S»
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$1,459
$1,392
$1,364
$1,319
$997
0.66
$1,563
$1,481
$1,448
$1,394
$1,107
0.5
$1,754
$1,646
$1,601
$1,530
$1,308
0.33
$2,158
$1,994
$1,927
$1,818
$1,734
D-28
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: paper (BOILER: packaged watertube
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 72 MMBtu/hr
BOILER
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$1,949
$1,591
$1,395
$1,247
$1,177
$1,104
0.66
$2,216
$1,782
$1,545
$1,365
$1,281
$1,192
0.5
$2,705
$2,132
$1,819
$1,582
$1,470
$1,354
0.33
$3,744
$2,876
$2,401
$2,042
$1,873
$1,696
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: 'paper | BOILER: packaged watertube
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 172 MMBtu/hr
BOILER
CAPACITY
MMBtu/hr
10
25
50
100
150
250
CAPACITY FACTOR
0.8
$2,474
$1,967
$1,690
$1,480
$1,382
$1,278
0.66
$2,844
$2,230
$1,894
$1,639
$1,520
$1,395
0.5
$3,520
$2,710
$2,266
$1,930
$1,773
$1,608
0.33
$4,958
$3,730
$3,059
$2,549
$2,311
$2,061
D-29
-------
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: MSW (BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 108 MMBtu/hr
BOILER
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,123
$1,721
$1,587
$1,512
$1,443
0.66
$2,394
$1,907
$1,744
$1,653
$1,570
0.5
$2,889
$2,246
$2,031
$1,912
$1,801
0.33
$3,942
$2,968
$2,642
$2,461
$2,293
SCALED COST EFFECTIVENESS, $/TON NOx REMOfED
FUEL: MSW |BOILER: stoker
NOx CONTROL: SNCR - urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 121 MMBtu/hr
TAPiriTY
JjflrMLi 1 T
MMBtu/hr
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,603
$1,975
$1,764
$1,647
$1,539
0.66
$3,025
$2,263
$2,008
$1,866
$1,735
0.5
$3,796
$2,790
$2,453
$2,266
$2,093
0.33
$5,434
$3,910
$3,400
$3,117
$2,855
SCALED COST EFFECTIVENESS, $/TON NOx REMOVED
FUEL: MSW | BOILER: stoker
NOx CONTROL: SNCR • urea based
REFERENCE COST BASE: Nalco Fuel Tech, 1992; 325 MMBtu/hr
BOILER
CAPACITY
50
150
250
350
500
CAPACITY FACTOR
0.8
$2,167
$1,672
$1,507
$1,415
$1,330
0.66
$2,486
$1,887
$1,686
$1,575
$1,472
0.5
$3,070
$2,280
$2,015
$1,868
$1,732
0.33
$4,312
$3,114
$2,713
$2,490
$2,284
D-30
-------
APPENDIX E. ANNUAL COSTS OF RETROFIT NOX CONTROLS:
NATURAL-GAS-FIRED ICI BOILERS
This appendix contains cost spreadsheets for natural-gas-fired boilers retrofitted with various
NOX controls. The spreadsheets are based on data from actual boiler retrofit experiences or
studies. Capital annualization for all analyses are based on a 10-year amortization period and a
10-percent interest rate. All costs presented are in 1992 dollars. For further information on the
methodology and assumptions made in these cost analyses, see Chapter 6.
This appendix contains cost spreadsheets for the following boilers:
Boiler and NOX Control Page
Packaged watertube, 45 MMBtu/hr, with WI and O2 trim E-3
Packaged firetube, 10.5 MMBtu/hr, with WI and O2 trim E-5
Field-erected watertube, 75 MMBtu/hr, with BOOS and O2 trim E-7
Field-erected watertube, 75 MMBtu/hr, with BOOS, WI, and O2 trim E-9
Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB E-ll
Field-erected watertube, 590 and 1,300 MMBtu/hr, with LNB * E-17
Packaged watertube, 265 MMBtu/hr, with LNB and CEM E-21
Packaged watertube, 17.7, 41.3, 45, 55, and 265 MMBtu/hr, with LNB
and FOR E-23
Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FOR,
and CEM E-33
Packaged firetube, 2.9, 5.23, 10.46, 20.9, and 33.5 MMBtu/hr, with
FOR and O2 trim E-39
Packaged watertube, 50, 100, 150, 200, and 250 MMBtu/hr, with SCR E-49
Field-erected watertube, 250 MMBtu/hr, with SCR E-59
Packaged watertube, 50 and 150 MMBtu/hr, with SCR (variable catalyst
life) E-61
Field-erected watertube, 250 MMBtu/hr, with SCR (variable catalyst life) E-69
E-l
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE
BOILER CAPACITY (MHBtu/hr): 45
FUEL TYPE: NATURAL GAS
CONTROL METHOD: WATER INJECTION WITH OXYGEN TRIM
~""—Trf""»—~~—TW~TrTW*"»Tr-[r~~~»*™—•••••••••—— - ——--•»
TOTAL CAPITAL INVESTMENT COST (TCIC)
CHAP. 6 REFERENCES
COLANNINO. 1993
COST BASE
1992 DOLLARS
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST **•
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP. SP (as required)
4. BUILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
•** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY
TOTAL CAPITAL INVESTMENT COST «**
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLOG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
SO
0.66
SO
0.5
SO
0.33
so
so
so
S24.786
$0
so
$24.786
SO
SO
S24.786
SO
SO
S24.786
CONTINUED ON NEXT PAGE
E-3
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTU8E CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS COLANhlNO. 1993
CONTROL METHOD: WATER INJECTION WITH OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS {O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 8 $O.OS/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX NET EFFICIENCY LOSS. N.GAS 9 $3.63/HHBTU
"•* TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
• AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02VCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*" TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.6
$5,675
$5.675
$0
$496
$248
$248
$991
$6.666
0.66
$4.682
$4.682
$0
$496
$248-
$246
$991
$5.673
*»••»•****«»•••*••««««*
COST BASE
1992 DOLLARS
»mmm»mmmmmmm
0.5
$3.547
$3.547
$0
$496
$248
$248
$991
$4.538
mm**mmMmmmm
0.33
$2.341
$2.341
$0
$496
$248
$248
$991
$3,332
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** HOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0.1627
$24.786
$4.034
$6.666
$10.700
0.16
O.OS6
65
0.8
45
16.4
mmmmmmmm^mmt
$652
10
0.1
0 16?7
$i«.*B6
$4.034
$5.673
$9.707
0.16
0.056
65
0.66
45
mmmxm*m*mmm
13.5
$717
10
0.1
0.1627
$24,786
$4.034
$4.538
Ksax»««xc
$8.572
0.16
0.056
65
0.5
45
10.2
10
0.1
0.1627
$24.786
$4.034
$3.332
CKXKXKKS**
$7,366
0.16
0.056
65
0.33
45
mmmmmmmmmmm
6.6
$836 | $1,089
r»*^-«»«**«»*«««««*W«B*C««»*«^*"B-««*««««*M«***
E-4
-------
:OST EFFECTIVENESS OF RETROFIT NOx CONTROLS
JOILER TYPE: PACKAGED F1RETUBE CHAP. 6 REFERENCES
-UEL TYPE: NATURAL GAS COLANN1NO. 1993
.ONTROL METHOD: WATER INJECTION WITH OXYGEN TRIM
COST BASE
1992 DOLLARS
FOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (OIC)
•** TOTAL DIRECT INSTALLATION COST !"** DIC
3. SITE PREP. SP (as required) SP
4. 'BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *•* DCC
(PEC+D1C+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+1CC+CONT)
BOILER CAPACITY FACTOR
0.8
$0
0.66
SO
0.5
$0
0.33
$0
SO
So
$24.786
$0
JO
$24,786
$0
$0
$24,786
$0
$0
$24,786
CONTINUED ON NEXT PAGE
E-5
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS COLANN1NO, 1993
CONTROL METHOD: WATER INJECTION WITH OXYGEN TRIH
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
Z. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0 . 05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX NET EFFICIENCY LOSS. K.GAS i J3.63/MMBTU
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (O.OrTCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+1AC)
0.8
$2.646
$2.648
*0
$496
$24B
$246
$991
$3.640
COST BASE
1992 DOLLARS
0.66
$2.185
$2.185
$0
$496
$248
$248
$991
$3.176
0.5
$1.655
$1,655
$0
$496
$248
$246
$991
$2.646
0.33
$1.092
$1.092
$0
$496
$248
$248
$991
$2.084
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&M)
1. ANNUALIZEO CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT CO.'TS '.TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
•*• NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 ctays/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$24.786
$4.034
$3.640
$7.673
0.12
0.042
65
0.8
10.5
2.9
$2.674
10
0.1
0.1627
$24.786
$4,034
$3.176
$7.210
0.12
0.042
65
0.66
10.5
2.4
$3.045
10
0.1
0.1627
$24.786
$4.034
$2.646
$6.680
0.12
0.042
65
0.5
10.5
1.8
$3.724
10
0.1
0.1627
$24.786
$4.034
$2.084
$6.117
0.12
0.042
65
0.33
10.5
1.2
$5.168
E-6
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED VATERTUBE
BOILER CAPACITY (HMBtu/hr): 75
FUEL TYPE: NATURAL GAS
CONTROL METHOD: BOOS WITH OXY6EN TRIM
TOTAL CAPITAL INVESTMENT COST (TCIC)
CHAP. 6 REFERENCES
COLANNINO. 1993
COST BASE
1992 DOLLARS
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*"* TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP. SP (as required)
4. BUILDINGS, 8LDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*• TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY
TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLOG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
$0
0.66
$0
0.5
$0
0.33
SO
$0
to
J24.786
JO
JO
J24.786
JO
JO
J24.786
JO
JO
J24.786
CONTINUED ON NEXT PAGE
E-7
-------
COST EFFECTIVENESS OF RETROFIT NDx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS COLANNINO. 1993
CONTROL METHOD: BOOS WITH OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
S. ELECTRICITY • $0.05/kW-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX NET EFFICIENCY LOSS. N.GAS 8 J3.63/MHBTU
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (O.Ol'TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
0.8
$4.729
$4,729
$0
$496
$248
$248
$991
$5.720
0.66
$3.901
$3.901
$0
$496
$248"
$248
$991
$4.893
COST BASE
1992 DOLLARS
0.5
$2.956
$2.956
$0
$496
$248
$248
$991
$3.947
0.33
$1.951
$1.951
$0
$496
$248
$248
$991
$2.942
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capita] and O&H)
1. ANNUALIZED CAPITAL INVESTHENT COST (ACIC)
EXPECTED LIFET1HE OF EQUIPHENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTHENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTHENT COST *** ACIC
2. ANNUAL O&M COSTS (O&H. above) O&H
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HHBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx).l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS).***
10
0.1
0.1627
$24.786
$4.034
$5.720
$9.754
0.18
0.09
50
0.8
75
23.7
10
0.1
0.1627
$24.786
$4.034
$4.893
$8.927
0.18
0.09
50
0.66
75
19.5
$412
mmmmmmmmmmmm
10
0.1
0.1627
$24.786
$4.034
$3.947
$7.981
0.18
0.09
SO'
0.5
75
•••••••••••
14.8
tmmmmmmmmmmmi
$457 | $540
10
0.1
0 162~
$24.7£.6
$4.034
$2.942
$6.976
0.18
0.09
SO
0.33
75
9.8
>•••••••••••
$715
E-8
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS COLANNINO. 1993
CONTROL METHOD: BOOS l> WATER INJEC WITH OXYGEN TRIM
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC4CONT)
BOILER CAPACITY FACTOR
0.8
$0
0.66
SO
0.5
$0
0.33
SO
$0
$0
$34.700
so
$0
$34,700
$0
$0
$34,700
SO
$0
$34.700
CONTINUED ON NEXT PAGE
E-9
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS COLANNINO. 1993
CONTROL METHOD: BOOS It WATER INJEC WITH OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC:)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY » $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX NET EFFICIENCY LOSS, N.GAS 9 $3.63/HHBTU
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IACJ
1. OVERHEAD (60X OF SUM OF ALL LABOR
• AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02'TCIC)
3. PROPERTY TAX (0.01'TCIC)
. 4. INSURANCE (O.OrTCIC)
"** TOTAL INDIRECT ANNUAL COSTS *** IAC
•*• TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** 04M
(DAC+IAC)
0.8
$18.915
$18.915
$0
$694
$347
$347
$1.388
$20.303
COST BASE
1992 DOLLARS
0.66
$15.605
$15.605
$0
$694
$347-
$347
$1.388
$16.993
0.5
$11.822
$11.822
$0
$694
$347
$347
$1.388
$13.210
0.33
$7.803
$7.803
$0
$694
$347
$347
$1.388
$9.191
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and 08.M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZEO CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (WMMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$34.700
$5.647
$20.303
$25.951
0.18
0.045
75
0.8
75
35.5
10
0.1
0.1627
$34.700
$5.647
$16.993
$22.640
0.18
0.045
75
0.66
75
29.3
••*««•«*»•• C
10
0.1
0.1627
$34.700
$5.647
$13.210
$18.857
0.18
0.045
75
0.5
75
22.2
KKKXM*MCW
10
0.1
0.1627
$34.700
$5.647
$9.191
$14.838
0.18
0.045
75
0.33
75
14.6
>•«**»•*«•»*
$731 | $774 $850 | $1.014
E-10
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE
BOILER CAPACITY (MHBtu/hr): 51
FUEL TYPE: NATURAL GAS
CONTROL METHOD: LOU NOx BURNER
CHAP. 6 REFERENCES
CAL ARB. 1987
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST •**
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST •***
3. SITE PREP, SP (as required)
4. ' BUILDINGS, BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
S. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY
TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
$19.628
$19.828
0.66
$19.828
$19.828
0.5
$19.828
$19.828
0.33
$19.828
$19.828
$13.285
$33,113
$0
$33.113
$13.285
$33.113"
$0
$33.113
$13.285
$33.113
$0
$33.113
$13.285
$33.113
$0
$33.113
CONTINUED ON NEXT PAGE
E-ll
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CAL ARE. 1987
CONTROL METHOD: LOW NOx BURNER
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60% OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (O.OI'TCIC)
4. INSURANCE (O.OI'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *" IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** OiH
(DAC+IAC)
o.e
$0
$0
$662
$331
$331
$1.325
$1.325
0.66
$0
$0
$662
$331'
$331
$1.325
$1.325
0.5
$0
$0
$662
$331
$331
$1.325
$1,325
0.33
$0
$0
$662
$331
$331
$1.325
$1.325
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (AC1C)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) 01M
*** TOTAL ANNUALIZED COST *** ACIC+O&H
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) •**
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*•* COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$33.113
$5.389
$1.325
$6.714
0.16
0.08
50
0.8
51
14.3
10
0.1
o.ie:7
$33. it:
$5.389
$1.325
$6.714
0.16
0.08
50
0.66
51
11.8
10
0.1
0.1627
$33.113
$5.389
$1.325
$6.714
0.16
0.08
50
0.5
51
8.9
10
0.1
0.1627
$33.113
$5.389
$1.325
$6.714
0.16
0.08
50
0.33
51
5.9
$470 | $569 $751 | $1.138
E-12
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CAL ARB. 1987
CONTROL METHOD: LOW NOx BURNER
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST "* DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS, BLDG (as required) BLDG
«** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST "* ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
J65.235
$65.235
0.66
$65.235
$65.235
0.5
$65.235
$65.235
0.33
$65.235
$65.235
$15,466
$80.702
$29.842
$110.543
$15.466
$80,702"
$29.842
$110.543
$15.466
$80.702
$29.642
$110.543
$15.466
$80.702
$29.842
$110.543
CONTINUED ON NEXT PAGE
E-13
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)' 75 - — — — — —
FUEL TYPE: NATURAL 6AS CAL ARB, 1987
CONTROL METHOD: LOW NOx BURNER
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kU-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60% OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01*TCIC)
***' TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.6
$0
$0
$2.211
SI. 105
$1.105
$4.422
$4.422
0.66
$0
$0
$2.211
$1.105"
$1.105
$4.422
$4.422
0.5
$0
$0
$2.211
$1.105
$1.105
$4.422
$4.422
0.33
$0
$0
$2,211
$1.105
$1.105
$4.422
$4.422
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (K'C.. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZEO COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) »**
[CAP*CF*(24 hr/day)*(365 days/yr)]''[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS)'"*
10
0.1
0.1627
$110.543
$17.990
$4.422
$22.412
0.18
0.09
50
0.8
75
23.7
$948
10
0.1
0.1627
$110.543
$17.990
$4.422
$22.412
0.18
0.09
50
0.66
75
19.5
.*>•>«
10
0.1
0.1627
$110.543
$17.990
$4.422
$22.412
0.18
0.09
50
0.5
75
14.8
$1.516
10
0.1
0.1627
$110.543
$17.990
$4.422
$22.412
0.18
0.09
50
0.33
75
9.8
*L2L
E-14
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOW NOx BURNER
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT 320000
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (QIC)
"* TOTAL DIRECT INSTALLATION COST *** DIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** . TCIC
(OCC+ICC-ttONT)
— — ~
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$158.723
0.66
$158.723
0.5
$158,723
0.33
$158.723
$47.617
$206.340
$15.872
$15.872
$15.872
$3.174
$1,587
$52.379
$51.744
$310.463
$47.617
$206.340
$15.872
$15.872
$15.872
$3,174
$1.587
$52.379
$51.744
$310,463
$47.617
$206.340
$15.872
$15.872
$15,872
$3.174
$1.587
$52,379
$51.744
$310,463
$47.617
$206.340
$15.872
$15.872
$15.872
$3.174
$1.587
$52.379
$51.744
$310.463
CONTINUED ON NEXT PAGE
E-15
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MNBtu/hr)- 265 - -
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOU NOx BURNER
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 1 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
**• TOTAL DIRECT ANNUAL COSTS *** , DAC
B. INDIRECT ANNUAL COSTS (1AC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
* AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TC1C)
4. INSURANCE (0.01'TCIC)
**• TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(OAC+IAC)
tmmmm»mmm**mt
tmmmm»mm»mmttm
0.8
$0
$0
$6.209
$3.105
$3.105
$12.419
$12.419
xmmmmfmmxmmmm
0.66
$0
$0
$6.209
$3.ior
$3.105
$12.419
$12.419
COST BASE
1992 DOLLARS
t**m*mmmmmmmmm*xmm*m****
***mmmmmmm*mmmmmmmmmm*m
0.5 0.33
$0
$0
$6.209
$3.105
$3.105
$12.419
$12.419
$0
$0
$6.209
$3.105
$3.105
$12.419
$12.419
COST. EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
I. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
**• ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL DIM COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$310.463
$50.526
$12,419
$62.945
0.24
0.12
50
0.8
265
111.4
••••••••KKX
10
0.1
0.1627
$310.463
$50.526
$12.419
$62.945
'0.24
0.12
50
0.66
265
91.9
10
0.1
0.1627
$310.463
$50.526
$12.419
$62.945
0.24
0.12
50
0.5
265
69.6
10
0.1
0.1627
$310.463
$50.526
$12.419
$62.945
0.24
0.12
50
0.33
265
46.0
$565 $685 $904 $1,369
E-16
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE
BOILER CAPACITY (MHBtu/hr): 590
FUEL TYPE: NATURAL GAS
CONTROL METHOD: LOW NOx BURNER
CHAP. 6 REFERENCES
CIBO. 1992
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
**» TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DJC)
*** TOTAL DIRECT INSTALLATION COST ***
(30 percent of purchased equipment)
3. SITE PREP, SP (as required)
4. -BUILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
*** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY (20 PERCENT OF DIRECT AND INDIRECT)
*** TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
$1,175,725
0.66
$1.175.725
0.5
$1,175.725
0.33
$1.175.725
$352,717
$1.528,442
$117,572
$117,572
$117,572
$23.514
$11,757
$387.989
$383.286
$2.299.718
$352.717
$1,528.442"
$117,572
$117.572
$117.572
$23.514
$11,757
$387.989
$383,286
$2,299,718
$352.717
$1.528.442
$117.572
$117.572
$117.572
$23.514
$11.757
$387.989
$383.286
$2.299.718
$352.717
$1.528.442
$117.572
$117.572
$117.572
$23,514
$11.757
$387.989
$383.286
$2.299.718
CONTINUED ON NEXT PAGE
E-17
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED UATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOW NOx BURNER
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC;
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 J0.05/W-hr
6. STEAM
7. FUEL
6. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
"• TOTAL INDIRECT ANNUAL COSTS *** IAC
»** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
—
0.8
SO
SO
$45.994
$22.997
S22.997
S91.989
S91.989
0.66
SO
SO
$45.994
$22.997-
S22.997
S91.989
$91.989
COST BASE
1992 DOLLARS
*mm***mmmmummmmmmmmmmmm
[«*««««**«•**••*•««*•««*
0.5 0.33
$0
SO
$45.994
$22.997
$22.997
$91.989
$91.989
SO
So
$45.994
$22,997
$22.997
$91.989
$91.989
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx BEHOVED PER YEAR (TONS/YR) ***
[CAP*CF»(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.' 6274539
J2. 299. 718
S374.269
S91.989
$466.257
0.3
O.IS
50
0.8
590
310.1
mmrnmm^mmmmm
10
0.1
0.16274539
S2. 299. 718
$374.269
$91.989
$466.257
0.3
0.15
50
0.66
590
255.8
10
0.1
0.16274539
$2.299.718
$374,269
$91.989
$466.257
0.3
0.15
50
0.5
590
193.8
10
0.1
0.16274539
$2.299.718
$374.269
$91.989
.
$466.257
0.3
0.15
SO
0.33
590
127.9
SI. 504 | $1.822 S2.406 | S3. 645
E-18
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO, 1992
CONTROL METHOD: LOU NOx BURNER
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) SP
4. BUILDINGS. 8LDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.1 OPEC)
A. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
"* TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and Indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
S3. 056. BBS
0.66
$3.056.885
O.S
$3.056.885
0.33
$3.056.885
$917.065
$3.973.950
$305.688
$305.686
$305.688
$61.138
$30.569
$1.008.772
$996.544
$5.979.267
$917,065
$3,973.95E
$305.686
$305.688
$305.686
$61.138
$30.569
$1.008.772
$996.544
$5.979.267
$917.065
$3.973.950
$305.666
$305.688
$305.666
$61.138
$30,569
$1.008,772
$996.544
$5,979.267
$917.065
$3.973,950
$305.688
$305.688
$305.688
$61.138
$30.569
$1.008.772
$996.544
$5.979.267
CONTINUED ON NEXT PAGE
E-19
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATER TUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOU NOx BURNER
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
Z. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY « JO.OS/kV-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (I AC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TC1C)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
m*mmmmmmmmmm
0.8
SO
$0
$119.585
$59.793
$59.793
$239,171
J239.171
COST BASE
1992 DOLLARS
0.66
$0
$0
$119.585
$59.793"
$59.793
$239.171
$239.171
0.5
$0
$0
$119.585
$59.793
$59.793
$239.171
$239.171
0.33
$0
$0
$119.585
$59.793
$59.793
$239.171
$239.171
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITA! INVESTMENT COSTS (TCIC. above)
"** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M, above) O&M
*** TOTAL ANNUAL I ZEO COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (NMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
£CAP*CF*(24 hr/day)*(365 days/yr)J*[(NOx)l-(NOx)2]/2000
*"* COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS} ***
10
0.1
0.1627
$5.979.267
$973.096
$239.171
$1.212.269
mm*mm*mmm:mx
0.4
0.2
50
0.8
1300
••**•*«•»••
911.0
mmmmmmxmmmm
10
0.1
0.1627
$5.979.267
$973.098
$239.171
$1.212.269
0.4
0.2
50
0.66
1300
«*•••**•••*
751.6
10
0.1
0.1627
$5,979.267
$973.098
$239.171
$1.212.269
0.4
0.2
50
0.5
1300
»••«««*«*••
569.4
10
0.1
0.1627
$5.979.267
$973.098
$239.171
$1.212.269
0.4
0.2
50
0.33
1300
xmmmmmmmmmm
375.8
$1.331 $1,613 $2.129 | $3.226
E-20
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOU NOx BURNER WITH CEH SYSTEM
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
•** TOTAL DIRECT INSTALLATION COST *** OIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) SP
4. BUILDINGS. 6LDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST «•* DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
' 2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and Indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
.............
COST BAS
E
1992 DOLLARS
BOILER CAPACITY FACTOR
O.B
$263.245
0.66
$263.245
0.5
$263.245
0.33
$263.245
$78.973
$342.218
$26.324
$26,324
$26.324
$5.265
$2,632
$86.671
$85.618
$514.907
$78.973
$342,218'
$26.324
$26.324
$26.324
$5,265
$2.632
$86.871
$85.818
$514.907
$78.973
$342.218
$26.324
$26,324
$26.324
$5.265
$2.632
$86.871
$85.818
$514.907
$78.973
$342.218
$26.324
$26.324
$26.324
$5.265
$2.632
$86.871
$85.818
$514.907
CONTINUED ON NEXT PAGE
E-21
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOW NOx BURNER WITH CEH SYSTEM
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A, DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
• AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02'TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
••* TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$0
$0
$10,298
$5.149
$5.149
$20.596
$20.596
0.66
$0
$0
$10.298
$5.14?
$5.149
$20.596
$20.596
O.S
$0
$0
$10.298
J5.149
$5.149
$20.596
$20.596
mmmmm**m*mm
0.33
$0
$0
$10.298
$5.149
$5.149
$20.596
$20.596
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
"«* ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
I. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$514.907
$83,799
$20.596
$104.395
0.24
0.12
50
0.8
265
111.4
10
0.1
0.1627
$514.907
$83.799
$20.596
$104.395
0.24
0.12
50
0.66
265
91.9
10
0.1
0 1627
$S!4.907
$83.799
$20.596
$104.395
0.24
0.12
50
0.5
265
69.6
10
0.1
0.1627
$514.907
$83.799
$20.596
$104.395
0.24
0.12
50
0.33
265
mmmnmmmmmmm
46.0
mmmmmmmmmmm*
$937 $1.136 J1.499 $2.271
E-22
-------
:OST EFFECTIVENESS OF RETROFIT NOx CONTROLS
JOtlER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
•UEL TYPE: NATURAL GAS CIBO. 1992
:ONTROL METHOD: LNB AND FGR
fOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. SIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *•• DIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) ' SP
4. .E'JILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
tmmm*mmmmmim*M
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$28.017
0.66
$28.017
0.5
$28.017
0.33
$28.017
$8.405
$36.421
$2.802
$2.802
$2.802
$560
$280
$9.245
$9.133
$54,800
$8.405
$36.421'
$2.802
$2.802
$2.802
$560
$280
$9.245
$9.133
$54.800
$8.405
$36.421
$2.802
$2.802
$2.802
$560
$280
$9.245
$9.133
$54,800
$8.405
$36.421
$2.802
$2.802
$2.802
$560
$280
$9.245
$9.133
$54.800
CONTINUED ON NEXT PAGE
E-23
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)- 17 7 -
FUEL TYPE: NATURAL 6AS CIBO. 1993
CONTROL METHOD: LNB AND FGR
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 8 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 8 $3.63/MHBtu
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$500
$500
$2.313
($4.503)
($1.189)
$300
$1.096
$548
$548
$2.492
$1.303
0.66
$500
$500
$1.909
($3.715)
($806)
$300
$1.096
$548"
$548
$2.492
$1.686
COST BASE
1992 DOLLARS
*••«•••*••*•
0.5
$500
$500
$1,446
($2.814)
($368)
$300
$1.096
$548
$548
$2.492
$2.124
0.33
$500
$500
$954
($1.857)
$97
$300
$1.096
$548
$548
$2.492
$2.589
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. «bjve)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M.. above) O&M
•*• TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$54. BOD
$8.919
$1.303
$10.221
0.16
0.06
60
0..8
17.7
6.0
10
0.1
0.1627
$54.800
$8.919
$1.686
$10.604
0.16
0.06
60
0.66
17.7
4.9
10
0.1
0.1627
$54.800
$8.919
$2.124
$11.042
0.16
0.06
60
0.5
17.7
3.7
10
0.1
0.1627
$54.800
$8.919
$2. -589
$11.507
0.16
0.06
60
0.33
17.7
2.5
$1.717
$2.159
$2.967 | $4.685
E-24
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS IHPELL CORP.. 1989
CONTROL METHOD: LNB AND FGR
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC>
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
**• TOTAL DIRECT CAPITAL COST *** OCC
(PEC+DIC+SP+BLDG)
8. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
Z. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
•** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$95.751
0.66
$95,751
O.S
$95.751
0.33
$95.751
$50.394
$146,145
$26.203
$36.286
$208,634
$50.394
$146.145"
$26.203
$36.286
$208,634
$50.394
$146.145
$26.203
$36.286
$208.634
$50.394
$146.145
$26.203
$36.286
$208,634
BWKCMKKMX
CONTINUED ON NEXT PAGE
E-25
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS IMPELL CORP. . 1989
CONTROL METHOD: LN8 AND FGR
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DA':)
1. OPERATING LABOR
Z. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kW-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 9 {3.63/MMBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUH OF ALL LABOR
AND MAINTENANCE MATERIALS)
Z. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01«TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
0.8
$500
$500
$5.228
($10.506)
($4.278)
$300
$4.173
$2.086
$2.086
$8.645
$4.367
0.66
$500
$500
$4.313
($8.668)
($3.355)
$300
$4.173
$2.085
$2.086
$8.645
$5.291
0.5
$500
$500
$3.267
($6.566)
($2.299)
$300
$4.173
12. 086
$2.086
$8.645
$6.346
0.33
$500
$500
$2,157
($4.334)
($1.177)
$300
$4,173
$2.086
$2.086
$8.645
$7.468
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (Incl. capital and O&H) '
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZEO CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*•* NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]i*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$208.634
$33.954
$4,367
$38.321
0.16
0.06
60
0.8
41.3
13.9
$2.758
10
0.1
0.1627
$208.634
$33,954
$5.291
$39.245
0.16
0.06
60
0.66
41.3
11.5
$3,424
10
0.1
0.1627
$208.634
$33,954
$6.346
$40.301
0.16
0.06
60
0.5
41.3
8.7
$4.641
10
0.1
0.1627
$208.634
$33.954
$7.468
$41.422
0.16
0.06
60
0.33
41.3
5.7
$7.228
E-26
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CAL ARB. 19B7
CONTROL METHOD: LNB AND F6R
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*•* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLOG (as required) BLOG
*** TOTAL DIRECT CAPITAL COST «** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** • TCIC
(OCC+1CC+CONT)
BOILER CAPACITY FACTOR
0.6
$48.381
0.66
$48,381
0.5
$48.381
tmm*mmmmmmmm
0.33
$48.381
$57.403
$105.785
$35.989
$141.773
$57.403
$105,785-
$35.969
$141.773
$57.403
$105.785
$35.989
$141.773
$57.403
$105.785
$35.989
$141.773
CONTINUED ON NEXT PAGE
E-27
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS CAL ARB. 1987
CONTROL METHOD: LNB AND FGR
ANNUAL OPERATIN6 AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $O.OS/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS « $3.63/MHBtu
*** TOTAL DIRECT ANNUAL COSTS *** . DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (SOX OF SUM OF ALL LABOR
• AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (D.Ol'TCIC)
**• TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
0.8
$500
$500
$5.881
($11.448)
($4,566)
$600
$2.835
$1.418
$1.418
$6.271
$1.705
COST BASE
1992 DOLLARS
m»*mmmmm**mmmmmmmmmmmmmmmmmmmmmm***
0.66
$500
$500
$4.852
($9.444)
($3,592)
$600
$2.835
$1,418"
$1.41S
$6.271
$2.679
0.5
$500
$500
$3.676
($7.155)
($2.479)
$600
$2.835
$1.418
$1.418
$6.271
$3.792
0.33
$500
$500
$2.426
($4.722)
($1.296)
$600
$2.635
$1.418
$1.418
$6.271
$4.975
COST .EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTHENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&H
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/HMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0 16?7
$14;, 7/3
$23.073
$1.705
$24.778
0.16
0.06
60
O.B
45
«*»•****«*«
15.1
xm**mmmmmmm
***********
$1.637
10
0.1
0.1627
$141.773
$23.073
$2.679
$25.752
0.16
0.06
60
0.66
45
«»«K*B*BH8
12.5
B«»BB4EBBBB*
************
$2.062
10
0.1
0.1627
$141.773
$23.073
$3,792
$26.865
0.16
0.06
60
0.5
45
9.5
*»•*••**•*•
************
$2.840
10
0.1
0.1627
$141,773
$23.073
$4.975
$28.048
0.16
0.06
60
0.33
45
••»BBMX«*»
6.2
EX«*atVB*«*«*
************
$4.492
E-28
-------
COST. EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE
BOILER CAPACITY (MHBtu/hr): 55
FUEL TYPE: NATURAL GAS
CONTROL METHOD: LNB AND FGR
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DIG)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP. SP (as required)
4. BUILDINGS. BLDG (as required)
*»* TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *"
C. CONTINGENCY
-** TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
CHAP. 6 REFERENCES
CAL ARB. 1987
COST BASE
1992 DOLLARS
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
J84.370
0.66
$84,370
o.s
$84.370
0.33
$84.370
{122.639
$207.008
$40.500
$247.508
$122.639
$207.008"
$40.500
$247.508
$122.639
$207.008
$40.500
$247.508
$122.639
$207.008
$40.500
$247.508
CONTINUED ON NEXT PAGE
E-29
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CAL ARE, 1987
CONTROL METHOD: LNB AND FGR
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY « $0.05/kW-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS B $3.E3/HHBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (O.OrTCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
fe
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** OIM
(DAC+IAC)
0.8
$500
$500
$7.186
($13.991)
($5.803)
$600
$4.950
$2,475
$2,475
$10.500
$4.697
0.66
$500
$500
$5,930
($11.543)
($4.612)
$600
$4.950
$2.475
$2.475
$10.500
$5.888
COST BASE
1992 DOLLARS
mmmmmm»mmmm»
0.5
$500
SSOO
$4.493
($8.745)
($3.252)
$600
$4,950
$2.475
$2.475
$10.500
$7.248
0.33
$500
$500
$2.965
($5,771)
($1.806)
$600
$4.950
$2.475
$2.475
$10.500
$8.694
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVt'TK-NT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
•*• TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHStu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ••*
[CAP*CF*(*4 hr/
-------
BOILER TYPE: PA
BOILER CAPACITY (MMBtu/hr):
FUEL TYPE: NA~
CONTROL METHOD: LN
SALES TAX
FREIGHT
•ROFIT NOx CONTROLS
0 VATERTUBE CHAP. 6 REFERENCES
GAS CIBO. 1992
) FGR
COST (TCIC)
IL COST (DCC)
.QUIPHENT COST (PEC)
AND AUXILIARY EQUIPMENT (EQP) EQP
TEH
IENTATION
AX
AL PURCHASED EQUIPMENT COST *** PEC
TALLATION COST (DIC)
AL DIRECT INSTALLATION COST *** DIC
>ercent of purchased equipment)
SP (as required) SP
BLOG (as required) BLD6
CAPITAL COST *** DCC
C+SP+BLDG)
ITAL COST (ICC)
6 (0.10PEC)
ON AND FIELD EXPENSES (0.10PEC)
ON FEE (0.10PEC)
.02PEC)
E TEST (0.01PEC)
CT CAPITAL COST *** ICC
(20 percent of direct and indirect) CONT
ENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$236.321
0.66
$236.321
0.5
$236,321
0.33
$236.321
$70.696
$307,217
$23.632
$23.632
$23.632
$4.726
$2.363
$77,986
$77.041
$462.244
$70.696
$307.217'
$23.632
$23.632
$23.632
$4.726
$2.363
$77,986
$77.041
$462.244
$70.896
$307,217
$23.632
$23.632
$23.632
$4.726
$2.363
$77.986
$77.041
$462.244
$70.896
$307.217
$23.632
$23.632
$23,632
$4.726
$2.363
$77,986
$77,041
$462.244
CONTINUED ON NEXT PAGE
E-31
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (HHBtu/hr)- 265 -
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LNB AND FGR
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
Z. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
S. ELECTRICITY 9 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS i $3.63/HHBtu
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$500
$500
$34.635
($67.413)
($31.778)
$300
$9.245
$4.622
$4.622
$18.790
($12.988)
mmmmmmmmmmmm
0.66
$500
$500
$28.574
($55.616)
($26.042)
$300
$9.245
$4.62?
14.622
$18.790
($7.252)
COST BASE
1992 DOLLARS
0.5
$500
$500
$21.647
($42.133)
($19.486)
$300
$9.245
$4,622
$4.622
$18.790
($697)
0.33
$500
$500
$14.287
($27.808)
($12.521)
$300
$9.245
$4.622
$4.622
$18.790
$6.269
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
•** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/.hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]!t[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$462.244
$75.22S
($12.988)
$62.240
0.24
0.10
60
0.8
265
•»*•*•«*•«•
133.7
n*B«*B«nv
$465
10
0.1
0.1627
$462.244
$75,228
($7.252)
$67.976
0.24
0.10
60
0.66
265
110.3
Bm«ttKKKHKBK
$616
10
0.1
0.1627
$462.2-;*
$75.228
($697)
$74.531
0.24
0.10
60
0.5
265
83.6
•m«M«»««*«
$892
10
0.1
0.1627
$462.244
$75.228
$6.269
$81.497
0.24
0.10
60
0.33
265
55.2
BXXm»*«*BBK
$1.478
E-32
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE
BOILER CAPACITY (MHBtu/hr): 81.3
FUEL TYPE: NATURAL GAS
CONTROL METHOD: LNB AND FGR WITH CEH SYSTEM
TOTAL CAPITAL INVESTMENT COST (TCIC)
CHAP. 6 REFERENCES
1MPELL CORP.. 1S89
COST BASE
1992 DOLLARS
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP, SP (as required)
4. BUILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY
TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
$215.634
0.66
$215.634
0.5
$215.634
0.33
$215,634
$68,507
$284.141
$33.213
$62.459
$379.813
$68.507
$284.141-
$33.213
$62.459
$379.813
$68.507
$284,141
$33.213
$62.459
$379.813
$68.507
$284.141
$33.213
$62.459
$379.613
CONTINUED ON NEXT PAGE
E-33
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER WE: PACKAGED WATERTU8E CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS IHPELLCORP..
CONTROL METHOD: LNB AND FGR WITH CEH SYSTEM
ANNUAL OPERATING AND MAINTENANCE COSTS (0&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY • $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 0 $3.63/HHBtu
0*4.83 R=2.35
*** TOTAL DIRECT ANNUAL COSTS *** . DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
* AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
**• TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS »*• 04M
(DAC+IAC)
1989
0.6
$500
$500
$10.456
($20.682)
($9.226)
$300
$7.596
$3.798
$3.798
$15.493
$6.267
»«•»***«*••*•«•*•••«•*
COST BASE
1992 DOLLARS
0.66
$500
$500
$8.626
($17.063)
($7.436)
$300
$7.596
$3.798-
$3.798
$15.493
$8.056
0.5
$500
$500
$6.535
($12.926)
($5.391)
$300
$7.596
$3.798
$3.798
$15.493
$10.101
0.33
$500
$500
$4.313
($8.531)
($3.218)
$300
$7.596
$3.798
$3.798
$15.493
•**VK»**M
$12.274
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. VEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZEO CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&H. above) O&M
**• TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) «**
10
0.1
0.1627
$379.813
$61.813
$6.267
*»***X«*««*
$68.079
0.18
0.07
60
0.8
81.3
30. B
•••*«•••«« «
$2.213
10
0.1
0.1627
$379.813
$61.813
$8.056
$69.869
0.18
0.07
60
0.66
81.3
25.4
•««»»«*«»*««
10
0.1
0.1627
$379.813
$61.813
$10.101
X*CB«E«*KEC
$71.914
0.18
0.07
60
0.5
81.3
19.2
r*uzx»««»B«
$2.753 $3.740
10
0.1
0.1627
$379.813
$61.813
$12.274
•««*••«*»*»
$74.087
0.18
0.07
60
0.33
81.3
12.7
• •••«M««**B
$5,838
E-34
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LOW NOx BURNER AND F6R WITH CEH SYSTEM
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM _
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** OIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) • SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *»• DCC
(PEC+DIC+SP+8LDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01PEC)
•** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$426.040
0.66
$426.040
0.5
$426.040
0.33
$426.040
$127.812
$553.851
$42,604
$42.604
$42.604
$8.521
$4.260
$140.593
$138.889
$833.333
$127.812
$553.851"
$42.604
$42.604
$42.604
$8.521
$4.260
$140.593
$138.889
$833.333
$127.812
$553.851
$42.604
$42.604
$42.604
$8.521
$4.260
$140.593
$138.889
$833.333
$127.812
$553.851
$42.604
$42.604
$42.604
$8.521
$4.260
$140,593
$138.889
$833,333
CONTINUED ON NEXT PAGE
E-35
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO, 1992
CONTROL METHOD: LOU NOx BURNER AND F6R WITH CEH SYSTEM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY « $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 8 $3.63/HH8tu r & d
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02MCIC)
3. PROPERTY TAX (0.01*TC1C)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
O.B
$7.000
$11.894
($23.150)
($4.256)
$4.200
$16.667
$8.333
$8.333
$37.533
$33.277
mmmmmmmmmatmm
0.66
$7.000
$9.812
($19.098)
($2.286)
$4.200
$16.667
$8.333-
$8.333
$37,533
$35.247
COST BASE
1992 DOLLARS
••••«•«•««•
0.5
$7.000
$7.434
($14.468)
($35)
$4.200
$16.667
$8.333
$8.333
$37.533
$37.498
0.33
$7,000
$4.906
($9.549)
$2.357
$4.200
$16,667
$8.333
$8.333
$37.533
$39.890
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
fOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) **«
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
**» COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$833,333
$135,621
$33.277
$168.899
n»K«snKKB
0.18
0.07
60
0.8
91
34.4
$4.905
10
0.1
0.1627
$833.333
$135.621
$35.247
$170.868
0.18
0.07
60
0.66
91
28.4
$6.014
10
0.1
0.1627
$833.333
$135.621
$37.498
$173.120
' 0.18
0.07
60
0.5
91
21.5
10
0.1
0.1627
$833.333
$135.621
$39.890
$175.511
0.18
0.07
60
0.33
91
14.2
$8.043 $12.355
E-36
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LNB AND FGR WITH CEH SYSTEM
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*»* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (D1C)
*** TOTAL DIRECT INSTALLATION COST *** DIC
(30 percent of purchased equipment)
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+D1C+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.10PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.10PEC)
3. CONSTRUCTION FEE (0.10PEC)
4. STARTUP (0.02PEC)
5. PERFORMANCE TEST (0.01 PEC)
**« TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*" TOTAL CAPITAL INVESTMENT COST *»* TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$340.725
0.66
$340.725
0.5
$340.725
0.33
$340.725
$102.218
$442.943
$34,073
$34.073
$34,073
$6.815
$3.407
$112.439
$111.076
$666,459
$102.218
$442,943'
$34.073
$34.073
$34,073
$6.815
$3.407
$112.439
$111.076
$666.459
$102,218
$442,943
$34.073
$34,073
$34,073
$6.815
$3.407
$112.439
$111.076
$666.459
$102.218
$442,943
$34,073
$34,073
$34.073
$6.815
$3.407
$112.439
$111.076
•EBBKMXKXKX
$666,459
CONTINUED ON NEXT PAGE
E-37
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS CIBO. 1992
CONTROL METHOD: LNB AND FGR WITH CEH SYSTEM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 8 J0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS t 53.63/HHBtu
*** TOTAL DIRECT ANNUAL COSTS **« OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60% OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (O.OI*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS '" O&M
(DAC+IAC)
KTCXVMM****
0.8
$500
$500
$34,635
($67.413)
($31.778)
$300
$13.329
$6.665
$6.665
$26.958
($4.820)
0.66
$500
$500
$28.574
($55.616)
($26.042)
$300
$13.329
$6.665
$6.665
$26.958
$916
COST BASE
1992 DOLLARS
•••**••••«»
0.5
$500
$500
$21,647
($42.133)
($19.466)
$300
$13.329
$6.665
$6.665
$26.958
$7.472
0.33
$500
$500
$14.287
($27.808)
($12.521)
$300
$13.329
$6,665
$6.665
$26.958
$14.437
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (Incl. capital and O&M)
I. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZEO CAPITAL INVESTMENT COST *«* ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** AC1C+0&H
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
Z. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF»(24 hr/day)*(365 days/yr)}*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS-) ***
10
0.1
0.16Z7
$666.459
$108,463
($4.820)
$103.643
0.24
0.10
60
0.8
265
mmmmm*m**m*
133.7
10
0.1
0.1627
$666.459
$108.463
$916
$109.379
0.24
0.10
60
0.66
265
110.3
$775 | $992
10
0.1
0.1627
$666.459
$108.463
$7,472
$115.935
0.24
0.10
60
0.5
265
»»«»«*»»«»
83.6
10
0.1
0.1627
$666.459
$108.463
$14.437
$122.900
0.24
0.10
60
0.33
265
•*•••*«»*••
55.2
••«•*•*«»« *
$1.387 | $2.228
E-38
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TrPE: PACKAGED FIRETUBE
BOILER CAPACITY (HMBtu/hr): 2.9
FUEL TYPE: NATURAL GAS
CONTROL METHOD: FGR AND OXYGEN TRIM
CHAP. E REFERENCES
HUGH DEAN. 1988
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
**• TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP. SP (as required)
4. BUILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLOG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY (20 percent of direct and indirect)
** TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
SLOG
OCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
O.B
$23.546
$1.531
$843
$25.920
0.66
$23.546
$1,531
$843
$25.920
0.5
$23.546
$1.531
$843
$25.920
0.33
$23.546
$1.531
$843
$25.920
$8.764
$34,684
$4.873
$7,911
$47.468
$8.764
$34.684
$4.873
$7.911
$47.468
$8.764
$34.684
$4.873
$7.911
$47.468
$8.764
$34,684
$4,873
$7,911
$47.468
CONTINUED ON NEXT PAGE
E-39
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE; PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY • $0.05/kV-hr
6. STEAH
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS, N. GAS 8 $3.63/HHBtu
•*• TOTAL DIRECT ANNUAL COSTS *** ' DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. -OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
•*• TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
0.8
$500
$500
$235
($745)
$490
$600
$949
$475
$475
$2.499
$2.989
0.66
$500
$500
$194
($615)
$579
$600
$949.
$475
$475
$2.499
$3.078
COST BASE
1992 DOLLARS
0.5
$500
$500
$147
($466)
$681
$600
$949
$475
$475
$2.499
$3.180
0.33
$500
$500
$97
($307)
$790
$600
$949
$475
$475
$2.499
• X X KM • •*•*
$3.288
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOP
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) *»•
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx}2]/2000
*** COST EFFECTIVENESS {$/TON NOx REMOVED. 1992 DOLLARS) •**
10
O.I
0.1627
$47.468
$7,725
$2.989
$10.714
««**cxn*« m
0.12
0.07
40
0.8
2.9
0.5
$21.741
***********
•nttBB***K*:c
10
0.1
0.1627
$47.468
$7.725
$3.078
$10.803
0.12
0.07
40
0.66
2.9
0.4
1 $26.572
10
0.1
0.1627
$47,468
$7.725
$3.180
$10.905
0.12
0.07
40
0.5
2.9
»mmmmm**m.mM
0.3
m*xmmmm**mmm
**********«*i
$35.406
10
0.1
0.1627
$47.468
$7,725
$3.268
$11.013
0.12
0.07
40
0.33
2.9
0.2
************
I-***********
$54.179
E-40
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FJRETU8E CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. .BUILDINGS. BLOG (as required) BLOG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*"» TOTAL INDIRECT CAPITAL COST •** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(OCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$24.984
$1.624
$892
$27.500
0.66
$24.984
$1.624
$892
$27.500
0.5
$24.984
$1.624
$89?
$27.500
0.33
$24.984
$1.624
$892
$27.500
$9.290
J36.790
$5.300
$8.418
$50.508
$9.290
$36.790"
$5.300
$8.418
$50.508
$9.290
$36.790
$5.300
$8.416
$50.508
$9.290
$36.790
$5.300
$8.416
$50.508
CONTINUED ON NEXT PAGE
E-41
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS HUGH DEAN. 1986
CONTROL METHOD: F6R AND OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (DIM)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 6 $3.63/MMBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
0.8
$500
$500
$314
($1.330)
($17)
$600
$1.010
$505
$505
$2.620
$2.604
0.66
$500
$500
$259
($1.098)
$161
$600
$1.010
$505"
$505
$2.620
$2.781
COST BASE
1992 DOLLARS
O.S
$500
$500
$196
($832)
$365
$600
$1.010
$505
$505
$2.620
$2.985
0.33
$500
$500
$129
($549)
$581
$600
$1.010
$505
$505
$2.620
$3.201
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
**» ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&H
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HHBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) •**
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$50.508
$8.220
$2.604
$10.823
0.12
0.07
40
0.8
5.23
mmmmmmmmmmm
0.9
10
0.1
0.1627
$50.508
$8.220
$2.781
$11.001
0.12
0.07
40
0.66
5.23
0.7
10
0.1
0.1627
$50.508
$8.220
$2.985
$11.205
0.12
0.07
40
0.5
5.23
0.5
10
0.1
0 1627
«?0.508
$8.220
$3,201
$11.421
0.12
0.07
40
0.33
5.23
0.4
$12.304 $15.159 $20.380 $31.475
E-42
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*«* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. 6LDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+OIC+SP+BLOG)
8. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
D.8
$29,346
£1.907
$942
$32.195
0.66
$29.346
$1.907
$S42
$32.195
0.5
$29.346
$1.907
$942
$32.195
tmmmmmmwmmmm
0.33
$29.346
$1.907
$942
$32.195
$9.290
$41.485
$5.255
$9.348
$56,087
$9.290
$41.485
$5.255
$9.348
$56.087
$9.290
$41.485
$5.255
$9.348
$56.087
$9.290
$41.485
$5.255
$9.348
$56.087
CONTINUED ON NEXT PAGE
E-43
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
.. .....
FUEL TYPE: NATURAL GAS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kU-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS B $3.63/HMBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X Of SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+IAC)
0.8
$500
$500
$967
($2.661)
($694)
$600
$1.122
$561
J561
$2.843
$2.150
0.66
$500
$500
$798
($2.195)
($397)
$600
$1.122.
$561
$561
$2.843
$2.446
*.«•.*•••••.••.••«••••
•.••••••*....•••...•••»
COST BASE
1992 DOLLARS
****mmmmm**mmmm*mmm*mm*
0.5 0.33
$500
$500
$604
($1.663)
($59)
$600
$1.122
$561
$561
$2.843
$2.785
$500
$500
$399
($1.098)
$301
$600
$1.122
$561
$561
$2.643
• MVMKBWX
$3.145
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu^hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP'CF*(24 hr/day)*(365 days/yr)].*[(NOxn-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$56.087
$9.128
$2.150
***********
$11.278
mmmmmx JBKKXX
0.12
0.07
40
0.8
10.46
1.8
10
0.1
0.1627
$56.087
$9.128
$2.446
$11.574
0.12
0.07
40
0.66
10.46
1.5
10
0.1
0.1627
$56.087
$9.128
$2.785
$11.913
0.12
0.07
40
0.5
10.46
1.1
10
0.1
0.1627
$56.087
$9.128
$3.145
$12.273
0.12
0.07
40
0.33
10.46
0.7
$6.410 $7.974 $10.834 $16.912
..«.«.*..
E-44
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS HUGH DEAN, 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
••• TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLOG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
•** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
*«***••«••»
COST BASE
1992 DOLLARS
***mmmmmmmmmmmmmmm*mmmmm
BOILER CAPACITY FACTOR
0.8
$34.204
$2.224
$1.041
$37.469
0.66
$34.204
$2.224
$1.041
$37.469
0.5
$34.204
$2.224
$1.041
$37.469
0.33
$34.204
$2.224
$1.041
$37.469
$9.815
$47.284
$5.255
$10.508
$63.046
$9.815
$47,284
$5.255
$10.508
$63.046
$9.815
$47.284
$5.255
$10.508
$63,046
$9.815
$47.284
$5.255
$10.508
$63.046
CONTINUED ON NEXT PAGE
E-45
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRFTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5, ELECTRICITY « $0.05/kU-hr
6. STEAM
7. FUEL
6. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 9 $3.63/MMBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (I AC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
• AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCJC)
3. PROPERTY TAX (0.01MCIC)
4. INSURANCE (0.01'TCIC)
•** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+IAC)
mmmmmwmmmmmm
0.8
$500
$500
$3.790
($5.323)
($533)
$600
$1.261
$630
$630
$3.122
$2.589
mmmmmmm*mmmm
0.66
$500
$500
$3.127
($4.392)
($265)
$600
$1.261
$630
$630
$3.122
$2.857
COST BASE
1992 DOLLARS
mmmmm*mmmmmmmmmm*mmnmm*
0.5 0.33
$500
$500
$2.369
($3,327)
$42
$600
$1.261
$630
$630
$3,122
$3.164
$500
$500
$1.563
($2.196)
$368
$600
$1.261
$630
$630
$3.122
$3.490
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CA»IT,'L RECOVERY FACTOR
T0f,"i CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&H
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
•*• COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$63.046
$10.260
$2.589
$12.849
0:12
0.07
40
0.8
20.9
3.5
mmmmmm**m*tm
***********
$3.651
10
0.1
0.1627
$63.046
$10.260
$2,857
$13.118
0.12
0.07
40
0.66
20.9
2.9
10
0.1
0.1627
$63.046
$10.260
$3.164
$13.424
0.12
0.07
40
0.5
20.9
xmmmmmmmmmm
2.2
10
0.1
0.1627
$63.046
$10.260
$3.490
$13.750
0.12
0.07
40
0.33
20.9
mmmmmmmmmm*
1.5
$4.518 $6.103 $9.471
E-46
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS HUSH DEAN. 1988
CONTROL METHOD: FGR AND OXYGEN TRIM
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST V* DIC
3. SITE PREP, SP (as required) , SP
4. 'BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST "* ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** 'OTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.6
$37.971
$2.469
$1.091
$41.531
0.66
$37.971
$2,469
$1.091
$41.531
0.5
$37.971
$2.469
$1.091
$41.531
...........
0.33
$37.971
$2.469
$1.091
$41.531
$11.401
$52.932
$5,255
$11.637
$69.824
$11,401
$52.932"
$5.255
$11,637
$69.824
$11.401
$52.932
J5.255
$11.637
$69.824
$11.401
$52.932
$5.255
$11.637
$69,824
CONTINUED ON NEXT PAGE
E-47
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED FIRETUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr) • 33 5
FUEL TYPE: NATURAL GAS HUGH DEAN. 1988
CONTROL METHOD: F6R AND OXYGEN TRIM
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY « $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER: IX FUEL SAVINGS. N. GAS 6 {3.63/HHBtu
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$500
$500
$6.300
($8.517)
($1,217)
$600
$1.396
$698
$698
$3.393
$2.176
0.66
$500
$500
$5.197
($7.027)
($829)
$600
$1.396
$698
$698
$3.393
$2.564
««**•••*•••*•••*•*«••••
COST BASE
1992 DOLLARS
EHMnKMMfl
o.s
$500
{500
$3.937
{{5.323)
({386)
{600
{1.396
{698
{698
{3.393
$3.007
0.33
$500
$500
$2.599
($3.513)
$85
$600
$1.396
$698
$698
$3.393
$3.478
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
•** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP«CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$69.824
$11.363
$2.176
$13.539
0.12
0.07
40
O.S
33.5
5.6
$2,404
10
0.1
C.icZ?
$6b.a24
$11.363
$2.564
$13.927
0.12
0.07
40
0.66
33.5
4.6
$2.998
10
0.1
0.1627
{69.824
$11.363
$3.007
{14.371
0.12
0.07
40
0.5
33.5
3.5
10
0.1
0.1627
$69.824
$11.363
{3.478
.
{14.842
0.12
0.07
40
0.33
33.5
2.3
{4.083 $6.390
E-48
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARr AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST **• . PEC
2. DIRECT INSTALLATION COST (DIC)
**• TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLOG (as required) BLDG
"* TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TC1C
(DCC+ICC+CONT)
mmm mm «•«« *
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$121,300
0.66
$121,300
0.5
$121.300
0.33
$121.300
$85.000
$206.300
$24,260
$24.260
$24.260
$4.852
$2.426
J80.058
$57,272
$343,630
$85.000
$206.300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
$85.000
$206.300
$24.260
$24,260
$24.260
$4.852
$2,426
$80.058
$57,272
$343.630
$85.000
$206.300
$24.260
$24,260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
CONTINUED ON NEXT PAGE
E-49
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. E REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC;
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 3 yrs)
5. ELECTRICITY 8 $0.05/kW-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL (catalyst)
9. CHEMICALS (amnonia B $250/ton. 1 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
mmmmmmm***
0.8
$2,000
$16,667
$523
$4.167
$876
$24.232
$1.200
$6.873
$3.436
$3.436
$14.945
$39,177
COST BASE
1992 DOLLARS
0.66
$2.000
$16,667
$431
$4,167
$723
$23.987
$1.200
$6.873
$3.436
$3.436
$14.945
$38.933
0.5
$2.000
$16,667
$327
$4.167
$548
$23.708
$1.200
$6.873
$3,436
$3.436
$14,945
$38.653
0.33
$2.000
$16.667
$216
$4.167
$361
$23.410
$1.200
$6.873
$3.436
$3.436
$14,945
$38.356
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTb (TUC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST »** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$343.630
$55.924
$39.177
$95.101
0.16
0.02
85
0.8
50
BKXKSXBXK
23.8
10
0.1
0.1627
$343.630
$55.924
$38.933
$94,857
0.16
0.02
85
0.66
50
19.7
10
0.1
0.1627
$343.630
$55,924
$38,653
$94.577
0.16
0.02
85
0.5
50
14.9
10
0.1
0.1627
J343.630
$55.924
$38.356
$94.280
0.16
0.02
85
0.33
50
9.S
$3.991 $4,825 $6.351 $9.592
E-50
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*" TOTAL DIRECT INSTALLATION COST *"* DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) 8LDG
*" TOTAL DIRECT CAPITAL COST *** OCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (O.ZOPEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(OCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$152.600
0.66
$152.600
0.5
$152.600
0.33
$152.600
$107.000
$259.600
$30,520
$30.520
$30,520
$6,104
$3,052
$100.716
$72,063
$432.379
$107,000
$259.600
$30,520
$30,520
$30,520
$6.104
$3.052
$100.716
$72,063
$432,379
$107.000
$259,600
$30.520
$30,520
$30.520
$6.104
$3.052
$100.716
$72.063
$432.379
$107.000
$259.600
$30.520
$30.520
$30.520
$6.104
$3,052
$100.716
$72.063
$432.379
CONTINUED ON NEXT PA6E
E-51
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
ANNUAL OPERATINS AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 3 yrs)
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (ammonia 0 J250/ton. 2.1 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS "* DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$33.333
$523
$8.333
$1.840
$46.029
$1.200
J8.64B
$4.324
$4.324
$18.495
$64.524
0.66
$2.000
$33.333
$431
$8.333
$1.518
$45.616
$1.200
$8.648
$4.324
$4.324
$18.495
$64.111
0.5
$2.000
$33.333
$327
$8.333
$1.150
$45,143
$1.200
$8.648
J4.324
$4.324
$18,495
$63.638
0.33
$2,000
$33,333
$216
$8.333
$759
$44.641
$1.200
$8.648
$4.324
$4.324
$18.495
$63.136
COST EFFECTIVENESS
A. TOTAL ANNUALI2ED COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$432,379
$70.368
$64.524
$134,892
0.18
0.03
85
0.8
100
mmm*m**mm
53.6
10
0.1
0.1627
$432,379
$70.368
$64.111
$134,479
0.18
0.03
85
0.66
100
44.2
10
0.1
0.1627
$432.379
$70,368
$63.638
$134.006
0.18
0.03
85
0.5
100
33.5
10
0.1
0.1627
$432.379
$70.368
$63.136
$133.504
0.18
0.03
85
0.33
100
22.1
$2.516 | $3.040 | $3.999 $6.037
E-52
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS DAMON. 1987
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
I. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (QIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) '' SP
4. -"BUILDINGS, BLDG (as required) 6LD5
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SPtBLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.6
0.66
0.5
0.33
J492.271
$492.271
-
J492.271
J49J.271
CONTINUED ON NEXT PAGE
E-53
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS DAMON, 1987
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (DIM)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 2 yrs)
5. ELECTRICITY 0 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (amnonia 0 $250/ton)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *" DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$54.675
$6,700
$13.669
$4.400
$79,444
$0
$9.845
$4.923
$4.923
$19.691
$99.135
0.66
$54,675
$6,700
$13.669
$4,400
$79.444
$0
$9.845
$4.923
$4.923
$19.691
$99.135
0.5
$54.675
$6,700
$13.669
$4.400
$79.444
$0
$9.845
$"4,923
$4.923
$19,691
$99,135
0.33
$54.675
$6,700
$13.669
$4.400
$79.444
$0
$9.845
$4.923
$4.923
$19.691
$99.135
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (fncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *" ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
J492.271
$80.115
$99.135
$179.249
0.18
0.03
85
0.8
100
BBKKKXKBX
S3. 6
SBKBSXVKXI
10
0.1
0.1627
$492.271
$80,115
$99.135
$179.249
0.18
0.03
85
0.66
100
44.2
10
0.1
0.1627
$492.271
$80,115
$99.135
$179.249
0.18
0.03
85
0.5
100
33.5
10
0.1
0.1627
$492.271
$80.115
$99,135
$179.249
0.18
0.03
85
0.33
100
22.1
$3.344 | $4.053 $5.350 | $8.105
E-54
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
EOILER TYPE: PACKAGED KATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** . PEC
2. DIRECT INSTALLATION COST (DIG)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** OCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DO>ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$190.997
0.66
$190.997
0.5
$190.997
0.33
$190.997
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90.140
$540.838
$133.643
$324.640
$38.199
$38.199
$38,199
$7,640
$3.820
$126.058
$90.140
$540.838
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90,140
$540.836
$133,643
$324,640
$38.199
$38.199
$38.199
$7,640
$3.620
$126.058
$90.140
$540.636
CONTINUED ON NEXT PAGE
E-55
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr}- 150 —.—.„
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 3 yrs)
5. ELECTRICITY 0 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (ammonia » J250/ton, 3.3 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.6
$2.000
$50.000
$523
$12,500
$2.891
$67.914
$1.200
$10.817
$5.408
$5.408
$22.834
$90.747
*««**»*•*•««««*««*=
COST BASE
1992 DOLLARS
0.66
$2.000
$50.000
$431
$12.500
$2.385
$67.316
$1.200
$10,817
$5.408
$5.408
$22.834
$90.150
0.5
$2.000
$50.000
$327
$12.500
$1.807
$66,633
$1,200
$10,817
$5,408
$5,408
$22,834
$89.467
0.33
$2.000
$50.000
$216
$12,500
$1.192
$65.908
$1.200
$10.817
$5,408
$5.408
$22.834
$88.742
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPiTM INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*•* COST EFFECTIVENESS (J/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0.1627
$540.838
$88.019
$90,747
KMBcan*
$178.766
0.18
0.03
85
0.8
150
BO. 4
mm^mmm^mmi
10
0.1
0.1627
$540.838
$88.019
$90.150
$178.169
0.18
0.03
85
0.66
150
66.3
KKKSBXKKX
$2.223 $2.686
10
0.1
0.1627
$540.838
$88.019
$89.467
$177.486
0.18
0.03
85
0.5
150
50.3
10
0.1
0.1627
$540.838
$88.019
$88.742
$176.761
0.18
0.03
85
0.33
150
33.2
$3.531 $5.329
E-56
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
•** TOTAL PURCHASED EQUIPMENT COST *** PEC
Z. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLOG (as required) BLDG
*•* TOTAL DIRECT CAPITAL COST *** DCC
(PEC+D1C+SP+8LDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** . TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$230.900
0.66
$230.900
0.5
$230.900
0.33
$230.900
$161.600
$392.500
$46.180
$46.180
$46.180
$9.236
$4.618
$152.394
$108.979
$653.873
$161.600
$392.500
$46.180
$46.180
$46.180
$9.236
$4.618
$152.394
$108.979
$653,873
$161.600
$392.500
$46.180
$46.180
$46.180
$9.236
$4.618
$152.394
$108.979
$653.873
$161.600
$392.500
$46.180
$46.180
$46.180
$9.236
$4.618
$152.394
$108,979
$653.873
CONTINUED ON NEXT PAGE
E-57
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DACJ
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 3 yrs)
5. ELECTRICITY » $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (aimonla 9 $250/ton. 4.4 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (I AC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
•** TOTAL INDIRECT ANNUAL COSTS *** I AC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2,000
$66.667
$523
$16.667
$3.854
$89.711
$1,200
$13.077
$6.539
$6.539
$27.355
$117,065
0.66
$2.000
$66.667
$431
$16.667
$3.180
$88.945
$1.200
$13.077
$6.539
$6.539
$27,355
$116.299
0.5
$2.000
$66.667
$327
$16.667
$2.409
$68.069
$1.200
$13.077
$"6.539
$6.539
$27.355
$115.424
0.33
$2.000
$66.667
$216
$16.667
$1.590
$87,139
$1.200
$13,077
$6.539
$6.539
$27.355
$114,494
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/HMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP«CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0.1627
$653,873
$106.415
$117.065
$223.480
0.24
0.04
85
0.8
200
mmmxxmmmf
143.0
10
0.1
0.1627
$653.873
$106,415
$116.299
$222,714
0.24
0.04
85
0.66
200
117.9
10
0.1
0 162"
$653. J'3
$106.415
$115.424
$221.839
0.24
0.04
85
0.5
200
89.4
10
0.1
0.1627
$653,873
$106.415
$114.494
$220.909
0.24
0.04
85
0.33
200
59.0
$1.563 | $1.888 $2.483 $3.746
„
E-58
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS PEERLESS, 1992
CONTROL METHOD: SCR
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
**" TOTAL PURCHASED EQUIPMENT COST **» PEC
Z. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST V* DIC
3. SITE PREP. SP (as required) • SP
4. /BUILDINGS, BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
A. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
im*m*mmmm*mm*mmmmmm*
BOILER CAPACITY FACTOR
0.8
$270.100
0.66
$270.100
0.5
$270.100
0.33
$270.100
$189.000
$459.100
$54.020
$54.020
$54.020
$10,804
$5.402
$178.266
$127,473
$764.839
$189.000
$459.100
$54.020
$54.020
$54.020
$10.804
$5.402
$178.266
$127.473
$764.839
$189.000
$459,100
$54.020
$54.020
$54.020
$10.804
$5.402
$178.266
$127.473
$764.839
$189.000
$459.100
$54,020
$54,020
$54.020
$10.804
$5.402
$178.266
$127,473
$764,839
CONTINUED ON NEXT PAGE
E-59
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 3 yrs)
5. ELECTRICITY • $0.05/kV-hr
6. STEAM
7. FUEL
8. VASTE DISPOSAL (catalyst)
9. CHEMICALS (amnonla » $250/ton. 5.5 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60% OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+IAC)
0.8
$2.000
$83.333
$523
$20.833
$4.818
$111.507
$1.200
$15.297
$7.648
$7.648
$31.794
KMEXMCMK
$143.301
0.66
$2.000
$83.333
$431
$20.833
$3.975
$110.573
$1.200
$15.297
$7.648
$7.648
$31.794
$142.366
0.5
$2.000
$83.333
$327
$20.833
$3.011
$109.505
$1.200
$15.297
$7.648
$7.648
$31.794
$141.298
KKX**CX«CB
0.33
$2.000
$83.333
$216
$20.833
$1.987
$108.370
$1.200
$15.297
$7.648
$7.648
$31.794
$140.163
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIL. above)
*" ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&H. above) O&H
*** TOTAL ANNUALIZED COST *** ACIC+O&H
6. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) *** "
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$764.839
$124.474
$143.301
$267.775
0.24
0.04
85
0.8
250
178.7
$1.498
10
0.1
0.1627
$764,839
$124.474
$142.366
$266.840
0.24
0.04
85
0.66
250
147.4
KKS**K*«KX
$1.810
10
0.1
0.1627
$764,839
$124.474
$141.298
$265.772
0.24
0.04
85
0.5
250
111.7
10
0.1
0.1627
$764.839
$124.474
$140.163
$264.637
0.24
0.04
85
0.33
250
73.7
$2.380 | $3.590
E-60
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** . . PEC
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BL06
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
O.B
$121.300
0.66
$121.300
0.5
$121.300
0.33
$121.300
$85.000
$206.300
$24.260
$24.260
$24.260
$4.652
$2.426
$80.058
$57.272
$343.630
$85.000
$206.300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
$85.000
$206,300
$24.260
$24.260
$24.260
$4,652
$2.426
$80.058
$57,272
$343.630
$85.000
$206.300
$24.260
$24.260
$24.260
$4.652
$2.426
$80.058
$57,272
$343.630
CONTINUED ON NEXT PAGE
E-61
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)- 50
FUEL TYPE: NATURAL SAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 6 yrs)
5. ELECTRICITY » $0.05/kU-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (aimnnia 9 $2507 ton. 1 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$8.333
$523
$2.083
$876
$13.815
$1.200
$6.673
$3.436
$3.436
$14.945
$28.761
(*•«•»«••• 1
0.66
$2.000
$8.333
$431
$2.083
$723
$13.571
$1.200
$6.673
$3.436
$3.436
$14.945
$28.516
COST BASE
1992 DOLLARS
0.5
$2.000
$8.333
$327
$2.083
$548
$13.291
$1.200
$6.673
$3.436
$3.436
$14.945
$28.236
0.33
$2.000
$8.333
$216
$2.083
$361
$12.994
$1.200
$6.873
$3.436
$3.436
$14.945
$27.939
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
**• ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&H. above) • O&H
*** TOTAL ANNUALIZED COST *** AC1C+0&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
**« NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$343.630
$55,924
$28.761
$84.685
0.16
0.02
85
0.8
50
**»•**«**
23.8
10
0.1
0.1627
$343.630
$55.924
$28.516
$84.440
0.16
0.02
85
0.66
50
19.7
10
0.1
0.1627
$343.630
$55.924
$28.236
$84.160
0.16
0.02
65
0.5
50
14.9
10
0.1
0.1627
$343.630
$55.924
$27.939
$83.863
0.16
0.02
85
0.33
50
9.8
$3.554 $4.296 $5.651 $8.532
E-62
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE
BOILER CAPACITY (HMBtu/hr): 50
FUEL TYPE: NATURAL 6AS
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
CHAP. 6 REFERENCES
PEERLESS. 1992
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQPJ
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP. SP (as required)
4. BUILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
**» TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY (0.20*(DCC+ICC))
TOTAL CAPITAL INVESTMENT COST ***
(DCC+ICC+CONT)
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
$121.300
0.66
$121.300
0.5
$121.300
0.33
$121.300
$85.000
$206.300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.056
$57.272
$343.630
$85.000
$206.300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
J85.000
$2136. 300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
$85.000
$206.300
$24.260
$24.260
$24.260
$4.852
$2.426
$80.058
$57.272
$343.630
CONTINUED ON NEXT PAGE
E-63
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every B yrs)
5. ELECTRICITY « $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (amnonia 9 S250/ton, 1 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
8. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*»* TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.6
$2.000
$6.250
$523
$1.563
$876
$11.211
$1.200
$6.873
$3.436
$3.436
$14.945
$26.156
COST BASE
1992 DOLLARS
0.66
$2.000
$6.250
$431
$1.563
$723
$10.967
$1,200
$6.873
$3.436
$3.436
$14.945
$25.912
0.5
$2.000
$6.250
$327
$1.563
$548
$10.687
$1.200
$6.873
'$3,436
$3.436
$14.945
$25.632
0.33
$2.000
$6.250
$216
$1.563
$361
$10.390
$1.200
$6.873
$3.436
$3.436
$14.945
$25,335
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZEO COST *** ACIC+O&M
8. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*{365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
o :cr?
$34j,P30
$55.924
$26.156
$82.081
N i
: ~ 5
H OJ N O • •
N • N tn - O9 O •—
NCBN OODtnrOOT
10
0.1
0.1627
$343.630
$55,924
$25,912
$81,836
0.16
0.02
85
0.66
SO
19.7
10
0.1
0.1627
$343.630
$55.924
$25.632
$81.556
0.16
0.02
85
0.5
50
14:9
10
0.1
0.1627
J343.630
$55.924
$25.335
$81.259
0.16
0.02
85
0.33
50
9.8
$3.445 $4.163 $5,477 $8.267
E-64
-------
COST EFFECTIVENESS OF RETROFIT MOx COKTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL 6AS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE ANALYSIS
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQPj EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST''*** DIC
3. ^SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLD6
**» TOTAL DIRECT CAPITAL COST *** DCC
(PEC+D1C+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04 PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$190.997
0.66
$190.997
0.5
$190.997
0.33
$190.997
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90.140
$540.838
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90.140
$540.838
$133,643
J3"24.640
$38.199
{38.199
$38.199
$7.640
$3.820
$126.058
$90.140
$540.838
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90.140
$540.838
CONTINUED ON NEXT PAGE
E-65
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE ANALYSIS
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 6 yrs)
5. ELECTRICITY » $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (ammonia 8 $250/ton. 3.3 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$25.000
$523
$6.250
$2.891
$36.654
$1.200
$10.817
$5.408
$5.408
$22.834
$59.497
0.66
$2.000
$25.000
$431
$6.250
$2.385
$36.066
$1.200
$10.817
$5.408
$5.408
$22.834
$58.900
0.5
$2.000
$25.000
$327
$6.250
$1.807
$35,383
$1.200
$10.817
$5.408
$5.408
$22.834
$58.217
0.33
$2,000
$25.000
$216
$6.250
$1.192
$34.658
$1.200
$10.817
$5.408
$5.408
$22.834
$57.492
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY ff.CTOR
TOTAL CAPITAL IhV^TMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M, above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$540.838
$88.019
$59.497
$147.516
0.18
0.03
85
0.8
150
BO. 4
*********
$1.834
10
0.1
0.1627
$540.838
$88.019
$58.900
$146.919
0.18
0.03
85
0.66
ISO
66.3
10
0.1
0.1627
$540,838
$88.019
$58.217
$146.236
0.18
0.03
85
0.5
150
50.3
10
0.1
0.1627
$540,836
$88.019
$57.492
$145.511
0.18
0.03
85
0.33
150
33.2
$2.215
$2.910 | $4.387
E-66
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE ANALYSIS
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** ' PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLOG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+1CC+CONT)
BOILER CAPACITY FACTOR
0.8
$190.997
0.66
$190.997
0.5
$190.997
0.33
$190.997
$133.643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.620
$126.058
$90.140
$540.838
$133,643
$324.640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.056
$90.140
$540.838
$133.643
$324,640
$38.199
$38.199
$38.199
$7.640
$3.820
$126.058
$90,140
$540,838
$133.643
$324,640
$38.199
$38,199
$38,199
$7.640
$3.820
$126.058
$90.140
$540.838
CONTINUED ON NEXT PAGE
E-67
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE ANALYSIS
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 8 yrs)
5. ELECTRICITY 9 $0.05AV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (aimonia » $250/ton. 3.3 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01*TCIC)
4. INSURANCE (0.01*TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** • IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$18,750
$523
$4.688
$2.891
$28.851
$1.200
$10.817
$5.408
$5.408
$22.834
$51.685
0.66
$2.000
$18.750
$431
$4.688
$2,385
$28.254
$1.200
$10.817
$5.408
$5.408
$22.834
$51.087
0.5
$2.000
$18.750
$327
$4.688
$1.807
$27.571
$1.200
$10.817
$5.408
$5.408
$22.834
$50.405
0.33
$2.000
$16,750
$216
$4.688
$1.192
$26.846
$1.200
$10.817
$5.408
$5.408
$22.834
$49.679
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST "* ACIC+O&M
B. NOx REMOVAL PCR YEAR
1. BASELINE NOx LEVEL (Ib/HMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
*** NOx REMOVED PE!R YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*•* COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$540.838
$88.019
$51.685
$139.704
0.16
0.03
85
0.8
150
80.4
mmrn*mxmmmt
10
0.1
0.1627
$540.838
$88.019
$51.087
$139.106
0.18
0.03
85
0.66
150
66.3
10
0.1
0.1627
$540.838
$88.019
$50.405
$138.423
0.18
0.03
85
0.5
150
50.3
10
0.1
C.1627
»:'j,838
$88.019
$49.679
$137,698
0.18
0.03
85
0.33
150
33.2
$1,737 $2.097 $2.754 $4.151
E-68
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS, 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EOF) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST **.* PEC
2. DIRECT INSTALLATION COST (DIC)
*" TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *•• DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$270.100
0.66
$270.100
0.5
$270.100
0.33
$270.100
$189,000
$459.100
$54.020
$54.020
$54.020
$10,804
$5,402
$178.266
$127.473
$764.839
$189.000
$459.100
$54.020
$54.020
$54.020
$10.804
$5,402
$178.266
$127.473
$764.839
$189,000
»59.100
$54.020
J54.020
$54.020
$10,804
$5,402
$178.266
$127,473
$764.839
$189.000
$459,100
$54.020
$54.020
$54,020
$10,804
$5,402
$178.266
$127.473
$764,839
CONTINUED ON NEXT PAGE
E-69
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual Inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 6 yrs)
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAK
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS (aimonia t $250/ton. 5.5 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01»TC1C)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$41.667
$523
J10.417
$4.818
$59.424
$1.200
$15.297
$7.648
$7.648
$31.794
$91.218
0.66
$2.000
$41,667
$431
$10.417
$3.975
$58.489
$1.200
$15.297
$7.648
$7.648
$31.794
$90.283
0.5
$2.000
$41,667
$327
$10.417
$3.011
$57,421
$1.200
$15,297
'$7.648
$7.648
$31.794
$89,215
0.33
$2.000
$41,667
$216
$10.417
$1.987
$56,286
$1.200
$15.297
$7.648
$7.648
$31.794
$88.080
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&H COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/HMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$764.839
$124.474
$91.218
$215.692
0.24
0.04
85
0.8
250
178.7
10
0.1
0.1627
$764.839
$124,474
$90.283
$214.757
0.24
0.04
85
0.66
250
147.4
10
0.1
0.1627
$764.839
$124,474
$89,215
$213.689
0.24
0.04
85
0.5
250
111.7
10
0.1
0.1627
$764.839
$124.474
$88.080
$212.554
0.24
0.04
85
0.33
250
73.7
$1.207 $1.457 $1.913 $2.883
E-70
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
••* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST'*** DIC
3. .SITE PREP. SP (as required) SP
4. BUILDINGS, BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+D1C+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING (0.20PEC)
2. CONSTRUCTION AND FIELD EXPENSES (0.20PEC)
3. CONSTRUCTION FEE (0.20PEC)
4. STARTUP (0.04PEC)
5. PERFORMANCE TEST (0.02PEC)
"* TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (0.20*(DCC+ICC)) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$270.100
0.66
$270.100
0.5
$270.100
0.33
$270.100
$189.000
$459.100
$54.020
$54.020
$54.020
$10.804
$5.402
$178.266
$127.473
$764.839
$189.000
$459.100
$54.020
$54.020
$54.020
$10.804
$5.402
$178,266
$127.473
$764.839
$189,000
$459.100
$54.020
$54,020
$54.020
$10.804
$5.402
$178.266
$127,473
$764,839
$189.000
$459.100
$54.020
$54.020
$54,020
$10.804
$5.402
$178.266
$127.473
$764.639
CONTINUED ON NEXT PAGE
E-71
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
««»**«**»»***«»»»"»»«»«»"»"»*»«*»*«*«««*«»«*"**«»»«»B»««*««*««*«*»»»»«««*«**«»»*««»m«»«««««»«»««i
BOILER TYPE: FIELD ERECTED UATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)' 250
FUEL TYPE: NATURAL GAS PEERLESS. 1992
CONTROL METHOD: SCR - VARIABLE CATALYST LIFE
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR (semi-annual inspection)
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement every 8 yrs)
5. ELECTRICITY 8 $0.05/kW-hr
6. STEAM
7. FUEL
8. tttSTE DISPOSAL (catalyst)
9. CHEMICALS (anmonia t $250/ton. 5.5 Ib/hr)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02'TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$2.000
$31.250
$523
$7.813
$4.818
$46.403
$1.200
$15.297
$7.648
$7.648
$31.794
$78.197
***«*KV*KMKm«C*KKB
COST BASE
1992 DOLLARS
0.66
$2.000
$31.250
$431
$7.813
$3.975
$45.469
$1.200
$15.297
$7.648
$7.648
$31.794
$77,262
0.5
$2.000
$31.250
$327
$7.813
$3,011
$44,400
$1.200
$15.297
'$7.648
$7.648
$31.794
$76,194
0.33
$2.000
$31.250
$216
$7.813
$1.987
$43.266
$1.200
$15,297
$7.648
$7.648
$31.794
$75,059
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST »** ACIC-KJ&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$764.839
$124.474
$78.197
$202,671
0.24
0.04
85
0.8
250
178.7
10
0.1
0.1627
$764.839
$124,474
$77.262
$201.736
0.24
0.04
85
0.66
250
147.4
10
0.1
0.1627
J764.B39
$124,474
$76.194
$200.668
0.24
0.04
85
0.5
250
111.7
10
0.1
0.1627
$764.839
$124.474
$75.059
$199,533
0.24
0.04
85
0.33
250
73.7
$1.134 $1.368 $1.797 | $2.707
E-72
-------
APPENDIX F. ANNUAL COSTS OF RETROFIT NOX CONTROLS:
COAL-FIRED ICI BODLERS
This appendix contains cost spreadsheets for coal-fired boilers retrofitted with various NOX
controls. The spreadsheets are based on data from actual boiler retrofit experiences or studies.
Capital annualization for all analyses are based on a 10-year amortization period and a 10 percent
interest rate. All costs presented are in 1992 dollars. For further information on the methodology
and assumptions made in these cost analyses, see Chapter 6.
This appendix contains cost spreadsheets for the following boilers:
Boiler and NOX Control Page
Field-erected watertube, 766 MMBtu/hr, with LNB F-3
FBC boiler, 460 MMBtu/hr, with urea-based SNCR F-5
Field-erected watertube, 760 MMBtu/hr, with SCR F-7
Boiler, 800 MMBtu/hr, with ammonia-based SNCR F-9
Tangential-fired, 1,255 MMBtu/hr, with ammonia-based SNCR F-ll
PC boiler, 2,361, 2,870, and 6,800 MMBtu/hr, with ammonia-based SNCR F-13
Coal-fired, 8,055 MMBtu/hr, with ammonia-based SNCR F-19
Wall-fired, 400 MMBtu/hr, with urea-based SNCR F-21
Spreader stoker, 303 MMBtu/hr, with urea-based SNCR F-23
F-l
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: COAL CIBO. 1992
CONTROL METHOD: LOW NOx BURNER
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** . PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
**• TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent of direct and indirect) CONT
*** TOTftu CAPITAL INVESTMENT COST *** . TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$1.195.653
$59.783
$62.772
$1.318.207
0.66
$1.195.653
$59,783
$62.772
$1.318.207
0.5
$1.195.653
$59,783
$62.772
$1,318.207
0.33
$1.195.653
$59.783
$62.772
$1.318.207
$655.616
$1.973.823
$278.986
$165.399
$49.819
$79,710
$39.855
$613.768
$517.518
$3.105.110
$655.616
$1.973.823
$278.986
$165.399
$49.819
$79.710
$39.855
$613.768
$517.518
$3.105.110
$655.616
$l-.973.823
$278.986
$165.399
$49,819
$79,710
$39.655
$613,768
$517.518
$3.105.110
$655.616
$1.973,823
$278.986
$165,399
$49.819
$79,710
$39.855
$613.768
$517.518
$3.105.110
CONTINUED ON NEXT PAGE
F-3
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: COAL CIBO, 1992
CONTROL METHOD: LOU NOx BURNER
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY » $0.05/kW-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS **' OAC
B. INDIRECT ANNUAL COSTS (I AC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
""* TOTAL INDIRECT ANNUAL COSTS *** IAC
••* TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
tmmttmmmmmmmm*
0.8
$21.105
$24.120
$50.250
$33.440
$126.915
$25.125
$49.848
$24.924
$24.924
$124,821
$253,736
COST BASE
1992 DOLLARS
0.66
$21.105
$24,120
$50.250
$27.588
$123.063
$25.125
$49.848
$24.924
$24.924
$124.821
$247.884
0.5
$21.105
$24.120
$50.250
$20.900
$116.375
$25.125
$49.848
$24.924
"$24.S24
$124.821
$241.196
0.33
$21.105
$24.120
$50.250
$13.794
$109.269
$25.125
$49.848
$24.924
$24.924
$124.821
$234.090
""
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&H)
1. ANNUALIZEO CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*«* ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** AC1C+0&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]* [(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$3.105.110
$505.342
$253,736
$759.078
0.7
0.35
50
0.8
766
939.4
$808
10
0.1
0.1627
$3.105.110
$505.342
$247.884
$753.226
0.7
0.35
50
0.66
766
775.0
$972
10
0.1
0.1627
$3.105.110
$505.342
$241.196
$746.538
0.7
0.35
50
0.5
766
587.1
10
0.1
0.1627
$3.105,110
$505.342
$234.090
$739.432
0.7
0.35
50
0.33
766
387.5
$1.271 1 $1,908
F-4
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: CIRCULATING FLU10IZED BED CHAP. 6 REFERENCES
FUEL TYPE: COAL HALCO FUEL TECH. 1992
CONTROL METHOD: SNCR - UREA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
**• TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (QIC)
*** TOTAL DIRECT INSTALLATION COST *** '' D1C
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BL03
*•* TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
**" TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER
O.B
tmmmmmmmm****
CAPACITY FA(
0.66
COST BASE
1992 DOLLARS
tmmmmmmmmmmmm
.TOR
0.5
tmmm»mm***mm
0.33
$680.930
$680.930
-
$680.930
$680.930
CONTINUED ON NEXT PAGE
F-5
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: CIRCULATING FLUIDIZED BCD CHAP. 6 REFERENCES
FUEL TYPE: COAL NALCO FUEL TECH. 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 8 $O.OS/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
o.e
W«*««KBBKB*
$197.186
0.66
$166.116
COST BASE
1992 DOLLARS
0.5
-
$130.608
0.33
$92.880
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL. RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL Ilb/MMBtu) (N0x}2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
"•* NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
**• COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
1680.930
$110.818
$197.186
$308.004
0.32
0.08
75
0.8
460
386.8
10
0.1
0.1627
$680.930
$110.818
$166.116
$276.934
0.32
0.08
75
0.66
460
319.1
10
0.1
0.1627
$680,930
$110.818
$130.608
$241.426
0.32
0.08
75
0.5
460
241.8
$796
$868 | $999
10
0.1
0 !6?7
$6b2 930
$110.818
$92.880
$203.698
0.32
0.08
75
0.33
460
««••«*•*•••
159.6
f*mmm*mmmmmm
$1.277
F-6
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FIELD ERECTED UATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: COAL UTILITY BOILERS ACT. 1994
CONTROL METHOD: SCR
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
AMMONIA STORAGE AND HANDLING EQP
SCR REACTOR (no catalyst)
FLUE GAS HANDLING
AIR HEATER MODIFICATIONS
CATALYST ($400/CFT)
FANS
MISCELLANEOUS
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLOG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (20 percent 'if direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$309.347
$1.003,377
$1.698.741
$382.683
$3.129,471
$50.669
$93.337
$6.667.626
0.66
$309.347
$1.003.377
$1.698.741
$382.683
$3.129,471
$50.669
$93.337
$6.667,626
0.5
$309.347
$1.003.377
$1.698.741
$382.683
$3.129.471
$50.669
$93.337
$6.667.626
0.33
$309.347
$1.003.377
$1.698.741
$382.683
$3,129.471
$50.669
$93.337
$6.667.626
INCLUDED
$6.667,626
$634.387
$1,509,031
$754.665
$67.788
$33.894
$2.999,765
$1.933,478
$11.600.869
INCLUDED
$6,667.626
$634,387
$1.509.031
$754.665
$67,788
$33.894
$2.999,765
$1,933,478
$11.600,869
INCLUDED
-
$6.667.626
$634.387
$1.509.031
$754.665
$67.788
$33.894
$2.999.765
$1.933,478
$11,600,869
INCLUDED
$6.667.626
$634.387
$1.509.031
$754,665
$67,788
$33.894
$2.999.765
$1.933.478
$11.600.869
CONTINUED ON NEXT PAGE
F-7
-------
COST EFFECTIVENESS OF RETROFIT
BOILER TYPE:
BOILER CAPACITY
FUEL TYPE:
CONTROL METHOD:
FIELD ERECTED
(HHBtu/hr):
COAL
SCR
NOx CONTROLS
WATERTUBE
766
CHAP.
UTILITY
6
REFERENCES
BOILERS
ACT.
1994
COST
1992
BASE
DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS (catalyst replacement) 4 YEARS LIFE
5. ELECTRICITY 9 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL (catalyst)
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1 . OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*" COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) ***
0.8
$96.480
$55.275
$948.324
$251.515
$9.600
$30.455
$49,600
$1.441,249
$91,455
$139,690
$169,845
$169,845
$570.835
$2.012.084
10
0.1
0.1627
$11.600.869
$1.887.988
$2.012.084
$3.900.072
0.7
0.14
80
0.8
766
1503
$2.595
0.66
$96.480
$55.275
$782.368
$207.500
$7.920
$25.125
$40.920
$1.215.588
$91.455
$139.690
$169.845
$169.845
$570.835
$1.786,423
10
0.1
0.1627
$11.600,869
Jl. 887. 988
$1.786.423
$3.674.411
0.7
0.14
80
0.66
766
1240
$2.963
0.5
$96.480
$55.275
$592.703
$157.197
$6.000
$19.034
$31.000
$957.689
$91.455
$139.690
$169.845
$169.845
$570.835
$1.528.524
10
0.1
0.1627
$11,600,869
$1,887,988
$1.528.524
$3.416,512
0.7
0.14
80
0.5
766
939
| $3,637
0.33
$96.480
$55.275
$391.184
$103,750
$3.960
$12,563
$20.460
$683.671
$91.455
$139.690
$169.845
$169.845
$570.835
$1,254.506
10
0.1
0.1627
$11.600,869
$1.887.988
$1,254.506
$3.142.494
0.7
0.14
80
0.33
766
620
$5.068
F-8
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1990
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
•** TOTAL PURCHASED EQUIPMENT COST *** . PEC
2. DIRECT INSTALLATION COST (DIG)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS, BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. ONE-TIME ROYALITY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST **" TCIC
(DCMCC+CDNT)
BOILER CAPACITY FACTOR
0.8
$265.776
$7,973
$13.289
$287.038
0.66
$265.776
$7.973
$13,289
$287,038
0.5
$265.776
$7.973
$13.289
$287.038
0.33
$265,776
$7.973
$13.289
$287.038
$89.910
$376.948
$66.222
$36.999
$32,071
$134.179
$269.471
$76.836
$723.255
$89.910
$376.948
$66,222
$36.999
$32.071
$134.179
$269.471
$76.836
$723,255
$89.910
- $376,948
$66.222
$36.999
$32.071
$134,179
$269.471
$76.836
$723,255
$89.910
$376,948
$66.222
$36,999
$32.071
$134,179
$269,471
$76.836
$723,255
CONTINUED ON NEXT PAGE
F-9
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6
RflTI FR TAPACTTV fUMR+u/hrl • ROfl .........
FUEL TYPE: COAL Exxon. 1990
CONTROL METHOD: SNCR - AMMONIA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (» $250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF LABOR & MAINTENANCE MAIL)
2. ADMINISTRATIVE (2X OF TC1C)
3. PROPERTY TAX (IX OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC* I AC)
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAP.TAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx)?
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF»(24 hr/day)*(365 days/yr)]*[(NDx)l-(NOx}2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
REFERENCES
0.8
$612. BSD
$324.120
$936.970
$14.465
17.233
J7.233
$28.930
$965.900
10
0.1
0.1627
$723.255
$117.706
$965,900
$1.083.606
0.7
0.39
45
0.8
800
883
J1.2Z7
0.66
$505.601
$267.399
$773.000
$14,465
$7.233
$7,233
$28.930
$801.930
10
0.1
0.1627
$723.255
$117.706
$601.930
$919.637
0.7
0.39
45
0.66
800
728
$1.262
COST BASE
1992 DOLLAR
0.5
$383.031
$202.575
$585,606
$14.465
$7.233
$7.233
$28,930
$614.536
10
0.1
0 1627
$723.255
$117.706
$614.536
$732,243
0.7
0.39
45
0.5
800
552
$1.327
S
0.33
$252.800
$133.700
$386.500
$14.465
$7.233
$7.233
$28.930
$415.430
10
0.1
0.1627
$723.255
$117.706
$415.430
$533.137
0.7
0.39
45
0.33
800
364
$1.464
F-10
-------
COST EFFECTIVENESS OF RETROFIT HOx CONTROLS
BOILER TYPE: TANGENTIAL FIRED UTILITY BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1991
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREISHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** "' DIC
3. SITE PREP. SP (as required) SP
«•
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4, ONE-TIME ROYALITY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$414.985
$12.450
$20.749
$448.164
0.66
$414.985
$12.450
$20.749
$448.184
O.S
$414.985
$12.450
$20.749
$448.184
0.33
$414.985
$12.450
$20.749
$448.184
$196.519
$644.703
$88.195
$80.868
$124.203
$169.037
$462.302
$140,695
$1.247.701
$196,519
$644.703
$88.195
$80,868
$124,202
$169.037
$462.302
$140.695
$1.247.701
$196.519
- $644.703
$88.195
J80.868
$124,202
$169.037
$462.302
$140.695
$1,247.701
$196,519
$644.703
$88.195
$80.868
$124.202
$169.037
$462.302
$140.695
$1.247.701
CONTINUED ON NEXT PAGE
F-ll
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: TANGENTIAL FIRED UTILITY BOILER CHAP. 6
BOILER CAPACITY (MMBtu/hr)' 1255 -
FUEL TYPE: COAL Exxon. 1991
CONTROL METHOD: SNCR - AMMONIA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (8 J250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (I AC)
1. OVERHEAD (60X OF LABOR & MAINTENANCE MAIL)
2. ADMINISTRATIVE (2X OF TCIC)
3. PROPERTY TAX (IX OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/dav)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED, 1992 DOLLARS) ***
REFERENCES
0.8
1220.051
$711.750
)931.801
$24,954
$12,477
112.477
$49.908
$981.709
10
0.1
0.1627
$1.247.701
$203.058
$981.709
$1.184.767
0.7
0.39
45
0.8
1255
1385
$855
0.66
$181.542
$587.194
$768.736
$24.954
$12.477
$12.477
$49,908
$818.644
10
0.1
0.1R'7
$1,24/,70.
$203.058
$818.644
$1.021.702
0.7
0.39
45
0.66
1255
1143
$894
COST BASE
1992 DOLLAR
0.5
$137.532
$444,844
$582,376
$24.954
$12.477
$12.477
$49.908
$632.284
10
0.1
0 1627
$1.247,701
$203,058
$632.284
$835,341
0.7
0.39
45
0.5
1255
866
I $965
S
0.33
J90.771
$293.597
$384.368
$24.954
$12.477
$12.477
$49.908
$434.276
10
0.1
0.1627
$1.247.70!
$203.058
$434.276
$637.334
0.7
0.39
45
0.33
1255
571
$1.115
F-12
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PC BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon, 1992
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** . PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *" DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*" TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. ONE-TIME ROYALITY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$463.810
$13.914
$23.191
1500.915
0.66
$463,810
$13.914
$23.191
$500.915
0.5
$463.810
$13.914
$23.191
$500.915
0.33
$463.810
$13.914
$23.191
$500,915
1114.420
$615.335
$328.950
$35,017
$47,600
$506.100
$917,667
$154,035
$1.687,037
$114.420
$615.335
$328.950
$35.017
$47.600
$506.100
$917.667
$154,035
$1.687.037
$114.420
- $615.335
$328.950
$35.017
$47,600
$506.100
$917.667
$154.035
$1.687.037
$114,420
$615,335
$328.950
$35.017
$47.600
$506.100
$917.667
$154.035
$1.687.037
CONTINUED ON NEXT PAGE
F-13
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PC BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1992
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 6 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (8 J250/TON)
10. OTHER
"* TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF LABOR & MAINTENANCE HATL)
2. ADMINISTRATIVE (2X OF TCJC)
3. PROPERTY TAX (IX OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
1283.824
$952.650
Jl. 236. 474
J33.741
J16.870
$16.870
$67.481
Jl. 303. 955
0.66
$234.155
$785.936
$1,020.091
$33.741
$16.870
$16.870
$67.481
$1.087.573
0.5
$177.390
$595.406
$772.796
$33.741
J16.870
' S:6.870
$67.481
$840.278
0.33
$117.077
$392.968
$510.046
$33.741
$16.870
$16.870
$67.481
$577.527
COST EFFECTIVENESS
A. TOTAL ANNUAL1ZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx}2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0.1627
$1.687.037
$274.558
$1.303.955
$1.578.513
0.7
0.39
45
0.8
2361
2606
10
0.1
0.1627
$1.687,037
$274.558
$1.087.573
$1.362.130
0.7
0.39
45
0.66
2361
2150
10
0.1
0.1627
$1.667.037
$274.558
$640.278
$1.114.835
0.7
0.39
45
0.5
2361
1629
10
0.1
0.1627
$1,687.037
$274.558
$577,527
$852,085
0.7
0.39
45
0.33
2361
1075
$606 $634 $684 $793
F-14
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6 REFERENCES
FUEL TYPE: PULVERIZED COAL Exxon. 1989
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** • PEC
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST *** OIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. OHE-TIHE ROYAL1TY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST •** • TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.6
$566,549
$16.996
$28.327
$611,873
0.66
$566.549
$16.996
$28.327
$611.873
0.5
$566.549
$16.996
$28.327
$611.873
0.33
$566.549
$16.996
$28.327
$611.873
$184.494
$796.367
$326.368
$65.034
$116.607
$901,397
$1.409,406
$195.656
$2.401,430
$184.494
$796.367
$326.368
$65.034
$116.607
$901.397
$1.409.406
$195.656
$2.401.430
$184.494
" $796.367
$326.366
$65.034
$116.607
$901.397
$1.409.406
$195.656
$2.401,430
$184.494
$796.367
$326.368
$65,034
$116.607
$901.397
$1.409.406
$195.656
$2.401.430
•CONTINUED ON NEXT PAGE
F-15
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6
BOILER CAPACITY (MHBtu/hrl* 2870
FUEL TYPE: PULVERIZED COAL Exxon. 1989
CONTROL METHOD: SNCR - AMMONIA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (8 J250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF LABOR t, MAINTENANCE MAIL)
2. ADMINISTRATIVE (2X OF TCIC)
3. PROPERTY TAX (IX OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&H
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** UAy RPMnVFn PFR YFAR FTflN^/VDl ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) «**
REFERENCES
0.8
$380,885
J996.450
$1.377.335
$0
148.029
$24.014
$24.014
$96.057
$1.473,392
10
0.1
0.1627
$3.401.430
$390.822
$1.473.392
$1.864.214
0.7
0.39
45
0.8
2870
3168
$588
0.66
$314.230
$822,071
$1.136.301
$0
$48.029
$24.014
$24,014
$96.057
$1.232.358
10
0.1
0.1627
$2,401.430
$390.822
$1.232.358
$1.623.180
0.7
0.39
45
0.66
2870
2613
$621
COST BASE
1992 DOLLAR
0.5
$238,053
$622,781
$860.634
$0
$48,029
$24.014
- $24.014
$96,057
$956,891
10
0.1
0.1627
$2.401.430
$390.822
$956.891
$1.347.713
0.7
0.39
45
0.5
2870
I960
| $681
S
0.33
$157.115
$411.036
$568.151
$0
$48.029
$24.014
$24.014
$96.057
$664.208
10
0.1
o.ier
$2. 401. .Mr
$390.822
$664.208
$1.055.029
0.7
0.39
45
0.33
2870
1307
$807
F-16
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PC BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1992
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
•** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIG)
*** TOTAL DIRECT INSTALLATION COST *** _.- DIG
3. SITE PREP. SP (as required) ' SP
4. BUILDINGS. BLOG (as requires) BIDG
*** TOTAL DIRECT CAPITAL COST •" DCC
(PEC+D1C+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. ONE-TIME ROYALITY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *" ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$1.006.700
$30.201
$50.335
$1,087.236
0.66
$1.006.700
$30.201
$50.335
$1.087.236
0.5
$1.006.700
$30.201
$50.335
$1.087,236
0.33
$1.006.700
$30.201
$50.335
$1.087,236
$214.610
$1.301.846
$392.500
$90,780
$89,280
$950,000
$1.522.560
$281.161
$3.105.567
$214.610
$1.301.846
$392.500
$90.780
$89.280
$950,000
$1.522.560
$281.161
$3.105.567
$214,610
-$1.301.846
$392.500
$90.780
$89,280
$950.000
$1.522.560
$281,161
$3.105,567
$214.610
$1.301.846
$392.500
$90.780
$89,280
$950.000
$1,522.560
$281.161
$3.105.567
CONTINUED ON NEXT PAGE
F-17
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PC BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon, 1992
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (9 S250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF LABOR & MAINTENANCE MAIL)
2. ADMINISTRATIVE (2X OF TCIC)
3. PROPERTY TAX (IX OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
**• TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$833.952
12.923.650
J3. 757. 602
S62.1U
$31.056
$31.056
$124.223
$3.881.825
0.66
$688.010
$2.412.011
$3.100.022
$62,111
$31 . 056
$31,056
$124.223
$3.224,244
0.5
$521,220
$1.827,281
$2.348.501
$62,111
$31,056
- $31,056
$124,223
$2.472.724
0.33
$344,005
$1.206.006
$1.550,011
$62.111
$31.056
$31.056
$124.223
$1,674,234
COST EFFECTIVENESS
A'. TOTAL ANNUAL1ZEO COST (incl. capital and O&M)
1. ANNUALIZEO CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
J3. 105. 567
$505.417
$3.881.825
$4.387,241
0.7
0.39
45
0.8
6800
7506
10
0.1
0.1627
$3.105.567
$505.417
$3.224.244
$3.729.661
0.7
0.39
45
0.66
6800
6192
10
0.1
0.1627
$3.105.567
$505.417
$2. 472, 724
$2.978,141
' 0.7
0.39
45
0.5
6800
4691
10
0.1
0.1627
$3.105.567
$505.417
$1.674.234
•
$2.179.650
0.7
0.39
45
0.33
6800
3096
$585 $602 $635 $704
F-18
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1990
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** .PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST **• DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS, BLDG (as required) BLDG
*•* TOTAL DIRECT CAPITAL COST •** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
Z. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. ONE-TIME ROYALITY FEE (NO CONTINGENCY ON THIS)
5. OTHERS
*** TOTAL INDIRECT CAPITAL COST *•» ICC
C. CONTINGENCY (15 percent of direct and indirect) CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(OCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$1.076.918
$32.366
$53.946
$1,165.231
0.66
$1.078.918
$32.368
$53.946
$1.165.231
0.5
$1.078.918
$32.368
$53.946
$1.165,231
0.33
$1.078.918
$32.368
$53.946
$1.165.231
$1.085.967
$2.251.198
$397.369
$121.081
$119.459
$1.680.539
$2.318.449
$433.366
$5.003.013
$1,085.967
$2.251,198
$397,369
$121.081
$119.459
$1.680.539
$2.318.449
$433.366
$5.003.013
$1.085.967
$2.251.198
$397.369
$121.081
$119.459
$1,680.539
$2.318.449
$433.366
$5,003.013
$1.085.967
$2.251.198
$397,369
$121,081
$119.459
$1.680,539
$2.318.449
$433.366
$5.003.013
CONTINUED ON NEXT PAGE
F-19
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: BOILER CHAP. 6 REFERENCES
FUEL TYPE: COAL Exxon. 1990
CONTROL METHOD: SNCR - AMMONIA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. AMMONIA (» $250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS **' DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (BOX OF LABOR & MAINTENANCE MATL)
2. ADMINISTRATIVE (2X OF TCIC)
3. PROPERTY TAX (1% OF TCIC)
4. INSURANCE (IX OF TCIC)
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$1. 178, 746
$2.474.700
13,653.446
$100.060
$50.030
$50.030
$200.121
$3.853.566
0.66
$972.465
$2.041.628
$3.014.093
$100.060
$50.030
$50,030
$200.121
$3.214.213
0.5
$736.716
$1.546.688
$2.283.404
$100.060
$50.030
$50.030
$200.121
$2.483.524
0.33
$486.233
$1.020.814
$1.507.046
$100.060
$50.030
$50.030
$200.121
$1.707.167
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPIT/L INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
S. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$5,003,013
$814,217
$3.853,566
$4.667.784
0.7
0.39
45
0.6
8055
8891
10
0.1
0.1627
J5. 003. 013
$814.217
$3.214,213
J4. 028. 431
0.7
0.39
45
0.66
8055
7335
10
0.1
0.1627
$5.003.013
$814,217
$2.483.524
$3.297.741
0.7
0.39
45
0.5
BOSS
5557
10
0.1
0.1627
$5.003.013^
$814,217
$1.707,167
$2.521,384
0.7
0.39
45
0.33
8055
3667
$525 $549 $593 $688
F-20
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: WALL-FIRED CHAP. 6 REFERENCES
FUEL TYPE: PULVERIZED COAL NALCO FUEL TECH. 1994
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEH SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required BLDG
*** TOTAL DIRECT CAPITAL COST *" DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST «*• ICC
C. CONTINGENCY (10 PERCENT - Not considered by NALCO) CONT
*** TOTAL CAPITAL INVESTMENT COST *** iCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
$580.000
$560.000
0.66
$580.000
$580.000
0.5
$580.000
$580.000
0.33
$580.000
$580,000
$177,000
$757.000
Included
$75.700
$832.700
$177.000
$757.000
Included
$75.700
$832.700
$177,000
$-757.000
Included
$75.700
$832.700
$177.000
$757,000
Included
$75.700
$832.700
CONTINUED ON NEXT PAGE
F-21
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: WALL-FIRED CHAP. 6 REFERENCES
FUEL TYPE: PULVERIZED COAL NALCO FUEL TECH. 1994
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
{10.600
$8.376
$303.059
$322.035
Included
$322.035
0.66
$10.600
$6.911
$227.294
$244.805
Included
$244.805
0.5
$10.600
$5.235
$189.412
$205.247
-
Included
$205.247
• 0.33
$10.600
$3.455
$125.012
$139.067
Included
$139.067
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
•** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]'[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$832.700
$135.518
$322.035
$457.553
0.7
0.39
45
0.8
400
441.5
10
0.1
0.1627
$832,700
$135,518
$244.805
$380,323
0.7
0.39
45
0.66
400
364.2
10
0.1
? 1627
J»V2.700
$135,518
$205.247
$340.765
0.7
0.39
45
0.5
400
275.9
10
0.1
0.1627
$832,700
$135.518
$139.067
$274,585
0.7
0.39
45
0.33
400
182.1
$1.036 $1.044 $1.235 $1.508
F-22
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: SPREADER STOKER CHAP. 6 REFERENCES
FUEL TYPE: COAL NALCO FUEL TECH. 1992
CONTROL HETHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
CEM SYSTEM
INSTRUMENTATION
SALES TAX
FREIGHT
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** • ' OIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST «** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$360.360
$360.360
-
$360.360
$360.360
CONTINUED ON NEXT PAGE
F-23
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: SPREADER STOKER CHAP. 6 REFERENCES
BOILER CAPACITY (MHBtu/hr)* 303
FUEL TYPE: COAL NALCO FUEL TECH. 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 $0.05/kW-hr
E. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1 . OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
5. OTHER
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+1AC)
0.8
1366.912
0.66
$302.702
0.5
-
$229.320
0.33
$151.351
COST EFFECTIVENESS
A. TOTAL ANNUALI2ED COST (incl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
«** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$360.360
$58,647
$366.912
$425.559
0.53
0.22
58
0.8
303
326.4
10
0.1
0.1627
$360.360
$58.647
$302.702
$361.349
0.53
0.22
58
0.66
303
269.3
10
0.1
0.1627
$360.360
$58.647
$229.320
$287.967
0.53
0.22
58
0.5
303
204.0
10
0.1
0.1627
$360.360
$58,647
$151,351
$209,998
0.53
0.22
58
0.33
303
134.6
$1.304 $1,342 $1.412 | $1.560
F-24
-------
APPENDIX G. ANNUAL COSTS OF RETROFIT NOX CONTROLS:
NONFOSSIL-FUEL-FIRED ICI BOILERS
This appendix contains cost spreadsheets for nonfossil-fuel-fired boilers retrofitted with
various NOX controls. The spreadsheets are based on data from actual boiler retrofit
experiences or studies. Capital annualization for all analyses are based on a 10-year amortization
period and a 10-percent interest rate. All costs presented are in 1992 dollars. For further
information on the methodology and assumptions made in these cost analyses, see Chapter 6.
This appendix contains cost spreadsheets for the following boilers:
Boiler and NOX Control Page
Wood-Fired:
Stoker, 190, 225, 300, 395, and 500 MMBtu/hr, with urea-based SNCR G-3
FBC boiler, 250 MMBtu/hr, with ammonia-based SNCR G-13
Paper-Fired:
Packaged watertube, 72 and 172 MMBtu/hr, with urea-based SNCR G-15
MSW-Fired:
Stoker, 108, 121, and 325 MMBtu/hr, with urea-based SNCR . G-19
G-l
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1993
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST *** • PEC
Z. DIRECT INSTALLATION COST (DIG)
*** TOTAL DIRECT INSTALLATION COST *** OIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. 6LDG (is required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+OIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$424.113
$424.113
-
{424.113
$424.113
CONTINUED ON NEXT PAGE
G-3
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)- 190 - -
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 8 J0.05/kU-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *"* DAC
B. INDIRECT ANNUAL COSTS (IAC)
1 . OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
**" TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+IAC)
0.8
$78.532
0.66
$66.930
0.5
-
$53.671
0.33
$39.583
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** HOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED, 1992 DOLLARS) ***
10
n i
o.:fi?/
$424,113
$69.023
$78.532
$147.555
0.25
0.11
55
0.8
190
91.5
10
0.1
0.1627
$424.113
$69.023
$66.930
$135.953
0.25
0.11
55
0.66
190
75.5
10
0.1
0.1627
$424,113
$69,023
$53,671
$122.693
0.25
0.11
55
0.5
190
57.2
10
0.1
0.1627
$424,113
$69.023
$39.583
$108.605
0.25
0.11
55
0.33
190
37.8
$1.612 $1.800 $2.144 $2.876
G-4
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEH SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (QIC)
•** TOTAL DIRECT INSTALLATION COST **.* DIC
3. SITE PREP. SP (as required) SP
4. EfUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *•* DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
**• TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$477.653
$477.853
-
$477.853
$477,853
CONTINUED ON NEXT PAGE
G-5
-------
COST EFFECTIVENESS OF RETROFIT HOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (OiM)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 J0.05AV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (1AC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** 1AC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
{103.699
0.66
$87,964
0.5
-
$69.981
0.33
$50,875
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** AC1C+0&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MHBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 d«ys/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (S/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$477.853
J77.768
1103.699
$181.467
0.25
0.11
55
0.8
225
108.4
10
0.1
0.1627
$477.853
$77.768
$87.964
$165.732
0.25
0.11
55
O.E6
225
89.4
10
0.1
0.1627
$477.853
$77.768
$69,981
$147.750
0.25
0.11
55
0.5
225
67.8
10
0.1
0.1627
$477,853
$77.768
$50.875
$128,643
0.25
0.11
55
0.33
225
44.7
$1.674 $1.853 | $2,181 | $2.877
G-6
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL HETHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*«* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (OIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*" TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$595.417
$595.417
*
$595.417
J595.417
CONTINUED ON NEXT PAGE
G-7
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OACJ
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY t $0.05/kW-hr
6. STEAM
7. FUEL
8. VASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
8. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$107,809
0.66
$91.949
0.5
-
$73.822
0.33
$54.563
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) Z
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MHBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) «**
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
J595.417
$96.901
$107.809
$204.710
0.25
0.11
55
0.8
300
144.5
10
0.1
0.1627
$S95.417
$96.901
$91,949
$188.850
0.25
0.11
55
0.66
300
119.2
10
0.1
0.1627
$595.417
$96.901
$73.822
$170.724
0.25
0.11
55
0.5
300
90.3
10
0.1
0.1627
$595.417
$96.901
$54.563
$151.464
0.25
0.11
55
0.33
300
59.6
$1.416 | $1.584 $1,890 $2.540
G-8
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR • UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
"** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESThcNT COST *** TCIC
(DCC+ICC+CONT)
BOILER CAPACITY FACTOR
O.B
0.66
0.5
0.33
$641.834
$641.834
-
J641.834
$641.834
CONTINUED ON NEXT PAGE
G-9
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
BOILER CAPACITY (MMBtu/hr)- 395 -
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATIN6 AND MAINTENANCE COSTS (DIM)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 9 J0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&H
(DAC+IAC)
•BVKVMwa
0.8
$50.263
COST BASE
1992 DOLLARS
0.66
$44.707
0.5
-
$38.358
0.33
$31.612
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (tncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
i. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
**" «0x REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
1641.834
$104.456
$50.263
$154.719
0.25
0.11
55
O.B
395
190.3
10
0.1
0.1627
$641.834
$104.456
$44.707
$149.163
0.25
0.11
55
0.66
395
157.0
$813 | $950
10
0.1
0.1627
$641.834
$104.456
$38.358
$142.814
0.25
0.11
55
0.5
395
118.9
10
0.1
0.1627
$641.834
$104.456
$31.612
$136.068
0.25
0.11
55
0.33
395
78.5
$1.201 $1.733
G-10
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EOP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST «** PEC
2. DIRECT INSTALLATION COST (DIC)
•** TOTAL DIRECT INSTALLATION COST *** ... DIC
3. SITE PREP. SP (as required) ' SP
4. BUILDINGS. BLOG (as required) ELDG
'** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$650,123
$650.123
-
$650.123
$650.123
CONTINUED ON NEXT PAGE
G-ll
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: WOOD NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY i JO.OS/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAOIAC)
•••KKUMfl
0.8
$134.437
COST BASE
1992 DOLLARS
0.66
$114.193
0.5
-
$91,057
0.33
$66,474
COST EFFECTIVENESS
A. TOTAL ANNUALIZEO COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
I. ANNUAL O&M COSTS (O&M. above) O&M
*»* TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HHBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
"•* NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) **»
10
0.1
0.1627
$650,123
$105.805
$134,437
$240.242
0.25
0.11
55
0.8
500
240.9
10
0.1
0.1627
$650.123
$105.805
$114.193
$219.998
0.25
0.11
55
0.66
500
198.7
10
0.1
0.1627
$650,123
$105.805
$91.057
$196.861
0.25
0.11
55
0.5
500
150.6
10
0.1
0.1627
$650,123
$105,805
$66,474
$172.279
0.25
0.11
55
0.33
500
99.4
$997 | $1.107
$1.308 | $1.734
G-12
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FLUIOIZEO BED COHBUSTOR (BUBBLING BED) CHAP. 6 REFERENCES
FUEL TYPE: WOOD HURST. 1988
CONTROL METHOD: SNCR - AMMONIA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
""* TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS, BLDG (as required) BLDS
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+D1C+SP+BLD&)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
rmmmmmmmmmt
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
$203.291
0.66
$203.291
0.5
$203.291
0.33
$203.291
included
$203.291
$86.13?
included
$291.428
above
$203.291
$88.137
above
$291.428
included
$203.791
$88.137
included
$291.428
above
$203.291
$88.137
above
$291.428
CONTINUED ON NEXT PAGE
G-13
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: FLUIOIZEO BED COMBUSTOR (BUBBLING BED) CHAP. 6 REFERENCES
FUEL TYPE: WOOD HURST, 19B8
CONTROL METHOD: SNCR - AMMONIA
ANNUAL OPERATING AND MAINTENANCE COSTS (OiH)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY » $0.05AV-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS (AMMONIA 9 J250/TON)
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD (60X OF SUM OF ALL LABOR
AND MAINTENANCE MATERIALS)
2. ADMINISTRATIVE (0.02*TCIC)
3. PROPERTY TAX (0.01'TCIC)
4. INSURANCE (0.01'TCIC)
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** DIM
(DAC+1AC)
0.8
$7.080
$109.600
$116.680
$0
$5.829
$2.914
$2.914
$11.657
$128.337
0.66
$5.841
$90.420
$96,261
$0
$5.829
$2.914
$2,914
$11.657
$107.918
COST BASE
1992 DOLLARS
0.5
$4,425
$68.500
$72.925
$0
$5.829
$2-.914
$2.914
$11.657
$84.562
0.33
$2.921
$45.210
$48.131
$0
$5.829
$2.914
$2.914
$11,657
$59.788
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
«** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HHBtu/hr) CAP
"*• NOx REMOVED PER YEAR (TONS/YR) *•*
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) **«
10
0.1
0.162745
$291.426
$47.429
$128.337
$175.766
0.25
0.11
55
0.8
250
120.5
10
0.1
0 162745
$2'jl.428
$47.429
$107.918
$155.347
0.25
0.11
55
0.66
250
99.4
10
0.1
0.162745
$291.428
$47.429
$84.582
$132.011
0.25
0.11
55
0.5
250
75.3
10
0.1
0.162745
$291.428
$47.429
$59.788
$107.216
0.25
0.11
55
0.33
250
49.7
$1.459
$1.563 | $1.754 $2.158
G-14
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED VATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: PAPER NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required) BLOG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*" TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICCKONT)
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.6
0.66
0.5
0.33
$225.789
$225.789
•
$225,789
J225.789
CONTINUED ON NEXT PAGE
G-15
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED UATERTUBE CHAP. 6 REFERENCES
BOILER CAPACITY (HHBtu/hr)- 72 -- - -.— .
FUEL TYPE: PAPER NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
ANNUAL OPERATIN6 AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** OAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
«** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$54,265
0.66
$45.909
0.5
-
$36.359
0.33
$26.211
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTO?
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/HMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
•** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
J225.789
$36.746
$54.265
$91.012
0.5
0.23
55
O.B
72
69.4
10
0.1
0.1627
$225.789
$36.746
$45.909
$82.655
O.S
0.23
55
0.66
72
57.2
10
0.1
0.1627
$225.789
$36.746
$36.359
$73.105
0.5
0.23
55
0.5
72
43.4
10
0.1
0.1627
$225.769
$36.746
$26.211
$62,957
0.5
0.23
55
0.33
72
28.6
$1.312 1 $1.444 $1.686 | $2.200
****************************************
G-16
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE
BOILER CAPACITY (MHBtu/hr): 172
FUEL TYPE: PAPER FIBER WASTE
CONTROL METHOD: SNCR - UREA
CHAP. 6 REFERENCES
NALCO FUEL TECH 1992
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP)
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*" TOTAL PURCHASED EQUIPMENT COST ***
2. DIRECT INSTALLATION COST (DIC)
*** TOTAL DIRECT INSTALLATION COST ***
3. SITE PREP, SP (as required)
4. 8BILDINGS. BLDG (as required)
*** TOTAL DIRECT CAPITAL COST ***
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST ***
C. CONTINGENCY
*** TOTAL CAPITAL INVESTMENT COST ***
(OCC+ICC+CONT)
EQP
PEC
DIC
SP
BLDG
DCC
ICC
CONT
TCIC
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$b38.776
J538.776
-
$538.776
$538,776
CONTINUED ON NEXT PAGE
G-17
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: PACKAGED WATERTUBE CHAP. 6 REFERENCES
FUEL TYPE: PAPER FIBER WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY 0 $0.05/kV-hr
6. STEAM
7. FUEL
B. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+1AC)
0.8
$136.352
0.66
$115,211
COST BASE
1992 DOLLARS
0.5
-
$91,049
0.33
$65.377
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M, above) O&M
«** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (HMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (I/TON NOx REMOVED, 1992 DOLLARS) ***
10
0.1
0.1627
$538.776
$87,683
$136.352
$224.036
O.S
0.23
55
0.8
172
mmmxmmmxm
165.7
10
0.1
0.1627
$538.776
$87.683
$115.211
$202.894
0.5
0.23
55
0.66
172
136.7
10
0.1
0.1627
$538,776
$87.683
$91.049
$178,732
0.5
0.23
55
0.5
172
103.6
10
C. !
0.1C'7
$538.776
$87,683
$65.377
$153.060
0.5
0.23
55
0.33
172
68.4
$1,352 1 $1,484 1 $1.725 1 $2.239
•»•«***»**»»»*»*«*«*»««***»»»*«*«»*»*•*
G-18
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
•** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIC)
•** TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *«* DCC
(PEC+DIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
**• TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(DCC+ICC+CONT)
COST BASE
1992 DOLLARS
*m*mmmmmm*mmm*mmmmmm
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
1424.666
$424.666
"
$424.666
$424.666
CONTINUED ON NEXT PAGE
G-19
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
BOILER CAPACITY (HMBtu/hr)- 108 - — - - - -
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&H)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (OAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
S. ELECTRICITY 0 J0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
6. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
**« TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(OAC+IAC)
0.8
J82.718
0.66
$70.386
mmmmmmm**mfmimxmm***
COST BASE
1992 DOLLARS
t*mmmmmmmmm
0.5
-
$56.293
(•*••«••**
0.33
$41.319
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (1ncl. capital and O&H)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
•** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&H. above) O&H
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (1b/HMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (NOx) 2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/day)«{365 days/yr)]*[(NOx)l-(NOx)2]/200D
*** COST EFFECTIVENESS ($/TON NOx REMOVED. 1992 DOLLARS) ***
10
0.1
0.1627
$424.666
$69.112
$62.718
$151.830
0.4
0.18
55
0.8
108
83.3
10
0.1
0.1627
$424.666
$69.112
$70,366
$139.496
0.4
0.18
55
0.66
108
*mmmm***m
68.7
$1.824
**********
10
0.1
0.1627
$424,666
$69.112
$56.293
$125.405
0.4
0.18
55
0.5
108
«««•••*•«
52.0
ECKMKBSKKI
$2.031 1 $2.410
10
0.1
0.1627
$424.666
$69.112
$41.319
$110.431
0.4
0.18
55
0.33
108
•»*•«*»•
34.3
tmm.mm**mx*
$3.216
G-20
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
COST BASE
1992 DOLLARS
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (DCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST **' PEC
2. DIRECT INSTALLATION COST (DIC)
"* TOTAL DIRECT INSTALLATION COST *** DIC
3. SITE PREP, SP (as required) SP
4. BUILDINGS. BLDG (as required) BLDG
*** TOTAL DIRECT CAPITAL COST *** DCC
(PEC+OIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(OCC+ICC+CONT)
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$711.461
J711.461
-
$711.461
$711.461
CONTINUED ON NEXT PAGE
G-21
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC)
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY « $0.05/kW-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+IAC)
0.8
$77.928
0.66
$67.883
COST BASE
1992 DOLLARS
mmmmmmmmmm
0.5
-
$56.402
0.33
$44.204
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (ACIC)
EXPECTED LIFETIME OF EQUIPMENT. YEARS
INTEREST RATE
TAPiTAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC. above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZED COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MMBtu) (N0x)2
3. NOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) ***
[CAP*CF*(24 hr/d»y)*(365 days/yr)]*[(NOx)l-(NOx)2]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 DOLLARS) **•
10
0.1
0.1627
$711,461
$115.787
$77.928
$193.715
0.4
0.18
55
0.8
121
93.3
10
0.1
0.1627
$711,461
$115.787
$67.883
$183.670
• 0.4
0.18
55
0.66
121
77.0
10
0.1
0.1627
$711,461
$115,787
$56.402
$172.189
0.4
0.18
55
0.5
121
SB. 3
10
0.1
0.1627
$711.461
$115.787
$44.204
$159.991
0.4
0.18
55
0.33
121
38.5
$2.077 1 $2.387 1 $2.954 I $4.158
***************************************
G-22
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
TOTAL CAPITAL INVESTMENT COST (TCIC)
A. DIRECT CAPITAL COST (OCC)
1. PURCHASED EQUIPMENT COST (PEC)
PRIMARY AND AUXILIARY EQUIPMENT (EQP) EQP
INSTRUMENTATION
SALES TAX
FREIGHT
CEM SYSTEM
*** TOTAL PURCHASED EQUIPMENT COST *** PEC
2. DIRECT INSTALLATION COST (DIG)
*•* TOTAL DIRECT INSTALLATION COST "*, QIC
3. SITE PREP. SP (as required) SP
4. BUILDINGS. BLDG (as required) BLOG
*** TOTAL DIRECT CAPITAL COST *** OCC
(PEC+OIC+SP+BLDG)
B. INDIRECT CAPITAL COST (ICC)
1. ENGINEERING
2. CONSTRUCTION AND FIELD EXPENSES
3. CONSTRUCTION FEE
4. STARTUP
5. PERFORMANCE TEST
*** TOTAL INDIRECT CAPITAL COST *** ICC
C. CONTINGENCY CONT
*** TOTAL CAPITAL INVESTMENT COST *** TCIC
(OCC+ICC+CONT)
tmm*mmmmmmm*»
COST BASE
1992 DOLLARS
BOILER CAPACITY FACTOR
0.8
0.66
0.5
0.33
$1.011,932
Jl. 011.932
-
Jl. Oil, 932
$1.011.932
CONTINUED ON NEXT PAGE
G-23
-------
COST EFFECTIVENESS OF RETROFIT NOx CONTROLS
BOILER TYPE: STOKER CHAP. 6 REFERENCES
FUEL TYPE: MUNICIPAL SOLID WASTE NALCO FUEL TECH 1992
CONTROL METHOD: SNCR - UREA
ANNUAL OPERATING AND MAINTENANCE COSTS (O&M)
CAPACITY FACTOR
A. DIRECT ANNUAL COSTS (DAC;
1. OPERATING LABOR
2. MAINTENANCE LABOR
3. MAINTENANCE MATERIALS
4. REPLACEMENT MATERIALS
5. ELECTRICITY • 10.05/kU-hr
6. STEAM
7. FUEL
8. WASTE DISPOSAL
9. CHEMICALS
10. OTHER
*** TOTAL DIRECT ANNUAL COSTS *** DAC
B. INDIRECT ANNUAL COSTS (IAC)
1. OVERHEAD
2. ADMINISTRATIVE
3. PROPERTY TAX
4. INSURANCE
*** TOTAL INDIRECT ANNUAL COSTS *** IAC
*** TOTAL ANNUAL OPERATING AND MAINTENANCE COSTS *** O&M
(DAC+1AC)
0.8
$194.596
0.66
$165.651
COST BASE
1992 DOLLARS
*B*«*caBBBX*cxcmx*M***c
0.5
-
$132.570
0.33
$97.422
COST EFFECTIVENESS
A. TOTAL ANNUALIZED COST (incl. capital and O&M)
1. ANNUALIZED CAPITAL INVESTMENT COST (AC1C)
EXPECTED LIFETIME OF EQUIPMENT, YEARS
INTEREST RATE
CAPITAL RECOVERY FACTOR
TOTAL CAPITAL INVESTMENT COSTS (TCIC, above)
*** ANNUALIZED CAPITAL INVESTMENT COST *** ACIC
2. ANNUAL O&M COSTS (O&M. above) O&M
*** TOTAL ANNUALIZEO COST *** ACIC+O&M
B. NOx REMOVAL PER YEAR
1. BASELINE NOx LEVEL (Ib/MMBtu) (NOx)l
2. CONTROLLED NOx LEVEL (Ib/MHBtu) (N0x)2
3. WOx REMOVAL EFFICIENCY (X)
4. CAPACITY FACTOR CF
5. BOILER HEAT INPUT CAPACITY (MMBtu/hr) CAP
*** NOx REMOVED PER YEAR (TONS/YR) **•
[CAP*CF*(24 hr/day)*{365 days/yr)]*[(NOx)l-(NOx)Z]/2000
*** COST EFFECTIVENESS (J/TON NOx REMOVED. 1992 COLLARS) ***
10
0.1
0.1627
$1.011.932
$164.687
$194.596
$359.284
0.4
0.18
55
O.S
325
250.5
***********
$1.434
10
0.1
0.1627
$1.011.932
$164.687
$165.651
$330.338
0.4
0.18
55
0.66
325
206.7
10
0.1
0.1627
$1.011,932
$164.687
$132.570
$297.258
0.4
0.18
55
0.5
325
156.6
*mm*mm******
$1.598 I $1.898
10
0.1
0.1627
$1.011.932
$164.687
$97.422.
$262.110
0.4
0.18
55
0.33
325
103.3
•K»M»**»«KS
$2.536
G-24
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA-453/R-94-022
4. TITLE AND SUBTITLE
Alternative Control Techniques Document —
Emissions from Industrial/Commercial/int
(IC1) Boilers
7. AUTHOR(S)
Carlo Castaldini; Scott Seu
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Acurex Environmental Corporation
Post Office Box 7044
Mountain View, California 94039
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Emissions Standards Division (MD-13)
Office of Air Quality Planning and Standai
Research Triangle Park, N.C. 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
March 1994
, .. .. . 6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
1O. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D2-0189
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
-ds
15.-SUPPLEMENTARY NOTES
EPA Work Assignment Manager: William Neuffer 919/541-5435
16. ABSTRACT
This document describes available control techniques for reducing NOx emissions
from ICI Boilers. Discussions of NOx formation and uncontrolled emission levels
are included. NOx control techniques include staged combustion, low NOx burners, nat\
gas reburn, Flue gas recirculation, wet injection, selective noncatalytic reduction,
and selective catalytic reduction. Achievable NOx emission levels, costs and cost
effectiveness and environmental impacts for these controls are presented.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Nonutility boilers
Nitrogen Oxide Emissions
NOx Control Techniques
Costs of Emission Controls
Low NOx Burners
Natural Gas Reburn
§ elective Noncatalytic .Reduction
elective Catalytic Reduction
18. DISTRIBUTION STATEMENT
EPA Form 2220-MR«v. 4-77) PREVIOUS EDITION is OBSOLETE
b.lDENTIFlERS/OPEN E.NDED TERMS c. COSATI Field/Group
-
19 SECURITY CLASS (This Reporr) 21. NO OF PAGES
486
20 SECURITY CLASS fTVlis pafej 22 PRICE
ral
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