EPA-453/R-94-022

Alternative Control

Techniques Document--

NOx Emissions from

Industrial/Commercial/Institutional

(ICI) Boilers

Emission Standards Division

U.S. ENVIRONMENTAL PROTECTION AGENCY

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

March 1994

iii

ALTERNATIVE CONTROL TECHNIQUES DOCUMENT

This report is issued by the Emission Standards Division, Office of Air

Quality Planning and Standards, U.S. Environmental Protection Agency, to

provide information to State and local air pollution control agencies. 

Mention of trade names and commercial products is not intended to

constitute endorsement or recommendation for use. Copies of this report

are available—as supplies permit—from the Library Services Office (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 NOx FORMATION AND BASELINE EMISSIONS ......... 2-5

2.3 CONTROL TECHNIQUES AND CONTROLLED

NOx EMISSION LEVELS .......................... 2-8

2.3.1 Combustion Modification Controls ............. 2-11

2.3.2 Flue Gas Treatment Controls .................. 2-15

2.4 COST AND COST EFFECTIVENESS OF 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 .................... 3-19
vi

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 .................... 3-43
vii

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 NOx CONTROL TECHNOLOGY EVALUATION ............. 5-1

5.1 PRINCIPLES OF NO x FORMATION AND

COMBUSTION MODIFICATION NO x CONTROL ........ 5-2

5.2 COMBUSTION MODIFICATION NO x CONTROLS FOR

COAL-FIRED ICI BOILERS ......................... 5-9
viii

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 x CONTROLS FOR

OIL- AND NATURAL-GAS-FIRED ICI BOILERS ........ 5-39

5.3.1 Water Injection/Steam Injection (WI/SI) .......... 5-43

5.3.2 Low-NOx Burners (LNBs) in Natural-gas- and

Oil-fired ICI Boilers ........................ 5-43

5.3.3 Flue Gas Recirculation (FGR) in Natural-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 x REDUCTION

PERFORMANCE ................................. 5-78

5.7 REFERENCES FOR CHAPTER 5 .................... 5-82

6 COSTS OF RETROFIT NO x CONTROLS ................... 6-1

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

6.1.1 Capital Costs of Retrofit NO x Controls ........... 6-2

6.1.2 Annual Operations and Maintenance (O&M)

Costs ...................................... 6-5

6.1.3 Total Annualized Cost and Cost Effectiveness ..... 6-5

6.2 NOx CONTROL COST CASES AND SCALING

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

6.3 CAPITAL AND TOTAL ANNUAL COSTS OF NO x

CONTROLS .................................... 6-11

6.4 COST EFFECTIVENESS OF NO x CONTROLS .......... 6-15

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 .................................... 6-18
x

6.4.3 NOx Control Cost Effectiveness: Fuel-oil-fired

ICI Boilers ................................. 6-25

6.4.4 NO Control Cost Effectiveness: Nonfossil-fuel-fired ICI x

Boilers .................................... 6-25

6.4.5 NOx Control Cost Effectiveness: Oil-fired

Thermally Enhanced Oil Recovery (TEOR)

Steam Generators ....................... 6-30

6.4.6 Cost Effect of Continuous Emissions Monitoring (CEM)

System ................................ 6-31

6.5 REFERENCES FOR CHAPTER 6 .................... 6-32

 7 ENVIRONMENTAL AND ENERGY IMPACTS ............... 7-1

7.1 AIR POLLUTION ................................. 7-1

7.1.1 NOx Reductions ............................. 7-1

7.1.2 CO Emissions .............................. 7-4

7.1.3 Other Air Pollution Emissions ................. 7-8

7.2 SOLID WASTE DISPOSAL ......................... 7-12

7.3 WATER USAGE AND WASTEWATER DISPOSAL ....... 7-13

7.4 ENERGY CONSUMPTION .......................... 7-13

7.4.1 Oxygen Trim (OT) ........................... 7-14

7.4.2 Water Injection/Steam Injection (WI/SI) .......... 7-16

7.4.3 Staged Combustion Air (SCA) ................. 7-16

7.4.4 Low-NOx Burners (LNBs) ..................... 7-16

7.4.5 Flue Gas Recirculation (FGR) .................. 7-18
xi

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 x EMISSION DATA .............. B-1

APPENDIX C — LOW-NO x INSTALLATION LISTS, COEN

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-1
xii

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-1
xiii

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

Figure 3-6 Firetube boiler .................................... 3-8

Figure 3-7 Single-retort horizontal-feed underfeed stoker .......... 3-11

Figure 3-8 Multiple-retort gravity-feed underfeed stoker ........... 3-11

Figure 3-9 Overfeed chain-grate stoker ......................... 3-12

Figure 3-10 Spreader stoker ................................... 3-12

Figure 3-11 Wall firing ....................................... 3-15

Figure 3-12 Tangential firing .................................. 3-15

Figure 3-13 Bubbling FBC schematic ........................... 3-18

Figure 3-14 Circulating FBC schematic .......................... 3-18

Figure 3-15 Two-pass HRT boiler .............................. 3-21

Figure 3-16 Four-pass gas-/oil-fired scotch boiler ................. 3-22

Figure 3-17 Exposed-tube vertical boiler ........................ 3-23
xv

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

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 x emissions with reduced

excess oxygen for a residual-oil-fired watertube

industrial boiler .................................. 5-8

Figure 5-3 Effect of BOOS on emissions ........................ 5-14

Figure 5-4 Foster Wheeler CF/SF LNB .......................... 5-16
xvii

LIST OF FIGURES (continued)

Page

Figure 5-5 Performance of CF/SF LNB ......................... 5-16

Figure 5-6 Riley low-NOx CCV burner with secondary air diverter ... 5-18

Figure 5-7 Riley low-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 2........................... 5-28

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

Figure 5-11 Overfeed stoker with short active combustion zone ..... 5-29

Figure 5-12 Effect of SCA on NO x and CO emissions, Chalmers University 5-33

Figure 5-13 NOx and CO versus bed temperature, pilot-scale BFBC ... 5-35

Figure 5-14 Effect of bed temperature on NO x and CO, Chalmers University 5-36

Figure 5-15 As the rate of water injection increases, NO x decreases . . 5-44

Figure 5-16 Staged air LNB ................................... 5-46
xviii

Figure 5-17 Staged fuel LNB .................................. 5-48

Figure 5-18 Low-NOx ASR burner .............................. 5-50

Figure 5-19 AFS air- and fuel-staged burner ...................... 5-50

Figure 5-20 Riley Stoker STS burner ............................ 5-51

Figure 5-21 Pyrocore LNB schematic ........................... 5-53

Figure 5-22 FGR system for gas- or oil-fired boiler ................ 5-57

Figure 5-23 Effects of cofiring on NO x emissions .................. 5-62

Figure 5-24 North American LNB on oil field steam generator ....... 5-66

Figure 5-25 Process Combustion Corporation toroidal combustor ... 5-67

Figure 5-26 The MHI PM burner nozzle .......................... 5-68
xix

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 boilers6-17

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 x emissions with reduced excess

oxygen for a residual-oil-fired watertube industrial boiler 7-8
xx

Figure 7-2 Pilot-scale test results, conversion of NO x to N2O (NOi = 300

ppm, N/NO = 2.0) ................................ 7-11

Figure 7-3 Curve showing percent efficiency improvement per every

1 percent reduction in excess air. Valid for estimating

efficiency improvements on typical natural gas, No. 2

through No. 6 oils, and coal fuels .................. 7-15

Figure 7-4 Unburned carbon monoxide loss as a function of excess 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 .................. 7-21
xxi

LIST OF TABLES

Page

TABLE 2-1 ICI BOILER EQUIPMENT, FUELS, AND

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

TABLE 2-2 SUMMARY OF BASELINE NO x EMISSIONS ............. 2-7

TABLE 2-3 EXPERIENCE WITH NO x CONTROL

TECHNIQUES ON ICI BOILERS ..................... 2-9

TABLE 2-4 SUMMARY OF COMBUSTION

MODIFICATION NO x CONTROL

PERFORMANCE ON ICI WATERTUBE

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

TABLE 2-5 SUMMARY OF COMBUSTION

MODIFICATION NO x CONTROL

PERFORMANCE ON ICI FIRETUBE

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

TABLE 2-6 SUMMARY OF FLUE GAS TREATMENT

NO CONTROL PERFORMANCE ON ICI x

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

TABLE 2-7 ESTIMATED COST AND COST

EFFECTIVENESS OF NO x CONTROLS

(1992 DOLLARS) ................................. 2-18

TABLE 2-8 EFFECTS OF NO x CONTROLS ON CO

EMISSIONS FROM ICI BOILERS ..................... 2-22

TABLE 3-1 ICI BOILER EQUIPMENT, FUELS, AND

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

TABLE 4-1 TYPICAL RANGES IN NITROGEN AND

SULFUR CONTENTS OF FUEL OILS ................. 4-6

TABLE 4-2 COMPARISON OF COMPILED

UNCONTROLLED EMISSIONS DATA

WITH AP-42 EMISSION FACTORS,

COAL-FIRED BOILERS ........................... 4-16

TABLE 4-3 COMPARISON OF COMPILED

UNCONTROLLED EMISSIONS DATA

WITH AP-42 EMISSION FACTORS,

OIL-FIRED BOILERS .............................. 4-19

TABLE 4-4 COMPARISON OF COMPILED

UNCONTROLLED EMISSIONS

DATA WITH AP-42 EMISSION

FACTORS, NATURAL-GAS-FIRED

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

TABLE 4-5 AP-42 UNCONTROLLED EMISSION

FACTORS FOR NONFOSSILFUEL-FIRED BOILERS ............................ 4-21
xxiv

LIST OF TABLES (continued)

Page

TABLE 4-6 AVERAGE NO x EMISSIONS FROM

MUNICIPAL WASTE COMBUSTORS ................ 4-22

TABLE 4-7 SUMMARY OF BASELINE NO x EMISSIONS ............. 4-23

TABLE 5-1 SUMMARY OF COMBUSTION

MODIFICATION NO x CONTROL

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

TABLE 5-2 EXPERIENCE WITH NO x CONTROL

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 x CONTROLS

FOR STOKER COAL-FIRED INDUSTRIAL BOILERS ..... 5-24

TABLE 5-5 NOx CONTROL TECHNIQUES FOR FBC BOILERS ....... 5-32

TABLE 5-6 REPORTED CONTROLLED NO EMISSION LEVELS, x

FULL-SCALE, COAL-FIRED FBC BOILERS ............ 5-35
xxv

TABLE 5-7 COMBUSTION MODIFICATION NO x CONTROLS

FOR FULL-SCALE NATURAL-GAS-FIRED

INDUSTRIAL BOILERS ............................ 5-41

TABLE 5-8 COMBUSTION MODIFICATION NO x CONTROLS

FOR OIL-FIRED INDUSTRIAL BOILERS ............... 5-42

TABLE 5-9 REPORTED NO x LEVELS AND REDUCTION

EFFICIENCIES IN ICI BOILERS WITH LNBs ............ 5-45

TABLE 5-10EFFECTS OF SWITCHING FROM RESIDUAL OIL TO

DISTILLATE FUEL ON INDUSTRIAL BOILERS ......... 5-63

TABLE 5-11ESTIMATES OF NO x REDUCTIONS WITH FUEL

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

TABLE 5-12SNCR NOx CONTROL FOR ICI BOILERS ............... 5-73

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

TABLE 5-14SCR NOx CONTROLS FOR ICI BOILERS ............... 5-77
xxvi

LIST OF TABLES (continued)

Page

TABLE 5-15SUMMARY OF NO x REDUCTION PERFORMANCE ....... 5-79

TABLE 6-1 ASSUMPTIONS FOR ESTIMATING CAPITAL AND

ANNUAL O&M COSTS .............................. 6-7

TABLE 6-2 BASELINE (UNCONTROLLED) NO x EMISSIONS

USED FOR COST CASES ........................... 6-9

TABLE 6-3 NOx REDUCTION EFFICIENCIES USED FOR COST CASES 6-10

TABLE 6-4 NOx CONTROL COST EFFECTIVENESS CASES ......... 6-11

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

CONTROLS FOR ICI BOILERS, 1992 DOLLARS ........ 6-12

TABLE 6-6 SUMMARY OF NO x CONTROL COST

EFFECTIVENESS, COAL-FIRED ICI

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

TABLE 6-7 SUMMARY OF NO x CONTROL COST

EFFECTIVENESS, NATURAL-GASFIRED ICI BOILERS ............................... 6-18
xxvii

TABLE 6-8 SUMMARY OF NO x CONTROL COST

EFFECTIVENESS, DISTILLATE-OILFIRED ICI BOILERS ............................... 6-26

TABLE 6-9 SUMMARY OF NO x CONTROL COST

EFFECTIVENESS, RESIDUAL-OIL-FIRED

ICI BOILERS ..................................... 6-27

TABLE 6-10SUMMARY OF NO x CONTROL COST

EFFECTIVENESS, NONFOSSIL-FUEL-FIRED ICI

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

TABLE 6-11NOx CONTROL COST EFFECTIVENESS

WITHOUT/WITH CEM SYSTEM, NATURAL-GASFIRED ICI BOILERS .............................. 6-31 a

TABLE 7-1 EXPERIENCE WITH NO x CONTROL TECHNIQUES

ON ICI BOILERS ................................. 7-2

TABLE 7-2 NOx EMISSIONS REDUCTION FROM MODEL

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

TABLE 7-3 CO EMISSION CHANGES WITH NO x CONTROL

RETROFIT — COAL-FIRED BOILERS ................ 7-5

TABLE 7-4 CO EMISSION CHANGES WITH NO x CONTROL

RETROFIT — GAS-FIRED BOILERS .................. 7-6
xxviii

LIST OF TABLES (continued)

Page

TABLE 7-5 CO EMISSION CHANGES WITH NO x CONTROL

RETROFIT — OIL-FIRED BOILERS ................... 7-7

TABLE 7-6 AMMONIA EMISSIONS WITH UREA-BASED SNCR

RETROFIT ..................................... 7-10
1-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 x emissions

from ICI boilers. Additional ACT documents are being developed for other

stationary source categories.

ICI boilers include steam and hot water generators with heat input

capacities from 0.4 to 1,500 MMBtu/hr (0.11 to 440 MWt). These boilers are

used in a variety of applications, ranging from commercial space heating

to process steam generation, in all major industrial sectors. Although
1-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 x formation and uncontrolled NO 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 x emission levels from ICI boilers and the

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 x levels associated with boiler designs, firing

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

NOx control technologies. The section is divided into a subsection on

combustion controls and another on flue gas treatment controls. As in the

utility boiler experience, retrofit combustion controls for ICI boilers have

targeted principally the replacement of the original burner with a low-NO x

design. When cleaner fuels are burned, the low-NO x burner (LNB) often

includes a flue gas recirculation (FGR) system that reduces the peak flame

temperature producing NO x. Where NO x regulations are especially
2-2

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 x. For these units, NO x reductions are

often achievable only with flue gas treatment technologies for which

experience varies.

Section 2.4 summarizes the cost of installing NO x controls and

operating at lower NO x levels. The data presented in this document are

drawn from the reported experience of technology users coupled with

costs reported by selected technology vendors. This information is

offered only as a guideline because control costs are always greatly

influenced by numerous site factors that cannot be taken fully into

account. Finally, Section 2.5 summarizes the energy and environmental

impacts of low-NO x operation. Combustion controls are often limited in

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 x
2-3

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 2-1
2-5

Heat

transfer

configurati

on

Design and

fuel type

Capacity

range,

MMBtu/hr

a

% of

ICI

boiler

unitsb,c

% of ICI

boiler

capacityb,

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

1.5-1,000f**  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 APPLICATIONS
2-6

 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 x controls that would limit this operational flexibility may

prove impractical. They can be found fully enclosed inside commercial

and institutional buildings and in industry steam plants or completely

outdoors in several industrial applications at refineries and chemical

plants. The location of these boilers often influences the feasibility of

retrofit for some control technologies because poor access and limited

available space.

ICI boiler equipment is principally distinguished by the method of

heat transfer of heat to the water. The most common ICI boiler types are

the watertube and firetube units. Firetube boilers are generally limited in

size to about 50 MMBtu/hr (15 MWt) and steam pressures, although newer

designs tend to increase the firing capacity. All of these firetubes are

prefabricated in the shop, shipped by rail or truck, and are thus referred to

as packaged. Watertube boilers tend to be larger in size than firetube

units, although many packaged single burner designs are well within the

firetube capacity range. Larger, multi-burner watertubes tend to be field
2-7

erected, especially older units. Newer watertubes also tend to be single

burners and packaged. Steam 
2-8

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 and
2-9

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 x emissions. The practice of burning hazardous wastes in

boilers and industrial furnaces is currently regulated by the EPA under the

Resource Conservation and Recovery Act (RCRA).

2.2 NOx FORMATION AND BASELINE EMISSIONS

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

NOx, is formed mainly from the high temperature reaction of atmospheric

nitrogen and oxygen (thermal NO x) and from the reaction of organically

bound nitrogen in the fuel with oxygen (fuel NO x). A third and less

important source of NO formation is referred to as "prompt NO," which

forms from the rapid reaction of atmospheric nitrogen with hydrocarbon

radical to form 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 x emissions

are reduced to extremely low limits, i.e., with natural gas combustion, the

contribution of prompt NO becomes more important.

The mechanisms of NO x formation in combustion are very complex

and cannot be predicted with certainty. Thermal NO is an exponential x

function of temperature and varies with the square root of oxygen
2-10

concentration. Most of the NO x formed from combustion of natural gas

and high grade fuel oil (e.g., distillate oil or naphtha) is attributable to

thermal NOx. Because of the exponential dependence on temperature, the

control of thermal NO x is best achieved by reducing peak combustion

temperature. Fuel NO results from the oxidation of fuel-bound nitrogen. x

Higher concentrations of fuel nitrogen typically lead to higher fuel NO x and

overall NO levels. Therefore, combustion of residual oil with 0.5 percent x

fuel-bound nitrogen, will likely result in higher NO x levels than natural gas

or distillate oil. Similarly, because coal has higher fuel nitrogen content

higher baseline NO x levels are generally measured from coal combustion

than either natural gas or oil combustion. This occurs in spite of the fact

that the conversion of fuel nitrogen to fuel NO x typically diminishes with

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 x emission levels for ICI boilers. Baseline data were

compiled from test results on more than 200 ICI boilers described in EPA

documents and technical reports. These data, representative of boiler

operation at 70 percent capacity or higher, are detailed in Appendix A. 

Table 2-2
2-11

Fuel Boiler type

Uncontrolle

d NOx

range,

lb/MMBtu

Average,

lb/MMBtu

Pulverized

coal

Wall-fired

Tangential

Cyclone

0.46-0.89

0.53-0.68

1.12a

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 0.15b 0.15

MSW Mass burn

Modular

0.40b

0.49b

0.40

0.49

TABLE 2-2. SUMMARY OF BASELINE NO x EMISSIONS
2-12

 summarizes the range and average NO x emissions from the various

categories of ICI boilers investigated in this study. On an average basis,

coal-fired ICI boilers emit the highest level of NO x, as anticipated. Among

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

NOx emissions than PC-fired units and are generally more efficient than

stokers. The large variations in baseline NO x levels for the FBC units are

generally the result of variations in air distribution among FBC units. 

Newer FBC designs incorporate a staged air addition that suppresses NO x

levels. Also the type of bed material and SO 2
2-13

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 x levels are also shown for ICI boilers

burning residual oil. For example, boilers with a capacity of less than 100

MMBtu/hr (29 MWt) can have emissions in the range of 0.20 to 0.79

lb/MMBtu, a factor of nearly 4. This is attributable predominantly to large

variations in fuel nitrogen content of these fuel oils. NO x emissions from

distillate-oil- and natural-gas-fired ICI boilers are significantly lower due by

and large to the burning of cleaner fuel with little or no fuel-bound

nitrogen. It is also important to note that baseline emission levels for the

larger boilers tend to be somewhat higher, on average. This is attributable

to the higher heat release rate that generally accompanies the larger units

in order to minimize the size of the furnace and the cost of the boiler. 

Also, another factor is the use 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 x EMISSION

LEVELS

The reduction of NO x emissions from ICI boilers can be

accomplished with combustion modification and flue gas treatment

techniques or a combination of these. The application of a specific

technique will depend on the type of boiler, the characteristic of its primary

fuel, and method of firing. Some controls have seen limited application,

whereas certain boilers have little or no flexibility for modification of

combustion conditions because of method of firing, size, or operating

practices. Table 2-3
2-14

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

NO control x

technique

Coal-fired Oil-/natural-gas-fired Nonfossil-fuel-fired MSW-fired

Field-erected

PC-fired Stoker

FB

C

Fielderected

watertube

Packaged

watertub

e

Packaged

firetube Stoker FBC Mass burn

BT/OT X X

WI/SI X X

SCA X X a X X X b Xa X X a

LNB X X X X

FGR X X X X

NGR X b Xb

SNCR X b X X X X b X X X 

SCR X b Xb Xb

BT/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-NO burners xFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid waste

SCA is designed primarily for control of smoke and combustible fuel rather than NO . Optimization of existing SCA (OFA) ports can lead a x

 to some NO reduction. x

Limited experience. b
2-15

 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

NOx emissions can be controlled by suppressing both thermal and

fuel NOx. When natural gas or distillate oil is burned, thermal NO x is the

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 x standards. Although very

effective in reducing thermal NO x, this technique has not been widely

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 NOx can also be reduced to some extent by minimizing the

amount of excess oxygen, delaying the mixing of fuel and air, and reducing

the firing capacity of the boiler. The 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 x is partially offset by some increase in thermal NO x

because of higher peak temperature with lower gas volume. OT and LEA
2-17

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 x can be

minimized. This SCA technique is particularly effective on high nitrogen

fuels such as coal and residual oil fired boilers, which may have high

baseline emissions and would result in high reduction efficiencies. For

PC, BOOS for NO x reduction is not practical. Therefore, SCA is usually

accomplished with the retrofit of internally air staged burner or overfire air

ports. The installation of low-NO x burners for PC- and residual-oil-fired

boilers is a particularly effective technique because it involves minimal

furnace modifications and retained firing capacity. Staged fuel burners in

some packaged watertube boilers without membrane convective side

furnace wall(s) may cause an increase in CO emissions at the stack, due to
2-18

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 x emission emitted by the

primary fuel. This reburning technique is best accomplished when the

reburning fuel is natural gas. Natural gas reburning (NGR) and cofiring

have been investigated primarily for utility boilers, especially coal-fired

units that are not good candidates for traditional combustion modifications

such as LNB. Examples of these boilers are cyclones and stoker fired

furnaces. Application of these techniques on ICI boilers has been limited

to some municipal solid waste (MSW) and coal-fired stokers.

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

NOx reduction occurs by the selective reaction of NH 2 radicals with NO to

form water and nitrogen. The reaction for the SNCR process must occur at

elevated temperatures, typically between 870 and 1,090 C (1,600 and

2,000 F) because the reduction proceeds without a catalyst. At much

lower flue gas temperatures, typically in the range of 300 to 400 C (550 to

750 F), the reaction requires the presence of a catalyst. SNCR is
2-19

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 Controls
2-20

Table 2-4
2-21

ICI boiler

and fuel NO control x

Percent

NOx

reduction

Controlled

NO level, x

lb/MMBtu Comments

PC, wallfiredSCA 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.a0.23-0.52 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-firedLNB 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-firedLNB 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-firedSCA 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 x CONTROL

PERFORMANCE ON ICI WATERTUBE BOILERS
2-22

 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 x control techniques for PC-fired ICI boilers

are LNB, NGR, and LNB+SCA. The average reduction achieved with the

retrofit of LNB on seven ICI boilers was 55 percent with a controlled level

of 0.35 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 NOx staging. Furthermore, the long term effectiveness of these

controls for stokers was not evaluated in these exploratory tests. The

average NOx reduction for eight stokers with enhanced air staging was 18

percent with a corresponding controlled NO level of 0.38 lb/MMBtu. x

Largest NOx reductions were accompanied by large increases in CO

emissions. Gas cofiring in coal-fired stokers, only recently explored,

achieves NOx reductions in the 20 to 25 percent range only by being able to

operate at lower excess air.

Air staging in coal-fired FBC boilers is very effective in reducing

NOx from these units. FBCs are inherently low NO x emitters because low

furnace combustion temperatures preclude the formation of thermal NO . x
2-23

Furthermore, the in-bed chemistry between coal particles, CO, and bed

materials (including SO 2 sorbents) maintains fuel nitrogen conversion to

NO at a minimum. The 
2-24

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.

NOx reductions and controlled levels for residual oil combustion are

influenced by the nitrogen content of the oil, the degree of staging

implemented, and other fuel oil physical and chemical characteristics. 

Because of these factors, NO x control performance on this fuel is likely to

vary, as shown in Table 2-4. Data on LNB for residual-oil-fired ICI boilers

were obtained primarily from foreign applications. The average controlled

NOx level reported with LNB for residual-oil-fired ICI boilers is 0.19

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 x reductions from such units. Among

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 x level for FGR-controlled ICI watertube boilers is 0.05

lb/MMBtu or approximately 40 ppm corrected to 3 percent O 2. For distillate
2-25

Fuel type NO control x

Percent

NOx

reduction

Controlled

NO level, x

lb/MMBtu Comments

Residualoil-firedLNB 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-firedLNB 15 0.15 Several LNB designs are available. Most operate on low

excess air.

FGR N.A.a0.04-0.16 Effective technique for clean fuels.

Naturalgas-firedSCA 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 x levels. Some

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 x CONTROL

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 2. Average NO 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 x levels achieved on these boiler types are generally slightly

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 2. FGR by itself is also capable to achieve these

low NOx levels when burning natural gas. In addition to these combustion

controls, both OT and WI have been retrofitted in combination on selected

packaged industrial boilers in California to meet very low NO levels. x
2-26

These controls offer the potential for economic NO x control because of low

initial capital investment compared to either FGR or LNB. NO x reduction

efficiencies and controlled levels have been reported in the range of about

55 to 75 percent depending on the amount of water injected and the level of

boiler efficiency loss acceptable to the facility.

2.3.2 Flue Gas Treatment Controls

Application of flue gas treatment controls in the United States is

generally sparse. Table 2-6
2-27

ICI boiler and fuel NO control x

Percent

NOx

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 x CONTROL

PERFORMANCE

ON ICI BOILERS
2-28

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

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 x levels in the range of 0.15 to 0.40 lb/MMBtu. SNCR

performance is known to vary with boiler load because of the shifting

temperature window. SNCR has been reported to be quite more effective

for FBC and stoker boilers. In circulating FBC boilers in California, SNCR

with either urea or ammonia injection, achieved an average NO x reduction

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 x reductions in the

range of 25 to 80 percent, averaging about 60 percent, with controlled

levels in the range of 0.035 to 0.31 lb/MMBtu.

2.4 COST AND COST EFFECTIVENESS OF NO x CONTROL TECHNIQUES

A simplified costing methodology, based primarily on the U.S.

EPA's Office of Air Quality Planning and Standards (OAQPS) Control Cost

Manual, was developed for this study. The capital control costs were

based on costs reported by vendors and users of the NO control x

technologies and from data available in the open literature. The total
2-29

capital investment was annualized using a 10-percent interest rate and an

amortization period of 10 years. Cost 
2-30

effectiveness was calculated by dividing the total annualized cost by an

NOx reduction for each retrofit cost case using boiler capacity factors in

the range of 0.33 to 0.80.
2-31

Table 2-7
2-32

Fuel type

Boiler type

and size,

MMBtu/hr

NO control x

technique

Estimated

NOx

control level,

lb/MMBtua

NOx

reduction,

tons/yr

Total capital

investment,

$/MMBtu/hr

Cost

effectiveness,

$/ton of NOx

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 8,000-11,000

Multiburner fielderected watertube

(300)

OT+SCAb0.15 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 x reduction

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 x controls for these

packaged boilers. The cost effectiveness of WI controls for packaged

boilers is anticipated to be low in spite of the associated efficiency losses. 

This is because an efficiency improvement was credited with the combined

application of oxygen trim controls that can compensate for some of the

losses of WI.

The installation of 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 with
2-34

cost effectiveness as low as $240/ton to as high as $6,300/ton, depending

on fuel 
2-35

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 x CONTROL

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 x emissions with some

increase in CO emissions. For those boilers, that have poor air

distribution to the active burners, a program of burner tuning with oxygen

trim is likely to achieve both some reduction in NO and CO as well. x
2-36

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

NOx

control

NOx

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 the
2-39
2-40

 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 x emission levels. In recognition of this, the South

Coast Air Quality Management District (SCAQMD) in California permits

400-ppm CO levels for low-NO x permits under its Rule 1146. Also, the

American Boiler Manufacturers Association (ABMA) recommends 400-ppm

CO levels when NO x emissions from ICI boilers are lowered. Increases in

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-based 
2-41

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

NOx control techniques. For example, the injection of water or steam to

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 latent
2-42

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 capacities. 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, pulverized and stoker coal, and solid waste fuels. Uncontrolled NO x

emissions also vary significantly among the various fuels and boiler design

types. Combustion modifications are the most common approach to reducin g

NOx, but experience with many ICI boiler types is limited. FGT controls can

substitute 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

assessment of NOx control technologies. A boiler is defined here as a

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

process heating, electrical or mechanical power generation, space heating ,

or a combination 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 new
3-2

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

chemical 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- 1
3-3

Heat

transfer

configuratio

n

Design and

fuel type

Capacity

range,

MMBtu/hr a

% of

ICI

boiler

unitsb,c

% of ICI

boiler

capacityb,

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

1.5-1,000e**  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 APPLICATIONS
3-4

 gives 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

various 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

heat 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

array of applications, such as wholesale and retail trade, office buildings ,

hotels, restaurants, hospit als, schools, museums, and government facilities,

primarily 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. 6
3-5

Figure 3-1. Occurrence of fuel types and heat transfer configurations by capacity.
3-6

Figure 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

natural 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

composition greatly influence the quantity and type of emissions produced,

and the feasibility of certain types of NO x controls, as will be discussed i n

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 important way of classifying boilers is by heat transfe r

configuration. The four major configurations are watertube, firetube, cas t

iron, and tubeless. In 
3-8
3-9

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 to
3-10

 water
3-11

 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 be

7,8

either packaged or field-erected, depending on their size. In general, mos t

units 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 as large as 150 MMBtu/hr (44 MWt) heat input capacity are typicall y

shop-assembled 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

government'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. 11
3-12

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

through tubes immersed in the boiler water, transferring heat to the water .

The firebox itself is also often immersed in the water. At high pressures, and

when subjected to 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

multiple small diameter watertubes, which are inherently stronger. As a

6

consequence, ICI firetube boilers are typically small, with heat inpu t

capacities limited 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

common. Firetubes are used primarily where loads are relatively constant .
3-13

Figure 3-6. Firetube boiler. 16

Nearly all 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 as 
3-14

it moves upward through the tubes. Cast iron boilers produce low-pressure

steam or hot water, and generally burn oil or natural gas. They are used

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 .

Although the majority of coal-fired ICI boilers are smaller cast iron units ,

coal-fired firetube or cast iron boilers are not as common as oil- or 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

industrial 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.

Nevertheless, 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

included 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. 17
3-15

3.2.1 Coal-fired Watertube Boilers

Coal-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

inventory was taken. Yet, due to their larger capacities, these unit s

accounted for 14 percent of the total operating capacity. Coal-fired

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

Stoker-firing systems account for approximately 90 percent of coal -

fired watertube ICI boilers. Stoker systems can be divided into thre e

19

groups: underfeed stokers, overfeed stokers, and spreader stokers. These

systems differ in how fuel is supplied to either a moving or stationary grate

for 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 more levels of overfire air introduced above the grate. This help s

ensure complete combustion of volatiles and low combustion emissions .

Most stokers also utilize flyash reinjection to minimize the unburned carbon

content in the flyash. Underfeed stokers were once the primary stoker type

used in industrial and utility steam generation, but the high costs o f

maintenance and these units' slow response to varying loads have made t hem

less competitive in the present market. Spreader stokers, however, ar e

extremely popular in industry today, due in part to their wide fuel capability,

discussed further below. 20
3-16

Figure 3-7. Single-retort horizontal-feed underfeed stoker. 21

Underfeed 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

steam loads of less than 30,000 lb/hr (~30 MMBtu/hr input). As shown in

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 .

Combustion 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 e
3-17

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. Allowable burning rates determine the size of 21

the grate area for a given heat input rate. The higher the burning rate th e

higher the 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

input capacity. In this type of stoker, coal is introduced through a coa l

21

hopper 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

assembly. 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, it
3-18

Figure 3-8. Multiple-retort gravity-feed underfeed stoker. 21

passes over 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 ,

combustion 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

chain, travelling, and water-cooled vibrating grates. These overfeed stoke r

systems are often referred to by the type of grate employed. Overfeed coalfired systems typically range up to 350 MMBtu/hr (100 MWt) heat inpu t

capacity. 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

uniformly over the surface of a moving grate. In a typical spreader stoke r

boiler, shown in Figure 3-1 0
3-19

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

secondary air and turbulence. The injection of the fuel into the furnace and

onto the 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 its volatile matter content, the more energy released in suspension ;

the higher the moisture content, the more energy released on the grate. 24

Many spreader stoker units incorporate a flyash recirculation system ,

whereby unburned solids in the flyash are collected and recirculated bac k

into the primary combustion chamber. Heat input capacities of spreade r

stokers typically range from 5 to 550 MMBtu/hr (1.5 to 160 MWt), althoug h
3-20

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 total 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

and pulverizing equipment can increase the capital cost of PC-fired units to

as high as 10 times that of an oil- or natural-gas-fired industrial boiler of the

same size. 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

boilers can be either single-wall-fired, with burners on only one wall of th e

furnace 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. 26
3-22

Figure 3-12 shows a plan view of a tangential -firing configuration, with

the burners mounted in the corners of the furnace. The fuel and air ar e

injected toward the center of the furnace to create a vortex that enhance s

air/fuel 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

Cyclone furnaces are often categorized as PC-fired systems eve n

though 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 fed

8

tangentially, with primary air, into a horizontal cylindrical furnace. Smalle r

coal particles are burned in suspension, while larger particles adhere to a

molten 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

heat release rates, cyclones emit high levels of NO x, and are generally more

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 x emissions, as wet-bott om boilers

generally operate at higher furnace temperatures and subsequently emi t

greater amounts of NO x. Boiler designs in wet- and dry-bottom furnace s

hinge on 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, due
3-23

Figure 3-12. Tangential firing. 26

primarily 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 are two major categories of FBC systems: (1) atmospheric ,

operating at a slight negative draft, and (2) pressurized, operating at from 4

to 30 atmospheres (60 to 450 psig). Pressurized FBC (PFBC) systems ar e

being demonstrated at two utility sites in the United States. No PFBC units

are currently in operation in the ICI sector, and it is unlikely that 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 several 
3-24

years away 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 limestone, are kept suspended by a steady upward flow of primary ai r

through the fuel bed. This fuel bed fluidization promotes turbulence, which

improves mixing of fuel and air, allowing the FBC to combust solid fuel at a

substantially lower and more uniformly distributed temperature—typicall y

815 to 870 C (1,500 to 1,600 F) — compared to stoker or PC-fired boilers ,

where furnace temperatures can peak at 1,590 C (2,900 F).

This lower temperature range provides two of the three mai n

advantages of FBCs over conventional boiler units:

Lower combustion temperatures result in less formation o f

thermal NOx and allow use of sorbent to reduce SO 2 emissions

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. 

30
3-25

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

controlled by manipulating the primary bed parameters of height ,

temperature, fuel inpu t, and fluidization velocity—the velocity of the primary

air through the bed.

Firetube 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

relative 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

boilers, the bubbling bed and the circulating bed. The fundamenta l
3-26

Figure 3-14. Circulating FBC schematic. 32

distinguishing feature between the se types is the fluidization velocity. In the

bubbling-bed design, the fluidization velocity is relatively slow, rangin g

between 5 and 12 ft/s, the idea being to minimize solid carryover into th e

convective 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

erosion 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 trapped 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

circulating FBC maintains a continuous, high-volume recycle rate tha t

increases the fuel residence time compared to the bubbling-bed design .
3-27

Because of this, circulating FBCs often achieve higher combustio n

efficiencies and better sorbent utilization in the control of SO2 emissions than

bubbling-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

utility 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

are 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 exclusively. Another 18 units burned coal in combination with wood ,

2

sludge, coke, or biomass. The coal-burning FBCs ranged between 8.4 an d

235 MMBtu/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 boilers. The largest coal-fired FBC unit in non-utility application in the

United States has an approximate heat input capacity of 1, 070 MMBtu/hr

(315 MWt), generating 160 MWe of electric power at a cogeneration facility. 2

From an economic standpoint, ICI FBC boilers that burn coal do 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-fired unit. The use of lower cost opportunity fuels, such as coke ,

biomass, wood waste, a nd low-grade coals, can provide sufficient economic

incentive to offset higher initial capital costs. When used in electric powe r

generating applications, FBC coal-fired power plants produce elect ricity at 1.5
3-28

to 3 times the cost of gas-based power g eneration. Future growth in the ICI 34

FBC boiler 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 firetube boilers used with coal are the horizontal return tubular (HRT) ,

Scotch, 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 5
3-29

Figure 3-15. Two-pass HRT boiler.38
3-30

, 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, heating the outer shell of the tank. At the rear of the boiler, th e

combustion gases then enter the firetubes. The gases flow through th e

firetubes, 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 of 
3-31

scaling or slagging.

3.2.2.2 Scotch Firetube Boilers

A Scotch, or 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

occurs 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

four-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

common gas- and oil-fired Scotch units are shown in Figures 3-6 and 3-1 6
3-32

Figure 3-16. Four-pass gas-/oil-fired scotch boiler. 39
3-33

.

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 7
3-34

Figure 3-17. Exposed-tube vertical boiler. 37
3-35

 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. 37
3-36

Figure 3-1 8
3-37

Figure 3-18. Submerged-tube vertical boiler. 37
3-38

 shows a submerged-tube vertical boiler in which the firetubes extend from

the furnace to the tube sheet, which is below the water level. This desig n

prevents the ends of the firetubes from overheating. A conical flue ga s

collector 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

Vertical 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 Boilers
3-39
3-40
3-41

Another 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

compact firebox boilers. A locomotive boiler is a single-pass horizonta l

firetube boiler; a short firebox boiler is a two-pass horizontal firetube unit ;

and a compact firebox boiler is a three-pass horizontal unit. 37

Currently available coal-fired firebox units either employ mechanical

underfeed stokers, or are capable of being hand-fired. They are generall y

limited in size to below 25 MMBtu/hr (7.3 MWt) heat input capacity. 40

3.2.3 Cast Iron Boilers

Commercial 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 heat 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 than 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

boiler 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 burners
3-42

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 ,

multiple-burner arrangements provided a means of controlling heat input in

lieu 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

(packaged) 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 packaged gas/oil fired Scotch firetube boiler predominates. Almost all 42

of these applications are for heating where loads do not fluctuate quickly .

Boilers 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 capacity or higher. However, in the ICI sector, most are smaller tha n

250 MMBtu/hr (73 MWt). Larger oil- and natural-gas-fired watertube boiler s

that are field-erected are similar to PC-fired units in firing configuration, but
3-43

with smaller furnace volumes (higher heat release rate per unit volume o r

waterwall 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

more rapid combustion characteristics of fuel oil. Field-erected watertub e

boilers fired 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 input 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 distinguishing
3-44

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 flexible 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

11
3-45

Figure 3-20. D-type packaged boiler and watertubes.45
3-46

 depicts 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 common. 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 designs 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- gasfired 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 rated
3-47

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

the 
3-48

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 1
3-49

Figure 3-21. Vertical tubeless boiler. 46
3-50

. This boiler consists of a vertical, rigid steel pressure vessel enclosed inside

another 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

mounted on the outside of the outer pressure vessel. Heat is transferred to

the water located between the two pressure vessels. This type of boiler i s

packaged 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

referred 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

horizontally oriented, with watertubes arranged in a coil-like design. For a

given size, there is little variability in the design or configuration of oil field

steam generators. Figure 3-2 2

4 7
3-51

Figure 3-22. TEOR steam generator.49
3-52

 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

Natural-gas- and oil-fired boilers often use similar combustio n

equipment, 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 before 
3-53
3-54

combustion. 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

larger 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

compressed 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 sizes 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 as much as 150 psi. Oil pressures are much lower than fo r

50

mechanical atomizers. The steam atomizer performs more efficiently over a

wider load range than do mechanical atomizers.

In mechanical atomizers the pressure of the fuel oil itself is us ed as the

means for atomization. The oil pressure required at the atomizer fo r

maximum 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 viscosity 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 be
3-55

heated to reduce its viscosity to 135 to 150 Saybolt Universal Seconds. 50

Figure 3-2 3
3-56

Figure 3-23. Effect of temperature on fuel oil viscosity.51
3-57

 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

generate combustible wastes from their industrial processes. In general ,

nonfossil-fuel-fired boilers include any boiler used in the production of steam

or hot water from biomass, including wood wastes and bagasse, and general

solid waste, including MSW, industrial solid waste (ISW), and RDF. 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 wastes 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.

Stokers 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

fuel enters the furnace through a chute and is spread pneumatically o r

mechanically 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 the
3-59

remainder is fed above the g rate to complete combustion. Most stoker units

are equipped with a flyash reinjection system.

Other methods used to fire wood are overfeed and underfeed stoke r

firing, gasification, pyrolysis, fuel cell firing, suspension firing, and FBC ,

though to a lesser degree tha n spreader stoker firing. Another type of boiler

combustion system, the Dutch oven, is also in use, but has been essentially

discontinued from new construction due to its low efficiency, 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.

Gasification is a method of firing wood waste or other biomas s

whereby the 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 process 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 54

burner. 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

environment with little oxygen. Thermal cracking of the fuel occurs ,

producing combustible gases that are then burned. One system uses a

moving variable-speed grate to introduce the waste fuel to the 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 the flue gases directed to the boiler passes. This system is available in

heat input capacities from 14 to 57 MMBtu/hr (4.1 to 16.7 MWt).

In a fuel cell boiler, w ood is piled on a stationary grate in a refractorylined cell. Forced draft air is supplied to drive off the volatiles in the woo d

and burn the carbon. The volatiles are mixed with secondary and tertiar y
3-60

combustion 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 entering the furnace. However, most of the ash that does enter the

furnace is usually entrained in the flue gas. Most newer boilers utilize a

flyash reinjection system to minimize the amount of unburned carbon in the

flyash.

Wood is also fired in FBC boilers, which are 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

company's cogeneration plant, to a 180-MMBtu/hr (53-MWt or 27-MWe) unit,

used by an independent power producer. In an additional 29 units 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 MWe, roughly equivalent to 1,500 MMBtu/hr (440 MWt) heat inpu t

capacity. This unit was operated by an independent power producer, and is

atypical 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 common practice to use an auxiliary fuel, particularly fossil

fuel, in all types of wood-fired boilers. Approximately 50 percent of wood -

fired boilers have some type of fossil fuel firing capability. Fossil fuels are 53
3-61

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

boilers 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,

Louisiana, 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 a
3-62

Figure 3-24. Ward fuel cell furnace. 56

refractory 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 earlier. In one type of fuel cell boiler system, the Ward furnace ,

shown 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 is
3-63

considered one of the mos t reliable, flexible, and simple methods of burning

bagasse.56

Recent trends in bagasse firing have been toward using spreade r

stoker systems. Bagasse spreader stoker boilers are similar in design t o

wood-fired 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

auxiliary 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 utilities. 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

rubbish consists of material such as paper, cardboard, plastics, textiles ,

rubber, leather, wood, furniture, and garden trimmings. Treatment plant waste

consists of sludge from water, wastewater, and industrial wastewate r

treatment facilities. Special wastes are roadside litter, dead animals, an d

abandoned vehicles. The exact makeup of MSW varies both seasonally and

geographically. For example, more organic material is usually contained in

MSW during the fall, especially in areas such as the northeast where man y
3-64

trees are deciduous. Typically, ov er one third of MSW in the United States is

paper, 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 capacity, while mass-burning units are as large as 290 MMBtu/h r

(85 MWt). Modular units have been in operation in the United States since 59

the late 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 5
3-65

Figure 3-25. Large MSW-fired boiler.60
3-66

. 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

controlled air (pyrolysis) and refractory furnaces. Controlled-air MSW units

received much developmental attention during the 1970s. Many of thes e

units, however, were subsequently shut down due to operation al or economic

problems. 62
3-67

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

further capacity increases. A typical modular boiler, shown in Figure 3-2 6
3-68

Figure 3-26. Modular MSW-fired boiler. 63
3-69

, 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

processes. The composition of ISW fuel at any one site is usually relatively

constant because the industrial activities that generate the waste are usually

well regulated. The 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

described above. These units encompass the same capacity range of th e

modular MSW-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

fuels, 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

recycled, and the remainder of the refuse processed into pelletized o r

powdered form. RDF can be 
3-70

burned alone or in combination with coal or oil. The most common use of 54

RDF is as 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. resource 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

experience of mass burn plants in Germany, Switzerland, Japan, and a

number of U.S. locations. Based on the number of plants in operation and the

number being planned in the near future, mass burn is the MSW -firing system

of choice, although RDF firing is still considered a viable technique ,

especially when refuse throughput is low to moderate, on the order of a few

thousand tons per day. 62,65
3-71

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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. 10.

4. Nonfossil Fuel Fired Industrial Boilers—Background Information .

Publication No. EPA-450/3-82-007. U.S. Environmental 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

Combustion 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. Surprenant, N. F., et al. (GCA Corp.). Emissions Assessment o f

Conventional Stationary Combustion Systems, Volume IV :

Commercial/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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. pp. A-1 to A-5.

8. Surprenant, 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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. A-4.

10. Steam—39th Edition. 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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. A-12.

13. Ibid. p. A-24.

14. Ibid. pp. A-2 to A-3.

15. Ibid. p. A-15.

16. Pacemaker II. Bulletin No. F2350 R1. Industrial Boiler Co., Inc .

Thomasville, GA. December 1987.

17. The Fabric Filter Manual. The McIlvaine Company. Northbrook, IL .

May 1985. Chapter IX. p. 10.01.

18. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. 13.

19. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r

Combustion 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 Fabric 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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. A-6.

23. Ibid. p. A-8.

24. Boilers and Auxi liary Equipment. Power Magazine. McGraw-Hill, Inc.

New York, NY. June 1988. pp. B-28 to B-32.

25. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. 25.

26. Lim, K. J., et al. (Acurex Environmental Corp.). Industrial Boile r

Combustion 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. Scott, R. L. Fluidized Bed Combustion: Pressurized Systems. U.S .

Department of Energy. Morgantown, WV. 

30. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed C ombustion

Boilers Market Asses sment. Prepared for the Gas Research Institute.

Chicago, IL. August 1991. p. 13.
3-74

31. Makansi, 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.

Proceedings of the 1987 International Conference on Fluidized Be d

Combustion. The A merican Society of Mechanical Engineers/Electric

Power Research Institute/Tennessee Valley Authority. New York, NY.

1987.

33. Lorelli, J., and C. Castaldini (Acurex Corp.). Fluidized-Bed 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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

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

Environmental Protection Agency. Research Triangle Park, NC .

August 1979. p. 14.

36. Ibid. p. A-18.

37. Ibid. pp. A-21 to A-24.

38. Fusion Welded Horizontal Return Tubular Boiler To ASME Code .

Bulletin No. F3350. Industrial Boiler Co., Inc. Thomasville, GA.

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

Combustion 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. Devitt, T., et al. (PEDCo Environmental, Inc.). Population an d

Characteristics of Industrial/Commercial Boilers in the U.S .

Publication No. EPA-600/7-79-178a. Prepared for the U.S .
3-75

Environmental 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

Combustion 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. Three-pass Vertical Tubeless Boilers. Bulletin No. F2050 990-3.0 .

Industrial Boiler Co., Inc. Thomasville, GA.

47. NOx Emission Control for Boilers and Process Heaters—Trainin g

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. Nutcher, P. B. High Technology Low NO x Burner Systems for Fire d

Heaters and Steam Generators. Process Combustion Corporation .

Pittsburgh, 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. Nonfossil Fuel Fired Industrial Boilers—Background Information .

Publication No. EPA-450/3-82-007. U.S. Environmental Protectio n
3-76

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. Nonfossil Fuel Fired Industrial Boilers—Background Information .

Publication 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 Fabric Filter Manual. The McIlvaine Company. Northbrook, IL .

May 1985. pp. 325.03 to 325.05.

63. Nonfossil Fuel Fired Industrial Boilers—Background Information .

Publication No. EPA-450/3-82-007. U.S. Environmental 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

NOx is a high-temperature byproduct of the combustion of fuels with

air. NO formation in flames has two principal sources. Thermal NO is that x x

fraction of total NO x that results from the high-temperature reaction between

the nitrogen and oxygen in the combustion air. The rate of thermal NO x

formation varies exponentially with peak combustion temperature an d oxygen

concentration. Fuel NOx is that fraction of total NO that results from th x e

conversion of organic-bound nitrogen in the fuel to NO via a high- x

temperature 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 x formed. When low-nitroge n

fuels such as natural gas, higher grade fuel oils, and some nonfossil fuels are

used, nearly all the NO generated is thermal NO . When coal, low-grade fuel x x

oils, and some organic wa stes are burned, fuel NO x generally becomes more

of a factor because of the higher levels of fuel-bound nitrogen available.

Aside from the physical and chemical characteristics of the fuels, man y

boiler design 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

distribution, and boiler operating loads. For example, steam pressure an d

temperature requirements may mandate a certain heat release rate and heat

absorption profile in the furnace which changes with the load of the boiler .
4-2

Solid fuels can be introduced into the furnace in several ways, eac h

influencing the rate of mixing with combustion air and the peak combustion

temperature. These parameters are very unit specific and vary according to

the design type and application of each individual boiler. As described i n

Chapter 3, ICI boilers include a broad range of furnace types operating in a

variety of applications and burning a variety of fuels ranging from 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 chapter discusses the primary factors influencing baseline NO x

levels and summarizes the baseline (uncontrolled) NO x emission level s

measured from a variety of ICI boiler and fuel combinations. Parameter s

affecting NOx emissions from ICI boilers are discussed in Section 4.1, while

compiled baseline emissions for ICI boilers are presented in Section 4.2 o n

the basis of boiler fuel type. Section 4.3 presents a summary of th e

information presented in this chapter.

4.1 FACTORS AFFECTING NO x EMISSIONS FROM ICI BOILERS

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 NOx in combination with each other, and often to

different 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 example, 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 r
4-3

utility-sized boilers. Conversely, cyclone units generally have higher NO 1

x

levels than wall-fired units due to their inherent turbulent, high-temperature

combustion process, which is conducive to NO x formation. Even within a

2

particular type of boiler, other design details may influe nce baseline NO . For x

example, in field erected PC wall-fired units, NO x may vary depending upon

whether a wet bottom or dry bottom furnace is used. Wet bottom furnace s

have higher 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 x emissions than PC-fired

units since the stokers inherently operate in a "staged combustion "

configuration. 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 x, and is achieved by d elaying — or staging — the

addition of combustion air. Higher NO x levels reported for spreader stokers

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 other 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 furnace and is reduced in the freeboard zone, where heterogeneou s

reducing reactions between char and NO x occur. Also, newer FBC designs 6
4-4

are incorporating combustion air staging in their original configuration t o

achieve low emissions for permitting in strict environmental areas. In staged

configurations, the lower part of the fluidized bed and furnace are kept at or

below stoichiometry. T he staged addition of combustion air results in lower

NO levels compared to unstaged designs. x

Regarding smaller packaged natural-gas- or oil-fired boilers, NO x

emissions generally depend more on fuel, heat release rate and capacit y

characteristics. In general, ICI boilers with higher heat release rates an d

higher capacities tend to have higher levels of NO x. This is discussed in more

detail in Section 4.1.3. For a given heat release rate and fuel type, however,

there is no strong correlation between NO x emissions and whether a

packaged boiler is a firetube or a watertube design.

4.1.2 Fuel Characteristic s

ICI boiler baseline NO x emissions are highly influenced by th e

properties of the fuels burned . NOx and other emissions will vary depending

on whether natural gas, oil, coal, or nonfossil fuels are used. Additionally ,

among each of these fuel types, emissions will depend on highly 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 formation. x

3,7-9

Much attention has been given to the role of fuel-bound nitrogen in N Ox

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 burning, anywhere from 5 to 60 percent of the nitrogen is converted ,

whereas for other fuels as much as 80 percent of the fuel bound nitrogen is

routinely converted. In general, higher nitrogen fuels such as coal an d

10,11

residual oil have lower conversion rates, as shown in Figure 4- 1
4-5

Figure 4-1. Conversion of fuel nitrogen.11
4-6

, but higher overall NO rates 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, including No. 2 oil and diesel oil normally used in residential an d

commercial heating, internal combustion engines, and sometimes in large r

boilers strictly regulated for SO and NO emissions. Residual oil consists of 2 x

the higher temperature fractions and still bottoms from the distillatio n

process, including No. 4, 5, and 6 fuel oils often used in industrial and some

commercial boilers.

Table 4-1 lists the range and average concentrations of nitrogen and

sulfur in distillate, residual, and crude oils. The data were compiled 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 and 
4-7

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 OILSa

sulfur, thereby contributing significantly lower NO and SO emissions. x 2

Distillate 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.

Sulfur content is typically specified when residual oil is purchased .

This is done to meet environmental regulations and to safeguard boile r

equipment from acid corrosion. Although lower sulfur content generall y

means lower nitrogen, there is no appar ent direct relationship between these

two fuel oil parameters, as illustrated in Figure 4- 2
4-8

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 ,

significant 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

12
4-9

Figure 4 - 3
4-10

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

9
4-11

 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 residual and distillate oils were burned, a clear correlation was see n

between nitrogen content and NO x, with higher NO x levels reported for th e

higher nitrogen 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

comparing 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

play 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 nitrogen 
4-12

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

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

Figure 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

emissions for western sub-bituminous coal due to the higher coa l
4-13

oxygen/nitrogen ratio, despite the coal's lower fuel nitrogen content. On a

broader scale, coal property data show that coals with high oxygen/nitrogen

ratios generally have lower nitrogen contents. Thus, the two influences —

higher NOx due to higher oxygen content, and lower NO x due to lower nit rogen

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 x formation is the

fuel ratio, defined as the ratio of a coal's fixed carbon to volatile matter .

Typically, under unstaged combustion conditions, lower fuel ratios (i.e. higher

volatile content of the coal) correlate to higher levels of NO x, because with

higher volatile content coals, greater amounts of volatile nitrogen ar e

released in the high temperature zone of the flame where sufficient oxyge n

is present to form NO x. Thus, considered by itself, higher volatile coal firing 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 results 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 NOx emissions. Thus, the

higher NOx levels associated with higher volatile coals may be balanced to a

certain degree by the lower excess air capability provided.

The difference between average NO x emission levels reported among

various fuel oil types (i.e., residual versus distillate) lies primarily in the fact

that residual oils are produced from the residue left after lighter fraction s

(gasoline, kerosene, and distillate oils) have been removed from crude oil .

Residual oils thus contain high quantities of nitrogen, sulfur, and othe r

impurities. As discussed, fuels with high nitrogen contents generall y

produce higher levels of fuel-bound NO x than fuels with low nitroge n
4-14

contents. Thus, with residual oil in particular, fuel NO makes up a greate r x

portion of the total NO x emitted. For any parti cular class of boilers, the range

in NOx emissions for residual oil is often wider than the range of emissions

for distillate oil. The larger amount and variation of fuel nitrogen in th e

residual oil accounts for this. Even within one type of fuel oil, larg e

23

variations in NOx emissions can be recorded due to the other factor s

discussed in this chapter. The variability in NO x emissions between th e

boilers listed in Appendix A burning the same type of oil is chiefly due t o

variations in boiler heat release rates and operating conditions. 

Besides distillate oil, many nonfossil fuel types are low-nitrogen -

content fuels. Thus, NOx emissions from ICI boilers fired on these fuels and

on natural gas are almost entirely thermal NO x, and the major factors which

influence their NOx levels are furnace heat release rate (related to capacit y

and operating load) and excess air level, both of which are discussed below. 24

While most wood burning boilers are stokers and are similar in design t o

coal-fired units, the relatively low nitrogen content of wood contributes t o

much lower fuel-bound NO x formation than with coal. In general, with wood

wastes the generation of particulates and other unburned combustibles i s

more of a concern than NO x formation. The wood moistur e content and wood

fuel size 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

quantities of yard waste. These variables result in wide ranges in MS W
4-15

composition and corresponding fuel properties. Stud ies have shown that the

non-combustible 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 NOx formation. As heat release rate increases, so does peak furnace

temperature and NOx formation, as illustrated in Figure 4- 5
4-16

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

and natural gas

fuels.16
4-17

. Boiler heat release rate varies primarily with the boiler firing type, th e

primary fuel burned, and the 
4-18

operating load. Additionally, boiler heat release rate per unit volume is often 3

related to boiler capacity, as illustrated in Figure 4- 6
4-19

Figure 4-6. Furnace heat release rate versus boiler size.32
4-20

. 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/hr (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 x formation than

spreaders. 5

Because packaged natural-gas- or oil-fired watertube boilers ar e

available in higher capacities and heat release rates than firetubes, the high

end of the ranges of reported baseline NO x tends to be greater for th e

watertube designs. However, as noted in Section 4.1.1, there is no obvious

correlation per se between NO x emissions and whether a boiler is a firetube

or a watertube.

4.1.4 Boiler Operational Factors

In addition to boiler design and fuel factors, the conditions unde r

which a unit is operated also influence baseline NO x levels. Chief amon g
4-21

these operational 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. Combustion air temperature, meanwhile, is dependent on the 33

degree 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.

Numerous 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- 7
4-23

Figure 4-7. Effect of excess oxygen and preheat on NO emissions, natural- x

gas-fired boilers. 39
4-24

, which presents data for natural-gas-fired watertube and firetube boil ers. The

thermal 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

management of boilers. However, many ICI boilers are typically fired wit h

excess oxygen levels which are more than adequate to assure complet e

combustion and provide a margin of safety to the operator. Thus, these

38

units often are operated at unnecessarily high excess oxygen levels tha t

result in unnecessarily high NO x emissions and losses in efficiency. Utilit y

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 combustion 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 x impact on fuels such as natural gas

and 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 41
4-25

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 results 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 Boilers
4-26

Table 4 - 2
4-27

TABLE 4-2. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH AP-42 EMISSION

FACTORS, COAL-FIRED BOILERS

Boiler type

NO ,x

lb/MMBtua

CO,

lb/MMBtua

THC,

lb/MMBtua

Compile

d datab AP-42

Compiled

data AP-42

Compiled

data AP-42

PC wall-fired 0.46-0.89 0.58-0.81 c,d 0.0-0.05 0.02-0.04 0.001-0.019 0.004-0.007PC tangential 0.53-0.68 0.58-0.81 c,d 0.0-0.14 0.02-0.04 0.004-0.009 0.004-0.007Cyclone 1.12 e 1.31c,d 0.0e 0.02-0.04 N.A. f 0.004-0.007Spreaderstoker

0.35-0.77 0.42-0.54 0.0-0.53 0.19-0.35 0.0-0.018 0.004-0.007

Overfeedstoker

0.19-0.44 0.29-0.41 0.001-1.65 0.35-0.42 0.022-0.024 0.004-0.007

Underfeedstoker

0.31-0.48 0.37-0.42 0.0-0.94 0.42-0.76 0.010 0.081-0.150

Bubbling FBC 0.11-0.81 N.A. 0.17-0.49 N.A. N.A. N.A.CirculatingFBC

0.14-0.60 N.A. 0.02-0.25 N.A. N.A. N.A.

To convert to ppm @ 3% O, multiply by the following: NO, 740; CO, 1,215; THC, 2,130. a 2 x

See Appendix A for compiled data. b

Current AP-42 does not distinguish PC units by firing configuration, but by dry- versus wet- c

bottom.

Includes utility boilers. d

Single data point. e

N.A. = Not available. No data available. f
4-28

 summarizes reported baseline NO , CO, and THC emission ranges for coal- x

fired boilers, and lists current AP-42 emission factors for comparison. 42-45

Industrial PC-fired boilers were among the highest emitters of NO x. The

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 NOx emissions for dry-bottom boilers in the range of 0.58 t o

0.81 lb/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.

Spreader stoker units averaged 0.60 lb/MMBtu (450 ppm) NO x from a

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 x emitters compared to PC-fired boil ers

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

average NOx emission level of 0.27 lb/MMBtu (200 ppm), for bubbling be d

units, and 0.32 lb/MMBtu (240 ppm), 
4-29

for circulating FBC boilers. NO x emissions ranged from 0.11 to 0.81 lb/MMBtu

(80 to 600 ppm), for bubbling bed FBC units, and from 0.14 to 0.60 lb/MMBtu

(105 to 445 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) .

However, the measured CO emission levels for overfeed and underfee d

stokers encompassed much wider ranges than reported in AP-42, rangin g

from 0 to 1.65 lb/MMBtu (0 to 2,000 ppm). Likewise, the THC emissions fo r

overfeed stokers also differed greatly from the AP-42 values, averagin g

roughly 0.023 lb/MMBtu (50 ppm). Overfeed stoker THC data were available

for only two units, however. This and the wide range of reported emissio n

values indicates that available baseline CO and THC data from overfeed and

underfeed stokers are generally inadequate. Circulating FBC boilers tend to

have lower CO emissions than bubbling bed units, ranging from 0.02 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

ranging from 0 to 0.14 lb/MMBtu (0 to 170 ppm). CO emissions from th e

stoker units 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 y
4-30

lower 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

suspension and the remainder on grates, generally emit less CO tha n

overfeed and underfeed stokers, although the CO data in Appendix A fo r

underfeed 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 Boilers
4-31

Table 4 - 3
4-32

TABLE 4-3. COMPARISON OF COMPILED UNCONTROLLED EMISSIONS DATA WITH AP-42

EMISSION FACTORS, OIL-FIRED BOILERS

Oil type and boiler

capacity

NO ,x

lb/MMBtua

CO,

lb/MMBtua

THC,

lb/MMBtua

Compile

d datab AP-42

Compiled

data

AP42 Compiled data AP- 42

Residual Oil: Firetube units 0.21-0.39 0.37 0.0-0.023 0.03

3

0.002-0.014 0.01

1

 Watertube units: 10 to 100MMBtu/hr

0.20-0.79 0.37 0.0-0.114 0.00

3

 0.0-0.031 0.00

9

 >100 MMBtu/hr 0.31-0.60 0.28-0.45 0.0-0.066 0.03

3

0.002-0.016 0.00

7

Distillate Oil: Firetube units 0.11-0.25 0.14 0.0-0.014 0.03

6

0.012c 0.00

4

 Watertube units: 10 to 100MMBtu/hr

0.08-0.16 0.14 0.0-1.177 0.03

6

 0.0-0.003 0.00

2

 >100 MMBtu/hr 0.18-0.23 N.A. d 0.0-0.837 N.A. 0.001-0.009 N.A.
4-33

 gives 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 of x

capacity, with NO ranging from 0.20 to 0.79 lb/MMBtu (160 to 625 ppm) . x

Average baseline NO levels for distillate-oil-fired units were lower a t x

approximately 0.15 lb/MMBtu (120 ppm). NO x from the distillate-oil-fired units

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

majority 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

variability, 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 to 100 MMBtu/hr capacity range, units emitted between 0 an d

1.18 lb/MMBtu (0 and 1,530 ppm). CO emissions from distillate-oil-fire d

firetube units 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

maintenance 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

The 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 x ranged from 0.06 to

0.31 lb/MMBtu (50 
4-34

Boiler type and

capacity

NO ,x

lb/MMBtua

CO,

lb/MMBtua

THC,

lb/MMBtua

Compiled

datab 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 obtained at reduced boiler load and emissions from smaller capacit y

boilers. As illustrated in Appendix A, NO x emissions from natural-gas-fired

boilers tend to increase with increasing boiler capacity.

Baseline CO emission levels show wide variability, ranging from 0 to

1.45 lb/MMBtu (0 to 1,990 ppm). The data indicate that for natural-gas-fire d

boilers 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 Boilers
4-35

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 FOR

NONFOSSILFUEL-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 x emission factors

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-fired boilers in Appendix A show an NO x range of 0.010 to

0.30 lb/MMBtu (7 to 220 ppm corrected to 3 percent O 2). Many of these boilers

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 x levels

than biomass-fueled units. The current AP-42 NO emission factors for MSW- x

fired units and RDF-fueled units are 0.4 to 0.49 lb/MMBtu (280 to 3 50 ppm) and
4-36

Combustor type

Capacity

(tons/day)

Uncontrolled NO x

emissions, ppm @ 7%

O2

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 x EMISSIONS FROM MUNICIPAL WASTE

COMBUSTORSa

0.36 lb/MMBtu (250 ppm), respectively. Uncontrolled CO emissions fro m

these boilers are relatively high, 0.24 to 0.38 lb/MMBtu (280 to 440 ppm) .

Table 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 combustion sources, each tested over a period of 1 to 3 hours. Th e

average NOx level of 210 ppm corrected to 7 percent O translates int 2 o

approximately 0.4 lb/MMBtu.

Nonfossil-fuel-fired FBC boilers burning wood waste, manure, an d

other agricultural wa ste byproducts had NO x emissions ranging from 0.10 to

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 to 4.52 lb/MMBtu (440 to 5,200 ppm), due to several factors,

including wood composition and boiler design type. Unburned TH C

emissions 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 institutional boilers such as cast iron and tubeless units. This is due in

part to the virtual lack of regulations on boilers in the capacity range below

10 MMBtu/hr (2.9 MWt), with the exception of recent rules adopted 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 NOx emissions from natural-gas-fired TEOR stea m

generators range between 0.09 and 0.13 lb/MMBtu (75 a nd 110 ppm), while for

crude-oil-fired steam generators, baseline NO x emissions generally rang e

from 0.30 to 0.52 lb/MMBtu (240 to 400 ppm), depending on the nitroge n

content of the crude oil. Because there is less variability in the design s

46,47

and configurations of TEOR steam generators, their NO x emissions, for a

given fuel, are usually less variable than other boilers.

4.3 SUMMARY
4-38

Table 4 - 7
4-39

Fuel Boiler type

Uncontrolle

d NOx

range,

lb/MMBtu

Average,

lb/MMBtu

Pulverized

coal

Wall-fired

Tangential

Cyclone

0.46-0.89

0.53-0.68

1.12a

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 0.15b 0.15

MSW Mass burn

Modular

0.40b

0.49b

0.40

0.49

TABLE 4-7. SUMMARY OF BASELINE NO x EMISSIONS
4-40

summarizes baseline NO emissions for the major ICI boiler equipmen t x

categories discussed in Chapter 3. Coal-fired cyclone boilers generally emit

the highest 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, distillate oil, and wood fuels. NO x emissions from coal-fired FBC an d

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, NOx emissions from firetube boilers are l ower than from watertube

boilers. This is l ikely due to the fact that most watertube boilers have larger

capacities than firetube units. As discussed above, as boiler capacit y

increases, NO emissions also increase in most cases. x

Actual emissions from individual boilers vary widely by boiler hea t

release rate, fuel quality and type, boiler design type, and operating factors

such as excess 
4-41

air level 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

bagasse. It is important to recognize that large variations in baselin e

(uncontrolled) NOx levels are possible due to several boiler design an d

operational factors, including variations in the chemical makeup of the fuel.

The most important fuel property that influences NO x is the fuel nitroge n

content, which determines to a large degree the amount of fuel NO x that may

be formed during combustion.
4-42

4.4 REFERENCES FOR CHAPTER 4

1. Evaluation and Costing of NOx Controls for Existing Utility Boilers in

the NESCAUM Region. Publication No. EPA-453/R-92-010. U.S .

Environmental Protection Agency. Research Triangle Park, NC .

December 1992. pp. 3-5 to 3-6.

2. Yagiela, A. S., et al. (Babcock & Wilcox). Update on Coal Reburnin g

Technology for Reducing NO x in Cyclone Boilers. Presented at th e

1991 Joint Symposium on Stationary Combustion NO Control. x

Washington, D.C. March 1991.

3. Evaluation and Costing of NOx Controls for Existing Utility Boilers in

the NESCAUM Region. Publication No. EPA 453/R-92-010. U.S .

Environmental Protection Agency. Research Triangle Park, NC .

December 1992. p. 3-1.

4. Systems Evaluation of the Use of 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. Fossil Fuel-Fired Industrial Boilers — Background Information .

Publication 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 x/N2O Control for Fluidized Be d

Combustion Power 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. Fossil Fuel-Fired Industrial Boilers — Background Information .

Publication 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. Field Testing: Application of Combustion Modifications to Contro l

Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n
4-43

No. EPA-600/2-76-086a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. April 1976. pp. 164 to 169.

10. Industrial Boiler Combustion Modification NO Controls, Volume I : x

Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S.

Environmental Protection Agency. Research Triangle Park, NC. July

1981. p. 3-4.

11. Evaluation and Costing of NOx Controls for Existing Utility Boilers in

the NESCAUM Region. Publication No. EPA-453/R-92-010. U.S .

Environmental Protection Agency. Research Triangle Park, NC .

December 1992. pp. 3-1 to 3-2.

12. Field Testing: Application of Combustion Modifications to Contro l

Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n

No. EPA-600/2-76-086a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. April 1976. p. 218.

13. Field Testing: Application of Combustion Modifications to Control NOx

Emissions from Utility Boilers. Publication No. EPA-650/2-74 -066. U.S.

Environmental Protection 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. Field 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 Development of a Low NO x Burner Suitable for High Nitroge n

Liquid 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

Formation Potential of Residual Fuel Oils. Paper No. 24-543 .

Presented at the 24th International Symposium on Combustion .

Australia. 1992.

20. Municipal Waste Combustors — Background Information 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. Fossil Fuel-Fired Industrial Boilers — Background Information .

Publication 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: NOx

Combustion Modification. Publication No. EPA-600/7-79-178f. U.S .

Environmental Protection Agency. Research Triangle Park, NC .

December 1979.

23. Industrial Boiler Combustion Modification NO Controls, Volume I : x

Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S.

Environmental Protection Agency. Research Triangle Park, NC. July

1981. p. 3-33.

24. Ibid. p. 3-2.

25. Nonfossil Fuel-Fired Industrial Boilers — Background Information .

Publication 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 Examination of the Combustion Process. Publication No. 86 -

JPGC-Pwr-20. American Society of Mechanical Engineers. New York,

NY. October 1986. p. 5.

27. Peavy, H. S., et al. Environmental Engineering. McGraw-Hil l

Publishing Company. New York, NY. 1985. p. 583.

28. Nonfossil Fuel-Fired Industrial Boilers — Background Information .

Publication No. EPA-450/3-82-007. U.S. Environmental 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. Composition 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

Control 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. EPA-600/8-77-003a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. January 1977. pp. 6 to 7.

34. Industrial Boiler Combustion Modification NO Controls, Volume I : x

Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S.

Environmental Protection Agency. Research Triangle Park, NC. July

1981. pp. 3-13 to 3-68.

35. Fossil Fuel-Fired Industrial Boilers — Background Information .

Publication No. EPA-450/3-82-006a. U.S. Environmental 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. EPA-600/8-77-003a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. January 1977. pp. 38 to 40.

37. Field Testing: Application of Combustion Modifications to Contro l

Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n

No. EPA-600/2-76-086a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. April 1976. pp. 91 to 99.

38. Ibid. p. 91.
4-46

39. Industrial Boiler Combustion Modification NO Controls, Volume I : x

Environmental Assessment. Publication No. EPA-600/7-81-126a. U.S.

Environmental Protection Agency. Research Triangle Park, NC. July

1981. p. 3-68.

40. Fossil Fuel-Fired Industrial Boilers — Background Information .

Publication No. EPA-450/3-82-006a. U.S. Environmental Protectio n

Agency. Research Triangle Park, NC. March 1982. p. 4-117.

41. Field Testing: Application of Combustion Modifications to Contro l

Pollutant Emissions from Industrial Boilers — Phase II. Publicatio n

No. EPA-600/2-76-086a. U.S. Environmental Protection Agency .

Research Triangle Park, NC. April 1976. p. 146.

42. Compilation of Air Pollutant Emission Factors, Supplement A .

Publication No. AP-42. U.S. Environmental Protection Agency .

Research Triangle Park, NC. October 1986.

43. Compilation of Air Pollutant Emission Factors, Supplement B .

Publication No. AP-42. U.S. Environmental Protection Agency .

Research Triangle Park, NC. September 1988.

44. Compilation of Air Pollutant Emission Factors, Supplement C .

Publication No. AP-42. U.S. Environmental Protection Agency .

Research Triangle Park, NC. September 1990.

45. Compilation of Air Pollutant Emission Factors, Supplement D .

Publication No. AP-42. U.S. Environmental Protection Agency .

Research Triangle Park, NC. September 1991.

46. Hunter, S. C. and S. S. Cherry (KVB, Inc.). NO x Emissions from

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

Control 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. NOx CONTROL TECHNO

This chapter presents a survey of applicable control technologies t o

reduce NOx emissions from ICI boilers. A review of current knowledge on the

effectiveness, applicability, and limitations of specific control techniques is

presented for each major fuel/equipment category discussed in Chapter 3 .

These categories are as follows:

Coal-fired:

— PC, field-erected watertube

— Stoker coal, packaged and field-erected

— FBC

Oil-fired:

— Residual oil, packaged and field-erected watertube

— Residual oil, packaged firetube

— Distillate oil, packaged and field-erected watertube

— Distillate oil, packaged firetube

— Crude oil, TEOR steam generator

Natural-gas-fired:

— Packaged and field-erected watertube

— Packaged firetube

Nonfossil-fuel-fired:

— Stoker-fed

— FBC

NOx emissions data from more than 200 boilers were compiled fro m

technical reports, NOx control equipment manufacturer literature, an d
5-2

compliance 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 MMBtu/hr PC-fired boiler. However, more than 90 percent of the units

listed in Appendix B have heat capacities less than 400 MMBtu/hr. Most o f

the emissions data were obtained durin g short-term tests. Where noted, test

data were collected from long-term tests based on 30-day continuou s

monitoring.

The control of NOx emissions from existing ICI boilers can b e

accomplished either through combustion modification controls, flue ga s

treatment controls, or a combination of these technologies. Combustio n

modification NO x controls such as SCA, LNB, and FGR modify the conditions

under which combustion occurs to reduce NO formation. Flue gas treatment x

controls—principally SNCR and SCR — are applied downstream of th e

combustion chamber and are based upon chemical reduction of alread y

formed NOx in the flue gas. Other g as treatment controls, besides SNCR and

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-fired 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 this section, the main discussion of NO x controls for ICI boilers i s

preceded by Section 5.1, which presents a brief overview of NO x formation

and basic concepts for its reduction by combustion modifications. Sections

5.2, 5.3, and 5.4 disc uss combustion modification NO x controls for coal-fired

boilers, oil- and natural-gas-fired units, and nonfossil-fuel-fired boilers ,

respectively. Section 5.5 discusses flue gas treatment controls for I CI boilers.

5.1 PRINCIPLES OF NO x FORMATION AND COMBUSTION MODIFICATION

NOx CONTROL

NOx is formed primarily from the thermal fixation of atmospheri c

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

NOx, known as prompt NO, is often present, though to a lesser degree tha n

fuel or thermal NO . For natural gas, distillate oil, and nonfossil fuel firing , x

nearly all NO emissions result from thermal fixation. With coal, residual oil, x

and crude oil firing, the proportion of fuel NO can be significant and, under x

certain boiler operating conditions, may be predominant.

The actual mechanisms for NO x formation in a specific situation ar e

dependent on the quantity of fuel bound nitrogen , if any, and the temperature

and stoichiometry of the flame zone. Although the NO x formation

mechanisms are different, both thermal and fuel NO x are promoted by rapid

mixing of fuel and combustion air. This rate of mixing may itself depend on

fuel characteristics such as the atomization quality of liquid fuels or th e

particle fineness of solid fuels. Additionally, thermal NO is greatly 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 air
5-4

— Use of fuel-rich primary flame zone

Decrease residence time at high temperature:

— Decreased peak flame temperature:

Decreased adiabatic flame temperature through dilution

Decreased combustion intensity

Increased flame cooling

Controlled mixing of fuel and air

Use of fuel-rich primary flame zone

— Decreased primary flame zone residence time
5-5

Table 5 - 1
5-6

TABLE 5-1. SUMMARY OF COMBUSTION MODIFICATION NO CONTROL APPROACHES x

NO control approach x Control concept Effect on thermal NO x Effect on fuel NOx

Primary control techniques

Operationaladjustments

Hardware

modification Major redesign

Decrease primaryflame zone O level 2

Decrease overall O2level

Reduces O rich, high NO 2 xpockets in the flame

Reduces exposure offuel N intermediariesto oxygen

LEA firing and OT FGR Low excess air burners

Delayed mixing of fueland air

Flame cooling and dilutionduring delayed mixingreduces peak temperature

Volatile fuel N reducesto N in absence of 2oxygen

Burneradjustments andtiming

LNB Optimum burner/

firebox design

Primary fuel-richflame zone

Flame cooling in low O ,2low temperature primaryzone reduces peaktemperature

Volatile fuel N reducesto N in absence of 2oxygen

BOOS; biasedburner firing

OFA ports Burner/firebox design

for SCA

Decrease peak flametemperature

Decrease adiabaticflame temperature

Direct suppression ofthermal NO mechanism x

Minor RAP FGR, LNB, water

injection

Decrease combustionintensity

Increased flame cooling;yields lower peaktemperature

Minor direct effect;indirect effect onmixing

Load reduction Enlarged firebox,

increased burnerspacing

Enlarged firebox,increased burnerspacing

Increase flamecooling; reduceresidence time

Increased flame zonecooling; yields lower peaktemperature

Minor Burner tilt WI or SI Redesign heat transfer

surface, fireboxaerodynamics

Create secondary NOxreducing zone

Use of low O2secondary combustionzone

Primary zone NO reduces xto N in absence of O 2 2

Primary zone NOxreduces to N in 2absence of O2

OFA ports Install reburning

burners, OFA ports;replace tube wallpanels, pipingductwork

Fuel switching Burn higher quality

fuel with low or nonitrogen content

Minor or slight increasebecause of highertemperature flame

Large NO reduction xdue to reduced fuelnitrogen conversion

Minor if dual-fuelcapability exists

Only for installation ofburner and fueldelivery system
5-7

 shows the relationship between these control strategies and currentl y

available combustion modification NO x control techniques, which ar e

categorized as either operational adjustments, hardware modifications, o r

techniques requiring major boiler redesign. The use of a secondary NO x

reduction 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

staging, or reburning, and is discussed in greater detail in the followin g

subsections. Additionally, fuel switching is also considered a viabl e

combustion control because of the reduction or elimination of fuel NO x with

the burning or cofiring of cleaner fuels. Table 5- 2
5-8

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

NO control x

technique

Coal-fired Oil-/natural-gas-fired Nonfossil-fuel-fired MSW-fired

Field-erected

PC-fired Stoker

FB

C

Fielderected

watertube

Packaged

watertub

e

Packaged

firetube Stoker FBC Mass burn

BT/OT X X

WI/SI X X

SCA X X a X X X b Xa X X a

LNB X X X X

FGR X X X X

NGR X b Xb

SNCR X b X X X X b X X X

SCR X b Xb Xb

BT/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-NO burners xFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid waste

SCA is designed primarily for control of smoke and combustible fuel rather than for NO control. Optimization of existing SCA (OFA) ports a x

 can lead to some NO reduction. x

Limited experience. b
5-9

 identifies combinations of NO x controls and major boiler fuel type categories

for which retrofit experience is available and documented.

Typically, the simplest boiler operational adjustments rely on th e

reduction of excess oxygen used in combustion, often referred to as BT/OT.

Figure 5 - 1
5-10

 NO t baseline operating conditions,

Figure 5-1. Effect of excess O on emissions for firetube boilers a 2 x
5-11

 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 NOx emissions can be reduced 10 to 15 percent when th e

stack excess oxygen concentration is lowered from 5 to 3 percent, measured

in the flue gas on a dry basis. The actual amount of NO x reduced by

decreasing 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

Although LEA operation can produce measurable reductions in NO ,x

in this study, LEA will not be considered a separate control technology bu t

a part of other retrofit technologies, since it accompanies the application of

low NO combustion hardwar e such as low NO burners. Additionally, boiler x x

operation with LEA is considered an integral part of good combustion ai r

management 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, x
5-12
5-13
5-14

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

reduced excess oxygen for a residual

oil-fired watertube industrial boiler. 5

excessive reduction in excess air can be accompanied by significan t

increases 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 loss 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 combustion modifications that reduce NO x often result in reduce d

combustion efficiency (manifested by increased CO).

Another operational adjustment listed in Table 5-1, load reduction ,

when implemented, decreases the combustion intensity, which, in turn ,
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

load turndown capability. Operating at reduced load is often infeasible fo r

many ICI boilers because steam load is dictated by process steam demands

and cannot be controlled independently. Reduced load on on e boiler must be

compensated for by increased load on another boiler, unless energ y

conservation 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 x are generally

predominant, a third type of NO x, known as prompt NO, has also bee n

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 NOx. C 2 and CH radicals present in hydrocarbon flames are believed

to be the primary sources of prompt NO because t hey react with atmospheric

nitrogen to form precursors such as HCN and NH 3, which are rapidly oxidized

to NO. The formation of prompt NO is greater in fuel-rich flames, an d

decreases with the increase in local O concentrations. Like fuel and thermal 2

6

NO formation, prompt NO formation has been shown to be a function o f x

flame temperature and stoichiometry. Prompt NO, however, generall y

accounts for smaller levels of NO than are due to thermal or fuel NO . For 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

6
5-16

In ICI boilers, prompt NO is believed to account for the first 15 to 20 ppm of

NOx formed during combustion. The control of prompt NO is not typicall y

7

targeted because of prompt NO's minor combustion to total NO . However, x

as NOx limits for ICI boilers grow stricter, especially in areas such as th e

South Coast 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 x controls that ar e

commercially available and the documented experience in NO x reduction

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

bituminous coal differ from those attainable when burning high volatil e

subbituminous coal or l ignites. However, the data available on coal-fired ICI

boilers 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 x controls. This secti on includes

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 ICI boiler population. Additionally, combustion modification tests for
5-17

bubbling bed FBC (BFBC) units include results obtained at pilot-scal e

facilities. 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 these controls. Little research on full-scale NO control retrofit x

technologies has been undertaken. Pilot-scale res earch provides an in-depth

view into the mechanisms of NO x formation and control in FBC. These data

are used in this study to support conclusions with respect to NO x reduction

efficiencies and controlled limits.

Sections 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 Combustion Modification NO x Controls for Pulverized Coal (PC)-fired

ICI Boilers
5-18

Table 5 - 3
5-19

TABLE 5-3. COMBUSTION MODIFICATION NO CONTROLS FOR FULL-SCALE PC-FIRED INDUSTRIAL x

BOILERS

Control technique Description of technique

Type of

industrial boiler

tested

% NOx

reduction

Controlled NO levels x

ppm @ 3% O ,2

lb/MMBtu Comments

SCA Fuel-rich firing burners with

secondary air injection

Wall-firedWall-firedWall-fired

Tangential

15273925

691 (0.93)250 (0.34)651 (0.88)

211-280 (0.29-0.38)

OFA.BOOS, reduced load.OFA, reduced load.

LNB Wall-fired boiler — LNB with

distributed air for controlledmixingTangential-fired boiler — uses airon wall concept for controlledmixing

Wall-firedWall-firedWall-firedWall-fired

Tangential

4965674918

280 (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 lowNO concentric firing system x(LNCFS).

Reburn with SCA(OFA)

Injection of coal, natural gas, oroil downstream of the burner area

Wall-fired

 w/coal reburn

Wall-fired

 w/coal reburn

Tangential-fired

 w/oil reburn

N.A.a

N.A.

30

170-250 (0.23-0.34)215-385 (0.29-0.52)

167 (0.23)

SCA (OFA) used with reburn inall tests.

LNB+SCA Combination of LNB and SCA

control techniques

Wall-firedWall-firedWall-firedWall-firedWall-firedWall-firedWall-fired

Tangential

4266

N.A.

6062654455

180-360 (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) NO data available. a x

Note: 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 PC-fired boilers. The table provides the ranges of percent NO x

reduction and the controlled NO x levels achieved in these tests. Mor e detailed

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 x, discussed in Section 5.1, is to dec rease

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 completed. 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

result, 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

alters the heat release profile which changes the slagging rates an d

properties 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 boiler 
 All ppm values in this study are referenced to 3 percent O .

a

2

5-21

with 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

obtained during this study. Using OFA, a 25 percent reduction in NO x was

achieved at the first unit, a tangential-fired unit at the Kerr-McGee Chemical

Corporation facility in Trona, California. This unit was retrofitted with a

separated OFA system in conjunction with an LNB system. Separated OFA

refers to the use of a separate OFA windbox mounted above but not a n

integral part of the main windbo x, as opposed to "close coupled" OFA which

is injected within the main windbox just above the top elevation of fuel .

Controlled NOx emissions from this unit range d from 211 to 280 ppm (0.29 to a

0.38 lb/MMBtu); 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 NOx emissions from this unit were 690 ppm (0.93 lb/MMBtu). The

NOxreduction efficiencies of these two units are in agreement with OF A

performance 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

effectively reduce NO without adversely affecting operation and equipment x

integrity. First, there must be sufficient height between the top row o f

burners 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 N2, and adequate residence time for the second stage gases to

achieve carbon burnout before exitin g the furnace. In order to maximize NO x

reduction, 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 complete 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 x. Additionally, OFA port design must, take int o

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

walls 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

remaining firing burners, keeping firing capacity constant. For maximu m

effectiveness, 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

burners located on two separate levels. With PC-firing, BOOS is commonly

considered more of an operating practice for pulverizer maintenance than for
5-23

Figure 5-3. Effect of BOOS on emissions.
5-24

NO control, as pulverizers are routinely taken out of service because o f x

maintenance requirements. The ability of boilers to operate units with on e

less pulverizer is generally very limited. For this reason, BOOS is not a

popular control option for PC-fired units.

Data for two wall-fired units operating with one pulverizer out o f

service show NOx reduction efficiencies of 27 and 39 percent. For on e

230 MMBtu/hr boiler, NO x was reduced from 340 ppm to 250 ppm (0.46 t o

0.34 lb/MMBtu), while for a 260 MMBtu/hr unit, NO x was reduced fro m

1,065 ppm to 651 ppm (1.44 to 0.88 lb/MMBtu). However, in order to achieve 12

the 39 percent reduction rate with the larger boiler, it was necessary for that

particular boiler to be operated at 50 percent load reduction. Additionally ,

airflow could not be easily controlled to the individual burners so that burner

swirl and coal air mixing were affected. 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

techniques of OFA and BOOS showed NO x reduction ranges of 15 t o

39 percent, while the single tangential-fired boiler with SCA showe d

25 percent reduction (see Table 5-3). Although the two units operated wit h

BOOS accounted for the higher NO x reduction efficiencies of 27 an d

39 percent, both had to be operated at significantly reduced load. Because

industrial units have fewer burners and typically have more limited pulverizerburner 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 of
5-25

the 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 staging in this type of LNB is accomplished by dividing th e

combustion 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

zone, where the remainder of burner air is injected. Peak combustio n

temperatures are also lower with the staged air burner because flames ar e

elongated and some heat from the primary combustion stage is transferred

to the boiler tubes prior to the completion of combustion. As discussed i n

Section 5.1, NOx formation is reduced due to the lowering of the peak flame

temperature, the delayed air/fuel mixing, and the low oxygen primary zone ,

where volatile fuel bound nitrogen compounds reduc e to form N2. Thus, both

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 o
5-27

Figure 5-4. Foster Wheeler CF/SF LNB. 9

industrial units. The CF/SF burner, shown in Figure 5-4, is an internall y

staged dual register burner. The outer register, where secondary air i s

injected, controls the overall flame shape while the inner register control s

ignition at the burner throat and the air/fuel mixture in the primar y

substoichiometric region of the flame. The newer version of the CF/S F

13

burner 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,

Virginia. This unit, fired on bituminous coal, utilizes four CF/SF burners .

Nearly 50 percent NO x reduction was achieve d, with average post-retrofit NO x

emissions 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 t
5-28

Figure 5-5. Performance of CF/SF LNB. 10

150 MMBtu/hr heat input) four-burner, wall-fired steam boiler, wher e

65 percent NOx reduction from baseline was achieved. Post-retrofit NO x

emissions at this site averaged 220 ppm (0.30 lb/MMBtu). Figure 5-5 shows 10

the NOx reduction performance of these two units —labeled as numbers 4 and

5 in the figure—as well as several utility sized boilers.

Babcock & Wilcox's DRB-XCL burner also utilizes dual registers 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

ring near the walls of the nozzle and a fuel-lean core. Reducing species are

formed by partial oxidation of coal volatiles from primary air and limite d

secondary air. The re ducing zone created in the fuel-lean core prevents NO x

formation 
5-29

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 NOx emissions

were reduced approximately 67 percent, when operating at the same excess

air level. Controlled NO x emissions for this unit ranged between 190 an d

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- 6
5-30

ondary air diverter.

Figure 5-6. Riley low-NO CCVTM burner with sec x 16
5-31

 depicts this 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

coal nozzle, creating a fuel-rich zone. As in the CF/SF LNB, the coal/ai r

mixture is divided into four distinct streams which then enter the furnace in

a helical pattern. This produces very slow mixing of the coal with secondary

air, which is injected through the single register. Devolatilization of the coal

in the fuel-rich mixture occurs at the burner exit in a substoichiometri c

primary combustion zone, resulting in lower fuel NO x formation. Thermal NO x

formation is suppressed by the reduction of peak flame temperature whic h

results from the staged combustion. 16

Riley's Tertiary Staged Venturi (TSV) burner is similar to the CC V

burner but uses additional tertiary air and an advanced air staging (OFA )

system for reducing NO x emissions. This burner was developed for use on

Riley's TURBO furnaces as well as downfired and arch fired boilers. These

boilers are characterized by downward tilted burner firing, which lengthens

the residence time of combustion products in the furnace. As such, th e

inherently long furnace retention time combined with gradual or distributed

air/fuel mixing typically results in lower NO emissions than a conventiona l x

wall-fired unit operating at similar conditions with identical fuel. TURBO

16

furnaces are commonly used to burn low volatile coals such as anthracite ,

which require longer residence time for complete combustion. Figure 5- 7
5-32

or turbo-furnace, down-fired and archFigure 5-7. Riley low-NO TSV burner with advanced air staging f x
5-33

 shows a schematic of a TURBO furnace and the TSV LNB. Six TSV burners,

in conjunction 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 NOx emissions ranged between

220 and 370 ppm (0.30 and 0.50 lb/MMBtu). 17

A different type of LNB has been developed for tangential-firing P C

boilers, incorporated into the LNCFS system. The burner itself, manufactured

by ABB Combustion 
5-34
5-35

Engineering, is referred to as the Concentric Firing System (CFS). The CFS

creates local staging by diverting a portion of secondary air horizontally away

from the coal stream toward the furnace waterwall 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 attachment feature provides greater control over volatile matter flame

stoichiometry 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

reduction was achieved, to 269 ppm (0.36 lb/MMBtu). When the full LNCF S

was used (CFS+OFA), NO reduction improved to 55 percent, with NO at 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 are 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 required 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

furnace walls. Because flames from staged combustion burners are ofte n
5-36

longer than from conventional burners, this may be a particularly important

issue to small-volume furnaces.

NOx emissions data for PC-fired units with LNB are summarized i n

Table 5-3. For four wall-fired units, NO x reductions ranged between 49 an d

67 percent, with controlled NO x emissions of 190 to 370 ppm (0.26 t o

0.50 lb/MMBtu). One tangential-fired unit experienced 18 percent reduction

efficiency, with an NO x level of 269 ppm (0.36 lb/MMBtu) . Again, the minimum

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

Reburning, also known as fuel staging, involves injecting a

supplemental fuel into the main furnace above the primary combustion zone

to produce a secondary combustion zone where a reducing atmospher e

exists. The general idea is to provide a chemical path for the primary zon e

NO to convert to N2 rather than NO 2. Hydrocarbon radicals formed durin g

secondary combustion provide this chemical path; hence, some of the NO x

created 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

boilers in Japan. Mitsubishi Heavy Industries (MHI) has developed th e

Mitsubishi Advanced Combustion Technology (MACT) pr ocess utilizing oil as

the reburn 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 NOx reduction to a level of 167 ppm (0.23 lb/MMBtu), durin g

bituminous coal firing. MACT has been used in at least eight other wall or 19

tangential coal-fired industrial boilers in Japan, with capacities rangin g
5-37

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 x reduction efficiencies of reburning in a

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

reduction efficiencies of 54 to 65 percent were achieved. Results showed

21

that reburning with natural gas produced the best NO x reduction and th e

lowest average NOx emissions, between 235 and 420 ppm (0.32 an d

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

SO2 emissions. The use of coal as a reburn fuel resulted in the lowest NO 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

applying natural gas reburn technology to cyclone-fired boilers. Cyclon e

boilers are currently being used in both the utility and industrial sectors .

Because cyclone boilers have a unique configuration that prevents th e

application of standard low-NO x burner technology—combustion occur s

within a water-cooled horizontally-tilted cylinder attached to the outs ide of the

furnace—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

conclusion that in general, it is unfeasible to retrofit cyclone boilers belo w

80 MWe capacity with natural gas reburn controls, which essentially excludes
5-38

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.

Thus, reburn technology is generally not applicable for retrofit t o

smaller 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 may emerge as a viable NO x control technique for industrial PC-fired

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 Foster 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 boilers, and in fact is responsible for the majority of NO x reduction

achieved. As mentioned earlier, in the Kerr-McGee boiler in California ,

18

55 percent NOx reduction was achieved with the LNCFS, combining OFA and

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 NOxreductions in the range of 42 to 66 percent (see Table 5-3). N o

baseline 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

250 MMBtu/hr unit at Western Illinois Power Cooperative's (WIPCO) Pear l

Station. Field tests showed that under normal operation, 50 percent red uction
5-39

of NOx was typically achieved while under careful ly controlled conditions, the

66 percent NOx reduction level was possible. Retrofit of four distribute d

mixing burners 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 extensive 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 NOx levels for these wall-fired units ranged between 1 80 and

370 ppm (0.24 and 0.50 lb/MMBtu). Generally, on utility bo ilers, NOx reduction

performance 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

data for PC-fired ICI boilers using LNB and SCA precludes reaching an y

definitive conclusions.

5.2.2 Combustion Modification NO x Controls for Stoker Coal-fire d ICI Boilers

The two most commonly used combustion modification NO x controls

for stoker coal-fired ICI boilers are SCA and FGR. A third combustio n

modification, RAP, has not been utilized as often. Gas cofiring with burners

above the grate is under active evaluation. Table 5- 4
5-40

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

BOILERS

Control

technique

Description of

technique

Type of

Stoker

boiler

tested

% NOx

reducti

on

Controlled NOx

levels ppm @

3% O ,2

lb/MMBtu Comments

SCA Reduction of

combustion airunder the grate andincrease of overfireair flow

SpreaderSpreaderSpreaderSpreaderSpreaderSpreaderOverfeedOverfeed

6

10263135

N.A.a

-1

N.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+SCA Recirculation and

mixing of stack fluegas with theundergrate orovergratecombustion air

SpreaderSpreaderSpreader

0

1360

300-345 (0.41-

0.47)

350 (0.47)140 (0.19)

FGR primarily leads toNO reduction by xlowering achievableexcess O .2

RAP Reduce temperature

of preheatedcombustion air

Spreader 32 219 (0.30) Limited applicability to

larger units with airpreheaters. Reducesboiler efficiency.
5-41

 summarizes 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 x control efficiency, ranging from

-1 to 60 percent reduction. Controlled NO x levels for spreader stokers wit h

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 design. 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 in

24

Appendix A, uncontrolled NO x emissions ranged from 341 to 659 ppm (0.4 6

to 30.89 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

stoker units, uncontrolled NO x levels ranged from 158 to 443 ppm (0.21 t o

0.60 lb/MMBtu).
5-42

The availability of existing OFA ports offers the opportunity fo r

increased air staging. Additional staging can be achieved by injecting more

overfire air above the fuel bed while reducing the undergrate airflow. Using

OFA, the boilers for which data were collected show a NO x reduction range

of zero to 35 percent, averaging 17 percent reduction. In two boilers, OFA did

not affect NOx. Controlled NO x emissions ranged from 230 to 400 ppm (0.31

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 older stokers incorporate OFA ports as smoke control devices.

Therefore, these OFA ports may not be optimally located for NO control x

purposes. For example, in one test, injection of OFA through oil burner ports

high above the grate reduced NO x by 25 percent. When OFA was injecte d

through the 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 flow for staging, there are certain operational limitations involved. First,

with the exception 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

overheat. There is also the possibility of creating local reducing zones with

low oxygen which may form harmful corrosion products. Still another

25

problem that may arise from reduced undergrate air firing is the formation of

clinkers. 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. 26 Thus, a minimum

amount of undergrate air must be used to provide adequate mixing an d
5-43

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, allowing boiler operators to lower the overall excess air level whic h

consequently reduces formation of NO x. FGR is primarily considered a

thermal NOx control technique, reducing NO x by lowering the peak furnac e

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 - 8
5-45

Figure 5-8. Schematic diagram of stoker with FGR. 27
5-46

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 NOx. In this unit, minimum excess oxygen levels and boiler loa d

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 operated at minimum stack excess oxygen of 8 percent. Figure 5- 9

illustrates the effect of adding FGR to the boiler on allowable excess oxygen.

After retrofit, boiler operators could lower excess oxygen levels to as low as

3 percent, keeping opacity the same a s pre-retrofit levels. Not only does this

represent a significant increase in boiler efficiency, but because NO x is

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 FGR
5-47

allowed the excess oxygen level to be reduced from 8 percent t o

approximately 3.5 percent, resulting in a reduction of NO x by as much as

60 percent. A controlled emission level of 140 ppm (0.19 lb/MMBtu) wa s

measured. Another spreader stoker unit also displayed simila r

27

characteristics 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 utilize the entire length of the grate for primary combustion, overfeed

stoker units often have sho rter active grate combustion zones depending on

the location of the furnace wall arch over the grate, as shown in Figure 5-11
5-48

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

27 Figure 5-11. Overfeed stoker with short active combustion zone. 26
5-49

. The particular boiler tested had a very short act ive combustion zone limited

to the front 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

combustion zone to lengthen beyond the furnace arch, resulting in flam e

quenching and impingement on the arch. Also, FGR caused unstabl e

combustion at the front portion of the active combustion zone. In contrast 26

with overfeed 
5-50
5-51
5-52

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 summary, the use of FGR in stoker coal-fired ICI boilers has bee n

demonstrated suc cessfully in a limited number of boilers. NO x reduction on

two of the spreader stokers ranged from 13 to 60 percent. For the overfeed

stoker 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 ,

thereby reducing NOx emissions and increasing boiler efficiency. FGR ha s

also been shown to be beneficial in dealing with grate overheating.

5.2.2.3 RAP

RAP is limited to stokers equipped with combustion air preheaters .

Usually only larger stokers with heat input capacities greater tha n

100 MMBtu/hr tend to have air preheaters. RAP is not commonly used i n

28

such boilers because significant losses in boiler efficiency occur when th e

flue gas bypasses the air preheaters. In bypassing the preheaters ,

recoverable heat from the flue gas is not utilized and the temperature of the

flue gas leaving the stack is increased unless major equipment modifications

are made to the heat transfer surfaces. Available emissions data for RAP is

limited to one spreader stoker boiler. Reduction of preheated combustion air

temperature reduced NO x by 32 percent. Because of its limited applicability 28

and negative effects on boiler efficiency, RAP is not considered a p rimary NOx

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

burning a fraction of the total fuel, typically 5 to 15 percent, as natural ga s
5-53

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 x levels. Recent tests on a spre ader stoker have

shown that NOx emissions can be reduced by 20 to 25 percent. More tests 29

are planned.

5.2.3 Combustion Modification NO x Controls for Coal-fired Fluidized-be d

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 x

 formation is

limited to the conversion of fuel nitrogen (fuel NO x). At these low combustion

temperatures, studies have shown little correlation between temperature and

NOx emission, thus combustion modification NO x controls for FBC boiler s

focus on the control of fuel NOx. The principal combustion modification 30,31

controls used for NO reduction in FBC boilers are staged combustion , x

control of bed temperature, and FGR. Table 5- 5
5-54

TABLE 5-5. NO CONTROL TECHNIQUES FOR FBC BOILERS x 30

Control

technique Control mechanism Application limits Potential limitations

SCA Staged combustion

reduces oxygen forconversion of volatilenitrogen; promotesheterogeneous NOreduction with CO overchar; causes increase inCaO char concentrationin dense bed

Secondary/primary airratio limited byfluidization requirementsin FBC and reheat steamtemperatures

Increase in CO emissions,carbon loss, and reducedsulfur capture primarily inFBC under severe staging(SR <0.8); excessive steam 1temperature

Control ofdense bedtemperature

Lower bed temperaturereduces volatilenitrogen conversion andincreasesheterogeneousreduction between charand formed NO

Bed 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 1,600 F forhigh sulfur capture.

Excessive temperaturereduction increases CO andcarbon loss (efficiencyreduction), necessitatinglonger gas residence timefor char combustion,especially with lowreactivity coal
5-55

summarizes the performance and process requirements of these thre e

techniques. Each of these control approaches is discussed in the following

subsections. Process variables that impact NO x formation are als o

discussed. As indicated earlier, most combustion modification research for

FBC has been conducted on pilot scale facilities. Available data from full -

scale units are limited; thus, the pilot-scale data offer the greatest 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 x from FBC boilers. Nearly all new commercial FBC

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 x formation

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

oxygen. By using SCA, which lowers the excess oxygen level in the dens e

portion 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 to
5-56

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

University. 34

NOx dominates the overall fuel NO x, and nitrogen is released at a muc h

slower 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

NOx reductions due to SCA in coal-fired FBC boilers have bee n

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 at 
5-57

Chalmers University in Sweden. Keeping the total excess air between 20 and

23 percent, NOx was reduced 40 percent from 125 to 75 ppm (0.17 t o

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, NOx reduction from baseline was only slightly more

than 40 percent. Meanwhile, CO emissions more than doubled from a

baseline level of 270 ppm to 565 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

instance, at the TNO Research facility in Sweden, tests conducted on a

14 MMBtu/hr BFBC 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 concerns 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 x reduction. Several tests have

shown that the greater the distance to the secondary air ports, the greater is

the NO suppression. This is due 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 NOx emission levels for FBC units with SCA have been highly

variable depending on the capacity, fuel type, OFA port location, and design

type (i.e., CFBC or BFBC) of the boilers. For instance, controlled NO x
5-58

Control

technique

FBC boiler

type

Controlled NO x

level, ppm @ 3%

O2, lb/MMBtu

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

from 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 x. Data obtained for full-scale units showed controlle d

39

NOx emissions ranging from 39 to 335 ppm for five CFBC boilers, and 75 to

100 ppm for two BFBC units. These data are tabulated in Table 5-6. Othe r

sources have reported p ractical NOx limits achieved with SCA to be between

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 Control
5-59

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

combustion 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 1,560 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 x formation for a pilot-scale BFBC was

reported to be about 2 to 3 ppm NOx reduction for every 10 C in temperature

drop. Figure 5-13 show s this effect, as well as the bed temperature's effect 41

on CO emissions, which increase as temperature is lowered. The effects of
5-60

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

University. 34

bed temperature on NO x and CO are shown in Figure 5-14 for the full-scal e

16 MWe BFBC test unit at Chalmers University, showing 54 percent NO x

reduction when bed temperature was lowered from 880 to 780 C (1,620 to

1,440 F). This equates to 13 ppm NO reduction per 10 C temperature drop, x

a greater effect than was experienced with the pilot-scale 
5-61

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

increase with lowered bed temperature, remaining fairly constant a t

270 ppm. For a CFBC pilot unit, the effect of bed temperature on NO 34

x

reduction was 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 NOx, the lowering of bed and freeboard gas temper atures is not considered

a primary NO control method. Steam temperature control, sulfur capture , x

and combustion 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

FGR through the air distribution plate in a FBC boiler is not a widel y

accepted NOx control technology, or one that has received much researc h

effort 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 extent, FGR also reduces thermal NO x by lowering the pea k

combustion temperature. When FGR is used in combination with SCA, th e

primary mechanism that results in NO x reduction is the gas temperature drop

in the lower portion of the bed combined with a localized reduction in th e

oxygen concentration. However, thermal NO x reduction in FBC is not as high

a priority as the control of fuel NO x. FGR application in FBC has been limited

for the most part to pilot scale research. However, test results reported for
5-62

two full scale CFBC units with SCA and FGR show a marked NO x reduction

efficiency of nearly 70 percent for FGR rates in excess of 30 percent .

Controlled NOx emissions ranged from 90 to 116 ppm (0.12 t o

0.16 lb/MMBtu). These data are listed in Table 5-6 and in Appendix B. 33

Several 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

Because 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

categories: chemical and physical coal properties, chemical and physica l

properties of sorbent and bed material, and FBC operational variables.

Coal Properties

Two important coal properties are the reactivity and size. Lowe r

reactivity coals emit lower levels of NO x under both staged and unstage d

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

with 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 x when low reactivity coals are burned, as discussed

in Section 5.2.3.1. Generally, an increase in coal size tends t o reduce NOx and
5-63

improve thermal efficiency. NO x is reduced due to the reduced surface area

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

NOx emissions also depend on the nitrogen content of the volatil e

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

NOx emissions will tend to be less under staged conditions than for unstaged

combustion.

The sulfur content of the coal does n ot in itself have any effect on NO x

emissions. Indirectly, however, the use of high-sulfur coals requires mor e

limestone sorbent to su ppress SO2 emissions, which will likely increase NO x

unless 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 catalyst in the oxidation of NH 3 to NO, increasing the conversio n

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

properties 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

CFBC boilers utilize lower Ca/S levels than do BFBC units, and thus tend to

emit less NOx. With staged combustion, however, the effect of Ca/S ratio on

NO formation is reduced due to the catalytic effect of CaO and CaS on 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 4 concentrations are

high, a net reduction in NO x is achieved with increased ash recycle. Th e

CaSO4 acts as a catalyst in oxidation of NH and reduction in NO in th 3 e

freeboard section of the furnace, according to localized temperature an d

concentration of NH and O . This was demonstrated in a 125 MMBtu/h r 3 2

45

BFBC boiler 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 x. However, under staged conditions, it i s

likely that better distribution of the coal and increasing the bed depth wil l

offer improved NO x control and more efficient operation, although th e

reduction is anticipated to be small. 46

The effect of fluidization velocity on NO x emissions from FBC boilers

is generally small. At constant high excess air levels, an increase in fluidizing

velocity 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

design and process parameters to such an extent that NO x levels can vary

significantly from one unit to the next. For a given type of FBC design, coal

properties such as nitrogen content and reactivity; and FBC operatin g

conditions such as bed temperatur e, ash recirculation, and coal distribution;

are principal variables affecting NO x. Additionally, the sulfur content of the

coal together with the required amount of sulfur capture determine th e
5-65

amount of sorbent used, which in turn influences NO x. Sorbent reactivity and

size distribution also play important roles in NO emissions since they affect x

calcium utilization 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 x CONTROLS FOR OIL- AN D

NATURAL-GAS-FIRED ICI BOILERS

Combustion modification NO x controls for full-scale oil- an d

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 x emissions from ICI boilers

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 x emissions are

limited to 30 ppm. Rule 1146.1 mandates a 30 ppm (0.04 lb/MMBtu) limit for

ICI boilers of at least 2 MMBtu/hr capacity but less than 5 MMBtu/hr .

Additionally, several districts re strict NOx from boilers used in the petroleum

refining 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 light distillate oil. Applicable controls include WI/SI; FGR; LNB; SCA ,

including BOOS and OFA; and a combination of these.

The control of NO x from fuel oil combustion relies on the suppression

of both fuel and thermal NO , while 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

temperature. Applicable combustion modification control techniques ar e

SCA, including BOOS and OFA; use of LNBs; FGR; and combinations of thes e
5-66

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

high-nitrogen residual oil to lighter oil fractions or gas have come unde r

increased consideration in regional and seasonal NO compliance options . x

Fuel switching is discussed in this section along with more traditiona l

combustion modification controls.
5-67

Tables 5 - 7
5-68

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

INDUSTRIAL

BOILERS

Control

technique Description of technique

Number of

industrial

boilers tested % NO reduction x

Controlled NOx

levels ppm @ 3% O ,2

lb/MMBtu Comments

WI Water injected into the flame in amounts

equivalent to a fraction of the fuel.

Watertube—2a 50-77 35-45 (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.

SCA Fuel-rich firing burners with secondary air

injection.

Watertube—5b

Watertube—7c

Firetube—1b

17-46

N.A.d

5

50-200 (0.06-0.24)67-170 (0.08-0.20)

67 (0.08)

Includes BOOS and OFA. BOOSapplies to multi-burner units only.

LNB LEA burners operate at lower oxygen

concentrations. Staged combustion burnerscontrol mixing of primary combustion airand fuel. Also have radiant ceramic fiberburner which reduces peak furnacetemperature.

Watertube—18b

Watertube—177c

Watertube—21g

Firetube—5bFiretube—2g

39-71 (for 5 boilers)e

N.A.N.A.

32e

N.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 LNB Flameless premix ceramic radiant burner Firetube—6 53-82 9-30 (0.01-0.036) Special design LNB limited to firetube

applications (<10 MMBtu/hr).

FGR Recirculation and mixing of stack flue gas

with burner combustion air.

Watertube—20bWatertube—13c

Firetube—57

53-74 (for 2 boilers)e

N.A.

55-76 (for 10 boilers)e

18-67 (0.02-0.08)30-85 (0.04-0.10)16-61 (0.02-0.08)

Requires motor, fan, and connectingducting. Reported NO data is for FGR xrates of 10 to 30%.

LNB+FGR Combination of LNB and FGR control

techniques.

Watertube—22bWatertube—50c

Firetube—5b

55-84 (for 5 boilers)e

N.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+SCA Combination of LNB and SCA control

techniques.

Watertube—9c N.A. 85-170 (0.10-0.20) Applicable principally to multi-burner

boilers.
5-69

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

Control

technique Description of technique

Number of industrial

boilers tested

% NOx

reduction

Controlled NOx

levels ppm @

3% O , lb/MMBtu 2 Comments

LNB Staged combustion burners control

mixing of primary combustion airand fuel

Residual WT, FT-18a,b

Residual WT-24

c

Distillate WT-7

b

Distillate WT-71

c

Distillate FT-1

b

30-60

N.A.

d

N.A.N.A.

15

69-200 (0.09-0.25)

80-475 (0.10-0.60)

e

60-119 (0.08-0.15)

65-260 (0.08-0.33)

f

120 (0.15)

Staged air burners could result inflame impingement on furnacewalls of smaller units.

FGR Recirculation and mixing of stack

flue gas with combustion air

Residual WT-2

b

Residual WT-1

c

Distillate WT-6

b

Distillate WT-2

c

Distillate FT-11

b

4-30

N.A.

20-68

N.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%.

SCA Fuel-rich firing burners with

secondary air injection

Residual WT-11

b

Residual WT-3

c

Residual FT-1

b

Distillate WT-1

b

Distillate WT-3

c

5-42

N.A.

4930

N.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+FGR Combination of LNB and FGR

control techniques

Residual WT-1

b

Residual WT-4

c

Distillate WT-10

b

Distillate WT-26

c

N.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+SCA Combination of LNB and SCA

control techniques

Residual WT-11

c

Distillate WT-6

c

N.A.N.A.

160-315 (0.20-0.40)

160 (0.20)

Applicable principally to multiburner boilers.

aWT = watertube; FT = firetube. Watertube boilers include both single-burner packaged (PKG-WT) boilers and multi-burner field-erected (FE-WT) boilers.

Data primarily from test reports. See Appendix B.

b

Data from Coen Company. See Appendix C. NO levels are not necessarily actual. Often represent vendor-guaranteed levels.

c

x

N.A. = Not available. No baseline (uncontrolled) NO data available.

d

x

Range for 90 percent of units listed in Appendix C.

e

Range for 96 percent of units listed in Appendix C.

f

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

applicability of these techniques for natural- gas-fired and oil-fired ICI boilers,

respectively. For natural-gas-fired boilers, more data were available fo r

watertube units equipped with LNB or combined LNB and FGR. Controlle d

NOx levels for these units ranged from as low as 13 ppm (0.02 lb/MMBtu) to

as high as 170 ppm (0.20 lb/MMBtu). The limited data available for gas-fired

watertube units with SCA show controlled NO x levels of 50 to 200 ppm (0.06

to 0.24 lb/MMBtu). Controlled NO emissions from gas-fired firetube units , x

most equipped 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

NOx levels. For example, units fired on distillate oil with LNB showed NO 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

methods as they are applied to both oil and natural gas combustion .

Although difference s in fuel type are acknowledged and affect NO x emission

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

collected for this section are contained in Appendix B. Additionally, dat a

provided by Coen Company and 
5-71
5-72

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 x in

natural-gas-fired ICI boilers. When water or steam are injected in the flame,

they reduce the peak flame temperature and the oxygen concentration. The

quenching of the flame reduces the NO x by as much as 75 p ercent, depending

on the amount of water or steam injected. Less water than steam is needed

to achieve the same quenching effect because of the heat of 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

technique is considered particularly effective for small single-burne r

packaged boilers operated infrequently. In these applications, the oil gu n

48

positioned in the center of the natural gas ring burner is used to inject th e

water at high pressure. The amount of water injected normally varie s

between 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 NOx reduction with water injection

rate. However, the technique has some important environmental and energy

impacts. 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-NOx Burners (LNBs) in Natural-gas- and Oil-fired ICI Boilers

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 firetube and field erected watertube boilers. Most of the available
5-74

data 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

staged 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

(Tampella 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

cyclonic burner, both of which are for use primarily in smaller package d

firetube boilers.

There 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 data in Tables 5-7 and 5-8 indicate that ICI boiler LNB experience

includes the reported NO levels and reduction efficiencies shown in Table 5- x
5-75

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 x LEVELS AND REDUCTION

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 residual oil, the heat release rate, and the amount of combustion ai r

preheat combined with level of FGR used for gas fuel are among the mor e

critical factors contributing to the wide range in controlled NO x levels. The

following subsections highlight the principal design features of LNB types.

5.3.2.1 Staged Combustion Burners

Staged combustion burners, the most common type of LNB, achieve

lower 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 applied to watertube boilers since 1979. Figure 5-16

50
5-76

Figure 5-16. Staged air LNB. 53
5-77

 is a schematic of a typical staged air burner, in which primary, secondary ,

and tertiary (denoted as staged air in the figure) air are injected into 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 .

Secondary and tertiary air complete the combustion downstream of th e

primary zone, lowering the peak temperature and reducing thermal NO x

formation. 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 packaged units because there is the possibility that flame impingemen t

will occur on the furnace walls, resulting in tube failure and corrosion .

Additionally, staged air burners are often wider and longer than conventional

burners, requiring significant modifications to existing waterwalls an d

windboxes. Burner size 
5-78

may also be an important fa ctor when assessing the feasibility of retrofitting

boilers located in restricted spaces.

Staged fuel burners are a slightly more recent development in staged

combustion LNBs. These burners were originally developed for use o n

process heaters in the refining and petrochemica l industries, and hence have

been applied primarily to process heaters rather than boilers. Figure 5-1 7
5-79

Figure 5-17. Staged fuel LNB. 52
5-80

 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 fuel is divided into primary and secondary streams. Despite the hig h

oxygen concentration in the primary combustion zone, therma l NOx formation

is limited by low peak flame temperatures which result from the fuel-lea n

combustion. Quenching of the flame by the high excess air levels als o

occurs, further limiting the peak flame temperatures and providing activ e

reducing agents for NO x reduction. Inerts from the primary zone the n

52

reduce peak flame temperatures and localized oxygen concentration in th e

secondary combustion zone, thereby reducing NOx formation. An advantage

of staged fuel 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, NOx reductions of 39 to 71 percent were r eported for three existing and

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 range is quite wide due to differences in boiler design, capacity, an d

burner 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

mentioned 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 a
5-81

staged air burner showed a 32 percent reduction in NO x, from 100 ppm down

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

natural-gas-fired LNB installations showed guaranteed or actual NO x levels

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 packaged to field erected units producing 25,000 to 520,000 lb/hr o f

steam (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 installations that reportedly emit 40 ppm NO x (0.05 lb/MMBtu) or les s

when firing natural gas. All of these boilers are packaged units ranging from

9,000 to 100,000 lb/hr steam capacity. 58

For smaller industrial gas-/oil-fired boilers, Riley Stoker has als o

introduced 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 recirculation
5-83

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 x levels in the

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 9
5-84

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

NOx emissions in the 30 to 40 ppm (0.035 to 0 .048 lb/MMBtu) range have been
5-85

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 air

preheat. 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 summary, LNB NO x reduction efficiencies for natural-gas-fire d

boilers including one firetube boiler and five watertube units range from 32

to 71 percent, in agreement with previously reported performance levels for

natural gas firing. LNB reduction efficiencies for 13 additional watertub e

units listed in Appendix B could not be computed because of a lack o f

baseline (uncontrolled) emissi ons data. Controlled NO x emissions for the 18

watertube 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

0.17 lb/MMBtu), for the remaining boilers, which ranged in size from 45 t o
5-86

380 MMBtu/hr input. Controlled NO x emissions reported by two LN B

manufacturers for nearly 200 units ranged between 30 and 170 ppm (0.04 to

0.20 lb/MMBtu). Some burner manufacturers have reported NO x reduction

efficiencies of anywhere from 50 to 
5-87

90 percent. In fact, several manufacturers guarantee NO x emissions belo w

40 ppm (0.05 lb/MMBtu) when firing natural gas in smaller indust rial packaged

boilers, primarily in response to the SCAQMD regulations in California. For

example, Faber, a division of Tampella Power, guarantees less than 40 ppm

NOx on any burner system and will guarantee less than 30 pp m

(0.04 lb/MMBtu) of NO x on a case-by-case basis. Similarly, Coen Company 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

firing distillate oil and 46 boilers firing residual oil. The distillate-fuel-fire d

boilers with staged air LNBs showed controlled NO x levels of 60 to 260 ppm

(0.08 to 0.33 lb/MMBtu). The 25 domestic units fired o n No. 6 residual oil (fuel

nitrogen contents 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

reduction 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,

test results showed NO x reductions between 30 and 60 percent, wit h

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

applications where new fan or ducting equipment are desired, som e

manufacturers 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

process heaters. This burner, depicted in Figure 5-2 1
5-89

Figure 5-21. Pyrocore LNB schematic. 63
5-90

, 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 emits 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

passes through a porous burner material and is ignited, establishing a thi n

combustion layer in contact with the surface. Because the surface material

is cooled by the incoming air/ fuel mixture and the material has a low thermal

conductivity, radiant temperatures of 1,700 to 2,000 F occur only on the outer

surface. 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 x reduction of 78 percent, with controlle d

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 x, to a controlled level of 24 ppm (0.03 l b/MMBtu), while a third

test on a 2 MMBtu/hr unit resulted in a controlled emission level of 17 ppm.

On the average, results from five field tests and one laboratory test showed

that NO was reduced by 71 percent and CO by 94 percent. To date, most x

64

burners supplied by Alzeta have been designed to achieve less than 30 ppm

NOx at full rated load, although the act ual emissions for many are reported to

be below 20 ppm. Currently, the single-burner applications of this burner are

limited to small packaged boilers of less than 20 MMBtu/hr because o f

physical 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 the 
5-91

Pyrocore burner's applicability to larger firetube and watertube boilers ,

including the use of multiple burners.

Additional research is currently focusing on the use of lower surface

firing rates, moderate temperature environments, and modest excess air t o

attain ultra-low NO x levels of 9 ppm and below. Alzeta Corporation and Zurn

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 York-Shipley for packaged firetube boilers. The burners are available up

to 16.6 MMBtu/hr heat input. In cyclonic combustion, high tangentia l

velocities 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 x formation. The tangential flame causes clos e

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

transfer and low excess air operation of the cyclonic burner result i n

increased boiler efficiency.

To achieve ultra-low NO x levels, a small quantity of low-pre ssure steam

is injected into the burner, which furt her reduces the local flame temperature

and NOx formation. Testing revealed that NO x emissions during natural gas

firing could be reduced from 70 ppm to less than 20 ppm without affectin g

burner 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 66
5-92

with 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 involves recycling a portion of the combustion gases from th e

stack 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 x control concepts similar to FGR

are such 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 currently being used on a number of watertube and firetub e

boilers firing natural gas. Only limited NO x reduction efficiency data ar e

available, however, as baseline (uncontrolled) NO x data for most units ar e

unreported. Data for four natural-gas-fired watertube boilers equipped with

FGR show a range in NO x reduction of 53 to 74 percent, while for 10 gas-fired

firetube units with FGR, NO x reduction efficiency ranged from 64 t o

76 percent. In all, controlled NO emission data were collected for a total of x

33 gas-fired watertube and 57 gas-fired firetube units operating with FGR .

Four of the watertube units and 26 of the firetube units were identified a s

retrofit applications. Controlled NO x levels ranged from 20 to 85 ppm (0.02 to

0.10 lb/MMBtu) 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

NOx reduction efficiency data for oil-fired units with FGR are also very

limited. In one test program, a single boiler was fired o n both residual oil and

distillate oil, using FGR and keeping all other variables constant. NO x was

reduced by 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 rather x

than fuel NOx. The 68 percent reduction was obtained with a relatively high

FGR rate of 28 percent. Another boiler firing distillate oil reported NO x

reduction of only 20 percent, using 10 percent FGR. Available data are to o

limited to estimate typical NO x reduction efficiencies for oil-firing boilers with

FGR. In general, however, thermal NO x reductions from distillate-oil-fire d

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

combustibles from distillate-oil-fired units, which limits the practical rate of

FGR that can be used. Controlled NO x emissions for distillate oil firing with

FGR were between 28 and 240 ppm (0.04 to 0.30 lb/MMBtu) for 19 boilers. For

three units firing residual oil, controlled NO x levels ranged from 125 t o

275 ppm (0.16 to 0.35 lb/MMBtu).

When compared to the number of LNB or combined LNB and FG R

installations 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

existing packaged watertube ICI boilers, FGR is rarely applied without th e

installation 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 injected into the combustion zone. Oxygen trim systems have been 57
5-94

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 most common combustion modification NO x controls for package d

watertube boilers are either LNB or combined LNB and FGR. FGR systems

have been applied more commonly to smaller firetube units. A typical FGR

system is shown in Figure 5-22. In order to retrofit a boiler with FGR, 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

boilers 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 boilers 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

commercially in an industrial unit in California, achieving NO x emission

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

volatility 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 benefits of FIR technology is that it impacts both prompt NO an d

thermal NO formation in gas-fired boilers. x

A second fundamental feature of FIR is that flue gas recirculation i s

induced using the natural gas dynamics of the burner flow streams, without

additional 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 Combustion Air (SCA) in Natural-gas- and Oil-fired ICI Boilers

Staged 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

accomplished using secondary OFA or side-fired air ports, or by using th e

BOOS technique. The applicability of OFA, side-fired air, or BOO S

(collectively grouped under the term SCA) depends primarily on the type of
5-96

furnace 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

implementing 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 x control method for existin g

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 for one experimental application of side-fired air to a 12 MMBtu/h r

firetube boiler fired on residual oil and natural gas. In this test program ,

sponsored by the U.S. EPA, secondary air was injected at the rear of th e

furnace opposite 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 x was reduced from 177 ppm

to 90 ppm (0.22 to 0.11 lb/MMBtu), a 49 percent reduction in NO x. During

these residual oil combustion tests, th e burner was operated at 76 percent of

stoichiometric conditions, and the overall excess oxygen level wa s

4 percent. 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 x, showing only 5 percent NO x reduction, from

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 load and because the burner oxygen level was higher, at 90 percen t

stoichiometry. Also, because natural gas combustion emits lower levels of
5-97

NOx than residual oil firing to begin with, it is generally more difficult t o

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 NOx control option due to the difficulty

of retrofitting SCA hardware. Hence, experience on these units has bee n

limited. Data are available for two experimental retrofit applications of SCA

in single-burner oil- and gas-fired packaged watertube units. The firs t

application, in a 22 MMBtu/hr unit (Location 19), involved the injection o f

secondary air through four steel lances which were inserted through th e

windbox and the refractory firing face. At 83 percent load, NO x emissions

were reduced by 29 percent (controlled NO = 157 ppm or 0.20 lb/MMBtu ) x

when residual oil was fired, by 30 percent (controlled NO = 77 ppm or 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 with combustion air preheating, which could vary the temperature

from 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 natural 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 maximize NOx reduction using SCA in packaged watertube units, it i s

necessary to operate the burner at substoichiometric levels, and secondary
5-98

air must 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

packaged watertube boilers are generally not considered practical fro m

installation and operational standpoints.

5.3.5.3 Field-erected Watertube Boilers

For field-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 more fuel is sent to desired burners. Usually, the upper row of burners

is fired fuel-lean, but this varies from boiler to boiler. 

BOOS is more applicable as 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 burners can be taken out of service. For this reason, BOOS is mor e

often used as a maintenance operation than a direct NO x control method. In

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

retrofit NOx control techniques because few equipment modifications ar e

required. For natural gas firing, data compiled for three industrial b oilers with

BOOS showed NO x reductions ranging from 17 to 44 pe rcent, with an average

of 29 percent reduction from uncontrolled NO x levels. Controlled NO x

emissions from these units, ranging in size from 60 to 120 MMBtu/hr, wer e

between 117 and 200 ppm (0.14 and 0.27 lb/MMBtu). For residual oil firing, 75
5-99

data from nine boilers using BOOS showe d NOx reduction efficiencies of 5 to

40 percent.

The wide range in control efficiencies is attributed to several factors,

including the burner arrangement, the percentage of burners taken out o f

service, and the overall excess air. Some burner arrangements are mor e

effective in reducing NO x with BOOS. For example, a square burner matrix is

more effective than an arrang ement in which all of the burners are located at

the same level. Another controlling factor is stoichiometry of the activ e

burners.

Although operation with BOOS can measurably reduce NO x, the

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 emissions. Adjustments to the airflow controls, such as burne r

76

registers, may be required to achieve the desired burner stoichiometr y

without increasing these emissions. Also, operation with BOOS usuall y

requires that the unit be derated unless modification to the fuel deliver y

system is made. 77

Data on NOx reductions from field-erected oil- or gas-fired ICI boilers

using OFA are very limited. Controlled emissions from two units firin g

residual oil were from 160 to 180 ppm (0.20 to 0.23 lb/MMBtu). Application 57

of the technique to utility boilers in California has reportedly resulted i n

average NO reductions of 24 percent for oil and nearly 60 percent for gas. x

78

Generally, 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 x Controls for Natural-gas- and

Oil-fired ICI Boilers
5-100

Many retrofits have utilized combinations of the above combustio n

modification methods. The most demonstrated combination is the use o f

LNB with FGR. As mentioned earlier, retrofit of combined LNB and FG R

controls 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 NOx control regulations without using

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. Many of the California boilers were existing units retrofitted with

LNB/FGR controls.

NOx reduction efficiencies of 55 to 84 percent were reported for fiv e

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 x emissions at or below 40 pp m

(0.05 lb/MMBtu), while the non-California units reported NO x levels between

40 and 170 ppm (0.05 to 0.20 lb/MMBtu). For the distillate-oil-firing units ,

baseline uncontrolled NO x levels were not available; thus, NO reductio x n

efficiencies could not be determined. Controlled emissions ranged from 30

to 200 ppm (0.04 to 0.25 lb/MMBtu). For the residual-oil-firing units ,

controlled 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

costs 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

watertube boiler resulted in controlled NO x emissions of 64 pp m

(0.08 lb/MMBtu), while in a new 150 MMBtu/hr residual-oil-fired boiler th e
5-101

controlled NOx level was 175 ppm (0.22 lb/MMBtu). Coen Company reports 81

controlled NOx emissions from 85 to 170 ppm (0.10 to 0.20 lb/MMBtu) for nine

boilers 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

emissions 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 x as any

other 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

natural gas in a gas cofiring configuration in the top row of burners of a

PC-fired boiler (representing a more strategic way to maximize NO x reduction

efficiency with reburning techniques) can result in larger NO x reductions

reaching 35 to 60 percent from uncontrolled levels. Figure 5-23

82
5-102

ions.

Figure 5-23. Effects of cofiring on NO emiss x 82
5-103

Fuel type

Fuel

nitrogen, %

weight

NOx

emissions

@ 3% O2

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

 illustrates NOx reduction as a function of gas cofiring rate, expressed as a

percentage of total heat input, measured during six full-scale utility boile r

cofiring field tests. These results are applicable, in theory, to large PC-fired

industrial boilers.

The replacement of high-nitrogen residual oil with a lower nitr ogen fuel

or natural gas is also very effective in reducing NO x. To illustrate, the dat a

shown in Table 5-10 were obtained from industrial boilers firing a residual oil

first, and then switching to a distillate fuel. 2 NOx reductions ranged fro m

about 50 to 80 percent for reductions in fuel oil nitrogen of 
5-104

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 x REDUCTIONS WITH FUEL SWITCHING

approximately 0.19 to 0.436 percent by weight. If all the recorded NO x

reduction is attributed to the drop in fuel nitrogen, about 55 to 65 pp m

reduction in NOx results from each 0.1 percentage point reduction in th e

nitrogen content of the oil. Table 5-11 lists estimates of NO x reductions

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 is marketing a proprietary liquid fuel for industrial boilers. Thi s

proprietary fuel is similar to distillate oil in thermal energy and physica l

properties, but contrary to distillate oil it contains essentially no fuel-bound

nitrogen (3 to 9 ppm). Therefore, its NO x emissions are similar to thos e

achievable with natural gas. Short-term performance with this proprietary 83

fuel show FGR-controlled emissions in the range of 18 to 35 ppm corrected
5-105

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 Combustion Modification NO Controls for Thermally Enhanced Oi l x

Recovery (TEOR) Steam Generators

NOx controls for TEOR steam generators have also been implemented

primarily 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, the 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 form 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 x. It has been reported that these device s

typically reduce the formation of NO x from small steam generator s

(<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). For

87

larger units greater than 35 MMBtu/hr (most 62.5 MMBtu/hr), Kern County data

from 326 tests showed controlled NO x levels ranging between 174 an d

340 ppm (0.22 and 0.43 lb/MMBtu). No uncontrolled data were reported fo r

these units; thus, it was not possible to report actual NO x reduction

efficiencies. However, assuming a typical uncontrolled NO x level of 300 ppm

(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

emission levels and average reported baseline levels. Actual NO x reduction

efficiencies may have been significantly higher or lower depending on the fuel
5-106

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 O2 controllers, have been

applied 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

86,87,89
5-107

Figure 5-24. North American LNB on oil field steam generator.92
5-108

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

 depicts one type of LNB+ SCA system, manufactured by the North American

Company, the principal vendor of LNB systems for TEOR steamers. Thi s

burner 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

various locations in the radiant heat transfer section. In a 62.5 MMBtu/h r

steam generator, 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 controllers are used to keep excess oxygen at the stack below 2 percent. 2

NOx emission levels of 100 to 160 ppm (0.13 to 0.20 lb/MMBtu) have bee n

reported when crude oil is f ired, representing 50 to 70 percent NO x reduction

when compared to unstaged conventional North American burners. 89

Another type of LNB system applicable for retrofit to TEOR stea m

generators is the single toroidal combustor, developed by Proces s

Combustion Corporation (Figure 5-25). The single toroidal combustor is a

two-stage burner in which approximately one-third of the fuel is combusted
5-109

under highly reducing, turbulent conditions inside a preco mbustion chamber.

The remaining 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 firebox. The vigorous internal recirculation and mixing within the fuel- 90

rich precombustion cha mber aids in NO x reduction, while combustion gases

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 x reductions of 60 percent, with averag e

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 x levels

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 flame 
5-110

by a blanket of recirculated flue gas. This burner, the MHI PM low-NO burner, x

illustrated schematically in Figure 5-2 6
5-111

Figure 5-26. The MHI PM burner nozzle. 93
5-112

, 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

TEOR 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 was

93

x

reduced by 63 percent.

Most 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 x levels of 87 to 232 ppm (0.11 t o

0.29 lb/MMBtu). Because no baseline data were available, it was impossible

to calculate NOx reduction efficiencies for these tests. However, thes e

controlled emissions may be compared to the generally accepted averag e

baseline 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 unit 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. x
5-113

Because of the limited data, however, no conclusions can be drawn abou t

typical reduction efficiencies for LNB gas firing.

LNB systems have also been applied on a very limited basis to steam

generators smaller than 35 MMBtu/hr. Reported NO x emission reduction s

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, LNB

86

retrofits 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 2

 trim showed controlled NO x levels

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 for x

two of these units ranged from 50 to 68 percent. For these particular units,

these reductions in NO x represent significant improvement over NO x

reduction 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 NOx formation
5-114

in natural-gas-fired packaged boilers. Originally designed to p roduce savings

in fuel consumption, the turbulator is a small stainless steel ventur i

incorporating strategically placed fins. The turbulator is inserted in the gas

pipe directly upstream of the burner, creating highly turbulent fuel flow. This

turbulence facilitates the bonding of hydrocarbon particles with the oxygen

molecules of the combustion air, resulting in increased 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 x. The only turbulator-related NO x emissions 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 turbulator raised full-load boiler efficiency by 3 percent, and the improved

air/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 COMBUSTION MODIFICATIONS FOR NONFOSSIL-FUEL-FIRED IC I

BOILERS

Application of combustion modification NO controls to nonfossil-fuel- x

fired ICI boilers is very limited. Many waste-fuel-fired boilers are not easily

modified to reduce NO x without compromising combustion efficiency an d

byproduct emissions. Furthermore, nonfossil fuels inc lude a variety of waste

fuels 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 applied
5-115

to at least 17 units fired on wood or MSW. These applications are discussed

in Section 5.3.

Combustion modification retrofit experience has been limited to th e

use of SCA. In one wood-/natural-gas-fired overfeed stoker unit, equippe d

with 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 x reduction was achieved, it should be noted

that combustion modification was applied to the gas burners without an y

change to the wood-firing stoker system. This control approach would no t

be possible on boilers without supplemental gas firing. Difficulties wer e

experienced with fluctuating bark flows, resulting in unsteady combustio n

conditions. 74

Applications of combustion modifications to new nonfossil-fuel-fired

units 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 x control purposes and to suppress the formation

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 also decreased by 50 percent, to levels below 25 ppm. Natural ga s

reburn represented 12 to 15 percent of the total heat input, and FGR rate s

during 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 efficiency, utilizing 17 percent FGR. Because of x

98,99

the limited documented experiences regarding the retrofit of combustio n

modifications to existing nonfossil-fuel-fired boilers, no meaningfu l

conclusions can be reached as far as NO control effectiveness or feasibility. x
5-116

5.5 FLUE GAS TREATMENT NO x CONTROLS FOR ICI BOILERS

NOx control with flue gas treatment involves the reduction of NO x in the

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

temperatures, between 870 and 1,100 C (1,600 and 2,000 F), without a

catalyst. When a catalyst is used, this conversion takes place at a 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 reagent injection nozzles, reagent storage and control equipment, and, in

the case of SCR, catalytic reactors. Because flue gas treatment NO x reduction

efficiency depends in large part on flue gas temperature, injection nozzl e

placement is limited to those locations where acceptable proces s

temperatures are present. Generally, in packaged ICI boilers, availabl e

locations for reagent injection and catalyst placement are further limited by

space considerations. These units may also operate with wide ranges i n

boiler steam load that cause flue gas tempe rature shifts outside the optimum

temperature window. Injection of reagents outside the optimum reactio n

temperature window results in lowered NO x reduction efficiency an d

emissions of unreacted ammonia. SNCR and SCR controls have been applied

primarily to larger boilers or new packaged boilers because thes e

applications offer better control of temperature window and steady loa d

demands.

5.5.1 Selective Noncatalytic Reduction (SNCR)

Two primary types of SNCR control technologies are currentl y

available for retrofit to ICI boilers. The first is based on the use of ammonia
5-117

(NH3) as the reducing agent, while the second, more recently introduced, i s

based on the use of urea (NH 2CONH2). Several urea-based systems ha ve been

patented and are commercially offered by several domestic vendors. Th e

following subsections briefly describe the experience to date using thes e

controls 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 NOx reduction efficiencies were obtained whether ammonia or ure a

was used. For ammonia injection, NO x reduction ranged from 50 t o

80 percent, depending on fuel type. For urea-based systems, most reported

NOx reduction efficiencies also fell within this range, although some were as

low as 25 percent and as high as 88 percent. Experience with SNCR 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

DeNOx process is based on a gas phas e homogeneous reaction between NO x

and ammonia 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 temperature range for this process is 870 to 1,100 C (1,600 to

2,000 F), although this can be lowered to 700 C (1,300 F) with additiona l

injection of gaseous hydrogen. At temperatures above 1,100 C (2,000 F), 100

ammonia injection becomes counterproductive, resulting in additional N O

formation. 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 is
5-118

TABLE 5-12. SNCR NO CONTROL FOR ICI BOILERS x

Reagent

Description of

technique Fuel type

Number of

industrial

boilers

tested

% NOx

reductio

n

Controlled NO levels x

Comments ppm @ 3% O 2

lb/MMBtu

Ammonia Injection of

ammonia into fluegas to chemicallyreduce NOx

Natural gas/oil 11 FE-WT a

5 PKG-WTb

50-7230-65

25-160

N.A.c

0.03-0.20

N.A.

Temperature window between870 and 1,100 C (1,600 and2,000 F). Most data are forThermal DeNO ®. x Coal 4 FBC 4 stoker

1 PCd

76-8050-66

57

30-65

110-132

135

0.04-0.087

0.15-0.18

0.18

Wood 10 stoker

8 FBC

50-8044-80

25-16024-140

0.035-0.230.035-0.20

MSW 13 stoker 45-79 48-195 0.068-0.28

Urea Injection of urea

into flue gas tochemically reduceNOx

Natural gas/oil 7 FE-WT 50-60 41-104 0.049-0.13 Most data are for NOxOUT®.

Coal 4 FBC

4 PC

9 stoker

57-8830-8340-74

21-106

110-300105-210

0.028-0.14

0.15-0.410.14-0.28

Wood 14 stoker

2 PKG-WT

2 FBC

1 cell

25-78

50

60-70

52

60-118

178-187

45-50

96

0.084-0.17

0.24-0.26

0.063-0.070

0.14

MSW 13 stoker 41-75 44-210 0.062-0.30

FE-WT = field-erected watertube. a

PKG-WT = packaged watertube. b

N.A. = Not available in reference source used. c

Boiler burning coke in Japan. d
5-119

commonly referred to as ammonia slip, breakthrough, or carryover. The

101

amount of ammonia slip also depends in part on the amount of ammoni a

injected. Although the chemical reaction requires one mole of NH 3 for each

mole of NO, the NH3/NOx ratio used is usually greater than 1 to avoid a n

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 x process has been applied to a number of boilers

firing 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

reduction, with controlled emissions of 45 and 50 ppm (0.06 an d

0.07 lb/MMBtu).
5-120

Overall, experience with ammonia-based SNCR on both new an d

existing units has shown the following results, listed in Table 5-12. NO x

reduction 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, NOx reduction ranged from 45 to 79 percent, while for four coal-fire d

FBC units, 76 to 80 percent reductions were achieved. Several natural-gasfired furnaces experienced 30 to 72 percent NO x

 reduction. In addition t o

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 all

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 NOx reductions for an individual boiler depend on the flue

gas temperature, 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 x in

the flue gas can affect the performa nce of the SNCR control. 104 The optimum

placement of SNCR injectors requires a detailed mapping of the temperature

profile in the convective passes of the boiler, because of the narro w

temperature window. According to Exxon, the Thermal DeNO x process has

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 ability to accommodate injection nozzles at a location where flue gas

temperatures and residence time are optimum for the reaction to take place.

In field-erected boilers, the ammonia is usually injected into either a

superheater tube bank or between a superheater tube bank and the stea m

generator tube bank, while, for a typical wood-fired stoker boiler, injectors 103
5-121

are usually located before the first superheater coil. In a coal or wood-fired

CFBC boiler, ammonia injectors are usually located after the cyclone to avoid

high solids and NH3 recirculation. Smaller units, especially package d

100

watertube and firetube boilers, have limited space and access for the i njection

nozzles.

5.5.1.2 Urea-based SNCR

Originally developed by the Electric Power Research Institute (EPRI),

a newer SNCR techno logy for flue gas treatment NO x control utilizes urea as

a reagent rather than ammonia. One urea-based SNCR process, known by the

trade name of NOxOUT®, is offered by Nalco Fuel Tech, Inc., and its licensees

(Foster Wheeler, Wheelabrator Air Pollution Control, Research Cottrell, Todd

Combustion, RJM Corporation, and several others internationally). Othe r

vendors, such as Applied Utility Systems and Noell, Inc., have also developed

and installed urea-based SNCR processes. In the NOxOUT process, a n

aqueous solution containing urea and chemical enhancers is injected into the

furnace or boiler at one or more locations, depending on the boiler type and

size. The urea reacts with NO x in the flue gas to produce nitrogen, carbo n

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 ammonia injection, NOxOUT is effective only within a certai n

temperature range. Without the use of chemical enhancers, urea injectio n

effectively reduces NO x at temperatures between 900 and 1,150 C (1,650 and

2,100 F). Residence time at temperature of interest is important. By usin g

proprietary enhancers and adjusting concentrations, greater NO x reduction

efficiency can be achieved over a wider temperature window. If the urea i s

released at too high a temperature, the chemical species can actually b e

oxidized to form NOx. Below this temperature, urea reacts with NO x to form
5-122

undesired amounts of ammonia. Table 5-12 lists NO x reduction efficiencies

of 25 to 88 percent, reported for different types of boilers burning coal, oil ,

MSW, and wood which have been retrofitted with urea injection. As wit h

Thermal DeNOx, actual reduction performance is highly dependent o n

temperature, amount of reagent used, and level of reagent/NO mixing. x

105

Most of the commercial experience includes MSW-, wood-, and coal-fire d

stokers, and gas-fired boilers and incinerators. These appl ications have been

on new and existing units. Successful demonstrations are documented o n

oil- and coal-fired boilers in the utility industry. NO x reductions of as low as

10 percent to as high as 76 percent have been recorded for utility boilers. An

average NOx reduction performance of 45 percent is estimated for PC-fire d

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

106

packaged 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 process takes advantage of the selectivity of ammonia t o

reduce NOx to nitrogen and water at lower temperature in the presence of a

catalytic surface. Two catalyst formulations are denoted "base metal," this

category including oxides of titanium, molybdenum, t ungsten, and vanadium,

and zeolites, 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

the flue gas upstream of the catalyst. The ammonia/flue gas mixture enters

the catalyst, where it is distributed through the catalytic bed. The flue 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 x reductions as
5-123

Thermal DeNOx SNCR using a much smaller amount of ammonia, due to the

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

catalyst 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

particulate collection devices, avoiding catalyst contamination. In mos t

cases, 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

developed special low-temperature catalysts which can be used a t

temperatures as low as 200 C (400 F).107
5-124

Boiler ID Boiler type

Capacity,

MMBtu/hr Fuel used

Controlled NOx emissions

ppm @ 3% O2lb/MMBtu

Darling-Delaware PKG-WTa110 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 has seen very limited application on domestic ICI boilers .

Table 5-13 shows a selected list of SCR applications on industrial boilers in

California. A more complete list of SCR installations on ICI boilers is included

in Appendix B. Most of the 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

boilers. 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 well
5-125

Description of

technique Fuel type

Number of

industrial

boilers tested

% NOx

reduction

Controlled levels

Comments

ppm @ 3%

O2lb/MMBtu

Injection of ammonia

into flue gas to

chemically reduce NOx

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 x CONTROLS FOR ICI BOILERS

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.

Table 5-14 summarizes performance data for SCR applications t o

boilers in the ICI sector. Data from Japanese oil-fired industrial boiler s

retrofitted with SCR show NO reductions ranging from 85 to 90 percent . x

These units had controlled NO x levels between 17 and 25 ppm (0.02 an d

0.03 lb/MMBtu), operating with flue gas treatment temperatures of 300 t o

370 C (575 
5-126

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.

Similar 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

experienced 53 percent NO x reduction with SCR. In summary, NO x

101

reduction efficiencies 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

modifications 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

incorporating SCR. Because catalysts lose their effectiveness over tim e

111

due to contamination or clogging of catalyst pores, they must be replace d

periodically. On large boilers, it has been reported that catalyst replacement

may be 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 x REDUCTION PERFORMANCE
5-127

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 45b0.39

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.c0.12-0.16 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 SBWTd,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 TABLE 5-15. (continued)

x

 REDUCTION PERFORMANCE

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

LNBg39-52 0.10-0.17 46 0.12

SNCR 50-72 0.03-0.19 58 0.10

SCRh N.A.c0.024 N.A. 0.024

LNB+SCA N.A. 0.10-0.20 N.A. 0.15

Distillate firetube LNBh15 0.15 15 0.15

FGR N.A. 0.04-0.16 N.A. 0.12

Distillate SBWTd,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

SCRh N.A. 0.011 N.A. 0.011

Residual oil

firetube

LNBi30-60 0.09-0.25 40 0.17

Residual oil

SBWTd,e

LNB 30-60 0.09-0.23 40 0.19

FGR 4-30 0.12-0.25 15 0.17

LNB+FGRh N.A. 0.23 N.A. 0.23

Residual oil

MBWTe,f

SCA 5-40 0.22-0.74 20 0.34

LNBj30-60 0.09-0.23 40 0.19

LNB+SCAh N.A. 0.22 N.A. 0.22

SCRi58-90 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 x
5-128

levels 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

NOx control performance attainable in all cases. Actual performance will be

influenced by several factors, including fuel type, degree of control applied,

and the boiler's design and operating condition. Because coal and residual

oil can vary in nitrogen content and other properties, the actual NO level x

achieved with these fuels will be very much a function of these fue l

properties. Certainly, the degree of FGR and air staging applied, 
5-129
5-130

or the amount of ammonia or urea reagent used, will influence the percen t

reduction efficiency and the NO level achieved. x

NOx from pulverized coal combustion in industrial boilers with LN B

controls 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

cautiously, 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

fired 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

distillate-oil-fired ICI boilers, FGR and LNB controls operating alone or i n

combination can attain NO x levels averaging 0.02 to 0.15 lb/MMBtu. Data on

residual oil are somewhat m ore sparse. NO control levels from residual-oil- x

fired 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

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5-133

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25. Ibid. p. 3-30.

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5-135

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36. Salam, T. F., et al. (University of Leeds, U.K.). Reduction of NO x by

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50. Ibid. p. 51.

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5-138

57. Personal communication with Brizzolara, L., A. H. Merri ll & Associates,

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58. Tampella Power. Faber Burner-LNB Projects List. Tampella Powe r

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5-139

68. Ibid. p. 65.

69. Low-NO Burner Design Achieves Near SCR Levels. Publication No . x

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70. Ibid. p. 5.

71. Ln/Series-Low NO Flue Gas Recirculation. Brochure 34. Industria l x

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73. Ibid. p. 3-39.

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80. Statewide Technical Review Group. Technical Support Document for

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81. Letter and attachments from DeHaan, T., Coen Co., Inc, to Seu, S. ,

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5-143

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

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108. Cogentrix Eyes SCR for 220-MW Coal Plant; To Seek Permits Befor e

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112. Makansi, J. Reducing NO Emission. Power Magazine. Septembe r x

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113. Castaldini, C. Evaluation and Costing of NO x Controls for Existin g

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 x CONT

This chapter evaluates the economic impacts of controlling NO from existing ICI boilers . x

Costing methodologies 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 x controls. Section 6.4 presents the cost effectiveness of NO x controls. Supporting

documentation, includin g costing spreadsheets, are included as appendices. Appendix D contains cost

effectiveness data for the boilers and control systems analyzed, scaled from annual cost data o f

Appendices E, F, and G. The latter appendices contain detailed cost analysis spreadsheets developed

from actual data provided by vendors, boiler owners, and regulatory agencies.

Whenever possible, cost data from actual retrofit projects were used to develop the 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 the control system, above what was required to operate the pre-retrofit boiler without NO x

control. Each of these cost categories can be further subdivided into individual cost components .

Section 6.1.1 discusses capital cost components, Section 6.1.2 discusses elements of O&M costs, and

Section 6.1.3 describes the methodology for 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

costs, contingency costs are also added to account for unpredictable expenses. Figure 6- 1
6-3

Figure 6-1. Elements of total capital investment cost. 1
6-4

 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 materials 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

widely, they were estimated as 30 percent of purchased equipment cost in this study, unless an actual

cost figure was provided. This is towards the low end of reported ranges for direct installation cost. 1,5

When direct installation cost data for new boiler applications were provided by vendors, the figure s

were doubled to account for additional retrofit 
6-5

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

conditions. 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 cost. 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

Other costs which may be included as capital costs are expenditures for site preparation ,

buildings, land, and working capital. Site preparation costs are sometimes accounted for in direc t

installation costs, and in most cases are unreported. Additional buildings are usually not required for

retrofit NOx control systems for ICI boilers, except in cases where existing facilities are absolutel y

unable to accommodate 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 analyses for large systems which require significant amounts of utilities, O&M labor, an d

materials. Because most of the control systems considered in this study do not require large amounts 1

of utilities, O&M labor and materials, working capital costs were not included in this study. Costs of

additional land were also not included since most retrofit control systems do not require much space.

These omissions are consistent with U.S. EPA OAQPS costing methodologies. 1

6.1.2 Annual Operations and Maintenance (O&M) Costs

Annual 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

equipment only, and are separate from the annual O&M costs of the existing boiler. Figure 6- 2
6-6

Figure 6-2. Elements of total annual O&M cost. 1
6-7

 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

catalysts. With FGR NO x control systems, boiler fuel consumption may actually decrease due t o

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

insurance. Following the cost methodology developed by OAQPS, overhead charges were estimated

as 60 percent of the annual labor and maintenance materials costs, while administrative, property tax,

and insurance costs were estimated as 4 percent of t he total capital investment cost described in Section

6.1.1.1
6-8

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 PECa

10% of PECa

10% of PECa

2% of PECa

1% of PECa

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

Total 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 10 
6-9

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 capital amortization period, other periods could have been selected if desired, as long as the same

amortization period is used when comparing costs of different control systems. When the annualized

capital cost is added to the total annual O&M costs 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 x removed from a boiler is a function of the achievable NO x reduction of the

control system and of the annual capacity of that unit. An annual capacity factor represents the ratio

of the amount of heat input a unit uses in a year to the amount it could have used if it was operated at

full rated capacity 24 hours a day, 365 days per year. For the 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

effectiveness was calculated for each boiler test case at capacity factors of 0.33, 0.5, 0.66, and 0.8 .

While data for the complete range of capacity factors are presented in the appendices, the summar y

tables in this chapter show cost effectiveness calculated for the mid-range capacity factors of 0.5 and

0.66 only.

To estimate the amount of NO x removed by a control system per year, pre-retrofit an d

post-retrofit NO emission levels must be known, in addition to the boiler capacity factor and heat input x

capacity rating. Assumed baseline NO x levels were selected for each fuel and boiler type based on data
6-10

Fuel Boiler type

Baseline NO ,x

lb/MMBtua

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 x EMISSIONS USED FOR COST CASES

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

contained in Chapter 5 and Appendix B, and are listed in Table 6- 3
6-11

NOx control technology Applicable boiler equipment NOx reduction efficiency, % a

BT/OT PKG-WT and FT 15

BT/OT and WI PKG-WT and FT 65

BOOS with OT FE-WT 50

BOOS/WI with OT FE-WT 75

LNB PC: wall-fired

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 x REDUCTION EFFICIENCIES USED FOR COST CASES

. These NO reduction efficiencies are assumed levels only; actual NO reduction performance o f x x

particular 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 NOx emission reduction per year to obtain

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 x CONTROL COST EFFECTIVENESS CASES

6.2 NOx CONTROL COST CASES AND SCALING METHODOLOGY

NO control cost cases were selected based on the prevalence of control system applications x

to specific types and sizes of boilers and on the availability of cost data. Table 6-4 lists the cost cases

analyzed and data sources from which various cost figures, principally capital and annual costs, were

obtained. Cost data were compiled primarily from 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 x controls for FBC boilers were
6-13

limited to SNCR, since combustion staging is usuall y integrated into the original FBC boiler design and

operation. 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

NOx control cost cases were then obtained from these values, using the logarithmic scaling law known

as the "six-tenths power rule," to account for differences in 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 units 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 x control configurations were used to

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 for 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 x CONTROLS
6-14

Table 6 - 5
6-15

Boiler type, size, and fuel NO control x

Controlled NO ,x

lb/MMBtua

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. CAPITAL AND TOTAL ANNUAL COSTS OF RETROFIT NO x CONTROLS

FOR

ICI BOILERS, 1992 DOLLARS
6-16

 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 cost2

(MMBtu/hr)

2

(MMBtu/hr)

1

0.6

Capital cost1

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.

The 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 boilers indicates that the cost of SCR has lowered due to technology improvements and market

competition. These benefits are likely to transfer into the industrial boiler sector.

Where applicable, the capital cost of SNCR has been found to be in the same range as 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 smaller, 400 MMBtu/hr boiler will require an investment of $830,000. Figure 6-3

17
6-18

Figure 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 x process for several boiler types. These

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 x CONTROLS

This section presents the cost effectiveness of various NO controls retrofitted to a range of ICI x

boilers, using 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 x
6-21

Boiler type

Boiler capacity,

MMBtu/hr

NO control x

technology

Controlled NO x

level, lb/MMBtu

Cost effectiveness,

$/ton NOx removeda,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 x CONTROL COST EFFECTIVENESS, COAL-FIRED

ICI BOILERS

Table 6-6 summarizes the results obtained for coal-fired ICI boilers retrofitted with various

NOx controls. The cost effectiveness values presented here and in all subsequent tables and figures in

this chapter were calculated using 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, x
6-22

costs for boilers with capacity factors such as 0.33 will be higher than those presented in this section.

See Appendix D for calculated cost effectiveness values for capacity factors of 0.33 and 0.80.
6-23

Figure 6 - 4
6-24

Figure 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 x controls retrofitted

to PC wall-fired boilers. The cost estimates depicted are based on data from a detailed cost study for

a 766 MMBtu/hr (224 MWt) PC wall-fired unit. 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

data show reduced costs per ton of NO removed as boiler capacity increases, due to greater amounts x

of NOx removed and economies of scale. SNCR controls were the most cost effective per ton of NO x

removed, with 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.

LNB controls required greater expenditures for equivalent NO x removal, ranging from $980

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.

However, due to the lack of experience in SCR application on PC-fired boilers, the actual cost of this

control option is 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 x levels achieved using LNB were higher than those

achieved using SNCR or SCR. This lower reduction efficiency, coupled with higher capital costs ,

results in higher cost effectiveness for LNB technology. For SCR controls, the most 
6-26

Boiler type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness,

$/ton NOx removeda,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

expensive 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 x levels are generally lower for tangential firing, and, hence, th e

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 fielderected wall-fired units firing natural gas, and are summarized in Table 6- 7
6-27

TABLE 6-7. (continued)

Boiler type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness,

$/ton NOx removeda,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. b
6-28

. 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 FGR controls, and Section 6.4.2.3 discusses field erected wall-fired units retrofitted with LNB .

These estimates do not include the cost of purchasing and maintaining a fully instrumented CEM system

to monitor compliance with an emission limit. The impact of CEMs on these costs is discussed i n

Section 6.4.6.
6-29

6.4.2.1 Natural-gas-fired Packaged Watertube Boilers

NOx control cost data for natural-gas-fired packaged (single-burner) watertube boilers are more

available than for 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 tabulated in Table 6-7 and shown in Figure 6- 5
6-31

Figure 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 control and lowest for LNB and WI+OT, with LNB+FGR falling in between. WI+OT i s x

considered cost-competitive with LNB because of its low initial capital investment. In spite of th e

thermal 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 x reduction decreased with increased

boiler capacity, 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 NOx control for a 250 MMBtu/hr (73 MWt) single-burner packaged boiler with LNB ar e

much lower 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

reason lies in the number of burners to be retrofitted. A field-erected unit with four or more burners,

for example, will tend to require capital equipment and installation costs several times higher than a

single-burner unit.

On average, LNB+FGR control costs per ton of NO x removed were twice as high as for LNB

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 x
6-33

removed, 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 estimates. 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 reflect the ranges in cost and are representative of the uncertainty in these estimates. Cost -

effectiveness ranges for LNB and for LNB+FGR overlap, due to the wide range of cost effectiveness

values obtained. These cost-effectiveness data illustrate the potential variability in the costs o f

retrofitting boilers with NO x controls, which are highly dependent on site-specific installation an d

operating factors. Figure 6- 6
6-34

Figure 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 x control systems, and

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 one of the most common retrofit NO x control strategies for natural-gas-fire d

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 MMBtu/hr (1.5 MWt) and smaller. The most significant cost components for these cost cases

were equipment and installation costs. The costs of NO x control for a 10 MMBtu/hr (2.9 MWt) firetube

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

actual thermal efficiency impact in a retrofit situation. The actual impact will depend on current unit

operating practices; given a poor operating condition with high 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 for 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 x removed for boilers ranging in size from

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

packaged 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 x control cost effectiveness estimates for fuel-oil-firing units wer e

made based on cost data for natural-gas-fired boilers, using appropriate baseline NO emission levels x

and fuel oil prices. Tables 6- 8
6-37

Boiler type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness,

$/ton NOx

removeda,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 BOILERS
6-38

Boiler type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness,

$/ton NOx

removeda,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 BOILERS

Figure 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 packaged
6-39

watertube boilers. NO x controls that use wat er injection were not considered for oil-fired units because

of lack of experience and greater operationa l and environmental impacts that are likely with these fuels

compared with natural gas. Comparative cost results for the different NO x control technologies ar e

similar 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 control per ton removed are lower for fuel oil firing than for natural gas x

firing due to higher baseline NO emission levels, and, hence, greater amounts of NO removal pe r x x

MMBtu heat input. 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

equipped with LNB is primarily due to the greater capital equipment and installation costs associated

with retrofitting multiple burners rather than a single burner. Multiple-burner field-erected boilers are

likely to benefit from selected BOOS. 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 reflect cost experiences for nine different installations. NO x control performance and cost ar e

considered the same regardless of the reagent used. Typical applications use either ammonia or urea
6-40

Boiler

type Fuel type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness,

$/ton NOx

removeda,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

effectiveness 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 the 
6-41
6-42
6-43
6-44

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 sized paper-fired units were lower, ranging from $1,280 to roughly $2,270 per ton of NO x

removed.

6.4.5 NO Control 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 NOx emission level of 0.38 lb/MMBtu (see Chapter 4) and the NO x reduction

efficiencies listed in Table 6-3, cost effectiveness is $3,790 per ton of NO x removed for LNB at 0.66

capacity factor, $8,000/ton for SNCR, and $19,400/ton for SCR.

6.4.6 Cost Effect of Continuous Emissions Monitoring (CEM) System

Addition of a CEM system to an NOx control retrofit package can increase the costs of NO x

control. For example, Table 6-1 1
6-45

Boiler type

Boiler

capacity,

MMBtu/hr

NO control x

technology

Controlled

NO level, x

lb/MMBtu

Cost effectiveness

without CEM,

$/ton NOx

removedb,c

Cost effectiveness

with CEM,

$/ton NOx

removedb,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 x CONTROL COST EFFECTIVENESS WITHOUT/WITH CEM

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 MMBtu/hr (77.7 MWt) unit, that showed a total CEM system capital cost of roughly $200,000,

including 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

systems 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. 27
6-46

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. Technical 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

Nitrogen 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 x Reduction Systems. Proceedings: 1987 Symposium o n

Stationary 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 Quality 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. x
6-47

15. Alternative Control Techniqu es Document--NO x Emissions from Utility Boilers. Publication

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

Castaldini, 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. Colannino, J. Low-Cost Techniques-Reduce Boiler NO x. Chemical Engineering. February

1993. p. 100.

20. Letter and Attachmen ts from Dean, H., Hugh Dean & Co., Inc., to Votlucka, P., South Coast

Air Quality Management District. Cost Effectiveness of FGR NO x Control for Firetub e

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. Letter and Attachments from Burlage, P., Peerless Mfg. Co., to Brizzolara, L., A.H. Merrill

& Associates. SCR Equipment and Installation Costs. June 22, 1992.

23. Hurst, B., et al. (Exxon Research and Engi neering Co.). Exxon Thermal DeNO Effectiveness x

Demonstrated 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.

Jordan, 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 :

Experience 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

International 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 x Controls for "Small" Oil-Fired Steam

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

Boilers, 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 chapter presents environmental and energy impacts for the NO emissions contro l x

techniques described in Chapter 5. These control techniques are specific to certain boiler and fue l

equipment, as shown in Table 7- 1
7-2

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

NO control x

technique

Coal-fired Oil-/natural-gas-fired Nonfossil-fuel-fired MSW-fired

Field-erected

PC-fired Stoker

FB

C

Fielderected

watertube

Packaged

watertub

e

Packaged

firetube Stoker FBC Mass burn

BT/OT X X

WI/SI X X

SCA X X a X X X b Xa X X a

LNB X X X X

FGR X X X X

NGR X b Xb

SNCR X b X X X X b X X X 

SCR X b Xb Xb

BT/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-NO burners xFGR = Flue gas recirculationNGR = Natural gas reburningSNCR = Selective noncatalytic reductionSCR = Selective catalytic reductionMSW = Municipal solid waste

SCA is designed primarily for control of smoke and combustible fuel rather than NO . Optimization of existing SCA (OFA) ports can lead a x

 to some NO reduction. x

Limited experience. b
7-3

. 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,

Section 7.2 the solid waste disposal impacts, Section 7.3 the water pollution impacts, and Section 7.4

the energy impacts.

7.1 AIR POLLUTION

7.1.1 NO Reductions x

Control techniques presented in this document can result in significant NO reductions fo r x

selected ICI boilers. The actual NO x reduction that can be achieved at each site will depend on many

factors including the extent of the equipment upgrade, the degree of control applied, and the 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 - 2
7-5

Boiler type and size,

MMBtu/hr

Baseline NOx

NO control x

technique

Control NOx

level,

lb/MMBtu

NOx reduction

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 x EMISSIONS REDUCTION FROM MODEL BOILERS
7-6

 lists the anticipated NO x reductions that can be achieved on a yearly basis with the retrofit of candidate

control techniques. These estimates are based on "model size" 
7-7
7-8

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/MMBtu 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 units. 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 modification of combustion conditions aimed at reducing NO x formation can result i n

increases in emissions of CO and hydrocarbons. This is because controls that reduce peak flam e

temperature and delay the mixing of fuel and air for NO x reduction can cause some incomplet e

combustion of the fuel. However, the actual impact of NO x control retrofits often depends on th e

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 - 3
7-10

Boiler type NO control x

NOx

reduction,

%

CO emissions impact

Baseline/low NO x, Reference

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 NAa1

FBC SCA 67 387-500/550-1,100 +86 7

NA = Not applicable. a

TABLE 7-3. CO EMISSION CHANGES WITH NO x CONTROL RETROFIT —

COAL-FIRED BOILERS
7-11

Boiler type NO control x

NOx

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 NAa342/30 -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

BOILERS
7-12

Oil/boiler

type NO control x

NOx

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 NAa1

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

the spreader stoker. Emissions of CO increased in nearly all cases, except for the retrofit of NGR on

the cyclone boiler and one minor application of OFA for 10 percent reduction in NO in the spreader x

stoker. The implementation of staged air will typically result in increased CO emissions .

Data on the effect of NOx controls on CO emissions from natural gas-fired ICI boilers were

limited to the retrofit of FGR, LNB and FGR+LNB controls. Bulk dilution of combustion mixtures with

FGR is limited by flame instability and reduced flammability. Slightly higher 
7-13
7-14

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 Table 7-4 suggest that baseline CO emission levels from these units ranged from

9 to 856 ppm, and that the application of these controls, along with an increase in excess air, resulted

in a reduction of CO in most cases. The average CO 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 x configuration increased

to only 22 p pm. Excess air is an important operational parameter that determines the level of C O

emissions following the retrofit of NO x controls. As suggested above, most of the reductions in C O

levels from these gas-fired boilers resulted from increases in excess air. Low-NO x firing with LN B

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 x emissions with reduced excess oxygen

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 x combustion controls such

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 x emissions are reduced to strict levels. Also, the 18

ABMA recommends an equivalent permitted level for CO for ICI boilers retrofitted with combustion

controls. 19

As shown in Table 7-5, the limited data base on fuel oil-fired ICI boilers indicates that baseline

CO emission levels for these selected boilers were below 20 ppm. When NO controls such as LNB, x

FGR, and BOOS were applied, the CO emission levels increased in nearly all cases. The increase in
7-16

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-bearing fuels are burned, these emissions also pose an operational concern because of cold end

corrosion and reduced heat transfer due to ammonium sulfate deposits. N 2O emissions are often a

byproduct of the SNCR reaction, and, because of this, some N O emissions are likely with the process. 2

In fact, the emissions have been reported with all reagents, particularly with urea reagents. Some

20

urea-based SNCR processes offer proprietary additives to minimize N O and NH emissions. 2 3

SNCR vendors 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

residence time, and by careful control of reagent use with boiler load and operating conditions .

Table 7 - 6
7-17

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 a
7-18

 lists NH3 slip levels rep orted for several retrofit installations. Boilers best suited for retrofit of SNCR

are FBC, bubbling and circulating designs. Stok ers and mass burning equipment have also been targets

for application of SNCR because combustion modifications have traditionally been limited an d

ineffective. In sp ite of large NO x reductions achieved in the units with the retrofit of SNCR, typically

in the range of 50 to 70 percent, NH 3 slip levels have been reported mostly in the range of less than 30

ppm, and often less than 20 ppm. Monitor ing of NH3 emissions is often difficult because direct on line

measurement 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 x to N2O

(NO = 300 ppm, N/NO = 2.0). i

20

Pilot-scale and f ield tests have clearly shown that a portion of the NO x reduced by the SNCR

process is merely transfor med into N2O emissions. Figure 7-2 illustrates the amount of N 2O produced

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

NOx reduced can actually be transformed to N 2O with urea, less when using ammonia. Cyanuric acid

is not a preferred chemical because of its obvious disadvantage in N 2O formation compared with the

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 x
7-21

controls 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

preceded 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

modification 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.

FGR resulted in an increase in PM from oil-fired packaged boilers by 15 percent over

baseline levels

Information on the effects of LNB on PM is unavailable. However, newer burner designs 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

NOx reduction techniques that have a potential impact on the disposal of solid waste ar e

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 likelihood
7-22

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 is used. With continuous use, the catalyst material will become less active. That is, th e

efficiency 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

starting 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 disposal of spent catalyst can present a potential environmental impact because some of

the catalyst formulations are potentially toxic and subject to hazardous waste disposal regulations under

RCRA and its amendments. For example, vanadia and titania catalysts are considered 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 x controls, especially SNCR. The use associated with WI or SI injection

is an obvious one. The amount of water used does often not exceed 50 percent of the total fuel input

on a weight basis. This is because excessive use of flame quenching with water can result in hig h

emissions of CO and high thermal efficiency loss. Therefore, a 50 MMBtu/hr (15 MWt) boiler would

use approximately 600,000 gal (2.2 million L) of water per year when operating with a 50 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 deposits 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 air
7-23

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 increase 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

combustion 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

regardless 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 method 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

equipment improvements can be readily made that reduce the amount of excess air resulting in a

thermal efficiency improvement and reduced NO x emissions without compromising the safety of the

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 2 and CO

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 2 of 3.5

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 air
E

CO

3,682

x 1

%EA

89.5

7-25

(7-2)

The reduction in excess air, however, can result in some increase in unburned fuel primarily

in the form of CO emissions, when gas or fuel oil is 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 have 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 require 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. 28
7-27

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 of 
7-28

higher gas velocities and more register control. This increase in pressure drop will tend to increase fan

power somewhat, or compensate for the reduction in energy consumption at lower combustion 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 - 6
7-29

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

electricity will depend on the baseline NO x emission level, the NH 3/NO ratio used, and the NO 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 corresponds to about $16,000/yr electricity cost. For steam-assisted ammonia injection ,

electricity use reduces to about 0.2 to 0.3 kW/ MWt or 0.05 to 0.08 kW/MMBtu/hr boiler capacity. The

amount of steam used is on the order of 25 to 75 lb/hr/MWt. I n general, ammonia is most economically

injected using compressed air rather than steam. Data supplied by Nalco Fuel Tech suggest that th e

urea-based SNCR process uses much lower levels of electricity than either ammonia-based SNCR or
7-31

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

energy needed to store, pretreat and inject the chemical reagent ammonia or ammonia hydroxide; (2)

the increased fan power to overcome the added pressure drop of the catalyst reactor in the flue gas; and

(3) the thermal efficiency loss associated with maintaining the catalyst reactor temperature within the

specifications for optimum performance at variable boiler loa d. The energy to store, pretreat, and inject

the reagent is equivalent to that of an SNCR system. Estimates of increased pressure drop across the

catalyst vary with the various catalyst vendors and applications, primarily fuel. Typically, the pressure

drop across a catalyst is on the order of 3 to 6 inches of water. Figure 7- 7
7-32

Figure 7-7. Estimated increase in energy consumption with SCR pressure drop.
( P in H2O) 0.0361 lb

in 2

in H2O 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 1.2
7-34

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. Schild, V., et al. (Black Hills Power and Light Co.). Western Coal-Fired Boiler Retrofit for

Emissions Control and Efficiency Improvement. Technical Paper No. 91-JPGC-FACT-7 .

American Society of Mechanical Engineers. New York, NY. 1991.

3. Folsom, B., et al. (Energy and Envir onmental Research Corporation). Field Evaluation of the

Distributed 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. Farzan, H., et al. (Hitachi Zosen Corporation). Three Stage Pulverized Coal Combustio n

System for In-Furnace NO x Reduction. Proceedings: 1985 Symposium on Stationar y

Combustion NOx Control. Publication No. EPRI CS-5361. U.S. Environmental Protectio n

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—Effects 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. Bijvoet, 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

Facility. 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 and attachments from Stoll, F. R., Hugh Dean & Co., Inc., to Briggs, A., Acure x

Environmental Corporation. Cleaver-Brooks FGR. April 5, 1993.

11. Kesselring, J. P., and W. V. Krill (Alzeta Corporation). A Low-NO x Burner for Gas-Fire d

Firetube Boilers. Proceedings: 1985 Symposium on Stationary Combustion NO Control. x

Publication 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 NOx Burner Retrofits: Case Studies. Technical Paper No. 91-10.22. Air and Wast e

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

Small 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

Emissions from Primary Boiler — Source Location: Miller Brewing Company, Irwingdale,

CA. Submitted to the South Coast Air Quality Management District, El Monte, CA. August

13, 1990.

16. Hunter, S. C., et al. Application of Combustion Modifications to industrial 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 Review 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. American 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 2O Formation in Selectiv e

Non-Catalytic NO x Reduction Processes. Proceedings: 1991 Joint Symposium on Stationary

Combustion NO Control — EPA/EPRI. March 1992. x

21. Letter 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

boilers which are listed separately. More detailed data may be obtained by referring directly to th e

individual references.
A-2
A-13

REFERENCES FOR APPENDIX A

1. Emissions Assessment of Conventional Stationary Combustion Systems, Volume V: Industrial

Combustion Sources. Publication No. EPA-600/7-81-003c. U.S. Environmental 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. Emissions Assessment of Conventional Stationary Combustion Systems, Volume IV :

Commercial/Insti tutional Combustion Sources. Publication No. EPA-600/7-71-003c. Prepared

by TRW, Inc., for the U.S. Environmental Protection Agency. Research Triangle Park, NC .

January 1981.

4. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control Levels fo r

Nitrogen 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

Improvement—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 x Emissions from Utility

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 Emission 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. Letter 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. McGavin, C. R., et al. FBC Testing of Coal/RDF Mixtures. Presented at the 10th International

Conference on Fluidized Bed Combustion. San Francisco, CA. May 1989.
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. Marlair, G., et al. The Lardet-Babcock/Cerchar 2.5 MWt Package Fluidized Bed Boiler .

Presented at the 9th International Conference on Fluidized Bed Combustion. Boston, MA. May

1987.

18. Cooke, R. C. Mesquite Lake Resource Recovery Project, a Case 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. Bijvoet, 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

Combustor. 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. Worldwide List of Fluid Bed Boiler Installations. Council of Industrial Boiler Owners (CIBO).

Burke, VA. 1990.

27. Abdulally , I. F. and D. Parham. Design and Operating Experience of a Foster Wheeler 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

Generation Experience. Presented at the Sixth Annual CIBO Fluidized Bed Conference .

Harrisburg, PA. December 1990.

29. Bashar, M. and T. S. Czarnecki. Design and Operation of a Lignite Fired CFB Boiler Plant .

Presented at the 10th International Conference on 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. Darling, 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. Emissions and Efficiency Performance of Industrial Coal Stoker Fired Boilers. Publication No.

EPA-600/7-81-111a. July 1981.
B-1

APPENDIX B. CONTROLLED NO x EMISSION DATA

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 x burners (LNB) marketed by Coen Company, of California, and

Tampella Power Corporation, Faber Burner Division, of Pennsylvania, are in Appendix C. Boile r

emissions data are listed by fuel type and whether the NO x control method used was a combustio n

modification or a flue gas treatment method.
B-2
B-24

REFERENCES FOR APPENDIX B

1. Vatsky, 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 NOx Control Update. Proceedings: 1987 Symposium on Stationary Combustion NO 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 

Foster 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 Low NO Concentric Firing System (LNCFS). ABB Combustion Engineering Services, Inc. x

Windsor, CT. 1991.

5. Schild, 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 x Emissions from Utility

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, CA. Proceedings of the Joint Symposium on Stationary Combustion NO Control. x

Publication No. IERL-RTP-1085. U.S. Environmental Protection Agency. Research Triangl e

Park, NC. October 1980.

9. Narita, T., et al. (Babcock Hitachi K.K.). Development of the Low NO x Burner For th e

Pulverized Coal Fired In-Furnace NO x Reduction System. Proceedings: 1985 Symposium o n

Stationary 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 Emissions 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. Folsom, B., et al. (Energy and Environmental Research Corporation). Field Evaluation of th e

Distribut ed Mixing Burner. Proceedings: 1985 Symposium on Stationary Combustion NO x
B-25

Control. Publication No. EPRI CS-436 0. U.S. Environmental Protection Agency/Electric Power

Research Institute. Palo Alto, CA. January 1986.

12. Farzan, 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 x Reduction. Proceedings: 1985 Sym posium on Stationary Combustion

NOx Control. Publication No. EPRI CS-4360. U.S. Environmental Protection Agency/Electri c

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. Goldberg, 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

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Prepared 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.

Prepared 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 Control and Efficiency Improvement—Site F. Publication No. EPA-600/ 7-80-065a.

Prepared for the U.S. Environmental Protection Agency, U.S. Department of Energy, and 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

Pollutant Emissions from Industrial Boilers—Phase II. Publication No. EPA-600/2-72-086a .

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1976.

20. Maloney, K. L., et al (KVB, Inc.). Low-sulfur Western Coal Use in Existing Small an d

Intermediate 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. Maloney, K. L. (KVB, Inc.). Combustion Modifications for Coal-Fired Stoker Boilers .

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Palo Alto, CA. July 1983.

22. Quartucy, G. C., et al. (KVB, Inc). Combustion Modification Techniques for Coal-Fired Stoker

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EPRI CS-4360. U.S. En vironmental Protection Agency/Electric Power Research Institute. Palo

Alto, CA. January 1986.

23. Hiltunen, M., and J. T. Tang. NO x Abatement in Ahlstrom Pyroflow Circulating Fluidized Bed

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1988 Seminar on Fluidized Bed Com bustion Technology for Utility Opns. Publication No. EPRI

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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

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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.

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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.

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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. x
B-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. Office 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 Generating 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. Kesselring, J. P., and W. V. Krill (Alzeta Corporation). A Low-NO x Burner for Gas-Fire d

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 x Control. Publication

No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric Power Research Institute.

Palo Alto, CA. July 1989.

43. Field Test Update: Ceramic Fiber Burner for Firetube Boilers. Gas Research Institute. Chicago,

IL. August 1987.
B-28

44. Yang, S. C., et al. Development of Low NO Gas Burners. Energy and Resources Laboratories x

(ERL), Industrial 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

Design 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 x Combustion Retrofit—VA Hospital —

Los Angeles Boiler No. 4. Report No. KVB71-72760-2130. Prepared for Keeler-Dorr-Oliver.

Williamsport, PA. May 1987.

51. Letter and attachments from DeHaan, T., Coen Co., Inc., to Seu, S., Acurex Environmental Corp.,

Low-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 x Levels in Oil- and Gas-Fired Water Tub e

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 x
B-29

CS-4360. U.S. Environmental Protection Agency/Electric Power Research Institute. Palo Alto,

CA. January 1986.

58. Castaldini, C., et al. (Acurex Corp.). Environmental Assessment of an Enhanced Oil Recovery

Steam Generator Equipped with a Low NO x Burner. Acurex Report No. T R-84-161/EE. Prepared

for the U.S. Environmental Protection Agency. Research Triangle Park, NC. January 1985.

59. McDannel, M. D., and T. D. Guth (KVB, Inc.) . NOx Control Technology Applicable to Oil Field

Steam Generators. Report No. KVB71 42000-1694. Prepared for Getty Oil Company .

Bakersfield, CA. March 1983.

60. Steiner, J., et al. Oil Field Steam Generator Emission Testing, Taft, California—Baseline Tests:

Section 26-C, Unit 50-1. Report No. TR-79-175. Acurex Corporation. Mountain View, CA .

May 1979.

61. Steiner, J., and R. Pape. Oil Field Steam Generator Emission 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 x Reduction Methods for California

Steam Generators by Applied Technology. Paper No. SPE 12772. Society of Petroleu m

Engineers. Dallas, TX. April 1984.

63. Brinkmann, P. E., and M. K. Poe (Mobil Exploration and Producing U.S., Inc.). NO x Emission

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

Process Combustion Corp. Presented at the Pacific Coast Oil Show and Conference. Lo s

Angeles, CA. November 1982.

65. 1986 Pollutant Survey (TEOR steam generators). Kern County Air Pollution Control District .

November 1986.

66. Abbasi, H., et al. Use of Natural Gas f or NOx Control in Municipal Waste Combustion. Institute

of Gas Technology. 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. Penterson, C.A., et al. (Riley Stoker Corporation). Reduction of NO x Emissions From MS W

Combustion Using Gas Reburning. Proceedings: 1989 Symposium on Stationary Combustio n

NOx Control. Publication No. EPRI GS-6423. U.S. Environmental Protection Agency/Electric

Power Research Institute. Palo Alto, CA. July 1989.

68. Lisauskas, R. A., et al. (Riley Stoker Corporation). Status of NO x Control Technology at Riley

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. Karas, J., and D. Goalwin (Bay Area Air Quality Management District). NO x Emissions fro m

Refinery 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. Tang, 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 DeNOx Operating Experience Information. March

1992.

74. Letter 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 Exxon 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. Letter 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 x Process Test Data for 300 TPD

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

Technical Paper No. 90-25.2. Air and Waste Management Association. Pittsburgh, PA. Jun e

1990.

83. Letter and 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

Proceedings: 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

System and its Operational Experiences. Proceedings of the 1989 International Conference o n

Fluidized Bed Combustion. The American Society of Mechanical Engineers/Electric Powe r

Research Institute/Tennessess Valley Authority. New York, NY. 1989.

88. Donais, R. E., et al. (Combustion Engineering, Inc.). 1989 Update on NO Emission Contro l x

Technologies at Combustion Engineering. Proceedings: 1989 Symposium on Stationar y

Combustion NOx Control. Publication No. EPRI GS-6423. U.S. Environmental Protectio n

Agency/Electric Power Research Institute. Palo Alto, CA. July 1989.

89. Letter 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 and 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 x BURNER PROJECTS

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, PA
D-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 x control combinations. To estimate cost effectiveness for the

boiler capacities listed in this appendix, which in most cases differ from the actual capacities of the 42

boilers cases, the logarithmic relationship known as the "six-tenths" power rule was used (Reference

5 of Chapter 6). 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 x emission values and

fuel prices.

This appendix contains the following tables:

Cost Case Page

Natural-gas-fired:

Packaged watertube, 45 MMBtu/hr, with WI and O 2 trim D-3

Packaged firetube, 10.5 MMBtu/hr, with WI and O 2 trim D-3

Packaged watertube, 51, 75, and 265 MMBtu/hr, with LNB D-4

Packaged watertube, 265 MMBtu/hr, with LNB and CEM D-5

Packaged watertube, 17.7 and 41.3 MMBtu/hr, with LNB and 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 2 trim D-8

Packaged watertube, 50-250 and 100 MMBtu/hr, with SCR D-9

Field-erected wall-fired, 75 MMBtu/hr, with BOOS and O 2 trim D-10

Field-erected wall-fired, 75 MMBtu/hr, with BOOS, WI, and O 2 trim D-10

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 2 trim D-17

Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-17
D-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 2 trim D-23

Field-erected wall-fired, 590 and 1,300 MMBtu/hr, with LNB D-23

Coal-fired:

Field-erected wall-fired, 766 MMBtu/hr, with LNB D-24

Circulating FBC, 460 MMBtu/hr, with urea-based SNCR D-24

Tangentially-fired, with SCR D-25

Field-erected wall-fired, 800 MMBtu/hr, with ammonia-based SNCR D-25

Wall-fired, 400 MMBtu/hr, with SNCR D-26

Spreader stoker, 303 MMBtu/hr, with urea-based SNCR D-26

Wood-fired:

Stoker, 190, 225, and 300 MMBtu/hr, with urea-based SNCR D-27

Stoker, 395 and 500 MMBtu/hr, with urea-based SNCR D-28

Bubbling FBC, 250 MMBtu/hr, with ammonia-based SNCR D-28

Paper-fired:

Packaged watertube, 72 and 172 MMBtu/hr, with urea-based SNCR D-29

MSW-fired:

Stoker, 108, 121, and 325 MMBtu/hr, with urea-based SNCR D-30
D-3
D-4
D-5
D-6
D-7
D-8
D-9
D-10
D-11
D-12
D-13
D-14
D-15
D-16
D-17
D-18
D-19
D-20
D-21
D-22
D-23
D-24
D-25
D-26
D-27
D-28
D-29
D-30
E-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

controls. 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 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 x Control Page

Packaged watertube, 45 MMBtu/hr, with WI and O 2 trim E-3

Packaged firetube, 10.5 MMBtu/hr, with WI and O 2 trim E-5

Field-erected watertube, 75 MMBtu/hr, with BOOS and O 2 trim E-7

Field-erected watertube, 75 MMBtu/hr, with BOOS, WI, and O 2 trim E-9

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 O2 trim E-39

Packaged watertube, 50, 100, 150, 200, and 250 MMBtu/hr, with SCR E-49

Field-erected watertube, 250 MMBtu/hr, with SCR E-59

Packaged watertube, 50 and 150 MMBtu/hr, with SCR (variable catalyst

life) E-61

Field-erected watertube, 250 MMBtu/hr, with SCR (variable catalyst life) E-69
E-2
E-3
E-4
E-5
E-6
E-7
E-8
E-9
E-10
E-11
E-12
E-13
E-14
E-15
E-16
E-17
E-18
E-19
E-20
E-21
E-22
E-23
E-24
E-25
E-26
E-27
E-28
E-29
E-30
E-31
E-32
E-33
E-34
E-35
E-36
E-37
E-38
E-39
E-40
E-41
E-42
E-43
E-44
E-45
E-46
E-47
E-48
E-49
E-50
E-51
E-52
E-53
E-54
E-55
E-56
E-57
E-58
E-59
E-60
E-61
E-62
E-63
E-64
E-65
E-66
E-67
E-68
E-69
E-70
E-71
E-72
F-1

APPENDIX F. ANNUAL COSTS OF RETROFIT NO CONTROLS: x

COAL-FIRED ICI BOILERS

This appendix contains cost spreadsheets for coal-fired boilers retrofitted with various NO x

controls. 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-23
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-10
F-11
F-12
F-13
F-14
F-15
F-16
F-17
F-18
F-19
F-20
F-21
F-22
F-23
F-24
G-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 controls. The spreadsheets are based on data from actual boiler retrofit experiences or studies . x

Capital 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 x

 Control Page

Wood-Fired:

Stoker, 190, 225, 300, 395, and 500 MMBtu/hr, with urea-based SNCR

G-3

FBC boiler, 250 MMBtu/hr, with ammonia-based SNCR 

G-13

Paper-Fired:

Packaged watertube, 72 and 172 MMBtu/hr, with urea-based SNCR G-15

MSW-Fired:

Stoker, 108, 121, and 325 MMBtu/hr, with urea-based SNCR G-19
G-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-3
G-4
G-5
G-6
G-7
G-8
G-9
G-10
G-11
G-12
G-13
G-14
G-15
G-16
G-17
G-18
G-19
G-20
G-21
G-22
G-23
G-24
G-25