EPA-453/R-94-022



# Alternative Control Techniques Document-- NO Emissions from x 

# 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 1994iii 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 reportare available—as supplies permit—from the Library Services Office (MD35), 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).v TABLE OF CONTENTS

Page

1 INTRODUCTION

..................................... 1-1

2 SUMMARY

.......................................... 2-1

2.1 ICI BOILER EQUIPMENT

........................... 2-2 2.2 NO FORMATION AND BASELINE EMISSIONS

......... 2-5

x 2.3 CONTROL TECHNIQUES AND CONTROLLED NO EMISSION LEVELS

.......................... 2-8 x 2.3.1 Combustion Modification Controls

............. 2-11 2.3.2 Flue Gas Treatment Controls

.................. 2-15 2.4 COST AND COST EFFECTIVENESS OF NO x CONTROL TECHNIQUES

......................... 2-15 2.5 ENERGY AND ENVIRONMENTAL IMPACTS OF NO x CONTROL TECHNIQUES

......................... 2-19

3 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

.................... 3-19vi 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 NONFOSSIL-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

.................... 3-43vii TABLE OF CONTENTS (continued)

Page

4 BASELINE EMISSION PROFILES

........................ 4-1

4.1 FACTORS AFFECTING NO EMISSIONS FROM ICI x 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

5 NO CONTROL TECHNOLOGY EVALUATION

............. 5-1 x 5.1 PRINCIPLES OF NO FORMATION AND x COMBUSTION MODIFICATION NO CONTROL

........ 5-2 x 5.2 COMBUSTION MODIFICATION NO CONTROLS FOR x COAL-FIRED ICI BOILERS

......................... 5-9viii 5.2.1 Combustion Modification NO Controls for x Pulverized Coal (PC)-fired ICI Boilers

....... 5-10 5.2.2 Combustion Modification NO Controls for x Stoker Coal-fired ICI Boilers

............... 5-23 5.2.3 Combustion Modification NO Controls for x Coal-fired Fluidized-bed Combustion (FBC) ICI Boilers

........................ 5-30 5.3 COMBUSTION MODIFICATION NO CONTROLS FOR x OIL- AND NATURAL-GAS-FIRED ICI BOILERS

........ 5-39 5.3.1 Water Injection/Steam Injection (WI/SI)

.......... 5-43 5.3.2 Low-NO Burners (LNBs) in Natural-gas- and x Oil-fired ICI Boilers

........................ 5-43 5.3.3 Flue Gas Recirculation (FGR) in Natural-gasand Oil-fired ICI Boilers

.................... 5-54 5.3.4 Fuel Induced Recirculation (FIR)

............... 5-56 5.3.5 Staged Combustion Air (SCA) in Natural-gasand Oil-fired ICI Boilers

.................... 5-56 5.3.6 Combined Combustion Modification NO x

Controls for Natural-gas- and Oil-fired ICI Boilers

................................ 5-60 5.3.7 Fuel Switching

.............................. 5-61 5.3.8 Combustion Modification NO Controls for x Thermally Enhanced Oil Recovery (TEOR) Steam Generators

................. 5-63 5.3.9 Gas Fuel Flow Modifiers

...................... 5-69 TABLE OF CONTENTS (continued)ix Page

5.4 COMBUSTION MODIFICATIONS FOR NONFOSSILFUEL-FIRED ICI BOILERS

........................ 5-70 5.5 FLUE GAS TREATMENT NO CONTROLS FOR ICI x 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 NO REDUCTION x PERFORMANCE

................................. 5-78 5.7 REFERENCES FOR CHAPTER 5

.................... 5-82

6 COSTS OF RETROFIT NO CONTROLS

................... 6-1 x 6.1 COSTING METHODOLOGY

......................... 6-1 6.1.1 Capital Costs of Retrofit NO Controls

........... 6-2 x 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 NO CONTROL COST CASES AND SCALING

x METHODOLOGY
................................. 6-9 6.3 CAPITAL AND TOTAL ANNUAL COSTS OF NO x CONTROLS

.................................... 6-11 6.4 COST EFFECTIVENESS OF NO CONTROLS

.......... 6-15 x 6.4.1 NO Control Cost Effectiveness: Coal-fired ICI

x Boilers

.................................... 6-15 6.4.2 NO Control Cost Effectiveness: Natural-gas-fired ICI

x Boilers

.................................... 6-18x 6.4.3 NO Control Cost Effectiveness: Fuel-oil-fired

x ICI Boilers

................................. 6-25 6.4.4 NO Control Cost Effectiveness: Nonfossil-fuel-fired ICI

x Boilers

.................................... 6-25 6.4.5 NO Control Cost Effectiveness: Oil-fired

x 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

7 ENVIRONMENTAL AND ENERGY IMPACTS

............... 7-1

7.1 AIR POLLUTION
................................. 7-1 7.1.1 NO Reductions

............................. 7-1

x 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-NO Burners (LNBs)

..................... 7-16 x 7.4.5 Flue Gas Recirculation (FGR)

.................. 7-18xi 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-1

APPENDIX B — CONTROLLED NO EMISSION DATA

.............. B-1 x

APPENDIX C — LOW-NO INSTALLATION LISTS, COEN x COMPANY AND TAMPELLA POWER CORP.

.......... C-1

APPENDIX D — SCALED COST EFFECTIVENESS VALUES

......... D-1

APPENDIX E — ANNUAL COSTS OF RETROFIT NO x

CONTROLS: NATURAL-GAS-FIRED ICI BOILERS

....................................... E-1xii

APPENDIX F — ANNUAL COSTS OF RETROFIT NO x

CONTROLS: COAL-FIRED ICI BOILERS

............. F-1

APPENDIX G — ANNUAL COSTS OF RETROFIT NO x

CONTROLS: NONFOSSIL-FUEL-FIRED ICI BOILERS

....................................... G-1xiii LIST OF FIGURES
Page
Figure 2-1 Cost effectiveness versus boiler capacity, PC wallfired boilers

..................................... 2-20
Figure 2-2 Cost effectiveness versus boiler capacity, naturalgas-fired packaged watertube boilers

................ 2-20
Figure 2-3 Cost effectiveness versus boiler capacity, distillateoil-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

................ 3-8xiv

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

........................ 3-23xv 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 NO x

emissions

....................................... 4-7xvi

Figure 4-4 Fuel NO formation as a function of coal x oxygen/nitrogen ratio and coal nitrogen content

....... 4-9
Figure 4-5 Effect of burner heat release rate on NO emissions for coal x and natural gas fuels

.............................. 4-11
Figure 4-6 Furnace heat release rate versus boiler size

............ 4-12
Figure 4-7 Effect of excess oxygen and preheat on NO x

emissions, natural-gas-fired boilers

................. 4-14
Figure 5-1 Effect of excess O on NO emissions for firetube boilers at 2 x baseline operating conditions, natural gas and oil fuels

. 5-7
Figure 5-2 Changes in CO and NO emissions with reduced x 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

.......................... 5-16xvii LIST OF FIGURES (continued)
Page
Figure 5-5 Performance of CF/SF LNB

......................... 5-16
Figure 5-6 Riley low-NO CCV burner with secondary air diverter

... 5-18 x
Figure 5-7 Riley low-NO TSV burner with advanced air staging for x turbo-furnace, down-fired and arch-fired installation

.... 5-19
Figure 5-8 Schematic diagram of stoker with FGR

................ 5-27
Figure 5-9 FGR effects on excess O

........................... 5-28 2
Figure 5-10 NO emission versus excess O , stoker boiler with FGR

... 5-28 2
Figure 5-11 Overfeed stoker with short active combustion zone

..... 5-29
Figure 5-12 Effect of SCA on NO and CO emissions, Chalmers University 5-33 x
Figure 5-13 NO and CO versus bed temperature, pilot-scale BFBC

... 5-35 x
Figure 5-14 Effect of bed temperature on NO and CO, Chalmers University 5-36 x
Figure 5-15 As the rate of water injection increases, NO decreases
. . 5-44 x
Figure 5-16 Staged air LNB

................................... 5-46xviii

Figure 5-17 Staged fuel LNB

.................................. 5-48
Figure 5-18 Low-NO ASR burner

.............................. 5-50 x
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 NO emissions

.................. 5-62 x
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
.......................... 5-68xix 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 NO emissions with reduced excess x oxygen for a residual-oil-fired watertube industrial boiler 7-8xx

Figure 7-2 Pilot-scale test results, conversion of NO to N O (NO = 300 x 2 i 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 O 2

and carbon monoxide emissions for natural gas fuel

.... 7-17
Figure 7-5 Energy penalty associated with the use of WI or SI for NO x

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

.................. 7-21xxi LIST OF TABLES
Page

TABLE 2-1 ICI BOILER EQUIPMENT, FUELS, AND

APPLICATIONS

.................................. 2-3

TABLE 2-2 SUMMARY OF BASELINE NO EMISSIONS

............. 2-7 x

TABLE 2-3 EXPERIENCE WITH NO CONTROL x TECHNIQUES ON ICI BOILERS

..................... 2-9

TABLE 2-4 SUMMARY OF COMBUSTION

MODIFICATION NO CONTROL x PERFORMANCE ON ICI WATERTUBE BOILERS

....................................... 2-12

TABLE 2-5 SUMMARY OF COMBUSTION

MODIFICATION NO CONTROL x PERFORMANCE ON ICI FIRETUBE BOILERS

....................................... 2-14

TABLE 2-6 SUMMARY OF FLUE GAS TREATMENT

NO CONTROL PERFORMANCE ON ICI x BOILERS

....................................... 2-16xxii

TABLE 2-7 ESTIMATED COST AND COST

EFFECTIVENESS OF NO CONTROLS x (1992 DOLLARS)

................................. 2-18

TABLE 2-8 EFFECTS OF NO CONTROLS ON CO x 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

....................................... 4-20xxiii

TABLE 4-5 AP-42 UNCONTROLLED EMISSION

FACTORS FOR NONFOSSILFUEL-FIRED BOILERS

............................ 4-21xxiv LIST OF TABLES (continued)
Page

TABLE 4-6 AVERAGE NO EMISSIONS FROM x MUNICIPAL WASTE COMBUSTORS

................ 4-22

TABLE 4-7 SUMMARY OF BASELINE NO EMISSIONS

............. 4-23 x

TABLE 5-1 SUMMARY OF COMBUSTION

MODIFICATION NO CONTROL x APPROACHES

................................... 5-4

TABLE 5-2 EXPERIENCE WITH NO CONTROL x TECHNIQUES ON ICI BOILERS

..................... 5-5

TABLE 5-3 COMBUSTION MODIFICATION NO x

CONTROLS FOR FULL-SCALE PC-FIRED INDUSTRIAL BOILERS

................... 5-11

TABLE 5-4 COMBUSTION MODIFICATION NO CONTROLS x FOR STOKER COAL-FIRED INDUSTRIAL BOILERS

..... 5-24

TABLE 5-5 NO CONTROL TECHNIQUES FOR FBC BOILERS

....... 5-32 x

TABLE 5-6 REPORTED CONTROLLED NO EMISSION LEVELS, x FULL-SCALE, COAL-FIRED FBC BOILERS

............ 5-35xxv

TABLE 5-7 COMBUSTION MODIFICATION NO CONTROLS x FOR FULL-SCALE NATURAL-GAS-FIRED INDUSTRIAL BOILERS

............................ 5-41

TABLE 5-8 COMBUSTION MODIFICATION NO CONTROLS x FOR OIL-FIRED INDUSTRIAL BOILERS

............... 5-42

TABLE 5-9 REPORTED NO LEVELS AND REDUCTION x 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 NO REDUCTIONS WITH FUEL x SWITCHING

..................................... 5-64

TABLE 5-12 SNCR NO CONTROL FOR ICI BOILERS

............... 5-73 x

TABLE 5-13 SELECTED SCR INSTALLATIONS, CALIFORNIA ICI BOILERS 5-77

TABLE 5-14 SCR NO CONTROLS FOR ICI BOILERS

............... 5-77 xxxvi LIST OF TABLES (continued)
Page

TABLE 5-15 SUMMARY OF NO REDUCTION PERFORMANCE

....... 5-79 x

TABLE 6-1 ASSUMPTIONS FOR ESTIMATING CAPITAL AND

ANNUAL O&M COSTS

.............................. 6-7

TABLE 6-2 BASELINE (UNCONTROLLED) NO EMISSIONS x USED FOR COST CASES

........................... 6-9

TABLE 6-3 NO REDUCTION EFFICIENCIES USED FOR COST CASES 6-10 x

TABLE 6-4 NO CONTROL COST EFFECTIVENESS CASES

......... 6-11 x

TABLE 6-5 CAPITAL AND TOTAL ANNUAL COSTS OF RETROFIT NO x

CONTROLS FOR ICI BOILERS, 1992 DOLLARS

........ 6-12

TABLE 6-6 SUMMARY OF NO CONTROL COST x EFFECTIVENESS, COAL-FIRED ICI BOILERS

....................................... 6-16

TABLE 6-7 SUMMARY OF NO CONTROL COST xEFFECTIVENESS, NATURAL-GASFIRED ICI BOILERS

............................... 6-18xxvii

TABLE 6-8 SUMMARY OF NO CONTROL COST xEFFECTIVENESS, DISTILLATE-OILFIRED ICI BOILERS

............................... 6-26

TABLE 6-9 SUMMARY OF NO CONTROL COST x EFFECTIVENESS, RESIDUAL-OIL-FIRED ICI BOILERS

..................................... 6-27

TABLE 6-10 SUMMARY OF NO CONTROL COST x EFFECTIVENESS, NONFOSSIL-FUEL-FIRED ICI BOILERS

....................................... 6-30

TABLE 6-11 NO CONTROL COST EFFECTIVENESS xWITHOUT/WITH CEM SYSTEM, NATURAL-GASFIRED ICI BOILERS

.............................. 6-31 a

TABLE 7-1 EXPERIENCE WITH NO CONTROL TECHNIQUES x ON ICI BOILERS

................................. 7-2

TABLE 7-2 NO EMISSIONS REDUCTION FROM MODEL x BOILERS

....................................... 7-3

TABLE 7-3 CO EMISSION CHANGES WITH NO CONTROL x RETROFIT — COAL-FIRED BOILERS

................ 7-5

TABLE 7-4 CO EMISSION CHANGES WITH NO CONTROL x RETROFIT — GAS-FIRED BOILERS

.................. 7-6xxviii LIST OF TABLES (continued)
Page

TABLE 7-5 CO EMISSION CHANGES WITH NO CONTROL x RETROFIT — OIL-FIRED BOILERS

................... 7-7

TABLE 7-6 AMMONIA EMISSIONS WITH UREA-BASED SNCR

RETROFIT
..................................... 7-101-xxix 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: [W]ithin 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 (NO ) per year. This alternative control techniques (ACT) document x provides technical information for use by State and local agencies to develop and implement regulatory programs to control NO emissions x 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. Although1-xxx

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 NO emission levels presented in this document x 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 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 NO formation and uncontrolled NO x x 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 NO x 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.2-1 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 NO emission levels from ICI boilers and the x feasibility of control for many units. Section 2.2 reviews baseline NO x emission reported for many categories of ICI boilers and highlights the often broad ranges in NO levels associated with boiler designs, firing x methods, and fuels. The experience in NO control retrofits is summarized in Section 2.3. x This information was derived from a critical review of the open literature coupled with information from selected equipment vendors and users of NO control technologies. The section is divided into a subsection on x 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-NO x design. When cleaner fuels are burned, the low-NO burner (LNB) often x includes a flue gas recirculation (FGR) system that reduces the peak flame temperature producing NO . Where NO regulations are especially x x2-2

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 NO . For these units, NO reductions are x x often achievable only with flue gas treatment technologies for which experience varies. Section 2.4 summarizes the cost of installing NO controls and x operating at lower NO levels. The data presented in this document are x 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 site factors that cannot be taken fully into account. Finally, Section 2.5 summarizes the energy and environmental impacts of low-NO operation. Combustion controls are often limited in x effectiveness by the onset of other emissions and energy penalties. This section reviews the emissions of CO, NH , N O, soot and particulate. 3 2 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 NO controls applicable to utility boilers are also candidate control

x2-3

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.2-4

Table 2-12-5

Heat transfer configurati on Design and

fuel type Capacity

range, MMBtu/hr a % of

ICI boiler units b,c % of ICI

boiler capacity b, c Applicatio

n d Watertube Pulverized

coal 100-

1,500+ ** e 2.5 PH, CG

Stoker coal 0.4-550+ f ** 5.0 SH, PH, CG FBC coal g 1.4-1,075   PH, CG Gas/oil 0.4-1,500+ 2.3 23.6 SH, PG, CG Oil field steamer 20-62.5 N.A. h N.A. PH

Stoker nonfossil 1.5-1,000 f **  1.1 SH, PH, CG FBC nonfossil 40-345 ** ** PH, CG

Other nonfossil 3-800   SH, PH, CG Firetube HRT coal 0.5-50 **  ** SH, PH

Scotch coal 0.4-50   SH, PH Vertical coal <2.5 **  ** SH, PH Firebox coal 0.4-15   SH, PH HRT gas/oil 0.5-50 1.5 1.5 SH, PH Scotch gas/oil 0.4-50 4.8 4.6 SH, PH

Vertical gas/oil <2.5 1.0 **  SH, PH

Firebox gas/oil <20 6.5 48 SH, PH

HRT nonfossil 2-50 N.A. N.A. SH, PH TABLE 2-1. ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS2-6

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 NO controls that would limit this operational flexibility may x 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 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 field2-7

erected, especially older units. Newer watertubes also tend to be single burners and packaged. Steam2-8

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. x 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 SO . Higher 2 fluidizing velocities are necessary for circulating beds which have become more popular because of higher combustion and SO sorbent efficiencies. 2 Where environmental emissions are strictly controlled and low grade fuels are economically attractive, FBC boilers have become particularly popular because of characteristically low NO and SO emissions. x 2 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 include municipal and2-9

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 NO emissions. The practice of burning hazardous wastes in x boilers and industrial furnaces is currently regulated by the EPA under the Resource Conservation and Recovery Act (RCRA). 2.2 NO FORMATION AND BASELINE EMISSIONS

x NO is the high-temperature byproduct of the combustion of fuel x and air. When fuel is burned with air, nitric oxide (NO), the primary form of NO , is formed mainly from the high temperature reaction of atmospheric x nitrogen and oxygen (thermal NO ) and from the reaction of organically x bound nitrogen in the fuel with oxygen (fuel NO ). A third and less x 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 NO precursors that are rapidly oxidized to NO at lower x temperatures. Prompt NO is generally minor compared to the overall quantity of NO generated from combustion. However, as NO emissions x are reduced to extremely low limits, i.e., with natural gas combustion, the contribution of prompt NO becomes more important. The mechanisms of NO formation in combustion are very complex x and cannot be predicted with certainty. Thermal NO is an exponential x function of temperature and varies with the square root of oxygen2-10

concentration. Most of the NO formed from combustion of natural gas x and high grade fuel oil (e.g., distillate oil or naphtha) is attributable to thermal NO . Because of the exponential dependence on temperature, the

x control of thermal NO is best achieved by reducing peak combustion x temperature. Fuel NO results from the oxidation of fuel-bound nitrogen. x Higher concentrations of fuel nitrogen typically lead to higher fuel NO and x overall NO levels. Therefore, combustion of residual oil with 0.5 percent

x fuel-bound nitrogen, will likely result in higher NO levels than natural gas x or distillate oil. Similarly, because coal has higher fuel nitrogen content higher baseline NO levels are generally measured from coal combustion x than either natural gas or oil combustion. This occurs in spite of the fact that the conversion of fuel nitrogen to fuel NO typically diminishes with x increasing nitrogen 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 NO x emissions because of the suppression of the thermal NO contribution. x Test data were compiled from several sources to arrive at reported ranges and average NO emission levels for ICI boilers. Baseline data were x 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 2-22-11 Fuel Boiler type Uncontrolle d NO x range, lb/MMBtu Average,

lb/MMBtu Pulverized coal Wall-fired

Tangential Cyclone 0.46-0.89 0.53-0.68 1.12 a 0.69

0.61 1.12 Coal Spreader stoker

Overfeed stoker Underfeed stoker 0.35-0.77 0.19-0.44 0.31-0.48 0.53

0.29 0.39 Bubbling FBC Circulating FBC 0.11-0.81 0.14-0.60 0.32

0.31 Residual oil Firetube

Watertube: 10 to 100 MMBtu/hr >100 MMBtu/hr 0.21-0.39
0.20-0.79 0.31-0.60 0.31

0.36 0.38

Distillate oil Firetube

Watertube: 10 to 100 MMBtu/hr >100 MMBtu/hr 0.11-0.25
0.08-0.16 0.18-0.23 0.17

0.13 0.21

Crude oil TEOR steam

generator 0.30-0.52 0.46
Natural gas Firetube

Watertube: 100 MMBtu/hr >100 MMBtu/hr TEOR steam generator 0.07-0.13
0.06-0.31 0.11-0.45 0.09-0.13 0.10

0.14 0.26 0.12

Wood <70 MMBtu/hr

70 MMBtu/hr 0.010-0.050 0.17-0.30 0.022

0.24 Bagasse 0.15 b 0.15 MSW Mass burn

Modular 0.40 b 0.49 b 0.40

0.49 TABLE 2-2. SUMMARY OF BASELINE NO EMISSIONS x2-12

summarizes the range and average NO emissions from the various x categories of ICI boilers investigated in this study. On an average basis, coal-fired ICI boilers emit the highest level of NO , as anticipated. Among x the higher emitters are the wall-fired boilers with burners on one or two opposing walls of the furnace. Average NO levels were measured at x approximately 0.70 lb/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 NO x 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 NO formation. FBC boilers emit significantly lower x NO emissions than PC-fired units and are generally more efficient than x stokers. The large variations in baseline NO levels for the FBC units are x generally the result of variations in air distribution among FBC units. Newer FBC designs incorporate a staged air addition that suppresses NO x levels. Also the type of bed material and SO 22-13

sorbent influence the level of NO generated. FBC units are, on average, x the lowest NO emitters among coal burning ICI equipment. x Large variations in baseline NO levels are also shown for ICI boilers x 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 lb/MMBtu, a factor of nearly 4. This is attributable predominantly to large variations in fuel nitrogen content of these fuel oils. NO emissions from x 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 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 NO x 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. 2.3 CONTROL TECHNIQUES AND CONTROLLED NO EMISSION x LEVELS The reduction of NO emissions from ICI boilers can be x 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 2-32-14TABLE 2-3. EXPERIENCE WITH NOCONTROL TECHNIQUES ON ICI BOILERSxNOcontrolxtechniqueCoal-firedOil-/natural-gas-firedNonfossil-fuel-firedMSW-firedField-erectedPC-firedStokerFBCFielderectedwatertubePackagedwatertubePackagedfiretubeStokerFBCMass burnBT/OTXXWI/SIXXSCAXXaXXXbXaXXaLNBXXXXFGRXXXXNGRXbXbSNCRXbXXXXbXXXSCRXbXbXbBT/OT = Burner tuning/oxygen trimWI/SI = Water injection/steam injectionSCA = Staged combustion air, includes burners out of service (BOOS), biased firing, or overfire air (OFA)LNB = Low-NOburnersxFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid wasteSCA is designed primarily for control of smoke and combustible fuel rather than NO. Optimization of existing SCA (OFA) ports can leadaxto some NOreduction.xLimited experience.b2-15

lists the applicability of candidate NO control techniques for ICI boiler x 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.2-16 NO emissions can be controlled by suppressing both thermal and x fuel NO . When natural gas or distillate oil is burned, thermal NO is the

x x only component that can be practically controlled due to the low levels of fuel N in the distillate oil. The combustion modification techniques that

2 are most effective in reducing thermal NO are particularly those that x 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 (FGR), 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 NO standards. Although very x effective in reducing thermal NO , this technique has not been widely x applied because of its potential for large thermal efficiency penalties, safety, and burner control problems. FGR, 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 NO can also be reduced to some extent by minimizing the

x amount of excess oxygen, delaying the mixing of fuel and air, and reducing the firing capacity of the boiler. The 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 NO is partially offset by some increase in thermal NO x x because of higher peak temperature with lower gas volume. OT and LEA2-17

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 NO are in part negated by increases in fuel NO that x x result by increases in excess air at reduced boiler load. The reduction of fuel NO with combustion modifications is most x 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 NO can be x 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 NO reduction is not practical. Therefore, SCA is usually x accomplished with the retrofit of internally air staged burner or overfire air ports. The installation of low-NO burners for PC- and residual-oil-fired x 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 to2-18

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. 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 NO emission emitted by the x 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. NO control experience for ICI boilers with flue gas treatment x 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 NO reduction occurs by the selective reaction of NH radicals with NO to x 2 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 is2-19

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. 2.3.1 Combustion Modification Controls2-20

Table 2-42-21

ICI boiler and fuel NO control x Percent

NO x reduction Controlled

NO level, x lb/MMBtu CommentsPC, wallfired SCA 15-39 0.33-0.93 Limited applicability because of potential side effects.

LNB 49-67 0.26-0.50 Technology transfer from utility applications. NGR N.A. a 0.23-0.52 Limited experience. Technology transfer from utility applications. LNB+SCA 42-66 0.24-0.49 Technology transfer from utility applications. PC, T-fired SCA 25 0.29-0.38 Effective technique. Technology transfer from utility applications. LNB 18 0.36 LNCFS utility firing system design with closed coupled b OFA. NGR 30 0.23 Limited experience. LNB+SCA 55 0.20 LNCFS utility firing system design. Technology transfer from utility applications. Spreader stoker SCA -1-35 0.22-0.52 Potential grate problems and high CO emissions.

FGR+SCA 0-60 0.19-0.47 Limited applicability. RAP 32 0.30 Limited applicability. Gas cofiring 20-25 0.18-0.20 Only recent exploratory tests. NO reduction via lower O

. x 2 Coal-fired BFBC SCA 40-67 0.10-0.14 SCA often incorporated in new designs. Circulating coal-fired FBC SCA N.A. 0.05-0.45 SCA often incorporated in new designs.

SCA+FGR N.A. 0.12-0.16 Limited application for FGR.Residualoil-fired LNB 30-60 0.09-0.23 Staged air could result in operational problems.

FGR 4-30 0.12-0.25 Limited effectiveness because of fuel NO contribution. x SCA 5-40 0.22-0.74 Techniques include BOOS and OFA. Efficiency function of c degree of staging. LNB+FGR N.A. 0.23 Combinations are not additive in effectiveness. LNB+SCA N.A. 0.20-0.40 Combinations are not additive in effectiveness.Distillateoil-fired LNB N.A. 0.08-0.33 Low-excess air burner designs.

FGR 20-68 0.04-0.15 Widely used technique because of effectiveness. SCA 30 0.09-0.12 Limited applications except BOOS , Bias and selected OFA c for large watertube. LNB+FGR N.A. 0.03-0.13 Most common technique. Many LNB include FGR. LNB+SCA N.A. 0.20 SCA also included in many LNB designs.Naturalgas-fired SCA 17-46 0.06-0.24 Technique includes BOOS and OFA. Many LNB include c SCA technique. LNB 39-71 0.03-0.17 Popular technique. Many designs and vendors available. FGR 53-74 0.02-0.10 Popular technique together with LNB. LNB+FGR 55-84 0.02-0.09 Most popular technique for clean fuels. LNB+SCA N.A. 0.10-0.20 Some LNB designs include internal staging. N.A. = Not available. No data are available to determine control efficiency. See Appendix B for detailed a individual test data. LNCFS = Low-NO Concentric Firing System by ABB-Combustion Engineering. b x BOOS is not applicable to single-burner packaged boilers and some multiburner units. c TABLE 2-4. SUMMARY OF COMBUSTION MODIFICATION NO CONTROL x PERFORMANCE ON ICI WATERTUBE BOILERS2-22

summarizes control efficiency and NO levels achieved with the retrofit of x combustion modification techniques for watertube ICI boilers. The data base includes primarily commercial facilities that were retrofit to meet regulated NO limits. In addition. the data base also includes result x 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. The most effective NO control techniques for PC-fired ICI boilers x 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 lb/MMBtu. A combination of LNB plus overfire air (OFA) also achieved an average of 0.35 lb/MMBtu on eight ICI boilers. Lower NO x 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 NO staging. Furthermore, the long term effectiveness of these x controls for stokers was not evaluated in these exploratory tests. The average NO reduction for eight stokers with enhanced air staging was 18

x percent with a corresponding controlled NO level of 0.38 lb/MMBtu. x Largest NO reductions were accompanied by large increases in CO

x emissions. Gas cofiring in coal-fired stokers, only recently explored, achieves NO reductions in the 20 to 25 percent range only by being able to x operate at lower excess air. Air staging in coal-fired FBC boilers is very effective in reducing NO from these units. FBCs are inherently low NO emitters because low x x furnace combustion temperatures preclude the formation of thermal NO

. x2-23

Furthermore, the in-bed chemistry between coal particles, CO, and bed materials (including SO sorbents) maintains fuel nitrogen conversion to 2 NO at a minimum. The2-24

control of NO is further enhanced by operating these boilers with some air x staging. In fact, many new FBC designs, including circulating FBCs, come equipped with air staging capability especially for low NO emissions. x Excessive substoichiometric conditions in the dense portion of the fluidized bed can result in premature corrosion 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. NO reductions and controlled levels for residual oil combustion are x 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, NO control performance on this fuel is likely to x 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 NO level reported with LNB for residual-oil-fired ICI boilers is 0.19 x lb/MMBtu based on 17 Japanese installations and one domestic unit equipped with Babcock and Wilcox (B&W) XCL-FM burner for industrial boilers. 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 NO reductions from such units. Among x the controls more widely used are LNB, FGR, and LNB with FGR. Many LNB designs also incorporate low excess air and FGR, internal to the burner or external in a more conventional application. The average NO x reduction for FGR on natural-gas-fired boilers is approximately 60 percent from many industrial boilers, nearly all located in California. The average controlled NO level for FGR-controlled ICI watertube boilers is 0.05 x lb/MMBtu or approximately 40 ppm corrected to 3 percent O . For distillate 22-25

Fuel type NO control x Percent

NO x reduction Controlled

NO level, x lb/MMBtu CommentsResidualoil-fired LNB 30-60 0.09-0.25 Staged air could result in operational problems.

SCA 49 0.11 Technique generally not practical unless incorporated in new burner design.Distillateoil-fired LNB 15 0.15 Several LNB designs are available. Most operate on low excess air. FGR N.A. a 0.04-0.16 Effective technique for clean fuels.Naturalgas-fired SCA 5 0.08 Technique not practical unless incorporated in new burner design. LNB 32-78 0.02-0.08 Several LNB designs are available. Some include FGR or internal staging. FGR 55-76 0.02-0.08 Effective technique. Used in many applications in California. LNB+FGR N.A. 0.02-0.04 Most popular technique for very low NO levels. Some x LNB designs include FGR. Radiant LNB 53-82 0.01-0.04 Commercial experience limited to small firetubes. N.A. = Not available. No data are available to determine control efficiency. See Appendix B for detailed a individual test data. TABLE 2-5. SUMMARY OF COMBUSTION MODIFICATION NO CONTROL x PERFORMANCE ON ICI FIRETUBE BOILERS oil, the average FGR-controlled level from watertube boilers is 0.08 lb/MMBtu or approximately 65 ppm corrected to 3 percent O . Average NO 2 x emissions controlled with LNB plus FGR are slightly lower than these levels. Table 2-5 summarizes results of controls for firetube units. Controlled NO levels achieved on these boiler types are generally slightly x lower than levels achieved on watertube units. For example, LNB+FGR recorded an average of about 0.033 lb/MMBtu or approximately 35 ppm corrected to 3 percent O . FGR by itself is also capable to achieve these 2 low NO levels when burning natural gas. In addition to these combustion

x controls, both OT and WI have been retrofitted in combination on selected packaged industrial boilers in California to meet very low NO levels. x2-26

These controls offer the potential for economic NO control because of low x initial capital investment compared to either FGR or LNB. NO reduction x 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. 2.3.2 Flue Gas Treatment Controls Application of flue gas treatment controls in the United States is generally sparse. Table 2-62-27

ICI boiler and fuel NO control x Percent

NO x reduction Controlled

NO level, x lb/MMBtu Comments PC, wall-fired SNCR-Urea 30-83 0.15-0.40 Experience relies primarily on utility retrofits. Because of relatively higher NO , x higher control efficiency is frequently achieved. Coal-fired FBC SCR 53-63 0.10-0.15 Limited applications to few foreign installations. No domestic experience. Coal-Stoker SNCR-Ammonia 50-66 0.15-0.18 Control levels achieved in combination with OFA controls. Coal-Stoker SNCR-Urea 40-74 0.14-0.28 Control levels achieved in combination with OFA controls. Wood-fired stoker SNCR-Ammonia 50-80 0.04-0.23 Vendors of technology report good efficiency for stoker applications irrespective of fuels. SNCR-Urea 25-78 0.09-0.17 MSW stokers and mass burn SNCR-Ammonia 45-79 0.07-0.31 Vendors of technology report good efficiency for stokers applications, irrespective of fuels. SNCR-Urea 41-75 0.06-0.30 SCR 53 0.05 Experience limited to one foreign installation. Coal-fired FBC SNCR-Ammonia 76-80 0.04-0.09 Technique is particularly effective for FBC boilers. Applications limited to California sites. SNCR-Urea 57-88 0.03-0.14 Wood-fired FBC SNCR-Ammonia 44-80 0.03-0.20 Technique is particularly effective for FBC boilers irrespective of fuel type. Applications limited to California sites. SNCR-Urea 60-70 0.06-0.07 Wood-fired Watertube SNCR-Urea 50-52 0.14-0.26 Limited application and experience. SCR 80 0.22 Only two known installations in the United States. Natural-gas- and distillate-oil-fired watertube SNCR-Ammonia 30-72 0.03-0.20 Limited application and experience. SNCR-Urea 50-60 0.05-0.10 SCR 53-91 0.01-0.05 Experience principally based on foreign and some southern California installations. TABLE 2-6. SUMMARY OF FLUE GAS TREATMENT NO CONTROL x PERFORMANCE

ON ICI BOILERS2-28

summarizes the range in NO reduction performance and controlled NO x x 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 NO reduction efficiency of SNCR for PC-fired boilers is based

x on results from four boilers, one a small utility unit. For these boilers, NO x reductions ranged from 30 to 83 percent and averaged 60 percent, with controlled NO levels in the range of 0.15 to 0.40 lb/MMBtu. SNCR x 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 NO reduction x and controlled level of nearly 75 percent and 0.08 lb/MMBtu, respectively. SNCR results for 13 coal-fired stokers ranged from 40 to 74 percent reduction, with controlled NO levels between 0.14 and 0.28 lb/MMBtu. For x stokers burning primarily waste fuels, including MSW mass burning equipment, several applications of SNCR resulted in NO reductions in the x range of 25 to 80 percent, averaging about 60 percent, with controlled levels in the range of 0.035 to 0.31 lb/MMBtu. 2.4 COST AND COST EFFECTIVENESS OF NO CONTROL TECHNIQUES x 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 NO control x technologies and from data available in the open literature. The total2-29

capital investment was annualized using a 10-percent interest rate and an amortization period of 10 years. Cost2-30

effectiveness was calculated by dividing the total annualized cost by an NO reduction for each retrofit cost case using boiler capacity factors in x the range of 0.33 to 0.80.2-31

Table 2-72-32 Fuel type Boiler type

and size, MMBtu/hr NO control x technique Estimated

NO x control level, lb/MMBtu a NO x

reduction, tons/yr Total capital

investment, $/MMBtu/hr Cost

effectiveness, $/ton of NO x Pulverized coal Watertube

(400) LNB 0.35 310 5,300 1,170-1,530

SNCR 0.39 270 1,600-2,100 1,010-1,400 SCR 0.14 490 20,000 3,400-4,200 Coal FBC (400) SNCR 0.08 210 1,600 890-1,030

S. Stoker (400) SNCR 0.22 270 1,100 1,300-1,500 Natural gas Single burner

packaged watertube (50) OT+WI 0.06 5.8 530 710-820

LNB 0.08 4.3 650-2,300 570-2,400 LNB+FGR 0.06 5.8 2,100-4,700 1,600-4,400 SCR 0.02 8.7 2,400-6,900 4,800-6,900 Packaged firetube (10.5) OT+WI 0.04 1.3 2,400 3,100-3,700

OT+FGR 0.07 0.65 5,300 8,000-11,000Multiburner fielderected watertube (300) OT+SCA b 0.15 53 190 210-240

LNB 0.12 60 5,100-8,300 2,100-4,200 Distillate oil Single burner

packaged watertube (50) LNB 0.10 3.3 2,300 460-1,900

LNB+FGR 0.07 6.6 2,100-4,700 1,000-3,300 SCR 0.03 25 2,400-6,900 3,900-5,500 Packaged firetube (10.5) OT+FGR 0.12 1.6 5,400 4,500-6,200

Multiburner watertube (300) LNB 0.10 72 5,100-8,300 3,100-6,300

Residual oil Single burner

packaged watertube (50) LNB 0.19 19 2,300 240-1,000

LNB+FGR 0.15 23 2,100-4,700 760-2,000 SCR 0.06 33 2,400-6,900 2,000-2,900 Firetube (10.5) LNB 0.17 4.6 5,400 2,700-3,600

Multiburner watertube (300) LNB 0.19 120 5,100-8,300 1,600-3,300

Wood waste Stoker

(150) SNCR 0.11 43 2,100-2,500 1,300-2,400

FBC (400) SNCR 0.11 61 970 1,500-1,600

MSW Stoker

(500) SNCR 0.18 240 2,100-3,300 1,500-2,100
Average levels calculated from the data base available to this study. Average levels do not necessarily represent a what can be achieved in all cases. SCA is burners out of service. b Notes: Boiler capacity factor between 0.50 and 0.66. See Appendices D, E, F, and G for details of costing.

Costs do not include installation of continuous emission monitoring (CEM) system. Annual NO reduction x based on 0.50 capacity factor. Total capital investment from Appendices E through G. TABLE 2-7. ESTIMATED COST AND COST EFFECTIVENESS OF NO x CONTROLS (1992 DOLLARS)2-33

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 NO retrofit market. x 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 gas-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 NO . These costs, however, do not x consider the installation of emission monitoring instrumentation. The cost of CEM systems can easily outweigh the cost of NO controls for these x 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 FGR, LNB, and LNB with FGR 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 with2-34

cost effectiveness as low as $240/ton to as high as $6,300/ton, depending on fuel2-35

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 $1,100/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 $1,010/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). 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. 2.5 ENERGY AND ENVIRONMENTAL IMPACTS OF NO CONTROL x TECHNIQUES Combustion modification controls to reduce NO emissions from ICI x 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 NO emissions with some x 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 NO and CO as well. x2-36

Figure 2-1. Cost effectiveness versus boiler capacity, PC wall-fired boilers.2-37

Figure 2-3. Cost effectiveness versus boiler capacity, distillate-oil-fired boilers.2-38

Figure 2-4. Cost effectiveness versus boiler capacity, residual-oil-fired boilers. Figure 2-2. Cost effectiveness versus boiler capacity, natural-gas-fired packaged watertube

boilers. Boiler and fuel type NO x

control NO x

reductio n,% CO emissions impact

Emissions at low NO ,

x ppm Average

change, % Coal-fired watertube LNB 67 13-430 +800 LNB+SCA 66 60-166 +215 Coal-fired stoker SCA 31 429 +80 Coal-fired FBC SCA 67 550-1,100 +86 Gas-fired packaged firetube FGR 59-74 3-192 - 93 - -6.3 LNB 32-82 0-30 -100 - -53 Gas-fired packaged watertube FGR 53-78 20-205 -70 - +450 LNB+FGR 55 2 -98 Distillate oil packaged watertube FGR 20-68 24-46 +20 - +1,000

Distillate oil packaged firetube LNB 15 13 +120

Residual oil watertube FGR 4-30 20-145 0 - +1,400 SCA 8-40 20-100 N.A. a N.A. = Not available. a TABLE 2-8. EFFECTS OF NO CONTROLS ON CO EMISSIONS FROM ICI x BOILERS Table 2-8 lists CO emissions changes that were recorded with the2-392-40

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 NO emission levels. In recognition of this, the South x Coast Air Quality Management District (SCAQMD) in California permits 400-ppm CO levels for low-NO permits under its Rule 1146. Also, the x American Boiler Manufacturers Association (ABMA) recommends 400-ppm CO levels when NO emissions from ICI boilers are lowered. Increases in x particulate emissions and unburned carbon are other potential impacts of combustion modification NO control retrofits on oil- and coal-fired ICI x 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-based2-41

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 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 NO control techniques. For example, the injection of water or steam to x chill the flame and reduce thermal NO will reduce the thermal efficiency of x 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 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 latent2-42

heat loss at the stack. Estimates of increases and potential decreases in energy consumption are presented in Chapter 7.3-1 3. ICI BOILER EQUIPMENT PROFILE

ICI boilers span a broad range of equipment designs, fuels, and heat input c apacities. The feasibility of retrofitting existing ICI boilers with NO x controls, and the effectivenes s and costs of these controls, depend on many boiler design characteristics such as heat transfer configuration, furn ace size, burner configuration, and heat input capacity. Many of these desig n character istics are influenced by the type of fuel used such as natural gas , fuel oil, pul verized and stoker coal, and solid waste fuels. Uncontrolled NO x emiss ions also vary significantly among the various fuels and boiler design types. Combustion modifications are the most common approach to reducin g NO , but experience with many ICI boiler types is limited. FGT controls can x su bstitute for combustion modifications or can provide additive NO x reductions from controlled-combustion levels. This chapter presents an overview of ICI boiler equipment to aid in the
ass essment of NO control technologies. A boiler is defined here as a x combustion device, fired with fossil or nonfossil fuels, used to p roduce steam
or to heat water. In most ICI boiler applications, the steam is used fo r pr ocess heating, electrical or mechanical power generation, space heating , or a com bination of these. Smaller ICI boilers produce hot water or stea m primarily for space heating. The complete boiler s ystem includes the furnace and combustion syste m, 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 new3-2

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
c h emical products industry, the food industry, and the petroleum industry. 1 As a whole, ICI boilers span the range of heat input capacities fro m 0.4 to 1,500 MMBtu/hr (0.11 to 440 MWt). Table 3- 13-3

Heat transfer configuratio n Design and

fuel type Capacity

range, MMBtu/hr a % of

ICI boiler units b,c % of ICI

boiler capacity b, c Application

d Watertube Pulverized coal 100-1,500+ ** 2.5 PH, CG

Stoker coal 0.4-550+ e ** f 5.0 SH, PH, CG FBC coal g 1.4-1,075   PH, CG Gas/oil 0.4-1,500+ 2.3 23.6 SH, PH, CG Oil field steamer 20-62.5 N.A. h N.A. PH

Stoker nonfossil 1.5-1,000 e **  1.1 SH, PH, CG

FBC nonfossil 40-345 ** ** PH, CG Other nonfossil 3-800   SH, PH, CG Firetube HRT coal 0.5-50 **  ** SH, PH

Scotch coal 0.4-50   SH, PH Vertical coal <2.5 **  ** SH, PH Firebox coal 0.4-25   SH, PH HRT gas/oil 0.5-50 1.5 1.5 SH, PH Scotch gas/oil 0.4-50 4.8 4.6 SH, PH Vertical gas/oil <2.5 1.0 **  SH, PH Firebox gas/oil <20 6.5 48 SH, PH HRT nonfossil 2-50 N.A. N.A. SH, PH Firebox nonfossil 2-20 N.A. N.A. SH, PH

Cast iron Coal <0.4-14 9.9 1.3 SH, PH

Gas/oil <0.4-14 72 9.6 SH, PH Tubeless Gas/oil <0.4-4 N.A. N.A. SH, PH TABLE 3-1. ICI BOILER EQUIPMENT, FUELS, AND APPLICATIONS3-4

g ives the distribution of the major ICI boiler types currently in use

. Figures 3-1 and 3-2 illustrate the range of heat input capacities applicable to vario us fuels, heat transfer configurations, and equipment types. Industrial boilers generally have heat input capac ities ranging from 10 to 250 MMBtu/hr (2.9 to 73 MWt). This range encompasses most boi lers currently in use in the industrial, commercial, and institutional sectors. Those industrial boi lers with he at input capacities greater than 250 MMBtu/hr (73 MWt) are generall y similar to utility boilers. Therefore, many of the NO controls applicable to 5 x utility boilers are also candidate controls for large industrial boilers. Boilers with heat input capac ities less than 10 MMBtu/hr are generally classified as commercial/institutional u nits. These boilers are used in a wide
arra y of applications, such as wholesale and retail trade, office buildings , hotels, restaurants, hospit als, schools, museums, and government facilities, prima rily providing steam and hot water for space heating. Boilers used in 3 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. 63-5Figure 3-1. Occurrence of fuel types and heat transfer configurations by capacity.3-6Figure 3-2. Occurrence of ICI boiler equipment types by capacity.3-7

As the types and sizes of ICI boilers are extremely varied, so too ar e the fuel types burned in thes e units. The most commonly used fuels include nat ural gas, distillate and residual fuel oils, and coal in both crushed an d pulverized form. Although the primary fuel types us ed are fossil based, there is a growing percen tage of nonfossil fuels being burned for industrial steam and nonutility power generation. The fuels' physical and chemica l composit ion greatly influence the quantity and type of emissions produced, and the feasibility of certain types of NO controls, as will be discussed i n x 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 main hea t transfer configurations of boilers. Section 3.2 addresses those units pr imarily 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 impor tant way of classifying boilers is by heat transfe r conf iguration. The four major configurations are watertube, firetube, cas t iron, and tubeless. In3-83-9 Figure 3-3. Simplified diagram of a watertube boiler. 9

Figure 3-4. Watertube boiler. 10 a watertube boiler (Figures 3-3 and 3-4), combustion heat is transferred to3-10

water3-11

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 hea t 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. They can b e 7,8 eit her packaged or field-erected, depending on their size. In general, mos t uni ts greater than 200 MMBtu/hr heat input capacity are field-erected. Fielderected units are asse mbled onsite; these include all large multi-burner gasand oil -fired boilers and most PC and stoker units. Packaged boilers ar e shipped by rail or flatbed truck as complete units. New gas- and oil-fire d boilers a s large as 150 MMBtu/hr (44 MWt) heat input capacity are typicall y shop-as sembled and shipped as packaged units. Demand for package d boilers peaked in the 1970s, when premium fuel restrictions and the rapidly escalating prices of oil and gas caused their decline. However, wit h go vernment's repeal of its premium fuel use restrictions, and with greate r availability and lowered prices of oil and gas, the packaged boiler is be coming increasingly popular. 113-12 Figure 3-5. Simplified diagram of a firetube boiler. 15 In a firetube boiler (Figures 3-5 and 3-6), the hot combustion gases fl ow throu gh 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 larg e variations in steam demand, firetube units are more susceptible to stru ctural failure than watertube boilers, since, in the firetube units, the high-pressure steam is contai ned by the boiler walls rather than by multipl e small diameter watertubes, which are inherently stronger. As a 6 conseque nce, ICI firetube boilers are typically small, with heat inpu t capacities limit ed to less than 50 MMBtu/hr (15 MWt) , and steam pressures 12 limited to 300 psig, although high-end steam pressures of 150 psig are more
com mon. Firetubes are used primarily where loads are relatively constant

.3-13 Figure 3-6. Firetube boiler. 16 Nearly al l firetube boilers are sold as packaged units because of thei r relatively small size. In a cast iron boiler, combustion gases rise through a vertical hea t exchanger and out through an exhaust duct. Water in the heat exchange r tubes is heated as3-14

it moves upward through the tubes. Cast iron boilers produce low-pressure stea m or hot water, and generally burn oil or natural gas. They are use d 13 primarily in the residential and commercial sectors, and have heat inpu t capacities up to 14 MMBtu/hr (4.1 MWt). 14 The tubeless des ign incorporates nested pressure vessels with water in between the shells. Combustion gases are fired into the inner pressur e vessel and are then sometimes recirculated outside the second vessel. 3.2 COAL-FIRED BOILER EQUIPMENT TYPES In 1977, 12 percent of all ICI boilers in the United States were coal - fired. Coal has not been utilized in ICI boiler s as extensively as oil or natural

3 gas, chiefly due to cost-effectiveness considerations for the smaller units

. Alth ough 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 naturalgas-fired firetube units. As discus sed above, this is because firetube boilers are usually limited to 50 MMBtu/hr (15 MWt) heat input capacity. For smaller in dustrial and commercial units below this capacity, coal has not been a popular fuel because of the high capital cost of coal handling equipmen t relative to the costs of the boilers. Thus, most ICI boilers are fueled with oil or natural gas. Nev ertheless, there has been a market percentage increase in coal - fired boilers since the early 1970s. Of the total industrial boiler unit s 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 group s consumed 66 percent of the t otal industrial coal used in 1980. These groups in cluded the chemical products industry, the paper products industry, th e food and kindred products industry, the primary metals industry, and th e transportation equipment industry. 173-15

3.2.1 Coal-fired Watertube Boilers Coa l-fired watertube boilers made up less than 1 percent of the tota l United States ICI boiler population in 1977, the last time an industrial boiler inven tory was taken. Yet, due to their larger capacities, these unit s
ac counted for 14 percent of the total operating capacity. Coal-fire d 18 watertube ICI boilers can be classified into three major categories: stokers, PC-fired units, and FBC boilers. The following subsections describe thes e types of boilers. 3.2.1.1 Stoker-firing Watertube Boilers Sto ker-firing systems account for approximately 90 percent of coal - fire d watertube ICI boilers. Stoker systems can be divided into thre e 19 g r oups: underfeed stokers, overfeed stokers, and spreader stokers. These systems differ in how fuel is supplied to either a moving or stationary grate fo r burning. One important similarity among all stokers is that all desig n types use underfeed air to combust the coal char on the grate, combined with
one or mo re levels of overfire air introduced above the grate. This help s
ensure complete combustion of volatiles and low combustion emissions

. Most stokers als o utilize flyash reinjection to minimize the unburned carbon
c o ntent in the flyash. Underfeed stokers were once the primary stoker type used in industrial and utility steam generation, but the high costs o f maintenance and these units' slow response to varying loads have made t hem le ss competitive in the present market. Spreader stokers, however, ar e extremely pop ular in industry today, due in part to their wide fuel capability, discussed further below. 203-16 Figure 3-7. Single-retort horizontal-feed underfeed stoker. 21
Underfee d stokers are generally of two types: the horizontal-feed , side-ash-discharge type, sh own in Figure 3-7; and the gravity-feed, rear-ashdischarge type, shown in Figure 3-8. The hori zontal-feed, side-ash-discharge type of stoker is used primarily in small boilers supplying relatively constant st eam loads of less than 30,000 lb/hr (~30 MMBtu/hr input). As shown i n 21 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 ca lled 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

. Combus tion air is supplied through tuyeres at the side grates, wher e combustion is completed. Overfire air is often supplied to the flame zon e above the bed to provide more combustion air and turbulence for mor e3-17 Figure 3-9. Overfeed chain-grate stoker. 21 complete combustion. These smaller underfeed stokers typically have one 22 or two retorts. Maximum allowable burn ing rates are typically 425,000 Btu/hr per square foot of grate area. Allowabl e burning rates determine the size of 21 the grate are a for a given heat input rate. The higher the burning rate th e higher t he intensity of combustion and thickness of the burning bed. Th e gravity-feed, rear-a sh-discharge underfeed stoker often has multiple retorts. Typically , this type of stoker has a maximum 500 MMBtu/hr (146 MWt) hea t inp ut capacity. In this type of stoker, coal is introduced through a coa l 21 hoppe r and is ram-fed to the inclined retorts and grates. The retorts an d grates are typically inclined 20 to 25

. Maximum allowable fuel burning rates are 600,000 Btu/ft -hr. 2 21 An overfeed stoker, shown in Figure 3-9, uses a moving grat e
assem bly. Coal is fed from a hopper onto a continuous grate that convey s the coal into the furnace. As coal moves through the furnace on the grate, it3-18 Figure 3-8. Multiple-retort gravity-feed underfeed stoker. 21 passes ove r several air zones for staged burning. The air serves a dua l purpose; it is used for combustion as well as for cooling the fuel bed an d grate, preventing fusing of the coal. At the far end of the moving grate , comb ustion is completed and ash discharged to the bottom of the furnace

. An adjustable gate at the coal feed point a llows regulation of the depth of the fuel bed. The three types of grates used with overfeed c oal stokers are the

23,24 ch ain, travelling, and water-cooled vibrating grates. These overfeed stoke r systems are often referred to by the type of grate employed. Overfeed coalfired sy stems typically range up to 350 MMBtu/hr (100 MWt) heat inpu t capacit y. Maximum fuel burning rates for overfeed stokers are roughl y 500,000 Btu/ft -hr. 2 21 In a spreader stoke r, mechanical or pneumatic feeders distribute coal unifo rmly over the surface of a moving grate. In a typical spreader stoke r boiler, shown in Figure 3-1 03-19 Figure 3-10. Spreader stoker. 21 , primary air is admitted evenly throughout the active grate area, providin g some fuel bed cooling, whil e above the grate an overfire air system provides
s e condary air and turbulence. The injection of the fuel into the furnace and onto th e grate combines suspension burning with a thin, fast-burning fue l bed. The amount of fuel burned in suspension depend s primarily on fuel size and composition, among other factors. Generally, the finer the fuel and/or the higher it s volatile matter content, the more energy released in suspension ; the highe r the moisture content, the more energy released on the grate. 24 Ma ny spreader stoker units incorporate a flyash recirculation system , whereby unburned solids in the flyash are collected and recirculated bac k into the primary combustion chamber. Heat input capacities of spreade r stokers ty pically range from 5 to 550 MMBtu/hr (1.5 to 160 MWt), althoug h3-20

there are a few units of 1,500 MMBtu/hr (440 MWt) or more. Maximum fuel 18 burning rates are highest for this stoker design, often reaching a maximum of 750,000 Btu/ft -hr. 2 21 In general, stoker coal is fed crushed with a nominal size less than 2 inches. Overfeed and sp reader stokers can be used to burn almost any type of coal or solid fuel, including wood, wood waste, and bagasse. Cokin g bituminous coals, however, are not used in overfee d stokers to avoid matting and restricting the airflow through the grate. Coking has little effect on the performance of spre ader stokers. Most packaged stoker units designed for 8 coal firing are less than 100 MMBtu/hr (29 MWt) capacity. Larger units are 25 typically field-erected. 3.2.1.2 PC-fired Watertube Boilers PC-fired boilers account for a small percentage of the ICI watertub e boiler population. In 1977, they accounted for less than 1/10th of 1 percen t of all installed ICI boiler units. However, they accounted for approximatel y 2.5 percent of t otal ICI boiler capacity. This disparity is due to the fact that 18 PC-fired boilers are almost e ntirely limited to sizes larger than 100 MMBtu/hr (29.3 MWt) heat input capacity. Below this level, the required coal-handling
a n d pulverizing equipment can increase the capital cost of PC-fired units to as high as 1 0 times that of an oil- or natural-gas-fired industrial boiler of the same size. Thus, when coal is the fuel of choice, stoker firing dominates in

26 units below about 150 MMBtu/hr (44 MWt) heat input capacity. PC firing and FBC are usually the choices for larger boilers. PC-fired ICI boi lers are nearly 27 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 coa l burns on a grate. Finely ground coal (70 percent through 200 mesh) i s typically mixed with primary combustion air and fed to the burner or burners,3-21 Figure 3-11. Wall firing. 26 whereupon it is ignited and mixed with secondary combustion air. D epending upon the location of the burners and the direction of coal injection into th e 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 schema tic of a single-wall-fired boiler. Wall-fired boil ers can be either single-wall-fired, with burners on only one wall of th e fur nace firing horizontally, or opposed-wall-fired, with burners mounted o n 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. 263-22 Figure 3-12 shows a plan view of a tangential -firing configuration, with the burn ers mounted in the corners of the furnace. The fuel and air ar e inje cted toward the center of the furnace to create a vortex that enhance s air/fue l mixing. Larger flame volumes and flame interaction contribute t o characteristically low er NO levels from tangential firing. Tangential boilers, x like opposed-wall boilers, are commonly used in utility applications. 26 Cyclon e furnaces are often categorized as PC-fired systems eve n th ough the coal burned in cyclones is crushed and not pulverized. Thes e furnaces burn low-fusion-temperature coal crushed to a maximum particl e size of about 4.75 mm (95 percent through 1/4 inch mesh). The coal is fe d 8 tangent ially, with primary air, into a horizontal cylindrical furnace. Smalle r
co al particles are burned in suspension, while larger particles adhere to a mol ten layer of slag on the combustion chamber wall. The larger particle s remain in the slag until they are burned. Because of their intense furnac e hea t release rates, cyclones emit high levels of NO , and are generally more x difficult to control with c ombustion 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 eith er dry bottom or wet bottom, depending on whether the ash is removed in so lid or molten state. This is an important differentiation with respect to NO emissions, as wet-bott om boilers x gener ally operate at higher furnace temperatures and subsequently emi t greater amounts of NO . Boiler designs in wet- and dry-bottom furnace s x hinge o n coal quality and ash fusion properties. Wet-bottom furnaces ar e 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 3.2.1.3 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, due3-23 Figure 3-12. Tangential firing. 26 prima rily to their capabilities to burn a wide range of solid fuels and to us e combined NO /SO controls within the furnace. FBC units generate steam for x x ICI facilities, cogenerators, independent power producers, and utilities. In the United States, FBCs in use in the industrial sector account for less than 1 0 percent of the total installed FBC generating capacity. 28 There a re two major categories of FBC systems: (1) atmospheric , operating at a slight negative draft, and (2) pressurized, operating at from 4 to 30 atmos pheres (60 to 450 psig). Pressurized FBC (PFBC) systems ar e being demonstrated at two utility sites in the United States. No PFBC units
are curr ently in operation in the ICI sector, and it is unlikely that suc h 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 several3-24

years aw ay from full commercialization in the utility industry, and that nearterm opportunities for large industrial applications rest with atmospheric FBC technology. Currently, only atmospheric FBC systems are used in the IC I

28 sector. Therefore, the remainder of this section describes atmospheri c

29 FBCs. In a typical FBC boiler , solid, liquid, or gaseous fuel or fuels, together with a mixture of in ert material (e.g., sand, silica, ash) and/or a sorbent such
as limesto ne, are kept suspended by a steady upward flow of primary ai r th rough the fuel bed. This fuel bed fluidization promotes turbulence, which i m proves mixing of fuel and air, allowing the FBC to combust solid fuel at a subst antially lower and more uniformly distributed temperature—typicall y 815 to 87 0 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 mai n advantages of FBCs over conventional boiler units:

Lower combustion temperatures result in less formation o f thermal NO and allow use of sorbent to reduce SO emissions

x 2 Lower combustion temperatures are generally below the as h fusion temperatur es of most fuels, resulting in less slagging and fouling of heat transfer surfaces FBCs are able to burn many types of fuels be sides coal, including low-grade fuels such as petroleum coke, waste coal, municipa l waste, and biomass materials Flexible-fuel capability is inherent in FBC design, and the ability to efficiently burn low-grade fuels would generally be impracti cal without FBC technology. High combustion efficiencies are g enerally due to the long retention times of solids in the fluidized beds. 303-25 Figure 3-13. Bubbling FBC schematic. 32 FBCs are primarily watertube boilers, especially among the large r units, although firetube units are also available. In some FBCs — bubbling bed units, described below — additional watertubes are located within th e fuel bed itself, oriented either horizontally or vertically. Steam output i s contr olled by manipulating the primary bed parameters of height , temperature, fuel inpu t, and fluidization velocity—the velocity of the primary air through the bed. Fir etube FBC boilers are also available and in use. However, of th e more than 50 FBC manufacturers worldwide, o nly 12 offer firetube designs in addition to the more conventional watertube systems. This indicates th e 31 rel ative popularity of watertube FBC systems as compared to the les s common firetube units. Figures 3-13 and 3-14 show the two principal types of atmospheric FB C boile rs, the bubbling bed and the circulating bed. The fundamenta l3-26 Figure 3-14. Circulating FBC schematic. 32 distinguishing feature between the se types is the fluidization velocity. In the bubbl ing-bed design, the fluidization velocity is relatively slow, rangin g betwee n 5 and 12 ft/s, the idea being to minimize solid carryover into th e
convec tive passes of the boiler. In some units, relatively slow fluidizatio n velocities allow watertubes to be placed within the bed itself, as long as tube
ero sion is not a problem. Circulating FBCs, however, employ fluidizatio n velocities as high as 30 ft/s and actually promote the carryover or circulation of solids—fuel and bed material. Solids leaving the prim ary combustion zone
are tra pped by high-temperature cyclones and recirculated back to th e primary combustion chamber. In some circulating-bed designs, a secondary combustion chamber is used to complete combustion of the fuel. Th e circul ating FBC maintains a continuous, high-volume recycle rate tha t increase s the fuel residence time compared to the bubbling-bed design

.3-27

Beca use of this, circulating FBCs often achieve higher combustio n efficiencies and better sorbent utilization in the control of SO emissions than 2 bu bbling-bed units. This is one reason why the bubbling bed FBC, stil l 33 favored for small-scale boilers, is not as favored for larg e-scale industrial and util ity applications. Circulating FBCs have their heat exchange tube s 33 downstream of the recirculating cyclone. Of atmospheric FBCs currently in use in all sectors, includin g industrial, utility, independent power production, and cogeneratio n applications, coal is the primary fuel used, followed in descending order by biomass, coal waste, and municipal waste. Coal waste and municipal waste
a r e not significant fuel types for larger FBC plants. Of 157 non-utility FBC 33 boilers in operation in the United States in 1991, 116 were of heat inpu t capacities below 250 MMBt u/hr (73 MWt or 37 MWe), and of these, 51 burned coal exclu sively. Another 18 units burned coal in combination with wood , 2 slud ge, coke, or biomass. The coal-burning FBCs ranged between 8.4 an d 235 MMB tu/hr heat input capacity (2.5 to 69 MWt, or 1.25 to 35 MWe output), and accounted for a relatively small a mount of the total capacity of coal-fired ICI boi lers. 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 ec onomic standpoint, ICI FBC boilers that burn coal do no t 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-fir ed unit. The use of lower cost opportunity fuels, such as coke , biomass, wood waste, a nd low-grade coals, can provide sufficient economic incen tive to offset higher initial capital costs. When used in electric powe r generating applications, FBC coal-fired power plants produce elect ricity at 1.53-28

to 3 times the cost of gas-based power g eneration. Future growth in the ICI 34 FBC boi ler market is expected to occur mainly among units that burn fuel s other than coal, such as waste fuels like wood and manure. 3.2.2 Coal-fired Firetube Boilers Coal-fired firetube boilers represent a small portion of the ICI boile r population. In 1977, coal-fire d firetube boilers accounted for only 10 percent of the industrial and commercial firetube boiler population in the Unite d States, and only 1.5 percent of al l ICI boilers. The four most common types 35 of firet ube boilers used with coal are the horizontal return tubular (HRT) , Sc otch, vertical, and the firebox; however, the HRT boiler is generally use d with gas or oil instead of coal. Virtually all coal-fired firetube boilers ar e packaged units. The following sections discuss these boiler types as well as other less common firetube boilers. 3.2.2.1 HRT Firetube Boilers In a typical HRT boiler, the firetub es are horizontal and self-contained, with the combustion chamber separate. When solid fuel such as c oal is used, it is fed through a feed chute onto grates in the primary com bustion chamber. The combustion gases then pass through the firetubes of the boiler. Most coal- and other solid-fuel-fired HRT boilers are two-pass designs. In a two-pass HRT boiler, shown in Figure 3-1 53-29Figure 3-15. Two-pass HRT boiler.383-30

, primary and secondary combustion chambers are located b eneath the boiler tank. The combustion gases flow over the bridge wall towards the rear of the boiler, heatin g the outer shell of the tank. At the rear of the boiler, th e combustio n gases then enter the firetubes. The gases flow through th e fire tubes, transferring additional heat to the water, and are then exhauste d through the boiler stack. HRT boilers come in various sizes, ranging from 0.5 to 50 MMBtu/h r (0.15 to 15 MWt) heat i nput 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 li quid or gaseous fuels, due to the possibility of3-31

scaling or slagging. 3.2.2.2 Scotch Firetube Boilers A Scotch, o r shell, boiler differs from the HRT boiler in that the boiler and furnace are containe d in the same shell. In a two-pass unit, combustion
occ urs in the lower half, with the flue gases passing beneath the bottom o f the water basin occupying the upper half. The gases then pass through the firetubes running through the basin. Scotch boilers also come in three- o r fo ur-pass configurations. The capacity of Scotch boilers ranges up t o 50 MMBtu/hr (15 MWt) heat input, with pressures up to 300 psig, althoug h more typical pressures are approx imately 200 psig. Like HRT boilers, coal is not as commonly used in Scotch bo ilers due to slagging and scaling. More 36
co mmon gas- and oil-fired Scotch units are shown in Figures 3-6 and 3-1 63-32 Figure 3-16. Four-pass gas-/oil-fired scotch boiler. 393-33

. 3.2.2.3 Vertical Firetube Boilers Another common firetube design is the vertical boiler. A vertica l firetube boiler is a single-pass unit in which the firetubes come straight u p from the water-cooled combustion chamber loc ated at the bottom of the unit. Figure 3-1 73-34 Figure 3-17. Exposed-tube vertical boiler. 373-35

depicts an exposed-tube vertical boiler in which the firetubes exten d from the top of the furnace into the steam space. This causes the steam to b e superheated and reduces carryover of moisture. 373-36 Figure 3-1 83-37 Figure 3-18. Submerged-tube vertical boiler. 373-38

shows a submerged-tube vertical boiler in which the firetubes extend from the furna ce to the tube sheet, which is below the water level. This desig n prevents the ends of the firetubes from overheating. A conical flue ga s coll ector directs the flue gases to an exhaust stack. The submerged-tub e boiler has essentially been discontinued, however, because the collector is difficult to build and tends to leak. 37 Ve rtical boilers are small, with heat input capacities unde r 2.5 MMBtu/hr (0.73 MWt). However, they are capable of burning all types of fuels, including coal. 3.2.2.4 Firebox Firetube Boilers3-393-403-41

Anothe r type of firetube boiler is the firebox boiler. These units ar e 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 compac t firebox boilers. A locomotive boiler is a single-pass horizonta l fire tube 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 und erfeed stokers, or are capable of being hand-fired. They are generall y limited in size to below 25 MMBtu/hr (7.3 MWt) heat input capacity. 40 3.2.3 Cast Iron Boilers Commerci al cast iron boilers consist of several vertical sections o f heat exchange tubes mounted above a firebox. Water enters each section at the bottom, and is heated or converted to st eam as it passes upward through the h eat exchange tubes. The capacity of a commercial cast iron boiler i s determined by the number of heat exchange sections in the boiler. In 1977, only 12 percent of the 1.5 million cast iron boilers i n 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. The majority of cast iron boilers ar e 41 below 0.4 MMBtu/hr (0.1 MWt) heat input capacity and are fueled by natura l gas or fuel oil. All cast iron boilers are packaged units, a s they are usually no greater tha n 14 MMBtu/hr (4.1 MWt) in heat input capacity, and, hence, ar e relatively small. 3.3 OIL- AND NATURAL-GAS-FIRED ICI BOILER EQUIPMENT TYPES Oil- and natural-gas-fired ICI boilers accounted for 88 perce nt of the ICI bo iler population in 1977. These boilers are generally similar to coal-fire d 3 units, with the exception of stoker systems, whic h are not used to burn liquid or gaseous fuels. However, some boilers are designed with oil/gas burners3-42

and a solid fuel stoker system, to allow use of the most economicall y 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 , multi ple-burner arrangements provided a means of controlling heat input in lie u of burner turndown capability. With advances in burner control an d turndown capability—most new burners can maintain stable flames as low as 10 percent of capacity—the use of multiple burners in smaller units ha s declined. Most newer units smaller than 200 MMBtu/hr (59 MWt) heat input capacity have only one burner. O il- and natural-gas-fired boiler types can be categorized as watertube, firetube, cast iron, or tubeless, and as eithe r packaged or field-erected. Watertube boilers can either be shop-assembled (packa ged) or field-erected. Firetube and cast iron boilers are nearly al l packaged because of their smaller sizes. In the smaller sizes and most commercial applications of ICI boilers, the pac kaged gas/oil fired Scotch firetube boiler predominates. Almost all 42 of these a pplications are for heating where loads do not fluctuate quickly

. Boil ers designed for low temperature (250 F or less) and low pressure (1 5 psig and less) stea m are the most widely used in residential, apartment, and commercial construction. 42 3.3.1 Oil- and Natural-gas-fired Watertube Boilers Oil- and natural-gas-fired watertube boilers come in a wide range o f capacities, from small commercial units o f 0.4 MMBtu/hr (0.1 MWt) heat input capacity, to very large industr ial boilers of 1,500 MMBtu/hr (440 MWt) or heat input capaci ty or higher. However, in the ICI sector, most are smaller tha n 25 0 MMBtu/hr (73 MWt). Larger oil- and natural-gas-fired watertube boiler s that are fi eld-erected are similar to PC-fired units in firing configuration, but3-43

with s maller furnace volumes (higher heat release rate per unit volume o r water wall surface area). Units with heat input capacities greater tha n 150 MMBtu/hr (44 MWt) are typically wall-fired or tangential-fir ed with multiple burners. Field-erected watertube boilers strictly designed for oil firing ar e more compact than coal-fired boilers with the same heat input, bec ause of the
mo re rapid combustion characteristics of fuel oil. Field-erected watertub e boilers f ired by natural gas are even more compact due to the rapi d combustion rate of the gaseous fuel, the low flame luminosity, and the ashfree content of natural gas. 43 In general, field-erected watertube boilers are much more commo n than packaged units in the boiler size categ ory above 100 MMBtu/hr (29 MWt) heat i nput capacity, whereas below this capacity, watertube boilers ar e usually packaged. There are, howev er, 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-gasfired ICI boilers is the horizontal bent tube, classified by the number of drums, headers, and tube configuration, with the latter bei ng the most distinguishing3-44 Figure 3-19. Watertube design configurations. 44

factor. Figure 3- 19 shows the three most common tube configurations used in packaged units. The "A" ty pe has two small lower drums, or headers, and a large upper drum for steam and water separation. Most steam production occurs in the center fu rnace wall tubes entering the drum. The "D" type, the most flexib le design and the most widespread, has two drums and a large - volume combustion chamber that is easy to outfit with a superheater o r economizer. The "O" config uration's symmetry exposes the least amount of tube surface to radiant heat. Figure 3-2 0 113-45Figure 3-20. D-type packaged boiler and watertubes.453-46

depic ts a typical D-type packaged boiler, and its watertubes, equipped with a single oil/natural gas burner at the end. 3.3.2 Oil- and Natural-gas-fired Firetube Boilers The most common types of firetube boilers used for oil and natur al gas firing are the Scotch, the HRT, th e vertical, and the firebox boilers. Available units range from 0.4 MMBt u/hr (0.1 MWt) to 50 MMBtu/hr (15 MWt) heat input capacity, although most in use in the ICI sector have capacities belo w 25 MMBtu/hr (7.3 MWt). These firetube boilers almost always employ a 35 single burner rather than multiple bu rners, and nearly all are packaged units. Of these four types of firetube designs, the Scotch firetube boile r is the most c ommon. In a four-pass Scotch boiler, such as that shown i n Figure 3-16, the burner is located at the end of the unit. Combustion gases pass first through the furnace tube, which i s an extension of the combustion chamber, to the end of the boiler, and then enter firetubes at the bo ttom of the unit

. The flue gases then flow back toward the front of the unit, and the n enter two more systems of firetubes lo cated above the combustion chamber, before finally exhausting through the stack. A two-pass Scotch boiler i s 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 des igns and capacities to the coal-fired units discussed earlier. They are essentially the same as the coal-fire d firetube units, but differ in that burners rather than stoker systems are used. 3.3.3 Oil- and Natural-gas-fired Cast Iron Boilers Although approximately 70 percent of ICI boilers are oil- or natural- gasfire d cast iron units, these systems comprise only about 10 percent of th e total United States ICI boiler capacity. Two-thirds of these boilers are rated3-47

below 0.4 MMBtu/ hr (0.1 MWt) heat input capacity. Most of them are used in the3-48

commercial and institutional sectors to provide low-pressure steam or ho t water. Cast iron boilers using oil or natural gas a re 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 threepass vertical tubeless boiler, shown in Figure 3-2 13-49 Figure 3-21. Vertical tubeless boiler. 463-50

. This boiler consists of a vertical, rigid steel pressure vessel enclosed inside anoth er pressure vessel, with water in between. This assembly is itsel f enclosed within an insulated outer s hell. 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 furnac e. Flue gases pass up through the inner vessel, and then make second and third passes over con vection fins
mo unted on the outside of the outer pressure vessel. Heat is transferred to the wate r located between the two pressure vessels. This type of boiler i s pac kaged and is available in heat input capacities ranging from 0.25 t o 4.2 MMBtu/hr (0.07 to 1.23 MWt). The largest units are roughly 6 feet i n diameter and 9 feet in height. 46 Boilers used in thermally enhanced oil recovery (TE OR) operations are
re ferred to as TEOR steam generators. These units are typically package d 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 an d hori zontally 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. Figure 3-2 2 4 73-51Figure 3-22. TEOR steam generator.493-52

shows a typical oil field steam generator. 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 fluidize d bed, or as an auxiliary fuel when additional heat is required. 31,48 3.3.5 Oil Burning Equipment Natura l-gas- and oil-fired boilers often use similar combustio n equipm ent, and in fact, many units are capable of firing either fuel. The use of fuel oil, however, generally requires special equipment to "atomize" th e fuel before3-533-54

combusti on. In some installations, this atomization equipment may play a key role in the combustion perf ormance 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 lar ger amount of oil particle surface for contact with the combustion air , assuring prompt ignition and rapid combustion. The most common types 50 of atomizers are steam and mechanical atomizers. Steam atomizers, which may also be used with moisture-fre e comp ressed air, are the most widely used. These types of atomizer s 50 produce a steam-fuel emulsion which, when released into a furnace, atomizes the oil through rap id expansion of the steam. Steam atomizers are available in s izes up to 300 MMBtu/hr (88 MWt) input. The steam and oil pressur e required are dependent on the design of the steam atomizer, althoug h maximum oil pressures can be as high as 300 psi and maximum stea m pressures a s much as 150 psi. Oil pressures are much lower than fo r 50 mechanical ato mizers. 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 us ed as the
me ans for atomization. The oil pressure required at the atomizer fo r maxim um capacity typically ranges from 600 to 1,000 psi, depending o n capacity, load range, and fuel grade. Mechanical atomizers are available in 50 sizes up to 180 MMBtu/hr (53 MWt) input. The vi scosity of the oil is the most important property affectin g atomization in mechanical atomizers. As viscosity inc reases, larger viscous 51 forces must be overcome by the energy suppl ied to the nozzle. This detracts from the energy available for droplet breakup, resulting in coarser atomi zation and possible adverse affects on combustion efficiency. Thus, for prope r 51 atomization and combustion, oil of grades higher than No. 2 must usually be3-55

he ated to reduce its viscosity to 135 to 150 Saybolt Universal Seconds. 50 Figure 3-2 33-56Figure 3-23. Effect of temperature on fuel oil viscosity.513-57

shows the effect of temperature on viscosity for No . 2 (distillate) through No. 6 (residual) fuel oils.3-58

3.4 NONFOSSIL-FUEL-FIRED ICI BOILER EQUIPMENT TYPES Nonfossil-fuel-fired boilers are commonly used in industries tha t gen erate 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 wa ste, including MSW, industrial solid waste (ISW), and RDF. Th e following subsections briefly describe the types of f uels burned and the most common types of nonfossil-fuel-fired boilers currently in use. 3.4.1 Wood-fired Boilers Wood wast es are typically burned in boilers used in the paper an d allied products industry, the forest products industry, and the furnitur e industry. Types of wood wastes are s awdust, 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. Stok ers are the most common type of wood-firing systems in th e 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 tha n 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. As in the coal-fired sprea der stoker described earlier, 53 fu el enters the furnace through a chute and is spread pneumatically o r mechan ically across the furnace, where part of the wood burns i n 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 i s injected under the grate to drive off the volatiles and burn the char, while the3-59

remainder is fed above the g rate to complete combustion. Most stoker units are equipped with a flyash reinjection system. Other m ethods used to fire wood are overfeed and underfeed stoke r firin g, gasification, pyrolysis, fuel cell firing, suspension firing, and FBC , though to a lesser degree tha n spreader stoker firing. Another type of boiler combustion sy stem, the Dutch oven, is also in use, but has been essentially di scontinued from new construction due to its low efficiency, hig h construction costs, and inability to follow loa d swings. The overfeed stoker 53 is the second most common method of wood firing after the spreader stoker. Gas ification is a method of firing wood waste or other biomas s whereby t he fuel is partially combusted to generate a combustible fuel ga s rich in carbon monoxide and hydrogen, which is then burned. Hea t to sustain the pro cess is derived from exothermic chemical reactions, while th e combustible comp onents of the resulting gas are generated by endothermic reactions. In essence, a gasification system behaves as a type of biomass

5 4 bur ner. One manufacturer offers flyash gasification systems ranging fro m 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-temperatur e environme nt with little oxygen. Thermal cracking of the fuel occurs , producing combustible gases that are then burned. One system uses a moving v ariable-speed grate to introduce the waste fuel to the pyrolyti c gasification chamber, where the fuel is thermally cracked between 1,500 F and 1,850 F. The resulting combustible gases are then f ired in an afterburner and th e 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, w ood is piled on a stationary grate in a refractorylined cel l. Forced draft air is supplied to drive off the volatiles in the woo d and bur n the carbon. The volatiles are mixed with secondary and tertiar y3-60

com bustion air and pass into a second chamber where combustion i s completed. Fuel cell boilers range in heat input capacity from 3 MMBtu/hr

53 (0.9 MWt) to 60 MMBtu/hr (17.6 MWt). In suspension firing boilers, small-sized wood fuel, such a s sanderdust, is typically blown into the furnace and combusted in m id-air. The small-sized fuels required by these boilers are typically cl eaner and drier than other wood wastes, which can result in increased combustion efficiency and less ash e ntering 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 reinje ction system to minimize the amount of unburned carbon in the flyash. Wood is also fired in FBC boilers, which are detail ed in Section 3.2.1.3. In 1991, 10 nonutility FBC boilers below 250 MMBtu/hr (73 MWt) heat inpu t 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 timbe r comp any's cogeneration plant, to a 180-MMBtu/hr (53-MWt or 27-MWe) unit, used b y an independent power producer. In an additional 29 units belo w 250 MMBtu/hr (73 MWt) heat input capacity, wood was fired in combinatio n 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 M We, roughly equivalent to 1,500 MMBtu/hr (440 MWt) heat inpu t capacity. This unit was operated by an independent power producer, and is atypi cal in size. The next largest wood-fired FBC in the ICI sector wa s 345 MMBtu/hr (100 MWt or 51 MW e) heat input capacity. This is more typical of the ICI wood-fired FBC boiler range. 2 It is fairly co mmon practice to use an auxiliary fuel, particularly fossil fuel, i n all types of wood-fired boilers. Approximately 50 percent of wood - fired boilers have some type of fossil fuel firing capability. Fossil fuels are 533-61

fired during startup o peration, as an augmentation fuel, or alone when wood fuel is unavailable. Fossil fuels are used more freq uently in larger wood-fired boi lers than in smaller boilers below 100 MMBtu/hr (29 MWt) heat inpu t capacity. Wood-fired boilers are available in both firetube and watertub e 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 unit s generally range between 2 and 20 MMBtu/hr (0.6 to 6 MWt) heat inpu t capacity. The firing methods discussed above are used with both firetub e and watertube boilers. Packaged watertube boilers are the most difficult of all boilers to fire with wood waste. This is because th e 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 i s essential that the dry wood particle s 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 afte r processing sugar cane. It is used in sugar industry boilers in Hawaii, Florida, Louisia na, Texas, and Puerto Rico. This fuel is available on a seasona l 52 basis. Other agricultural wastes include nut hull s, rice hulls, corn cobs, olive pits, and sunflower seed hulls. The earliest type of bagasse-bur ning furnace was the Dutch oven with flat grates. In this type of furnace, the bagasse was burned in a pile on a3-62 Figure 3-24. Ward fuel cell furnace. 56

refrac tory hearth and combustion air admitted to the pile around it s circumference through tuyeres. However, this type of furnace resulted i n high maintenance costs and was essentially discontinued from ne w installation. A more commonly used pile burning boiler is the fuel cell , described e arlier. In one type of fuel cell boiler system, the Ward furnace , sh own in Figure 3-24, bagasse is gravity-fed through chutes into individua l cells, where it is burne d 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 combustion is complet ed in a secondary furnace. This type of design is3-63

considered one of the mos t reliable, flexible, and simple methods of burning bagasse. 56 Recen t trends in bagasse firing have been toward using spreade r sto ker systems. Bagasse spreader stoker boilers are similar in design t o wood-f ired spreader stokers, except that flyash reinjection is not normall y used. Spreader stokers require bagasse with a high p ercentage of fines and

57 a moisture content not over 50 percent. 56 Like most other waste-fueled boilers, bagasse-fired units typically use auxiliar y fuels such as natural gas or fuel oil during startup or whe n additional capacity is required. Most operators minimize the amount o f auxiliary fuel used , and typically less than 15 percent of the total annual fuel heat input to bagasse boilers comes from fossil fuels. Bagasse-fired boilers 57 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 municipali ties and industries. Boilers that fire general solid waste are found i n manufacturing plants, district heating plants, municipal heating plants, and electric u tilities. As mentioned earlier, general solid waste can be furthe r classified as MSW, ISW, or as RDF. MSW is made up of food wastes, rubbish, dem olition and construction wastes , treatment plant wastes, and other special wastes. Combustibl e rubbis h 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 wastewate r treatmen t facilities. Special wastes are roadside litter, dead animals, an d abandon ed 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 man y3-64

trees are deciduous. Typically, ov er one third of MSW in the United States is pa per, with the next most abundant constituents being food wastes an d garden trimmings. 58 MSW-fired boiler s 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 MMBt u/hr (11 MWt) heat input ca pacity, while mass-burning units are as large as 290 MMBtu/h r ( 8 5 MWt). Modular units have been in operation in the United States since

59 the l ate 1960s, while most existing mass-burning facilities have bee n 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 i n Figure 3-2 53-65Figure 3-25. Large MSW-fired boiler.603-66

. The facility includes a waterwall furnace and an overfeed stoker system

. MSW is loaded by overhead crane into the feed chute, which deposits th e 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 th e 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 furna ce type are controll ed air (pyrolysis) and refractory furnaces. Controlled-air MSW units
re ceived much developmental attention during the 1970s. Many of thes e units, however, were subsequently shut down due to operation al or economic problems. 623-67

Small modular units differ from the mass-burning boilers in that they
are typically hopper- and ram-fed instead of crane-fed. These units ar e packaged and designed to allow installation of additional units as the need for fur ther capacity increases. A typical modular boiler, shown in Figure 3-2 63-68 Figure 3-26. Modular MSW-fired boiler. 633-69

, utilizes a furnace with a primary and secondar y combustion chamber. MSW is fired at approximately 820 C (1,500 F) in the primary chamber and a t 1,040 C (1,900 F) in the secondary chamber. An auxiliary burner is used in the secondary chamber whenever additio nal heat is required. This particular type of unit is an example of a controlle d-air or "starved-air" boiler, as the air in the primary comb ustion chamber is below stoichiometric levels to reduce ash and fuel entrainment. 63 3.4.4 Industrial Solid Waste (ISW)-fired Boilers ISW is composed of tho se wastes, typically paper, cardboard, plastic, rubber, textiles, wood, agricultural waste, and trash, arising from industria l proc esses. 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 a verage 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 unit s describ ed above. These units encompass the same capacity range of th e modular M SW-fired boilers, but can also be as large as 60 MMBtu/h r (17 .6 MWt) heat input capacity. Large-mass burning boilers are no t commonly used at industrial facilities; thus, ISW is usually on ly fired in massburning 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 fu els, which are burned in the same form as they are received at the boile r site, RDF is generated by the sorting and processing of the general soli d waste. Usually, noncombustibles, such as glass and metal, are removed and recycl ed, and the remainder of the refuse processed into pelletized o r powdered form. RDF can be3-70

b u rned alone or in combination with coal or oil. The most common use of 54 RDF is a s a substitute for part of the coal used in coal-fired stoker and P C boilers. However, a few stoker units burn RDF alone; these units are similar to standard coal-fired boilers. 64 Both RDF-firing and mass burn system s were commonly used in early U.S. r esource recovery plants. Currently, the majority of U.S. MSW firin g units utilize mass burn and not RDF firing, due in part to the successfu l expe rience 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 , especial ly when refuse throughput is low to moderate, on the order of a few thousand tons per day. 62,653-71

3.5 REFERENCES FOR CHAPTER 3 1. CIBO NO RACT Guidance Document. Council of Industrial Boile r x Owners. Burke, VA. January 1993. p. 5.
2. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion Boilers Market Asses sment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. Appendix A.
3. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. 10.
4. Non fossil Fuel Fired Industrial Boilers—Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n Agency
. Emission Standards and Engineering Division. Researc h Triangle Park, NC. March 1982.
5. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r Combu stion Modification NO Controls, Volume 1: Environmenta l x Assessment. Publication No. EPA-600/7-81-126a. Prepared for th e U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981. p. 2-1.
6. Surpren ant, N. F., et al. (GCA Corp.). Emissions Assessment o f Conventional Stationary Combustion Systems, Volume IV : Commercia l/Institutional Combustion Sources. Publication No. EPA600 /7-81-003b. Prepared for the U.S. Environmental Protectio n Agency. Research Triangle Park, NC. January 1981.
7. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. pp. A-1 to A-5.
8. Surpren ant, N. F., et al. (GCA Corp.). Emissions Assessment o f Conventional Stationary Combustion Systems, Volume V: Industria l Combustion Sources. Publication No. EPA-600/781-003c. Pre pared for the U.S. Environmental Protection Agency. Research Triangle Park , NC. April 1981.3-72

9. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. A-4.
10. Steam—39th Edition. Bab cock & Wilcox. New York, NY. 1978. p. 25- 6.
11. Boilers and Auxi liary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY. June 1988. p. B-52.
12. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. A-12.
13. Ibid. p. A-24.
14. Ibid. pp. A-2 to A-3.
15. Ibid. p. A-15.
16. Pace maker II. Bulletin No. F2350 R1. Industrial Boiler Co., Inc

. Thomasville, GA. December 1987.
17. The Fab ric Filter Manual. The McIlvaine Company. Northbrook, IL

. May 1985. Chapter IX. p. 10.01.
18. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. 13.
19. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r Combu stion Modification NO Controls, Volume 1: Environmenta l x Assessment. Publication No. EPA-600/7-81-126a. Prepared for th e U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981. p. 2-4.3-73

20. The Fab ric Filter Manual. The McIlvaine Company. Northbrook, IL

. May 1985. Chapter IX. p. 10.03.
21. Steam—39th Edition. Babcock & Wilcox. New York, NY. 1 978. pp. 11- 1 to 11-6.
22. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. A-6.
23. Ibid. p. A-8.
24. Boilers and Auxi liary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY. June 1988. pp. B-28 to B-32.
25. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. 25.
26. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r Combu stion Modification NO Controls, Volume 1: Environmenta l x Assessment. Publication No. EPA-600/7-81-126a. Prepared for th e U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981. pp. 2-11 to 2-13.
27. Boilers and Auxi liary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY. June 1988. p. B-54.
28. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion Boilers Market Asses sment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. pp. 6 to 8.
29. Scot t, R. L. Fluidized Bed Combustion: Pressurized Systems. U.S

. Department of Energy. Morgantown, WV.
30. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion Boilers Market Asses sment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. p. 13.3-74

31. Ma kansi, J., and R. Schwieger. Fluidized-bed Boilers. Powe r Magazine. McGraw-Hill, Inc. New York, NY. May 1987.
32. Gaglia, B. N. and A. Hall (Gilbert/Commonweal th, Inc.). Comparison of Bubbling and Circulating Fluidized Bed Industrial Steam Generation. Proce edings of the 1987 International Conference on Fluidized Be d Combustion. The A merican Society of Mechanical Engineers/Electric Power Researc h Institute/Tennessee Valley Authority. New York, NY. 1987.
33. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion Boilers Market Asses sment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. pp. 3 to 6.
34. Ibid. p. 21.
35. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

. Enviro nmental 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.
39. CB Packaged Boilers. Bulletin No. CBF-178 R11. Cleaver Brooks

. Milwaukee, WI. December 1986.
40. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r Combu stion Modification NO Controls, Volume 1: Environmenta l x Assessment. Publication No. EPA-600/7-81-126a. Prepared for th e U.S. Environmental Protection Agency. Research Triangle Park, NC. July 1981. p. 2-3.
41. De vitt, T., et al. (PEDCo Environmental, Inc.). Population an d Char acteristics of Industrial/Commercial Boilers in the U.S

. Publi cation No. EPA-600/7-79-178a. Prepared for the U.S

.3-75 Enviro nmental Protection Agency. Research Triangle Park, NC

. August 1979. p. 15.
42. Govan, F. A. and D. R. Ba hnfleth. 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 Boile r Combu stion Modification NO Controls, Volume 1: Environmenta l x Assessment. Publication No. EPA-600/7-81-126a. Prepared for th e 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. Cle aver Brooks. Milwaukee, WI. July 1987.
46. Th ree-pass Vertical Tubeless Boilers. Bulletin No. F2050 990-3.0

. Industrial Boiler Co., Inc. Thomasville, GA.
47. NO Emission Control for Boilers and Process Heaters—Trainin g

x Manual. Southern California Edison. Rosemead, CA. April 1991.
48. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion Boilers Market Asses sment. Prepared for the Gas Research Institute. Chicago, IL. August 1991. p. 26.
49. Nutche r, P. B. High Technology Low NO Burner Systems for Fire d x Heaters and Steam Generators. Process Combustion Corporation

. Pitts burgh, PA. Presented at the Pacific Coast Oil Show an d Conference. Los Angeles, CA. November 1982.
50. Steam—39th Edition. Babcock & Wilcox. New York, NY. 1 978. pp. 7-3 to 7-4.
51. Sotter, J. G. Fuel Oil Atomization for Boilers . Report No. 10-173. KVB, Inc. Tustin, CA. June 1974. pp. 5 to 8.
52. Non fossil Fuel Fired Industrial Boilers—Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n3-76

Agency
. Emission Standards and Engineering Division. Researc h 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 Pu blishing Co. New York, NY. 1985. p. 671.
55. Wood Waste Burnin g Systems. Bulletin No. WW-74. Coen Company. Burlingame, CA.
56. Steam—39th Edition. Babcock & Wilcox. New York, NY. 1 978. pp. 27- 3 to 27-4.
57. Non fossil Fuel Fired Industrial Boilers—Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n Agency
. Emission Standards and Engineering Division. Researc h 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 Fab ric Filter Manual. The McIlvaine Company. Northbrook, IL

. May 1985. pp. 325.03 to 325.05.
63. Non fossil Fuel Fired Industrial Boilers—Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n Agency
. Emission Standards and Engineering Division. Researc h Triangle Park, NC. March 1982. pp. 3-43 to 3-44.
64. Ibid. pp. 3-48 to 3-49.
65. Boilers and Auxi liary Equipment. Power Magazine. McGraw-Hill, Inc. New York, NY. June 1988. p. B-57.4-1 4. BASELINE EMISSION PROFILES

NO is a high-temperature byproduct of the combustion of fuels with x air. NO fo rmation in flames has two principal sources. Thermal NO is that

x x fraction of total NO that results from the high-temperature reaction between x the nit rogen and oxygen in the combustion air. The rate of thermal NO x formation varies exponentially with peak combustion temperature an d oxygen
con centration. Fuel NO is that fraction of total NO that results from th e x x conversion of organic-bound nitrogen in the fuel to NO via a high - x tempera ture reaction with oxygen in the air. The amount of nitrogen in th e fuel, peak combustion temperature, oxygen conce ntration, and mixing rate of fuel and air influence the amount of fuel NO formed. When low-nitroge n x fuels such as natural gas, higher grade fuel oils, and some nonfossil fuels are used, nearly all the NO generate d is thermal NO . When coal, low-grade fuel x x oils, and some organic wa stes are burned, fuel NO generally becomes more x of a factor because of the higher levels of fuel-bound nitrogen available. Aside from the physical and chemical characteristics of the fuels, man y boiler d esign and operating parameters influence the formation of NO x because they impact peak flame temperatures, fuel-air mixing rates, an d oxygen concentrations. Principal among these ar e the heat release rates and absorption profiles in the furnace, fuel feed mechanisms, combustion ai r distribu tion, and boiler operating loads. For example, steam pressure an d temperatu re requirements may mandate a certain heat release rate and heat absorp tion profile in the furnace which changes with the load of the boiler

.4-2

Solid f uels can be introduced into the furnace in several ways, eac h influencin g 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 i n Cha pter 3, ICI boilers include a broad range of furnace types operating in a vari ety of applications and burning a variety of fuels ranging from clea n burning natural gas to several t ypes of nonfossil and waste fuels. Thus, NO x emissions from ICI boilers tend to be highly variable. This ch apter discusses the primary factors influencing baseline NO x levels and summarizes the baseline (uncontrolled) NO emission level s x measured from a variety of ICI boiler and fuel combinations. Parameter s affecting NO emissions from ICI boilers are discussed in Section 4.1, while x compiled baseline emissions for ICI boilers are presented in Section 4.2 o n th e basis of boiler fuel type. Section 4.3 presents a summary of th e information presented in this chapter. 4.1 FACTORS AFFECTING NO EMISSIONS FROM ICI BOILERS x The ranges in baseline NO emissions for ICI bo ilers are due to several x factors including boiler design, fuel type, and b oiler operation. These factors usually influence baseline NO in combination with each other, and often to x diffe rent degrees depending on the particular ICI boiler unit. Thus, wid e variations among ICI boiler NO emissions are common, even among similar x boiler designs or fuel types. These factors are discussed in the followin g subsections. 4.1.1 Boiler Design Type The firing type of the boiler influences the overall NO emission level. x For exampl e, for a given fuel, tangential field-erected units typically have a baseline level less than wall-fired boil ers because of their inherent staging of fuel and air in a concentric fireball. This trend has been documented fo r4-3

utilit y-sized boilers. Conversely, cyclone units generally have higher NO 1 x level s than wall-fired units due to their inherent turbulent, high-temperature combusti on process, which is conducive to NO formation. Even within a x 2 particular type of boiler, other design details may influe nce baseline NO . For x example, in field erected PC wall-fired units, NO may vary depending upon x whet her a wet bottom or dry bottom furnace is used. Wet bottom furnace s have h igher furnace temperatures to maintain the slag in a molten state , leading to greater thermal NO formation. x 3 In comparison, coal stokers have lower NO emissions than PC-fired x units since the stokers inherently operate in a "staged combustion "
con figuration. Staged combustion, which is discussed in greater detail i n 4 Chapter 5, relies on the reduction of the peak flame zone oxygen level t o reduce formation of fuel NO , and is achieved by d elaying — or staging — the x addition of combustion air. Higher NO levels reported for spreader stokers x are due to a portion of the fuel burning in suspension with more effectiv e fuel/air mixing and higher combustion temperatures. In comparison, o verfeed and underfeed stokers combust more of the coal on a grate wher e combustion is naturally s taged, with a fuel rich zone close to the grate and a more fully mixed zone above the grate. A dditionally, underfeed and overfeed units tend to have larger fireboxes and, consequently, lower heat releas e rates, resulting in lower peak temperatures and lower levels of thermal NO x formation. 5 The o ther major design type of solid-fuel-fired units, FBC boilers , report lower baseline NO emissions than similarly-sized wall-, tangential-, or x cyclone-fired units, due mostly to the lower combustion temperatures used in FBCs. In FBC boilers, NO formation generally peaks in the lower part of x the furna ce and is reduced in the freeboard zone, where heterogeneou s red ucing reactions between char and NO occur. Also, newer FBC designs x 64-4

are incorporating combustion air staging in their original configuration t o achieve low emissions for permitting in strict environmental areas. In staged configura tions, the lower part of the fluidized bed and furnace are kept at or below stoichiometry. T he staged addition of combustion air results in lower NO levels compared to unstaged designs. x Regard ing smaller packaged natural-gas- or oil-fired boilers, NO x emiss ions generally depend more on fuel, heat release rate and capacit y charact eristics. In general, ICI boilers with higher heat release rates an d higher capacities tend to have higher levels of NO . This is disc ussed in more x de tail in Section 4.1.3. For a given heat release rate and fuel type, however, there is no strong correlation between NO emissions and whether a x packaged boiler is a firetube or a watertube design. 4.1.2 Fuel Characteristic s

ICI boiler baseline NO emissions are highly influenced by th e x properties of the fuels burned . NO and other emissions will vary depending x on whether natural gas, oil, coal, or nonfossil fuels are used. Additionally , among each of these fuel types, emissions will depend on highly variabl e factors such as fuel grade and fuel source. In particular, studies have shown that fuel nitrogen cont ent — and for coal the oxygen content and the ratio of fixed carbon to volatile matter — are key factors influencing NO f ormation. x 3,7-9 Much attention has been given to the role of fuel-bound nitrogen in N O x formation. For any given fuel, only a portion of the available fuel nitrogen is converted during combustion to fuel NO . Published data indicate that fo r x coal burn ing, 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 rout inely converted. In general, higher nitrogen fuels such as coal an d 10,11 residual oil have lower conversion rates, as shown in Figure 4- 14-5Figure 4-1. Conversion of fuel nitrogen.114-6

, but higher overall NO r ates than lower nitrogen fuels such as distillate oil. x 3 The nitrogen content of bituminous coals can vary from as low as 0.8 to a s high as 3.5 percent by weight. Fuel oil is normally divided into distillate oil and residual oil. Distillate oil represent s the lighter fraction of the distillation process, i ncluding No. 2 oil and diesel oil normally used in residential an d
com mercial heating, internal combustion engines, and sometimes in large r boilers strictly regulated for SO and NO emissions. Residual oil consists of 2 x the hi gher temperature fractions and still bottoms from the distillatio n process, includi ng 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 fro m various sources, including emission test reports, to illustrate the variability of these fuel properties. Many areas will have oils with d ifferent values, these depending on many factors such as the type of crude, refinery processe s (e.g ., hydrodesulfurization), and blending. Clearly, the lighter oils contai n much lower levels of fuel nitrogen and4-7 Distillate oil (No. 2) Residual oil (No. 6) Nitroge n Sulfur Nitroge n Sulfur Average <0.01 0.72 0.36 1.3 Low <0.001 0.20 0.10 0.10 High 0.01 0.70 0.80 3.5 Standard deviation 0.005 0.20 0.17 0.90

Reference 13-15 9, 14, 16-20 All concentrations are percent by weight. a TABLE 4-1. TYPICAL RANGES IN NITROGEN AND SULFUR CONTENTS OF

FUEL OILS a

sulfur , thereby contributing significantly lower NO and SO emissions

. x 2 Dist illate oil normally has less than 0.01-percent nitrogen content, wherea s 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. Sul fur content is typically specified when residual oil is purchased

. This is done to meet environmental regulations and to safeguard boile r equipmen t from acid corrosion. Although lower sulfur content generall y means lower nitrogen, there is no appar ent direct relationship between these two f uel oil parameters, as illustrated in Figure 4- 24-8

Figure 4-2. Fuel oil nitrogen versus sulfur for residual oil. (Data from several EPA- and EPRI-sponsored tests; see Table 4-1.) . Because the deliberate denitrification of fuel oil is not a refinery practice , si gnificant swings in the nitrogen content of residual oil occur even whe n 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 o f the gas. Nitrogen in natural gas, however, does not contribute as much to the productio n of fuel NO as with liquid or solid fuels, the reason being that the nitrogen in natural x gas is in its molecular form (N ), as in the combustion air. In contrast , 2 nitrogen in liquid or solid fuels is released in its atomic form (N) and reacts at relatively low temperatures with oxygen to form fuel NO

. x 124-9 Figure 4 - 34-10

Figure 4-3. Effect of fuel nitrogen content on total NO emissions. x 94-11

shows the effect of fuel nitrogen content on total NO emissions for 26 oil - x fired and 15 coal-fire d industrial boiler tests. For the oil-fired tests, in which both resid ual and distillate oils were burned, a clear correlation was see n betw een nitrogen content and NO , with higher NO levels reported for th e x x higher ni trogen content oils. The field tests of coal-fired units, however , showed no direct correlation between total NO emissions and coal fue l x nitrogen content, per se. Similar results were also reported in a stud y 9 comp aring the use of low-sulfur western coal to the use of easter n bituminous coal in ICI boilers. It is believed tha t while nitrogen content does 8 pla y a key role in NO formation, as was seen in the oil tests, other coal fuel x factors such as oxygen content also influence NO formation concurrently , x masking any obvious correlation between coal fuel nitrogen4-12

Figure 4-4. Fuel NO formation as a function of coal oxygen/nitrogen ratio x and coal nitrogen content. 21

and NO
.

x This was suggested by test results showing a possible linkage betwee n the ratio of coal oxygen to coal nitrogen and the amount of NO formed

. x Figur e 4-4 shows the results of a study of the effects of the coa l oxygen/ nitrogen ratio on fuel NO formation in tangential PC-fired boilers

. x The figure shows the relationship between fuel NO , coal nitrogen content , x and the coal oxygen/nitrogen ratio. The data indicate slightly higher NO x emissi ons for western sub-bituminous coal due to the higher coa l4-13

oxyg en/nitrogen ratio, despite the coal's lower fuel nitrogen content. On a broader scale, coal property data show that coals with high oxygen/nitrogen rat ios generally have lower nitrogen contents. Thus, the two influences
— higher NO due to higher oxygen content, and lower NO due to lower nit rogen

x x content — would tend to balanc e one another resulting in reasonably similar fuel NO emissions for a variety of coal types.

x 7,21 Another major coal factor influencing baseline NO formation is th e x fuel rat io, defined as the ratio of a coal's fixed carbon to volatile matter

. Typically, under unstaged combustion conditions, lower fuel ratios (i.e. higher volati le content of the coal) correlate to higher levels of NO , because wit h x higher volatile content coals, greater amounts of volatile nitrogen ar e rel eased in the high temperature zone of the flame where sufficient oxyge n is present to form NO

. Thus, co nsidered by itself, higher volatile coal firing x 3 will tend to result in higher baseline NO levels. It has been shown , x 22 however, that firing coal with high volatile content and lower fixed carbo n generally r esults in less solid carbon to be burned out in the post-flam e gases, meaning that the coal can be fired at lower excess air befor e combustible losses became a problem. As discussed in Section 4.1.4, lower 8
excess air requirements generally result in lower NO emissions. Thus, the x higher NO levels associated with higher volatile coals may be balanced to a

x certain degree by the lower excess air capability provided. The dif ference between average NO emission levels reported among x various fuel oil types (i.e., residual versus distillate) lies primarily in the fact that resi dual oils are produced from the residue left after lighter fraction s (gas oline, kerosene, and distillate oils) have been removed from crude oil

. Residual oils thus contain high quantities of nitrogen, sulfur, and othe r impu rities. As discussed, fuels with high nitrogen contents generall y produce h igher levels of fuel-bound NO than fuels with low nitroge n x4-14

contents. Thus, with residual oil in particular, fuel NO makes up a greate r x portion of the total NO emitted. For any parti cular class of boilers, the range x in NO emissions for residual oil is often wider than the range of emissions

x for distillate oil. The larger amount and variation of fuel nitrogen in th e resid ual oil accounts for this. Even within one type of fuel oil, larg e 23 varia tions in NO emissions can be recorded due to the other factor s x discus sed in this chapter. The variability in NO emissions between th e x boiler s listed in Appendix A burning the same type of oil is chiefly due t o variations in boiler heat release rates and operating conditions. Besid es distillate oil, many nonfossil fuel types are low-nitrogen - content fuels. T hus, NO emissions from ICI boilers fired on these fuels and x on natural gas are almost entirely thermal NO , and the major factors which x influence their NO levels are furnace heat release rate (related to capacit y x and operating load) and excess air level, both of which are discussed below. 24 Wh ile most wood burning boilers are stokers and are similar in design t o coal-fired units, the relatively low nitrogen content of wood contributes t o much lowe r fuel-bound NO formation than with coal. In general, with wood x wastes the generation of particulates and other unburned combustibles i s more of a concern than NO formation. The wood moistur e content and wood x fuel siz e are the two most important fuel quality factors influencing thos e emissions. 25 Moisture content also plays an important role in the formation o f uncombustible emissio ns in MSW firing. By its nature, MSW composition is highly dependent on the net waste contributions of residential an d 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 large r quantiti es of yard waste. These variables result in wide ranges in MS W4-15

composition and corresponding fuel properties. Stud ies have shown that the
non-co mbustible content of MSW can range from 5 to 30 percent, th e moisture content from 5 to 50 percent, and the heating value fr om about 7,000 to 15,000 kJ/kg (3,000 to 6,500 Btu/lb). Nitrogen contents, too, are ofte n 26 highly variable depending o n the source of MSW. Ultimate analyses of MSW from different parts of the United States have shown nitrogen content s ranging between 0.2 and 1.0 percent. Thus, emissions from MSW-fire d 27-31 boilers will also tend to be highly variable. 4.1.3 Boiler Heat Release Rate Boiler heat release rate per f urnace area is another influential variable affecting NO formation. As heat release rate increases, so does peak furnace x temper ature and NO formation, as illustrated in Figure 4- 5 x4-16

Figure 4-5. Effect of burner heat release rate on NO emissions for coal x and natural gas

fuels. 164-17

. Boiler heat release rate varies primarily with the boiler firing type, th e primary fuel burned, and the4-18

operating load. Additionally, boiler heat release rate per unit volume is often 3 related to boiler capacity, as illustrated in Figure 4- 64-19Figure 4-6. Furnace heat release rate versus boiler size.324-20

. For example, among coal-fired boilers, PC-fired units are typically th e largest in capacity . The data in Appendix A include PC-fired units from 111 to 64 0 MMBtu/h r (32.5 to 188 MWt) heat input capacity, whereas the coal stoker s listed in Appendix A are generally smaller, ranging in size from 3 to 44 4 MMBtu/hr (0.88 to 130 MWt), with the vast majority b eing below 200 MMBtu/hr (59 MWt) capacity. These ranges are fairly representative of the capacit y ranges discussed in Chapter 3. Compared to other coal-fired boiler designs, PC -fired units tend to have larger capacities, heat release rates, and, a s shown by the data in Appendix A, generally higher baseline NO levels. x Among stoker units, the larges t capacity stokers are spreader stokers
as reflected in the Appendix A data. The majority of spreader stoker dat a
came from units greater than 100 MMBtu/hr (29 MWt) in capacity, while th e other two stoker types were us ually 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 indi cated earlier, tend to have larger fireboxes . Consequently, overfeed and underfeed stokers generally have lower heat release rates per unit area, resulting i n lower peak temperatures and lower levels of thermal NO formation tha n x spreaders. 5 Becau se packaged natural-gas- or oil-fired watertube boilers ar e availa ble in higher capacities and heat release rates than firetubes, the high end of t he ranges of reported baseline NO tends to be greater for th e x watertube designs. However, as noted in Section 4.1.1, there is no obvious
c o rrelation per se between NO emissions and whether a boiler is a firetube x or a watertube. 4.1.4 Boiler Operational Factors In addit ion to boiler design and fuel factors, the conditions unde r wh ich a unit is operated also influence baseline NO levels. Chief amon g x4-21

these oper ational factors are the amount of excess oxygen in the flue gases and the combustion air temperature. Excess oxygen refers to the oxyge n concentration in the stack gases,4-22

and is dependent on the amount of excess air provided to the boiler fo r combustion. Comb ustion air temperature, meanwhile, is dependent on the 33 degr ee of air preheat used before the air is introduced into the furnace o r burner. Air preheat is usually used to increase furnace thermal efficiency. Num erous sources have discussed the typical relationship of excess oxygen levels and NO , wherein as excess oxygen in creases, so does NO
. x x 34-37 This relationship is shown in Figure 4- 74-23

Figur e 4-7. Effect of excess oxygen and preheat on NO emissions, natural- x gas-fired boilers. 394-24

, which presents data for natural-gas-fired watertube and firetube boil ers. The therma l efficiency advantages of operating boilers at low excess oxyge n levels have long been k nown, as long as the boiler is operated with a certain margin of excess air above the minimum level required to avoid excessiv e combustible emissions formation (CO, partic ulate). Operation on low excess oxygen or air is therefore considered a fundame ntal part of good combustion managem ent of boilers. However, many ICI boilers are typically fired wit h
excess ox ygen levels which are more than adequate to assure complet e combu stion and provide a margin of safety to the operator. Thus, thes e 38 units often are operated at unnecessarily high excess oxygen levels tha t result in unnecessarily high NO emissions and losses in efficiency. Utilit y x boilers, on the other hand, are typically fired with a smaller safety margin of excess air, but these units are more closely monitored by operating pe rsonnel 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 NO . The level x of c ombustion air preheat has a direct effect on the temperatures in th e combustion zone, which, in turn, has a direct impact on the amount of the rmal NO formed. More specifically, the greater degree that the air is preheated , x the higher the peak combustion temperature and the higher the th ermal NO
. x 40 Because the air preheat temperature pri marily affects thermal NO formation, x the use of air preheat has its greatest NO impact on fuels such as natural gas x an d distillate oils. Boilers with combustion air preheat systems ar e 40,41 usually larger than 50 MMBtu/hr in capacity, with preheat temperatures in the range of 120 to 340 C (250 to 650 F). In 414-25

particular, many stoker boilers are equipped with air preheat. 4.2 COMPILED BASELINE EMISSIONS DATA — ICI BOILERS This section presents compiled uncontrolled NO emissions data fo r x ICI boilers. Where data were available, CO and total unburned hydrocarbon (THC) emissions are also re ported. These baseline data were compiled from test res ults on more than 200 boilers described in EPA documents an d technical reports. These d ata are detailed in Appendix A. Emission tests on these boilers were performed at greater than 70-percent boiler load in most
cases. 4.2.1 Coal-fired Boilers4-26

Table 4 - 24-27TABLE 4-2. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH AP-42 EMISSIONFACTORS, COAL-FIRED BOILERSBoiler typeNO,xlb/MMBtuaCO,lb/MMBtuaTHC,lb/MMBtuaCompiled databAP-42CompileddataAP-42CompileddataAP-42PC wall-fired0.46-0.890.58-0.81c,d0.0-0.050.02-0.040.001-0.0190.004-0.007PC tangential0.53-0.680.58-0.81c,d0.0-0.140.02-0.040.004-0.0090.004-0.007Cyclone1.12e1.31c,d0.0e0.02-0.04N.A.f0.004-0.007Spreaderstoker0.35-0.770.42-0.540.0-0.530.19-0.350.0-0.0180.004-0.007Overfeedstoker0.19-0.440.29-0.410.001-1.650.35-0.420.022-0.0240.004-0.007Underfeedstoker0.31-0.480.37-0.420.0-0.940.42-0.760.0100.081-0.150Bubbling FBC0.11-0.81N.A.0.17-0.49N.A.N.A.N.A.CirculatingFBC0.14-0.60N.A.0.02-0.25N.A.N.A.N.A.To convert to ppm @ 3% O, multiply by the following: NO, 740; CO, 1,215; THC, 2,130.a2xSee Appendix A for compiled data.bCurrent AP-42 does not distinguish PC units by firing configuration, but by dry- versus wet-cbottom.Includes utility boilers.dSingle data point.eN.A. = Not available. No data available.f4-28

su mmarizes reported baseline NO , CO, and THC emission ranges for coal- x fi red boilers, and lists current AP-42 emission factors for comparison. 42-45 In dustrial PC-fired boilers were among the highest emitters of NO . Th e x emission level from a wet bottom cyclone fired ind ustrial boiler was recorded at 1.12 lb/MMBtu. The data for dry-bottom boilers compiled for this stud y show a range in NO emissions from 0.46 to 0.89 lb/MMBtu. In comparison, x AP- 42 shows NO emissions for dry-bottom boilers in the range of 0.58 t o x 0.81 l b/MMBtu. However, the AP-42 factors include several utility boilers as
no distinction is made among application for this class of boilers. For wetbottom industrial PC-fired boilers, only one data point was obtained in thi s study. Spr eader stoker units averaged 0.60 lb/MMBtu (450 ppm) NO from a x range of 0.40 to 1.08 lb/MMBtu ( 300 to 800 ppm). The other two stoker types, overfeed and underfeed, averaged 0.29 and 0.36 lb/MMBtu respectively (215 and 265 ppm). Emission data for spreader stokers compiled for this stud y show generally higher emission levels than suggested by current AP-4 2 emission factors. FBC boilers are typically low NO emitters compared to PC-fired boil ers x and most spreader stokers, as the data indicate. This is due to severa l reasons, one of which is the lower combustion temperatures, as discusse d 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 averag e NO emission level of 0.27 lb/MMBtu (200 ppm), for bubbling be d x units, and 0.32 lb/MMBtu (240 ppm),4-29

for circulating FBC boilers. NO emissions ranged from 0.11 to 0.81 lb/MMBtu x (80 to 600 ppm) , for bubbling bed FBC units, and from 0.14 to 0.60 lb/MMBtu (105 to 4 45 ppm), for circulating FBC units. No AP-42 factors are currentl y available for industrial FBC boilers. CO and THC emission data for all typ es 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 lb/MMBtu (0 to 60 ppm), while fo r spreader stokers, CO ranged between 0 and 0.53 lb/MMBtu (0 to 645 ppm)

. Howev er, the measured CO emission levels for overfeed and underfee d stok ers encompassed much wider ranges than reported in AP-42, rangin g from 0 t o 1.65 lb/MMBtu (0 to 2,000 ppm). Likewise, the THC emissions fo r overfe ed stokers also differed greatly from the AP-42 values, averagin g
r o ughly 0.023 lb/MMBtu (50 ppm). Overfeed stoker THC data were available for only tw o units, however. This and the wide range of reported emissio n values indica tes that available baseline CO and THC data from overfeed and underfeed stokers are generally inadequate. Circulating FBC boilers tend to hav e lower CO emissions than bubbling bed units, ranging from 0.02 t o 0.25 lb/MMBtu (24 to 300 ppm). The bubbling bed units' CO levels were higher at 0.17 to 0.49 lb/MMBtu (205 to 595 ppm). The higher fluidization velocities and recirculation used in the circula ting FBC units generally increase air/fuel mixing and combustion efficiency. PC-fired boilers tend to emit less CO than stoker units. The data i n Table 4- 2 show CO emissions from PC wall-fired and tangential boiler s rangi ng from 0 to 0.14 lb/MMBtu (0 to 170 ppm). CO emissions from th e stoker un its listed were higher, ranging from 0 to 1.65 lb/MMBtu (0 t o 2,000 ppm ). The use of pulverized coal allows better air/fuel mixing , increasing the combustion efficiency in the furnace which is evidenced b y4-30

lowe r CO. In stoker units, however, coal combustion takes place on grates, and the combustion air supplied to the fuel bed generally does not allow as high combustion efficiencies. Spreader stokers, which burn some fuel i n
sus pension and the remainder on grates, generally emit less CO tha n overfeed and underfeed stokers, although the CO data in Appendix A fo r under feed stokers is suspect, as mentioned above. The combustio n temperatures in stokers are also lower than in PC-fired units, contributing to higher levels of CO. 4.2.2 Oil-fired Boilers4-31

Table 4 - 34-32TABLE 4-3. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH AP-42EMISSION FACTORS, OIL-FIRED BOILERSOil type and boilercapacityNO,xlb/MMBtuaCO,lb/MMBtuaTHC,lb/MMBtuaCompiled databAP-42CompileddataAP42CompileddataAP-42Residual Oil:Firetube units0.21-0.390.370.0-0.0230.0330.002-0.0140.011Watertube units:10 to 100MMBtu/hr0.20-0.790.370.0-0.1140.0030.0-0.0310.009>100 MMBtu/hr0.31-0.600.28-0.450.0-0.0660.0330.002-0.0160.007Distillate Oil:Firetube units0.11-0.250.140.0-0.0140.0360.012c0.004Watertube units:10 to 100MMBtu/hr0.08-0.160.140.0-1.1770.0360.0-0.0030.002>100 MMBtu/hr0.18-0.23N.A.d0.0-0.837N.A.0.001-0.009N.A.4-33

gi ves baseline emission data for oil-fired ICI boilers, categorized by type of oil, boiler capacity, and heat transfer config uration. Residual-oil-fired boilers averaged approximately 0.36 lb/MMBtu (280 ppm) of NO , regardless o f x capacity, with NO ranging from 0.20 to 0.79 lb/MMBtu (160 to 625 ppm)

. x Aver age baseline NO levels for distillate-oil-fired units were lower a t x approximately 0.15 lb/MMBtu (120 ppm). NO from the distillate-oil-fired units x ranged from 0.08 to 0.25 lb/MMBtu (63 to 200 ppm) . These data are in general agreement with AP-42 emission factors. Reported CO emission levels for residual oi l boilers were low, with the majo rity of units reporting CO levels below 0.030 lb/MMBtu (40 ppm). Th e baseline CO data for distillate-oil-fired watertube boile rs, however, show wide variabi lity, with units in the large capacity (greater than 100 MMBtu/hr ) category emitting anywhere from 0 to 0.84 lb/MMBtu (0 to 1,090 ppm), while in the 10 t o 100 MMBtu/hr capacity range, units emitted between 0 an d 1.1 8 lb/MMBtu (0 and 1,530 ppm). CO emissions from distillate-oil-fire d firetube uni ts were low, under 0.015 lb/MMBtu (20 ppm). High levels of C O emissions from industrial boilers indicate, in part, poor burner tuning an d main tenance levels for many of these units, which are often operated wit h little supervision and required maintenance. Reported unburned THC emissions for residual-oil-fired boilers ranged from 0 to 0.031 lb/MMBtu (0 to 70 ppm), while for distillate-oil-fired units the range was between 0 and 0.022 lb/MMBtu (0 to 50 ppm). These are in general agreement with current AP-42 THC emission factors. 4.2.3 Natural-gas-fired Boilers Th e data base compiled for this study indicated that baseline NO x emission levels for natural-gas-fired firetube boilers ranged from 0.07 t o 0.13 lb/MMBtu (58 to 109 ppm). F or watertube units, NO ranged from 0.06 to x 0.31 lb/MMBtu (504-34 Boiler type and capacity NO , x lb/MMBtu a CO, lb/MMBtu a THC, lb/MMBtu a Compiled data b AP-42 Compiled data AP-42 Compiled data AP-42 Firetube units 0.07-0.13 0.095 0.0-0.784 0.019 0.004-0.117 0.0076 Watertube units: 100 MMBtu/hr 0.06-0.31 0.13 0.0-1.449 0.033 0.0-0.023 0.0055 >100 MMBtu/hr 0.11-0.45 0.26-0.52 0.0-0.233 0.038 0.0-0.051 0.0016 To convert to ppm @ 3% O , multiply by the following: NO , 835; CO, 1,370; THC, 2,400. a 2 x See Appendix A for compiled data. b TABLE 4-4. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH

AP-42 EMISSION FACTORS, NATURAL-GAS-FIRED BOILERS

to 260 ppm) for units less than or equal to 100 MMBtu/hr capacity, and from 0.11 to 0.45 lb/MMBtu (95 to 375 ppm) for units greater than 100 MMBtu/h r capacity. As shown in Table 4-4, the low end of the emission range is wel l below the current AP-42 emission factors. This is due in part to emission s data ob tained at reduced boiler load and emissions from smaller capacit y boilers. As illustrated in Appendix A, NO emissions from natural-gas-fired x boilers tend to increase with increasing boiler capacity. Baseline CO emission levels show wide variability, ranging from 0 to 1.45 lb/MMBtu (0 to 1,990 ppm). The data indicate that for natural-gas-fire d boiler s less than or equal to 100 MMBtu/hr in capacity, CO emissions ar e often higher than in the current AP-42 emission factors. THC emission s ranged from 0 to 0.117 lb/MMBtu (0 to 280 ppm). 4.2.4 Nonfossil-fuel-fired Boilers4-35 Fuel and equipment type NO , x lb/MMBtu CO,

lb/MMBtu THC,

lb/MMBtu Wood Waste: Units with 50,000 to 400,000 lb/hr steam output (~70 to 580 MMBtu/hr heat input) 0.27 (0.17-0.30) a 0.38-4.52 0.16
Units with less than 50,000 lb/hr steam output (<70 MMBtu/hr heat input) 0.022 (0.010-0.050) a 0.38-4.52 0.16
Bagasse 0.15 N.A. b N.A. General Solid Waste: Mass burn municipal solid waste 0.4 0.24 0.012 Modular municipal solid waste 0.49 0.38 N.A. Refuse derived fuel 0.36 0.26 N.A. Compiled data range, Appendix A. a N.A. = Not available. No data available. b TABLE 4-5. AP-42 UNCONTROLLED EMISSION FACTORS FORNONFOSSILFUEL-FIRED BOILERS

Table 4-5 shows AP-42 uncontrolled emission fact ors for wood waste-, bagasse-, and general solid waste-fired boilers. AP-42 NO emission factors x for wood-fired units are 0.27 lb/MMBtu (190 ppm), for larger boilers, an d 0.065 lb/MMBtu (50 ppm), for smaller units. The limited emissions data fo r wood-fi red boilers in Appendix A show an NO range of 0.010 t o x 0.30 lb/MMBtu (7 to 220 ppm corrected to 3 percent O ). Many o f these boilers 2 operate inefficiently with very high excess air levels, at times greater tha n 5 times the amount required for complete co mbustion. Bagasse-fired boilers generally emit low levels of NO , roughly 0.15 lb/MMBtu (105 ppm). x Boilers that burn general solid waste typically show higher NO levels x than biomass-fueled units. The current AP-42 NO emis sion factors for MSW- x fired units and RDF-fueled units are 0.4 to 0.49 lb/MMBtu (280 to 3 50 ppm) and4-36 Combustor type Capacity (tons/day) Uncontrolled NO x

emissions, ppm @ 7%

O 2 Range Average Mass burn/refractory 56-375 59-240 155 Mass burn/rotary waterwall 100-165 146-165 156

Mass burn/waterwall 100-1,000 68-370 243 Refuse derived fuel (RDF) 300-1,000 195-345 270
Modular, excess air 50-120 105-280 140 Modular, starved air 36-90 86-280 215 All types 36-1,000 59-370 210 Source of data: Reference 20. a TABLE 4-6. AVERAGE NO EMISSIONS FROM MUNICIPAL WASTE x COMBUSTORS a

0.36 lb/MMBtu (250 ppm), respectively. Uncontrolled CO emissions fro m thes e boilers are relatively high, 0.24 to 0.38 lb/MMBtu (280 to 440 ppm)

. Tab le 4-6 presents a detailed breakdown of NO emissions for municipa l x waste combustors (MWCs) by major equipment types. The data come from 52 combus tion sources, each tested over a period of 1 to 3 hours. Th e averag e NO level of 210 ppm corrected to 7 percent O translates int o x 2 approximately 0.4 lb/MMBtu. Non fossil-fuel-fired FBC boilers burning wood waste, manure, an d other agricultural wa ste byproducts had NO emissions ranging from 0.10 to x 0.42 lb/MMBtu (70 to 300 ppm). This is lower than the coal-fired FBC e mission levels because of the lower nitrogen contents of the nonfossil fuels.4-37

AP-42 CO emission factors for all wood-fired boilers span a wid e range, from 0.38 t o 4.52 lb/MMBtu (440 to 5,200 ppm), due to several factors, includ ing wood composition and boiler design type. Unburned TH C emissi ons are significantly higher than levels measured in fossil-fuel-fire d boilers. Reported AP-42 levels are 0.16 lb/MMBtu (327 ppm), on average. 4.2.5 Other ICI Boilers There are limited baseline NO emissions data for small commercia l x and instit utional 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 MMBt u/hr (2.9 MWt), with the exception of recent rules adopted i n 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 be en regulated due to their size; hence, little testing has been done to characterize their emissions. Uncontrolled NO emissions from natural-gas-fired TEOR stea m x generators range between 0.09 and 0.13 lb/MMBtu (75 a nd 110 ppm), while for crud e-oil-fired steam generators, baseline NO emissions generally rang e x from 0.30 t o 0.52 lb/MMBtu (240 to 400 ppm), depending on the nitroge n conte nt of the crude oil. Because there is less variability in the design s 46,47 and configurations of TEOR steam generators, their NO emissions, for a x given fuel, are usually less variable than other boilers. 4.3 SUMMARY4-38

Table 4 - 74-39 Fuel Boiler type Uncontrolle d NO x range, lb/MMBtu Average,

lb/MMBtu Pulverized coal Wall-fired

Tangential Cyclone 0.46-0.89 0.53-0.68 1.12 a 0.69

0.61 1.12 Coal Spreader stoker

Overfeed stoker Underfeed stoker 0.35-0.77 0.19-0.44 0.31-0.48 0.53

0.29 0.39 Bubbling FBC Circulating FBC 0.11-0.81 0.14-0.60 0.32

0.31 Residual oil Firetube

Watertube: 10 to 100 MMBtu/hr >100 MMBtu/hr 0.21-0.39
0.20-0.79 0.31-0.60 0.31

0.36 0.38

Distillate oil Firetube

Watertube: 10 to 100 MMBtu/hr >100 MMBtu/hr 0.11-0.25
0.08-0.16 0.18-0.23 0.17

0.13 0.21

Crude oil TEOR steam

generator 0.30-0.52 0.46
Natural gas Firetube

Watertube: 100 MMBtu/hr >100 MMBtu/hr TEOR steam generator 0.07-0.13
0.06-0.31 0.11-0.45 0.09-0.13 0.10

0.14 0.26 0.12

Wood <70 MMBtu/hr

70 MMBtu/hr 0.010-0.050 0.17-0.30 0.022

0.24 Bagasse 0.15 b 0.15 MSW Mass burn

Modular 0.40 b 0.49 b 0.40

0.49 TABLE 4-7. SUMMARY OF BASELINE NO EMISSIONS x4-40

summarizes baseline NO emissions for the major ICI boiler equipmen t x categories discussed in Chapter 3. Coal-fired cyclone boilers generally emit the highe st levels of NO , followed by PC wall-fired units, PC tangentia l x boilers, coal-fired stokers, MSW-burning units, and crude-oil-fired TEO R steam generators. The lowest NO emissions are from boilers fi red on natural x gas, distil late oil, and wood fuels. NO emissions from coal-fired FBC an d x stoker boilers are generally lower than from PC-fired boiler typ es. In general, few data are available for ICI boilers less than 10 MMBtu/hr (2.9 MWt) i n thermal capacity, which includes many fossil- and nonfossil-fuel-fi red firetube units, cast iron units, and tubeless types. With the exception of distillate-oil-fired units, the data show that for a given fuel, NO emissions from firetube boilers are l ower than from watertube x boilers. This is l ikely due to the fact that most watertube boilers have larger capacitie s than firetube units. As discussed above, as boiler capacit y increases, NO emissions also increase in most cases. x Actua l emissions from individual boilers vary widely by boiler hea t release rate, fuel quality and type, boiler design type, and operating factors such as excess4-41

air le vel or load. Fuel type is a major factor influencing baseline NO levels. x Listed in descending order of NO emissions, the fuels are pulverized coal , x stoker coal, MSW, crude oil, residual oil, distillate oil, natural gas, wood, and ba gasse. It is important to recognize that large variations in baselin e (uncontrolled) NO levels are possible due to several boiler design an d x opera tional factors, including variations in the chemical makeup of the fuel. The mos t important fuel property that influences NO is the fuel nitroge n x content, which determines to a large degree the amount of fuel NO that may x be formed during combustion.4-42

4.4 REFERENCES FOR CHAPTER 4
1. Evaluation and Costing of NO Controls for Existing Utility Boilers in x th e NESCAUM Region. Publication No. EPA-453/R-92-010. U.S

. Enviro nmental 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 Reburnin g Technol ogy for Reducing NO in Cyclone Boilers. Presented at th e x 19 91 Joint Symposium on Stationary Combustion NO Control

. x Washington, D.C. March 1991.
3. Evaluation and Costing of NO Controls for Existing Utility Boilers in x the NES CAUM Region. Publication No. EPA 453/R-92-010. U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. December 1992. p. 3-1.
4. Systems Evaluation of the Use of Lo w-Sulfur Western Coal in Existing Small and Intermediate-Sized Boilers. Publication No. EPA-600/7-78- 153a. U.S. Environmental Protection Agency. Re search Triangle Park, NC. July 1978. p. 30.
5. Fossi l Fuel-Fired Industrial Boilers — Background Information

. Pub lication No. EPA-450/3-82-006a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. p. 3-39.
6. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Po wer Plants. Acurex Report No. 90-102/ESD. Prepared by Acurex Corporation for the Electr ic Power Research Institute. Palo Alto, CA. July 1990. pp. 3-4 to 3-5.
7. Fossi l Fuel-Fired Industrial Boilers — Background Information

. Pub lication No. EPA-450/3-82-006a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. p. 4-127.
8. Systems Evaluation of the Use of Lo w-Sulfur Western Coal in Existing Small and Intermediate-Sized Boilers. Publication No. EPA-600/7-78- 153a. U.S. Environmental Protection Agency. Re search Triangle Park, NC. July 1978. pp. 16 to 19.
9. Fiel d Testing: Application of Combustion Modifications to Contro l Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n4-43 No. E PA-600/2-76-086a. U.S. Environmental Protection Agency

. Research Triangle Park, NC. April 1976. pp. 164 to 169.
10. Indu strial Boiler Combustion Modification NO Controls, Volume I : x Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmen tal Protection Agency. Research Triangle Park, NC. July 1981. p. 3-4.
11. Evaluation and Costing of NO Controls for Existing Utility Boilers in x th e NESCAUM Region. Publication No. EPA-453/R-92-010. U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. December 1992. pp. 3-1 to 3-2.
12. Fiel d Testing: Application of Combustion Modifications to Contro l Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n No. E PA-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 NO x Emissions from Utility Boilers. Publication No. EPA-650/2-74 -066. U.S. Environmental Protection Ag ency. Research Triangle Park, NC. June 1974.
14. Emission Reduction on Two Ind ustrial Boilers with Major Combustion Modifications. Publication No. EPA-600/7-78-099a. U.S. E nvironmental Protection Agency. Research Triangle Park, NC. June 1978.
15. Fuel Oil Manual. Industrial Press, Inc. New York, NY. 1969. p. 23.
16. Fiel d Testing: Application of Combustion Modifications to Contro l Pollutant Emissions from Industrial Boilers — Phase I. Pu blication No. EPA-650/2-74-078a. U.S. Environmen tal 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. Environmenta l Protection Agency. Research Triangle Park, NC. April 1980.
18. The De velopment of a Low NO Burner Suitable for High Nitroge n x Li quid Fuels. Prepared by Energy and Environmental Researc h Corporation under EPA Contract 68-02-3125. February 1981.4-44

19. Urban, D. L. , S. P. Huey, and F. L. Dryer. Evaluation of the Cok e Formati on Potential of Residual Fuel Oils. Paper No. 24-543

. Pr esented at the 24th International Symposium on Combustion

. Australia. 1992.
20. Municipal Waste Combustors — Background Information fo r Proposed Standards: Control of NO Emissions. Publication No. EPA-450/3-89- x 27a. U.S. Environm ental Protection Agency. Research Triangle Park, NC. August 1989. p. 2-1.
21. Fossi l Fuel-Fired Industrial Boilers — Background Information

. Pub lication No. EPA-450/3-82-006a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. p. 4-128.
22. Technology Assessment Report for Industrial Boiler Applicati ons: NO x Combus tion Modification. Publication No. EPA-600/7-79-178f. U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. December 1979.
23. Indu strial Boiler Combustion Modification NO Controls, Volume I : x Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmen tal Protection Agency. Research Triangle Park, NC. July 1981. p. 3-33.
24. Ibid. p. 3-2.
25. Nonfossil Fuel-Fired Industrial Boilers — Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n 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 E xamination 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-Hil l Publishing Company. New York, NY. 1985. p. 583.
28. Nonfossil Fuel-Fired Industrial Boilers — Background Information

. Pu blication No. EPA-450/3-82-007. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. p. 3-39.4-45

29. Municipal Waste Combustio n Study. Publication No. EPA/530-SW-87- 021c. U.S. Environmen tal Protection Agency. Washington D.C. June 1987. p. 3-4.
30. Dennis, C. B., et al. Analysis of External Combustion of Munici pal Solid Waste. Publication No. AN L/CNSW-53. Argonne National Laboratory. Argonne, IL. December 1986. p. 12.
31. Co mposition and Properties of Municipal Solid Waste and it s 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 Contro l of Emissions of Oxides of Nitrogen from Industrial , Institutional, and Comm ercial Boilers, Steam Generators and Process Heaters. Statewide Technical Review Group. Cali fornia Air Resources Board. Sacramento, CA. April 1987. p. 36.
33. Guidelines for Industrial Boiler Performance Improvement. Publ ication No. E PA-600/8-77-003a. U.S. Environmental Protection Agency

. Research Triangle Park, NC. January 1977. pp. 6 to 7.
34. Indu strial Boiler Combustion Modification NO Controls, Volume I : x Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmen tal Protection Agency. Research Triangle Park, NC. July 1981. pp. 3-13 to 3-68.
35. Fossi l Fuel-Fired Industrial Boilers — Background Information

. Pub lication No. EPA-450/3-82-006a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. pp. 4-127 to 4-137.
36. Guidelines for Industrial Boiler Performance Improvement. Publ ication No. E PA-600/8-77-003a. U.S. Environmental Protection Agency

. Research Triangle Park, NC. January 1977. pp. 38 to 40.
37. Fiel d Testing: Application of Combustion Modifications to Contro l Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n No. E PA-600/2-76-086a. U.S. Environmental Protection Agency

. Research Triangle Park, NC. April 1976. pp. 91 to 99.
38. Ibid. p. 91.4-46

39. Indu strial Boiler Combustion Modification NO Controls, Volume I : x Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S. Environmen tal Protection Agency. Research Triangle Park, NC. July 1981. p. 3-68.
40. Fossi l Fuel-Fired Industrial Boilers — Background Information

. Pub lication No. EPA-450/3-82-006a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1982. p. 4-117.
41. Fiel d Testing: Application of Combustion Modifications to Contro l Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n No. E PA-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

. Pub lication No. AP-42. U.S. Environmental Protection Agency

. Research Triangle Park, NC. October 1986.
43. Compilation of Air Pollutant Emission Factors, Supplement B

. Pub lication No. AP-42. U.S. Environmental Protection Agency

. Research Triangle Park, NC. September 1988.
44. Compilation of Air Pollutant Emission Factors, Supplement C

. Pub lication No. AP-42. U.S. Environmental Protection Agency

. Research Triangle Park, NC. September 1990.
45. Compilation of Air Pollutant Emission Factors, Supplement D

. Pub lication No. AP-42. U.S. Environmental Protection Agency

. Research Triangle Park, NC. September 1991.
46. Hu nter, S. C. and S. S. Cherry (KVB, Inc.). NO Emissions fro m x Petroleum Industry Operations. Publication No. 4311. Prepared f or the American Petroleum Institute. Washington, D.C. October 1979.
47. Technical Support Document for a Suggested Control Measure for the Contro l of Emissions of Oxides of Nitrogen from Industrial , Institutional, and Comm ercial Boilers, Steam Generators and Process Heaters. Statewide Technical Review Group. Cali fornia Air Resources Board. Sacramento, CA. April 1987. p. 45.5-1 LOGY EVALUATION

5. NO CONTROL TECHNO

x Thi s chapter presents a survey of applicable control technologies t o reduce NO emissions from ICI boilers. A review of current knowledge on the

x ef fectiveness, applicability, and limitations of specific control techniques is pre sented 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 NO emissions data from more than 200 boilers were compiled fro m x technical reports, NO control equipment manufacturer literature, an d x5-2

compli ance and rule development records available at California's Sout h Coast Air Quality Ma nagement 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 dat a base of Appendix B because their heat input capacities are characteristic of large industrial boilers. The largest unit for which data are listed is a 1,250 M MBtu/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 o f the emissions data were obtained durin g short-term tests. Where noted, test data w ere collected from long-term tests based on 30-day continuou s monitoring. The cont rol of NO emissions from existing ICI boilers can b e x acc omplished either through combustion modification controls, flue ga s treatment controls, or a combination of these technologies. Combustio n modification NO controls such as SCA, LNB, and FGR modify the conditions x under which combustion occurs to reduce NO formation. Flue gas treatment x contr ols—principally SNCR and SCR — are applied downstream of th e combust ion chamber and are based upon chemical reduction of alread y formed NO in the flue gas. Other g as treatment controls, besides SNCR and

x SCR, that combine NO and SO reduction are being developed. However , x 2 these controls are generally expensive and are currently targeted pri marily for coal-f ired utility boilers. Several demonstrations of these technologies ar e underway at electrical power plants under the U.S. Department of Energ y (DOE) Clean Coal Technology (CCT) demonstration program and othe r programs sponsored by indus try. With the exception of reburning and SCRbased technologies, these advanced controls are not discus sed here because they are not likely to be applied to the ICI boiler population in the foreseeable future.5-3 In t his section, the main discussion of NO controls for ICI boilers i s x prec eded by Section 5.1, which presents a brief overview of NO formatio n x and basic concepts for its reduction by combustion modifications. Sections 5.2, 5.3, and 5.4 disc uss combustion modification NO controls for coal-fired x boilers, oil- and natural-gas-fired units, and nonfossil-fuel-fired boilers , respectively. Section 5.5 discusses flue gas treatment controls for I CI boilers. 5.1 PRINCIPLES OF NO FORMATION AND COMBUSTION MODIFICATION x NO CONTROL x NO i s formed primarily from the thermal fixation of atmospheri c x nitrogen in the combustion air (thermal NO ) or from the conversion o f x chemically bound nitrogen in the fuel (fuel NO ). Additionally, a third type of x NO , known as prompt NO, is often present, though to a lesser degree tha n x fuel o r thermal NO . For natural gas, distillate oil, and nonfossil fuel firing , x nearly all NO emissions r esult from thermal fixation. With coal, residual oil, x and cr ude oil firing, the proportion of fuel NO can be significant and, under x certain boiler operating conditions, may be predominant. The act ual mechanisms for NO formation in a specific situation ar e x dependent on the quantity of fuel bound nitrogen , if any, and the temperature and stoichiometry of the flame zone. Although the NO formatio n x mechanisms are different, both thermal and fuel NO are promoted by rapid x mixing of fuel and combustion air. This rate of mixing may itself depend on fue l characteristics such as the atomization quality of liquid fuels or th e particle fineness of solid fuels. Additionally, thermal NO is gre atly increased 1 x by increased residence time at high temperature, as mentioned earlier. Thus, primary combustion modification controls for both thermal and fuel NO x typically rely on the following control strategies:

Decrease primary flame zone O level: 2

— Decreased overall O level 2

— Controlled (delayed) mixing of fuel and air5-4 — Use of fuel-rich primary flame zone Decrease residence time at high temperature:

— Decreased peak flame temperature:

Decrea sed 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 time5-5

Table 5 - 15-6TABLE 5-1. SUMMARY OF COMBUSTION MODIFICATION NOCONTROL APPROACHESxNOcontrol approachxControl conceptEffect on thermal NOxEffect on fuel NOxPrimary control techniquesOperationaladjustmentsHardwaremodificationMajor redesignDecrease primaryflame zone Olevel2Decrease overall O2levelReduces Orich, high NO2xpockets in the flameReduces exposure offuel N intermediariesto oxygenLEA firing and OTFGRLow excess air burnersDelayed mixing of fueland airFlame cooling and dilutionduring delayed mixingreduces peak temperatureVolatile fuel N reducesto Nin absence of2oxygenBurneradjustments andtimingLNBOptimum burner/firebox designPrimary fuel-richflame zoneFlame cooling in low O,2low temperature primaryzone reduces peaktemperatureVolatile fuel N reducesto Nin absence of2oxygenBOOS; biasedburner firingOFA portsBurner/firebox designfor SCADecrease peak flametemperatureDecrease adiabaticflame temperatureDirect suppression ofthermal NOmechanismxMinorRAPFGR, LNB, waterinjectionDecrease combustionintensityIncreased flame cooling;yields lower peaktemperatureMinor direct effect;indirect effect onmixingLoad reductionEnlarged firebox,increased burnerspacingEnlarged firebox,increased burnerspacingIncrease flamecooling; reduceresidence timeIncreased flame zonecooling; yields lower peaktemperatureMinorBurner tiltWI or SIRedesign heat transfersurface, fireboxaerodynamicsCreate secondary NOxreducing zoneUse of low O2secondary combustionzonePrimary zone NOreducesxto Nin absence of O22Primary zone NOxreduces to Nin2absence of O2OFA portsInstall reburningburners, OFA ports;replace tube wallpanels, pipingductworkFuel switchingBurn higher qualityfuel with low or nonitrogen contentMinor or slight increasebecause of highertemperature flameLarge NOreductionxdue to reduced fuelnitrogen conversionMinor if dual-fuelcapability existsOnly for installation ofburner and fueldelivery system5-7

sh ows the relationship between these control strategies and currentl y
av ailable combustion modification NO control techniques, which ar e x ca tegorized as either operational adjustments, hardware modifications, o r techniques requiring major boiler redesign. The use of a secondary NO x reducti on combustion zone is also included in the table. This strategy i s based on a secondary low oxygen reducin g zone where NO is reduced to N

. x 2 This is accomplished with secondary injection of fuel downstream of th e primary combustion zone. This control technique is referred to as fue l stagin g, or reburning, and is discussed in greater detail in the followin g
su bsections. Additionally, fuel switching is also considered a viabl e combusti on control because of the reduction or elimination of fuel NO with x the burning or cofiring of cleaner fuels. Table 5- 25-8TABLE 5-2. EXPERIENCE WITH NOCONTROL TECHNIQUES ON ICI BOILERSxNOcontrolxtechniqueCoal-firedOil-/natural-gas-firedNonfossil-fuel-firedMSW-firedField-erectedPC-firedStokerFBCFielderectedwatertubePackagedwatertubePackagedfiretubeStokerFBCMass burnBT/OTXXWI/SIXXSCAXXaXXXbXaXXaLNBXXXXFGRXXXXNGRXbXbSNCRXbXXXXbXXXSCRXbXbXbBT/OT = Burner tuning/oxygen trimWI/SI = Water injection/steam injectionSCA = Staged combustion air, includes burners out of service (BOOS), biased firing, or overfire air (OFA)LNB = Low-NOburnersxFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid wasteSCA is designed primarily for control of smoke and combustible fuel rather than for NOcontrol. Optimization of existing SCA (OFA) portsaxcan lead to some NOreduction.xLimited experience.b5-9

identifies combinations of NO controls and maj or boiler fuel type categories x for which retrofit experience is available and documented. Typica lly, the simplest boiler operational adjustments rely on th e reduction of e xcess oxygen used in combustion, often referred to as BT/OT. Figure 5 - 15-10NOt baseline operating conditions,Figure 5-1. Effect of excess Oonemissions for firetube boilers a2x5-11

shows the results of several tests to determi ne the effect of excess air levels on NO emissions from nat ural-gas and oil-fired firetube boilers. These test

x 2 results show that NO emissions can be reduced 10 to 15 percent when th e x stack excess oxygen concentration is lowered from 5 to 3 percent, measured in th e flue gas on a dry basis. The actual amount of NO reduced b y x dec reasing excess air varies significantly based on fuel and burne r conditions. These reductions are due mainly to lower oxygen concentration in the flame, where NO formation is highest. x Al though LEA operation can produce measurable reductions in NO , x in this study, LEA will not be considered a separate control technology bu t a p art of other retrofit technologies, since it accompanies the application of low NO combustion hardwar e such as low NO burners. Additionally, boiler

x x op eration with LEA is considered an integral part of good combustion ai r
ma nagement that minimizes dry gas heat loss and maximizes boile r efficiency. Therefore, most boilers should b e operated on LEA regardless of

3 whether NO reduction is an issue. However,

x5-125-135-14 Figure 5-2. Changes in CO and NO emissions with x reduced excess oxygen for a residual oil-fired watertube industrial boiler. 5
excessive reduction in excess air can be accompanied by significan t increas es in CO. As illustrated in Figure 5-2, when excess air is reduce d below a certain level, CO emissions increase exponentially. This rapi d increase in CO is indicative of reduced mixing of fuel and air that results in a lo ss in combustion efficiency. Each boiler type has its own characteristic "knee" in the CO versus excess oxygen depending on sever al factors such as fuel type and burner maintenance. In general, along with LE A, the application of c ombustion modifications that reduce NO often result in reduce d x combustion efficiency (manifested by increased CO). Ano ther operational adjustment listed in Table 5-1, load reduction , when i mplemented, decreases the combustion intensity, which, in turn ,5-15

decreases the peak flame temperature and the amount of thermal NO formed. x However , test results have shown that with industrial boilers, there is onl y slight NO reduction available from this techni que as the NO reduction effect

x x of lowering the loa d is often tempered by the increase in excess air required at reduced load. Higher excess air levels are often required with old er single- 4 burner units because high burner velocity promotes internal gas recirculation and stable combustion. Multiple-burner boilers generally provide a greate r lo ad turndown capability. Operating at reduced load is often infeasible fo r many ICI boi lers because steam load is dictated by process steam demands and cannot be controlled independently. Reduced load on on e boiler must be compens ated for by increased load on another boiler, unless energ y
co nservation measures permit a net reduction in fuel consumption

. Therefore, reduced load operation is not considered as a viable retrofit NO x control technology and will not be discussed further in this report. Although the formations of fuel and thermal NO are generall y x predominant , a third type of NO , known as prompt NO, has also bee n x reported. Prompt NO is so termed because of i ts early formation in the flame
zone where the fuel and air first react, at temperatures too low to produc e thermal NO . C and CH rad icals present in hydrocarbon flames are believed

x 2 to be the primary sources of prompt NO because t hey react with atmospheric nitrogen to form precursors such as HCN and NH , which are rapidly oxidized 3 to NO. The formation of prompt NO is greater in fuel-rich flames, an d decreases with the increase in local O concentrations. L ike fuel and thermal 2 6 NO formation, prompt NO formation has been shown to be a function o f x flame t emperature and stoichiometry. Prompt NO, however, generall y
accou nts for smaller levels of NO than are due to thermal or fuel NO . Fo r x x example, in utility boiler systems, prompt NO is assumed to be less tha n 50 ppm, while the thermal NO contribution can be as high as 125 to 2 00 ppm. x 65-16

In ICI boilers, prompt NO is believed to account for the first 15 to 20 ppm of NO form ed during combustion. The control of prompt NO is not typicall y x 7 targeted because of prompt NO's minor combustion to total NO . However, x as NO li mits for ICI boilers grow stricter, especially in areas such as th e

x South Coa st Air Basin of Southern California, the control of prompt NO i s gaining more importance as evidenced by the development of ne w techniques, such as fuel induced recirculation, as discussed in Section 5.5. The following sections discuss retrofit NO controls that ar e x commer cially available and the documented experience in NO reductio n x performance for each major ICI boiler and fuel category mentioned earlier. 5.2 COMBUSTION MODIFICATION NO CONTROLS FOR COAL-FIRED ICI x BOILERS Coal rank plays an important role i n the NO reduction performance of x combustion control technologies. Ty pically, controlled limits for low volatile bitumin ous coal differ from those attainable when burning high volatil e subbituminous coal or l ignites. However, the data available on coal-fired ICI boiler s are insufficient to warrant a breakdown of achievable control level s based on coal type. Nearly all data compiled in this study were for boiler s 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 emission s data for ICI coal-fired units operating with NO controls. This secti on includes x data from 18 field operating PC-fired units, 11 stoker units, and 10 fiel d operating FBC boilers. Large PC-fire d industrial boilers are similar in design to utility boilers. Thus , control techniques applicable to many utility boilers 8 can often be applied to large indus trial boilers as well. Data from three pilotscale PC-fired facil ities are also included in Appendix B, because their firing capacities are in the ICI boiler range and test results are consid ered indicative of the I CI boiler population. Additionally, combustion modification tests for5-17

bubbl ing bed FBC (BFBC) units include results obtained at pilot-scal e faci lities. Pilot-scale research on retrofit combustion modification NO x control for FBC far exceeds published data on full-scale FBC installations

. This is because commercial FBC boilers are relatively new, the majorit y having been installed after 1985, and many new units come already equipped with the se controls. Little research on full-scale NO control retrofi t x technologies has been undertaken. Pilot-scale res earch provides an in-depth view into the mechanisms of NO formation and control in FBC. These data x are used in this study to support conclusions with respect to NO reduction x efficiencies and controlled limits. S e ctions 5.2.1 through 5.2.3 summarize the combustion modification techniques applicable to the three major coal-fired industr ial boiler types: PC, stokers, and FBC units. 5.2.1 Comb ustion Modification NO Controls for Pulverized Coal (PC)-fired x ICI Boilers5-18

Table 5 - 35-19TABLE 5-3. COMBUSTION MODIFICATION NOCONTROLS FOR FULL-SCALE PC-FIRED INDUSTRIALxBOILERSControl techniqueDescription of techniqueType ofindustrial boilertested% NOxreductionControlled NOlevelsxppm @ 3% O,2lb/MMBtuCommentsSCAFuel-rich firing burners withsecondary air injectionWall-firedWall-firedWall-firedTangential15273925691 (0.93)250 (0.34)651 (0.88)211-280 (0.29-0.38)OFA.BOOS, reduced load.OFA, reduced load.LNBWall-fired boiler — LNB withdistributed air for controlledmixingTangential-fired boiler — uses airon wall concept for controlledmixingWall-firedWall-firedWall-firedWall-firedTangential4965674918280 (0.38)220 (0.30)190-225 (0.26-0.34)370 (0.50)269 (0.36)Wall-fired boilers used staged airburners.Tangential-fired boiler used lowNOconcentric firing systemx(LNCFS).Reburn with SCA(OFA)Injection of coal, natural gas, oroil downstream of the burner areaWall-firedw/coal reburnWall-firedw/coal reburnTangential-firedw/oil reburnN.A.aN.A.30170-250 (0.23-0.34)215-385 (0.29-0.52)167 (0.23)SCA (OFA) used with reburn inall tests.LNB+SCACombination of LNB and SCAcontrol techniquesWall-firedWall-firedWall-firedWall-firedWall-firedWall-firedWall-firedTangential4266N.A.6062654455180-360 (0.24-0.49)220-264 (0.30-0.36)220-370 (0.30-0.50)275 (0.37)275 (0.37)275 (0.37)330 (0.45)148 (0.20)Data for wall-fired units do notshow benefit of adding SCA toLNB.N.A. = Not available. No baseline (uncontrolled) NOdata available.axNote: References, and greater detail including baseline emissions, for these data are included in Appendix B.5-20

summarizes test results of combustion modification techniques applicable to ICI P C-fired boilers. The table provides the ranges of percent NO x reduction and the controlled NO levels achieved in these tests. Mor e detailed x data are contained in Appendix B. The following are brief discussions of each applicable control, the attained NO reduction efficiency attained and potential x operational limits and impacts of retrofit on existing ICI boilers. 5.2.1.1 SCA One approach to reducing NO , discussed in Section 5.1, is to dec rease x the primary flame zone oxygen level. The intent of SCA c ontrols is to achieve a primary fuel-rich flame zone, where both fuel and thermal NO format ions are suppressed, followed by an air-rich secondary zone where fuel combustion is comple ted. This is done by injecting air into the combustion zone i n stages, rather than injecting all of it with the fuel through the burner. As a
re sult, the primary flame zone becomes fuel-rich. SCA for PC-fired boiler s 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 primar y combustion airflow to the burners. OFA is applicable to both wall-fired and tangential-fired un its. OFA is not applicable to cyclone boilers and other slagging furnaces because combustion staging si gnificantly alte rs the heat release profile which changes the slagging rates an d propertie s of the slag. Additional duct work, furnace wall penetration o r 9 replacement, and extra fan capacity may be req uired when retrofitting boilers with OFA. To retrofit an existing PC-fired boilerAll ppm values in this study are referenced to 3 percent O

. a 2 5-21 wi th OFA involves installing OFA ports in the wall of the furnace an d extending the burner windbox. Data for two PC-fired boilers operating with and without OFA wer e obtain ed during this study. Using OFA, a 25 percent reduction in NO wa s x achie ved at the first unit, a tangential-fired unit at the Kerr-McGee Chemical Corporatio n facility in Trona, California. This unit was retrofitted with a separated OFA system in conjunction with an LNB system. Separated OFA refers t o the use of a separate OFA windbox mounted above but not a n integral part of the main windbo x, as opposed to "close coupled" OFA which is injecte d within the main windbox just above the top elevation of fuel

. Controlled NO emissions from this unit range d from 211 to 280 ppm (0.29 to x a 0.38 lb/M MBtu); this unit was also LNB-equipped. The second unit, a 325 MMBtu/hr wall-fired boiler, achieved 15 percent NO reduction using OFA. x Controlled NO em issions from this unit were 690 ppm (0.93 lb/MMBtu). The x NO reduction efficiencies of these two units are in agreement with OF A x performa nce estimates for PC-fired utility boilers, which range between 1 5 and 30 percent NO reduction. x 9,10 Two principal design requ irements for the installation of OFA ports in
an existing PC-fired boiler must be met in order for the technology t o effec tively reduce NO without adversely affecting operation and equipment x integrity. First, there must be sufficient height between the top row o f bu rners and the furnace exit, not only to physically accommodate the OF A ports but also to provide adequate residence time for the primary stage NO to reduce to N , and adequate residence time for the second stage gases to 2 achieve carbon burnout before exitin g the furnace. In order to maximize NO x redu ction, previous studies have shown that the optimum location for OF A injection is 0.8 seconds (residenc e time of primary gas before OFA injection)5-22

above the top burner row. Additionally, these studies have shown that t o 11 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 complet e combustion and maximize NO reduction. Some important x parameters affecting the mixing of OFA and first stage gases are OF A injection velocity, OFA port size , number, shape, and location; and degree of staging. Thus, OFA port design is critical in determining the effectiveness

11 of OFA in reducing NO . Additionally, OFA port design must, take int o x account the effects of port installation on the structural integrity of the boiler walls. Structural loads may be transferred from the firing walls to the sid e wall s of the furnace, and OFA port shapes may be designed to minimiz e structural modifications. Given the magnitude of retrofitting PC-fired boilers with OFA and the moderate NO reduction efficiencies of 15 to 30 percent , x 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 com bustion is BOOS, in which ideally all of the fuel flow is diverted from a selected numb er of burners to the remainin g firing burners, keeping firing capacity constant. For maximu m effecti veness, it is often the case that the top row of burners be set on ai r only, mimicking the opera tion of OFA discussed above (Figure 5-3). For PCfired boilers, this means shutting down the pulverizer (mill), as fuel flo w cannot be shut off at the individual burners as can be done with oil- and gasfired units. This sometimes presents a problem when pulverizers serv e bur ners located on two separate levels. With PC-firing, BOOS is commonly considered more of an operating practice for pulverizer maintenance than for5-23 Figure 5-3. Effect of BOOS on emissions.5-24

NO control, as pulverizers are routinely taken out of service because o f x maintenanc e requirements. The ability of boilers to operate units with on e less pul verizer is generally very limited. For this reason, BOOS is not a popular control option for PC-fired units. Data fo r two wall-fired units operating with one pulverizer out o f service sh ow NO reduction efficiencies of 27 and 39 percent. For on e x 230 MMB tu/hr boiler, NO was reduced from 340 ppm to 250 ppm (0.46 t o x 0.34 l b/MMBtu), while for a 260 MMBtu/hr unit, NO was reduced fro m x 1,065 ppm to 651 ppm (1.44 to 0.88 lb/MMBtu). However, in order to achieve 12 the 39 percent r eduction 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 a nd coal air mixing were affected. Operating at reduced load whe n 12 using BOOS is often required for industrial sized units due to the limite d number of burners and pulverizers. In summary, data from three wall-fired boilers operating with SC A te chniques of OFA and BOOS showed NO reduction ranges of 15 t o x 39 percent, while the single tangential-fired boiler with SCA showe d 25 p ercent reduction (see Table 5-3). Although the two units operated wit h BOOS acc ounted for the higher NO reduction efficiencies of 27 an d x 39 percent, both had to be operated at significantly reduced load. Because industrial units have fewer burners and typically have more limited pulverizerbu rner arrangements, BOOS is not considered a widely applicable contro l technique. 5.2.1.2 LNBs for PC-fired Boilers LNBs, principally designed for utility boiler applications, have als o been retrofitted to several large industrial boilers over the past decade. All major manufacturers of utility type boilers offer LNB for PC firing. Some of5-25

th e larger manufacturers are ABB-Combustion Engineering, Babcock & Wilcox, Foster Wheeler, and Riley Stok er. In order to achieve low NO levels, x LNBs basically incorporate int o their design combustion techniques such as LEA, SCA, or recycling of combustion products. One of the most commo n types of LNB is the staged air burner.5-26

Air stagin g in this type of LNB is accomplished by dividing th e combust ion air into two or more streams within the burner, delaying th e mixing of fuel and air. A portion of the air is used to create a fue l-rich primary combustion zone where the fuel is only partially combusted. Secondar y combustion of this unburned fuel occurs do wnstream of the primary burnout
zo ne, where the remainder of burner air is injected. Peak combustio n temper atures are also lower with the staged air burner because flames ar e elongated and some heat from the primary combustion stage is transferred to th e boiler tubes prior to the completion of combustion. As discussed i n Section 5.1, NO formation is reduced due to the lowering of the peak flame x temper ature, the delayed air/fuel mixing, and the low oxygen primary zone , where volatile fuel bound nitrogen compounds reduc e to form N . Thus, both 2 thermal and fuel NO are reduced. x One example of a staged air LNB is Foster Wheeler's Controlle d Flow /Split Flame (CF/SF) LNB, which has been retrofitted to at least tw o5-27 Figure 5-4. Foster Wheeler CF/SF LNB. 9

ind ustrial units. The CF/SF burner, shown in Figure 5-4, is an internall y stage d dual register burner. The outer register, where secondary air i s injected , controls the overall flame shape while the inner register control s ign ition at the burner throat and the air/fuel mixture in the primar y subs toichiometric region of the flame. The newer version of the CF/S F 13 bur ner also incorporates a split flame nozzle that forms four distinct coa l streams. The result is that volatiles are driven off an d are burned under more reducing conditions than wo uld occur without the split flame nozzle. CF/SF 9 burners have been retrofit ted to a 110,000 lb (steam)/hr (about 140 MMBtu/hr heat input) single wall -fired boiler at a Dupont chemical plant in Martinsville, Vi rginia. This unit, fired on bituminous coal, utilizes four CF/SF burners

. Nearly 50 percent NO reduction was achieve d, with average post-retrofit NO x x emis sions of 280 ppm (0.38 lb/MMBtu). Post-retrofit CO emissions wer e 25 ppm. CF/SF burners were also retrofitted to a 125,000 lb/hr (abou t5-28 Figure 5-5. Performance of CF/SF LNB. 10 150 MMBtu/hr heat input) four-burner, wall-fired steam boiler, wher e 65 percent NO reduction from baseline was achieved. Post-retrofit NO x x emissions at this site averaged 220 ppm (0.30 lb/MMBtu). Figure 5-5 shows 10 the NO reduction performance of these two units —labeled as numbers 4 and

x 5 in the figure—as well as several utility sized boilers. Babco ck & Wilcox's DRB-XCL burner also utilizes dual registers t o 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 rin g near the walls of the nozzle and a fuel-lean core. Reducing species are formed b y partial oxidation of coal volatiles from primary air and limite d secondary air. The re ducing zone created in the fuel-lean core prevents NO x formation5-29

during devolatilization, and the reducing species generated by oxidatio n decompose the formed NO as combustion continues. In a DRB-XCL burner x 14 retrofit program to a 22 0,000 lb/hr (about 275 MMBtu/hr heat input) wall-fired boiler at the Neil Simpson Power Station in Wyoming , average NO emissions x were reduced approximately 67 percent, when operating at the same excess air level . Controlled NO emissions for this unit ranged between 190 an d x 255 ppm (0.26 and 0.34 lb/MMBtu). 15 Riley Stoker also manufactures a LNB for PC wall-fired units, know n
as the Controlled Combustion venturi (CCVTM) burner. Figure 5- 65-30ondary air diverter.Figure 5-6. Riley low-NOCCVTM burner with secx165-31

depicts th is burner, which uses a single register, unlike the dual registe r 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
co al nozzle, creating a fuel-rich zone. As in the CF/SF LNB, the coal/ai r mixt ure 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 substoichiometri c primary combustion zone, resulting in lower fuel NO forma tion. Thermal NO x x formati on is suppressed by the reduction of peak flame temperature whic h results from the staged combustion. 16 Ril ey's Tertiary Staged Venturi (TSV) burner is similar to the CC V bur ner but uses additional tertiary air and an advanced air staging (OFA ) system for reducing NO emissions. This burner was developed for use on x Riley's TURBO furnaces as well as downfired and arch fired boilers. These boilers are characterized by downward tilted burner firing, which lengthens the re sidence time of combustion products in the furnace. As such, th e inh erently long furnace retention time combined with gradual or distributed air/fuel mixing typically results in lower NO emissions than a conventiona l x wall-f ired unit operating at similar conditions with identical fuel. TURB O 16 fu rnaces are commonly used to burn low volatile coals such as anthracite , which require longer residence time for complete combustion. Figure 5- 75-32or turbo-furnace, down-fired and archFigure 5-7. Riley low-NOTSV burner with advanced air staging fx5-33

shows a schematic of a TURBO furnace and the TSV LNB. Six TSV burners, in conj unction with OFA, were used in a 400,000 lb/hr (about 470 MMBtu/h r heat input) industrial T URBO furnace at a paper manufacturing facility in the Midwest. Firing bituminous coals, contro lled NO emissions ranged between x 220 and 370 ppm (0.30 and 0.50 lb/MMBtu). 17 A different type of LNB has been developed for tangential-firing P C boilers, incorporated into the LNCFS system. The burner itself, manufactured by ABB Combustion5-345-35

Eng ineering, is referred to as the Concentric Firing System (CFS). The CFS creates local staging by diverting a portion of secondary air horizontally away fr om the coal stream toward the furnace waterwall tubes. This delays th e mixing of secondary air with the coal during the initial coal devolatilizatio n stage of the combustion process, the stage when significant amounts of fuel nitrogen are typically released. Early ignition and devolatilization ar e achieved by using flame attachment coal nozzle tips. This early ignition and flame atta chment feature provides greater control over volatile matter flame stoi chiometry while enhancing flame stability and turndown. The boiler at 18 Kerr-McGee Chemical, mentio ned in the above discussion on OFA, has been retrofitted with the LNCFS. Operating with t he CFS LNB only, 18 percent NO x redu ction was achieved, to 269 ppm (0.36 lb/MMBtu). When the full LNCF S
was u sed (CFS+OFA), NO reduction improved to 55 percent, with NO a t x x 148 ppm or 0.20 lb/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 a re also applicable to larger industrial PC-fired boilers. In som e cases, as with the Neil S impson 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 b y replacing two furnace wall tube panels , each containing two burner throats. 15 In general, however, because there are already existing burner ports, LN B retrofits to PC-fired units do n ot require as much rework of the furnace walls
as does installation of new OFA ports. However, significant modification s may be requ ired for the windbox in order to improve air distribution wit h changes in the fuel d ucting. Consideration must also be given to LNB flame characteristics such as s hape and length to avoid flame impingement on the furna ce walls. Because flames from staged combustion burners are ofte n5-36

lon ger than from conventional burners, this may be a particularly important issue to small-volume furnaces. NO emissions data for PC-fired units with LNB are summarized i n x Table 5 -3. For four wall-fired units, NO reductions ranged between 49 an d x 67 percent , with controlled NO emissions of 190 to 370 ppm (0.26 t o x 0.50 lb/MMBtu). One tangential-fired unit experienced 18 percent reduction efficiency, with an NO level of 269 ppm (0.36 lb/MMBtu) . Again, the minimum x long-term NO level that can be reached w ith LNB retrofit depends on several x factors, principally coal type, furnace dimension, boiler load, combustion air control, and boiler operating practice. 5.2.1.3 Reburn (Fuel Staging) with SCA, PC-fired Boilers Reb urning, also known as fuel staging, involves injecting a supplemental fuel into the main furnace above the primary combustion zone to produ ce a secondary combustion zone where a reducing atmospher e exist s. The general idea is to provide a chemical path for the primary zon e NO to con vert to N rather than NO . Hydrocarbon radicals formed durin g 2 2 seco ndary combustion provide this chemical path; hence, some of the NO x cre ated in the primary combustion zone is reduced to molecular nitrogen

. OFA is utilized in conjunction with reburning to complete combustion o f supplemental fuel. Domestic experience in the ICI sector is nonexistent. Reburning has been chiefly developed and applied to larger industrial boiler s in Japan. Mitsubishi Heavy Industries (MHI) has developed th e Mitsubishi Advanced Combustion Technology (MACT) pr ocess utilizing oil as the r eburn fuel. Use of MACT in a 700,000 lb/hr (about 825 MMBtu/hr hea t input) tangential-fired boiler at Taio Paper Company in Japan resulted in a 30- percent NO reduction to a level of 167 ppm (0.23 lb/MMBtu), durin g x bi tuminous coal firing. MACT has been used in at least eight other wall or 19 ta ngential coal-fired industrial boilers in Japan, with capacities rangin g5-37

between 170 and 200 MMBtu/hr. In the United States, except for several utility demonstration projects and pilot scale test programs, rebur ning has not been applied to any commercial facility. The results from one pilot-scale test are 20 included in Appendix B—a test conducted at the 6 MMBtu/hr B&W Smal l Boiler Simulator facility. This test analyzed the NO reduction efficiencies of reburning in a x cyclone furnace with three types of fuel—bituminous coal, residual oil, an d natural gas. With the main burners of the furnace firing bituminous coal, NO x red uction efficiencies of 54 to 65 percent were achieved. Results showe d 21 that rebur ning with natural gas produced the best NO reduction and th e x lowest av erage NO emissions, between 235 and 420 ppm (0.32 an d x 0.57 lb/MMBtu). This was due to the low nitrogen con tent of natural gas. Use of natural gas as the reburning fuel also brings the added benefit of reducing SO emi ssions. The use of coal as a reburn fuel resulted in the lowest NO 2 x 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 o f ap plying natural gas reburn technology to cyclone-fired boilers. Cyclon e boil ers are currently being used in both the utility and industrial sectors

. Bec ause cyclone boilers have a unique configuration that prevents th e application of standard low-NO burner technology—combustion occur s x within a water-cooled horizontally-tilted cylinder attached to the outs ide of the fu rnace—this study sought to assess the feasibility of retrofitting existin g cyclone furnaces with reburn controls. Reburning technology prior to th e 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
conc lusion that in general, it is unfeasible to retrofit cyclone boilers belo w 80 MWe capacity with natural gas reburn controls, which essentially excludes5-38

all but the largest industrial cyclones. The reason for this is that cyclon e 16 units below this size range generally have insuf ficient furnace height to allow sufficient residence time for reburn and OFA to work effectively. For a 41 MWe boiler, it was determined that t he furnace would have to be extended by over 50 percent, which is impractical. From this study, it appears tha t 16 gas reburn is most applicable to larger existing cyclone boilers. Thu s, reburn technology is generally not applicable for retrofit t o smal ler cyclone boilers in the ICI sector because of insufficient furnac e heights. For wall-fired and tangential-fired units, however, n atural gas or coal reburn m ay emerge as a viable NO control technique for industrial PC-fired x units as indicated by utility demonstrations. 5.2.1.4 LNB with SCA The use of LNBs with SCA (OFA) in PC-fired boilers combines th e effects of staged burner combustion and staged furnace combustion. ABBCE, B&W, and Fo ster Wheeler offer OFA with LNB systems for retrofit. OFA is an integral part of ABB -CE's LNCFS NO reduction package for tangential- x fired bo ilers, and in fact is responsible for the majority of NO reductio n x achie ved. As mentioned earlier, in the Kerr-McGee boiler in California ,

18 55 percent NO reduction w as achieved with the LNCFS, combining OFA and x the CFS LNB . Note that the NO reduction efficiencies for combined control x techniques are not additive. Emissions data for seven wall-fired u nits using LNB and SCA controls show NO reductions in the range of 42 to 66 percent (see Table 5-3). N o

x basel ine data were reported, however, for one of the seven units. Thi s reduction range reflects LNB and SCA performance for six boilers. Th e 66 percent reduction efficiency was obtained on an industrial siz e 25 0 MMBtu/hr unit at Western Illinois Power Cooperative's (WIPCO) Pear l Station. Field tests showed that under normal operation, 50 percent red uction5-39

of NO was typically achieved while under careful ly controlled conditions, the

x 66 pe rcent NO reduction level was possible. Retrofit of four distribute d x mixing bur ners with tertiary air ports required replacement of the front wall, modifications to the windbox, replacement of the burner management syst em, and provision of an alternative support structure for the hopper. Because 22 of the e xtensive boiler modification required for this particular LNB+SC A system, it is generally intended for use in new boiler designs rather than in retrofit applications. Controlled NO levels for these wall-fired units ranged between 1 80 and x 370 ppm (0.24 and 0.50 lb/MMBtu). Generally, on utility bo ilers, NO reduction x per formance for this combination of controls can reach as high as 65 o r 70 percent. Thus, for large (greater than 250 MMBtu/hr) industrial boilers,

23 this may be the maximum reduction achievable as well. Ho wever, insufficient da ta for PC-fired ICI boilers using LNB and SCA precludes reaching an y definitive conclusions. 5.2.2 Combustion Modification NO Controls for Stoker Coal-fire d ICI Boilers x The two m ost commonly used combustion modification NO controls x for sto ker coal-fired ICI boilers are SCA and FGR. A third combustio n modification, RAP, has not been utilized as often. Gas cofiring with burners ab ove the grate is under active evaluation. Table 5- 45-40TABLE 5-4. COMBUSTION MODIFICATION NOCONTROLS FOR STOKER COAL-FIRED INDUSTRIALxBOILERSControltechniqueDescription oftechniqueType ofStokerboilertested% NOxreductionControlled NOxlevels ppm @3% O,2lb/MMBtuCommentsSCAReduction ofcombustion airunder the grate andincrease of overfireair flowSpreaderSpreaderSpreaderSpreaderSpreaderSpreaderOverfeedOverfeed610263135N.A.a-1N.A.350 (0.47)353 (0.48)237 (0.32)263 (0.36)369 (0.50)230-387 (0.31-0.52)166 (0.22)172-202 (0.23-0.27)Danger of grateoverheating, clinkerformation, corrosion,high CO emissions.FGR+SCARecirculation andmixing of stack fluegas with theundergrate orovergratecombustion airSpreaderSpreaderSpreader01360300-345 (0.41-0.47)350 (0.47)140 (0.19)FGR primarily leads toNOreduction byxlowering achievableexcess O.2RAPReduce temperatureof preheatedcombustion airSpreader32219 (0.30)Limited applicability tolarger units with airpreheaters. Reducesboiler efficiency.5-41

sum marizes the data compiled for stoker coal-fired ICI boilers wit h combustion modification NO controls. Available data are li mited to 12 stoker x units. The data show wide variability in NO control efficiency, ranging from x -1 to 60 percent reduction. Controlled NO levels for spreader stokers wit h x SCA ranged from 230 to 387 ppm (0.31 to 0 .52 lb/MMBtu), while for spreaders with FGR+ SCA, NO ranged from 140 to 350 ppm (0.19 to 0.47 lb/MMBtu)

. x Data were available for only one spreader unit with RAP. This unit had a controlled NO level of 219 ppm (0.30 lb/MMBtu). x 5.2.2.1 SCA Stoker units naturally operate with a form of staged combustion due to their desig n. As the coal is fed onto the grate, volatile matter is drive n from the fuel bed and burned abo ve the bed level. The coal solids remaining are subsequently burned on a bed with lower c ombustion intensity. Because of this natural staging, NO emissions from stoker units are generally lower x than those from PC-fired units of the same size. As presented i n 24 Ap pendix A, uncontrolled NO emissions ranged from 341 to 659 ppm (0.4 6 x to 30.8 9 lb/MMBtu) during nine tests of PC wall- and tangential-fired unit s ranging in size from 100 to 200 MMBtu/hr. For eight tests of similarly sized stok er units, uncontrolled NO levels ranged from 158 to 443 ppm (0.21 t o x 0.60 lb/MMBtu).5-42

The ava ilability of existing OFA ports offers the opportunity fo r increased air staging. Additional staging can be achieved by injecting more overfi re air above the fuel bed while reducing the undergrate airflow. Using OF A, the boilers for which data were collected show a NO reduction rang e x of zero to 35 percent, averaging 17 percent reduction. In two boilers, OFA did not affect NO . Controlled NO emissions ranged from 230 to 400 ppm (0.31 x x and 0.54 lb/MMBtu) for the spreader stokers tested and 166 to 202 ppm (0.22 to 0.27 lb/MMBtu) for the overfeed stokers. No data were collected fo r underfeed stoker type boilers in this study. Many o lder stokers incorporate OFA ports as smoke control devices. Therefore, these OFA ports may not be optimally located for NO contro l x purposes. For example, in one test, injection of OFA through oil burner ports high above the grate reduced NO by 25 percent. When OFA was injecte d x through t he actual OFA ports located closer to the grate, only 10 percen t reduction was achieved. 25 Because the use of SCA in stoker boile rs requires reduced undergrate air flo w for staging, there are certain operational limitations involved. First, with the e xception of a water-cooled vibrating grate, the only grate coolin g mechanism used in stoker units is the flow of combustion a ir under the grate. During SCA operation, if undergrate air is lowered too much, the grate ca n overhea t. There is also the possibility of creating local reducing zones with low o xygen which may form harmful corrosion products. Still anothe r 25 problem that may arise from reduced undergrate air firing is the formation of cl inkers. For coals with low ash fusion temperatures, significant clinke r formation can be caused by the excessively high bed temperatures resulting from combustion with insufficient amount s of excess air. Thus, a minimum 26
amou nt of undergrate air must be used to provide adequate mixing an d5-43

cooling. As such, there is a limit to the degree of OFA used in stoker boilers and consequently achievable NO reduction. x 5.2.2.2 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 fur nace and mixing it with the fresh combustion air. One effect of FGR in stoker units is that recirculated flue gas dilutes the oxygen c oncentration of the combustion air, a llowing boiler operators to lower the overall excess air level whic h conseque ntly reduces formation of NO . FGR is primarily considered a x thermal NO control technique, reducing NO by lowering the peak furnac e

x x temperature. Because te mperatures in ICI stoker units are lower than in PCfired units, thermal NO control has not been as high a priority for stoker coal- x fired boilers.5-44 Figure 5 - 85-45 Figure 5-8. Schematic diagram of stoker with FGR. 275-46 Figure 5-9. FGR effects on excess O

. 2 27
depicts a schematic of a stoker boiler equipped with FGR. Flue gas is drawn from the entrance of the stack and mixed with the un dergrate combustion air. This type of FGR system was used in a 100,000 lb/hr (125 MMBtu/hr hea t input) spreader stoker fired on bitum inous coal. Test results from this boiler illustrate the effect of FGR on allowable e xcess oxygen and consequently, its effects on NO . In this unit, minimum excess oxygen levels and boiler loa d x were restricted by opacity. To prevent opacity from reaching unacceptable levels, pre-retrofit load was limited to 80 percent of capacity and the boile r
was operate d 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 a s pre-retrofit levels. Not only does this repr esent a significant increase in boiler efficiency, but because NO i s x dependent on the excess oxygen us ed, lower emission levels were achieved,
as shown in Figure 5-10. Thus, at a constant load of 80 percent, using FGR5-47

al lowed the excess oxygen level to be reduced from 8 percent t o approximately 3.5 percent, resulting in a reduction of NO by as much a s x 60 percent. A controlled emission level of 140 ppm (0.19 lb/MMBtu) wa s
meas ured. Another spreader stoker unit also displayed simila r

27 charac teristics when operated with FGR, experiencing 13 percent NO x reduction. Less reduction was achieved in this unit because excess air was not reduced as much. In a third spreader stoker, ho wever, no NO reduction 26 x was achieved using FGR, since initial excess oxygen levels were alread y quite low at 4 percent. FGR did not allow the boiler operators to reduce oxyge n concentration, thus resulting in no measurable change in NO emissions. x 26 FGR was also applied to an overfeed stoker, but test results showe d the use of FGR on this boiler to be unsatisfactory. Unlike spreader stokers which util ize the entire length of the grate for primary combustion, overfeed stoker units often have sho rter active grate combustion zones depending on th e location of the furnace wall arch over the grate, as shown in Figure 5-115-48

Figure 5-10. NO emission versus excess O , stoker boiler with FGR. 2 27 Figure 5-11. Overfeed stoker with short active combustion zone. 265-49

. The particular boiler tested had a very short act ive combustion zone limited to the f ront half of the grate, due to the location of its furnace arch. Th e lowering of excess oxygen in the combustion air with FGR caused the active combu stion zone to lengthen beyond the furnace arch, resulting in flam e quenching and impingement on the arch. Also, FGR caused unstabl e combustion at th e front portion of the active combustion zone. In contrast 26 with overfeed5-505-515-52

stokers, FGR's eff ect of lengthening the active combustion zone in spreader stokers is of little consequence because the length required for the coal t o burn out is much shorter than the length of the fuel bed. 27 In summa ry, the use of FGR in stoker coal-fired ICI boilers has bee n demonstrated suc cessfully in a limited number of boilers. NO reduction on x two of the spreader stokers ranged from 13 to 60 percent. For the overfeed sto ker unit, FGR caused unsatisfactory combustion conditions includin g flame quenching, flame impingement, and unstable comb ustion. The primary effect of FGR is to allow reduction of the excess oxygen level of the boiler , thereb y reducing NO emissions and increasing boiler efficiency. FGR ha s x also been shown to be beneficial in dealing with grate overheating. 5.2.2.3 RAP RA P is limited to stokers equipped with combustion air preheaters

. Usual ly only larger stokers with heat input capacities greater tha n 100 MM Btu/hr tend to have air preheaters. RAP is not commonly used i n 28 such boil ers because significant losses in boiler efficiency occur when th e flue gas bypasses the air preheaters. In bypassing the preheaters , rec overable 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 NO by 32 percent. Because of its limited applicability x 28 and negative effects on boiler efficiency, RAP is not considered a p rimary NO x control method for stoker coal-fired ICI boilers. 5.2.2.4 Natural Gas Cofiring Gas cofiring for stokers has only recently been investigated fo r improving boiler opera tion and reducing emissions. The technique involves burnin g a fraction of the total fuel, typically 5 to 15 percent, as natural ga s5-53

above the grate. The cofiring improves boiler efficiency through reduce d
excess air, lower LOI in ash, and reduced flue gas exit temperature. Th e reduced excess air lowers NO levels. Recent tests on a spre ader stoker have x shown that NO emissions can be reduced by 20 to 25 percent. More tests x 29 are planned. 5.2.3 Co mbustion Modification NO Controls for Coal-fired Fluidized-be d x Combustion (FBC) ICI Boilers In FBC boilers, the fuel is burned at low combusti on temperatures, 790 to 900 C (1,450 to 1,650 F). At these low temperatures, NO formation i s x limited to the conversion of fuel nitrogen (fuel NO ). At these low combustion x temperatures, studies have shown little correlation between temperature and NO emission, thus combustion modification NO controls for FBC boiler s x x focus on the control of fuel NO
. The principal combustion modification x 30,31 cont rols used for NO reduction in FBC boilers are staged combustion , x control of bed temperature, and FGR. Table 5- 55-54TABLE 5-5. NOCONTROL TECHNIQUES FOR FBC BOILERSx30ControltechniqueControl mechanismApplication limitsPotential limitationsSCAStaged combustionreduces oxygen forconversion of volatilenitrogen; promotesheterogeneous NOreduction with CO overchar; causes increase inCaO char concentrationin dense bedSecondary/primary airratio limited byfluidization requirementsin FBC and reheat steamtemperaturesIncrease in CO emissions,carbon loss, and reducedsulfur capture primarily inFBC under severe staging(SR<0.8); excessive steam1temperatureControl ofdense bedtemperatureLower bed temperaturereduces volatilenitrogen conversion andincreasesheterogeneousreduction between charand formed NOBed temperature is tiedto fuel reactivity (ratio ofvolatiles/fixed carbon).Higher bed temperatureor an increase inresidence time isrequired for lowreactivity coal. Optimumtemperature is between1,500 and 1,600F forhigh sulfur capture.Excessive temperaturereduction increases CO andcarbon loss (efficiencyreduction), necessitatinglonger gas residence timefor char combustion,especially with lowreactivity coal5-55

summarizes the performance and process requirements of these thre e techniques . Each of these control approaches is discussed in the following subs ections. Process variables that impact NO formation are als o x discussed. As i ndicated 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 insight s into the control mechanisms and NO reduction potential of these controls. x 5.2.3.1 SCA in Coal-fired FBC Boilers SCA is widely accepted as the most effective combustion modification control for reducing NO from FBC boilers. Nearly all new commercial FBC x units come equipped with overfire air ports along the free board section of the combustor to inject secondary and s ometimes tertiary combustion air. The 32 primary objective of using SCA in an FBC boiler is to reduce NO formation x by operating the fluidized bed of a bubbling FBC (BFBC) boiler, or the lower portion of a circulating FBC (CFBC) boiler under substoichiometri c 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 f or high to medium volatile coals than for low volatile fuels such as anthracite. High-volatile-content fuels, als o described as high-reactivity fuels (reactivity being defined as the ratio o f volatile matter to fixed carbon), contain larger amounts of fuel nitrogen in the volatile matter. When introduced to the combustor, these fuels underg o thermal decomposition and quickly releas e the organically bound nitrogen in the volatile matter, whereupon it combines to form NO in the presence o f oxyge n. By using SCA, which lowers the excess oxygen level in the dens e por tion of the fluidized bed, this conversion of volatile nitrogen to NO i s suppressed. For lower volatile fuels, the amount of fuel nitrogen in th e volatile fraction is also lower. For these f uels, conversion of char nitrogen to5-56

Figure 5-12. Effect of SCA on NO and CO emissions, Chalmers x University. 34

NO dominates the overall fuel NO , and nitrogen is released at a muc h x x slowe r rate which is a function of the char combustion rate. Thus, SCA has less of a NO reducing effect for these lower reactivity fuels. x 33 NO r eductions due to SCA in coal-fired FBC boilers have bee n x reported on the order of 40 percen t for full scale units in the ICI sector. For 34 example, Figure 5-12 shows th e effects of SCA on NO and CO emissions for x a 16 MWe BFBC boiler firing bituminous coal at5-57

Chalmers University in Sweden. Keeping the total excess air between 20 and 23 percen t, NO was reduced 40 percent from 125 to 75 ppm (0.17 t o x 0. 10 lb/MMBtu) when 20 percent of the total air supply was injected through OFA ports . When the proportion of air injected as secondary air wa s increased to 25 pe rcent, NO reduction from baseline was only slightly more x than 40 percent. Meanwhile, CO emissions more than doubled from a baseline level of 270 ppm to 565 p pm. NO reduction efficiencies of as high 34 x as 60 to 70 percent have also been repor ted in several pilot-scale tests. For 32 insta nce, at the TNO Research facility in Sweden, tests conducted on a 14 MMBtu/hr B FBC unit with SCA showed 67 percent NO reduction. Pilot- x 35 scale tests, however, generally involve much higher a mounts of staging—i.e., lower primary zone stoichiometries—than are practically achieved in full scale units, due to c oncerns over combustion efficiency, corrosion of watertubes, and refractory integrity. 32 Besides the amount of SCA used and fuel type, the locatio n of the OFA ports can also have a significant impact on NO reduction . Several tests have x shown that the greater the distance to the secondary air ports, the greater is the NO suppression. This is d ue to the increased residence time between 36-38 the primary and secondary air injection stages. However, there are practical limits on how high in the freeboard the OFA can be introduced withou t affecting combustion efficiency, corrosion, and steam temperature control

. Additionally, because of the different rates of fuel nitrogen conversion fo r low- or high-reactivity coals mentioned earlier, in order to maximize NO x reduction the optimal secondary air location must be specifically de signed for each type of fuel used, as well as for fuel with different size distributions. Reported NO emission levels for FBC units with SCA have been highly x variable dependin g on the capacity, fuel type, OFA port location, and design type (i .e., CFBC or BFBC) of the boilers. For instance, controlled NO x5-58 Control technique FBC boiler

type Controlled NO x

level, ppm @ 3% O , lb/MMBtu 2 SCA Circulating

Circulating Circulating Circulating Circulating Bubbling bed Dual bubbling bed 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) FGR+SCA Circulating

Circulating 90-116 (0.12-0.16)

100-115 (0.14- 0.16) TABLE 5-6. REPORTED CONTROLLED NO EMISSION LEVELS, FULL- x SCALE, COAL-FIRED FBC BOILERS

emissions from a 222 MMBtu/hr CFBC unit fired on bituminous coal ranged fr om 51 to 335 ppm (0.07 to 0.45 lb/MMBtu), while an identical unit fired o n brown coal emitted 103 to 155 p pm (0.14 to 0.21 lb/MMBtu) of NO

. Another x 33 CFBC unit, rated at 140 MMBtu/hr and firing bituminous coal, emitted 28 0 ppm (0.38 lb/MMBtu) NO

. Data obtained for full-scale units showed controlle d x 39 NO emissions ranging from 39 to 335 ppm for five CFBC boilers, and 75 to x 100 ppm for two BFBC units. These data are tabulated in Table 5-6. Othe r sources have reported p ractical NO limits achieved with SCA to be between x 80 and 130 ppm (0.11 and 0.18 lb/MMBtu) for CFBC and 100 to 200 ppm (0.14 to 0.27 lb/MMBtu) for BFBC boilers. 32 5.2.3.2 Bed Temperature Control5-59

Figure 5-13. NO and CO versus bed temperature, pilot-scale BFBC. x 41 The temperature within FBC boilers is determined primarily by th e combust ion requirements of the coal and the temperature required t o maximize sulfur captu re. The optimum temperature range for sulfur capture is 800 and 850 C (1,470 to 1,56 0 F). In this range, the sulfur capture can be 40 as high as 98 percent depending on the Ca/S ratio, sorbent reactivi ty and size, residence time, and ash recirculation rate. Low bed combustion temperature lowers the formation of t hermal NO
. x The effects of bed temperature on NO formation for a pilot-scale BFBC was x reported to be about 2 to 3 ppm NO reduction for every 10 C in temperature x drop. Figure 5-13 show s this effect, as well as the bed temperature's effect

41
o n CO emissions, which increase as temperature is lowered. The effects of5-60

Figure 5-14. Effect of bed temperature on NO and CO, Chalmers x University. 34

be d temperature on NO and CO are shown in Figure 5-14 for the full-scal e x 16 MW e BFBC test unit at Chalmers University, showing 54 percent NO x reduct ion when bed temperature was lowered from 880 to 780 C (1,620 t o 1,440 F). Thi s equates to 13 ppm NO reduction per 10 C temperature drop, x a greater effect than was experienced with the pilot-scale5-61

unit. The difference in temperature dependence is most likely due t o differences in furnace geometry and the type of coal used. Unlike the pilotscale results shown in Figure 5-13, CO emissions at Chalmers did no t in crease with lowered bed temperature, remaining fairly constant a t 270 ppm. For a CFBC pilot unit, the effect of bed temperature on NO

3 4 x reduction wa s 8 ppm reduction per 10 C. Similarly, tests conducted at the 42 former 110 MWe CFBC Nuclear Power Station showed roughly 10 ppm NO x reduction per 10 C temperature drop in the bed. 43 Although lowering bed temperature has shown me asurable reductions in NO , the lowering of bed and freeboard gas temper atures is not considered

x a primar y NO control method. Steam temperature control, sulfur capture , x and comb ustion efficiency usually do not allow bed and freeboar d temperatures much lower tha n 815 C (1,500 F). Under staged combustion, 40 lower bed and freeboard temperatures are not generally desired sinc e temperature affects the rate of gas-solid catalytic reactions intended t o reduce NO
.

x 5.2.3.3 FGR in Coal-fired FBC Boilers FG R through the air distribution plate in a FBC boiler is not a widel y accepted NO control technology, or one that has received much researc h x ef fort to date. In general, FGR allows operation with reduced combustio n 40 oxygen levels in the den se portion of the bed, contributing to NO reduction. x To some e xtent, FGR also reduces thermal NO by lowering the pea k x combu stion temperature. When FGR is used in combination with SCA, th e primary mechanism that results in NO reducti on is the gas temperature drop x in t he lower portion of the bed combined with a localized reduction in th e oxygen concentration. However, thermal NO re duction in FBC is not as high x a priority as the control of fuel NO . FGR application in FBC has been limited x for the most part to pilot scale research. However, test results reported for5-62

two full scale CFBC units with SCA and FGR show a marked NO reductio n x effi ciency of nearly 70 percent for FGR rates in excess of 30 percent

. Cont rolled NO emissions ranged from 90 to 116 ppm (0.12 t o x 0.16 lb/MMBtu). These data are listed in Table 5-6 and in Appendix B. 33 Severa l disadvantages of applying FGR to CFBC units have bee n identified :

33 Combustion efficiency and sulfur retention are generally lowered Larger combustor, backpassing boiler chamber, greater bag house capacity, and fan size are required Greater power consumption is required for additional equipment Boiler capital and operating costs are increased Be cause of these potential adverse side effects, FGR is generally no t considered a viable NO control technology for FBC boilers. x 40 5.2.3.4 Other Process Variables Affecting NO x The actual NO levels achieved by combustion modification or othe r x controls will depend on several process variables which can influence NO x emissions in FBC boilers. These variables can be grouped into three major categor ies: chemical and physical coal properties, chemical and physica l properties of sorbent and bed material, and FBC operational variables. Coal Properties Two impo rtant coal properties are the reactivity and size. Lowe r reactivity coals emit lower levels of NO under both staged and unstage d x conditions, due to the catalytic properties of char in red ucing formed NO, and because of the rapid oxidation of volatile nitrogen to NO. However, coal s 43 wi th low reactivity, and, hence, lower volatile content, are generally burne d less efficiently in FBC boilers than high reactivity coals. Also, SCA is not as effective in reducing NO w hen low reactivity coals are burned, as discussed x in Section 5.2.3.1. Generally, an increase in coal size tends t o reduce NO and x5-63

improve t hermal efficiency. NO is reduced due to the reduced surface area x of the char which acts as a catalyst in NH oxidation to NO in the presence of 3 excess oxygen. Thermal efficiency tends to impro ve as a result of the lower 44 levels of elutriated coal leaving the bed. 44 NO emissions also depend on the nitrogen content of the volatil e x fraction of the coal being used, generally increasing as this nitrogen content increases. Under staged combustion, fuel nitrogen conversion is signific antly 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 NO emissions will tend to be less under staged conditions than for unstaged x combustion. The sulfur content of the coal does n ot in itself have any effect on NO x emis sions. Indirectly, however, the use of high-sulfur coals requires mor e limestone sorbent to su ppress SO emissions, which will likely increase NO 2 x unles s the FBC boiler is operated with some degree of air staging. This i s because under oxygen rich conditions, excessive calcined limestone (CaO) acts as a ca talyst in the oxidation of NH to NO, increasing the conversio n 3 rate of volatile nitrogen to NO. With combustion staging, CO levels in the 44 dense portion of the bed reduces formed NO over char and CaO surfaces. Sorbent/Bed Material NO emissions are also affected by the chemical and physica l x proper ties of the bed material and sorbent used for sulfur capture. A n increase in Ca/S ratio for improved sulfur capture, for example, will increase NO , especially under unstaged combus tion conditions, as discussed earlier. x CF BC boilers utilize lower Ca/S levels than do BFBC units, and thus tend to emit less NO . W ith staged combustion, however, the effect of Ca/S ratio on x NO forma tion is reduced due to the catalytic effect of CaO and CaS on NO x reduction in the presence of high concentrations of CO.5-64

Operational Variables Several operational variables have been reported to affect NO x formation, including ash recirculation, coal distribution in the bed, an d fluidization velocity. Of these, ash recirculation has the most effect. When CaO concentrations in the ash are low and char and CaSO concentration s are 4 hi gh, a net reduction in NO is achieved with increased ash recycle. Th e x CaSO acts as a catalyst in oxidation of NH and reduction in NO in th e

4 3 freeboard section of the furnace, according to localized temperature an d concentra tion of NH and O
. This was demonstrated in a 125 MMBtu/h r 3 2 45 BFBC b oiler in Japan, where the use of ash reinjection resulted in a 67 percent NO reduction, from 90 to 30 ppm (0.12 to 0.04 lb/MMBtu). x 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 NO . However, under staged conditions, it i s x like ly that better distribution of the coal and increasing the bed depth wil l offer improved NO control and more efficient operation, although th e x reduction is anticipated to be small. 46 The effect of fluidization velocity on NO emissions from FBC boilers x is generally small. At constant high excess air levels, an increase in fluidizing
ve locity has shown a small effect on NO . When overall excess air is kep t x low, the effect is relatively insignificant. 46 In summary, NO emissions from FBC boilers are influenced b y several x de sign and process parameters to such an extent that NO levels can var y x significa ntly from one unit to the next. For a given type of FBC design, coal proper ties such as nitrogen content and reactivity; and FBC operatin g conditions such as bed temperatur e, ash recirculation, and coal distribution;
are principal variables affecting NO

. Additionally, the sulfur content of the x coal together with the required amount of sulfur capture determine th e5-65

amount of sorbent used, which in turn influences NO

. Sorbent reactivity and x size distribution also play important roles in NO emissions since they affect x calcium u tilization in the fuel bed. Of the combustion modification NO x control techniques examined in this section, SCA is the most widel y applicable and cost-effective method. 5.3 COMBUSTION MODIFICATION NO CONTROLS FOR OIL- AN D x NATURAL-GAS-FIRED ICI BOILERS Co mbustion modification NO controls for full-scale oil- an d x natural-gas-fired ICI boilers have been implemented primarily in California

. Most of the retrofit activity has been in response to local air districts' rule s restricting NO emissions from boilers and process heaters. For example , x SCAQMD Rules 1146 and 1146.1 regulate NO emissions from boile rs as small x as 2 MMBtu/hr in capacity. Rule 1146 restricts NO emissi ons from ICI boilers x with heat input c apacities 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 capa city and has more than a 25 percent annual capacity factor, in which case NO emissions ar e x limited to 30 ppm. Rule 1146.1 mandates a 30 ppm (0.04 lb/MMBtu) limit for ICI bo ilers of at least 2 MMBtu/hr capacity but less than 5 MMBtu/hr

. Additionally, several districts re strict NO from boilers used in the petroleum x refi ning industry. It should be noted that these limits are possible i n Southern California only because of the reliance on cle an burning natural gas and ligh t distillate oil. Applicable controls include WI/SI; FGR; LNB; SCA , including BOOS and OFA; and a combination of these. The control of NO from f uel oil combustion relies on the suppression x of both fuel and thermal NO , whil e with natural gas combustion, NO control x x focuses primarily on thermal NO only. In order to achieve this suppression, x control methods involve combustion staging or reduction of peak flam e tem perature. Applicable combustion modification control techniques ar e SCA, including BOOS and OFA; use of LNBs; FGR; and combinations of thes e5-66

techniques. As explained earlier in this chapter, load reduction, reduced air preheat, and low excess air firing are not considered independent or viabl e control technologies. Fuel switching has traditionally not been viewed as a control technology. How ever, the switching from coal to oil or gas and from hi gh-nitrogen residual oil to lighter oil fractions or gas have come unde r incre ased consideration in regional and seasonal NO compliance options

. x Fue l switching is discussed in this section along with more traditiona l combustion modification controls.5-67

Tables 5 - 75-68TABLE 5-7. COMBUSTION MODIFICATION NOCONTROLS FOR FULL-SCALE NATURAL-GAS-FIREDxINDUSTRIALBOILERSControltechniqueDescription of techniqueNumber ofindustrialboilers tested% NOreductionxControlled NOxlevels ppm @ 3% O,2lb/MMBtuCommentsWIWater injected into the flame in amountsequivalent to a fraction of the fuel.Watertube—2a50-7735-45 (0.04-0.056)Thermal efficiency loss of 0.5 to 2.5%.Often implemented with OT, LNB, orBOOS. CO increase is expected.Experience limited to SouthernCalifornia.SCAFuel-rich firing burners with secondary airinjection.Watertube—5bWatertube—7cFiretube—1b17-46N.A.d550-200 (0.06-0.24)67-170 (0.08-0.20)67 (0.08)Includes BOOS and OFA. BOOSapplies to multi-burner units only.LNBLEA burners operate at lower oxygenconcentrations. Staged combustion burnerscontrol mixing of primary combustion airand fuel. Also have radiant ceramic fiberburner which reduces peak furnacetemperature.Watertube—18bWatertube—177cWatertube—21gFiretube—5bFiretube—2g39-71 (for 5 boilers)eN.A.N.A.32eN.A.25-140 (0.03-0.17)30-170 (0.04-0.20)f<40 (<0.05)23-68 (0.03-0.08)<40 (<0.05)LEA LNBs more applicable to singleburner systems. Staged air burnerscould result in flame impingement onfurnace walls of smaller units.Radiant LNBFlameless premix ceramic radiant burnerFiretube—653-829-30 (0.01-0.036)Special design LNB limited to firetubeapplications (<10 MMBtu/hr).FGRRecirculation and mixing of stack flue gaswith burner combustion air.Watertube—20bWatertube—13cFiretube—5753-74 (for 2 boilers)eN.A.55-76 (for 10 boilers)e18-67 (0.02-0.08)30-85 (0.04-0.10)16-61 (0.02-0.08)Requires motor, fan, and connectingducting. Reported NOdata is for FGRxrates of 10 to 30%.LNB+FGRCombination of LNB and FGR controltechniques.Watertube—22bWatertube—50cFiretube—5b55-84 (for 5 boilers)eN.A.N.A.13-39 (0.02-0.05)25-170 (0.03-0.20)20-37 (0.02-0.04)Combined methods are not additive intheir effectiveness.LNB+SCACombination of LNB and SCA controltechniques.Watertube—9cN.A.85-170 (0.10-0.20)Applicable principally to multi-burnerboilers.5-69TABLE 5-8. COMBUSTION MODIFICATION NOCONTROLS FOR OIL-FIRED INDUSTRIAL BOILERSxControltechniqueDescription of techniqueNumber of industrialboilers tested% NOxreductionControlled NOxlevels ppm @3% O, lb/MMBtu2CommentsLNBStaged combustion burners controlmixing of primary combustion airand fuelResidual WT, FT-18a,bResidual WT-24cDistillate WT-7bDistillate WT-71cDistillate FT-1b30-60N.A.dN.A.N.A.1569-200 (0.09-0.25)80-475 (0.10-0.60)e60-119 (0.08-0.15)65-260 (0.08-0.33)f120 (0.15)Staged air burners could result inflame impingement on furnacewalls of smaller units.FGRRecirculation and mixing of stackflue gas with combustion airResidual WT-2bResidual WT-1cDistillate WT-6bDistillate WT-2cDistillate FT-11b4-30N.A.20-68N.A.N.A.91-197 (0.12-0.25)275 (0.35)28-120 (0.04-0.15)240 (0.30)28-126 (0.04-0.16)Requires motor, fan, andconnecting ducting. Reporteddata are for FGR rates of 10 to30%.SCAFuel-rich firing burners withsecondary air injectionResidual WT-11bResidual WT-3cResidual FT-1bDistillate WT-1bDistillate WT-3c5-42N.A.4930N.A.157-588 (0.20-0.74)160-240 (0.20-0.30)90 (0.11)77 (0.10)70-95 (0.09-0.12)Includes BOOS and OFA.BOOS applicable for boilerswith multiple burners only.Firetube test experimental.LNB+FGRCombination of LNB and FGRcontrol techniquesResidual WT-1bResidual WT-4cDistillate WT-10bDistillate WT-26cN.A.N.A.N.A.N.A.180 (0.23)80-435 (0.10-0.55)20-103 (0.03-0.13)30-200 (0.04-0.25)Combined methods are notadditive in their effectiveness.LNB+SCACombination of LNB and SCAcontrol techniquesResidual WT-11cDistillate WT-6cN.A.N.A.160-315 (0.20-0.40)160 (0.20)Applicable principally to multiburner boilers.WT = watertube; FT = firetube. Watertube boilers include both single-burner packaged (PKG-WT) boilers and multi-burner field-erecteda(FE-WT) boilers.Data primarily from test reports. See Appendix B.bData from Coen Company. See Appendix C. NOlevels are not necessarily actual. Often represent vendor-guaranteed levels.cxN.A. = Not available. No baseline (uncontrolled) NOdata available.dxRange for 90 percent of units listed in Appendix C.eRange for 96 percent of units listed in Appendix C.f

and 5-8 summarize the information available on the performance an d5-70

applicability of these techniques for natural- gas-fired and oil-fired ICI boilers, respec tively. For natural-gas-fired boilers, more data were available fo r watertube units equipped with LNB or combined LNB and FGR. Controlle d NO levels for these units ranged from as low as 13 ppm (0.02 lb/MMBtu) to x as high a s 170 ppm (0.20 lb/MMBtu). The limited data available for gas-fired wate rtube units with SCA show controlled NO levels of 50 to 200 ppm (0.06 x to 0 .24 lb/MMBtu). Controlled NO emissions from gas-fired firetube units , x most equi pped with FGR, ranged from 15 to 68 ppm (0.02 to 0.08 lb/MMBtu). The data presented in Table 5-8 also show wide variability i n controlled NO levels. For example, units fired on distillate oil with LNB showed NO x x ranging from 60 to 260 ppm (0.08 to 0.33 lb/ MMBtu). With combined LNB and FGR, NO ranged from 30 to 200 ppm (0.04 to 0.25 lb/MMBtu).

x The following subsections, 5. 3.1 through 5.3.7, describe each of these met hods as they are applied to both oil and natural gas combustion

. Although difference s in fuel type are acknowledged and affect NO emission x levels, in general the control equipment and techniques used for oil an d natural gas firing ar e similar. In fact, a large percentage of industrial boilers
are capable of burning gas and oil individually or in combination. All data 47
co llected for this section are contained in Appendix B. Additionally, dat a provided by Coen Company and5-715-72

Tampella Power Corporation are contained in Appendix C. These data incl ude emission levels based on vendor guarantees, an d actual recorded emissions. 5.3.1 Water Injection/Steam Injection (WI/SI) WI/SI are effective control techniques for reducing thermal NO i n x natura l-gas-fired ICI boilers. When water or steam are injected in the flame, they re duce the peak flame temperature and the oxygen concentration. The quenching of the flame reduces the NO by as much as 75 p ercent, depending x 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 vaporizatio n required to change water into steam. WI has seen very limited application in Sout hern California, where NO x emission regulations are the most stringent. Because of low initial cost, the tec hnique is considered particularly effective for small single-burne r packaged boilers operated infrequently. In these applications, the oil gu n 48 positio ned in the center of the natural gas ring burner is used to inject th e water a t high pressure. The amount of water injected normally varie s betw een 25 and 75 percent of the natural gas feedrate, on a mass basis

.5-73

Figure 5-15. As the rate of water injection increases, NO decreases. x 48 Figure 5-15 illustrates the general trend of NO reduction with water injection x rate. However, the technique has some important environmental and energy impa cts. For example, CO emissions increase because of the quenchin g effect on combustion, and the thermal efficiency of the boiler decrease s because the moisture content of the flue gas increases, contributing t o greater thermal losses at the stack. Another concern related to the technique is its potential for unsafe combustion conditions that can result from poo r feedrate control. 5.3.2 Low-NO Burners (LNBs) in Natural-gas- and Oil-fired ICI Boilers x LNBs for natural-gas- and oil-fired ICI units are becoming mor e widespread as the technology has been commercialized and improved, and as regulatory requirements become stricter. LNBs in the ICI se ctor have been applied primarily to packaged watertub e ICI boilers, and to a lesser extent, to packaged f iretube and field erected watertube boilers. Most of the available5-74

dat a are from gas-fired boilers located in California. Some of the principa l types of LNB available are staged combustion burners, relying on eithe r stag ed air or staged fuel, LNB with FGR, and ceramic fiber burners

. Additionally, another type of burner known as the cyclonic combustion bur ner has recently been introduced. Major manufacturers of staged combustio n burners for ICI sized boilers include Coen Company, Inc., Faber Burne r (Ta mpella Power), Todd Combustion, Peabody, Riley Stoker, Industria l Combustion, and the John Zink Company. Alzeta Corporation has developed the radiant ceramic burner, while York-Shipley has recently introduced th e cyclon ic burner, both of which are for use primarily in smaller package d firetube boilers. Th ere are also burners known as LEA burners, which reduce NO x formation by operating at low oxygen concentrations. An added benefit o f LEA burners is improved thermal efficiency. When compared to conventional burners, however, these burners provide moderate reductions in NO , x reportedly on the order o f 10 to 25 percent reduction. The primary benefits 49 of LEA burners are their increase d efficiency and fuel saving characteristics. Because of the greater difficulty in achieving equa l air distribution in multiple burner systems, LE A burners are generally more applicable to single burner systems. The dat a in Tables 5-7 and 5-8 indicate that ICI boiler LNB experience includes the reported NO levels and re duction efficiencies shown in Table 5- x5-75 Fuel Performance levels Residual oil 30-60% 0.09-0.60 lb/MMBtu Distillate oil N.A. a 0.08-0.33 lb/MMBtu Natural gas conventional burners 32-71% 0.03-0.20 lb/MMBtu Natural gas radiant burners 53-82% 0.01-0.036 lb/MMBtu N.A. = Not available. a TABLE 5-9. REPORTED NO LEVELS AND REDUCTION x EFFICIENCIES IN ICI BOILERS WITH LNBs

9, exclusive of LNB vendor data from Appendix C. There are many factor s that affect the level of NO achieved with these burners . The nitrogen content x of res idual oil, the heat release rate, and the amount of combustion ai r preheat com bined with level of FGR used for gas fuel are among the mor e
cr itical factors contributing to the wide range in controlled NO levels. Th e x 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 NO emissions by staging the injection of either air or fuel in the near

x burner region. Hence, staged combustion burners may be further classified as either staged ai r burners or staged fuel burners. Staged air burners have been ap plied to watertube boilers since 1979. Figure 5-1 6 505-76 Figure 5-16. Staged air LNB. 535-77

is a sc hematic of a typical staged air burner, in which primary, secondary , and ter tiary (denoted as staged air in the figure) air are injected into th e burner. As the figure notes, the division of combustion air reduces th e oxygen concentration in the primary burner combustion zone, lowering th e amount of NO formed and increasing the amount of NO reducing agents

. Sec ondary and tertiary air complete the combustion downstream of th e primar y zone, lowering the peak temperature and reducing thermal NO x fo rmation. Besides the basic staged air burner shown, there are variation s on staged air burners which incorp orate internal recirculation of combustion products to aid in NO reduction. x Due to the staging effect of staged air burners, flame lengths tend to be longer than those of conve ntional burners. This is of particular concern 51 for pac kaged units because there is the possibility that flame impingemen t will oc cur on the furnace walls, resulting in tube failure and corrosion

. Additionally, staged air burners are often wider and longer than conventional bur ners, requiring significant modifications to existing waterwalls an d windboxes. Burner size5-78

may also be an important fa ctor when assessing the feasibility of retrofitting boilers located in restricted spaces. Staged fuel b urners are a slightly more recent development in staged comb ustion LNBs. These burners were originally developed for use o n process heaters in the refining and petrochemica l industries, and hence have been appl ied primarily to process heaters rather than boilers. Figure 5-1 75-79 Figure 5-17. Staged fuel LNB. 525-80

is a schematic of a staged fuel burner, manufactured by the John Zin k Company. Here, combustion air is introduced without sep aration and instead the fu el is divided into primary and secondary streams. Despite the hig h oxygen concentration in the primary combustion zone, therma l NO formation x is limit ed by low peak flame temperatures which result from the fuel-lea n combust ion. Quenching of the flame by the high excess air levels als o
oc curs, further limiting the peak flame temperatures and providing activ e red ucing agents for NO reduction. Inerts from the primary zone the n x 52
re duce peak flame temperatures and localized oxygen concentration in th e secondary combustion zone, thereby reducing NO formation. An advantage x of staged fu el burners over staged air burners is that they tend to hav e 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, NO reductions of 39 to 71 percent were r eported for three existing and

x one new water tube boiler. Controlled NO levels for these and 10 other gas- x fired watertube boilers, five of which were existing units retrofitted with LNBs, ranged from 25 ppm (0.03 lb/MMBtu), for a 10 MMBtu/hr boiler in Taiwan, to 140 ppm (0.17 lb/MMBtu), for a 100 MMBtu/hr floor firing unit in Germany

. This ra nge is quite wide due to differences in boiler design, capacity, an d burne r type. An example of the levels of performance achievable wit h different burners is that when a different LNB was tested in the German boiler mentione d above, the controlled NO level was 112 ppm (0.13 lb/MMBtu ) x instead of 140 ppm (0.17 lb/MMBtu). 55 All but one of the above 14 units were packaged. The only field-erecte d unit, a 380 MMBtu/hr dual burner unit at Luz-Segs II in California, reported a controlled NO level of 80 ppm (0.10 lb/MMBtu) when retrofitt ed with an LNB. x 56 Test results from one gas-fired firetube unit at Fort Knox retrofitted with a5-81

staged air burner showed a 32 percent reduction in NO , from 100 ppm down x to 68 ppm (0.12 to 0.08 lb/MMBtu). No other data are available for firetub e units with staged air LNB.5-82

Additional data supplied by Coen Company (see Appendix C) for 177 natu ral-gas-fired LNB installations showed guaranteed or actual NO level s x typically between 30 and 170 ppm (0.04 to 0.20 lb/MMBtu) with LNB. These 57 data include emis sions levels for boilers of various types and sizes, ranging from packa ged to field erected units producing 25,000 to 520,000 lb/hr o f ste am (approximately 30 to 600 MMBtu/hr heat input). All units used Coe n DAF LNBs. Appendix C also contains a list of 23 Tampella P ower Corp. Faber LNB i nstallations that reportedly emit 40 ppm NO (0.05 lb/MMBtu) or les s x when firing natural gas. All of these boilers are packaged units ranging from 9,000 to 100,000 lb/hr steam capacity. 58 For sma ller industrial gas-/oil-fired boilers, Riley Stoker has als o int roduced the Axial Staged Return (ASRTM) flow burner, the Axial Flam e Staged (AFSTM) burner, and the Swirl Tertiary Staged (STSTM) burner. Th e ASR burner is based on patented Deutsche Babcock technology that use s axial staging of primary and se condary air streams and internal recirculation5-83 Figure 5-18. Low-NO ASR burner. x 59 of self-aspirated hot furnace gases. The burner, illustrated in Figure 5-18, has a maximum design capacity of 275 MMBtu/hr, with controlled NO level s in the x 20 to 30 ppm (0.025 to 0.035 lb/MMBtu) range when firing natural gas with 12 to 30 percent FGR assistance. The AFS burner incorporates axial stagin g 59 of primary and secondary air and staged fuel addition. Th e burner, illustrated i n Figure 5-1 95-84 Figure 5-19. AFS air- and fuel-staged burner. 59 , has a firing capacity in the 20 to 40 MMBtu/hr range. With FGR addition, 59 NO emissions in the 30 to 40 ppm (0.035 to 0 .048 lb/MMBtu) range have been x5-85 Figure 5-20. Riley Stoker STS burner. 59
reported in full-scale retrofits

. The STS burner, illustrated in Figure 5-20, is 59 designed for retrofit on multiple burner wall-fired boilers with 500 F ai r prehe at. In one full-scale STS burner retrofit at a paper mill, reported NO x emissions ranged fro m 90 to 110 ppm (about 0.1 to 0.13 lb/MMBtu) with high air preheat and heat release rate and without FGR. 59 In s ummary, LNB NO reduction efficiencies for natural-gas-fire d x boilers including one firetube boiler and five watertube units range from 32 to 71 percent, in agreement with previously reported performance levels for natu ral gas firing. LNB reduction efficiencies for 13 additional watertub e uni ts listed in Appendix B could not be computed because of a lack o f baseline (uncontrolled) emissi ons data. Controlled NO emissions for the 18 x water tube units ranged from 25 to 30 ppm (0.03 to 0.04 lb/MMBtu), for th e smaller units (10 to 31 MMBtu/hr input), and from 58 to 140 ppm (0.07 t o 0.1 7 lb/MMBtu), for the remaining boilers, which ranged in size from 45 t o5-86

380 MMBtu/hr input. Controlled NO emissions reported by two LN B x manufacturers for nearly 200 units ranged between 30 and 170 ppm (0.04 to 0.20 lb/MMBtu). Some burner manufacturers have reported NO reductio n x efficiencies of anywhere from 50 to5-87

90 percent. In fact, several manufacturers guarantee NO emissions belo w x 40 ppm (0.05 lb/MMBtu) when firing natural gas in smaller indust rial packaged boile rs, primarily in response to the SCAQMD regulations in California. For example, Faber, a division of Tampella Power, guarantees less than 40 ppm NO on any burner system and will guarantee less than 30 pp m x (0.04 lb /MMBtu) of NO on a case-by-case basis. Similarly, Coen Company x 60 states that less than 30 ppm of NO will be emitted from its M icro-NO ® LNB. x x 61 Performance levels of less than 20 ppm are achievable on a case-by-cas e basis. For oil firing with staged air LNBs, data were collected for 84 boiler s firi ng distillate oil and 46 boilers firing residual oil. The distillate-fuel-fire d boi lers with staged air LNBs showed controlled NO levels of 60 to 260 ppm x (0.08 to 0.33 lb/MMBtu). The 25 domestic units fired o n No. 6 residual oil (fuel nitrogen c ontents of 0.14 to 0.3 percent) had controlled emissions of 80 t o 475 ppm (0.10 to 0.60 lb/MMBtu). Due to a lack of baseline uncontrolle d emissions data for these domestic units, it was not possible to calculate NO x red uction efficiencies for the boilers. Additionally, overall performanc e results of 17 firetube and watertube boilers in Japan firing residual oil have been reported. Fo r these units, which ranged in size from 5 to 40 MMBtu/hr, tes t results showed NO reductions between 30 and 60 percent, wit h x controlled emissions between 69 and 185 ppm (0.09 and 0.23 lb/MMBtu). 62 The retrofit of LNBs usually involves removing the o riginal 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 applicat ions where new fan or ducting equipment are desired, som e manufact urers offer complete packaged burner units, in which the retrofi t burner is combined with combustion controls, flame safeguard equipment ,5-88

fuel piping, and a combustion air fan. These are sold together as factor y assembled, self-contained packages. 5.3.2.2 Ceramic Fiber Burners Alzeta Corporation has developed a ceramic fibe r 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 wa tertube and firetube units, the Pyrocore burner has b een demonstrated primarily in firetube boilers and proc ess heaters. This burner, depicted in Figure 5-2 15-89 Figure 5-21. Pyrocore LNB schematic. 635-90

, 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 em its energy in the form of IR radiation. In the Pyrocore burner, fuel gas is premixed with combustion air befor e entering the burner. The mixture pas ses through a porous burner material and is ignited, establishing a thi n
c o mbustion 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 o ccur only on the outer surface. The low combustion temperature limits thermal NO formation.

63 x Field tests of this burner retrofitted to a 3.3 MMBtu/hr firetube boiler at Hall Chemical in Ohio showed NO reduction of 78 percent, with controlle d x emission levels of 15 ppm (0.02 lb/MMBtu). Another field test conducted on an 8 MMBtu/hr boiler retrof itted with the Pyrocore burner showed 53 percent reduction in NO , to a controlled level of 24 ppm (0.03 l b/MMBtu), while a third x 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 th at NO was reduced by 71 percent and CO by 94 percent. To date, mos t

x 64 burners suppl ied by Alzeta have been designed to achieve less than 30 ppm NO at full rated load, although the act ual emissions for many are reported to x 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 o f physica l limits on the size of the radiant burner. Structural issues are th e major concern with larger application s. Further research and tests are being conducted to extend the5-91

Pyr ocore burner's applicability to larger firetube and watertube boilers , including the use of multiple burners. Ad ditional research is currently focusing on the use of lower surface firing rates, moderate temperature environments, and modest excess air t o attain ultra-low NO l evels of 9 ppm and below. Alzeta Corporation and Zurn x Industries have recently commissioned an ultra-low-NO boiler, the Radiant x Cell BoilerTM, that utilizes the Alzeta flameless Pyrocore radiant burners and has a reported capability of 9 ppm of NO and less than 50 ppm of CO. x 65 5.3.2.3 Other LNBs An LNB type known as a cyclonic burner has recently been developed by Yor k-Shipley for packaged firetube boilers. The burners are available up to 16.6 MMBtu/hr heat input. In cyclonic combustion, high tangentia l veloci ties are used in the burner to create a swirling flame pattern in th e furnace. This causes intense internal mixing as well as recirculation o f combustion gases, dilut ing the temperature of the near-stoichiometric flame and lowering thermal NO formation. The tangential flame causes clos e x contact between combustion gases and the furnace wal l, adding a convective component to the radiant heat transfer within the furnace. The in creased heat transf er and low excess air operation of the cyclonic burner result i n increased boiler efficiency. To achieve ultra-low NO levels, a small quantity of low-pre ssure steam x is injected into the burner, which furt her reduces the local flame temperature and NO formation. Testing revealed that NO emissions during natural gas

x x firi ng could be reduced from 70 ppm to less than 20 ppm without affectin g bur ner stability, low excess air operation, or turndown performance

. However, the use of steam did result in a boiler heat efficiency lo ss of roughly 5 percent. The cyclonic burner is available as a stand-alone retrofit burner

665-92

wi th a bolt-on feature. However, no retrofit emissions data were obtaine d during this study. 5.3.3 Flue Gas Recirculation (FGR) in Natural-gas- and Oil-fired ICI Boilers FGR inv olves recycling a portion of the combustion gases from th e stac k to the boiler windbox. These low oxygen combustion products, when mixed with combustion air, lower the overall excess oxygen concentratio n and act as a heat sink to lower the peak flame temperature and the residence time at peak flame tempera ture. These effects result in reduced thermal NO x formation. However, there is l ittle effect on fuel NO emissions. The amount x of NO reduction achievable depends primarily on the fuel nitrogen content

x and amount of FGR used. Other thermal NO control con cepts similar to FGR x are su ch control techniques as WI and SI, in which water, rather tha n recirculated flue gas, is used as an inert substance to lower the peak flam e temperature. FGR is much more commonly used, however. FGR is cu rrently being used on a number of watertube and firetub e boilers firing natural gas. Only limited NO reduction efficiency data ar e x availa ble, however, as baseline (uncontrolled) NO data for most units ar e x unre ported. Data for four natural-gas-fired watertube boilers equipped with FGR show a range in NO reduction of 53 to 74 percent, while for 10 gas-fired x firetube units with FGR, NO reduction efficiency ranged from 64 t o x 7 6 percent. In all, controlled NO emission data were collected for a total of x 33 g as-fired watertube and 57 gas-fired firetube units operating with FGR

. Four of t he watertube units and 26 of the firetube units were identified a s retrofit applications. Controlled NO level s ranged from 20 to 85 ppm (0.02 to x 0.10 lb/MMB tu) for the watertube units and 16 to 37 ppm (0.02 t o 0.04 lb/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.5-93

Boilers are usually not operated w ith more than 20 percent FGR due to flame stability considerations. 67 NO reduction efficiency data for oil-fired units with FGR are also very x limited. In one test program, a single boiler was fired o n both residual oil and dist illate oil, using FGR and keeping all other variables constant. NO wa s x reduced b y 68 percent for distillate oil firing, yet was only reduced b y 11 percent when residual oil was used. These data illustrate t hat 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 NO rathe r x than fuel NO . The 68 percent reduction was obtained with a relatively high x FGR rate of 28 percent. Another boiler firing distillate oil reported NO x reducti on of only 20 percent, using 10 percent FGR. Available data are to o limited to estimate typical NO reduction effic iencies for oil-firing boilers with x FGR. In general, however, thermal NO reductions from distillate-oil-fire d x boilers with FGR are somewhat le ss than from natural-gas-fired units. This 68 is due to the greater potential for flame instability and emissions of unburned
co mbustibles from distillate-oil-fired units, which limits the practical rate of FGR t hat can be used. Controlled NO emissions for distillate oil firing with x FGR were between 28 and 240 ppm (0.04 to 0.30 lb/MMBtu) for 19 boilers. For three unit s firing residual oil, controlled NO levels ranged from 125 t o x 275 ppm (0.16 to 0.35 lb/MMBtu). When compared to the number of LNB or combined LNB and FG R install ations listed in Tables 5-7 and 5-8, the number of watertube boiler s equipped only with FGR is relatively small. In general, for retrofit cases t o exist ing packaged watertube ICI boilers, FGR is rarely applied without th e install ation of a new LNB as well. This is because the performance of many older burner systems tend to be adversely affected when an in ert such as fuel gas is in jected into the combustion zone. Oxygen trim systems have been 575-94 Figure 5-22. FGR system for gas- or oil-fired boiler. 71 installed to allow use of an existing burner with FGR and LNB toget her. Thus, the mo st common combustion modification NO controls for package d x 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 sho wn in Figure 5-22. In order to retrofit a boiler with FGR, th e major additional equipment needed are a gas recirculation fan and ducting. Major companies that suppl y FGR equipment for packaged gas- and oil-fired bo ilers are Cleaver Brooks, Coen Company, Industrial Combustion, Keele r (Tampella Power), and Todd Combustion.5-95

5.3.4 Fuel Induced Recirculation (FIR) Fuel induced recirculation (FIR) is a control technology for natu ral-gasfired boi lers recently introduced by the John Zink and Holman Boile r 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 demonstrate d
comm ercially in an industrial unit in California, achieving NO emissio n x readings as low as 17 ppm with little adverse affect on CO emissions. 69 The primary difference between FIR and FGR is t hat 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 low ers the
vo latility of the fuel mixture, FIR reduces the concentration of hydrocarbo n radicals that produce prompt NO. Additionally, FIR reduces thermal NO in 6 x the same manner as FGR, by acting as a thermal diluent. Thus, one of th e main bene fits of FIR technology is that it impacts both prompt NO an d thermal NO formation in gas-fired boilers.

x A se cond fundamental feature of FIR is that flue gas recirculation i s induced us ing the natural gas dynamics of the burner flow streams, without additi onal equipment such as recirculation fans. According to th e 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 Combusti on Air (SCA) in Natural-gas- and Oil-fired ICI Boilers Stage d combustion for oil- and natural-gas-fired boilers in the IC I sector consists of injecting a portion of the total combustion air downstream of the fuel-rich primary combustion zone. Staged combustion can b e
acco mplished using secondary OFA or side-fired air ports, or by using th e BO OS technique. The applicability of OFA, side-fired air, or BOO S (collectively grouped under the term SCA) depends primarily on the type of5-96

furnac e design involved — i.e., watertube or firetube — and the size of th e boiler. Generally, SCA is not considered viable for retrofit to packaged boiler units due to installation difficulties. The following subsections summar ize the performance, applicability, and availability of the various methods o f implement ing SCA on the major types of natural-gas- or oil-fired ICI boilers. 5.3.5.1 Firetube Boilers SCA is not considered a primary NO control method for existin g x firetube boilers because of the major modifications re quired to retrofit staged air to these boilers. BOOS is not applicable bec ause these units rarely have 72 more than one burner. Side-fired air application is difficult as retrofit requires penetration of the firetube boile r water shell. Performance data are available only f or one experimental application of side-fired air to a 12 MMBtu/h r firetube bo iler fired on residual oil and natural gas. In this test program , spo nsored by the U.S. EPA, secondary air was injected at the rear of th e furnace opposit e the burner through eight pipes connected to a forced-draft fan. In this way the secondary air was i ndependent of the primary burner air. Test results for residual oil firing showed that NO was red uced from 177 ppm x to 90 ppm (0.22 to 0.11 lb/MMBtu), a 49 percent reduction in NO . Durin g x these residual oil combustion tests, th e burner was operated at 76 percent of stoic hiometric conditions, and the overall excess oxygen level wa s 4 percen t. However, boiler load was reduced to 50 percent due t o

73 combustion instabilities at high loads. Tests conducted on the same boiler but firing natural gas at 71 percent load had almost no effect on NO , showing only 5 percent NO re duction, from x x 70 to 67 ppm (0.084 to 0.080 lb/M MBtu). NO reduction for gas-firing may not x have been as high as the residual oil-firing case because of the sl ightly higher test l oad and because the burner oxygen level was higher, at 90 percen t stoichiometry. Also, because natural gas combustion emits lower levels of5-97

NO than residual oil firing to begin with, it is generally more difficult t o x achieve as much percentage NO reduction with natural gas. x 5.3.5.2 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 th e case with firetube boilers, retrofit of SCA to smaller packaged watertube units is generally not considered a primary NO control option due to the difficulty x of ret rofitting SCA hardware. Hence, experience on these units has bee n lim ited. Data are available for two experimental retrofit applications of SCA in si ngle-burner oil- and gas-fired packaged watertube units. The firs t appl ication, in a 22 MMBtu/hr unit (Location 19), involved the injection o f second ary air through four steel lances which were inserted through th e windbox a nd the refractory firing face. At 83 percent load, NO emission s x were red uced by 29 percent (controlled NO = 157 ppm or 0.20 lb/MMBtu ) x when re sidual oil was fired, by 30 percent (controlled NO = 77 ppm o r x 0.10 lb/MMBtu) when distillate oil was fired, and by 46 per cent (controlled NO x = 50 ppm or 0.07 lb/MMBtu) when natural gas was fired. 74 At the second site, identified as "Location 38," secondary air wa s injected into a 56 MMBtu/hr boiler through any of 10 SFA po rts. This unit was equipped wit h combustion air preheating, which could vary the temperature fro m roughly 65 to 176 C (150 to 350 F). At operating conditions o f 89 percent load, 2.3 percent excess oxygen, and 14 percent SCA flow, NO x was reduced by 42 percent from the baseline, when residual oil was fired

. During n atural gas firing, staged combustion resulted in a reduction o f 32 percent from the baseline conditions at 2.4 percent excess oxygen an d 14 percent SCA. Results from these two applications showed that in order 74 to maxim ize NO reduction using SCA in packaged watertube units, it i s x nece ssary to operate the burner at substoichiometric levels, and secondary5-98

air mu st be injected sufficiently downstream of the burner exit to allow fo r cooling of combustion gases. These types of SCA retrofits on full-scal e pack aged watertube boilers are generally not considered practical fro m installation and operational standpoints. 5.3.5.3 Field-erected Watertube Boilers For f ield-erected watertube boilers equipped with more than on e burner, staged combustion can be achieved by using OFA, 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 b y maintaining normal air distribution to the burners whil e adjusting fuel flow so that mo re 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 a n NO control technique for natural-gas- x and oil-fired boilers than it is for coal-fired units. As mentioned previously, with PC-fired ICI boilers the mill-burner arrangement usually determine s which burne rs can be taken out of service. For this reason, BOOS is mor e often used as a maintenance operation than a direct NO control method. In x contrast, with oil or natural ga s firing, burners can be shut off individually or fuel flow adjusted to achieve optimum biased burner firing or BOO S operation. For large wall-fired units, BOOS or biased firing are attractive fi rst level retro fit NO control techniques because few equipment modifications ar e

x required. For natural gas firing, data compiled for three industrial b oilers with BOOS showed NO reductions ranging from 17 to 44 pe rcent, with an average x of 29 pe rcent reduction from uncontrolled NO levels. Controlled NO x x em issions from these units, ranging in size from 60 to 120 MMBtu/hr, wer e between 11 7 and 200 ppm (0.14 and 0.27 lb/MMBtu). For residual oil firing, 755-99

data from nine boilers using BOOS showe d NO reduction efficiencies of 5 to x 40 percent. The wide range in control efficiencies is attributed to several factors, in cluding the burner arrangement, the percentage of burners taken out o f service, and the overall excess air. Some burner arrangements are mor e effective in reducing NO with BOOS. Fo r example, a square burner matrix is x more effective than an arrang ement in which all of the burners are located at th e same level. Another controlling factor is stoichiometry of the activ e burners. Althou gh operation with BOOS can measurably reduce NO , th e x operating performance of the boiler can be somewhat degraded because of the need to increase excess air in order to control CO, hydrocarbon, an d smoke emi ssions. Adjustments to the airflow controls, such as burne r 76
re gisters, may be required to achieve the desired burner stoichiometr y wit hout increasing these emissions. Also, operation with BOOS usuall y req uires that the unit be derated unless modification to the fuel deliver y system is made. 77 Data on NO reductions from field-erected oil- or gas-fired ICI boilers

x us ing OFA are very limited. Controlled emissions from two units firin g residu al oil were from 160 to 180 ppm (0.20 to 0.23 lb/MMBtu). Application 57 of t he technique to utility boilers in California has reportedly resulted i n
avera ge NO reductions of 24 percent for oil and nearly 60 percent for gas.

x 78 Gener ally, OFA is applicable only to large furnaces with sufficient volum e above the burners to allow complete combustion and steam temperatur e control. Because of require d 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 5.3.6 Combined Combustion Modification NO Contr ols for Natural-gas- and x Oil-fired ICI Boilers5-100 Many r etrofits have utilized combinations of the above combustio n modificat ion methods. The most demonstrated combination is the use o f LNB with FGR. As mentioned earlier, retrofit of combined LNB and FG R contro ls to existing packaged boilers is often more feasible than using FGR alone. Also, combined retrofit of FGR and LNB to ICI boile rs is considered by some to be a way of meeting str ingent NO control regulations without using x flue gas treatment controls. Data have been collected for 101 natural-gas- 80 fired units, 44 dis tillate-oil-fired boilers, and 13 residual-oil-fired boilers (see Appendices B and C). All were watertube boilers, the majority located i n California. Man y of the California boilers were existing units retrofitted with LNB/FGR controls. NO reduc tion efficiencies of 55 to 84 percent were reported for fiv e x units firing natural gas. No baseline uncontr olled NO data were available for x the other boilers; thus, reduction efficiencie s could not be calculated. Nearly all California units reported controlled NO emissions at or below 40 pp m x (0.05 lb/MMBtu), while the non-California units reported NO levels between x 40 and 170 ppm (0.05 to 0.20 lb/MMBtu). For the distillate-oil-firing units , baseline uncontrolled NO levels were not available; thus, NO reductio n x x e f ficiencies could not be determined. Controlled emissions ranged from 30 to 200 pp m (0.04 to 0.25 lb/MMBtu). For the residual-oil-firing units , controlle d NO levels were between 80 and 435 ppm (0.10 to 0.55 lb/MMBtu). x While some experience has been obtained in combin ing SCA with LNB
or FGR, 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 cost s involved in installing SCA in existing units, especially in package d boilers. The use of SCA with an LNB in a new 140 MMB tu/hr natural-gas-fired wate rtube boiler resulted in controlled NO emissions of 64 pp m x (0.08 lb/MMBtu), while in a new 150 MMBtu/hr residual-oil-fired boiler th e5-101

controlled NO l evel was 175 ppm (0.22 lb/MMBtu). Coen Company reports x 81 controlled NO emissions from 85 to 170 ppm (0.10 to 0.20 lb/MMBtu) for nine x boile rs with LNB and SCA, firing natural gas or distillate oil. For 11 unit s firing residual oi l, NO ranged from 160 to 315 ppm (0.20 to 0.40 lb/MMBtu). x 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 NO x emi ssions from fuel combustion in boilers, switching from high-nitroge n 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 effectiv e in reducing NO as any x othe r combustion control. Low-nitrogen fuels, such as distillate oil an d natural gas, can be used to displace a fraction of the coal or residual oil, or replace them entirely. In either case, signif icant NO reductions are possible. x For example, the cofiring of natural gas with coal in utility boilers h as reduced NO emissions by a minimum of 10 to 30 percent, depending on the boiler , x coal, cofiring configuration, and amount of gas firing. The use of 33 percent 82 natura l gas in a gas cofiring configuration in the top row of burners of a PC-fired boiler (representing a more strategic way to maximize NO reduction x efficiency with reburning techniques) can result in larger NO reduction s x reachin g 35 to 60 percent from uncontrolled levels. Figure 5-2 3 825-102ions.Figure 5-23.Effects of cofiring on NOemissx825-103 Fuel type Fuel

nitrogen, % weight NO x

emissions @ 3% O 2 Residual oil 0.44 350

Distillate oil 0.006 65

Residual oil 0.27 298

Distillate oil 0.015 127

Residual oil 0.20 186

Distillate oil 0.014 84 TABLE 5-10. EFFECTS OF SWITCHING FROM RESIDUAL OIL

TO DISTILLATE FUEL ON INDUSTRIAL BOILERS

illustra tes NO reduction as a function of gas cofiring rate, expressed as a x percen tage of total heat input, measured during six full-scale utility boile r cofiring fi eld tests. These results are applicable, in theory, to large PC-fired industrial boilers. The replacement of high-nitrogen residual oil with a lower nitr ogen fuel
or natura l gas is also very effective in reducing NO . To illustrate, the dat a x shown in Table 5-10 were obtained from industrial boilers firing a residual oil first, an d then switching to a distillate fuel. NO reductions ranged fro m 2 x about 50 to 80 percent for reductions in fuel oil nitrogen of5-104

Base fuel Replacem

ent fuel Quantity used, % Estimated NO x

reduction, % PC Natural

gas 10-20

10-20 (reburning zone) 100 10-30 30-60 60-70

Residual oil with 0.6% N Natural

gas 100 50-80

Distillate oil 100 50-80

Residual oil with 0.3% N 100 30-40

Note: All emissions data were obtained from short-term tests. TABLE 5-11. ESTIMATES OF NO REDUCTIONS WITH FUEL SWITCHING x

approximately 0.19 to 0.436 percent by weight. If all the recorded NO x redu ction is attributed to the drop in fuel nitrogen, about 55 to 65 pp m reducti on in NO results from each 0.1 percentage point reduction in th e x nitrogen content of the oil. Table 5-11 lists estimates of NO reduction s x attainable from ICI boilers cofiring or switching to a cleaner fuel. In addition to natural gas and low-nitrogen fuel oil, the Shell Oi l Company i s marketing a proprietary liquid fuel for industrial boilers. Thi s proprieta ry fuel is similar to distillate oil in thermal energy and physica l propert ies, but contrary to distillate oil it contains essentially no fuel-bound nitrogen ( 3 to 9 ppm). Therefore, its NO emissions are similar to thos e x ach ievable with natural gas. Short-term performance with this proprietary 83 fuel show FGR-controlled emissions in the range of 18 to 35 ppm corrected5-105

to 3 percent O (0.022 to 0.042 lb/MMBtu). It is used as a standby liquid fuel 2 for many boilers in Southern California in cases where natural gas i s curtailed. 5.3.8 Com bustion Modification NO Controls for Thermally Enhanced Oi l x Recovery (TEOR) Steam Generators NO controls for TEOR steam generators have also been implemented x pri marily in California, due to stringent NO emission regulations. Fo r x instance, in Kern County, California, ove r 2,000 oil field steam generators are in use, th e majority fired on crude oil. Other fuels used in these boiler s 84,85 include natural gas and refinery gas. Nearly all units in Kern County utilize
some fo rm of combustion modification NO control, including OT systems , x LNB, or FGR. 84 5.3.8.1 OT Systems OT systems or controllers limi t the excess oxygen during combustion to reduce the formation of NO . It has been reported that these device s x typically reduce the formation of NO from small steam generator s x (<35 MMBtu/hr input capacity) by 15 to 25 percent. Controlled NO 86 x emissions from 71 tests conducted on small cr ude-oil-fired steam generators in Kern County ranged from 166 to 398 ppm (0.21 to 0.50 lb/MMBtu). Fo r 87 larger units greater than 35 MMBtu/hr (most 62.5 MMBtu/hr), Kern County data from 32 6 tests showed controlled NO levels ranging between 174 an d x 340 ppm (0.22 and 0.43 lb/MMBtu). No uncontrolled data were reported fo r th ese units; thus, it was not possible to report actual NO reductio n x efficiencies. However, assuming a typical uncontrolled NO level of 300 ppm x (0.38 lb/MMBtu), as rep orted in References 49 and 88 for large TEOR units in Kern County, average NO reduction on the order of 17 percent was achieved. x It should be remembered that this is only an averag e value, based on average emissio n levels and average reported baseline levels. Actual NO reduction x efficiencies may have been significantly higher or lower depending on the fuel5-106

characteristics, combustion conditions, and design type of each unit. Th e average levels are illustrative to a certain degree, however, as most TEO R steam generators are similar in design and all of the units tested fired Kern County crude. 84 5.3.8.2 LNBs with SCA and OT LNB systems, which generally are us ed with O controllers, have been 2 applie d primarily to large (35 to 62.5 MMBtu/hr) crude oil-fired stea m generators. The most effective and widely used LNB systems als o incorporate SCA, usually using sidefire air injection. I n fact with TEOR steam generators it is co mmon to describe a combined LNB+SCA system as either
a n LNB or an SCA system. Figure 5-2 4 86,87,895-107Figure 5-24. North AmericanLNB on oil field steam generator.925-108

Figure 5-25. Process Combustion Corporation toroidal combustor. 90

depicts one type of LNB+ SCA system, manufactured by the North American Com pany, the principal vendor of LNB systems for TEOR steamers. Thi s burne r system is being used on over 100 crude oil-fired generators in Ker n County. Minor modifications are made to a standard burner and secondary air injection nozzles are inserted around the circumference of the furnace at vari ous locations in the radiant heat transfer section. In a 62.5 MMBtu/h r steam gen erator, 28 secondary air injection ports are used, positioned 17 to 27 feet downstream of the burner. In most applications of this b urner system, O co ntrollers are used to keep excess oxygen at the stack below 2 percent. 2 NO e mission levels of 100 to 160 ppm (0.13 to 0.20 lb/MMBtu) have bee n x reported when crude oil is f ired, representing 50 to 70 percent NO reduction x when compared to unstaged conventional North American burners. 89 Anoth er type of LNB system applicable for retrofit to TEOR stea m ge nerators is the single toroidal combustor, developed by Proces s Combustion Corporation (Figure 5-25). The single toroidal combustor is a tw o-stage burner in which approximately one-third of the fuel is combusted5-109

under highly reducing, turbulent conditions inside a preco mbustion chamber. The rem aining two-thirds of the fuel is combusted in a secondary burnou t
zone at the entrance to the steam generator. The second stage is arranged so that the addition and mixing of 5 to 10 percent secondary excess air takes place in the high-velocity jet of flame emitted from the chamber throat inside the fireb ox. The vigorous internal recirculation and mixing within the fuel-

90 rich precombustion cha mber aids in NO reduction, while combustion gases x are entrained into the high-velocity f lame of the secondary combustion zone, lowering the peak flame temperature. Results of 50 separate field tests using this burner showed average NO reductions of 60 percent, with averag e x emissions of 125 ppm (0.16 lb/MMBtu) for 62.5 MMBtu/hr sized units an d 150 ppm (0.19 lb/MMBtu) for 25 to 30 MMBtu/hr units. Controlled NO levels x ranged from 90 to 225 ppm (0.11 to 0.28 lb/MMBtu). 91 A third type of LNB for TEOR steam generators utilizes a split flam e arrangement, whereby an inner fuel-rich diffusion flame is separated f rom and outer fuel-lean premix flame5-110

by a blanket of recirculated flue gas. This burner, the MHI PM low-NO burner, x illustrated schematically in Figure 5-2 65-111 Figure 5-26. The MHI PM burner nozzle. 935-112

, was retrofitted to a 62.5 MMBtu/hr cr ude-oil-fired steam generator as part of
an EPA- sponsored test program on a demonstration unit. No additiona l TEO R steamers have been retrofitted with this burner. Full-load NO x emissions of 110 ppm (0.14 lb/MMBtu) we re obtained with what were deemed "acceptable" smoke and CO emissions (<100 ppm CO). This compares t o emissions of approximately 300 ppm (0.38 lb/MMBtu) measured from a n identical generator equipped with a conventional burner. Thus, NO wa s 93 x reduced by 63 percent. Mos t LNB retrofit experiences have been with crude-oil-fired unit s larger than 35 MMBtu/h r. Results from 134 tests conducted on such units in Kern County show controlled NO levels of 87 to 232 ppm (0.11 t o x 0.29 lb/M MBtu). Because no baseline data were available, it was impossible to ca lculate NO reduction efficiencies for these tests. However, thes e x contr olled emissions may be compared to the generally accepted averag e base line of 300 ppm for Kern County crude oil firing. For illustrativ e 84,88 purposes, comparing average controlled emissions to this average baseline, 59 percent NO reduction was achieved with LNB systems. Again, however, x it must be remember ed that actual efficiencies may have varied significantly from u nit to unit. Limited test data are available for natural gas fired unit s equipped with LNB. Data for two 62.5 MMBtu/hr ga s-fired generators showed NO reductions of 8 and 28 percent. x5-113

Because of the limited data, however, no conclusions can be drawn abou t typical reduction efficiencies for LNB gas firing. LNB systems ha ve also been applied on a very limited basis to steam generators smaller than 35 MMBtu/hr. Reported NO emission reduction s x range from 30 to 60 percent for these units. The limited application of LNB 86 to small generators is due to the longer and wider flame pro duced by the LNB and the geometry of smal l 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. Thus, LN B 86 retrofit s are primarily applicable to TEOR steam generators larger tha n 35 MMBtu/hr. 5.3.8.3 FGR and OT FGR systems have been applied t o TEOR steam generators on a more limited basis than LNB systems. Results from Kern Coun ty tests of 36 crudeoil-fired steam generators with FGR and O trim showed controlled NO levels 2 x similar to those obtained with LNB systems, ranging from 79 t o 264 ppm (0.10 to 0.33 lb/MMBtu). Thus, for crude oil firing, FGR controls appear a s 87 effective as LNB systems in reducing NO . For natural gas firing, tests o f x three large units using FGR in combination with LNB measured controlle d emission levels of 25 to 35 ppm (0.03 to 0.04 lb/MMBtu). NO reduction fo r x two of these units ranged from 50 to 68 percent. For these particular units, the se reductions in NO represent significant improvement over NO x x reduct ion efficiencies obtained using LNB alone. Data are too limited , 56,88 however, to characterize the perfo rmance of FGR controls used with naturalgas-fired TEOR steam generators. 5.3.9 Gas Fuel Flow Modifiers In addition to the combust ion techniques discussed thus far, a device known as a gas turbulator has been demonstrated to reduce NO formation x5-114

in natural-gas-fired packaged boilers. Originally designed to p roduce savings in fue l consumption, the turbulator is a small stainless steel ventur i incorp orating 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 combustio n efficiency. Fuel savings typica lly range between 2 and 10 percent, but have

94 been as high as 35 percent. 95 From an NO standpoint, the more efficient turbu lent mixing of the fuel

x and air results in lower excess air requirements for efficient combustion , producing lower levels of NO

. The only turbulator-related NO emissions x x 94, 95 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 turb ulator raised full-load boiler efficiency by 3 percent, and the improved ai r/fuel mixing reduced the required excess oxygen by 27 percent

. Consequently, NO emissions were reduced from 58 to 35 ppm at 3-percent x oxygen, a 40-percent decrease. 96 5.4 COM BUSTION MODIFICATIONS FOR NONFOSSIL-FUEL-FIRED IC I BOILERS Application of combustion modification NO contro ls to nonfossil-fuel- x fired ICI boilers is very limited. Many waste-fuel-fired boilers are not easily modifie d to reduce NO without compromising combustion efficiency an d x byproduct emissions. Furthermore, nonfossil fuels inc lude a variety of waste fu els with varying combustion characteristics and pollutant profiles

. Consequently, adaptation of conventional combustion controls can b e difficult and very site- specific. Cur rently, more attention has focused on the application of flue gas treatment controls to nonfossil-fuel-fired ICI boilers , especially in California, w here flue gas treatment controls have been applied5-115

to at least 17 units fired on wood or MSW. These applications are discussed in Section 5.3. Combust ion modification retrofit experience has been limited to th e
use o f SCA. In one wood-/natural-gas-fired overfeed stoker unit, equippe d wit h four gas burners as well as a traveling grate for wood firing, stage d combustion was achieved by removing one of the four gas burners fro m service. Although 20 percent NO reduction was achieved, it should be noted x that combustion modification was applied to the gas burners without an y cha nge to the wood-firing stoker system. This control approach would no t be possible on boilers without supplemental gas firing. Difficulties wer e exper ienced with fluctuating bark flows, resulting in unsteady combustio n conditions. 74 Applic ations of combustion modifications to new nonfossil-fuel-fired
un its involve MSW-fired boilers equipped with FGR and natural gas rebur n controls. Gas reburn for MSW boilers is being develop ed by Riley Stoker and Takuma Company, for NO control purposes and to suppress the formation x of air toxic organics and combustible emissions. In a 45 MMBtu/hr overfeed 97 stoker MSW facility in Minnesota, NO emissions were reduced by 40 percent x using FGR. When natural gas reburn was used in combinat ion with FGR, NO x was reduced by 60 percent, to a controlled level below 50 ppm. CO emissions
were als o decreased by 50 percent, to levels below 25 ppm. Natural ga s reburn re presented 12 to 15 percent of the total heat input, and FGR rate s duri ng these tests were roughly 8 percent. Test results from a pilot-scal e 97 MSW-fired stoker boiler equipped with FGR and natural gas reburn showed 49 percent NO reduction efficie ncy, utilizing 17 percent FGR. Because of x 98,99 the lim ited documented experiences regarding the retrofit of combustio n modi fications to existing nonfossil-fuel-fired boilers, no meaningfu l conclusions can be reached as far as NO control effectiveness or feasibility. x5-116

5.5 FLUE GAS TREATMENT NO CONTROLS FOR ICI BOILERS x NO control with flue gas treatment involves the reduction of NO in the x x flue gas by injecting a chemical reducing agent into the post-combustio n region of a combustion unit. The reducing agents, primarily ammonia an d urea, convert the NO in the flue gas to molecular nitrogen at hig h tempe ratures, 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 lowe r temperature range, roughly 300 and 425 C (575 to 800 F). Flue gas treatment methods without a catal yst 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 reagen t injection nozzles, reagent storage and control equipment, and, in the case of SCR, catalytic reactors. Because flue gas treatment NO r eduction x effi ciency depends in large part on flue gas temperature, injection nozzl e pl acement is limited to those locations where acceptable proces s temperat ures are present. Generally, in packaged ICI boilers, availabl e locations for reagent injection and catalyst placement are further limited by spa ce considerations. These units may also operate with wide ranges i n boiler steam load that cause flue gas tempe rature shifts outside the optimum temperat ure window. Injection of reagents outside the optimum reactio n tempe rature window results in lowered NO reduction efficiency an d x emissions of unreacted ammonia. SNCR and SCR controls have been applied pri marily to larger boilers or new packaged boilers because thes e applicat ions offer better control of temperature window and steady loa d demands. 5.5.1 Selective Noncatalytic Reduction (SNCR) Two pri mary types of SNCR control technologies are currentl y available for retrofit to ICI boilers. The first is based on the use of ammonia5-117

(NH ) as the reducing agent, while the second, more recently introduced, i s 3 based on the use of urea (NH CONH ). Several urea-based systems ha ve been 2 2 patented and are commercially offered by several domestic vendors. Th e following subsections briefly describe the experience to date using thes e contro ls on ICI boilers. Available data for SNCR application to industria l boilers are contained in Appendix B and summarized in Table 5-12. Genera lly, similar NO reduction efficiencies were obtained whether ammonia or ure a

x was us ed. For ammonia injection, NO reduction ranged from 50 t o x 80 percent, de pending on fuel type. For urea-based systems, most reported NO reduction efficie ncies also fell within this range, although some were as x low as 25 percent and as high as 88 percent. Experience with SNCR o n smaller capacity boilers is minimal. Low-load operation and frequent loa d changes on such boilers pose additional complexiti es on the retrofit of SNCR for these boilers. 5.5.1.1 Ammonia-based SNCR Exxon Research and Engineering Company developed and patent ed an ammonia -based SNCR process known as Thermal DeNO ®. The Therma l x DeNO process is based on a gas phas e homogeneous reaction between NO

x x and ammo nia which produces molecular nitrogen and water at hig h temperature. In this process, aqueous or anhydrous ammonia is vaporized and injected into the flue gas through wall-mounted nozzles at a locatio n selected for optimum reaction temperature and reside nce time. The optimum reaction t emperature range for this process is 870 to 1,100 C (1,600 t o 2,000 F), although this can be lowered to 700 C (1,300 F) with additiona l injec tion of gaseous hydrogen. At temperatures above 1,100 C (2,000 F), 100 ammonia injection becomes counterproductive, resulting in additional N O form ation. Below 870 C (1,600 F), the reaction rate drops and undesire d amounts of ammonia are carried out in the flue gas. Unreacted ammonia is5-118TABLE 5-12. SNCR NOCONTROL FOR ICI BOILERSxReagentDescription oftechniqueFuel typeNumber ofindustrialboilerstested% NOxreductionControlled NOlevelsxCommentsppm @ 3% O2lb/MMBtuAmmoniaInjection ofammonia into fluegas to chemicallyreduce NOxNatural gas/oil11 FE-WTa5 PKG-WTb50-7230-6525-160N.A.c0.03-0.20N.A.Temperature window between870 and 1,100C (1,600 and2,000F). Most data are forThermal DeNO®.xCoal4 FBC4 stoker1 PCd76-8050-665730-65110-1321350.04-0.0870.15-0.180.18Wood10 stoker8 FBC50-8044-8025-16024-1400.035-0.230.035-0.20MSW13 stoker45-7948-1950.068-0.28UreaInjection of ureainto flue gas tochemically reduceNOxNatural gas/oil7 FE-WT50-6041-1040.049-0.13Most data are for NOxOUT®.Coal4 FBC4 PC9 stoker57-8830-8340-7421-106110-300105-2100.028-0.140.15-0.410.14-0.28Wood14 stoker2 PKG-WT2 FBC1 cell25-785060-705260-118178-18745-50960.084-0.170.24-0.260.063-0.0700.14MSW13 stoker41-7544-2100.062-0.30FE-WT = field-erected watertube.aPKG-WT = packaged watertube.bN.A. = Not available in reference source used.cBoiler burning coke in Japan.d5-119

common ly referred to as ammonia slip, breakthrough, or carryover. Th e 101 amount of ammonia slip also depends in part on the amount of ammoni a i n jected. Although the chemical reaction requires one mole of NH for each 3 mol e of NO, the NH /NO ratio used is usually greater than 1 to avoid a n 3 x undesired reaction which results in formation of NO. NH /NO ratios of 4 to 100 3 x 1 have been reported in fluidized bed applic ations. Ratios used are usually 102 greater than 1 due to competing reactions at the temperatures involved. The Thermal DeNO process has been applied to a number of boilers x fi ring both fossil and nonfossil fuels. In the U.S., most Thermal DeNO x applications have been on new units, many located in C alifornia. At least two retrofit applications on wood-fired industri al boilers have also been reported,
one to a 375 MMBtu/hr wood-fired stoker unit and one to a 210 MMBtu/h r boiler, also a wood-fired stoker. Both retrofits resulted in 50 percent NO 100 x redu ction, with controlled emissions of 45 and 50 ppm (0.06 an d 0.07 lb/MMBtu).5-120 Ov erall, experience with ammonia-based SNCR on both new an d existing units has shown the following results, listed in Table 5-12. NO x reducti on ranged from 50 to 80 percent for 10 wood-firing stokers an d between 44 and 80 percent for eight wood-firing FBC u nits. For 13 MSW-fired units, NO reduction ranged from 45 to 79 percent, while for four coal-fire d

x FBC units, 76 to 80 percent reductions were achieved. Several natural-gasfired furnaces experienced 30 to 72 percent NO reduction. In addition t o x these applications, it has been repo rted 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. Thus, for al l 103 applications, ammonia-based DeNO reduced NO by roughly 30 to 80 pe rcent. x x The upper range of NO reduction efficiency range is more characteristic of x boilers operating at steady load such as cogeneration FBC units. Achievable NO reductions for an individual boiler depend on the flue x gas tempe rature, the residence time at that temperature, the initial NO x concentration , the NH /NO ratio, the excess oxygen level, and the degree of 3 x ammonia/flue gas mixing. Also, stratifica tion of both temperature and NO in x the flue gas can affect the performa nce of the SNCR control. The optimum 104 placement of SNCR injectors requires a detailed mapping of the temperature profile in the convective passes of the boiler, because of the narro w temperature window. According to Exxon, the Thermal DeNO process has x no measurable effect on CO, CO , or SO emissions. 2 x 100 The feasibility of retrofitting an existi ng boiler with SNCR often hinges on the ab ility to accommodate injection nozzles at a location where flue gas temperatures and residence time are optimum for the reaction to take place. In fiel d-erected boilers, the ammonia is usually injected into either a superhea ter tube bank or between a superheater tube bank and the stea m generator tube bank, while, for a typical wood-fired stoker boiler, injectors 1035-121

a r e 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 NH recirculation. Smaller units, especially package d 3 100 watertube and firetube boilers, have limited space and access for the i njection nozzles. 5.5.1.2 Urea-based SNCR Origin ally developed by the Electric Power Research Institute (EPRI), a newer SNCR techno logy for flue gas treatment NO control utilizes urea as x a reagent rather than ammonia. One urea-based SNCR process, known by the trade name of NOxOUT®, is offered by Nalco Fuel Tech, Inc., and its licensees (Foster Wheeler, Wheelabrator Air Pollution Control, Research Cottrell, Todd Co mbustion, RJM Corporation, and several others internationally). Othe r vendors, such as Applied Utility Systems and Noell, Inc., have also developed and inst alled urea-based SNCR processes. In the NOxOUT process, a n aqueous solution containing urea and chemical enhancers is injected into the furnace or bo iler at one or more locations, depending on the boiler type and size. Th e urea reacts with NO in the flue gas to produce nitrogen, carbo n x dioxide, and water. The main advantage of urea injection over ammoni a injection is that urea is a nontoxic liquid that can be safely stored an d handled. Like am monia injection, NOxOUT is effective only within a certai n temperature range. Without the use of chemical enhancers, urea injectio n effectively reduces NO at temperatures between 900 and 1,150 C (1,650 and x 2, 100 F). Residence time at temperature of interest is important. By usin g pro prietary enhancers and adjusting concentrations, greater NO reductio n x effici ency can be achieved over a wider temperature window. If the urea i s rel eased at too high a temperature, the chemical species can actually b e oxidized to form NO . Below this temperature, urea reacts with NO to form x x5-122

undesired amounts of ammonia. Table 5-12 lists NO reduction efficiencies x 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 wit h Ther mal DeNO , actual reduction performance is highly dependent o n x temperat ure, amount of reagent used, and level of reagent/NO mixing. x 105 Most o f the commercial experience includes MSW-, wood-, and coal-fire d stokers, and gas-fired boilers and incinerators. These appl ications have been
on n ew and existing units. Successful demonstrations are documented o n oil- and coal- fired boilers in the utility industry. NO reductions of as low as x 10 percent to as high as 76 percent have been recorded for utility boilers. An
av erage NO reduction performance of 45 percent is estimated for PC-fire d

x boilers. Due to residence time and temperature constraints, smal l

106 package d watertube and firetube boilers with fluctuating steam loads ar e difficult applications, and require case-by-case determinations for cost and performance levels. 5.5.2 Selective Catalytic Reduction (SCR) The SCR p rocess takes advantage of the selectivity of ammonia t o reduce NO to nitrogen and water at lower temperature in the presence of a

x catalytic surface. Two catalyst formulations are denoted "base metal," this category including oxides of titanium, molybdenum, t ungsten, and vanadium, and z eolites, which are alumina-silicate-based. These formulations ma y include other components that impart structural stability. Catalysts come in various shapes and sizes, according to the particular application. Gaseous ammonia is injected with a carrier gas, typically steam or compressed a ir, into th e flue gas upstream of the catalyst. The ammonia/flue gas mixture enters the catalyst, where it is distributed through the catalytic bed. The flue ga s then leaves the catalytic reactor and continues to the exit stack or ai r preheater. SCR technology is capable of achie ving similar NO reductions as x5-123

Thermal D eNO SNCR using a much smaller amount of ammonia, due to the x positive effects of the lower reaction temperature and the sel ective catalyst. 101 Because of this, ammonia slip tends to be less with SCR than with SNCR. SCR operates most efficiently at tempe ratures 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. Recent 101,107 catalys t formulations can resist poisoning and abrasion in flue ga s environments with high a sh loading and trace metals, while maintaining NO x reduction performance. Typically, the catalytic reactor is locate d ahead of the air heater, to take advantage of the temperature regime. Sometimes, howe ver, the reactor may be placed just ahead of the stack and downstream o f par ticulate collection devices, avoiding catalyst contamination. In mos t
ca ses, however, such placement requires reheating of the flue gas to mee t temperature requirements, impacting the cost of t he system. To avoid reheat requirements, some m anufacturers are currently developing or have already deve loped special low-temperature catalysts which can be used a t temperatures as low as 200 C (400 F). 1075-124 Boiler ID Boiler type Capacity, MMBtu/hr Fuel used Controlled NO emissions x ppm @ 3% O 2 lb/MMBtu Darling-Delaware PKG-WT a 110 Natural gas/ propane 9 0.011
Fletcher Oil and Refining Unknown 49 Distillate oil 20 0.025 Lockheed PKG-WT N.A. b Natural gas/ distillate oil 9 0.011
Kalkan Foods, Inc. PKG-WT 78.6 Natural gas/ methanol 9 0.011
Ultramar Refinery PKG-WT N.A. Refinery gas 11 0.011 Southern California Edison Unknown 107 MWe Natural gas 20 0.024 PKG-WT = Packaged watertube boiler. a N.A. = Not available. b TABLE 5-13. SELECTED SCR INSTALLATIONS, CALIFORNIA ICI BOILERS

SCR ha s seen very limited application on domestic ICI boilers

. T a ble 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 i ndustrial applications of this control technology have been in Japan, where much of the original SCR techn ology development took place. Within the industrial sector, SCR has been applied primarily t o 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-fire d bo ilers. However, it was recently announced that SCR will be incorporate d into the design of a 220 MWe stoker coal-fire d power plant in Virginia, as well5-125 Description of technique Fuel type Number of industrial boilers tested % NO x

reduction Controlled levels

Comments

ppm @ 3% O 2 lb/MMBtu Injection of ammonia into flue gas to chemically reduce NO x Oil 7 85-90 17-25 0.022- 0.032 Temperature window

between 300 and 425 C (575 and 800 F). Natural Gas 3 53-80 9-46 0.011- 0.055 Coal 2 53-63 72-110 0.097-0.15 Ref. gas 4 83-94 9-11 0.011- 0.013 MSW 1 53 36 0.051 Wood waste 2 80 154 0.22 TABLE 5-14. SCR NO CONTROLS FOR ICI BOILERS x as a 125 MWe CFBC in Sweden. Major suppliers of SCR cat alysts include 108,109 MHI, Babcock Hitachi, Corm etech, Engelhard, Johnson Matthey, and Norton. Ta ble 5-14 summarizes performance data for SCR applications t o boilers in the ICI sector. Data from Japanese oil-fired industrial boiler s retrofitte d with SCR show NO reductions ranging from 85 to 90 percent

. x Thes e units had controlled NO levels between 17 and 25 ppm (0.02 an d x 0.03 lb/MMBtu), operating with flue gas treatment temperatures of 300 t o 370 C (5755-126

to 700 F). Specific information was not available on the types of oil fire d

109 in these boilers or on boiler operating conditions; therefore, these reported NO levels should not be used to extrapolate controlled NO levels for all oil- x x fired boilers. Simila r reduction efficiencies of 83 and 94 percent were obtained o n units firing refinery gas. One of these units was located in Japan, th e 110 others at a California refinery. Results from tests conducted on three naturalgas- and two coal-fired boilers with SCR showed more moderate reductio n efficiencies of 53 to 80 percent. Likewise, a single MSW-fired uni t exper ienced 53 percent NO reduction with SCR. In summary, NO x x 101 reduction e fficiencies with SCR have been reported in the range between 53 and 90 percent. Available data are too limited, however, to allow an y correlations between fuel type, boiler type, and SCR effectiveness to b e made. The retrofit of SCR to an existing boiler requires far more extensiv e modi fications than does SNCR, as the SCR reactor must be placed in th e existing flue gas path where the temperature is sufficiently high for efficient NO control. This is in addition to the required installation of reagen t x injectors and storage and control equipment. The difficulty in retrofit ting SCR to existing boilers was reflected in the compliance plans put forth b y petroleum refiners in California's South Coast Air Basin, in response to the SCAQMD Rule 1109. Rather than retrofit existing boilers with SCR, man y refiners instead opted to replace their old boilers with new units alread y incorpo rating SCR. Because catalysts lose their effectiveness over tim e 111 du e to contamination or clogging of catalyst pores, they must be replace d periodically. On large boilers, it has been reported that catalyst replacement may b e necessary every 1 to 5 years, depending on the application and th e level of contaminants in the fuel. 112 5.6 SUMMARY OF NO REDUCTION PERFORMANCE x5-127

Boiler and fuel NO control x Range in performance Average performance a

Reduction efficiency, % Controlled

NO , x lb/MMBtu Reduction

efficiency, % Controlled NO , x lb/MMBtu PC-fired boilers: all firing types with wall or corner burners SCA 15-39 0.33-0.93 27 0.62 LNB 18-67 0.26-0.50 55 0.35 Reburn+OFA 30-65 0.23-0.52 52 0.34 LNB+SCA 42-66 0.24-0.49 60 0.38 SNCR 30-83 0.15-0.40 45 b 0.39 Coal-fired stokers SCA -1-35 0.22-0.52 18 0.38 FGR+SCA 0-60 0.19-0.47 24 0.54 SNCR 40-74 0.14-0.28 58 0.22 Coal-fired FBC SCA 40-67 0.05-0.45 58 0.18 FGR+SCA N.A. c 0.12-0.16 N.A. 0.14 SNCR 57-88 0.03-0.14 74 0.08 SCR 53-63 0.10-0.15 60 0.12 Gas-fired firetube LNB 32-78 0.02-0.08 50 0.03

Radiant LNB 53-82 0.011-0.036 71 0.02 FGR 55-76 0.02-0.08 65 0.07 LNB+FGR N.A. 0.02-0.04 N.A. 0.03 Gas-fired SBWT d,e WI 50-77 0.04-0.056 64 0.05 FGR 53-74 0.02-0.08 64 0.05 LNB 46-71 0.03-0.11 58 0.08 LNB+FGR 55-84 0.018-0.09 76 0.06 SCR 80-91 0.011-0.06 85 0.024 (continued) Arithmetic averages of reported control efficiency NO levels with specified controls. Values a x do not necessarily reflect emission targets that can be achieved in all cases. Average NO reduction is based on utility boiler PC experience. b x N.A. = Not available. c SBWT = Single-burner watertube. Also referred to as packaged watertube (PKG-WT). d Data for gas- and oil-fired watertube boilers are limited to performance reported in e Appendix B, exclusive of equipment vendor data reported in Appendix C. TABLE 5-15. SUMMARY OF NO REDUCTION PERFORMANCE x TABLE 5-15. (continued)

Boiler and fuel NO control x Range in performance Average performance a

Reduction efficiency, % Controlled

NO , x lb/MMBtu Reduction

efficiency, % Controlled NO , x lb/MMBtu Gas-fired MBWT e,f SCA (BOOS) 17-46 0.06-0.24 31 0.15 LNB g 39-52 0.10-0.17 46 0.12 SNCR 50-72 0.03-0.19 58 0.10 SCR h N.A. c 0.024 N.A. 0.024 LNB+SCA N.A. 0.10-0.20 N.A. 0.15 Distillate firetube LNB h 15 0.15 15 0.15 FGR N.A. 0.04-0.16 N.A. 0.12 Distillate SBWT d,e LNB N.A. 0.08-0.33 N.A. 0.10 FGR 20-68 0.04-0.15 44 0.08 LNB+FGR N.A. 0.03-0.13 N.A. 0.07 SCR h N.A. 0.011 N.A. 0.011 Residual oil firetube LNB i 30-60 0.09-0.25 40 0.17

Residual oil SBWT d,e LNB 30-60 0.09-0.23 40 0.19 FGR 4-30 0.12-0.25 15 0.17 LNB+FGR h N.A. 0.23 N.A. 0.23 Residual oil MBWT e,f SCA 5-40 0.22-0.74 20 0.34 LNB j 30-60 0.09-0.23 40 0.19 LNB+SCA h N.A. 0.22 N.A. 0.22 SCR i 58-90 0.025-0.15 85 0.045 Wood-fired stoker SNCR 25-80 0.04-0.23 58 0.13 Wood-fired FBC SNCR 44-80 0.035-0.20 64 0.09 MSW-fired stoker SNCR 41-79 0.06-0.31 60 0.18 Arithmetic averages of reported control efficiency NO levels with specified controls. Values do not a x necessarily reflect emission targets that can be achieved in all cases. N.A. = Not available. c SBWT = Single-burner watertube. Also referred to as packaged watertube (PKG-WT). d Data for gas- and oil-fired watertube boilers are limited to performance reported in Appendix B, exclusive e of equipment vendor data reported in Appendix C. MBWT = Multi-burner watertube. Also referred to as field-erected watertube (FE-WT). f Most LNB applications include FGR. g Only one data point available. h Experience relies primarily on Japanese industrial installations. i No data available. NO levels assumed to be on the same order as those reported for single-burner j x packaged watertubes. Table 5-15 summarizes the reduction efficiencies and controlled NO x5-128

lev els for each boiler, fuel, and control combination investigated in thi s report. Arithmetic average performances are listed, but care must be used in interpreting them. Because these are averages, th e data do not represent the NO con trol performance attainable in all cases. Actual performance will be x influen ced by several factors, including fuel type, degree of control applied,
an d the boiler's design and operating condition. Because coal and residual oil can vary in nitrogen content and other properties, the actual NO leve l x ach ieved with these fuels will be very much a function of these fue l properties. Certainly, the degree of FGR and air staging applied,5-1295-130

or the amount of ammonia or urea reagent used, will influence the percen t reduction efficiency and the NO level achieved. x NO from pulverized coal combustion in industrial boilers with LN B x co ntrols was shown to be controlled to levels ranging from 0.26 to 0.5 0 lb/ MMBtu. These data include results for both tangential- and wall-fire d boilers. The average, 0.35 lb/MMBtu, is lower than reported average control levels for utility bo ilers. Therefore, this average efficiency should be used 113
ca utiously, considering the limited data available to this study. Other dat a show SNCR to be quite effective in reducing NO from coal- and waste-fuel- x fi red FBC and stoker boilers. Average levels for these sources controlle d with either ammonia or urea range from 0.08 to 0.22 lb/MMBtu. For gas- and distillat e-oil-fired ICI boilers, FGR and LNB controls operating alone or i n combinati on can attain NO levels averaging 0.02 to 0.15 lb/MMBtu. Data on x residual oil are somewhat m ore sparse. NO control levels from residual-oil- x fir ed boilers are largely influenced by the nitrogen content of the fuel

. Combustion controls for these boilers show average controlled level s ranging from 0.17 to 0.34 lb/MMBtu.5-131

5.7 REFERENCES FOR CHAPTER 5
1. Nutche r, P. B. High Technology Low NO Burner Systems for Fire d x Heat ers and Steam Generators. Process Combustion Corp

. Pitts burgh, PA. Presented at the Pacific Coast Oil Show an d Conference. Los Angeles, CA. November 1982. p. 4.
2. Cato, G. A., et al. (KVB, Inc). Field Testing: Application of Combustion Modif ications to Control Pollutant Emissions from Industria l Bo ilers—Phase I. Publication No. EPA-600/2-74-078a. U.S

. Enviro nmental Protection Agency. Research Triangle Park, NC

. October 1974. p. 86.
3. Castaldi ni, C. Evaluation and Costing of NO Controls for Existin g x Utility Boilers in the NESCAUM Region. Publication No. EP A 453/R- 92-010. U.S. Environmental Protection Agency. Researc h Triangle Park, NC. December 1992. p. 4-2.
4. Cato, G. A., et al. (KVB Inc). Field Testing : Application of Combustion Modif ications to Control Pollutant Emissions from Industria l Boilers—Phase II. Publication No. EPA-600/2-72-086a. U.S

. Environmental Protection A gency. Research Triangle Park, NC. April 1976. p. 162.
5. Heap, M. P., et al. Reduction of Nitrogen Oxide Emissions fro m Package Boilers. Publicat ion No. EPA-600/2-77-025, NTIS-PB 269 277. January 1977.
6. Hopkins, K. C., et al. (Carnot). NO Reduction on Natural Gas-Fire d x Bo ilers Using Fuel Injection Recirculation (FIR) — Laborator y Demons tration. Presented at the International Power Generatio n Conference. San Diego, CA. October 1991. p. 2.
7. Low-NO Burner Design Achieves Near SCR Levels. Publication No

. x PS-4446. John Zink Company April 1993. p. 2.
8. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Modification NO Controls—Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. pp. 2-12 to 2-14.5-132

9. Vatsk y, J., and E. S. Schindler (Foster Wheeler Corp.). Industrial and Utility Boiler NO Control. Proceedings: 1985 Symposium o n x Stationary Combustion NO Control. Publication No. EPRI CS-4360

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. January 1986.
10. Va tsky, J. (Foster Wheeler Energy Corporation). NO Control: Th e x Foste r Wheeler Approach. Proceedings: 1989 Symposium o n Stati onary Combustion NO Control. Publication No. EPRI GS-6423

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. July 1989.
11. Lisauskas, R. A., et al. (Riley Stoker Corp.). Engineering and E conomic An alysis of Retrofit Low-NO Combustion Systems. Proceedings : x 1987 Symposium on Statio nary Combustion NO Control. Publication x No. EP RI CS-5361. U.S. Environmental Protection Agency/Electri c Power Research Institute. Palo Alto, CA. August 1987.
12. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Modification NO Controls—Volume I, Environmental Assessment

. x Public ation No. EPA-600/ 7-81-126a. Prepared for the U.S

. Environmen tal Protection Agency. Research Triangle Park, NC. July 1981. pp. 3-18 and 3-19.
13. Vatsk y, J., and E. S. Schindler (Foster Wheeler Energy Corporation)

. Industr ial and Utility Boiler Low NO Control Update. Proceedings : x 1987 Symposium on Statio nary Combustion NO Control. Publication x No. EP RI CS-5361. U.S. Environmental Protection Agency/Electri c Power Research Institute. Palo Alto, CA. August 1987.
14. LaRue, A. (Babcock & Wilcox). The XCL Burner—Latest Dev elopments an d Operating Experience. Proceedings: 1989 Symposium o n Stati onary Combustion NO Control. Publication No. EPRI GS-6423

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. July 1989.
15. Schild, V., et al. (Black Hills Power a nd Light Co.). Western Coal-Fired Boile r Retrofit for Emissions Control and Efficiency Improvement

. Tech nical Paper No. 91-JPGC-FACT-7. American Society o f Mechanical Engineers. New York, NY. 1991.5-133

16. Penterson, C. A., and R. A. Lisauskas ( Riley Stoker Corp.) Application and Further Enh ancement of the Low-NO CCV Burner. Proceedings: x 1993 Symposium on Stationary Combustion NO Control. U.S

. x Environmental Protection Agency/Electric Power Research Institute

. May 1993.
17. Penterson , C. A. (Riley Stoker Corp.) Controlling NO Emissions t o x M e et the 1990 Clean Air Act. Technical Paper No. 91-JPGC-FACT-11. American Society of Mechanical Engineers. New York, NY. 1991.
18. Buchs, R. A., et al. (K err-McGee Chemical Corporation). Results From a Co mmercial Installation of Low NO Concentric Firing Syste m x (LNCFS). ABB Combustion Engineering Services, Inc. Windsor, CT. 1991.
19. Araoka, M., et al. (Mitsubishi Heavy Industries, Inc.). Application o f Mitsubishi "Advanced MACT" In-Furnace NO Removal Pro cess at Taio x Paper Co., Ltd. Mishima Mill No. 118 Boiler. Proceedings: 198 7 Symposium on Stationary Combustion NO Control. Publication No. x EPRI CS-536 1. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. August 1987.
20. EE RC. Gas Reburning Technology Review. Prepared for the Ga s Research Institute. Chicago, IL. July 1991.
21. Farzan, H., et al. (Babcock & Wilcox Company). Pilot Evaluation o f Reburni ng for Cyclone Boiler NO Control. Proceedings: 198 9 x Symposium on Stationary Combustion NO Control. Publication No. x EPRI GS-6423. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
22. Folsom, B., et al. (Energy and Environmental Research Corporation). Field Evaluation of the Distr ibuted Mixing Burner. Proceedings: 1985 Symposium on Stationary Combustion NO Control. Publication No. x EPRI CS-436 0. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
23. Vatsky, J., and T. W. Sweeney. Development of an Ultra-Low NO x Pulverized Coal Burner. Foster Whee ler Energy Corporation. Clinton, NJ. Presented at the 1991 Joint Symposium on Stationary Co mbustion NO Control—EPA/EPRI. Washington, D.C. March 25-28, 1991. x5-134

24. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Modification NO Controls—Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. pp. 3-26.
25. Ibid. p. 3-30.
26. Quartucy, G. C., et al. (KVB, Inc). Combustion Modification Techn iques for C oal-Fired Stoker Boilers. Proceedings: 1985 Symposium o n Stationary Combustion NO Control. Publication No. EPRI CS-4360

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. January 1986.
27. Malone y, K. L. (KVB, Inc.). Combustion Modifications for Coal-Fire d Stoker Boilers. Proceedings of the 1982 Joint Symposium o n Stationary Combustion NO Control. Publication No. EPRI CS-3182

. x U.S. Environmental Protection Agency/ Electric Power Researc h Institute. Palo Alto, CA. July 1983.
28. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Mo dification NO Controls — Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. p. 3-31.
29. Energy Systems Associates. Characterization of Gas Cofiring in a St oker-Fired Boiler. Publication No. GRI-93/0385. Gas Researc h Institute. Chicago, IL. November 1993. p. 6.
30. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Power Plants. Acurex Report No. 90-102/ESD. Acure x Corporation. Prepared for the Electric Power Research Institute. Palo Alto, CA. July 1990. p. 3-1.
31. Martin, A. E. Emission Control Technology for Industrial Boilers

. Noyes Data Corporation. Park Ridge, New Jersey. 1981. p. 3-39.
32. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Power Plants. Acurex Report No. 90-102/ESD. Acure x Corporation. Prepared for the Electric Power Research Institute. Palo Alto, CA. July 1990. pp. 3-6 to 3-10.5-135

33. Hiltunen , M., and J. T. Tang. NO Abatement in Ahlstrom Pyroflo w x Circulating Fluidized Bed Boilers. Ahlstrom Pyropower Corp. Finland.
34. Leckne r, B., and L. E. Anand (Chalmers University, Sweden)

. Emissions from a Circulating and Stationary Fluidized Bed Boiler: A Co mparison. Proceedings of the 1987 International Conference o n Flui dized Bed Combustion. The American Society of Mechanica l Engineers/Electric Power Research Institute/Tennessee Valle y Authority. New York, NY. 1987.
35. Bijvoet, U. H. C., et al. (TNO Organization for Applied Scientifi c Research ). The Characterization of Coal and Staged Combustion i n th e TNO 4-MWth AFBB Research Facility. Proceedings of the 198 9 International Conference on Fluidized Bed Combusti on. The American Soc iety of Mechanical Engineers/Electric Power Researc h Institute/Tennessee Valley Authority. New York, NY. 1989.
36. Salam, T. F ., et al. (University of Leeds, U.K.). Reduction of NO b y x Staged Combustion Combined with Ammonia Injection in a Fluidised Be d Combustor: Influence of Fluidising Velocity and Excess Ai r Levels. Proceedings of the 1989 International Co nference on Fluidized Bed Combustion. The American Society of Mechanica l Engineers/Electric Power Research Institute/Tennessee Valle y Authority. New York, NY. 1989.
37. Tetebayashi, T., et al. Simulta neous NO and SO Emission Reduction x 2 with Fluidized-Bed Combustion. Presented at the 6th Internationa l Conference on Fluidized Bed Combustion. Atlanta, GA. 1980.
38. Katayama, H., et al. Correlation Between Be nch-Scale Test FBC Boiler and Pilot Pl ant FBC Boiler Combustion Characteristics. Presented at the 7 th International Conference on Fluidized Bed Combustion. Sa n Francisco, CA. 1989.
39. Linneman , R. C. (B. F. Goodrich Chemical). B. F. Goodrich's FB C experience. Proceedings: 1988 Seminar on Fluidized Bed Combustion Technology for Utility Opns. Publication No. EPRI GS-6118. Electric Power Research Institute. Palo Alto, CA. February 1989.
40. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Power Plants. Acurex Report No. 90-102/ESD. Acure x5-136 Corporation. Prepared for the Electric Power Research Institute. Palo Alto, CA. July 1990. pp. 3-11 to 3-15.
41. Hasegawa, T., et al. (Mitsubishi H eavy Industries, Ltd.). Application of AFBC to Very Low NO Coal Fired Industrial Boiler. Procee dings of the x 19 89 International Conference on Fluidized Bed Combustion. Th e American Society of Mechanical Engineers/Electric Power Researc h Institute/Tennessee Valley Authority. New York, NY. 1989.
42. Zhao, J. et al. (University of British Columbia). NO Emissions in a x Pilot Scale Circulating Fluidized Bed Combustor. Public ation No. EPRI GS- 6423. 1989 Symposium on Stationary Combustion NO Control

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. July 1989.
43. Friedman, M. A., et al. Test Program Status at Col orado — Ute Electric Ass ociation 110 MWe Circulating FBC Boilers. Proceedings of th e 19 89 International Conference on Fluidized Bed Combustion. Th e American Society of Mechanical Engineers/Electric Power Researc h Institute/Tennessee Valley Authority. New York, NY. 1989.
44. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Power Plants. Acurex Report No. 90-102/ESD. Acure x Corporation. Prepared for the Electric Power Research Institute. Palo Alto, CA. July 1990. pp. 3-17 and 3-18.
45. Johnsson, J. E. A Kinetic Model for NO Formation in Fluidized Be d x Co mbustion. Proceedings of the 1989 International Conference o n Flui dized Bed Combustion. The American Society of Mechanica l Engineers/Electric Power Research Institute/Tennessee Valle y Authority. New York, NY. 1989.
46. State of the Art Analysis of NO /N O Control for Fluidized Be d x 2 Combustion Power Plants. Acurex Report No. 90-102/ESD. Acure x Corporation. Prepared for the Electric Power Research Institute. Palo Alto, CA. July 1990. p. 3-19.
47. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Mo dification NO Controls — Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. pp. 2-38.5-137

48. Co lannino, J. Low-Cost Techniques Reduce Boiler NO . Chemica l x Engineering. February 1993. p. 100.
49. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 48.
50. Ibid. p. 51.
51. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 53.
52. Waibel, R., et al. (John Zink Co.). Fuel Staging Burners for NO x Control. ASM International. Metals Park, OH. April 1986.
53. Souther n California Edison. NO Emission Control for Boilers an d x Proc ess Heaters—A Training Manual. Southern California Edison

. Rosemead, CA. April 1991.
54. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987, p. 61.
55. Oppenber g, R. Primary Measures Reducing NO Levels in Oil- an d x Gas- Fired Water Tube Boilers. Report No. 176. Deutsche-Babcock

. Germany. September 1986.
56. Londerv ille, S. B., and J. H. White (Coen Company). Coen Compan y Ov erview and Burner Design developments for NO Control

. x Proceedings: Third Annual NO Control Conference. Council o f x Industrial Boiler Owners. Burke, VA. February 1990.5-138

57. Personal communication with Brizzolara, L., A. H. Merri ll & Associates, Inc. Coen Company Low NO Installation List. June 22, 1992. x 58. Tampe lla Power. Faber Burner-LNB Projects List. Tampella Powe r Corporation. Williamsport, PA. 1992.
59. Lisauskas, R. A., and Green, R. W. Recent Low-NO Gas and Oi l x Burner Applications. Proceedings: 1993 Joint Symposium o n St ationary Combustion NO Control. U.S. Environmental Protectio n x Agency/Electric Power Research Institute. May 1993.
60. Nationwide Boiler, Inc. Faber Low NO Burner Summary. Nationwide x Boiler Inc. Tustin, CA. 1989.
61. Micro -NO Low NO Burners. Publication No. Micro-NO /11-89. Coen x x x Co., Inc. Stockton, CA. November 1989.
62. Suzuki, T., et al. (Kobe Steel). Development of Low-NO Combustion x for Industrial Application. Proceedings: 1985 Symposium o n Stationary Combustion NO Control. Publication No. EPRI CS-4360

. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. January 1986.
63. Alzeta Corp. Commercial Status of the Radiant Pyrocore Burner i n Process Heaters and Boilers. Alzeta Corp. Santa Clara, CA. Ma y 1988.
64. Gas Res earch Institute. Field Test Update: Ceramic Fiber Burner for Firetube Boilers. Gas Research Institute. Chicago, IL. August 1987.
65. Letter a nd attachments from Moreno, F. E., Alzeta Corporation, t o Castaldini, C., Acurex Environmental Corporation. July 26, 1993.
66. Chojnack i, D., et al. (Donlee Technologies, Inc.). Developments i n Ultra-Low NO Burner/Boilers. Proceedings of the 1992 International x Gas Research Conference. 1992. p. 352.
67. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 63.5-139

68. Ibid. p. 65.
69. Low-NO Burner Design Achieves Near SCR Levels. Publication No

. x PS-4446. John Zink Company. April 1993. P. 4.
70. Ibid. p. 5.
71. Ln/ Series-Low NO Flue Gas Recirculation. Brochure 34. Industria l x Combustion. Monroe, WI. October 1989.
72. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Mo dification NO Controls — Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n 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 t o Industrial Combustion Equipment. KVB, Inc. Irvine, CA. 1977.
75. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Modification NO Controls—Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. p. 7-39.
76. Castaldi ni, C. Evaluation and Costing of NO Controls for Existin g x Utility Boilers in the NESCAUM Region. Publication No. EP A 453/R- 92-010. U.S. Environmental Protection Agency. Researc h Triangle Park, NC. December 1992. p. 4-26.
77. Lim, K. J., et al. (Acurex Corp.) Industrial Boiler Combustio n Mo dification NO Controls — Volume I, Environmental Assessment

. x Publication No. EPA-600/ 7-81-126a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. July 1981. p. 3-43.
78. Environme ntal Assessment of Utility Boiler Combustion Modification NO Controls. Publication No. EPA-600/7-80-075a and b. U.S

. x Environmental Protection A gency. Research Triangle Park, NC. April 1980.
79. Castaldi ni, C. Evaluation and Costing of NO Controls for Existin g x Utility Boilers in the NESCAUM Region. Publication No. EP A5-140

453/R- 92-010. U.S. Environmental Protection Agency. Researc h Triangle Park, NC. December 1992. p. 4-27.
80. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 75.
81. Let ter and attachments from DeHaan, T., Coen Co., Inc, to Seu, S. , Acure x Environmental Corporation. Low NO Retrofits. February 6 , x 1992.
82. Folsom, B. A., et al. Preliminary Guidelines for Gas Cofiring in CoalDesigned Boilers. Gas Research Institute Report prepared under GRI Contract No. 5091-254-2368. September 1992. p. 3-9.
83. Letter and attachments fr om Chant, P., the FReMCo Corporation, Inc., to Neuffer, B. J., U.S. Environmental Protection Agency. October 13, 1993.
84. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 45.
85. Nutcher, P., and H. Shelton. NO Reduction Technologies for the Oi l x Patch. Process Combustion Corporation. Presented at the Pacifi c Coast Oil Show and Conference. Bakersfield, CA. November 1985.
86. Collins, J. (Radian Corp.). Technology Study of NO Controls fo r x "Small " Oil Field Steam Generators. Document No. 87-243-101-02

. Prepar ed for Western Oil and Gas Association. Bakersfield, CA

. January 1987.
87. Ke rn County Air Pollution Control District. 1986 Pollutant Surve y (TEOR steam generators). November 1986.5-141

88. Nu tcher, P. High Temperature Low NO Burner Systems for Fire d x Heaters and Steam Generator . Process Combustion Corp. Presented at th e Pacific Coast Oil Show and Conference. Los Angeles, CA

. November 1982.
89. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. pp. 53-56.
90. Let ter and attachments from Nutcher, P. B., Process Combustio n Cor poration, to Votlucka, P., South Coast Air Quality Managemen t District. Descript ion of a Single Toroidal Combustor Low-NO Burner x used in TEOR Steam Generators. July 1987.
91. Nutche r, P. B. High Technology Low NO Burner Systems for Fire d x Heat ers and Steam Generators. Process Combustion Corp

. Pitts burgh, PA. Presented at the Pacific Coast Oil Show an d Conference. Los Angeles, CA. November 1982. p. 14.
92. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 55.
93. Cast aldini, C., et al. Environmental Assessment of an Enhanced Oi l Recovery Steam Generator Equipped with a Low NO Burner. Acurex x Report No. TR-84-161/EE. Acurex Corporation. Prepared for the U.S. Enviro nmental Protection Agency. Research Triangle Park, NC

. January 1985.
94. Sw ientek, R. J. Turbulence Device Cuts Gas Consumption. Foo d Processing Magazine. May 1992. p. 201.
95. Su mmary of Meeting Between Neuffer, W., U.S. Environmenta l Pr otection Agency, and Rosborne, J., Utilicon Associates, Inc

. GASPROFLO Fuel Turbulator Information. April 1993. TM5-142

96. Flow Mod ifier Ups Efficiency in Gas-Fired Boilers. Power Magazine

. January 1992. p. 101.
97. Ab basi, H., and F. J. Zone. Emission Reduction from MS W Combustion Systems Using Natural Gas. Gas Research Institut e Report No. 92/0370. Institute of Gas Technology and Riley Stoke r Corporation. Chicago, IL. December 1992.
98. Penters on, C.A., et al. (Riley Stoker Corporation). Reduction of NO x Em issions From MSW Combustion Using Gas Reburning

. Proce edings: 1989 Symposium on Stationary Combustion NO x Control. Publication No. EPRI GS-6423. U.S. Environmental Pro tection Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
99. Li sauskas, R. A., et al. (Riley Stoker Corporation). Status of NO x Control Technology at Riley Stoker. Proceedings: 1989 Symposium on Stationary Combustion NO Control. Publication No. EP RI GS-6423. x U.S

. Environmental Protection Agency/Electric Power Researc h Institute. Palo Alto, CA. July 1989.
100. Haas, G. Selective Non -Catalytic Reduction (SNCR): Experience with the Exxon Thermal DeNO P rocess. Exxon Research and Engineering x Co. P resented at the Fifth NO Control Conference Council o f x Industrial Boiler Owners. Long Beach, CA. February 1992.
101. Clarke, M. (Environmental Research and Edu cation). Technologies for Minimiz ing the Emission of NO from MSW Incineration. Technica l x Paper No. 89-167.4. Air and Waste Management Association

. Pittsburgh, PA. June 1989.
102. Hurst, B. E., et al. E xxon Thermal DeNO Effectiveness Demonstrated x in a Wood-Fired Boiler. Exxon Research and Engineering Company

. Florham P ark, NJ. Presented at the 13th National Waste Processin g Conference and Exhibit. May 1-4, 1988.
103. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 70.5-143

104. Mason , H. NO Control by Non-Catalytic Reduction. Acurex Corp

. x Presented at the Second NO Control Conference, Co uncil of Industrial x Boiler Owners. City of Industry, CA. February 1989.
105. Epperly, W. R., et al. Control of Nitrogen Oxides Emissions fro m Stationary Sourc es. Fuel Tech, Inc. Presented at the Annual Meeting of the American Power Conference. Illinois. April 1988.
106. Alternative Control Techniques Documen t--NO Emissions from Utility x Boil ers. Publication No. EPA-453/R-94-023. U.S. Environmenta l Protection Agency. Office of Air Quality Planning and Standards

. Research Triangle Park, NC. March 1994.
107. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 72.
108. Cogen trix Eyes SCR for 220-MW Coal Plant; To Seek Permits Befor e Power Sales Deal. Utility Environment Report. January 24, 1992.
109. Sweden Gets SCR f or CFBs. Coal and Synfuels Technology. Volume 13, No. 12. March 23, 1992.
110. Let ter and attachments from confidential company to Votlucka, P. , So uth Coast Air Quality Management District. Industrial SC R Experience. October 1988.
111. Statewide Te chnical Review Group. Technical Support Document for Suggested Control Measu re for the Control of Emissions of Oxides of Nitrogen from Industrial, Institu tional, and Commercial Boilers, Steam Generators, and Process Heaters. California Air Resources Board and the Sou th Coast Air Quality Management District. Sacramento, CA

. April 29, 1987. p. 73.
112. Makansi, J. Reducing NO Emission. Power Magazine. Septembe r x 1988.
113. Castaldi ni, C. Evaluation and Costing of NO Controls for Existin g x Utility Boilers in the NESCAUM Region. Publication No. EPA 453/R-92-5-144

010. U.S. Environm ental Protection Agency. Research Triangle Park, NC. December 1992. pp. 1-12, 13.6-1 ROLS

6. COSTS OF RETROFIT NO CONT x

This cha pter evaluates the economic impacts of controlling NO from existing ICI boilers

. x Costing me thodologies and assumptions are discussed in Section 6.1. Section 6.2 presents the cost s calculated for various NO controls retrofitted t o ICI boilers. Section 6.3 discussed the capital and total x annual costs of NO controls. Section 6.4 presents the cost effectiveness of NO controls. Supporting x x documentation, includin g costing spreadsheets, are included as appendices. Appendix D contains cost effectivenes s data for the boilers and control systems analyzed, scaled from annual cost data o f Appe ndices E, F, and G. The latter appendices contain detailed cost analysis spreadsheets developed from actual data provided by vendors, boiler owners, and regulatory agencies. When ever possible, cost data from actual retrofit projects were used to develop the cos t effectivene ss figures presented in Section 6.4. When key cost figures from actual projects wer e 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 OAQP S Control Cost Manual, although certain cost co mponents have been modified specifically for this study, 1 based on conventional costing practice and actual cost data. Costs of retrofit NO controls for IC I x boilers can be divided into two major cost categories — capital investment costs and annual operations and maintenance (O&M) costs. Capital cost s are the total investment necessary to purchase, construct, and make operational a control s ystem. O&M costs are the total annual costs necessary to operate and maintain th e control system, above what was required to operate the pre-retrofit boiler without NO x co ntrol. Each of these cost categories can be further subdivided into individual cost components

. Sectio n 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 eva luating a control technology's overall cost effectiveness based on these capital and O&M costs.6-2

6.1.1 Capital Costs of Retrofit NO Controls x Capital costs of NO controls inclu de both direct and indirect cost components. Direct capital x costs are expenses required to purchase equipment for the control system, referred to as purchase d 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 th e overall control syste m, but not attributable to a specific equipment item. These costs are also referred
to as indire ct installation costs. In addition to direct and indirect components of capital investmen t

cos ts, contingency costs are also added to account for unpredictable expenses. Figure 6- 16-3 Figure 6-1. Elements of total capital investment cost. 16-4

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 prese nted 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 eq uipment costs include the costs of primary control equipment, such as low-NO x burners, FGR 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 als o included in the purchased equipment cost. For this study, in strumentation, tax, and freight charges were estimated as being 18 percent of the total primary and auxiliary equipment costs. 1 6.1.1.2 Direct Installation Costs The second major component of direct capital costs, direct installation costs include both labor and mat erials costs for foundations, supporting structures, piping, insulation, painting, handling an d 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 t o accommodate the control system, and existing facilities. Although direct installation costs may vary wid ely, 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 figure s were doubled to account for additional retrofit6-5

expenses. Costs of research and development and the cost of lost production during installation and

1,6 startup were not included in direct installation cost. 6.1.1.3 Indirect Installation Costs Indirect installation costs consist of engineering costs, construction and field expenses , construction fees, and expenses associated with startup, perfor mance tests, and permitting. When actual cost data were unavailable, these costs we re estimated to be approximately 33 percent of the purchased equipment cost. For SCR retrofits, indirect installation was estimated as 66 percent of purchase d 1 equipment cost to account for additional engineering and construction requirements. 6.1.1.4 Contingencies Contingency costs were added to cap ital cost estimates to account for additional expenses due to such things as pric e changes, small design changes, errors in estimation, strikes, or adverse weather

con ditions. These are unpredictable costs likely to occur. In the cost spreadsheets of Appendices E, 5 F, and G, con tingency costs were estimated primarily as 20 percent of the total direct and indirec t capital c ost. Cost estimates obtained from selected control vendors already included contingencies.

7,8 To avoid double accounting, no additional contingency costs were added. 6.1.1.5 Other Capital Costs Othe r costs which may be included as capital costs are expenditures for site preparation , buildi ngs, land, and working capital. Site preparation costs are sometimes accounted for in direc t installation costs, and in most cases are unreported. Additional buildings are usually not required for retrofit NO control systems for ICI boilers, except in cases where existing facilities are absolutel y

x unable to a ccommodate additional equipment installation. For the purposes of this study, sit e preparation and building costs were listed in the cost spreadsheets, but were only used if source s 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. This fund is primarily used in 7
cost a nalyses for large systems which require significant amounts of utilities, O&M labor, an d materials. Becau se most of the control systems considered in this study do not require large amounts

1 of util ities, 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 6.1.2 Annual Operations and Maintenance (O&M) Costs An nual O&M costs of NO control systems are classified as either direct or indirect annua l x costs. For this study, O&M costs were consi dered to be costs resulting from the use of the NO control x equip ment only, and are separate from the annual O&M costs of the existing boiler. Figure 6- 26-6 Figure 6-2. Elements of total annual O&M cost. 16-7

displays common elements of an nual O&M costs. Included as direct annual O&M costs are expenses for labor and maintenance materials, u tilities 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 syste m catal ysts. With FGR NO control systems, boiler fuel consumption may actually decrease due t o x increased boiler efficiency, r esulting in an overall fuel savings. Two sources estimated fuel savings of 1 to 2 percent when FGR was retrofitted. In the cost calculations of Appendices E, F, and G, fuel 9,10 savings of 1 percent were included for all FGR systems. Prices for fuels and elect ricity in the U.S. were obtained from Energy User News. The cost 11 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 anhydrou s 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, an d in surance. Following the cost methodology developed by OAQPS, overhead charges were estimated as 60 perc ent of the annual labor and maintenance materials costs, while administrative, property tax, and insurance costs were estimated as 4 percent of t he total capital investment cost described in Section 6.1.1. 16-8 Cost element Cost assumption Direct capital costs NO control equipment x Instrumentation Sales taxes Freight Total = Purchased Equipment Cost (PEC) Direct installation cost Site preparation Buildings Given 10% of equipment cost 3% of equipment cost 5% of equipment cost
30% of PEC 0 unless given 0 unless given Indirect capital costs Engineering Construction and field expenses Construction fee Startup Performance test 10% of PEC a 10% of PEC a 10% of PEC a 2% of PEC a 1% of PEC a Contingency 20% of direct and indirect capital costs O&M costs FGR fuel savings Overhead Administrative Property tax Insurance 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. a TABLE 6-1. ASSUMPTIONS FOR ESTIMATING CAPITAL AND ANNUAL O&M COSTS

Table 6-1 summarizes the assumptions made for estim ating capital and O&M costs for retrofit NO control systems. When developing a NO control cost spreadsheet based on data from a particular x x reference source, these estimates were used whenever data were not provided by the source. 6.1.3 Total Annualized Cost and Cost Effectiveness Tota l capital investment and total annual O&M costs may be combined to give a tota l annualized cost. Total capital investment is converte d 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 d one 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 106-9

years was assumed f or the NO control systems, which results in a capital recovery factor of 0.1627. x 13 The interest ra te of 10 percent was selected as a typical constant dollar rate of return on investment to provide a basis for calculation of an nualized capital investment cost. Although 10 years was chosen as the c apital amortization period, other periods could have been selected if desired, as long as the same amortiz ation period is used when comparing costs of different control systems. When the annualized capital cost is added to the total annual O&M costs d iscussed in Section 6.1.2, the resulting figure is the total annualized cost of the NO control system. x In order to compare the cost effectiveness of different controls on a given boiler, the tota l annualized cost of each control sy stem was divided by the amount of NO removed by the system over x 1 year. The amount of NO removed from a boiler is a function of the achievable NO reduction of the x x 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 purp oses 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 NO control cost effectiveness, cost x effectivenes s 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 summar y t a bles in this chapter show cost effectiveness calculated for the mid-range capacity factors of 0.5 and 0.66 only. To estima te the amount of NO removed by a control system per year, pre-retrofit an d x post-retrofit NO emission levels must be known, in addition to the boiler capacity factor and heat input x capacity rating. Assumed baseline NO levels were selected for each fuel and boiler type based on data x6-10 Fuel Boiler type Baseline NO , x lb/MMBtu a Natural gas Firetube 0.12 Watertube 10 to <75 MMBtu/hr 0.16 75 to 150 MMBtu/hr 0.18 >150 to <350 MMBtu/hr 0.24 350 to <750 MMBtu/hr 0.30 750 MMBtu/hr 0.40 Distillate oil All 0.20 Residual oil All 0.38 Pulverized coal Wall-fired 0.70 Coal Spreader stoker 0.53 Coal FBC 0.32 Wood Stoker 0.25 Wood FBC 0.25 Wood/natural gas Stoker 0.20 Paper Packaged watertube 0.50 MSW Stoker 0.40 To convert to ppm at 3 percent O , multiply by the following factors: natural a 2 gas, 835; distillate oil, 790; residual oil, 790; coal, 740; wood, 710; paper, 710; MSW, 705 (approximate). TABLE 6-2. BASELINE (UNCONTROLLED) NO EMISSIONS USED FOR COST CASES x

containe d in Appendices A and B and summarized in Table 4-7 of Chapter 4. Table 6-2 lists th e average baseline NO levels assumed for the purposes of calculating co st effectiveness. For natural-gas- x fired watertube boilers, five boiler size categories were considered i n the retrofit cost analyses. Average baseline NO emissions increase with boiler size because of the higher heat release rate and greate r

x thermal NO formation. NO reduction efficiencies for each typ e of control were selected based on data

x x contained in Chapter 5 and Appendix B, and are listed in Table 6- 36-11

NO control technology x Applicable boiler equipment NO reduction efficiency, % x 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 Nat. gas/oil: PKG-WT, FE-WT b 50 50 FGR Nat. gas/oil: PKG-FT c 40 LNB and FGR Nat. gas/oil: PKG-WT 60 SNCR PC: wall-fired Coal: FBC Coal: Stoker Nonfossil: stoker, PKG-WT, FBC 45 75 58 55 SCR PC: wall-fired Nat. gas/oil: PKG-WT 80 85 See Chapter 5 and Appendix B. a PKG-WT = packaged watertube; FE-WT = field-erected watertube. b PKG-FT = packaged firetube. c TABLE 6-3. NO REDUCTION EFFICIENCIES USED FOR COST CASES x . These NO reduction efficiencies are assumed levels only; actual NO reduction performance o f

x x partic ular control systems may vary depending on boiler, fuel, and operating characteristics, a s discussed in Chapter 5. Total annualized costs are divided by the amount of NO emission reduction per year to obtain x the cost effectiveness in terms of dollars per ton of NO reduced. As stated earlier, all costs in thi s x analysis are expressed in terms of 1992 dollars.6-12 Fuel type Boiler type Boiler capacity, MMBtu/hr NO control x technology Cost data

reference PC Wall-fired 250-750 250-750 250-750 250-750 LNB

SNCR-ammonia SNCR-urea SCR 14

16 17 15 Coal FBC Spreader stoker 250-750 250-750 SNCR-urea

SNCR-urea 18

17 Natural gas/distillate oil/residual oil Packaged watertube Packaged watertube 10-250 10-250 OT

OT+WI 19

19 Packaged firetube Packaged firetube Packaged firetube 3-34 3-34 3-34 OT

OT+WI FGR 19

19 20 Packaged watertube Packaged watertube Packaged watertube 10-250 10-250 10-250 LNB

LNB+FGR SCR 6,14

6,14,21 9,22 Field-erected wall-fired 250-750 LNB 14

Nonfossil fuel Stoker Packaged watertube FBC 50-500

10-250 250-750 SNCR-urea

SNCR-urea SNCR-ammonia 16

16 23 TABLE 6-4. NO CONTROL COST EFFECTIVENESS CASES x

6.2 NO CONTROL COST CASES AND SCALING METHODOLOGY

x NO control cost cases were selected based on the prevalence of control system applications x to specific t ypes and sizes of boilers and on the availability of cost data. Table 6-4 lists the cost cases anal yzed and data sources from which various cost figures, principally capital and annual costs, were obtained. Cost data were compiled primarily from publ ished 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 c osts for LNB and SCR were provided by the Council of Industrial Boiler Owners (CIBO) , and recent costs were developed for small utility PC- 14 fired boilers. Cost estimates for SNCR with urea and ammonia reagents were provided by vendors

15 of these technologies. Experience with NO controls for ICI PC-fired boilers is generally very sparse; x therefore, these cost estimates should be used with cau tion. Data on NO controls for FBC boilers were x6-13

limited to SNCR, since combustion staging is usuall y integrated into the original FBC boiler design and operati on. For firetube boilers, data were also limited primarily to FGR only. Cost estimates o f 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 cos t effectiveness figures presented in Appendices E, F, and G. Cost effectiveness estimates for each of the NO control cost cases were then obtained from these values, using the logarithmic scaling law known x as the "six-tenths power rule," to account for differences in boile r capacity size. Cost effectiveness was 5 calculated for each cost case, using each applicable source of raw cost data. For example, the cos t effectivene ss of LNB used in 10 to 250 MMBtu/hr (2.9 to 73 MWt) natural-gas-fired package d watertube un its was calculated using annual costs derived from References 6 and 14, each of whic h provided data on more than one LNB retrofit project. Each individual retrofit project was used t o 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 th e following subsections. In al l, cost data for 42 different boiler/NO control configurations were used to x develop these ranges, varying in boiler type, size, fuel, and NO control technology. x Most of the data obtained were for natural-gas-fired units, in part because of boiler retrofi t activity in California's South Coast Air Basin, where natural gas is the primary fuel used. Cos t effectiveness figures for distillate- and residua l-oil-fired units were estimated using the annual costs for natural-gas-fired units. Appropriate baseline NO levels f or fuel oil firing were used to calculate annual x NO reduction. For FGR, fuel oil prices were used to estimate the annual fuel savings. x 6.3 CAPITAL AND TOTAL ANNUAL COSTS OF NO CONTROLS x6-14 Table 6 - 56-15

Boiler type, size, and fuel NO control x Controlled NO , x lb/MMBtu a Capital cost,

$/MMBtu/hr Total annual cost,

$/yr/MMBtu/hr b Reference 400 MMBtu/hr PC-fired wall-fired watertube LNB 0.35 5,300 1,220 14 SNCR 0.28 1,600-2,100 950-1,200 16,17 SCR 0.14 20,000 5,800 15 400 MMBtu/hr FBC SNCR 0.08 1,600 680 18 400 MMBtu/hr stoker SNCR 0.22 1,100 1,200 17 10.5 MMBtu/hr oil/gas firetube OT+WI 0.04 (Gas) 2,400 690 19 OT+FGR 0.07 (Gas)

0.12 (No. 2 oil) 5,400 1,100 20
50 MMBtu/hr oil/gas packaged watertube OT+WI 0.06 (Gas) 530 210 19 LNB 0.08 (Gas)

0.10 (No. 2 oil) 0.19 (No. 6 oil) 650-2,300 340-420 6,14

LNB+FGR 0.06 (Gas)

0.07 (No. 2 oil) 0.15 (No. 6 oil) 2,100-4,700 430-890 6,14,21

SCR 0.02 (Gas)

0.03 (No. 2 oil) 0.06 (No. 6 oil) 2,400-6,900 1,500-1,900 9,22

300 MMBtu/hr oil/gas field-erected watertube OT+SCA (BOOS) 0.15 (Gas) 190 96 19

LNB 0.12 (Gas)

0.10 (No. 2 oil) 0.19 (No. 6 oil) 5,100-8,300 990-1,500 14

150 MMBtu/hr wood-fired stoker SNCR 0.11 2,100-2,500 500-800 16

400 MMBtu/hr wood-fired FBC SNCR 0.11 970 590 23

500 MMBtu/hr MSW stoker SNCR 0.18 2,100-3,300 940-1,100 15
Arithmetic average of reported NO control performance. Not indicative of levels achievable in all cases. a x Calculated based on 0.66 capacity factor or 5,460 operating hours per year at the boiler capacity. b Note: All estimates are rounded to two significant figures. TABLE 6-5. CAPI TAL AND TOTAL ANNUAL COSTS OF RETROFIT NO CONTROL S x FOR ICI BOILERS, 1992 DOLLARS6-16

summarizes the capital an d total annualized costs of retrofit controls on selected "model" size boilers. The table also lists the anticipated NO control levels applicable to each control technology and model x boiler. This information corresponds to data presen ted in Chapter 5. The total annualized cost includes the payments for the initial investment and the recurring dire ct and indirect O&M costs. The references indicate the sources of the capital cost data, and, in some cases, th e O&M cost data, used in the analysis. As indicated earlier, when the ref erence 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:Capital cost 2 ( MMBtu / hr ) 2 ( MMBtu / hr ) 1 0

. 6 Capital cost 1

6-17 (6-1)

The ranges in both capital an d operating costs indicate that the references provided more than one cost case from which data could be extrapolated to the model boilers. Th e reported capital cost of retrofit NO controls has been found to vary by two orders o f x magnitude, from the low cost o f BOOS ($190/MMBtu) and WI ($530/MMBtu), on small- to mediumsized 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 o f $20,000/MMBtu based on estimates from a comparable- sized utility boiler. However, because of the 15 lack of experience with SCR on coal-fired industrial boilers, it is difficult to draw any definitiv e conclusions with respect to the actual retrofit cost of SCR on t hese boiler types. Recent experience with utility boi lers 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 app licable, the capital cost of SNCR has been found to be in the same range as th e capital costs of such combustion controls as LNB and FGR. Both SNCR-urea and SNCR-ammoni a 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) boil er, the capital cost for SNCR-ammonia was estimated by Exxon to be about $900/MMBtu/hr. For an 812 MMBtu/hr (238 MWt) tangential boiler, 16 the capital cost for SNCR-urea was estimated by Nalco Fu el Tech to be about $600/MMBtu/hr. , while 17

a sm aller, 400 MMBtu/hr boiler will require an investment of $830,000. Figure 6- 3 176-18Figure 6-3. Total capital cost reported by Exxon for SNCR-ammonia on a variety of industrial boilers.6-19

plots the actual or estimated capital cost for the Thermal DeNO proce ss for several boiler types. These x costs were prepared b y 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, includin g waste fuels. These data show the exponential increase in capital cost with decreasing boiler siz e

24,25 (boiler capacity is plotted on a logarithmic scale).6-20

6.4 COST EFFECTIVENESS OF NO CONTROLS x This section presents the cost effectiveness of various NO c ontrols retrofitted to a range of ICI x boilers, usin g the costing methodology and assumptions discussed earlier. Section 6.4.1 describes the boiler NO control cases analyzed, and Sections 6.4.2 through 6.4.6 discuss the cost analyses results.

x 6.4.1 NO Control Cost Effectiveness: Coal-fired ICI Boilers

x6-21

Boiler type Boiler capacity,

MMBtu/hr NO control x technology Controlled NO x

level, lb/MMBtu Cost effectiveness,

$/ton NO removed

x a,b PC wall-fired 250

400 500 750 LNB

LNB LNB LNB 0.35

0.35 0.35 0.35 1,340-1,760

1,170-1,530 1,090-1,430 980-1,280 250 400 500 750 SNCR-ammonia

SNCR-ammonia SNCR-ammonia SNCR-ammonia 0.39 0.39 0.39 0.39 1,360-1,450

1,310-1,400 1,300-1,370 1,270-1,330 250 400 500 750 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea 0.39

0.39 0.39 0.39 1,120-1,340

1,040-1,240 1,010-1,190 960-1,130 250 400 500 750 SCR

SCR SCR SCR 0.14

0.14 0.14 0.14 3,800-4,800

3,400-4,200 3,200-4,000 3,000-3,700 CFBC 250

400 500 750 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea 0.08

0.08 0.08 0.08 960-1,130

890-1,030 860-980 810-920 Spreader stoker 250

400 500 750 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea 0.22

0.22 0.22 0.22 1,360-1,440

1,320-1,380 1,300-1,360 1,280-1,320 Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year a capital amortization. 1992 dollars. b TABLE 6-6. SUMMARY OF NO CONTROL COST EFFECTIVENESS, COAL-FIRED x ICI BOILERS

Table 6-6 summarizes the results obtained for coal-fired ICI boilers retrofitted with various NO controls. The cost effectiveness values presented here and in all subsequent tables and figures in x this chapter were calculated using capa city factors of 0.50 to 0.66. These capacity factors were chosen

as mid-ran ge capacity levels for this analysis, although it is likely that small ICI boilers such a s packaged firetube units will have capacity factors less t han 0.50. In all cost cases, costs per ton of NO 7 x control were higher as the capacity factor decreased, due to the r educed amount of NO removed. Thus, x6-22

c o sts 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 0.80.6-23 Figure 6 - 46-24Figure 6-4. Cost effectiveness versus boiler capacity, PC wall-fired boilers.6-25

graphically shows the relationship of cost eff ectiveness and boiler capacity for NO controls retrofitted x to P C wall-fired boilers. The cost estimates depicted are based on data from a detailed cost study for

a 766 MMB tu/hr (224 MWt) PC wall-fired unit. Cost estimates for other boiler sizes wer e 14 extrapolated using the 0.6 power law for capital cost and a propor tional dependence for O&M cost. The dat a show reduced costs per ton of NO removed as boiler capacity increases, due to greater amounts x of NO removed and economies of scale. SNCR controls were the most cost effective per ton of NO

x x removed, wit h costs ranging from a low of $950 per ton of NO removed, for a 750 MMBtu/h r x (220 MWt) unit , to a high of $1,340 per ton, for a smaller, 250 MMBtu/hr (73 MWt) unit. Th e difference in cost effectiveness between SNCR with urea and SNCR with ammonia is well within the margin of error for this cost analysis. LN B controls required greater expenditures for equivalent NO removal, ranging from $980 x to $1,760 per ton of NO removed. LNB costs were de veloped based on estimates provided by CIBO. x 14 SCR has the highest costs per ton of NO removal, ranging from $4,610 to $7,810 per ton of NO

. x x These estimates were also developed from EPA cost estimates for a 100 MWe utility boiler. Recent 15 trends in SCR applica tions have shown significant decreases in capital investment for this technology. Howeve r, due to the lack of experience in SCR application on PC-fired boilers, the actual cost of this control option i s speculative at this stage. Overall, on a per-ton of NO removed basis of comparison, x SNCR controls were the most cost effective for PC wall-fired boilers. It should be noted that the controlled NO levels achieved using LNB were higher than those x 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 most6-26 Boiler type Boiler

capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness,

$/ton NO removed

x a,b Packaged watertube (single-burner) 10 25 50 100 150 250 WI+OT

WI+OT WI+OT WI+OT WI+OT WI+OT 0.06

0.06 0.06 0.06 0.06 0.08 960-1,160

800-940 710-820 570-650 540-610 380-430
10 25 50 100 150 250 LNB

LNB LNB LNB LNB LNB 0.08

0.08 0.08 0.09 0.09 0.12 990-4,300

720-3,070 570-2,390 410-1,670 360-1,450 240-920 Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and (continued) a 10-year capital amortization. 1992 dollars. b TABLE 6-7. SUMMARY OF NO CONTROL COST EFFECTIVENESS, NATURAL- x GAS-FIRED ICI BOILERS expensiv e cost elements were purchased equipment cost and annual chemical or catalyst replacement costs. SCR catalyst replacement was based on a 4-ye ar catalyst life. Both capital and O&M SCR costs are in line with EPA estimates for small PC-fired utility boilers. In g eneral, costs per ton of NO control x for tangential-fired PC boilers may be expected to be slightly higher than those estimated for the PC wall-fired units, since baseline NO levels are generally lower for tangential firing, and, hence, th e x amount of NO removed will be slightly lower.

x 6.4.2 NO Control Cost Effectiveness: Natural-gas-fired ICI Boilers

x Cost effectiveness estimates were made f or packaged watertube, packaged firetube, and fielderect ed wall-fired units firing natural gas, and are summarized in Table 6- 76-27 TABLE 6-7. (continued)

Boiler type Boiler

capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness,

$/ton NO removed

x a,b Packaged watertube (single-burner) (continued) 10 25 50 100 150 250 LNB+FGR

LNB+FGR LNB+FGR LNB+FGR LNB+FGR LNB+FGR 0.06

0.06 0.06 0.07 0.07 0.10 2,630-7,630

1,930-5,510 1,540-4,350 1,110-3,090 990-2,730 650-1,760
10 25 50 100 150 250 SCR

SCR SCR SCR SCR SCR 0.02

0.02 0.02 0.03 0.03 0.04 7,400-10,090

5,730-8,010 4,830-6,880 3,040-5,350 2,690-4,990 1,810-3,460 Packaged firetube 2.9 5.2 10.5 20.9 33.5 WI+OT

WI+OT WI+OT WI+OT WI+OT 0.04

0.04 0.04 0.04 0.04 4,190-5,240

3,600-4,450 3,050-3,720 2,640-3,180 2,410-2,890
2.9 5.2 10.5 20.9 33.5 FGR+OT

FGR+OT FGR+OT FGR+OT FGR+OT 0.07

0.07 0.07 0.07 0.07 26,570-35,410

15,160-20,380 7,970-10,830 4,520-6,100 3,000-4,080
Field-erected wall-fired(multipleburner) 100 250 400 500 750 BOOS+OT

BOOS+OT BOOS+OT BOOS+OT BOOS+OT 0.09

0.12 0.15 0.15 0.20 440-510

280-330 210-240 210-240 150-170
100 250 400 500 750 BOOS+WI+OT

BOOS+WI+OT BOOS+WI+OT BOOS+WI+OT BOOS+WI+OT 0.05 0.06 0.08 0.08 0.10 750-820

530-570 410-440 400-430 300-310
250 400 500 750 LNB

LNB LNB LNB 0.12

0.15 0.15 0.20 3,030-6,210

2,070-4,210 1,920-3,900 1,690-3,400 Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and a 10-year capital amortization. 1992 dollars. b6-28

. 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 fi retube units retrofitted with WI+OT, and F GR 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 i n Section 6.4.6.6-29

6.4.2.1 Natural-gas-fired Packaged Watertube Boilers NO control cost data for natural-gas-fired packaged (single-burner) watertube boilers are more x available than for othe r 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 in stalling SCR systems on packaged boilers rated as small as 66,000 lb steam/hr (8.3 kg/s).6-30 As t abulated in Table 6-7 and shown in Figure 6- 56-31Figure 6-5. Cost effectiveness versus boiler capacity, natural-gas-fired packaged watertube boilers.6-32

, cost effectiveness estimates for packaged watertube units fired by natural gas were highest for SCR NO contr ol and lowest for LNB and WI+OT, with LNB+FGR falling in between. WI+OT i s x considered cos t-competitive with LNB because of its low initial capital investment. In spite of th e therm al efficiency loss of 0.5 to 1.0 percent associated with WI, this technique can be cost effectiv e especially for small boilers with a low capacity factor. As was the case with coal-fired units, cost s per ton of NO reduction decreased with increased x boiler capac ity, due to the increased amount of NO removed from the larger units and genera l x 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 uni ts smaller than this capacity,
costs of NO control increase rapidly as capacity decreases, especially when SCR is used. The costs

x per ton of NO control for a 250 MMBtu/hr (73 MWt) single-burner packaged boiler with LNB ar e

x much lowe r than those estimated for a multiple-burner field-erected unit of similar size. Some of the discrepancy be tween the figures can be attributed to the different data sources; however, the principal

r e ason 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 NO removed were twice as high as for LNB x and WI+OT, while SCR control costs per to n of NO removed were 3 times higher. Cost effectiveness x of WI+OT ranged from $380 to $1,160 per ton of NO removed. Cost effectiveness for LNB controls x ranged from $240 to $4,300 per ton of NO removed, across the capacity range of 10 to 250 MMBtu/hr x (2.9 to 73 MWt). LNB+FGR cost effec tiveness ranged from about $650 to $7,630/ton, while SCR had the highest range in cost per ton of NO x6-33

rem oved, approximately $1,810 to $10,090/ton. The high-end costs of these ranges were for th e smallest, 10 MMBt u/hr (2.9 MWt) units at a 0.50 capacity factor. Because it is likely that many units this small are operated at even l ower capacity factors, actual costs of NO control may be much higher x than these est imates. For these lower capacity factor boilers, controls with a high initial capita l investment, such as SCR, LNB, and LNB+FGR, are particularly penalized when compared on a costeffectiveness basis. Figure 6-5 illustrates the overall trend of cost e ffectiveness with boiler capacity. The enclosed

areas reflec t the ranges in cost and are representative of the uncertainty in these estimates. Cost

- effec tiveness ranges for LNB and for LNB+FGR overlap, due to the wide range of cost effectiveness values obtai ned. These cost-effectiveness data illustrate the potential variability in the costs o f retrofitting boilers with NO controls, which are highly dependent on site-specific installation an d x operating factors. Figure 6- 66-34Figure 6-6. Cost effectiveness versus boiler capacity, natural-gas-fired packaged watertube boilers using SCR controls.6-35

illustrates the variability of the cost effect iveness of SCR controls, assuming various catalyst lifetimes. As catalyst life increases, cost effectiveness slowly decreases. 6.4.2.2 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 fo r FGR+OT controls w ere obtained from a distributor of industrial boilers and NO control systems, and x are based on experiences with nearly 20 units operating with FGR. Costs for WI+OT are based on 20 recently reported NO retrofit experiences in Southern California. x 19 FGR+OT is o ne of the most common retrofit NO control strategies for natural-gas-fire d x firetube units, besides LNB or combined LNB and FGR. Costs per ton of NO removed for these units x firing natural gas were relatively high, rang ing from $3,000 to $35,410, with the highest costs being for units 5 MMB tu/hr (1.5 MWt) and smaller. The most significant cost components for these cost cases were equipment and installation costs. The costs of NO con trol for a 10 MMBtu/hr (2.9 MWt) firetube x unit retrofitted with FGR+OT are re latively 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 cos t estimates were made for firetube units retrofit ted with LNB or LNB+FGR controls, it is likely that cost effectiveness for these control cases will be comparable to t hose estimated for packaged watertube units of similar capacity.6-36 The estimated costs for WI+OT for thes e firetube boilers are based on a retrofit investment of $35,000, irrespective of boiler size, and an efficiency p enalty of 1.0 percent. It is difficult to predict the
actua l thermal efficiency impact in a retrofit situation. The actual impact will depend on current unit operating practices; given a poor operating condition with high ex cess air combustion, the retrofit of this control may, in some cases, result in an improvemen t. 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 i n Table 6-7, the estimated cost for this control st rategy is similar to that for LNB retrofit, but still slightly higher than comparable controls for watertube units. This is due to lower baseline NO levels fo r x 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 BOO S 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 wit h several burners with small heat input ratings per burner offer the greater opportunity for implementation of these eff ective control techniques. Where possible, the retrofit of BOOS and BOOS+WI+OT i s likely to be the more cost effective options in spite of thermal efficiencies, here assumed to rang e between 0.25 and 1.0 percent. The lower the capacity fac tor of these boilers, the more cost-competitive these controls may prove to be. Esti mates 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 NO removed for natural-gas-fired field-erected units with LNB , x listed in Table 6-7, range from $1,690 to $6,210 per ton of NO remove d for boilers ranging in size from x 250 to 750 MMBtu/hr (73 to 220 MWt). The costs per ton of NO control for a multiple-burner field- x erected 250 MMBtu/hr (73 MWt) unit are much higher than the costs estimated for a single-burne r pack aged unit due to greater capital equipment and installation costs as discussed in Section 6.4.2.1

. Although the listed cost effectiveness ranges a re for a capacity factor as low as 0.50, most field-erected units have factors closer to 0.66. The high end of the cost effectiveness ranges listed in Table 6- 7 7 represent a 0.50 capacity factor. If considering a 0.66 capacity factor only, the high-end cos t effectiveness estimates are roughly 25 percent lower . The estimates presented are based on capital cost data supplied for two boilers retrofitted with LNB. 14 6.4.3 NO Control Cost Effectiveness: Fuel-oil-fired ICI Boilers

x As discussed earlier, NO control cost effectiveness estimates for fuel-oil-firing units wer e x mad e based on cost data for natural-gas-fired boilers, using appropriate baseline NO emission levels x and fuel oil prices. Tables 6- 86-37 Boiler type Boiler

capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness,

$/ton NO x removed a,b Packaged watertube 10 LNB 0.10 790-3,440 (single burner) 25 LNB 0.10 580-2,450 50 LNB 0.10 460-1,910 100 LNB 0.10 370-1,500 150 LNB 0.10 330-1,310 250 LNB 0.10 280-1,110

10 LNB+FGR 0.08 1,900-5,900 25 LNB+FGR 0.08 1,340-4,210 50 LNB+FGR 0.08 1,030-3,280 100 LNB+FGR 0.08 800-2,580 150 LNB+FGR 0.08 690-2,250 250 LNB+FGR 0.08 580-1,910

10 SCR 0.03 5,920-8,070 25 SCR 0.03 4,590-6,410 50 SCR 0.03 3,860-5,500 100 SCR 0.03 2,740-4,820 150 SCR 0.03 2,420-4,490 250 SCR 0.03 2,170-4,150 Packaged firetube 2.9 FGR+OT 0.12 15,640-20,940 5.2 FGR+OT 0.12 8,800-11,930 10.5 FGR+OT 0.12 4,490-6,200 20.9 FGR+OT 0.12 2,410-3,360 33.5 FGR+OT 0.12 1,500-2,150 Field-erected wall-fired (multiple burner) 250 LNB 0.10 3,630-7,450 400 LNB 0.10 3,100-6,320 500 LNB 0.10 2,880-5,850 750 LNB 0.10 2,530-5,100 Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year a capital amortization. 1992 dollars. b TABLE 6-8. SUMMARY OF NO CONTROL COST EFFECTIVENESS, DISTILLATE- x OIL-FIRED ICI BOILERS6-38 Boiler type Boiler

capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness,

$/ton NO x removed a,b Packaged watertube 10 LNB 0.19 420-1,810 (single burner) 25 LNB 0.19 300-1,290 50 LNB 0.19 240-1,010 100 LNB 0.19 190-790 150 LNB 0.19 170-690 250 LNB 0.19 150-580

10 LNB+FGR 0.23 1,220-3,320 25 LNB+FGR 0.23 920-2,430 50 LNB+FGR 0.23 760-1,950 100 LNB+FGR 0.23 640-1,580 150 LNB+FGR 0.23 580-1,400 250 LNB+FGR 0.23 520-1,220

10 SCR 0.06 3,110-4,240 25 SCR 0.06 2,420-3,370 50 SCR 0.06 2,030-2,900 100 SCR 0.06 1,440-2,530 150 SCR 0.06 1,270-2,360 250 SCR 0.06 1,140-2,190 Packaged firetube 2.9 FGR+OT 0.23 8,560-11,350 5.2 FGR+OT 0.23 4,960-6,600 10.5 FGR+OT 0.23 2,690-3,590 20.9 FGR+OT 0.23 1,600-2,100 33.5 FGR+OT 0.23 1,120-1,460 Field-erected wall-fired (multiple burner) 250 LNB 0.19 1,910-3,920 400 LNB 0.19 1,630-3,330 500 LNB 0.19 1,520-3,080 750 LNB 0.19 1,330-2,680 Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year a capital amortization. 1992 dollars. b TABLE 6-9. SUMMARY OF NO CONTROL COST EFFECTIVENESS, RESIDUAL- x OIL-FIRED ICI BOILERSFigure 6-7. Cost effectiveness versus boiler capacity, distillate-oil-fired boilers.Figure 6-8. Cost effectiveness versus boiler capacity, residual-oil-fired boilers. and 6-9 summarize these estimates, a nd Figures 6-7 and 6-8 graphically show the results for packaged6-39

watertube boilers. NO controls that use wat er injection were not considered for oil-fired units because x of lack of experience and greater operationa l and environmental impacts that are likely with these fuels

co mpared with natural gas. Comparative cost results for the different NO control technologies ar e x si milar to those obtained for natural-gas-fired units, as expected, with SCR showing the highest costs per ton of NO removed and LNB showing the lowest. Like the cost estimates for natural gas firing,

x LNB+FGR control costs were, on average, twice as high as the costs of LNB controls, while SC R controls were 3 times as high. Overall costs of NO con trol per ton removed are lower for fuel oil firing than for natural gas x firing d ue to higher baseline NO emission levels, and, hence, greater amounts of NO removal pe r x x MMBtu heat i nput. As discussed for natural gas-fired boilers, the cost effectiveness discrepanc y between a 250 MMBtu/hr (73 MWt) packaged boiler and a 250 MMBtu/hr (73 MWt) field-erected unit equ ipped 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. Whe re applicable, this technique can result in considerable NO x reduction at much lower cost than LNB retrofit. 6.4.4 NO Control Cost Effectiveness: Nonfossil-fuel-fired ICI Boilers

x Limited cost data were available f or nonfossil-fuel-fired boilers retrofitted with NO controls. x For this reason, cost estimates could only be made for the application of SNCR controls to several types of nonfossil-fuel-fired boilers. Data wer e obtained directly from leading SNCR system manufacturers, and reflec t cost experiences for nine different installations. NO control performance and cost ar e x considered the same regardless of the reagent used. Typical applications use either ammonia or urea6-40

Boiler type Fuel type Boiler capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness,

$/ton NO x removed a,b Stoker Wood 50 150 250 350 500 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea SNCR-urea 0.11

0.11 0.11 0.11 0.11 1,810-3,130

1,270-2,380 1,080-2,130 980-2,000 890-1,870 MSW 50

150 250 350 500 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea SNCR-urea 0.18

0.18 0.18 0.18 0.18 3,390-3,800

1,890-2,790 1,690-2,450 1,580-2,270 1,470-2,090 Packaged watertube Paper 10 25 50 100 150 250 SNCR-urea

SNCR-urea SNCR-urea SNCR-urea SNCR-urea SNCR-urea 0.23

0.23 0.23 0.23 0.23 0.23 2,220-3,520

1,780-2,710 1,550-2,270 1,370-1,930 1,280-1,770 1,190-1,610 BFBC Wood 250 350 400 500 750 SNCR-ammonia

SNCR-ammonia SNCR-ammonia SNCR-ammonia SNCR-ammonia 0.11 0.11 0.11 0.11 0.11 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 a amortization. 1992 dollars. b TABLE 6-10. SUMMARY OF NO CONTROL COST EFFECTIVENESS, NONFOSSIL- x FUEL-FIRED ICI BOILERS

in aqueous solution. Table 6-10 summarizes the cost effectiveness ranges for these boilers. Cos t effecti veness estimates made for wood-fired stokers with urea injection are comparable to thos e calculated for wood-fired FBC boilers with ammonia injection, ranging between $890 and $2,130 per ton of NO removed for boilers 250 to 500 MMBtu/hr (73 to 146 MWt). The range in cost effectiveness

x for MSW-fired stokers of the6-416-426-436-44

same capacity retrofit with urea injection is $1,470 and $2,450 per ton of NO removed. For wood- or x MSW-fired boilers smaller than 250 MMBtu/ hr (73 MWt) but at least 50 MMBtu/hr (15 MWt), SNCR control costs ranged from approximate ly $1,270 to $3,800 per ton of NO removed. Cost estimates for x similarly size d paper-fired units were lower, ranging from $1,280 to roughly $2,270 per ton of NO x removed. 6.4.5 NO Con trol Cost Effectiveness: Oil-fired Thermally Enhanced Oil Recovery (TEOR)

x Steam Generators No cost analyses were performed for NO controls for TEOR steam generators. However, it x 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. Based on these estimates, 26 and assuming a baseline NO emission level of 0.38 lb/MMBtu (see Chapter 4) and the NO reduction x x efficiencies listed in Table 6-3, cost effectiveness is $3,790 per ton of NO removed for LNB at 0.66 x 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 NO control retrofit package can increase the costs of NO x x control. For example, Table 6-1 16-45

Boiler type Boiler

capacity, MMBtu/hr NO control x technology Controlled

NO level, x lb/MMBtu Cost effectiveness

without CEM, $/ton NO x removed b,c Cost effectiveness

with CEM, $/ton NO x removed b,c Packaged 10 LNB 0.08 3,260-4,300 5,410-7,140 watertube 25 LNB 0.08 2,320-3,070 3,850-5,080

50 LNB 0.08 1,810-2,390 3,000-3,960 100 LNB 0.09 1,260-1,670 2,090-2,760 150 LNB 0.09 1,100-1,450 1,830-2,410 250 LNB 0.12 700-920 1,160-1,530
10 LNB+FGR 0.06 3,700-5,000 5,480-7,360 25 LNB+FGR 0.06 2,530-3,460 3,800-5,140 50 LNB+FGR 0.06 1,900-2,620 2,890-3,930 100 LNB+FGR 0.07 1,260-1,760 1,950-2,680 150 LNB+FGR 0.07 1,050-1,500 1,660-2,290 250 LNB+FGR 0.10 630-910 1,020-1,420 Based on data contained in Reference 19, for a 265 MMBtu/hr (7.7 MWt) natural-gas-fired unit. a Capacity factor: 0.50-0.66. Costs based on 10-percent interest rate and 10-year capital amortization. b 1992 dollars. c TABLE 6-11. NO CONTROL COST EFFECTIVENESS WITHOUT/WITH CEM x SYSTEM, NATURAL-GAS-FIRED ICI BOILERS a shows th e 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 M MBtu/hr (77.7 MWt) unit, that showed a total CEM system capital cost of roughly $200,000, incl uding installation. Average cost increased by roughly 65 percent when a CEM system wa s 14 included. While it is not possible to draw conclusions from one source about the extent to which CEM sy stems will increase costs, the data nevertheless show that CEM cost impact is considerable. Fo r 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 CE M systems only for boilers that are 40 MMBtu/hr (12 MWt) or greater in capacity. 276-46

6.5 REFERENCES FOR CHAPTER 6
1. OAQPS Control Cost Manual — Fourth Edition. Publication No. EPA-450/3-90-006. U.S. Environmenta l 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. Techn ical Support Document for a Suggested Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial Boilers, Stea m Generators, and Process Heaters. (California ARB, 1987) Sta tewide Technical Review Group. California Air Resources Board. Sacramento, CA. April 1987.
7. Devitt, T., et al (PEDCo Environmental, Inc.). Population and Characteristics o f 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, Particulate Matter, and Nitrog en Oxide Controls on Fossil Fuel Fired Industrial Boilers. Publication No

. EPA-450/3-82-021. Prepared for the U.S. Environmental Protection Agency. Researc h Triangle Park, NC. August 1982.
9. Damon , J., et al. (United Engineers and Constructors). Updated Technical and Economi c Review of Selective Catalytic NO Reduction Systems. Proceedings: 1987 Symposium o n x St ationary Combustion NO Control. Publication No. EPRI CS-5361. U.S. Environmenta l x 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 Quali ty Management District. Cost Analyses of FGR Retrofit to Natural-gas-fire d 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., Ac urex Environmental Corporation. NO Control Technology Costs. June 12, 1992. x6-47

15. Alternative Control Techniqu es Document--NO Emissions from Utility Boilers. Publication x No. EPA-453/R-94-023. U.S. Environmental Protection Agency. Office of Air Qualit y Planning and Standards. Research Triangle Park, NC. March 1994.
16. Letter and attachments from Shaneberger, D., Exxon Research and Engineering Company, to Castald ini, C., Acurex Environmental Corporation. Thermal DeNO Costs. December 3 , x 1993.
17. Letter and attachments from Pickens, R., Nalco Fuel Tech, to Castaldini, C., Acure x Environmental Corporation. NO Control Technology Costs. March 15, 1994. x 18. Letter and Attachments from Pickens, R., Nalco Fuel Tech, to Castaldini, C., Acure x Environmental Corporation. SNCR-urea (NOxOUT) Control Costs. June 9, 1992.
19. Col annino, J. Low-Cost Techniques-Reduce Boiler NO . Chemical Engineering. February x 1993. p. 100.
20. Letter and Attachmen ts from Dean, H., Hugh Dean & Co., Inc., to Votlucka, P., South Coast Ai r Quality Management District. Cost Effectiveness of FGR NO Control for Firetub e x Boilers. January 12, 1988.
21. University of California at Riverside Central Utility Plant Boiler System Study. Impel l Corporation. Walnut Creek, CA. June 1989.
22. L e tter 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 Engi neering Co.). Exxon Thermal DeNO Effectiveness x Demons trated in a Wood-Fired Boiler. Presented at the 13th National Waste Processin g Conference and Exhibit. May 1988.
24. Letter and attachments from G. A. Haas, Exxon Research and Engineering Company, to B. Jor dan, U.S. EPA, OAQPS, Durham, NC. NO Control Technologies Questionnaire

. x February 18, 1993.
25. Bodylski, J. A. and G. A. Haas. The Selective Non-Catalytic Reduction (SNCR) Process : Expe rience with Exxon Thermal DeNO Process at Two Circulating Fluidized Bed Boile r x Commercial Appli cations. Presented at the American Flame Research Committee 1992 Fall Internati onal Symposium on Emission Reduction and Energy Conservation: Progress i n Combustion Technology. Cambridge, MA. October 1992.
26. Collins, J. (Radian Corp.). Technology Study of NO Controls for "Small" Oil-Fired Steam x Generators. Prepared for th e Western Oil and Gas Association. Bakersfield, CA. January 6, 1987.
27. Rule 1146 — Emissions of Oxides of Ni trogen from Industrial, Institutional, and Commercial Bo ilers, Steam Generators, and Process Heaters. South Coast Air Quality Managemen t District. El Monte, CA. January 1989.7-1 7. ENVIRONMENTAL AND ENERGY IMPACTS

This cha pter presents environmental and energy impacts for the NO emissions contro l x techniqu es described in Chapter 5. These control techniques are specific to certain boiler and fue l equipment, as shown in Table 7- 17-2TABLE 7-1. EXPERIENCE WITH NOCONTROL TECHNIQUES ON ICI BOILERSxNOcontrolxtechniqueCoal-firedOil-/natural-gas-firedNonfossil-fuel-firedMSW-firedField-erectedPC-firedStokerFBCFielderectedwatertubePackagedwatertubePackagedfiretubeStokerFBCMass burnBT/OTXXWI/SIXXSCAXXaXXXbXaXXaLNBXXXXFGRXXXXNGRXbXbSNCRXbXXXXbXXXSCRXbXbXbBT/OT = Burner tuning/oxygen trimWI/SI = Water injection/steam injectionSCA = Staged combustion air, includes burners out of service (BOOS), biased firing, or overfire air (OFA)LNB = Low-NOburnersxFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid wasteSCA is designed primarily for control of smoke and combustible fuel rather than NO. Optimization of existing SCA (OFA) ports can leadaxto some NOreduction.xLimited experience.b7-3

. 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 boiler s reburning with natural gas has only limited application potential to boi lers burning municipal solid waste or stoker coal. Flue gas treatment c ontrols 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, Se ction 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 NO Reductions

x Co ntrol techniques presented in this document can result in significant NO reductions fo r x selected ICI boilers. The actual NO reduction that can be achieved at each site will depend on many x factors inclu ding the extent of the equipment upgrade, the degree of control applied, and the boiler s current configuration such as furnace size, number of burners and burner matrix. For example, th e amount of flue gas recirculated has a strong influence on the percent NO reduction. Also, the amount x that can be safely recirculated will depend on the optimization of the burner design in order to maintain safe flame con ditions, and low emissions of other pollutants such as CO. In another example, th e amount of SCR catalyst that can be retrofit may depend on site acces sibility. Many ICI boilers are often located inside buildings making access for large retrofit difficult at best.7-4 Table 7 - 27-5 Boiler type and size, MMBtu/hr Baseline NO x NO control x technique Control NO x

level, lb/MMBtu NO reduction x lb/MMBtu Tons/yr

(0.50 CF )

a % Tons/yr (0.33 CF) Tons/yr

(0.50 CF) Tons/yr

(0.66 CF) PC 400 0.70 610 BT/OT LNB NGR SNCR SCR 0.62

0.35 0.28 0.39 0.14 15

50 60 45 85 46 200 240 180 320 70

310 370 270 490 93

400 490 360 650 Stoker coal 250 0.53 290 SCA SNCR 0.42

0.29 20

45 40

86 60

130 79

170 FBC coal 400 0.32 280 SCA SNCR 0.19

0.13 40

75 75

110 110

170 150

220 FE-WT gas 300 0.26 150 BT/OT SCA LNB LNB+FGR SNCR SCR 0.20

0.15 0.12 0.10 0.10 0.04 15

35 55 60 60 85 13

35 60 69 69 95 20

53 92 110 110 140 26

69 120 140 140 190 FE-WT No. 2 oil 300 0.21 140 BT/OT SCA LNB LNB+FGR SNCR SCR 0.18

0.13 0.10 0.08 0.10 0.03 15

40 50 60 50 80 13

35 48 56 48 78 20

53 72 85 72 120 26

69 95 110 95 160 FE-WT No. 6 oil 300 0.38 250 BT/OT SCA LNB FGR LNB+FGR SCR 0.32

0.29 0.19 0.34 0.15 0.08 15

25 50 10 60 80 26

39 82 17 100 130 34

59 120 26 150 200 52

78 160 35 200 260 PK-WT gas 50 0.14 15 BT/OT WI/SI LNB LNB+FGR SNCR SCR 0.12

0.06 0.08 0.06 0.07 0.02 15

55 45 57 50 85 1.4

5.8 4.3 5.8 5.1 8.7 2.2

8.8 6.6 8.8 7.7 13 2.8

12 8.7 12 10 17 PK-WT No. 2 oil 50 0.13 14 BT/OT LNB FGR 0.11

0.10 0.07 15

25 45 1.4

2.2 4.3 2.2

3.3 6.6 2.8

4.3 8.6 PK-WT No. 6 oil 50 0.36 39 BT/OT LNB LNB+FGR SCR 0.31

0.19 0.15 0.06 15

45 60 85 3.6

12 15 22 5.5

19 23 33 7.2

25 30 43 FT gas 15 0.10 3.3 BT/OT WI/SI LNB FGR LNB+FGR 0.09

0.04 0.08 0.07 0.03 15

65 20 30 70 0.22

1.3 0.43 0.65 1.5 0.33

2.0 0.66 1.0 2.3 0.44

2.6 0.87 1.3 3 FT No. 2 oil 15 0.17 5.6 BT/OT LNB FGR 0.15

0.09 0.12 15

50 30 0.43

1.7 1.1 0.66

2.6 1.6 0.86

3.5 2.2 FT No. 6 oil 15 0.31 10 BT/OT LNB 0.26

0.17 15

45 1.1

3.0 1.6

4.6 2.2

6.1 Stoker nonfossil 150 0.24 79 SNCR 0.11 55 28 43 56 FBC nonfossil 200 0.25 110 SNCR 0.11 55 40 61 80 Mass MSW 500 0.40 440 NGR SNCR 0.16

0.18 60

55 170

160 260

240 350

320 CF = capacity factor. a TABLE 7-2. NO EMISSIONS REDUCTION FROM MODEL BOILERS x7-6

lists the anticipated NO reductions that can be achieved on a yearly basis with the retrofit of candidate x control techniques. These estimates are based on "model size"7-77-8

boilers, baseline emissions presented in Chapter 4, and NO reduction potentials presented in Chapter x 5. Thus, a 400 MMBtu/h r (73 MWt) circulating FBC boiler burning coal with a baseline level of 0.32 lb/MM Btu could successfully employ SNCR to reduce emission levels to approximatel y 0.10 lb/MMBtu, corresponding to 210 tons/yr NO reduction at a capacity factor of 0.50. x 7.1.2 CO Emissions The CO emissions from ICI boilers are normally near ze ro, with the exception of a few boilers that have poor combustion air control or burner problems. In an extensive study of industrial boilers' 1 emissions, oil-fired units were found to have the lowest baseline CO emissions than either coal- or gasfired u nits. This was attributed to higher excess air levels typically used to avoid visible smok e emissions when oil is burned. CO emissions are generally caused by poor fuel-air mixing, flam e 1 quenching, and low residence time at elevated temperatures. Ad ditionally, in some ICI furnace designs, CO emissions can also occur because of furnace gas leaks between furnace tubes. The modif ication of combustion conditions aimed at reducing NO formation can result i n x incr eases in emissions of CO and hydrocarbons. This is because controls that reduce peak flam e tempe rature and delay the mixing of fuel and air for NO reduction can cause some incomplet e x co mbustion of the fuel. However, the actual impact of NO control retrofits often depends on th e x operating condit ions of the ICI boiler and the extent of improvements made to the combustion control system. In some cases, combustion NO control can also result in lower emissions of CO and othe r x unburned fuel emissions.7-9 Tables 7 - 37-10

Boiler type NO control x NO x

reduction, % CO emissions impact

Reference

Baseline/low NO , x ppm Average

change, % WT LNB 67 20-27/13-420 +800 2

LNB+SCA 66 35/60-166 +215 3 Cyclone NGR 65 30/30 0 4 Spreader stoker SCA (OFA) 31 231-252/429 +80 5 10 313/300 -4 6 26 0/49 NA a 1 FBC SCA 67 387-500/550-1,100 +86 7 NA = Not applicable. a TABLE 7-3. CO EMISSION CHANGES WITH NO CONTROL RETROFIT — x COAL-FIRED BOILERS7-11 Boiler type NO control x NO x

reduction, % CO emissions impact

Reference

Baseline/ low NO ,

x ppm Average

change, % PKG-FT FGR 59 16/13 -18 8

FGR 73 205/77 -62 9 FGR 71 205/192 -6.3 9 FGR 64 205/103 -50 9 FGR 74 205/84 -59 9 FGR 67 23/3 -87 8 FGR 73 105/7 -93 8 FGR 76 205/67 -67 9 FGR 69 205/49 -76 9 FGR 73 51/12 -76 10 LNB 82 9/9 0 11 LNB 53 51/24 -53 12 LNB 32 39/8 -80 13 LNB 78 856/30 -97 11 LNB NA a 342/30 -91 11 LNB NA 205/0 -100 11 LNB NA 9/9 0 12 PKG-WT FGR 74 205/62 -70 9

FGR 62 20/20 0 14 FGR 78 10/55 +450 14 FGR 53 205/205 0 9 FGR 73 14/22 +57 10 FGR 56 132/77 -42 10 LNB+FGR 55 60-125/2 -98 15 NA = Not applicable. a TABLE 7-4. CO EMISSION CHANGES WITH NO CONTROL RETROFIT — GAS- x FIRED BOILERS7-12 Oil/boiler type NO control x NO x

reduction, % CO emissions impact

Reference

Baseline/low NO , x ppm Average

change, % Distillate/WT FGR 68 4/46 +1,000 16

FGR 20 20/24 +20 14 Distillate/FT LNB 15 6/13 +120 13 Residual/WT FGR 4 20/20 0 14

FGR 30 10/145 +1,400 14 SCA (BOOS) 8 0/100 NA a 1 SCA (BOOS) 40 0/20 NA 1 NA = Not applicable. a TABLE 7-5. CO EMISSION CHANGES WITH NO CONTROL RETROFIT — OIL- x FIRED BOILERS

through 7-5 list changes in emissions of CO measured following the retrofit of selected controls. These data can also be found in Ap pendix A of this document. As shown in Table 7-3, LNB, SCA and NGR controls achieved NO reductions in the range of 10 to 67 percent, with lowest reductions reported for x t h e 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 NO in the spreader x stoker. Th e implementation of staged air will typically result in increased CO emissions

.

Data on the effect of NO controls on CO emissions from natural gas-fired ICI boilers were x limited to the retrofit of FGR, LNB and FGR+LNB controls. Bulk dilution of combustion mixtures with FGR is limited by flame instability and reduced flammability. Slightly higher7-137-14

excess air levels at high rates of FGR (typically 15 to 20 perce nt) coupled with improved burner settings often can result in decreased CO emissions in addition to lower NO

. x The data in T able 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 reducti on for these retrofits was nearly 70 percent. One of the boilers with an initial low CO level, 10 ppm, showed an increase in CO to 55 ppm whe n FGR was implemented. In another application, the CO level in the low-NO configuration increased x to only 22 p pm. Excess air is an important operational parameter that determines the level of C O emissi ons following the retrofit of NO controls. As suggested above, most of the reductions in C O x levels from these gas-fired boilers resulted from increases in excess air. Low-NO firing with LN B x 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.7-15 Figure 7-1. Changes in CO and NO emissions with reduced excess oxygen x for a residual-oil-fired watertube industrial boiler. 17

Figure 7-1 illustrates the dependence of CO emissions o n excess air. The rapid increase in CO is indicative of reduced fuel and air mixing that often accompanies low-NO combustion controls such x as LNB and SC A. Each boiler type has its own characteristic "knee" in CO versus 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 boil ers when NO emissions are reduced to strict levels. Also, the x 18 ABMA reco mmends 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 NO controls such as LNB, x FGR, and BOOS were applied, the CO emission levels increased in nearly all cases. The increase in7-16

CO, however, did not res ult in emission levels greater than 200 ppm, considered a safe limit for boiler operation. 7.1.3 Other Air Pollution Emissions Other air polluti on emissions that are a concern when NO controls are applied to ICI boilers x are: ammonia (NH ) and nitrous oxide (N O), unburned hydrocarbon (HC), particulate matter (PM), 3 2 and air toxic emissions. Ammonia and N O emissions are associ ated with the use of the SNCR process, 2 primarily, and with SCR to a lesser extent. With either urea or ammo nia hydroxide, unreacted ammonia emissions escape the SNCR temperature window resulting in direc t emissions to the atmosphere. When sulfur-be aring fuels are burned, these emissions also pose an operational concern because of cold end

corro sion and reduced heat transfer due to ammonium sulfate deposits. N O emissions are often a 2 byproduct of the SNCR reaction, and, because of this, some N O emissions are likely with the process. 2 In f act, the emissions have been reported with all reagents, particularly with urea reagents. Som e 20 urea-based SNCR processes offer proprietary additives to minimize N O and NH emissions. 2 3 SNCR vendo rs have paid particular attention to minimizing the breakthrough of unreacte d ammonia conside ring the potentially negative impacts on the operation of the boiler. This is typically accomplished by careful selection of the injection location, m ethod of injection to maximize mixing and

re sidence time, and by careful control of reagent use with boiler load and operating conditions

. Table 7 - 67-17 Fuel/boiler type NO reduction, x % Ammonia emission level, ppm Reference Coal/CFBC 57 <18 21 70 <10 21 30 <5 21 Wood/stoker 50 <40 21 60 <27 21 25 <21 21 47 <10 21 35 <21 21 50 <40 21 52 <30 21 MSW/mass 69 <25 21 48 <10 21 60 <10 21 75 22 22 70 17 21 41 <5 21 60 <7 21 60 12 22 60 <15 21 50 <21 21 58 22 22 Paper/PKG-WT 50 <10 21 Fiber/PKG-WT 50 <10 21 Test data are included in Appendix A. a TABLE 7-6. AMMONIA EMISSIONS WITH UREA-BASED

SNCR RETROFIT a7-18

lists NH slip levels rep orted for several retrofit installations. Boilers best suited for retrofit of SNCR

3 are FBC, bubbling and circulating designs. Stok ers and mass burning equipment have also been targets for applic ation of SNCR because combustion modifications have traditionally been limited an d ineffective. In sp ite of large NO reductions achieved in the units with the retrofit of SNCR, typically x in the range of 50 to 70 percent, NH slip levels have been reported mostly in the range of less than 30 3 ppm, and often less than 20 ppm. Monitor ing of NH emissions is often difficult because direct on line 3 me asurement methods are only now being introduced into the market place and are often ver y expensive, therefore not a part of the monitoring system at these facilities.7-19 Figure 7-2. Pilot-scale test results, conversion of NO to N O x 2 (NO = 300 ppm, N/NO = 2.0). i 20

Pilot-scale and f ield tests have clearly shown that a portion of the NO reduced by the SNCR x process is merely transfor med into N O emissions. Figure 7-2 illustrates the amount of N O produced 2 2 in relation to the amount of NO reduction with three types of SNCR chemicals: cyanuric acid, urea, x and ammonia. These test results obtained in a pilot-scale facility, show that nearly 30 percent of the NO reduced can actually be transformed to N O with urea, less when using ammonia. Cyanuric acid x 2 is not a preferred chemical because of its obvious disadvantage in N O formation compared with the 2 other two more popular SNCR chemicals. In addition, cyanuric acid is 6 t o 8 times more expensive than

urea.7-20 Increases in H C, PM and air toxic emissions are primarily of concern with the application of combusti on 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 NO x7-21

contr ols are implemented. HC emissions are the result of poor combustion conditions such a s inefficient fuel-air mixing, low temperatures, and sh ort residence time. These emissions are most often p r eceded by large increases in CO, soot, and unburned carbon content. Thus, by limiting CO, smoke and unburned carbon in the flyash, HC em issions are also suppressed, and changes with retrofit of NO x controls become imperceptible. A comprehensive test program in the mid-1970s reported on the effect of combustio n modifica tion controls for industrial boilers. The results of this program revealed the following trends with respect to filterable PM : 23 LEA reduced PM emissions on the order of 30 percent SCA, including BOOS, increased PM by 20 to 95 percent Burner adjustments and tuni ng had no effect on PM. However, the lower CO emission levels generally achieved with these adjustments would tend to lower PM as well. FG R 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 hav e improved combustion ai r 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 pea k temperatures that are needed to suppress NO formation. x 7.2 SOLID WASTE DISPOSAL NO red uction techniques that have a potential impact on the disposal of solid waste ar e x 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 ca n 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 d id not exist before. The environmental and economic impact of this requirement cannot be easily quantified. An increase i n flyash disposal can also occur with the use of flue gas treatment NO controls x such as SNCR a nd SCR on coal-fired boilers. Both of these control options use ammonia-base d reagents to reduce NO to N and water. Excessi ve use of reagent can result in ammonia slip emissions, 2 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 likelihood7-22

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 i s used. With continuous use, the catalyst material will become less active. That is, th e ef ficiency of the catalyst in reducing NO will gradually deteriorate. When this happens, the catalyst x materia l must be replaced. This is often accomplished by replacing layers of individual module s star ting with the most exposed layer (at the inlet), until all the catalyst 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 ho urs, for oil and coal applications. However, some catalysts have shown longer life, 8 to 10 years, when applied on clean-burning fuel. 24 The dis posal 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 an d its amendments. For example, vanadia and titania catalysts are considered hazardou s material. However, recent industry trends have shown that these material are readily regenerable. In fact, many catalyst vendors recycle this material thus avoid ing any disposal problem for the user. Some of the catalysts, especially those that use rare earth materi al 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 NO controls, especially SNCR. The use associated with WI or SI injection x 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 hig h emissions of CO and high thermal efficiency loss. Therefore, a 50 MMBtu/hr (15 MWt) boiler would

use app roximately 600,000 gal (2.2 million L) of water per year when operating with a 50 percen t capacity factor. An increase in water use and wastewater disposal requirement could result from the use o f SNCR techniques , either urea or ammonia based. This is because ammonia slip when combined with SO in the flue gas will form corrosive salts that deposit on heat transfer surfaces such as air heaters. 3 These depos its must be removed to minimize pressure drop and material corrosion. Air heater aci d 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 air7-23

heater washing has no t 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 consum ption associated with NO control techniques for ICI x boilers. Energy con sumption can come in various forms: a boiler fuel consumption penalty caused by reduced thermal or combustion efficiency; an increase in electrical power to operate fans and pumps;

an in crease in fuel consumption due to reheat of flue gas; an increase in energy for treatment an d 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 complet e comb ustion is the most noted of these energy savings techniques. Others include the installation o f 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 NO reduction as well. x 7.4.1 Oxygen Trim (OT) ICI boilers are operated at various excess air level s, 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 regardl ess of fuel burned and method of burning because fuel and air do not perfectly mix and th e residence time in the combustion cha mber 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 meth od of burning determines the minimum amount of excess air required for safe and nea r complete combustion. For example, the following minimum excess O levels are considered typical 2 for these fuels :

25 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. This 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 equipm ent improvements can be readily made that reduce the amount of excess air resulting in a thermal efficiency improvement and reduced NO emissions without compromising the safety of the x operation of the unit. Qualified boiler and burner engineers and consultants can upgrade ke y components of the combustion ai r control system, including the installation of monitors for O and CO 2 levels in the stack.E ( T 70 ) 63

. 1 x % EA

89

. 5

7-24 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. 25

(7-1) Figure 7-3 illustrates the efficiency improvement that can be obtained by reducing exces s combustion air in ICI boilers. For example, a 10-percent reduction in excess air (say, from O of 3.5 2 to 2.0 percent) would result in an efficiency improvement of approximately 0.6 percent 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 ft of natural 3 gas per year or about $13,600/yr savings . Algebraically, the relationship between boiler efficiency and excess air can be expressed as follows : 26

Where: T = stack temperature in F % EA = the change in percent excess airE CO 3 , 682 x 1 % EA

89

. 5

7-25 (7-2) The r eduction 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 bur ned, and in unburned carbon in the flyash, when coal is burned. Increased e missions of CO have a detrimental effect on the efficiency, as illustrated in Figure 7-4. For example, the example boiler describe above opera ting at 2.0 percent oxygen might have an increase in CO to about 350 ppm, measured on a dry basis i n 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 incre ased CO must be considered. The objective of boiler/burner tuning, however, is to r educe 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 a s follows :

26

Where: T = stack temperature in F % EA = the change in percent excess air 7.4.2 Water Injection/Steam Injection (WI/SI) The injection of water or steam i n the burner zone to reduce peak flame temperature and NO x will ha ve a detrimental impact on the efficiency of the boiler. Figure 7-5 illustrates the relationshi p 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. The amount of water injected is typically in the range of 20 t o 27 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 NO reduction efficiency is also lower. x 7.4.3 Staged Combustion Air (SCA) The operation of an ICI boiler with staged combustion air, whether BOOS or OFA, will likely not re quire additional energy. Taking selected burners out of service will not influence the ai r 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.7-26 Figure 7-4. Unburned carbon monoxide loss as a function of excess O 2

and carbon monoxide emissions for natural gas fuel. 287-27 Figure 7-5. Energy penalty associated with the use of WI or SI for NO x

control in ICI boilers. 7.4.4 Low-NO Burners (LNBs) x Minor or no increases in energy consumption are anticipated with the retrofit of LN B 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 of7-28

higher gas velocities and more register control. This increase in pressure drop will tend to increase fan powe r somewhat, or compensate for the reduction in energy consumption at lower combustion ai r levels. 7.4.5 Flue Gas Recirculation (FGR) The retrofit of FGR requires the installati on 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 - 67-29 Figure 7-6. Estimated energy consumption in FGR use.( 0

. 5 ) ( 8 , 760 hr / yr ) ( 0

. 0013558 kW

/ ft lb ) ( FGR ft 3 / s ) ( P lb

kW / MMBtu / hr × 250 MMBtu / hr × 0

. 5 × 8 , 760 hr / yr 319 , 740

7-30 (7-3) illustrates the calculated power requirements with the use of FGR. The relationship between power consumption and FGR rate is based on the following equation:

Where: 0.5 = The capacity factor

P = Assumed to be 10 inches of water to account for efficiency loss Some additional energy penalty w ill 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 pret reatment and injection of ammoniabased 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 DeNO x installations, anhydrous ammonia is store d in liquid form under pressure. The liquid ammonia must be vaporized with some heat, mixed wit h 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. I f steam is used, less electricity is needed but power co nsumption must take into consideration the amount of steam used. Data supplied by Exxon suggest th at the amount of electricity needed for the Thermal DeNO x Process is on the order of 1.0 to 1.5 kW for each MWt of boiler capacity (or 0.29 t o 0.44 kW/ MMBtu/hr) when using compressed air as the carrier medium. The actual amount o f 29 electrici ty will depend on the baseline NO emission level, the NH /NO ratio used, and the NO x 3 x reduction target. Therefore, a 250 MMBtu/hr (73 MWt) boiler operating with a capacity factor of 0.5 will use approximately:
(7-4)

which c orresponds 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 lb/hr/MWt. I n general, ammonia is most economically inje cted using compressed air rather than steam. Data supplied by Nalco Fuel Tech suggest that th e
ure a-based SNCR process uses much lower levels of electricity than either ammonia-based SNCR or7-31

SCR. Typical aux iliary 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 of SCR systems consists of three principal areas: (1) th e
e n ergy 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 ther mal efficiency loss associated with maintaining the catalyst reactor temperature within the specifications for optimum performance at variable boiler loa d. The energy to store, pretreat, and inject t h e 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- 77-32 Figure 7-7. Estimated increase in energy consumption with SCR pressure drop.( P in H 2 O ) 0

. 0361 lb

in 2 in H

2 O 144 in 2

ft 2 Q ft 3

s 0

. 5 0

. 85 ×

7-33 (7-5)

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 illustrates the energy consumption associated with the additional pressure drop. The relationshi p between energy consu mption and pressure drop across the catalyst is based on the following equation:

Where: P = Pressure drop across catalyst, in inches of water Q = Flue gas flowrate in actual ft /s 3 Finally, the third potentially large source of energy consumption is the result of increased flue gas tempera ture 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 1.27-34

percent for an increase in flue gas temperature of 50 F. From an efficie ncy 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.7-35

7.5 REFERENCES FOR CHAPTER 7 1. Cato, G. A., et al. (KVB, Inc). Field Testing: Application of Combustion Modifications t o Control Pollutant Emissions from Industrial Boilers—Phase II. Publication No

. EPA-600/2-72-086a. Prepared for the U.S. Environmental Protection Agency. Researc h Triangle Park, NC. April 1976.
2. Sc hild, V., et al. (Black Hills Power and Light Co.). Western Coal-Fired Boiler Retrofit for Emissi ons 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 Envir onmental Research Corporation). Field Evaluation of the Di stributed Mixing Burner. Proceedings: 1985 Symposium on Stationary Combustion NO x Control. Publication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electri c Power Research Institute. Palo Alto, CA. 1989.
4. Fa rzan, H., et al. (Hitachi Zosen Corporation). Three Stage Pulverized Coal Combustio n Sy stem for In-Furnace NO Reduction. Proceedings: 1985 Symposium on Stationar y x Co mbustion NO Control. Publication No. EPRI CS-5361. U.S. Environmental Protectio n x 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. Enviro nmental 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—Ef fects of Combustion Modification NO Control on Emissions—Site A. Repor t x No. TR-79-25/EE. Acurex Corporation. Mountain View, CA. August 1979.
7. Bijvoe t, U. H. C., et al. (TNO Organization for Applied Scientific Research). Th e Characteri zation of Coal and Staged Combustion in the TNO 4-MWth AFBB Researc h Facili ty. Proceedings of the 1989 International Conference on Fluidized Bed Combustion

. The American Society of Mechanical Engineer s/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 Sout h 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 Brook s FGR Experience. September 14, 1992.
10. Letter an d attachments from Stoll, F. R., Hugh Dean & Co., Inc., to Briggs, A., Acure x Environmental Corporation. Cleaver-Brooks FGR. April 5, 1993.
11. Kesselr ing, J. P., and W. V. Krill (Alzeta Corporation). A Low-NO Burner for Gas-Fire d x Firetube Boilers. Proceedings: 1985 Symposium on Stationary Combustion NO Control

. x Pub lication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electric Powe r Research Institute. Palo Alto, CA. January 1986.7-36

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 NO Bu rner Retrofits: Case Studies. Technical Paper No. 91-10.22. Air and Wast e

x Management Association. Pittsburgh, PA. June 1991.
14. Office of Air Quality Planing and Standards. Ov erview of the Regulatory Baseline, Technical Basis, and Alternative Control Levels for Nitrogen Oxides (NO ) Emissions Standards fo r x Smal l Steam Generating Units. Publication No. EPA-450/3-89-13. U.S. Environmenta l Protection Agency. Research Triangle Park, NC. May 1989.
15. Roman, V. (KVB, Inc.). Compliance Test Repor t: Oxides of Nitrogen and Carbon Monoxide Emissi ons 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 combustio n equipment. KVB, Inc., Irvine, CA. 1977.
17. Heap, M. P., et al. Reduction of Nitrogen Oxide Emissions fro m Package Boilers. Publication No. EPA-600/2-77-025, NTIS-PB 269 277. January 1977.
18. Technical R eview Group, State of California. A Suggested Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial Instituti onal & Commercial Boilers, Steam Generators & Process Heaters. April 29, 1987. p. 18.
19. Am erican Boiler Manufacturers Association (ABMA). Guidelines on Carbon Monoxid e Emissions for Oil- and Gas-Fired Industrial Boilers. 1991. p. 4.
20. Muzio, L. J., et al. (Fossil Energy Research Corporation). N O Formation in Selectiv e 2 Non-Catalytic NO Reducti on Processes. Proceedings: 1991 Joint Symposium on Stationary x Combustion NO Control — EPA/EPRI. March 1992. x 21. Let ter and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C., Acure x Environmental Corporation. NOxOUT Urea-Based SNCR Performance. June 9, 1992.
22. Hofmann, J. E., et al. (Nalco Fuel Tech). NO Control for Munici pal Solid Waste Combustors. x Technical Paper No. 90-25-2. Air and Waste Manage ment Association. Pittsburgh, PA. June 1990.
23. Cato, G. A., et al. (KVB Engineering Inc.). Field Testing: Application of Combustio n Modifications to Control Pollutant Emissions From Industrial Boilers — Phase II. Publication No. EPA-600/2-76-086a. April 1976. p. 192.
24. Smith J. C., Resp onse 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 Industria l Boiler Performance Improvement. Publication No. EPA-600/8-77-003a. January 1977. p. 44.7-37

26. Coen Company. Sales Meeting Proceedings of 1991.
27. Performance Test Codes (ASME). Boiler Efficiency. PTC 4.1a. 1964.
28. Payne, W. F. Efficient Boiler Operations Sourcebook. Fairmont Press, Atlanta, GA. Ma y 1985. p. 61.
29. Letter and attachments from Haas, G. A., Exxon Research and Engineering Company, t o Jordan , B., U.S. EPA, Office of Air Quality Planning and Standards, Durham, NC. NO x 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 Planni ng and Standards, Durham, NC. Comments on Draft Alternative Control Techniques Document. October 27, 1993. p. 5.A-1 APPENDIX A. ICI BOILER BASELINE EMISSION DATA
This appendix lists baselin e NO , CO, and unburned THC data for more than 200 ICI boilers. x The data were obtained primarily from published technical papers and EPA documents summarizing data from nume rous test programs. Boiler data are listed by fuel type, with the exception of FB C boil ers which are listed separately. More detailed data may be obtained by referring directly to th e individual references.A-2A-13

REFERENCES FOR APPENDIX A
1. Emissions Assessment of Conventional Stationary Combustion Systems, Volume V: Industrial Combu stion Sources. Publication No. EPA-600/7-81-003c. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. 1981.
2. Technology Assessment Report for Industrial Boiler Applications: NO Combustion Modification. x Publication No. EPA-600/7-79-178f. U.S. Environmental Protection Agency. Research Triangle Park, NC. December 1979.
3. Emiss ions Assessment of Conventional Stationary Combustion Systems, Volume IV : Commercial/Insti tutional Combustion Sources. Publication No. EPA-600/7-71-003c. Prepared by TR W, 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 fo r Ni trogen Oxides Emission Standards for Small Steam Generating Units. Publication No. EPA450/3-89-1 3. Office of Air Quality Planning and Standards. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. May 1989.
5. Field Tests of Industrial Stoker Coal-Fired Boilers for Emission Control and Efficienc y Impro vement—Site E. Publication No. EPA-600/7-80-064a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. March 1980.
6. Field Tests of Industrial Stoker Coal-Fired Boilers for Emission Control and Efficienc y Improvement—Site H. Publication No. EPA-600/7-80-112a. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. May 1980.
7. Industrial Boiler Combustion Modification NO Controls, Volume I: Environmental Assessment. x Publication No. EPA-600/7-81-126a. U.S. Envi ronmental Protection Agency. Research Triangle Park, NC. July 1981.
8. Letter from LeBlanc, B., Riley Stoker Corp., to Sanderford, E ., MRI. NO Emissions from Utility x and Industrial Boilers. April 15, 1992.
9. Letter from Co ffey, A., Cleaver Brooks, to Herbert, E. L., Herbert & Conway, Inc. Cleave r Brooks FGR Experience. September 14, 1992.
10. Letter from Eichamer, P., Exxon Chemical Co., to Snyder, R., MRI. ACT NO Data. July 10, x 1992.
11. Cleaver Brooks System 20 FGR. Cleaver Brooks Co. 1993.
12. NO Emiss ion Factors for Wood-Fired Boilers. Publication No. EPA-600/7-79-219. U.S

.

x Environmental Protection Agency. Research Triangle Park, NC. September 1979.
13. Lett er and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C., Acure x Environmental Corp. NOxOUT Urea-Based SNCR Performance. June 9, 1992.
14. McGav in, 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.A-14

15. Dahl, J. Agricultural Waste Fueled Energy Projects. Presented at the Second CIBO Alternat e Fuels Conference. Arlington, VA. May 1989.
16. Makansi, J. and R. Schwieger. Fluidized Bed Boilers. Power Magazine. May 1987.
17. Ma rlair, 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 H istory. 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. Pre sented at the 10th International Conference on Fluidized Bed Combustion. San Francisco, CA. May 1989.
20. Bijv oet, U. H. C., et al. Characterization of Coal and Staged Combustion in the TNO 4 MW t AFBB Research Facility. Presented at the 10th International Conference on Fluidized Be d Combustion. San Francisco, CA. May 1989.
21. Tavoulareas, S., et al. EPRI's Res earch 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 Be d Com bustor. Presented at the 10th International Conference on Fluidized Bed Combustion. San Francisco, CA. May 1989.
25. Hutchinson, B. The Pyrofl ow 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. Worl dwide 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 CF B Boiler. Presented at the 10th International Conference on Fluidized Bed Combustion. Sa n Francisco, CA. May 1989.
28. Studley, B. and D. Parham. Foster Wheeler Mt. Carmel Anthracite Culm-Fired CFB Stea m Gener ation 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 Fluid ized Bed Combustion. San Francisco, CA. May 1989.A-15

30. Belin, F., et al. Lauhoff Grain Coal-Fired CFB Boiler—Design, Startup, and Operation

. Presented at the Sixth Annual CIBO Fluidized Bed Conference. Ha rrisburg, 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 Foste r Wheele r. Presented at the Fifth Annual CIBO Fluidized Bed Conference. Sacramento, CA

. December 1989.
33. Tang, J. and F. Engstrom. Technical Assessment on the Ahlstrom Pyroflow Circulating an d Conventional Bubbling FBC System. Presented at the 9th International Conference on Fluidized Bed Combustion. Boston, MA. May 1987.
34. Dar ling, S. L., et al. Design of the Scott Paper CFB. Presented at the 9th Internationa l 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. Ma y 1989.
36. Emissio ns and Efficiency Performance of Industrial Coal Stoker Fired Boilers. Publication No. EPA-600/7-81-111a. July 1981.B-1 APPENDIX B. CONTROLLED NO EMISSION DATA x

This appendix lists controlled emissions data for boilers used in the ICI sector. Wher e appropriate, data for small utility boilers and representat ive pilot-scale units are also included. The data

were compiled primarily from technical reports, EPA documents, compliance records, an d manufacturers' literature, as listed in the references at the end of this appendix. Additional low-NO x performance data s pecific to low-NO burners (LNB) marketed by Coen Company, of California, and x Ta mpella Power Corporation, Faber Burner Division, of Pennsylvania, are in Appendix C. Boile r emiss ions data are listed by fuel type and whether the NO control method used was a combustio n x modification or a flue gas treatment method.B-2B-24

REFERENCES FOR APPENDIX B
1. Vats ky, J. (Foster Wheeler Energy Corporation). NO Control: The Foster Wheeler Approach. x Proceedings: 1989 Symposium on Stationary Combustion NO Control. Publication No. EPRI x GS-6423. U.S. Environmental P rotection Agency/ Electric Power Research Institute. Palo Alto, CA. July 1989.
2. Vatsky, J., and E. S. Schindler (Foster Wheeler Energy C orporation). Industrial and Utility Boiler Low NO Control Update. Proceedings: 1987 Symposium on Stationary Combustion NO

x x Control. Publication No. EPRI CS-536 1. 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 NO Pulverized Coal Burner

. x Foste r Wheeler Energy Corporation. Clinton, NJ. Presented at the 1991 Joint Symposium o n Stationary Combustion NO Control—EPA/EPRI. Washington, D.C. March 25-28, 1991. x 4. Buchs, R.A., et al. (Kerr-McGee Chemical Corpor ation). Results From a Commercial Installation of L ow NO Concentric Firing System (LNCFS). ABB Combustion Engineering Services, Inc.

x Windsor, CT. 1991.
5. Schi ld, V., et al. (Black Hills Power and Light Co.). Western Coal-Fired Boiler Retrofit fo r Emissions Control and Efficiency Improvement. Technical Paper No. 91-JPGC-FACT-7

. American Society of Mechanical Engineers. New York, NY. 1991.
6. Letter for Lebla nc, B., Riley Stoker Corp., to Sanderford, E., MRI. NO Emissions from Utility x and Industrial Boilers. April 15, 1992.
7. Lim, K. J ., et al. (Acurex Corp.) Industrial Boiler Combustion Modification NO x Controls—Volume I, Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S

. Environmental Protection Agency. Research Triangle Park, NC. July 1981.
8. Carter, W. A. Thirty Day Field Tests of Industrial Boiler Combustion Modifications. KVB Inc. Irvine, C A. Proceedings of the Joint Symposium on Stationary Combustion NO Control

. x Publicat ion No. IERL-RTP-1085. U.S. Environmental Protection Agency. Research Triangl e Park, NC. October 1980.
9. Narit a, T., et al. (Babcock Hitachi K.K.). Development of the Low NO Burner For th e x Pu lverized Coal Fired In-Furnace NO Reduction System. Proceedings: 1985 Symposium o n x St ationary Combustion NO Control. Publication No. EPRI CS-4360. U.S. Environmenta l x Protection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
10. Penterson, C.A. (Riley Stoker Corp.) Controlling NO Emis sions to Meet the 1990 Clean Air Act. x Technical Paper No. 91-JPGC-FACT-11. American Society of Mechanical Engineers. Ne w York, NY. 1991.
11. Fols om, B., et al. (Energy and Environmental Research Corporation). Field Evaluation of th e Distribut ed Mixing Burner. Proceedings: 1985 Symposium on Stationary Combustion NO xB-25

Control. Publication No. EPRI CS-436 0. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
12. Far zan, H., et al. (Babcock & Wilcox Company). Pilot Evaluation of Reburning for Cyclon e Boiler NO Control. Proceedings: 1989 Symposium on Stationary Combustion NO Control

.

x x Publication No. EPRI GS-6423. U.S. Environmental Protecti on Agency/ Electric Power Research Institute. Palo Alto, CA. July 1989.
13. Okigami, N ., et al. (Hitachi Zosen Corporation). Three-Stage Pulverized Coal Combustio n System for In-Furnace NO Reduction. Proceedings: 1985 Sym posium on Stationary Combustion x NO Control. Publication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electri c x Power Research Institute. Palo Alto, CA. January 1986.
14. Araoka, M., et al. (Mitsubishi Heavy Industries, Inc.). Application of Mitsubishi "Advance d MACT" In-Furnace NO Removal Process at Tai o Paper Co., Ltd. Mishima Mill No. 118 Boiler. x Proceedings: 1987 Symposium on Stationary Combustion NO Control. Publication No. EPRI x CS-5361. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. August 1987.
15. Gol dberg, P. M., and E. B. Higginbotham. Field Testing of an Industrial Stoker Coal-Fire d Boiler—Effects of Combustion Modification NO Control on Emissi ons—Site A. Report No. TR- x 79-25/EE. Acurex Corporation. Mountain View, CA. August 1979.
16. Langsjoen, P. L., et al. (KVB, Inc.). Field Tests of Industrial Stoker Coal-Fired Boilers fo r Emissions Contro l and Efficiency Improvement—Site C. Publication No. EPA-600/ 7-79-130a. Pr epared for the U.S. Environmental Protection Agency, U.S. Department of Energy, and th e American Boiler Manufacturers Association. Washington, D.C. May 1979.
17. Gabrielson, J . E., et al. (KVB, Inc.). Field Tests of Industrial Stoker Coal-Fired Boilers fo r Emissions Control a nd Efficiency Improvement—Site D. Publication No. EPA-600/ 7-79-237a. Pr epared for the U.S. Environmental Protection Agency, U.S. Department of Energy, and th e American Boiler Manufacturers Association. Washington, D.C. November 1979.
18. Langsjoen, P. L., et al. (KVB, Inc.). Field Tests of Industrial Stoker Coal-Fired Boilers fo r Emissions C ontrol and Efficiency Improvement—Site F. Publication No. EPA-600/ 7-80-065a. Pr epared for the U.S. Environmental Protection Agency, U.S. Department of Energy, and th e American Boiler Manufacturers Association. Washington, D.C. March 1980.
19. Cato, G. A., et al. (KVB Inc). Field Testing: Application of Com bustion Modifications to Control Polluta nt Emissions from Industrial Boilers—Phase II. Publication No. EPA-600/2-72-086a

. Prepared fo r the U.S. Environmental Protection Agency. Research Triangle Park, NC. Apri l 1976.
20. Malon ey, K. L., et al (KVB, Inc.). Low-sulfur Western Coal Use in Existing Small an d In termediate Size Boilers. Publication No. EPA-600/7-78-153a. Prepared for the U.S

. Environmental Protection Agency. Research Triangle Park, NC. July 1978.B-26

21. Malon ey, K. L. (KVB, Inc.). Combustion Modifications for Coal-Fired Stoker Boilers

. Proceedings of the 1982 Joint Symposium on Stationary Combustion NO Control. Publication x No. EPRI CS-3182. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. July 1983.
22. Quartucy, G. C., et al. (KVB, Inc). Combustion Modification Techniques for Coal-Fired Stoker Boilers. Proceedings: 1985 Symposium on Stationary Combustion NO Control. Publication No. x EPRI CS-4360. U.S. En vironmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
23. Hil tunen, M., and J. T. Tang. NO Abatement in Ahlstrom Pyroflow Circulating Fluidized Bed x Boilers. Ahlstrom Pyropower Corp. Finland.
24. Linneman, R. C. (B. F. Goodrich Chemical). B. F. Goodrich's FBC experience. Proceedings : 1988 Seminar on Fluidized Bed Com bustion Technology for Utility Opns. Publication No. EPRI GS-6118. Electric Power Research Institute. Palo Alto, CA. February 1989.
25. Leckner, B., and L. E. Anand (Chalmer s University, Sweden). Emissions from a Circulating and Stationary Fluidized Bed Boiler: A Comparison. Proceedings of the 1987 Internationa l Conferenc e on Fluidized Bed Combustion. The American Society of Mechanica l Engineers/Electric Power Research Institute /Tennessee Valley Authority. New York, NY. 1987.
26. Jones , O. Initial Operation of Conoco's South Texas Fluidized Bed Combustor. Conoco, Inc

. Houston, TX. Presented at the 10th Energy Technology Conference.
27. Sadowski, R. S., and A. F Wormser (Wormser Engineering, Inc.). Operating Experience with a Coal-Fired Two-Stage Fluidized Bed Combustor in an Industrial Plant Setting. Proceedings of the American Power Conference. Volume 45. 1983.
28. Bijvoet , U. H. C., et al. (TNO Organization for Applied Scientific Research). Th e Characterizati on of Coal and Staged Combustion in the TNO 4-MWth AFBB Research Facility. Proceedings of the 198 9 International Conference on Fluidized Bed Combustion. The American Society of Mechanical En gineers/Electric Power Research Institute/Tennessee Valley Authority. New York, NY. 1989.
29. Hasegawa, T., et al. (Mitsubishi Heavy Industri es, Ltd.). Application of AFBC to Very Low NO x Coal Fired Industrial Boiler. Proceedings of the 1989 International Conference on Fluidized Bed Combustion. The American Society of Mechanical Engineers/Electric Power Researc h Institute/Tennessee Valley Authority. New York, NY. 1989.
30. Letter from Co ffey, A., Cleaver Brooks, to Herbert, E. L., Herbert & Conway, Inc. Cleave r Brooks FGR Experience. September 14, 1992.
31. Memorandum from Sanderford E., MRI, to Neuffer, W. , U.S. EPA. Data for Southern California Low-NO Applications. Attachment 4. February 18, 1992.

xB-27

32. Memoran dum from Votlucka, P., South Coast Air Quality Management District, to File/Rul e 1146. Proposed Rule 1146—Trip to Beverly Hills Hilton to Inspect the Boiler Room. February 1987

. 33. Memorandum from Sanderford E., MRI to Neuffer, W., U.S. EPA. Data for Southern California Low-NO Applications. Attachment 6. February 18, 1992.

x 34. Statewide Technical Review Group. Technical Support Document for Suggested Control Measure for the Control of Emissions of Oxides of Nitroge n 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 Qualit y Management District. Results from Boiler Manufacturer's Test of a Gas-Fired Boiler With and Without FGR. October 14, 1987.
36. Cleaver Brooks Division. NO versus Recirculation Rate—200 hp Gas Firing—R&D Lab Tests. x December 1987.
37. Cleaver Brooks Division. NO versus Recirculation Rate—350 hp Gas Firing—R&D Lab Tests. x December 1987.
38. Offic e of Air Quality Planning and Standards. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control Levels for Nitrogen Oxides (NO ) Emissions Standards for Small x Steam Ge nerating Units. Publication No. EPA-450/3-89-13. U.S. Environmental Protectio n Agency. Research Triangle Park, NC. May 1989.
39. Letter and attachments from Stoll, F. R., Hugh Dean & Co., Inc., to Briggs, A., Acure x Environmental. Cleaver-Brooks FGR. April 5, 1993.
40. Kes selring, J. P., and W. V. Krill (Alzeta Corporation). A Low-NO Burner for Gas-Fire d x Firetube Boilers. Proceedings: 1985 Symposium on Stationary Combustion NO Control

. x Publication No. EPRI CS-4360. U.S. Environmental Prot ection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
41. Roman, V. (KVB, Inc.). Compliance Test Report: Oxides of Nitrogen and Carbon Monoxid e 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.
42. LaRue, A. (Babcock & Wilcox). The XCL Burner—Latest Developments and Operatin g Experience. Proceedings: 1989 Symposium on Sta tionary Combustion NO Control. Publication x 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.B-28

44. Yang, S. C., et al. Development of Low NO Gas Burners. Energy and Resources Laboratories x (ERL), In dustrial Technology Research Institute. Taiwan. Presented at the 1991 Join t Symposium on Stationary Combustion NO Control—EPA/EPRI. Washi ngton, D.C. March 25-28, x 1991.
45. Potts, N. L., and M. J. Savoie (U. S. Army Construction Engineering Research Laboratory). Low NO Burner Retrofits: Case Studies. Technical Pap er No. 91-10.22. Air and Waste Management x Association. Pittsburgh, PA. June 1991.
46. Buening, H. J. (KVB, Inc.). Testing of Low-NO Combustion Retr ofit—Boiler No. 3. Report No. x KVB71-60451-2008. Prepared for IBM, Inc., San Jose, CA. January 1985.
47. Larsen, L. L., and W. A. Car ter (KVB, Inc.). Testing of Low-NO Combustion Retrofit—Boiler x 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 Burne r Desi gn developments for NO Control. Proceedings: Third Annual NO Control Conference

. x x Council of Industrial Boiler Owners. Burke, VA. February 1990.
49. Technical memorandum from Woodward, R ., Hague International. Results of Emissions Testing of Low-NO Burner Installed in Hospital Boiler. January 1988.

x 50. Buening , H. J. (KVB, Inc.). Testing of Low-NO Combustion Retrofit—VA Hospital

— x 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-NO Retrofits. February 6, 1992.

x 52. Roman, V. (KVB, Inc.). Compliance Test Report: Oxides of Nitrogen and Carbon Monoxid e Emission s 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 NO and CO Emission Results. Coen Company

. x Distributed at t he Fifth Annual CIBO NO Control Conference. Long Beach, CA. February 10, x 1992.
54. Letter and attachments for Marx, W., CIBO, to Se u, S., Acurex Environmental Corporation. NO x Control Technology Survey. June 12, 1992.
55. Hunter, S. C., et al. Application of Combustion Modifications to Industrial Combustio n Equipment. KVB, Inc., Irvine, CA. 1977.
56. Oppenberg, R. Primary Measures Reducing NO Levels in Oil- and Gas-Fired Water Tub e x Boilers. Report No. 176. Deutsche-Babcock. Germany. September 1986.
57. Suzuki, T., et al. (Kobe Steel). Development of Low-NO Combustion for Industrial Application. x Proceedings: 1985 Symposium on Stationary Combustion NO Control. Publication No. EPRI xB-29

CS-4360. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. January 1986.
58. Castaldi ni, C., et al. (Acurex Corp.). Environmental Assessment of an Enhanced Oil Recovery Steam Generator Equipped with a Low NO Burner. Acurex Report No. T R-84-161/EE. Prepared x for the U.S. Environmental Protection Agency. Research Triangle Park, NC. January 1985.
59. McDannel, M. D., and T. D. Guth (KVB, Inc.) . NO Control Technology Applicable to Oil Field x Steam Gen erators. 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: Secti on 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 Tes ting, Taft, California—Prototype Low NO Burner Tests: Section 26-C, Unit 50-1. Report No. TR-7 9-26/EE. Acurex Corporation.

x Mountain View, CA. September 1979.
62. Anderson, D. F., and T. Szytel (Grace Petroleum Corp.). NO Reduction Methods for California x Steam Generators by Applied Technology. Paper No. SPE 12772. Society of Petroleu m Engineers. Dallas, TX. April 1984.
63. Br inkmann, P. E., and M. K. Poe (Mobil Exploration and Producing U.S., Inc.). NO Emission x Reduction from Gas Fired Steam Generators. Technical Paper No. 89-19.6. Air and Wast e Management Association. Pittsburgh, PA. June 1989.
64. Nutcher, P. High Temperature Low NO Burner System s for Fired Heaters and Steam Generator. x Proces s Combustion Corp. Presented at the Pacific Coast Oil Show and Conference. Lo s Angeles, CA. November 1982.
65. 1986 Pollu tant Survey (TEOR steam generators). Kern County Air Pollution Control District

. November 1986.
66. Abbasi, H., et al. Use of Natural Gas f or NO Control in Municipal Waste Combustion. Institute x of Gas T echnology. Chicago, IL. Presented at the 1991 Joint Symposium on Stationar y Combustion NO Control—EPA/EPRI. Washington, D.C. March 25-28, 1991. x 67. Penter son, C.A., et al. (Riley Stoker Corporation). Reduction of NO Emissions From MS W x Combu stion Using Gas Reburning. Proceedings: 1989 Symposium on Stationary Combustio n NO Control. Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric x Power Research Institute. Palo Alto, CA. July 1989.
68. Lisauskas, R. A., et al. (Riley Stoker Corporation). Status of NO Control Technology at Riley x Stoker. Proceedings: 1989 Symposium on Stationary Combustion NO Control. Publication No. x EPRI GS-6423. U.S. Envir onmental Protection Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.B-30

69. Letter and attachments from Haas, G. A., Exxon Research and Engineering Co., to Jordan, B. C., U.S. EPA. NO Control Technologies Questionnaire. February 18, 1993. x 70. Ka ras, J., and D. Goalwin (Bay Area Air Quality Management District). NO Emissions fro m x Refin ery and Industrial Boilers and Heaters. Technical Paper No. 84-42.6. Air and Wast e Management Association. Pittsburgh, PA. June 1984.
71. Hofmann , J. E. (Nalco Fuel Tech). The NOxOUT Process for Control of Nitrogen Oxides

. Proceeding s: Third Annual NO Control Conference. Council of Industrial Boiler Owners

. x Burke, VA. February 1990.
72. Ta ng, J. T. (Pyropower Corporation). NO Control in Ahlstrom Pyroflow Boiler. Proceedings: x Second Annual NO Control Conference. Council of Industrial Boiler Owners. Burke, VA

. x February 1989.
73. Letter and attachments from Haas, G., Exxon Research and Engineering Company, to Seu, S. , Acurex Environmental Corporation. Ther mal DeNO Operating Experience Information. March x 1992.
74. Lett er and attachments from Pickens, R. D., Nalco Fuel Tech, to Castaldini, C., Acure x Environmental Corporation. NOxOUT Urea-Based SNCR Performance. June 9, 1992.
75. Bodylski, J. A., and Haas, G. A. The Selective N oncatalytic Reduction Process: Experience with the Exxo n Thermal DeNO Process at Two Circulating Fluidized Bed Boiler Commercia l x Applica tions. Presented at the American Flame Research Committee's 1992 Fall Internationa l Symposium on Emissions Reductions and Energy Conser vation. Cambridge, MA. October 1992. pp. 3-5.
76. Let ter and attachments from Valentine, J., Fuel Tech Inc., to Torbov, S., Acurex Corporation

. Summary of Urea NOxOUT Demonstration. January 1989.
77. SNCR NO Control Demonstration. Wisconsin Electric Power Company, Valley Power Plan t x Unit #4. March 1992.
78. Hurst, B. E., et al. Exxon Thermal DeNO Effectiveness Demonstrated in a Wood-Fired Boiler. x 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 DeNO Process Test Data for 300 TPD x MSW Incineration Plant. Technical Paper No. 89-23B.7. Air and Waste Managemen t Association. Pittsburgh, PA. June 1989.
80. Clarke, M. (Environmental Research and Educ ation). Technologies for Minimizing the Emission of NO From MSW Incineration. Technical Paper No. 89-167.4. Air and Waste Managemen t

x Association. Pittsburgh, PA. June 1989.
81. City of Commerce MSW Plant. Proceedings: Second Annual NO Control Conference. Council x of Industrial Boiler Owners. Burke, VA. February 1989.B-31

82. Hofmann, J. E., et al. (Nalco Fuel Tech). NO Control for Municipal Solid Waste Combustors. x Techni cal Paper No. 90-25.2. Air and Waste Management Association. Pittsburgh, PA. Jun e 1990.
83. Letter a nd attachments from confidential company to Votlucka, P., South Coast Air Qualit y Management District. Industrial SCR Experience. October 1988.
84. Behrens, E. S., et al. SCR Operating Ex perience on Coal Fired Boilers and Recent Progress. Joy Environmental Equipment Company. Monrovi a, CA. Presented at the 1991 Joint Symposium on Stationary Combustion NO Control—EPA/EPRI. Washington, D.C. March 25-28, 1991. x 85. Furuya, K. (Electric Power Development Company). E PDC's Fluidized Bed Combustion RD&D: a Progress Report on Wakamatsu 50 MW Demonstration Test and the World's Largest FB C Retrofit Project. Proceedings of the 1989 Internation al Conference on Fluidized Bed Combustion. The American Society of Mechanical Engineers/Electric Power Research Institute/Tennesses s Valley Authority. New York, NY. 1989.
86. Christian, A. W. (M. C. Patten & Company). State of the Art NO Control in Package Boilers. x Pr oceedings: Fourth Annual NO Control Conference. Council of Industrial Boiler Owners

. x Burke, VA. February 1991.
87. Kuroda, H., et al. (Kure Works of Babcock-Hitachi K.K.). Recent Developments in the SC R Syst em and its Operational Experiences. Proceedings of the 1989 International Conference o n Flui dized Bed Combustion. The American Society of Mechanical Engineers/Electric Powe r Research Institute/Tennessess Valley Authority. New York, NY. 1989.
88. Dona is, R. E., et al. (Combustion Engineering, Inc.). 1989 Update on NO Emission Contro l x Te chnologies at Combustion Engineering. Proceedings: 1989 Symposium on Stationar y Combustion NO Control. Publication No. EPRI GS-6423. U.S. Environmental Protectio n x Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.
89. Let ter and attachments from Shaneberger, D. E., Exxon Research and Engineering Co. NO x Emissions Data: ICI Boilers with Flue Gas Tr eatment NO Controls — SNCR. September 1993. x 90. Letter and attachments from Wax, M. J., Institute of Clean Air Companies. NC-300 Catalys t Installations. September 16, 1993.
91. Letter an d attachments from Pickens, R., Nalco Fuel Tech. Inc. NOxOUT Process Experienc e 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.C-1 APPENDIX C. LOW-NO INSTALLATION LISTS, x COEN COMPANY AND TAMPELLA POWER CORP.

(Note: NO levels reported in the Coen list are not

x necessarily those achieved with the Coen low-NO x burner, but often represent NO guarantees. Actual x levels may be lower.)C-24 FABER BURNER — LOW-NO BURNER PROJECTS x 40 ppm OR LESS — FIRING NATURAL GAS

Quantity capacity Boiler manufacturer

Boiler Tampella Power 1 17,500 pph TP — Package Williamsport, PA International Business Machines 1 36,000 pph TP — Package San Jose, CA Formosa Plastics Co. 2 35,000 pph TP — Package Point Comfort, TX 3 55,000 pph Miller Brewing Co. 4 50,000 pph TP — Package Irwindale, CA Veterans Administration Medical Center 1 12,500 pph TP — CP Sheridan, WY Veterans Administration Medical Center 1 45,000 pph B&W — Package Los Angeles, CA Veterans Administration Medical Center 1 20,000 pph B&W — Package Des Moines, IA 2 15,000 pph General Motors Proving Grounds 2 50,000 pph (1) B&W — Package Milford, MI (1) TP — Package Armstrong World Industries 1 9,000 pph TP — CP South Gate, CA Nationwide Boiler Co. 2 75,000 pph Nebraska — Package Fremont, CA Canadian Forces Base 1 60,000 pph TP — Package Halifax, Nova Scotia (No. 6 oil) Hershey Chocolate 3 40,000 pph TP — Package Hershey, PA Kimberly Clark 1 40,000 pph B&W — Package Fullerton, CA Farmer John 3 23,000 pph (1) CE — Marine Vernon, CA 12,000 pph (2) B&W — Package 3M Corporation 2 30,000 pph Nebraska — Package Camarillo, CA 22,000 pph Trane — Package Georgia Pacific 1 30,000 pph TP — Package Buena Park, CA Medical Center Co. 1 100,000 pph Nebraska — Package Cleveland, OH Sunkist Growers 1 40,000 pph B&W — Package Ontario, CA Luzerne County 3 17,500 pph TP — Package Wilkes-Barre, PAD-1 APPENDIX D. SCALED COST EFFECTIVENESS VALUES
The following tables present cost effectiveness figur es 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 NO control combinations. To estimate cost effectiveness for the x 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). Co st 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 NO emission values and x fuel prices. This appendix contains the following tables: Cost Case Page Natural-gas-fired: Packaged watertube, 45 MMBtu/hr, with WI and O trim D-3 2 Packaged firetube, 10.5 MMBtu/hr, with WI and O trim D-3 2 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 FGR D-5 Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FGR D-6 Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FGR, and CEM D-7 Packaged firetube, 2.9-33.5 MMBtu/hr, with FGR and O trim D-8 2 Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-9 Field-erected wall-fired, 75 MMBtu/hr, with BOOS and O trim D-10 2 Field-erected wall-fired, 75 MMBtu/hr, with BOOS, WI, and O trim D-10 2 Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-11 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 FGR D-13 Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FGR D-14 Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FGR, and CEM D-15 Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-16 Packaged firetube, 2.9-33.5 MMBtu/hr, with FGR and O trim D-17 2 Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-17D-2

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 FGR D-19 Packaged watertube, 45, 55, and 265 MMBtu/hr, with LNB and FGR D-20 Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FGR, 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 FGR and O trim D-23 2 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-30D-3D-4D-5D-6D-7D-8D-9D-10D-11D-12D-13D-14D-15D-16D-17D-18D-19D-20D-21D-22D-23D-24D-25D-26D-27D-28D-29D-30E-1 APPENDIX E. ANNUAL FIT NO CONTROLS: x NATURAL-GAS-FIRED ICI BOILERS

This appendix contains cost spreadsh eets for natural-gas-fired boilers retrofitted with various NO x con trols. The spreadsheets are based on data from actual boiler retrofit experiences or studies. Capita l

annua lization 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 inform ation on the methodology and assumptions made in these cost analyses, see Chapter 6. This appendix contains cost spreadsheets for the following boilers:
Boiler and NO Control Page x Packaged watertube, 45 MMBtu/hr, with WI and O trim E-3 2 Packaged firetube, 10.5 MMBtu/hr, with WI and O trim E-5 2 Field-erected watertube, 75 MMBtu/hr, with BOOS and O trim E-7 2 Field-erected watertube, 75 MMBtu/hr, with BOOS, WI, and O trim E-9 2 Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB E-11 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 FGR E-23 Packaged watertube, 81.3, 91, and 265 MMBtu/hr, with LNB, FGR, and CEM E-33 Packaged firetube, 2.9, 5.23, 10.46, 20.9, and 33.5 MMBtu/hr, with FGR and O trim E-39

2 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-69E-2E-3E-4E-5E-6E-7E-8E-9E-10E-11E-12E-13E-14E-15E-16E-17E-18E-19E-20E-21E-22E-23E-24E-25E-26E-27E-28E-29E-30E-31E-32E-33E-34E-35E-36E-37E-38E-39E-40E-41E-42E-43E-44E-45E-46E-47E-48E-49E-50E-51E-52E-53E-54E-55E-56E-57E-58E-59E-60E-61E-62E-63E-64E-65E-66E-67E-68E-69E-70E-71E-72F-1 APPENDIX F. ANNUAL COSTS OF RETROFIT NO CONTROLS: x COAL-FIRED ICI BOILERS

This a ppendix contains cost spreadsheets for coal-fired boilers retrofitted with various NO x con trols. The spreadsheets are based on data from actual boiler retrofit experiences or studies. Capita l annualization for all analyses are based on a 10-year amorti zation 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 NO Control x 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-11 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-23F-2F-3F-4F-5F-6F-7F-8F-9F-10F-11F-12F-13F-14F-15F-16F-17F-18F-19F-20F-21F-22F-23F-24G-1 APPENDIX G. ANNUAL COSTS OF RETROFIT NO CONTROLS: x NONFOSSIL-FUEL-FIRED ICI BOILERS

This appendix contains cost spreadsheets for nonfossil-fuel-fired boile rs retrofitted with various NO cont rols. The spreadsheets are based on data from actual boiler retrofit experiences or studies

. x Ca pital annualization for all analyses are based on a 10-year amortization period and a 10-percen t interest rate. All c osts 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 NO Control Page x 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-19G-2 For a given cost case, cost estimates were calculated using all applicable boiler cases, in order to compare costs provided by different sour ces. For example, for natural gas-fired packaged watertube boilers with LNB, cost effectiveness was calculated u sing the annual costs developed for three different boilers listed in Appendix E. The results are presented on the following page for each of the three units.G-3G-4G-5G-6G-7G-8G-9G-10G-11G-12G-13G-14G-15G-16G-17G-18G-19G-20G-21G-22G-23G-24G-25