EPA-453/R-93-034

Alternative Control

Techniques Document—

NOx Emissions from

Process Heaters

(Revised)

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

September 1993

Please note: The page numbers seem to 

have been screwed up in this electronic 

form. Sorry about that!
ALTERNATIVE CONTROL TECHNIQUES DOCUMENTS

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 or commercial

products is not intended to constitute endorsement or

recommendation for use. Copies of this report are available—as

supplies permit—from the Library Services Office (MD-35), U.S.

Environmental Protection Agency, Research Triangle Park, North

Carolina 27711, or for a nominal fee, from the National

Technical Information Service, 5285 Port Royal Road, Springfield,

Virginia 22161.
iii

TABLE OF CONTENTS

Section Page

1.0 INTRODUCTION .................... . 1-1

2.0 SUMMARY ...................... . 2-1

2.1 UNCONTROLLED NOX EMISSIONS .......... . 2-1

2.2 AVAILABLE NOX EMISSION CONTROL TECHNIQUES ... . 2-4

2.3 CAPITAL COSTS AND COST EFFECTIVENESS ..... . 2-5

2.4 IMPACTS OF NOX CONTROLS ............ . 2-22

3.0 PROCESS HEATER DESCRIPTION AND INDUSTRY 

CHARACTERIZATION .................. . 3-1

3.1 PROCESS HEATER DESCRIPTION .......... . 3-1

3.1.1 Heated Feed .............. . 3-2

3.1.2 Reaction Feed ............. . 3-2

3.1.3 Process Heater Design Parameters .... . 3-2

3.1.3.1 Combustion Chamber Set-Ups . . . 3-2

3.1.3.2 Combustion Air Supply ..... . 3-3

3.1.3.3 Tube Configurations ...... . 3-6

3.1.3.4 Burners ............ . 3-6

3.2 INDUSTRY CHARACTERIZATION ........... . 3-10

3.2.1 Process Heaters in Use ......... . 3-10

3.2.2 Process Heater Energy Consumption ... . 3-12

3.3 REFERENCES FOR CHAPTER 3 ........... . 3-19

4.0 CHARACTERIZATION OF NOX EMISSIONS ......... . 4-1

4.1 FORMATION OF NOX ............... . 4-1

4.1.1 Thermal NOx Formation ......... . 4-1

4.1.2 Fuel NOx Formation ........... . 4-4

4.1.3 Prompt NOx Formation .......... . 4-6

4.2 FACTORS AFFECTING UNCONTROLLED NOX EMISSIONS . . 4-6

4.2.1 Heater Design Parameters ........ . 4-6

4.2.1.1 Fuel Type ........... . 4-7

4.2.1.2 Burner Type .......... . 4-8

4.2.1.3 Combustion Air Preheat .... . 4-10

4.2.1.4 Firebox Temperatures ..... . 4-10

4.2.1.5 Draft Type .......... . 4-12

4.2.2 Heater Operating Parameters ...... . 4-14

4.2.2.1 Excess Air .......... . 4-14

4.2.2.2 Burner Adjustments ...... . 4-15

4.3 UNCONTROLLED NOX EMISSION FACTORS AND MODEL

HEATERS .................... . 4-15

4.3.1 Uncontrolled NOx Emissions ....... . 4-17

4.3.2 Model Heaters ............. . 4-25

4.4 REFERENCES FOR CHAPTER 4 ........... . 4-30
TABLE OF CONTENTS (continued)

Section Page

iv

5.0 NOx CONTROL TECHNIQUES ............... . 5-1

5.1 COMBUSTION CONTROLS .............. . 5-1

5.1.1 Low Excess Air ............. . 5-2

5.1.2 Combustion Air Preheat ......... . 5-4

5.1.3 Use of Air Lances to Achieve Staged

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

5.1.4 Staged-Air, Low-NOx Burners ...... . 5-9

5.1.5 Staged-Fuel, Low-NOx Burners ...... . 5-15

5.1.6 Flue Gas Recirculation ......... . 5-17

5.1.7 Ultra-Low NOx Burners ......... . 5-21

5.1.8 Radiant Burners ............ . 5-23

5.2 SELECTIVE NONCATALYTIC REDUCTION ....... . 5-24

5.2.1 Exxon Thermal DeNOx® (Ammonia Injection) . 5-27

5.2.1.1 Process Description 

(Thermal DeNOx®) ....... . 5-29

5.2.1.2 Factors Affecting Thermal DeNOx®

Performance .......... . 5-31

5.2.1.3 NOx Reduction Efficiency Using 

Thermal DeNOx® ........ . 5-32

5.2.1.4 Ammonia Slip Considerations For 

Thermal DeNOx® ........ . 5-32

5.2.2 Nalco Fuel Tech NOxOUT® (Urea Injection) . 5-32

5.2.2.1 Process Description (NOxOUT®) . . 5-33

5.2.2.2 Factors Affecting NOxOUT® 

Performance .......... . 5-35

5.2.2.3 NOx Emission Reduction 

Efficiency Using NOxOUT® ... . 5-36

5.2.2.4 Ammonia Slip Considerations For

NOxOUT® ............ . 5-36

5.3 SELECTIVE CATALYTIC REDUCTION ......... .

5-36

5.3.1 Process Description (SCR) ....... . 5-37

5.3.2 Factors Affecting SCR Performance ... . 5-40

5.3.3 NOx Emission Reduction Efficiency Using

SCR .................. . 5-43

5.4 SPECIAL CONSIDERATIONS ............ . 5-46

5.5 ACHIEVABLE NOx EMISSION REDUCTIONS ...... . 5-50

5.6 REFERENCES FOR CHAPTER 5 ........... . 5-58

6.0 CONTROL COSTS ................... . 6-1

6.1 CAPITAL AND ANNUAL COSTS METHODOLOGIES .... . 6-2

6.1.1 Costs of LNBs ............. . 6-2

6.1.1.1 Capital Costs of LNBs ..... . 6-2

6.1.1.2 Operating Costs of LNBs .... . 6-4

6.1.2 Cost of ULNBs ............. . 6-5

6.1.2.1 Capital Costs of ULNBs .... . 6-5

6.1.2.2 Operating Costs of ULNBs ... . 6-5
TABLE OF CONTENTS (continued)

Section Page

v

6.1.3 Costs of SNCR ............. . 6-6

6.1.3.1 Capital Costs of SNCR ..... . 6-6

6.1.3.2 Operating Costs of SNCR .... . 6-6

6.1.4 Costs of SCR .............. . 6-7

6.1.4.1 Capital Costs of SCR ..... . 6-7

6.1.4.2 Operating Costs of SCR .... . 6-7

6.1.5 Costs of FGR .............. . 6-8

6.1.5.1 Capital Costs of FGR ..... . 6-8

6.1.5.2 Operating Costs of FGR .... . 6-9

6.1.6 Costs of LNBs Plus SNCR ........ . 6-9

6.1.6.1 Capital Costs of LNBs Plus

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

6.1.6.2 Operating Costs of LNBs

Plus SNCR ........... . 6-10

6.1.7 Costs of LNBs Plus SCR ......... . 6-10

6.1.7.1 Capital Costs of LNBs 

Plus SCR ........... . 6-10

6.1.7.2 Operating Costs of LNBs

Plus SCR ........... . 6-10

6.1.8 Costs of ND-to-MD Conversion ...... . 6-10

6.1.8.1 Capital Costs of ND-to-MD

Conversion .......... . 6-10

6.1.8.2 Operating Costs of ND-to-MD

Conversion .......... . 6-11

6.2 TOTAL ANNUAL COST FOR MODEL HEATERS ...... . 6-11

6.2.1 Control Costs for the ND Gas-Fired,

Low- and Medium-Temperature Model

Heaters ................ . 6-12

6.2.2 Control Costs for MD Gas-Fired, Low- and

Medium-Temperature Model Heaters .... . 6-12

6.2.3 Control Costs for ND Oil-Fired, Low- and

Medium-Temperature Model Heaters .... . 6-12

6.2.4 Control Costs for MD Oil-Fired, Low- and

Medium-Temperature Model Heaters .... . 6-18

6.2.5 Control Costs for the Olefins Pyrolysis

Model Heaters ............. . 6-18

6.2.6 Costs for ND-to-MD Conversion ..... . 6-18

6.3 COST EFFECTIVENESS OF NOX CONTROLS FOR PROCESS

HEATERS .................... . 6-18

6.4 COST EFFECTIVENESS OF RADIANT BURNERS ..... . 6-32

6.5 REFERENCES FOR CHAPTER 6 ........... . 6-34

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

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

7.1.1 NOx Emission Reductions ........ . 7-1
TABLE OF CONTENTS (continued)

Section Page

vi

7.1.2 Emissions Trade-Offs .......... . 7-3

7.1.2.1 Impacts on HC and CO Emissions

from the Use of LNBs, ULNBs

and FGR ............ . 7-3

7.1.2.2 Impacts on NH3, N2O, CO, and

PM Emissions from the Use

of SNCR and SCR ........ . 7-10

7.2 SOLID WASTE IMPACTS .............. . 7-14

7.3 ENERGY IMPACTS ................ . 7-15

7.4 REFERENCES FOR CHAPTER 7 ........... . 7-17

APPENDIX A: REFINERY PROCESS HEATER INVENTORY ..... . A-1

APPENDIX B: CURRENT AND FUTURE NOxOUT® APPLICATIONS . . . B-1

APPENDIX C: LIST OF PROCESS HEATER NOx CONTROL RETROFITS

FOR MOBIL TORRANCE REFINERY ........ . C-1

APPENDIX D: FOSTER WHEELER PROCESS HEATER SCR

INSTALLATIONS ............... . D-1
vii

LIST OF TABLES

Page

TABLE 2-1. UNCONTROLLED EMISSION FACTORS FOR MODEL

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

TABLE 2-2. REDUCTION EFFICIENCIES FOR CONTROL TECHNIQUES

APPLIED TO NATURAL GAS- AND REFINERY FUEL 

GAS-FIRED PROCESS HEATERS ......... . 2-6

TABLE 2-3. REDUCTION EFFICIENCIES FOR CONTROL TECHNIQUES

APPLIED TO ND AND MD, DISTILLATE AND RESIDUAL

OIL-FIRED PROCESS HEATERS ......... . 2-7

TABLE 2-4. MODEL HEATERS: NOx EMISSION REDUCTIONS, 

CAPITAL COSTS, AND COST EFFECTIVENESS FOR

ND, NATURAL GAS-FIRED LOW- AND MEDIUMTEMPERATURE HEATERS ............ . 2-9

TABLE 2-5. MODEL HEATERS: NOx EMISSION REDUCTIONS,

CAPITAL COSTS, AND COST EFFECTIVENESS FOR 

MD, NATURAL GAS-FIRED, LOW- AND MEDIUMTEMPERATURE HEATERS ............ . 2-12

TABLE 2-6. MODEL HEATERS: NOx EMISSION REDUCTIONS,

CAPITAL COSTS, AND COST EFFECTIVENESS FOR ND, 

OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE

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

TABLE 2-7. MODEL HEATERS: NOx EMISSION REDUCTIONS, 

CAPITAL COSTS, AND COST EFFECTIVENESS FOR MD,

OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE

HEATERS .................. . 2-15

TABLE 2-8. MODEL HEATERS: NOx EMISSION REDUCTIONS,

CAPITAL COSTS, AND COST EFFECTIVENESS FOR ND

OLEFINS PYROLYSIS HEATERS ......... . 2-16

TABLE 3-1. SURVEY OF OPERATING REFINERIES IN THE U.S. . . 3-13

TABLE 3-2. MAJOR REFINERY PROCESSES REQUIRING A FIRED 

HEATER ................... . 3-14

TABLE 3-3. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER

APPLICATIONS IN THE CHEMICAL INDUSTRY ... . 3-17

TABLE 3-4. REPORTED APPLICATIONS OF FIRED HEATERS

IN THE CHEMICAL MANUFACTURING INDUSTRY ... . 3-18
LIST OF TABLES (continued)

Page

viii

TABLE 4-1. AP-42 ESTIMATES FOR UNCONTROLLED NOx EMISSIONS

FROM BOILERS AND PROCESS HEATERS ...... . 4-18

TABLE 4-2. AVERAGE UNCONTROLLED NOX EMISSIONS FROM 

REFINERY PROCESS HEATERS BASED ON 

EMISSION DATA FROM API ........... . 4-22

TABLE 4-3. AVERAGE UNCONTROLLED NOx EMISSIONS FROM 

PROCESS HEATERS AT ONE REFINERY 

INSTALLATION ................ . 4-24

TABLE 4-4. MODEL HEATERS AND UNCONTROLLED NOx EMISSION

FACTORS: NATURAL GAS-FIRED, LOW- AND

MEDIUM-TEMPERATURE ND WITHOUT PREHEAT ... . 4-26

TABLE 4-5. MODEL HEATERS AND UNCONTROLLED NOx EMISSION

FACTORS: NATURAL GAS-FIRED, LOW- AND

MEDIUM-TEMPERATURE MD WITH PREHEAT ..... . 4-26

TABLE 4-6. MODEL HEATERS AND UNCONTROLLED EMISSION

FACTORS: DISTILLATE AND RESIDUAL OILFIRED, LOW- AND MEDIUM-TEMPERATURE ND

WITHOUT PREHEAT .............. . 4-31

TABLE 4-7. MODEL HEATERS AND UNCONTROLLED EMISSION

FACTORS: DISTILLATE AND RESIDUAL

OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE MD

WITH PREHEAT ................ . 4-31

TABLE 4-8. MODEL HEATERS AND UNCONTROLLED EMISSION

FACTORS: NATURAL GAS-FIRED AND HIGHHYDROGEN FUEL GAS-FIRED OLEFINS PYROLYSIS

FURNACES .................. . 4-32

TABLE 5-1. CONTROLLED EMISSIONS FOR STAGED COMBUSTION

USING AIR LANCES .............. . 5-8

TABLE 5-2. CONTROLLED EMISSIONS LEVELS FOR STAGED-AIR 

LNBs .................... . 5-10

TABLE 5-3. STAGED-AIR BURNER NOx CONTROL PERFORMANCE

AND EMISSION LEVELS ............ . 5-11

TABLE 5-4. STAGED-FUEL LOW-NOx BURNER CONTROLLED

NOx EMISSION LEVELS ............ . 5-18
LIST OF TABLES (continued)

Page

ix

TABLE 5-5. CONTROLLED NOx EMISSION LEVELS FOR STAGEDFUEL LOW-NOx BURNERS ............ . 5-19

TABLE 5-6. RADIANT BURNER APPLICATIONS ........ . 5-25

TABLE 5-7. PARTIAL LIST OF EXXON'S THERMAL DeNOx® 

INSTALLATIONS ............... . 5-30

TABLE 5-8. NALCO FUEL TECH NOXOUT® PROCESS HEATER 

APPLICATIONS ................ . 5-37

TABLE 5-9. CONTROLLED EMISSION FACTORS FOR SCR ADDED TO

HEATERS WITH LNBs ............. . 5-44

TABLE 5-10. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER

APPLICATIONS IN THE CHEMICAL INDUSTRY ... . 5-47

TABLE 5-11. MODEL HEATERS: CONTROLLED EMISSIONS FOR 

ND, NATURAL GAS-FIRED, LOW- AND MEDIUMTEMPERATURE HEATERS ............ . 5-52

TABLE 5-12. MODEL HEATERS: CONTROLLED EMISSIONS FOR

MD, NATURAL GAS-FIRED, LOW- AND MEDIUMTEMPERATURE HEATERS ............ . 5-53

TABLE 5-13. MODEL HEATERS: CONTROLLED EMISSIONS FOR

ND OIL-FIRED HEATERS ............ . 5-54

TABLE 5-14. MODEL HEATERS: CONTROLLED EMISSIONS FOR

MD OIL-FIRED HEATERS ............ . 5-55

TABLE 5-15. MODEL HEATERS: CONTROLLED EMISSIONS FOR

ND OLEFINS PYROLYSIS HEATERS ........ . 5-56

TABLE 6-1. UTILITY, CHEMICAL, AND MAINTENANCE COSTS . . . 6-3

TABLE 6-2. COSTS OF CONTROL TECHNIQUES FOR ND

NATURAL GAS-FIRED MODEL HEATERS ...... . 6-13

TABLE 6-3. COSTS OF CONTROL TECHNIQUES FOR MD

NATURAL GAS-FIRED MODEL HEATERS ...... . 6-15

TABLE 6-4. COSTS OF CONTROL TECHNIQUES FOR ND

OIL-FIRED MODEL HEATERS .......... . 6-17

TABLE 6-5. COSTS OF CONTROL TECHNIQUES FOR MD OIL-FIRED

MODEL HEATERS ............... . 6-19

TABLE 6-6. COSTS OF CONTROL TECHNIQUES FOR ND

OLEFINS PYROLYSIS MODEL HEATERS ...... . 6-20
LIST OF TABLES (continued)

Page

x

TABLE 6-7. ND-TO-MD CONVERSION COSTS FOR THE ND MODEL

HEATERS .................. . 6-21

TABLE 6-8. COST EFFECTIVENESS OF CONTROL TECHNIQUES

FOR ND NATURAL GAS-FIRED MODEL HEATERS ... . 6-23

TABLE 6-9. COST EFFECTIVENESS OF CONTROL TECHNIQUES

FOR MD NATURAL GAS-FIRED MODEL HEATERS ... . 6-26

TABLE 6-10. COST EFFECTIVENESS OF CONTROL TECHNIQUES

FOR ND OIL-FIRED MODEL HEATERS ....... . 6-28

TABLE 6-11. COST EFFECTIVENESS OF CONTROL TECHNIQUES

FOR MD OIL-FIRED MODEL HEATERS ....... . 6-29

TABLE 6-12. COST EFFECTIVENESS OF CONTROL TECHNIQUES

FOR ND PYROLYSIS MODEL HEATERS ....... . 6-30

TABLE 6-13. CARB COST EFFECTIVENESS FOR NOx EMISSION

CONTROL TECHNIQUES ............. . 6-31

TABLE 6-14. RADIANT BURNER COST EFFECTIVENESS ..... . 6-33

TABLE 7-1. OPTIMUM LOW-EXCESS-AIR, GASEOUS EMISSIONS AND

EFFICIENCIES FOR SIX PROCESS HEATERS WITH

LOW-NOx BURNERS .............. . 7-6

TABLE 7-2. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS 

FOR A 20 MMBtu/hr REFINERY HEATER WITH LNB 

PLUS LEA OPERATION (REFINERY FUEL GAS) ... . 7-8

TABLE 7-3. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS 

FOR A 6.7 MMBtu/hr (200 hp) BOILER WITH

LNB PLUS FGR ................ . 7-9
xi

LIST OF FIGURES

Page

Figure 2-1. Model heaters: NOx emission reductions,

capital costs, and cost effectiveness at a

capacity factor of 0.9 for ND, natural

gas-fired, low- and medium-temperature

heaters .................. . 2-17

Figure 2-2. Model heaters: NOx emission reductions,

capital costs, and cost effectiveness at a

capacity factor of 0.9 for MD, natural

gas-fired, low- and medium-temperature

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

Figure 2-3. Model heaters: NOx emission reductions,

capital costs, and cost effectiveness at a

capacity factor of 0.9 for ND, oil-fired,

low- and medium-temperature heaters .... . 2-19

Figure 2-4. Model heaters: NOx emission reductions,

capital costs, and cost effectiveness at a

capacity factor of 0.9 for MD, oil-fired, 

low- and medium-temperature heaters .... . 2-20

Figure 2-5. Model heaters: NOx emission reductions,

capital costs, and cost effectiveness at a

capacity factor of 0.9 for ND olefins

pyrolysis heaters ............. . 2-21

Figure 3-1. Cross-section of a typical process heater . . 3-4

Figure 3-2. Examples of radiant section tube orientations 3-7

Figure 3-3. Typical burners by type of fuel burned ... . 3-9

Figure 3-4. Size distribution of the existing fired 

heater population ............. . 3-11

Figure 3-5. Annual energy consumption projection for 

process heaters used in petroleum refining . . 3-15

Figure 4-1. Impact of temperature on NOx formation ... . 4-3

Figure 4-2. Effect of fuel-bound nitrogen on NOx

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

Figure 4-3. Effect of combustion air preheat temperature 

on NOx emissions .............. . 4-11
LIST OF FIGURES (continued)

Page

xii

Figure 4-4. Effect of firebox temperature on thermal NOx

formation for gas-fired heaters with constant 

excess air ................. . 4-13

Figure 4-5. Effect of excess air on NOx formation in

gas-fired process heaters at various

combustion air preheat temperatures .... . 4-16

Figure 4-6. Uncontrolled NOx emission data versus

heat input for gas-fired refinery process 

heaters of various design types ...... . 4-19

Figure 4-7. Uncontrolled NOx emission factors for gasfired refinery process heaters with known

burner configuration, draft type, and air

preheat conditions ............. . 4-20

Figure 4-8. Uncontrolled NOx emission rates for gasfired process heaters at one refinery

installation ................ . 4-23

Figure 4-9. Natural draft process heater refinery

inventory ................. . 4-27

Figure 4-10. Mechanical draft process heater refinery

inventory ................. . 4-29

Figure 5-1. Effect of combustion air preheat temperature 

on NOx emissions .............. . 5-5

Figure 5-2. Staged combustion air lances installed on a

conventional gas burner .......... . 5-7

Figure 5-3. Schematic of a staged-air low-NOx burner . . . 5-12

Figure 5-4. Schematic of a staged-fuel low-NOx burner . . 5-16

Figure 5-5. Cross-section of an internal flue gas

recirculation burner ............ . 5-22

Figure 5-6. Exxon Thermal DeNOx system ........ . 5-28 ®

Figure 5-7. Nalco Fuel Tech NOXOUT®-type NOx reduction 

system ................... . 5-34

Figure 5-8. Schematic of a selective catalytic reduction

system ................... . 5-39

Figure 5-9. Effect of temperature and oxygen on NOx

conversion ................. . 5-41
LIST OF FIGURES (continued)

Page

xiii

Figure 7-1. NOx emission factor for 10 process heaters 

equipped with low-NOx burners as a function 

of stack oxygen .............. . 7-5

Figure 7-2. Pilot-scale test results, NH3 emissions. 

Inlet NO = 700 ppm ............. . 7-11

Figure 7-3. Pilot-scale test results; NOx reduction

and N2O production versus temperature ... . 7-13

1-1

1.0 INTRODUCTION

Congress, in the Clean Air Act Amendments of 1990 (CAAA),

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.

Process heaters have been identified as a category with

emission sources that emit more than 25 tons of nitrogen oxide

(NOx) per year. This alternative control techniques (ACT)

document provides technical information for use by State and

local agencies to develop and implement regulatory programs to

control NOx emissions from process heaters. Additional ACT

documents are being developed for other stationary source

categories.

The information in this ACT document was generated through

literature searches and contacts with process heater control

equipment vendors, engineering firms, chemical plants, and

petroleum refineries. Chapter 2.0 presents a summary of the

findings of this study. Chapter 3.0 presents information on

process heater operation and industry applications. Chapter 4.0

contains a discussion of NOx formation and uncontrolled process

heater NOx emission factors. Alternative control techniques and

achievable controlled emission levels are included in 
1-2

Chapter 5.0. The cost and cost effectiveness of each control

technique are presented in Chapter 6.0 Chapter 7.0 describes

environmental and energy impacts associated with implementing the

NOx control techniques.
2-1

2.0 SUMMARY

This chapter presents a summary of the information contained

in this document. Section 2.1 presents a summary of NOx

formation and uncontrolled NOx emissions. Section 2.2 presents a

summary of available NOx emission control techniques and

achievable NOx emission reductions. Section 2.3 presents a

summary of the capital costs and cost effectiveness for these NOx

control techniques. Process heaters are direct fired heaters

used primarily in the petroleum refining and petrochemical

industries. Process fluids are heated to temperatures in excess

of 204EC (400EF) in the radiative and convective sections of the

heaters. Flue gas entering the convective section is usually in

excess of 800EC (1500EF) for most process heaters.

Due to the broad spectrum of process heater designs and

capacities, this study uses a limited number of model heaters to

evaluate the available NOx control techniques for process

heaters. The model heaters and uncontrolled emission factors are

introduced in Chapter 4. The model heaters and uncontrolled

emission factors are based on a refinery data base, published

literature and data. The performance of the control techniques

applied to model heaters is presented in Chapter 5 and is based

on published literature and data. Costs and cost effectiveness

of the control techniques applied to the model heaters are

presented in Chapter 6 and are based on published cost

methodologies. 
2-2

2.1 UNCONTROLLED NOx EMISSIONS

Nitrogen oxides are produced by three different formation

mechanisms: thermal, fuel, and prompt NOx. Thermal NOx is

primarily temperature-dependent, and fuel NOx is primarily

dependent on the presence of fuel-bound nitrogen and the local

oxygen concentration. Prompt NOx is the least understood

formation mechanism. Most combustion control techniques are

designed to reduce thermal and/or fuel NOx. Post combustion

techniques reduce NOx in the flue gas regardless of the formation

mechanism.

Thermal NOx formation increases rapidly at temperatures

exceeding 1540EC (2800EF) and is the primary source of NOx in

natural gas- and refinery fuel gas-fired heaters. Refinery fuel

gas firing generally yields higher thermal NOx formation than

natural gas firing due to the higher flame temperatures caused by

the higher hydrogen content of the refinery fuel gas.

Fuel NOx formation is minimal in heaters that fire natural

gas and refinery fuel gas, which contain little or no fuel-bound

nitrogen. Fuel NOx represents a considerable fraction of the

total NOx emissions in heaters burning nitrogen-bearing fuels,

such as distillate and residual oils. 
2-3
2-4

TABLE 2-1. UNCONTROLLED EMISSION FACTORS FOR MODEL HEATERS

Model heater type

Uncontrolled emission factor,

lb/MMBtu

Thermal NOx Fuel NOx Total NOx

a

ND, natural gas-firedb0.098 N/A 0.098

MD, natural gas-firedb

0.197 N/A 0.197

ND, distillate oil-fired 0.140 0.060 0.200

ND, residual oil-fired 0.140 0.280 0.420

MD, distillate oil-fired 0.260 0.060 0.320

MD, residual oil-fired 0.260 0.280 0.540

ND, pyrolysis, natural gas-fired 0.135 N/A 0.104

ND, pyrolysis, high-hydrogen fuel gas-firedc

0.162d N/A 0.140

Total NO = Thermal NO + Fuel NO a

x x x

Heaters firing refinery fuel gas with up to 50 mole percent hydrogen can have up to 20 percent higher NO b

x

 emissions than similar heaters firing natural gas.

High-hydrogen fuel gas is fuel gas with 50 mole percent or greater hydrogen content. c

Calculated assuming approximately 50 mole percent hydrogen. d

N/A = Not applicable.
2-5

 Uncontrolled emission factors for the model heaters are

presented in Table 2-1. The uncontrolled NOx emission factors

for natural gas-fired, low- and medium-temperature model heaters

are 0.098 and 0.197 pounds per million British thermal units

(lb/MMBtu) for the natural draft (ND) and mechanical draft (MD)

heaters, respectively. The uncontrolled NOx emission factors for

the ND oil-fired model heaters are 0.200 and 0.420 lb/MMBtu for

distillate and residual oil-firing, respectively. The distillate

and residual oil-fired MD model heaters have uncontrolled NOx

emission factors of 0.320 and 0.540, respectively. The

uncontrolled emission factors for the pyrolysis model heaters are

0.135 and 0.162 lb/MMBtu for the natural gas-fired and

high-hydrogen fuel gas-fired heaters, respectively.

The uncontrolled emission factors for MD model heaters are

greater than for ND model heaters because the MD model heaters

have combustion air preheat, which increases thermal NOx

emissions. The oil-fired model heaters have higher thermal NOx

emissions than the natural gas-fired model heaters, primarily due

to the higher flame temperature for oil firing. Residual oil 
2-6

contains a greater content of fuel-bound nitrogen and therefore

has higher fuel NOx emissions than the distillate oil-fired

heaters.

2.2 AVAILABLE NOx EMISSION CONTROL TECHNIQUES

The following NOx control techniques are currently used in

industry: low-NOx burners (LNB's), ultra-low NOx burners

(ULNBs), selective noncatalytic reduction (SNCR), and selective

catalytic reduction (SCR). Also, LNB's are used in combination

with flue gas recirculation (FGR), SNCR, and SCR. 

Combustion modifications such as LNB, ULNB and FGR inhibit

NOx formation by controlling the combustion process. Staging

techniques are usually used by LNB and ULNB to supply excess air

to cool the combustion process or to reduce available oxygen in

the flame zone. Staged-air LNB's create a fuel-rich reducing

primary combustion zone and a fuel-lean secondary combustion

zone. Staged-fuel LNB's create a lean primary combustion zone

that is relatively cool due to the presence of excess air, which

acts as a heat sink to lower combustion temperatures. The

secondary combustion zone is fuel-rich. Ultra-low-NOx burners

use staging techniques similar to staged-fuel LNB in addition to

internal flue gas recirculation. Flue gas recirculation returns

a portion of the flue gas to the combustion zone through ducting

external to the firebox that reduces flame temperature and

dilutes the combustion air supply with relatively inert flue gas. 

Unlike combustion controls, SNCR and SCR do not reduce NOx

by inhibiting NOx formation, but reduce NOx in the flue gas. 

These techniques control NOx by using a reactant that reduces NOx

to nitrogen (N2 ) and water. The reactant, ammonia (NH3) or urea

for SNCR, and NH3 for SCR, is injected into the flue gas stream. 

Temperature and residence time are the primary factors that

influence the reduction reaction. Selective catalytic reduction

uses a catalyst to facilitate the reaction.

The reduction efficiency of each control technique varies

depending on the process heater application and design. The

efficiencies for LNB, ULNB, and SCR are considered to be

representative averages based on operating experience. Fuel NOx
2-7

reduction efficiencies and the reduction efficiencies for FGR,

and SNCR are based on a Canadian Petroleum Products Institute

report. Tables 2-2 
2-8

TABLE 2-2. REDUCTION EFFICIENCIES FOR CONTROL TECHNIQUES APPLIED

TO NATURAL GAS- AND REFINERY FUEL GAS-FIRED PROCESS HEATERS AND

PYROLYSIS FURNACES

Control technique - low and medium 

temperature heaters Total effective NO reduction, percent x

a

LNB 50

ULNB 75

SNCR 60

SCR 75

LNB + FGR 55

LNB + SNCR 80

LNB + SCR 88

Control technique - pyrolysis furnaces Total effective NO reduction, percent x

a

LNB 25

ULNB 50

SNCR 60

SCR 75

LNB + FGR 55

LNB + SNCR 70

LNB + SCR 81

Further discussion on the NO reduction efficiencies of each control technique is included in Chapter 5. a

x
2-9

TABLE 2-3. REDUCTION EFFICIENCIES FOR CONTROL TECHNIQUES APPLIED

TO ND AND MD, DISTILLATE AND RESIDUAL OIL-FIRED PROCESS HEATERS

Draft and fuel type Control technique Total effective NO reduction, percent x

a

ND, distillate (ND) LNB 40

(MD) LNB 43

(ND) ULNB 76

(MD) ULNB 74

SNCRb 60 

(MD) SCR 75 

(MD) LNB + FGR 43 

(ND) LNB + SNCR 76

(MD) LNB + SNCR 77 

(MD) LNB + SCR 86

ND, residual (ND) LNB 27

(MD) LNB 33

(ND) ULNB 77 

(MD) ULNB 73 

SNCR 60 

(MD) SCR 75 

(MD) LNB + FGR 28

(ND) LNB + SNCR 71 

(MD) LNB + SNCR 73

(MD) LNB + SCR 83

MD, distillate (MD) LNB 45

(MD) ULNB 74

(MD) SNCR 60 

(MD) SCR 75 

(MD) LNB + FGR 48

(MD) LNB + SNCR 78

(MD) LNB + SCR 92

MD, residual (MD) LNB 37 

(MD) ULNB 73

(MD) SNCR 60 

(MD) SCR 75 

(MD) LNB + FGR 34

(MD) LNB + SNCR 75

(MD) LNB + SCR 91

Further discussion on the NO reduction efficiencies of each control technique is included in Chapter 5. a

x

Reduction efficiencies for ND or MD SNCR are equal. b

and 2-3 present the reduction efficiencies for each NOx control
2-10

technique. The total effective reduction efficiencies for

natural gas- and refinery fuel gas-fired heaters are shown in

Table 2-2 and for low- and medium-temperature process heaters

range from 50 percent for LNB to 88 percent for LNB plus SCR. 

The total effective percent reductions for pyrolysis furnaces are

lower for control techniques that use LNB's or ULNB's compared to

the low- and medium-temperature heaters, and range from

25 percent for LNB to 81 percent for LNB plus SCR. The total

effective reduction efficiencies of the oil-fired heaters are

shown in Table 2-3 and range from 27 percent for ND LNB on ND

residual oil-fired heaters to 92 percent for MD LNB plus SCR on

MD distillate oil-fired heaters. The total effective reduction

efficiencies of the gas-fired heaters are the same for ND or MD

operation. However, different reduction efficiencies for thermal

and fuel NOx emissions result in varying total effective

reduction efficiencies for the oil-fired heaters.

2.3 CAPITAL COSTS AND COST EFFECTIVENESS

The capital costs and cost effectiveness for each of the NOx

control techniques discussed in Section 2.2 are presented in this

section for the model heaters. Cost methodologies from reports

published by the Canadian Petroleum Products Institute and the

South Coast Air Quality Management District are used to estimate

the capital and annual costs for the control techniques. 

The cost of converting ND heaters to MD heaters is included

in the cost analysis in which MD control techniques are used on

ND model heaters. Natural draft-to-MD conversion is not

considered a NOx control technique and is usually performed to

take advantage of thermal efficiency gains. These efficiency

gains are site specific and are not included or quantified in

this study. Therefore, the actual cost effectiveness of control 
2-11
2-12

techniques that include ND-to-MD conversion may be lower than

shown in this study.

Cost effectiveness of the control techniques, in $/ton of

NOx removed, is calculated as the total annual cost divided by

the annual NOx reduction, in tons, for each control technique

applied to each model heater. Tables 2-4 through 2-8 present the

cost effectiveness of these control techniques for the ND natural

gas-fired, MD natural gas-fired, ND oil-fired, MD oil-fired, and

ND pyrolysis model heaters, respectively. Burner control

techniques generally have the lowest cost effectiveness, with SCR

having the highest. Ultra-low-NOx burner cost effectiveness is

lower than LNB in all cases because the additional reduction

efficiency more than offsets the additional cost. The cost

effectiveness of SNCR is greater than that of LNB in most cases

because of the higher capital and operating costs for SNCR. LowNOx burners plus FGR have higher cost effectiveness than SNCR in

most cases. The capital cost for SNCR are comparable to LNB plus

FGR, but the higher operating costs result in higher

cost-effectiveness values for SNCR. The highest reduction

efficiencies are achieved by SCR and LNB plus SCR, but these

techniques also have the highest cost effectiveness due to the

relatively high capital and annual costs for SCR.

The lowest cost effectiveness is achieved with ULNB's and

the highest with SCR for each model heater. The range of cost

effectiveness for each of the five types of model heaters at a

capacity factor of 0.9 are (1) $981/ton to $16,200/ton for the ND

natural gas-fired heaters, (2) $813/ton to $10,600/ton for the MD

natural gas-fired heaters, (3) $419/ton to $6,490/ton for the ND

oil-fired heaters, (4) $245/ton to $4,160/ton for the MD oilfired heaters, and (5) $1,790/ton to $14,100/ton for the ND

pyrolysis heaters. Figures 2-1 through 2-5 graphically present

the reduction efficiencies, capital cost, and cost effectiveness

for the model heaters.
TABLE 2-4. MODEL HEATERS: NOx EMISSION REDUCTIONS, CAPITAL COSTS, AND COST EFFECTIVENESS

FOR ND, NATURAL GAS-FIRED LOW- AND MEDIUM-TEMPERATURE HEATERS

Model heater Uncontrolled NO factors:

capacity, MMBtu/hr emission factor, lb/MMBtu Total effective NO NO reduction,

x

NOx control technique reduction, percent tons/yr Capital cost, $

x x

a,b

Cost effectiveness, $/ton @ capacity

c

0.1 0.5 0.9

17 0.098 (ND) LNB 50 3.65 58,200 25,400 5,070 2,820 

0.197 (MD) LNB 50 7.33 191,000 41,400 8,280 4,600

0.098 (ND) ULNB 75 5.47 62,500 18,200 3,630 2,020 

0.197 (MD) ULNB 75 1.10 249,000 36,000 7,200 4,000

0.098 (ND) SNCR 60 4.38 155,000 56,700 11,800 6,770 

0.197 (MD) SNCR 60 8.80 258,000 47,100 9,760 5,610

0.197 (MD) SCR 75 1.10 951,000 141,000 28,700 16,200

0.197 (MD) LNB + FGR 55 8.07 253,000 50,000 10,100 5,710

0.098 (ND) LNB + SNCR 80 5.84 213,000 58,400 12,000 6,840 

0.197 (MD) LNB + SNCR 80 1.17 346,000 47,100 9,690 5,530

0.197 (MD) LNB + SCR 88 12.8 995,000 132,000 26,700 15,100

36 0.098 (ND) LNB 50 7.73 92,600 19,100 3,810 2,120 

0.197 (MD) LNB 50 15.5 302,000 30,900 6,170 3,430

0.098 (ND) ULNB 75 11.6 96,900 13,300 2,660 1,480 

0.197 (MD) ULNB 75 23.3 308,000 21,000 4,200 2,330

0.098 (ND) SNCR 60 9.27 243,000 42,100 8,850 5,150 

0.197 (MD) SNCR 60 18.6 405,000 35,000 7,260 4,180

0.197 (MD) SCR 75 23.3 1,500,000 106,000 21,700 12,300

0.197 (MD) LNB + FGR 55 17.1 399,000 37,300 7,590 4,290

0.098 (ND) LNB + SNCR 80 12.4 335,000 43,500 9,020 5,190 

0.197 (MD) LNB + SNCR 80 24.9 544,000 35,100 7,280 4,190

0.197 (MD) LNB + SCR 88 27.2 1,570,000 99,200 20,200 11,400
TABLE 2-4. (continued)

Model heater Uncontrolled NO factors:

capacity, MMBtu/hr emission factor, lb/MMBtu Total effective NO NO reduction,

x

NOx control technique reduction, percent tons/yr Capital cost, $

x x

a,b

Cost effectiveness, $/ton @ capacity

c

0.1 0.5 0.9

77 0.098 (ND) LNB 50 16.5 133,000 12,800 2,570 1,430 

0.197 (MD) LNB 50 33.2 457,000 21,900 4,370 2,430

0.098 (ND) ULNB 75 24.8 138,000 8,830 1,770 981

0.197 (MD) ULNB 75 49.8 463,000 14,800 2,950 1,640

0.098 (ND) SNCR 60 19.8 383,000 31,200 6,670 3,940

0.197 (MD) SNCR 60 39.9 639,000 25,900 5,450 3,170

0.197 (MD) SCR 75 49.8 2,390,000 80,100 16,400 9,370

0.197 (MD) LNB + FGR 55 36.5 610,000 26,700 5,480 3,120

0.098 (ND) LNB + SNCR 80 26.4 516,000 31,400 6,610 3,850 

0.197 (MD) LNB + SNCR 80 53.2 839,000 25,400 5,340 3,119

0.197 (MD) LNB + SCR 88 58.1 2,480,000 74,100 15,200 8,640

121 0.098 (ND) LNB 50 26.0 232,000 14,200 2,840 1,580 

0.197 (MD) LNB 50 52.2 685,000 20,900 4,170 2,320

0.098 (ND) ULNB 75 39.0 237,000 9,660 1,930 1,070 

0.197 (MD) ULNB 75 78.3 691,000 14,000 2,810 1,560

0.098 (ND) SNCR 60 31.2 502,000 26,100 5,660 3,380 

0.197 (MD) SNCR 60 62.6 838,000 21,700 4,610 2,710

0.197 (MD) SCR 75 78.3 3,160,000 67,900 14,000 8,020

0.197 (MD) LNB + FGR 55 57.4 887,000 24,700 5,080 2,890

0.098 (ND) LNB + SNCR 80 41.6 734,000 28,500 6,020 3,520 

0.197 (MD) LNB + SNCR 80 83.5 1,190,000 22,900 4,840 2,830

0.197 (MD) LNB + SCR 88 91.4 3,370,000 64,300 13,200 7,550
TABLE 2-4. (continued)

Model heater Uncontrolled NO factors:

capacity, MMBtu/hr emission factor, lb/MMBtu Total effective NO NO reduction,

x

NOx control technique reduction, percent tons/yr Capital cost, $

x x

a,b

Cost effectiveness, $/ton @ capacity

c

0.1 0.5 0.9

186 0.098 (ND) LNB 50 39.9 346,000 13,800 2,760 1,530 

0.197 (MD) LNB 50 80.2 955,000 18,900 3,780 2,100

0.098 (ND) ULNB 75 59.9 351,000 9,310 1,860 1,030 

0.197 (MD) ULNB 75 12.0 961,000 12,700 2,540 1,410

0.098 (ND) SNCR 60 47.9 650,000 22,100 4,850 2,930 

0.197 (MD) SNCR 60 96.3 1,090,000 18,300 3,930 2,330

0.197 (MD) SCR 75 120 4,130,000 58,200 12,100 6,940

0.197 (MD) LNB + FGR 55 88.3 1,220,000 22,100 4,550 2,600

0.098 (ND) LNB + SNCR 80 63.9 996,000 25,200 5,360 3,150 

0.197 (MD) LNB + SNCR 80 128 1,600,000 20,200 4,300 2,530

0.197 (MD) LNB + SCR 88 140 4,460,000 55,700 11,500 6,600

NO reductions = Uncontrolled emission factor (lb/MMBtu) * Capacity(MMBtu/hr) * Effective reduction (%) * 1 ton/2,000lb * 8,760 hr/yr * Capacity factor. a

x

NO reductions in this column are calculated at a capacity factors of 1.0. To obtain reductions corresponding to particular capacity factors, substitute the desired capacity factor into the b

x

above equation.

Cost effectiveness is calculated by dividing the total annual cost (TAC) by the NO reductions. Refer to Chapter 6 for the TAC. c

x
TABLE 2-5. MODEL HEATERS: NOx EMISSION REDUCTIONS, CAPITAL COSTS, AND COST EFFECTIVENESS

FOR MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS

Model heater emission factor, NO control Total effective NO NO reduction,

capacity, MMBtu/hr lb/MMBtu technique reduction, percent tons/yr Capital cost, $

Uncontrolled NOx

x x x

a,b

Cost effectiveness, $/ton @ capacity factors:c

0.1 0.5 0.9

40 0.197 LNB 50 17.3 130,000 12,000 2,390 1,330

ULNB 75 25.9 136,000 8,380 1,680 931 

SNCR 60 20.7 258,000 20,300 4,400 2,640 

SCR 75 25.9 1,270,000 91,500 18,700 10,600

LNB + FGR 55 19.0 234,000 19,700 4,080 2,340 

LNB + SNCR 80 27.6 388,000 22,700 4,790 2,810 

LNB + SCR 88 30.2 1,400,000 85,200 17,400 9,880

77 0.197 LNB 50 33.2 282,000 13,500 2,700 1,500 

ULNB 75 49.8 288,000 9,200 1,840 1,020 

SNCR 60 39.9 383,000 15,700 3,480 2,130 

SCR 75 49.8 1,900,000 71,900 14,800 8,460

LNB + FGR 55 36.5 436,000 19,100 3,960 2,270 

LNB + SNCR 80 53.2 665,000 20,200 4,300 2,530 

LNB + SCR 88 58.1 2,180,000 69,300 14,200 8,110

114 0.197 LNB 50 49.2 507,000 16,400 3,280 1,820 

ULNB 75 73.8 514,000 11,100 2,210 1,230 

SNCR 60 59.0 484,000 13,500 3,040 1,880 

SCR 75 73.8 2,420,000 62,800 12,900 7,410

LNB + FGR 55 54.1 702,000 20,800 4,290 2,460 

LNB + SNCR 80 78.7 992,000 20,400 4,330 2,550 

LNB + SCR 88 86.1 2,930,000 62,800 12,900 7,390
TABLE 2-5. (continued)

Model heater emission factor, NO control Total effective NO NO reduction,

capacity, MMBtu/hr lb/MMBtu technique reduction, percent tons/yr Capital cost, $

Uncontrolled NOx

x x x

a,b

Cost effectiveness, $/ton @ capacity factors:c

0.1 0.5 0.9

174 0.197 LNB 50 75.1 541,000 11,500 2,290 1,270 

ULNB 75 113 548,000 7,730 1,550 859 

SNCR 60 90.1 624,000 11,400 2,630 1,660 

SCR 75 113 3,150,000 53,700 11,200 6,440

LNB + FGR 55 82.6 792,000 15,400 3,220 1,860 

LNB + SNCR 80 120 1,170,000 15,700 3,410 2,040 

LNB + SCR 88 131 3,700,000 52,600 10,900 6,250

263 0.197 LNB 50 113 777,000 10,900 2,180 1,210 

ULNB 75 170 783,000 7,310 1,460 813 

SNCR 60 136 800,000 9,770 2,300 1,470 

SCR 75 170 4,090,000 46,500 9,730 5,640

LNB + FGR 55 125 1,100,000 14,200 2,960 1,720 

LNB + SNCR 80 182 1,580,000 14,100 3,080 1,860 

LNB + SCR 88 199 4,860,000 46,100 9,580 5,530

NO reductions = Uncontrolled emission factor (lb/MMBtu) * Capacity(MMBtu/hr) * Effective reduction (%) * 1 ton/2,000lb * 8,760 hr/yr * Capacity factor. a

x

NO reductions in this column are calculated at a capacity factors of 1.0. To obtain reductions corresponding to particular capacity factors, substitute the desired capacity factor into the b

x

above equation.

Cost effectiveness is calculated by dividing the total annual cost (TAC) by the NO reductions. Refer to Chapter 6 for the TAC. c

x



Figure 2-1. Model heaters: NOx emission reductions, capital

costs, and cost effectiveness at a capacity factor of 0.9 for ND,

natural gas-fired, low- and medium-temperature heaters.

Figure 2-2. Model heaters: NOx emission reductions, capital

costs, and cost effectiveness at a capacity factor of 0.9 for MD,

natural gas-fired, low- and medium-temperature heaters.

Figure 2-3. Model heaters: NOx emission reductions, capital

costs, and cost effectiveness at a capacity factor of 0.9 for ND,

oil-fired, low- and medium-temperature heaters.

Figure 2-4. Model heaters: NOx emission reductions, capital

costs, and cost effectiveness at a capacity factor of 0.9 for MD

oil-fired, low- and medium-temperature heaters.

Figure 2-5. Model heaters: NOx emission reductions, capital

costs, and cost effectiveness at a capacity factor of 0.9 for ND

 olefins pyrolysis heaters.

2.4 IMPACTS OF NOx CONTROLS

The use of NOx control techniques may cause environmental

and energy impacts. Environmental impacts associated with 

combustion controls include carbon monoxide (CO) and unburned

hydrocarbon (HC) emissions. Environmental impacts of

postcombustion techniques include NH3, CO, and nitrous oxide

(N2 O) emissions with the use of SNCR; NH3 and sulfite (SO3)

emissions and solid waste disposal concerns with the use of SCR. 

Ammonia handling and storage also presents safety concerns with

SNCR and SCR. 

Energy impacts include additional electric energy

requirements for fans or blowers and thermal efficiency losses. 

Thermal efficiency losses result in increased fuel consumption. 

These impacts are described briefly below.

Combustion controls, such as LNB, ULNB, and FGR, modify the

combustion conditions to reduce the amount of NOx formed. 

Combustion controls are usually operated in such a manner that

reduces NOx without producing unacceptable levels of CO and HC. 

Combustion controls reduce NOx formation by reducing the peak

flame temperature and/or O2 concentrations in the flame zone. 

Reductions in NOx formation achieved by reducing flame

temperature and O2 levels can increase CO and HC emissions if NOx

reductions by combustion controls are taken to extremes.

The use of SNCR results in emissions of unreacted NH3 and

increases in CO and N2O emissions. Reactant-to-NOx ratios of

1.25 to 2.0:1 are typical of SNCR systems. The high ratio

results in unreacted NH3 emissions, or NH3 slip. Carbon monoxide

and N2O have been shown to be byproducts of urea injection. 

Unreacted NH3 and N2O are byproducts of NH3 injection. Selective

catalytic reduction NH3 slip concentrations are generally less

than SNCR NH3 slip concentrations because the catalytic reactor

allows a higher reaction rate and lower reactant-to-NOx injection

ratio (1.05:1 or less). Most catalysts used in SCR systems

controlling process heaters in refinery service contain titanium

and vanadium oxides. Catalyst formulations developed in the

early 1980's tend to convert up to 5 percent of any sulfur 
dioxide (SO2 ) present in high-sulfur fuels to SO3, resulting in

SO3 emissions. Newer catalyst formulations that convert less

than 1 percent SO2 to SO3 are available and have been

demonstrated in utility applications. 

Safety concerns for NH3 storage and transport are due to the

hazardous nature of concentrated NH3 vapor. Aqueous NH3 (NH3 in a

liquid solution at atmospheric pressure) is not considered as

hazardous as anhydrous NH3, which is stored as a concentrated

pressurized vapor. Aqueous NH3 is available for SCR and NH3 SNCR

processes.

State and local regulatory agencies may classify catalysts

containing vanadium pentoxide as a hazardous waste, however, and

require disposal of these catalyst materials in an approved

hazardous waste disposal facility. Such disposal problems are

not encountered with other catalyst materials, such as precious

metals and zeolites, because these materials are not considered

hazardous wastes.

Control techniques that require upgraded or newly installed

fans and blowers increase the electrical energy consumption for

process heaters using those control techniques. These control

techniques are LNB plus SCR, LNB plus FGR and ND heaters

converted to MD for MD LNB or MD ULNB use.

Current combustion controls balance NOx reduction with

acceptable fuel efficiency. Adding LNB, ULNB, and LNB plus FGR

may cause flames instability and reduced combustion efficiency. 

However, these impacts are minimal in properly designed systems. 

Injecting reactants into the flue gas stream in SNCR systems

produces approximately a 0.3 percent thermal efficiency loss. 

The injection of reactants and the pressure drop across the

catalyst in SCR systems produces approximately a 1.5 percent

thermal efficiency loss. Thermal efficiency losses generally

result in increased fuel consumption.
3.0 PROCESS HEATER DESCRIPTION AND INDUSTRY CHARACTERIZATION

This chapter describes process heaters and characterizes the

industries typically using them. Process heaters are used in the

petroleum refining and petrochemical industries, with minor

applications in the fibers, iron and steel, gas processing, and

other industries. Detailed technical descriptions of design 1

parameters, operations, and applications of process heaters are

presented in Section 3.1. The two main industries using process

heaters, petroleum refining operations and chemical manufacturing

facilities, are characterized in Section 3.2.

3.1 PROCESS HEATER DESCRIPTION

Process heaters (also known as process furnaces and

direct-fired heaters) are heat transfer units in which heat from

fuel combustion is transferred predominantly by radiation and

secondarily by convection to fluids contained in tubes. Process 1

heaters are generally used in heat transfer applications where

steam heaters (i.e., boilers) are inappropriate. These include

applications in which heat must be transferred at temperatures in

excess of 90E to 204EC (200E to 400EF). The process fluid stream

to be heated is contained in single-fired tubes along the radiant

section walls and ceiling, in two-sided fired tubes within the

radiant section, and in convection section tubes of the process

heater combustion chamber. This process fluid stream is heated

for one of two reasons: (1) to raise the temperature for

additional processing (heated feed), or (2) so that chemical

reactions may occur in the tubes (reaction feed). Sections 3.1.1

and 3.1.2 contain more information on these two types of process

heaters.
3-2

3.1.1 Heated Feed

Process heaters whose function is to heat a process fluid

stream before additional processing include distillation column

feed preheaters and reboilers, reactor feed preheaters, hot oil

furnaces, and viscous fluid heaters. This type of process 1

heater is found in both the petroleum refining and chemical

manufacturing industries. 

Fired heaters are used in the petroleum refining industry

principally as preheaters for various operations such as

distillation, catalytic cracking, hydroprocessing, and

hydroconversion. Fired heaters are used in a wide variety of 2

applications in the chemical manufacturing industry. They are

used as fired reactors (e.g., steam-hydrocarbon reformers and

olefins pyrolysis furnaces), feed preheaters for nonfired

reactors, reboilers for distillation operations, and heaters for

heating transfer oils.3

3.1.2 Reaction Feed

Chemical reactions occur inside the tubes of many process

heaters upon heating. Applications include steam-hydrocarbon

reformers used in ammonia and methanol manufacturing, pyrolysis

furnaces used in ethylene manufacturing, and thermal cracking

units used in refining operations.1

3.1.3 Process Heater Design Parameters

Process heaters may be designed and constructed in a number

of ways, but most process heaters include burner(s), combustion

chamber(s), and tubes that contain process fluids. 

Sections 3.1.3.1 through 3.1.3.4 describe combustion chamber setups, combustion air supply, tube configurations, and burners,

respectively.

3.1.3.1 Combustion Chamber Set-Ups. Process heaters

contain a radiant heat transfer area in the combustion chamber. 

This area heats the process fluid stream in the tubes by flame

radiation. Equipment found in this area includes the burner(s)

and the combustion chamber(s). Most heat transfer to the process

fluid stream occurs here, but these tubes do not necessarily

constitute a majority of the tubes in which the process fluid
3-3

flows. A typical process heater displaying this equipment is

shown in Figure 3-1.4
3-4
3-5

Figure 3-1. Cross-section of a typical process heater.4
3-6

Most process heaters also use a convective heat transfer

section to recover residual heat from the hot combustion gases by

convective heat transfer to the process fluid stream. This 4

section is located after the radiant heat transfer section and

also contains tubes filled with process fluid. The first few

rows of tubes in this section are called shield tubes and are

subject to some radiant heat transfer. Typically, the process

fluid flows through the convective section prior to entering the

radiant section in order to preheat the process fluid stream. 

The temperature of the flue gas upon entering the convective

section usually ranges from 800E to 1000EC (1500E to 2000EF).5,6

Preheating in the convective section improves the efficiency of

the process heater, particularly if the tube design includes fins

or other extended surface areas. An extended tube surface area

can improve efficiency by 10 percent. Extended tubes can reduce 7

flue gas temperatures from 800E to 1010EC (1500E to 2000EF) to

120E to 260EC (250E to 500EF).6

3.1.3.2 Combustion Air Supply. Combustion air is supplied

to the burners via natural draft (ND) or mechanical draft (MD)

systems. Natural draft heaters use duct work systems to route

air, usually at ambient conditions, to the burners. Mechanical

draft heaters use fans in the duct work system to supply air,

usually preheated, to the burners. The combustion air supply

must have sufficient pressure to overcome the burner system

pressure drops caused by ducting, burner registers, and dampers. 

The pressure inside the firebox is generally a slightly negative

draft of approximately 49.8 to 125 Pascals (Pa) (0.2 to 0.5 inch

of H2O [in. H2O]) at the radiant-to-convective section transition

point. The negative draft is achieved in ND systems via the stack

effect and in MD systems via fans or blowers.6

Natural draft combustion air supply uses the stack effect to

induce the flow of combustion air in the heater. The stack

effect, or thermal buoyancy, is caused by the density difference 
3-7

between the hot flue gas in the stack and the significantly

cooler ambient air surrounding the stack. Approximately 6

90 percent of all gas-fired heaters and 76 percent of all oilfired heaters use ND combustion air supply.7

There are three types of MD combustion air supply: forced

draft, induced draft, and balanced draft. The draft types are

named according to the position, relative to the combustion

chamber, of the fans used to create pressure difference in the

process heater. All three types of MD heaters rely on the fans

to supply combustion air and remove flue gas. In forced draft

combustion air systems, the fan is located upstream from the

combustion chamber, supplying combustion air to the burners. The

air pressure supplied to the burners in a forced draft heater is

typically in the range of 0.747 to 2.49 kilopascals (kPa) (3 to

10 in. H2O). Though combustion air is supplied to the burners 8

under positive pressure, the remainder of the process heater

operates under negative pressure caused by the stack effect. In

induced draft combustion air systems, the fan is located

downstream of the combustion chamber, creating negative pressure

inside the combustion chamber. This negative pressure draws, or

induces, combustion air into the burner registers. Balanced

draft combustion air systems use fans placed both upstream and

downstream (forced and induced draft) of the combustion chamber.8

There are advantages and disadvantages for both ND and MD 

combustion air supply. Natural draft heaters do not require the

fans and equipment associated with MD combustion air supply. 

Though simpler, ND heaters do not allow as precise control of

combustion air flow as do MD heaters. Mechanical draft heaters,

unlike ND heaters, provide the option of using alternate sources

of combustion oxygen, such as gas turbine exhaust, and the use of

combustion air preheat. Combustion air preheat has limited 8

application in ND heaters due to the pressure drops associated

with combustion air preheaters.

Combustion air preheaters are often used to increase the

efficiency of MD process heaters. The maximum thermal efficiency

obtainable with current air preheat equipment is 92 percent.9
3-8

Preheaters allow heat to be transferred to the combustion air

from flue gas, steam, condensate, hydrocarbon, or other hot

streams. The preheater increases the efficiency of the process 6

heater because some of the thermal energy is reclaimed that would

have been exhausted from the hot streams via cooling towers. If

the thermal energy is from the heater's flue gas, the heater

efficiency is increased. If the thermal energy is from a hot

stream other than the flue gas, the entire plant's efficiency is

increased. The benefit of higher thermal efficiency is that less

fuel is required to operate the heater.6

3.1.3.3 Tube Configurations. The orientation of the tubes

through which a process fluid stream flows is also taken into

consideration when designing a process heater. The tubes in the

convective section are oriented horizontally in most process

heaters to allow crossflow convection. However, the tubes in the

radiant area may be oriented either horizontally or vertically. 

The orientation is chosen on a case-by-case basis according to

the design specifications of the individual process heater. For

example, the arbor, or wicket, type of fired heater is a

specialty design to minimize the pressure drop across the

tubes. Figure 3-2 4,6
3-9

Figure 3-2. Examples of radiant section tube orientations.10
3-10

displays some of the tube orientation options available.

3.1.3.4 Burners. Many different types of burners are used

in process heaters. Burner selection depends upon several

factors including process heat flux requirements, fuel type, and

draft type. The burner chosen must provide a radiant heat 11

distribution that is consistent with the configuration of the

tubes carrying process fluid. Also, the number and location of

the burner(s) depends on the process heater application.11

Many burner flame shapes are possible, but the most common

types are flat and conical. Flat flames are generally used in

applications that require high temperatures such as ethylene

pyrolysis furnaces, although some ethylene furnaces use conical

flames to achieve uniform heat distribution. Long conical 6,11

flames are used in cases where a uniform heat distribution is

needed in the radiant section.11
3-11

Fuel compatibility is also important in burner selection. 

Burners may be designed for combustion of oil, gas, or a gas/oil

mixture. Figure 3-3 
3-12

Figure 3-3. Typical burners by type of fuel burned.14
3-13

shows typical burners found in process heaters. Gas-fired

burners are simpler in operation and design than oil-fired

burners and are classified as either premix or raw gas burners. 

In premix burners, 50 to 60 percent of the air necessary for

combustion is mixed with the gas prior to combustion at the

burner tip. This air is induced into the gas stream as the gas

expands through orifices in the burner. The remainder of the air

necessary for combustion is provided at the burner tip. Raw gas

burners receive fuel gas without any premixed combustion air. 

Mixing occurs in the combustion zone at the burner tip.12

Oil-fired burners are classified according to the method of

fuel atomization used. Atomization is needed to increase the

mixing of fuel and combustion air. Three types of fuel

atomization commonly used are mechanical, air, and steam. Steam

is the most widely used method because it is the most economical,

provides the best flame control, and can handle the largest

turndown ratios. Typical steam requirements are 0.07 to

0.16 kilogram (kg) steam/kg of oil.13

Combination burners can burn 100 percent oil, 100 percent

gas, or any combination of oil and gas. A burner with this

capability generally has a single oil nozzle in the center of a

group of gas nozzles. The air needed for combustion can be

controlled separately in this type of burner. Another option

available is to baseload the burners with one fuel and to add the

other fuel to meet increases in load demand. Combination burners

add flexibility to the process heater, especially when the

composition of the fuel is variable.15

The location and number of burners needed for a process

heater are also determined on an individual basis. Burners can

be located on the ceiling, walls, or floor of the combustion

chamber. Floor- and wall-fired units are the most common burner

types found in process heaters because they are both efficient

and flexible. In particular, floor-mounted burners integrate 
3-14

well with the use of combustion air preheat, liquid fuels, and

alternate sources of combustion oxygen such as turbine exhaust.15

The number of burners in a heater can range from 1 to

over 100. In the refinery industry, the average number of

burners is estimated at 24 in ND heaters with an average design

heat release of 69.4 million British thermal units per hour

(MMBtu/hr). The average number of burners is estimated at 20 in

MD heaters with ambient combustion air and an average design heat

release of 103.6 MMBtu/hr. The average number of burners is

estimated at 14 in MD heaters with combustion air preheat and an

average design heat release of 135.4 MMBtu/hr. In general, the 16

smaller the number of burners, the simpler the heater will be. 

However, multiple burners provide a more uniform temperature

distribution.

3.2 INDUSTRY CHARACTERIZATION

Statistical information on the two primary industries using

process heaters (the petroleum refining industry and the chemical

manufacturing industry) is contained in this section. The

statistical information includes the number and size of process

heaters in use by these industries, specific operations in each

industry that require process heaters, and energy consumption

projections for process heaters in these industries.

3.2.1 Process Heaters in Use

According to the annual refining survey published in the Oil

and Gas Journal, there were 194 operating refineries in the

United States as of January 1, 1991. Most of the heaters in 17

oil refineries are ND (89.6 percent), and the remaining heaters

are MD, both without preheat (8.0 percent) and with preheat

(2.4 percent). The mean size of all process heaters is

72 MMBtu/hr, while the mean size of MD heaters is 110 MMBtu/hr . 

2

Figure 3-4 
3-15

Figure 3-4. Size distribution of the existing fired heater

population.18
3-16

presents the size distribution breakdown for this industry. 

Based on a comparison of similar information from 1985, it is

evident that growth in the refining industry has been modest over

the last 5 years. In 1985, there were 191 operating refineries

in the United States ranging in capacity from 4,000 barrels crude

oil per calendar day (bbl/d) to 
3-17

494,000 bbl/d. As of January 1, 1991, the capacity range was 19

2,500 bbl/d to 433,000 b/d. This lower capacity range, coupled 17

with an increase in total production capacity of 379,000 bbl/d

(1985, 15.1 million bbl/d; 1991, 15.5 million bbl/d), provides

evidence of growth in small to mid-size plants and a trend

towards reductions in large facility production capacity. 

Table 3-1
3-18

TABLE 3-1. SURVEY OF OPERATING REFINERIES IN THE U.S.17

(State capacities as of January 1, 1991)

State No. of plants

Crude capacity,

bbl/d

Alabama

Alaska

Arizona

Arkansas

California

4

6

2

3

30

166,000

243,000

14,200

60,500

2,210,000

Colorado

Delaware

Georgia

Hawaii

Illinois

3

1

2

2

7

91,200

140,000

35,500

143,000

973,000

Indiana

Kansas

Kentucky

Louisiana

Michigan

4

8

2

19

4

427,000

351,000

219,000

2,330,000

124,000

Minnesota

Mississippi

Montana

Nevada

New Jersey

2

5

4

1

6

286,000

359,000

136,000

4,500

494,000

New Mexico

New York

North Dakota

Ohio

Oklahoma

4

1

1

4

7

77,300

39,900

58,000

454,000

409,000

Oregon

Pennsylvania

Tennessee

Texas

Utah

1

7

1

31

6

N/A

731,000

60,000

3,880,000

155,000

Virginia

Washington

West Virginia

Wisconsin

Wyoming

1

7

2

1

5

53,000

521,000

29,700

32,000

165,000

TOTAL 194 15,500,000

N/A = Not available.
3-19

 provides a breakdown of the number of refineries and total crude

capacity (bbl/d) in each State.

In 1980, the American Petroleum Institute (API) estimated

the total number of process heaters in the petroleum refining

industry to be about 3,200. The number of process heaters at 20

refineries varies in that large, integrated facilities may have

as many as 100 process heaters, and small refineries may have as

few as 4.2

The total number of chemical industry fired heaters was

estimated to be 1,400 in 1985. This number was estimated by

dividing the annual energy demand of the chemical industry fired

heaters in major applications (6.8 x 10 MMBtu/yr) by the 14

average-sized chemical industry fired heater (56.1 MMBtu/hr) as

reported by the Chemical Manufacturers Association.21

3.2.2 Process Heater Energy Consumption

The predominant uses of process heaters in the petroleum

refining industry are as preheaters for distillation, catalytic

cracking, hydroprocessing, and hydroconversion. Table 3-2
3-20

TABLE 3-2. MAJOR REFINERY PROCESSES REQUIRING A FIRED HEATER22

Process Process description

Heaters

used

Process heat requirements

Feedstock

temperature

outlet of

heater, EF

KJ/liter 10 Btu/bbl feed 3

Distillation

Atmospheric Separates light hydrocarbons from crude in a

distillation column under atmospheric conditions.

Preheater,

reboiler

590 89 700

Vacuum Separates heavy gas oils from atmospheric

distillation bottoms under vacuum.

Preheater,

reboiler

418 63 750-830

Thermal processes

Thermal cracking Thermal decomposition of large molecules into

lighter, more valuable products.

Fired

reactor

4,650 700 850-1,000

Coking Cracking reactions allowed to go to completion. 

Lighter products and coke produced.

Preheater 1,520 230 900-975

Visebreaking Mild cracking of residuals to improve their

viscosity and produce lighter gas oils.

Fired

reactor

961 145 850-950

Catalytic cracking

Fluidized catalytic

cracking

Cracking of heavy petroleum products. A catalyst

is used to aid the reaction.

Preheater 663 100 600-885

Catalytic

hydrocracking

Cracking heavy feedstocks to produce lighter

products in the presence of hydrogen and a

catalyst.

Preheater 1,290 195 400-850

Hydroprocessing

HydrodesulfurizationRemove contaminating metals, sulfur, and

nitrogen from the feedstock. Hydrogen is added

and reacted over a catalyst.

Preheater 431 65a390-850

Hydrotreating Less severe than hydrodesulfurization. Removes

metals, nitrogen, and sulfur from lighter

feedstocks. Hydrogen is added and reacted over a

catalyst.

Preheater 497 75b600-800

Hydroconversion

Alkylation Combination of two hydrocarbons to produce a

higher molecular weight hydrocarbon. Heater

used on the fractionator.

Reboiler 2,500 377c400

Catalytic

reforming

Low-octane napthas are converted to high-octane,

aromatic napthas. Feedstock is contacted with

hydrogen over a catalyst.

Preheater 1,790 270 850-1,000

Heavy gas oils and middle distillates. a

Light distillate. b

Btu/bbl of total alylate. c
3-21

 gives a more detailed breakdown of these operations. The total

annual energy consumption for process heaters in 1973 for the

petroleum refining industry was 2.0 x 10 Btu/yr, and in 1985 it 15

increased to 2.2 x 10 Btu/yr. Because the most current 15 23

information found was 1985 data, a growth projection was

calculated based on the latest trends. Assuming a linear growth

extrapolation (i.e., same slope as that of the 1973 to

1985 data), annual energy consumption for 1991 was estimated to

be 2.3 x 10 Btu/yr. Figure 3-5 15
3-22

Figure 3-5. Annual energy consumption projection for process

heaters used in petroleum refining.23
3-23

displays the growth estimate for the petroleum refining industry

energy consumption, based on the 1985 information.
3-24
3-25
3-26

The known energy requirement of the major chemical industry

fired heater applications in 1985 was 6.5 x 10 Btu/yr and is 14

shown in Table 3-3
3-27

TABLE 3-3. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER APPLICATIONS IN THE

CHEMICAL INDUSTRY24

Chemical Process Heater type Firebox temperature ( EF)

1985 fired heater energy

requirement,

10 Btu/yr 12

% of known chemical

industry heater

requirements

Low- and medium-temperature applications

Benzene Reformate extraction Reboiler 700 64.8 9.9Styrene Ethylbenzene

dehydrogenation

Steam superheater 1,500 - 1,600 32.1 4.9

Vinyl chloride monomer Ethylene dichloride

cracking

Cracking furnace N/A 12.6 1.9

P-Xylene Xylene isomerization Reactor fired preheater N/A 13.0 2.0Dimethyl terephthalate

Reaction of p-xylene andmethanol

Preheater, hot oil furnace

480 - 540 11.1 1.7

Butadiene

Butylenedehydrogenation Preheater, reboiler 1,100 2.6 0.4

Ethanol (synthetic) Ethylene hydration Preheater 750 1.3 0.2Acetone Various Hot oil furnace N/A 0.8 0.1Others See Table 3-7

High-temperature applications

Ethylene/propylene Thermal cracking Pyrolysis furnace 1,900 - 2,300 337.9 51.8Ammonia Natural gas reforming Steam hydrocarbon

reformer

1,500 - 1,600 150.5 23.1

Methanol Hydrocarbon reforming Steam hydrocarbon 1,000 - 2,000 25.7 4.0TOTAL KNOWN FIRED HEATER ENERGY REQUIREMENT 652.4 100
3-28

. As discussed earlier, the estimated energy requirement for 3

1985 was 6.8 x 10 Btu/yr. Thirty organic and seven inorganic 14 21

operations require process heaters in the chemical manufacturing

industry. Table 3-4 3
3-29

TABLE 3-4. REPORTED APPLICATIONS OF FIRED HEATERS

IN THE CHEMICAL MANUFACTURING INDUSTRY25

Category Applications

Organic chemicals manufacturing Acetone, acetic anhydride, acetylene, acrylic acids, alkyl benzene, allyl

chloride, amines, ammonia, benzenes, benzoic acid and other aromatic

acids, biphenyl, butadiene, chlorinated hydrocarbon solvents, cumene,

cyclohexane, dimethyl terephthalate, diphenylamine, esters, ethanol and

higher alcohols, ethylbenzene/styrene, ethylene/propylene, fatty acids,

formaldehyde, ketone, maleic anhydride, methanol, methyl ethyl ketone,

methylene dianiline, neo acids, phthalic anhydride, polyethylene,

polyvinyl chloride, pyridine, salicyclic acid, toluene diamine, toluene

dissocyanate, xylene

Inorganic chemicals manufacturing Carbon bisulfite, carbon disulfide, carbon monoxide, caustic soda,

hydrogen, silicones, sulfur chloride

Others Additives, agricultural products, asphalt, carbon black, elastomers,

fabrics, finishes, pharmaceuticals photo products, pigments, plasticizers,

polyamide adhesives, synthetic fibers
3-30

lists these operations. On the basis of process requirements,

fired heater applications in the chemical industry can be broadly

classified into two categories: low- and medium-fireboxtemperature applications, such as feed preheaters, reboilers, and

steam superheaters; and high firebox temperature applications,

such as olefins pyrolysis furnaces and steam-hydrocarbon

reformers. Low- and medium-firebox temperature heaters represent

approximately 20 percent of the chemical industry heater

requirements and are similar to those found in the petroleum

refining industry. High-firebox-temperature heaters represent 3

approximately 80 percent of the chemical industry heater

requirements and are unique to the chemical industry.

High-temperature pyrolysis fired heater applications

represent approximately 50 percent of the chemical industry

heater requirements. Gaseous hydrocarbons such as ethane,

propane, and butane and heavier hydrocarbons such as naptha

feedstocks are thermally converted to olefins such as ethylene

and propylene. The following are basic criteria for pyrolysis: 

adequate control of heat flux from inlet to outlet of the tubes,

high heat transfer rates at high temperatures, short residence

times, and uniform temperature distribution along the tube

length. The firebox temperatures for pyrolysis furnaces range

from 1050E to 1250EC (1900E to 2300EF).3,6

Steam-hydrocarbon reformers represent approximately

27 percent of the chemical industry heaters requirements. The

function of these furnaces is to reform natural gas or other

hydrocarbons with steam to produce hydrogen and carbon monoxide. 

The reforming reactions are not favored by conditions below 590EC

(1100EF) and proceed more favorably as the temperature increases. 
3-31
3-32

The firebox temperature of steam-hydrocarbon reformers ranges

from about 980E to 1100EC (1800E to 2000EF).21

3.3 REFERENCES FOR CHAPTER 3

 1. Shareef, S.A., C.L. Anderson, and L.E. Keller (Radian

Corporation). Fired Heaters: Nitrogen Oxides Emissions and

Controls. Prepared for the U. S. Environmental Protection

Agency. Research Triangle Park, NC. EPA Contract

No. 68-02-4286. June 1988. pp. 9-10.

 2. Reference 1, p. 25.

 3. Reference 1, p. 32.

 4. Reference 1, pp. 10-12.

 5. Control Techniques for NO Emissions from Stationary x

Sources--Revised Second Edition. U. S. Environmental

Protection Agency. Research Triangle Park, NC. Publication

No. EPA-450/3-83-002. January 1983. p. 5-33.

 6. Letter and attachments from Eichamer, P., Exxon Chemical

Company, to Neuffer, W., EPA/ISB. September 2, 1992. 

Comments on draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

 7. Reference 5, p. 5-35.

 8. Reference 1, p. 14.

 9. Reference 5, pp. 5-35 through 5-36.

10. Reference 1, p. 13.

11. Reference 1, p. 16.

12. Reference 1, p. 18.

13. Reference 5, p. 5-38.

14. Reference 1, p. 17.

15. Reference 1, p. 19.

16. Reference 1, pp. 19-20.

17. Thrash, L.A. Annual Refining Survey. Oil and Gas Journal. 

March 18, 1991. pp. 86-105.

18. Reference 1, p. 31.

19. Reference 1, p. 22.
3-33

20. Cherry, S.S., and S.C. Hunter (KVB-A Research-Cottrell

Company). Cost and Cost-Effectiveness of NO Control in x

Petroleum Industry Operations. Prepared for the American

Petroleum Institute. Washington, D.C. API Publication

No. 4331. October 1980. pp. 2-68 through 2-73.

21. Reference 1, p. 36.

22. Reference 1, p. 28.

23. Letter from Crockett, B.P., American Petroleum Institute, to

Crowder, J.U., EPA/ISB. July 23, 1984. Review of

Chapters 3 through 6 of NSPS BID draft. 

24. Reference 1, p. 34.

25. Reference 1, p. 33.
3-34
4-1

SIONS

4.0 CHARACTERIZATION OF NOx EMIS

A discussion of uncontrolled NOx emissions from process

heaters used in the petroleum refining and chemical industries is

presented in this chapter. Thermal, fuel, and prompt NOx

formation mechanisms are described in Section 4.1. A discussion

of the factors that affect uncontrolled NOx emissions is

presented in Section 4.2. Uncontrolled NOx emission factors and

model heaters are presented in Section 4.3. Finally, Section 4.4

lists the references cited in this chapter. 

4.1 FORMATION OF NOx

Seven oxides of nitrogen are known to occur naturally. Only

two, NO and NO2, are considered important in atmospheric

pollution. In this document, NO and NO2 are referred to as

"NOx ." This section presents a discussion of NOx formation

mechanisms that result from fuel combustion. Thermal, fuel, and

prompt NOx formation mechanisms are described in Sections 4.1.1,

4.1.2, and 4.1.3, respectively.

4.1.1 Thermal NOx Formation

Thermal NOx results from the thermal fixation of molecular

nitrogen and oxygen present in the combustion air. The rate of

thermal fixation increases rapidly at temperatures exceeding

1540EC (2800EF) and is more sensitive to local flame temperatures

than oxygen concentrations. Formation of thermal NO is 1

x

greatest in regions where the highest local flame temperatures

occur. The thermal NO formation mechanism is commonly 2

x

described using the Zeldovich mechanism, which is described by

the following simplified reactions:3
4-2

N2 + 0 o NO + N (Reaction 1)

N + O2 o NO + O (Reaction 2)

Reaction 1 has a high activation energy, indicating the high

temperatures necessary for NOx formation. At high combustion 4

temperatures, dissociation of molecular oxygen occurs, allowing

Reaction 1 to proceed. Reaction 1 describes molecular nitrogen

combining with atomic oxygen to produce NO and is much slower

than Reaction 2, which describes the combination of atomic

nitrogen with molecular oxygen. Therefore, Reaction 1 controls

the rate of formation of NO. The formation of an NO molecule

from Reaction 1 results in the release of an N atom, which

rapidly forms another NO molecule by the process described in

Reaction 2.5

The rate of thermal NOx formation is also described by the

Zeldovich mechanism in the following simplified equation:1,2

[NO] = k1 exp (-k2/T)[N2][O2] t 1/2

where:

[ ] = mole fraction;

k1, k2 = constants;

T = peak flame temperature (EK); and

t = residence time of reactants at peak flame

temperature.

The equation shows that the formation rate of thermal NOx

increases exponentially with increasing flame temperature and is

also directly proportional to residence time in the peak flame

zone. The key parameters of thermal NOx formation are defined by

this equation as temperature, oxygen and nitrogen concentrations,

and residence time in the flame zone. Variables that affect 1

these three parameters are discussed in Section 4.2. Figure 4-1
4-3

Figure 4-1. Impact of temperature on NOx formation.4
4-4

 shows the sensitivity of NOx formation to temperature. Note

that for an increase in temperature of less than 55EC (130EF),

the concentration of NOx increases by one order of magnitude. 

4
4-5
4-6

4.1.2 Fuel NOx Formation

The role of fuel-bound nitrogen as a source of NOx emissions

from combustion sources was recognized in 1968. Fuel NOx is the

result of the reactions between fuel-bound nitrogen and oxygen in

the combustion air. The bond in liquid and solid fuels between

individual nitrogen atoms and other atoms, such as carbon, is not

as strong as the N / N bond found in molecular nitrogen. In the

combustion process, organically bound nitrogen atoms contained in

the fuel are released and are rapidly oxidized to NO. 

5

The mechanisms by which chemically bound fuel nitrogen

compounds are converted to NOx emissions are not yet fully

understood. Several studies, however, indicate that two 6

separate mechanisms exist by which fuel-bound nitrogen compounds

react to form NOx. The first, involving volatiles from solid or

liquid fuels, is a gas-phase reaction. The second, involving

solid fuels, is a solid-phase char reaction.7

Intermediate species, such as HCN, HOCN, and NH2, are

postulated to be involved in gas-phase reactions. Gas-phase

reactions are strongly dependent on the stoichiometry and weakly

dependent on the local flame temperature. 

7

Char nitrogen reactions appear to depend more on flame

temperature and less on stoichiometry. The physical and chemical

characteristics of the char also influence the reaction rate.7

The available data indicate that the conversion of fuel-bound

nitrogen to NOx emissions ranges from 15 to 100 percent. 

Typically, fuels with relatively low nitrogen contents have

higher nitrogen to NOx conversion rates than fuels with high

nitrogen content, such as residual oils. However, the total

quantity of nitrogen conversion is greater with high-nitrogencontent fuels, although the conversion percentage is lower. For

example, 20 percent conversion of the nitrogen in a fuel with a

nitrogen content of 1 percent by weight yields a greater quantity

of NOx than 80 percent conversion of the nitrogen in a fuel with

a nitrogen content of 0.1 percent by weight. Figure 4-2
4-7

Figure 4-2. Effect of fuel-bound nitrogen on NOx emissions.1
4-8

 shows the increase in NOx emissions due to the increase in

nitrogen content of the fuel.1
4-9

4.1.3 Prompt NOx Formation

Prompt NOx is a newly recognized mechanism of NOx formation. 

Prompt NOx formation increases in rich combustion conditions when

fuels containing nitrogen are burned. Formation depends not on

the fuel-bound nitrogen content but instead on the condition of

the flame and tends to occur in rich zones in the flame front.7

Prompt NOx formation becomes an important consideration when

emission levels are 20 to 30 ppmv or below. Oxygen availability

is another important factor; high levels of excess air can reduce

prompt NOx formation. However, high excess air levels can also

reduce fuel efficiency.8

Similar to gas-phase fuel NOx formation, prompt NOx is

formed from products of intermediate reactions. The following

equations describe intermediate reactions and the oxidation of

the products:

1. CH + N2 )6 HCN + N;

2. CH2 + N2 )6 HCN + NH;

3. HCN + Ox )6 NO + ...;

4. N + Ox )6 NO + ...; and

5. NH + Ox )6 NO + ... .

where Ox indicates oxides such as O or O2.

9,10

4.2 FACTORS AFFECTING UNCONTROLLED NOx EMISSIONS 

Many factors affect the level of uncontrolled NOx emissions

from process heaters. Those factors can be categorized broadly

under two headings: heater design parameters and heater

operation parameters. Section 4.2.1 describes the heater design

parameters that affect uncontrolled NOx emissions. Section 4.2.2

describes heater operation parameters that affect uncontrolled

NOx emissions.

4.2.1 Heater Design Parameters

Heater design parameters that affect the level of

uncontrolled NOx emissions from process heaters include the 
4-10

following: (1) fuel type, (2) burner type, (3) combustion air

preheat, (4) firebox temperature, and (5) draft type.11

4.2.1.1 Fuel Type. Typically, process heaters burn liquid

or gaseous fossil fuels. Liquid fuels burned include liquid

butanes and pentanes, light fuel oils such as diesel and No. 2

distillate oil, and heavy fuel oils such as No. 6 residual oil. 

Gas fuels, such as hydrogen, methane, ethane, propane, and

butane, are burned individually or in a variety of blends.12

Natural gas and refinery fuel gas consist primarily of methane

and are common fuels for process heaters. Any number of the

previously mentioned gas fuels makes up the balance of components

in natural and refinery fuel gas.

Research indicates that combustion of low-nitrogen

distillate oil produces uncontrolled NOx emissions higher than

does the combustion of natural gas at identical conditions of

heat release rate, excess air, and combustion air preheat.11

Although some refinery gases may have trace amounts of HCN, NH3,

or other nitrogen-bearing species that may be oxidized to NOx,

natural gas and refinery gas usually do not contain chemically

bound nitrogen. Therefore, process heaters burning oil can be

expected to produce higher NOx emissions per unit of energy

absorbed than do comparable heaters burning natural gas, due to

higher combustion temperatures and the greater formation of fuel

NOx, which accompanies the combustion of fuel oils.11

Fuel NOx formation represents a greater fraction of the

total NOx when high-nitrogen fuels such as residual oil are

combusted. Therefore, fuel type has a large effect on the

magnitude of NOx emissions from a combustion source.1

When refinery gas is fired, variations in hydrogen content

can cause changes in the combustion characteristics of the fuel. 

The hydrogen content of refinery fuel gas fired in low- and

medium-temperature process heaters can vary from 0 to 50 percent. 

This variation in hydrogen content results in heating values

ranging from 2.6 x 10 to 8.2 x 10 Joules per cubic meter (J/m )

7 7 3

(700 to 2,200 British thermal units per standard cubic feet

[Btu/scf]). High hydrogen fuel gas, which contains up to
4-11

80 percent hydrogen; is primarily fired in high-temperature

heaters such as pyrolysis furnaces. High hydrogen fuel gas

containing 50 to 80 mole percent hydrogen can have heating values

ranging from 1.48 x 10 to 2.22 x 10 J/m (400 to 600 Btu/scf). 7 7 3

These variations in hydrogen content cause changes in flame

temperature, propagation, and flame volume. Increased hydrogen

content of the fuel produces a hotter flame, resulting in greater

thermal NOx formation. One source reports that for a heater

fired with fuel gas containing 50 percent or more hydrogen, NOx

emissions can increase 20 to 50 percent over the same heater

fired with natural gas.13

The proportions of oil and gas burned in a dual-fuel process

heater affect NOx emissions. As stated earlier, under the same

conditions, burners firing low-nitrogen distillate oil generate

higher NOx emissions than do similar burners firing natural gas. 

Consequently, NOx emissions from oil/gas-fired heaters vary

depending on the amount and type of oil that is mixed with the

gas because NOx emissions increase with increasing oil content.14

4.2.1.2 Burner Type. The type of burner used in a process

heater also has an impact on NOx emissions. The functions of a

burner are to ensure (1) proper mixing of combustion reactants,

(2) a continuous supply of combustion reactants, and (3) proper

heat dispersion by regulating the size and shape of the flame

envelope. Because NO formation is affected by the flame 15

x

temperature, mixing of the reactants, and the residence time of

the reactants at the peak flame temperature, burner design

clearly affects the level of uncontrolled NOx emissions. 

Burners are designed to fire specific fuels, and the fuel

type greatly affects the magnitude of NOx emissions from a

combustion source. Oil-fired heaters generate higher NOx

emissions per unit of energy input than do comparable gas-fired

heaters. Most fired heaters, until recently, have used burners 11

capable of firing oil or gas. However, the current trend is to 11

use gas-only burners to reduce the initial investment.16

Burners can be divided into conventional and low-NOx

burners. Conventional burners are designed for high combustion
4-12

efficiency and low hydrocarbon (HC) and carbon monoxide (CO)

emissions. Low-NOx burners are designed for low-NOx operation,

while maintaining low HC and CO emissions and high fuel

efficiency.

Conventional gas-fired burners are divided into three

categories: raw gas burners, premix burners, and high-intensity

burners. Raw gas burners receive fuel gas from the gas manifold

without any premixing of combustion air. Premix burners receive

a mixture of combustion air and fuel at the burner tip. Highintensity gas-fired burners are usually designed to fire low-Btu

fuel gas that is unsuitable for low- and medium-temperature

conventional burners. High-intensity burners are characterized

by extremely compact flames and low-excess-air operation. 

17

Gas burners designed for low-NOx operation usually use

staging techniques to reduce NOx emissions and are divided into

two categories: staged-air burners and staged-fuel burners. 

Staged-air, gas-fired burners divide the combustion zone into two

stages. The burner bypasses a fraction of the combustion air

around the primary combustion zone and supplies it to the

secondary combustion zone. The primary zone is operated under

rich combustion conditions, and the secondary combustion zone is

operated under lean combustion conditions. The primary zone

creates a reducing environment, which inhibits fuel-NOx

formation. The combustion reaction is cooled in the secondary

zone by the secondary air, which inhibits thermal-NOx formation. 

Staged-air, gas-fired burners may also supply tertiary air

around the outside of the secondary combustion zone, which

ensures complete combustion at relatively low combustion

temperatures. Staged-fuel, gas-fired burners divide the

combustion zone into two stages. The burner bypasses a fraction

of the fuel around the primary combustion zone and supplies it to

the secondary combustion zone. The primary zone is operated

under lean combustion conditions, and the secondary zone is

operated under rich conditions. The lean primary zone has a

relatively cool combustion temperature, which inhibits thermal
4-13

NOx formation. Limited oxygen availability in the rich secondary

zone further inhibits NOx formation.14

A relatively new type of premix burner uses a porous surface

of ceramic or metallic fibers to burn gas fuels. These burners

require forced draft combustion air supply. The combustion

reactions are located on the outer surface of radiant burners. 

The outer surface of the burners glows uniformly instead of the

flame extending outward from the burner tip, as in nonradiant

burners. Flame stability and the absence of flame impingement

are two operational advantages. Combustion occurs at

approximately 1000EC (1830EF), which yields low NOx formation

while producing low CO and HC emissions.18

There are two categories of oil burners: conventional oil

burners and staged-air, oil-fired burners. Conventional oil

burners have a single combustion zone, while staged-air oil-fired

burners have at least two combustion zones. The staged-air, 9

oil-fired burners are designed to achieve lower NOx emissions

than the conventional burners and operate similarly to the

staged-air gas-fired burners.19

4.2.1.3 Combustion Air Preheat. A fuel-efficient process

heater design is a priority consideration for heater users.

Combustion air preheat is an effective method of reducing fuel

consumption. However, preheating the combustion air increases

the flame temperature of the burner, which results in greater NOx

formation (Section 4.1.1). Tests show that the higher the 9

temperature of air preheat, the greater the formation of NOx. 

Figure 4-3
4-14

Figure 4-3. Effect of combustion air preheat temperature on NOx

emissions.15
4-15

 shows the effect of combustion air preheat on NOx emissions from

a test-scale, mechanical draft (MD) heater. Preheating the 15

combustion air temperature from ambient (21EC [70EF]) to 204EC

(400EF) increases NOx emissions by a factor of 1.4 and more than

doubles emissions when the air is preheated to 316EC (600EF).13

4.2.1.4 Firebox Temperature. As discussed in

Section 4.1.1, the rate of formation of thermal NOx increases

exponentially with increasing flame temperature. The flame

temperature is directly related to the firebox temperature, which 
4-16

is determined by the process requirements. Therefore, 9

applications requiring high firebox temperatures, such as steam

hydrocarbon reformers and olefins pyrolysis furnaces, will likely

have higher NOx emissions than applications using medium and low

firebox temperatures. In general, heaters with high volumetric 9

heat release rates have high flame and firebox temperatures. 

Figure 4-4
4-17

Figure 4-4. Effect of firebox temperature on thermal NOx

formation for gas-fired heaters with constant excess air.11
4-18

 shows the relationship between firebox temperature and thermal

NOx formation. This figure shows that for gas-fired heaters,

thermal NOx emissions increase by a factor of about 1.5 when the

firebox temperature is increased from 700EC (1300EF) to 1040EC

(1900EF). One source reports that below 1100EC (2100EF) thermal 15

NOx increases a nominal 10 percent for every 40EC (100EF)

increase in firebox temperature, which is consistent with the

above data. The same source reports that increasing the 16

temperature from 700E to 1000EC (1300E to 1900EF) can increase

thermal NOx formation by as much as a factor of 4 in some process

heaters. However, recent information indicates the rate of

thermal NOx formation at temperatures above 930EC (1700EF)

continues to increase, contrary to the trend shown by the

curve. The effect of increased firebox temperature on fuel NO 20

x

from oil-fired heaters is expected to be less than that described

above for gas-fired heaters because, fuel NOx formation is less

sensitive to temperature than thermal NOx formation.9

4.2.1.5 Draft Type. As discussed in Section 3.1.3.2, the

two basic methods for combustion air supply for process heaters

are natural draft (ND) and MD. These MD systems can be further

divided into three categories: forced draft, induced draft, and

balanced draft. The three types are distinguished by the

position of the fan(s) relative to the heater unit. The fan is

located upstream of the firebox in the forced draft heater and

downstream of the firebox in the induced draft heater. Balanced

draft heaters use both forced and induced draft fans to control

the combustion airflow. Balanced draft is more often used for

boilers than for process heaters. Boilers may operate with

radiant firebox pressures of +20 inches of water (in. H2O), but

process heaters operate with radiant firebox pressures slightly 
4-19

below ambient pressure. Process heater construction does not

tolerate large variations in firebox pressures like those in

boilers. In ND heaters, the pressure difference between the 16

hot gases in the stack and the cooler air outside results in a

"draft," which causes the combustion air to flow into the

burners. Draft type can influence uncontrolled NOx emissions by

affecting the level of excess air in the combustion zone. 

Additionally, NOx emissions can be lowered by converting the

heater to forced draft and operating with lower excess air and

improved flame shape.21

4.2.2 Heater Operating Parameters

This section describes the operating parameters that, in

addition to the design parameters, affect the level of

uncontrolled NOx emissions from process heaters. These operating

parameters include (1) excess air, (2) volumetric heat release,

and (3) burner adjustments.12-14

4.2.2.1 Excess Air. Excess air is required to ensure

complete combustion of fuel in the burner. Optimum fuel

efficiency and low HC, CO, and NOx emissions can be achieved only

over a small range of excess air levels. A typical excess air

level for a process heater is approximately 15 percent. The

amount of excess air present depends on a variety of factors

including fuel type, draft type, burner design, and air leaks.1,14

The excess air level should be measured at the burner or in the

radiant zone because air leakage above the radiant section may

indicate higher excess air levels in the stack than exist in the

burner combustion zone. The term "excess oxygen" is sometimes 16

used instead of "excess air." Three percent excess oxygen

corresponds to approximately 15 percent excess air. 

16

A statistical analysis of long-term continuous emissions

data on gas-fired heaters at petroleum refineries showed that NOx

emissions typically increase about 9 percent for each 1 percent

increase in the measured stack oxygen level. The data base for

this analysis includes a range of 540 to 3,400 hourly NOx

emission data points for each heater. The effect of excess air 14

on NOx formation in gas-fired heaters using these data is shown
4-20

in Figure 4-5. Another source reports a NOx emissions increase
4-21

Figure 4-5. Effect of excess air on NOx formation in gas-fired

process heaters at various combustion air preheat temperatures.22
4-22

of 6 percent for every 1 percent increase in excess oxygen.16

Increasing the excess air will result in greater NOx emissions

until the oxygen content of the flue gas reaches approximately

6 percent, at which point NOx formation begins to decrease. This

decrease can be attributed to the flame cooling effect of the

excess air, which reduces the formation of thermal NOx. One 2

source indicates that increased fuel firing is generally required

when excess oxygen levels are above 6 percent as a result of

decreased fuel efficiency. However, radiant burners are 16

reported to be capable of minimizing HC, CO, and NOx emissions

without sacrificing fuel efficiency, even with excess air levels

of 10 to 20 percent.8

4.2.2.2 Burner Adjustments. Burner adjustments can affect

NOx emissions by altering the flame characteristics. By

adjusting the burner to increase flame length, the peak flame

temperature is decreased, thereby decreasing NOx formation.13

Some heaters require a more uniform heat flux produced by welldefined, compact flames. This type of high-intensity flame

produces higher NOx levels than the long, low-intensity flame.12,13

For heaters equipped with staged-air burners, the relative

amount of air introduced into the primary and secondary burner

combustion zones can have a large effect on NOx emissions. Tests

indicate that combustion air distribution can be adjusted to

minimize NOx emissions from the heater. However, burner 13

adjustments or settings are generally dictated by process

requirements and may not coincide with optimum NOx control.16

4.3 UNCONTROLLED NOx EMISSION FACTORS AND MODEL HEATERS

Uncontrolled NOx emission rates were available from several

sources. These sources include AP-42 (Compilation of Air

Pollutant Emission Factors, fourth edition, October 1986),

American Petroleum Institute (API) publications, and an emission

inventory from process heater installations. Several factors

affect the uncontrolled emission rates, as mentioned in Section

4.2. The NOx emission factors predicted by these publications 
4-23
4-24

vary as a result of these factors. Because of the variability in

published uncontrolled NOx emission factors, a model heater

approach is used in this chapter in order to compare the

uncontrolled NOx emissions for the different types of heaters. 

These same model heaters are also used in Chapters 5 and 6 in

order to evaluate the NOx emission control techniques and the

cost effectiveness of available NOx emission control techniques. 

Uncontrolled NOx emission factors are presented in Section 4.3.1. 

The model heaters and corresponding uncontrolled emission factors

are presented in Section 4.3.2.

4.3.1 Uncontrolled NOx Emissions

AP-42 provides uncontrolled emission factors for process

heaters and boilers classified by the heat input rate, using the

higher heating value for the type of fuel burned. These 23

emission factors, shown in Table 4-1,
4-25

TABLE 4-1. AP-42 ESTIMATES FOR UNCONTROLLED NOX EMISSIONS

FROM BOILERS AND PROCESS HEATERS23

NOx emission factor

Heat rate,

MMBtu/hr Fuel ng/Ja lb/MMBtu

<10 Natural gas 41 0.10

10-100 Natural gas 58 0.14

>100 Natural gas 228 0.53

<10 Distillate oilb 63 0.15

Residual oilc 162 0.38

10-100 Distillate oilb 63 0.15

Residual oilc 162 0.38

>100 Residual oilc 197 0.46

ng/J = nanogram per Joule a

Distillate oils include Nos. 1 and 2 fuel oils. b

Residual oils include Nos. 4, 5, and 6 fuel oils. c
4-26

 are based on test data for boilers. Three ranges of heat rates

were defined for gas-fired units, two ranges of heat rates were

defined for distillate oil-fired units, and three ranges of heat

rates were defined for residual oil-fired units. Uncontrolled

NOx emission factors were reported for each of the ranges of heat

rates for each fuel.

Average emission factors for natural gas-, distillate oil-,

and residual oil-fired operation for ND and MD refinery heaters

were developed in a 1979 API-sponsored study. Figure 4-6 24
4-27

Figure 4-6. Uncontrolled NOx emission data versus heat input for

gas-fired refinery process heaters of various design types.24
4-28

 presents uncontrolled NOx emission factors versus heat input

developed from API data. The burner configuration, draft type,

and air preheat conditions were not reported for all of the

process heaters in the test. Figure 4-7
4-29

Figure 4-7. Uncontrolled NOx emission factors for gas-fired

refinery process heaters with known burner configuration, draft

type, and air preheat conditions.
4-30

 shows the NOx emission factors versus heat input for the gasfired process heaters with known burner configuration, draft

type, and preheat conditions. These figures illustrate that NOx

emissions are not related solely to heat input. In addition, the

increased NOx emissions resulting from using air preheaters by

the majority of MD units is reflected in the relatively high

emission factors for MD heaters shown in Figures 4-6 and 4-7.24

The uncontrolled NOx emissions for distillate and residual fuel

oils increase with 
4-31
4-32
4-33

increases in the nitrogen content of the fuel being burned as a

result of the formation of fuel NOx.

Uncontrolled NOx emission factors developed by averaging the

data shown in Figures 4-6 and 4-7 are presented in Table 4-2. 
4-34

TABLE 4-2. AVERAGE UNCONTROLLED NOx EMISSIONS FROM REFINERY

 PROCESS HEATERS BASED ON EMISSION DATA FROM API (lb/MMBtu) 24

Fuel Natural drafta Mechanical draftb

Gaseous 0.14 0.26

Distillate oilc 0.20 0.32

Residual oild 0.42 0.54

Using ambient combustion air. a

Using air preheated to 200EC (390EF), on average. b

Fuel nitrogen content of 0.04 percent. Fuel NO contributes c

x

0.06 lb/MMBtu to total uncontrolled emissions. 

Fuel nitrogen content of 0.29 percent. Fuel NO contributes d

x

0.28 lb/MMBtu to total uncontrolled emissions. 
4-35

 The emission factors in Table 4-2 for residual and distillate

oil were calculated from the emission factors for gas-firing with

adjustments for fuel nitrogen content based on information from

API Publication 4311. This table indicates that emissions are

not directly related to heat rate. The uncontrolled emission

factors in Table 4-2 are categorized by fuel and draft system. 

Uncontrolled emission factors were reported for gas-fired heaters

using ND without preheat, gas-fired heaters using MD with

preheat, distillate oil-fired heaters using ND without preheat,

distillate oil-fired heaters using MD with preheat, residual

oil-fired heaters using ND without preheat, residual oil-fired

heaters using MD with preheat. The emission factors increase 24

with increasing fuel-bound nitrogen content. The emission

factors for MD are higher than for ND because preheat was used in

the majority of the MD heaters. 

An emission inventory for gas-fired ND and MD process

heaters at a refinery installation is presented in Figure 4-8.25
4-36

Figure 4-8. Uncontrolled NOx emission rates for gas-fired

process heaters at one refinery installation.25
4-37

 This inventory, tabled in Appendix A, is considered to be

representative of the heat rates and emission rates for process

heaters installed in refinery and chemical manufacturing

applications. The MD heaters use air preheat and Figure 4-8

shows NOx emission rates are generally higher from MD heaters

compared to ND heaters. For both ND and MD heaters, emission

rates are largely insensitive to heater size. A summary of the

emission rates for the refinery process heater inventory is shown

in Table 4-3.
4-38

TABLE 4-3. AVERAGE UNCONTROLLED NOx EMISSIONS FROM PROCESS

HEATERS AT ONE REFINERY INSTALLATION25

Fuel

NOx emissions, lb/MMBtu

Natural drafta Mechanical draftb

No. of

heaters Range Average

No. of

heaters Range Average

Gaseous 32 .064 - .011 .098 26 .062 - .323 .197

Using ambient combustion air. a

Using air preheated to 310EC (595EF), on average. b
4-39

 The data presented in Table 4-3 are grouped by draft type, and

the average emission rates include both natural gas- and refinery

gas-fueled heaters. The average NOx emission rate is

0.098 lb/MMBtu for ND heaters and 0.197 lb/MMBtu for MD heaters. 

As discussed in Section 4.2.1.1, heaters firing refinery fuel gas

have higher NOx emissions rates than natural gas-fueled heaters. 
4-40
4-41
4-42

Pyrolysis furnaces, due to their high firebox temperatures

and combustion intensity, have relatively high uncontrolled NOx

emission rates. Two sources estimated from their operating

experience that uncontrolled NOx emissions range from

approximately 0.130 to 0.140 lb/MMBtu for natural gas-fired

furnaces. Limited data for natural gas-fired pyrolysis 26

furnaces was consistent with this range. Pyrolysis furnaces are

often fired with refinery gas, with hydrogen contents ranging to

50 mole percent or higher. According to one source, uncontrolled

NOx levels may be 20 to 50 percent higher when burning

high-hydrogen refinery gas fuel than the 0.130 to 0.140 lb/MMBtu

range for natural gas. A second source indicated that 27

controlled burner tests showed increases in uncontrolled NOx

emissions for high-hydrogen refinery gas fuel ranging from 15 to

20 percent over natural gas-fired emission levels. These 28

estimates indicate that uncontrolled NOx emission rates range

from 0.150 to 0.210 lb/MMBtu for high-hydrogen content refinery

gas firing; data were not available to verify this range.

4.3.2 Model Heaters

Five categories of model heaters were developed in this

study to represent process heaters that have similar uncontrolled

NOx emissions in the refinery and chemical industry. These

models were developed to take into account the variations in the

sizes, fuels, and draft systems that affect NOx emissions. The

five model heater categories are (1) natural gas-fired, low- and

medium-temperature ND without preheat; (2) natural gas-fired,

low- and medium-temperature MD with preheat; (3) oil-fired, lowand medium-temperature ND without preheat; (4) oil-fired, lowand medium temperature MD with preheat; and (5) ND without

preheat olefins pyrolysis heaters.

The natural gas-fired ND and MD, low- and medium-temperature

model heaters are based on the refinery process heater inventory

shown in Figure 4-8. The ND without preheat, natural gas-fired,

low- and medium-temperature model heaters are presented in

Table 4-4. 
4-43

TABLE 4-4. MODEL HEATERS AND UNCONTROLLED NOx EMISSION FACTORS: 

NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE ND 

WITHOUT PREHEAT25

Model heater

capacity,

MMBtu/hr

Size range,

MMBtu/hr

No. of

burners

Uncontrolled

NOx emission

factors,

lb/MMBtu

17 x < 20 4 0.098

36 20 < X < 50 7 0.098

77 50 < X < 100 8 0.098

121 100 < X < 150 19 0.098

185 150 < X 29 0.098

TABLE 4-5. MODEL HEATERS AND UNCONTROLLED NOx EMISSION FACTORS: 

NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE MD 

WITH PREHEAT25

Model heater

capacity,

MMBtu/hr

Size range,

MMBtu/hr No. of burners

Uncontrolled

NOx emission

factors,

lb/MMBtu

40 x < 50 6 0.197

77 50 < x < 100 16 0.197

114 100 < X < 150 34 0.197

174 150 < X < 200 31 0.197

263 200 < X 20 0.197
4-44

Figure 4-9. Natural draft process heater refinery inventory.25

Figure 4-9 presents a graphical representation of the heat rates
4-45

of the ND heaters in Figure 4-8. Several natural 
4-46
4-47

breaks tend to divide the heaters in Figure 4-9 into groups

according to heat rate and, therefore, model heaters were

developed to represent five heat rate ranges. Each model heater

represents the average size heater for the specified range of

heat rates. The heat rates of these five model heaters are 17,

36, 77, 121, and 185 MMBtu/hr. The uncontrolled emission factor

based on natural gas-firing for these model heaters is 0.098

lb/MMBtu, which is the average of the uncontrolled emission

factors for ND heaters as shown in Table 4-3. Typically, heaters

in this category fire natural gas or refinery fuel gas with less

than 50 mole percent hydrogen. As discussed in Section 4.2.1.1,

heaters firing refinery fuel gas with up to 50 mole percent

hydrogen can have up to 20 percent higher NOx emissions than the

same heater firing natural gas.16

The MD with preheat, natural gas-fired, low- and mediumtemperature model heaters are presented in Table 4-5. 

Figure 4-10
4-48

Figure 4-10. Mechanical draft process heater refinery

inventory.25
4-49

 presents a graphical representation of the heat rates of the MD

heaters in Figure 4-8. As is the case with ND heaters, several

natural breaks tend to divide the heaters into groups according

to heat rate and, therefore, five model heaters were developed to

represent heat rate ranges. Each model heater represents the

average size heater for the specified range of heat rates. The

heat rates of these five model heaters are 40, 77, 114, 174, and

263 MMBtu/hr. The uncontrolled emission factor based on natural

gas-firing for these model heaters is 0.197 lb/MMBtu, which is

the average of the uncontrolled emission factors for MD heaters

in Table 4-3. Typically, heaters in this category fire natural

gas or refinery fuel gas with less than 50 mole percent hydrogen. 

As discussed in Section 4.2.1.1, heaters firing refinery fuel gas

with up to 50 mole percent hydrogen can have up to 20 percent

higher NOx emissions than the same heater firing natural gas.16

A total of four low- and medium-temperature oil-fired model

heaters were developed. Two ND without preheat model heaters,

one distillate and one residual oil-fired, are presented in

Table 4-6. The capacity of each is 69 MMBtu/hr, which represents 
4-50

the average size of ND process heaters reported in an API

study. Two MD with preheat model heaters, one distillate and 24

one residual oil-fired, are presented in Table 4-7. The capacity

of each is 135 MMBtu/hr, which represents the average size of MD

process heaters with preheat reported in the API study. The

uncontrolled NOx emission factors for the oil-fired model heaters

were developed using Table 4-2. A thermal NOx and a fuel NOx

factor are presented in Tables 4-6 and 4-7
4-51

TABLE 4-6. MODEL HEATERS AND UNCONTROLLED EMISSION 

FACTORS: DISTILLATE AND RESIDUAL OIL-FIRED, LOWAND MEDIUM-TEMPERATURE ND WITHOUT PREHEAT24

Model heater

capacity, MMBtu/hr Fuel

No. of

burners

Uncontrolled NOx

emission factor,

lb/MMBtu

Thermal

NOx

Fuel NOx

69 Distillate oila 24 0.140 0.060

69 Residual oilb 24 0.140 0.280

0.04 percent N a

0.29 percent N b

TABLE 4-7. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS: 

DISTILLATE AND RESIDUAL OIL-FIRED, LOW- AND MEDIUMTEMPERATURE MD WITH PREHEAT24

Model heater

capacity, MMBtu/hr Fuel

No. of

burners

Uncontrolled NOx

emission factor,

lb/MMBtu

Thermal

NOx

Fuel NOx

135 Distillate oila 14 0.26 0.060

135 Residual oilb 14 0.26 0.280

0.04 percent N a

0.29 percent N b
4-52

 for each model heater and are not summed because each formation

mechanism is treated differently when considering achievable NOx

reductions for some control techniques. For the oil-fired ND

without preheat heaters the uncontrolled thermal NOx emission

factor is 0.140 lb/MMBtu for both distillate and residual oil

firing. Fuel NOx factors were calculated as the difference

between the uncontrolled NOx factors in Table 4-2 for gaseous and

oil fuels, and are 0.060 and 0.280 lb/MMBtu for distillate and

residual oil firing, respectively. For the oil-fired MD with

preheat heaters the uncontrolled thermal NOx emission factor is

0.260 lb/MMBtu for both distillate and residual oil firing. Fuel

NOx factors are 0.060 and 0.280 lb/MMBtu for distillate and

residual oil firing, respectively.
4-53

Table 4-8 
4-54

TABLE 4-8. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS:

NATURAL GAS-FIRED AND HIGH-HYDROGEN FUEL GAS-FIRED

OLEFINS PYROLYSIS FURNACES28

Model heater capacity,

MMBtu/hr Fuel

No. of

burners

Uncontrolled NOx

emission factor,

lb/MMBtu

84 Natural gas 24 0.135

84 High-hydrogen

fuel gas

24 0.162
4-55

presents two model heaters representing olefins pyrolysis

furnaces. The model pyrolysis heaters are an ND natural gasfired heater and a ND high hydrogen gas-fired heater with a heat

rate of 84 MMBtu/hr, without preheat. These models were

developed based on information and limited data from natural gasfired and high-hydrogen gas-fired pyrolysis furnace

installations, which are discussed in Section 4.3.1 The

uncontrolled NOx emission factor for the natural gas-fired model

pyrolysis furnace is 0.135 lb/MMBtu, which is the average of the

0.130 to 0.140 lb/MMBtu range discussed in Section 4.3.1. The

uncontrolled NOx emission factor for the high-hydrogen gas-fired

pyrolysis model furnace is 0.162 lb/MMBtu, which is 20 percent

higher than the natural gas-fired pyrolysis model furnace. 
4-56
4-57
4-58

4.4 REFERENCES FOR CHAPTER 4

 1. Shareef, S. A., C. L. Anderson, and L. E. Keller (Radian

Corporation). Fired Heaters: Nitrogen Oxides Emissions and

Controls. Prepared for U. S. Environmental Protection

Agency. Research Triangle Park, NC. EPA Contract

No. 68-02-4286. June 1988. pp. 42-48.

 2. Control Techniques for NOx Emissions from Stationary

Sources - Revised Second Edition. U. S. Environmental

Protection Agency. Research Triangle Park, NC. Publication

No. EPA-450/3-83-002. January 1983. p. 2-1.

 3. Standard Support and Environmental Impact Statement

Volume 2: Proposed Standards of Performance for Stationary

Gas Turbines. U. S. Environmental Protection Agency. 

Research Triangle Park, NC. Publication

No. EPA-450/2-77-017a. September 1977. pp. 3-71 to 3-73.

 4. Letter from Nichols, K., Chemical Recovery Group, to

Safriet, D., EPA/ISB. January 9, 1992. NOx emissions from

recovery furnaces.

 5. Newman, C. R. (GCA Corporation). Assessment of NOx Emission

Factors For Direct-Fired Heaters. Prepared for U. S.

Environmental Protection Agency. Research Triangle Park,

NC. EPA Contract No. 68-02-2693. January 1984. pp. 16-19.

 6. Reference 2, p. 3-4.

 7. Campbell, L. M., D. K. Stone, and G. S. Shareef (Radian

Corporation). Sourcebook: NOx Control Technology Data. 

Prepared for U. S. Environmental Protection Agency. 

Research Triangle Park, NC. EPA-600/2-91-029. July 1991.

 8. Letter and attachments from Pam, R., Alzeta Corporation, to

Neuffer, W., EPA/ISB. September 2, 1992. Comments on Draft

Alternative Control Techniques Document--Control of NOx

Emissions from Process Heaters.

 9. Reference 7, p. 5.

10. Malte, P. C. Perspective on NOx Formation and Control for

Gas Turbine Engines. University of Washington (Seattle, WA)

and Energy International (Bellevue, WA). Presented at

General Electric Research Center. Schenectady, NY. 

October 10, 1988. 46 pp.

11. Reference 1, pp. 48-52.

12. Martin, R. R. Burner Design Parameters for Flue Gas NOx

Control. John Zink Company. Tulsa, Oklahoma. Undated. 

39 pp.
4-59

13. Reference 5, p. 20.

14. Reference 1, pp. 57-59.

15. Reference 1, pp. 53-56.

16. Letter and attachments from Eichamer, P., Exxon Chemical

Company, to Neuffer, W., EPA/ISB. September 2, 1992. 

Comments on Draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

17. Reference 1, pp. 18-19.

18. Letter and attachments from Pam, R., Alzeta Corporation, to

Lyons, J., MRI. February 26, 1992. Alzeta product

literature.

19. Energy Section, Strategy Assessment Branch, Stationary

Source Division Air resources Board and Rule Development

Division, South Coast Air Quality Management District. A

Suggested Control Measure for the Control of Emissions of

Oxides of Nitrogen from Industrial, Institutional, and

Commercial Boilers, Steam Generators and Process Heaters. 

Prepared for the Statewide Technical Review Group. 

Sacramento, CA. April 29, 1987. p. 51.

20. Letter and attachments from Martin, R., Aztec Environmental

and Combustion Engineers, to Neuffer, W., EPA/ISB. 

January 26, 1993. Comments on Draft Alternative Control

Techniques Document--Control of NOx Emissions from Process

Heaters.

21. Padgett Process Services Ltd. A Study to Assess the

Available Technology and Associated Costs of Reducing NOx

Emissions from the Canadian Petroleum Refining Industry. 

Prepared for Canadian Petroleum Products Institute. 

Toronto, Canada. CPPI Report No. 91-1. November 28, 1990. 

p. 56.

22. Reference 1, p. 44.

23. Compilation of Air Pollutant Emission Factors Volume 1: 

Stationary Point and Area Sources, Fourth Edition (AP-42). 

U. S. Environmental Protection Agency. Research Triangle

Park, NC. October 1986. pp. 1.3-2, 1.4-2. 

24. Hunter, S. C., and S. S. Cherry (KVB-A Research-Cottrell

Company). NOx Emissions from Petroleum Industry Operations. 

Prepared for the American Petroleum Institute. Washington,

D.C. API Publication No. 4331. October 1979. pp. 27-30.

25. Letter and attachments from Davis, L., Exxon Company U.S.A.,

to Harris, R., MRI. February 7, 1992. Process heater

inventory of the Baton Rouge refinery.
4-60

26. Letter from Eichamer, P. D., and N. L. Morrow, Exxon

Chemical Company, to Neuffer, W. J., EPA/ISB. June 7, 1993. 

Pyrolysis furnace NOx emission rates.

27. Letter from Moran, E. J., Chemical Manufacturers

Association, to Neuffer, W. J., EPA/ISB. July 22, 1993. 

Pyrolysis furnace NOx emission rates.

28. Letter from Eichamer, P. D., and N. L. Morrow, Exxon

Chemical Company, to Neuffer, W. J., EPA/ISB. July 19,

1993. Pyrolysis furnace NOx emission rates.
5..0 NOx CONTROL TECHNIQUES

In this chapter, NOx control techniques for process heaters

are discussed. Nitrogen oxides control techniques for process

heaters can be categorized as either combustion controls or

postcombustion controls. Section 5.1 describes combustion

controls. Sections 5.2 and 5.3 address postcombustion controls. 

Pyrolysis furnaces, which consume a large portion of the energy

used in basic chemical plants, operate at much higher

temperatures than other process heaters and are a special

consideration. Pyrolysis furnaces are discussed separately in

Section 5.4. Section 5.5 presents a summary of the achievable

emission reductions for NOx control techniques as applied to

model process heaters. References for Chapter 5 are presented in

Section 5.6. 

a. COMBUSTION CONTROLS

As discussed in Chapter 4, the main factors contributing to

NOx formation include combustion temperature, available oxygen,

and fuel nitrogen content. Combustion modifications attempt to

reduce NOx formation by controlling the first two factors. 

Control of excess air reduces the amount of oxygen available to

combine with dissociated nitrogen and is discussed in

Section 5.1.1. Combustion staging methods reduce NOx formation

by either reducing available oxygen or providing excess oxygen to

cool the combustion process. Combustion air preheat is often

used in process heaters to improve thermal efficiency. Because

preheated combustion air increases combustion temperatures,

thermal NOx formation is increased. Combustion air preheat is

discussed in Section 5.1.2. Staged combustion incorporating air

lancing is discussed in Section 5.1.3. The technique of staging
5-62

combustion air was later incorporated into the design and

development of staged-air burners and is described in

Section 5.1.4. Fuel staging, discussed in Section 5.1.5, is a

more recently developed burner staging technique. Flue gas

recirculation (FGR) has been used as a NOx control technique for

boilers but has had limited application to process heaters. A

discussion of FGR for process heaters is provided in

Section 5.1.6. More recently, a class of burners has been

developed that uses a variety of techniques and is generally

referred to as ultra-low-NOx burners. In addition to staged

combustion, these burners may incorporate internal FGR and steam

injection; they are discussed in Section 5.1.7. Section 5.1.8

covers a separate class of burners, referred to as radiant

burners, which use a ceramic catalyst enclosing the burner tip. 

i. Low Excess Air

Low-excess-air (LEA) control systems optimize the amount of

air available for combustion. Optimizing the combustion air

supply reduces both fuel consumption and NOx formation. 

Decreased local oxygen concentrations, due to minimal excess air

in the combustion zone, forms a reducing atmosphere, which

inhibits the formation of both thermal and fuel NOx. 

Additionally, the resulting lower flue gas temperature further

reduces the formation of thermal NOx. Thermal efficiency is

increased by reducing the heat loss associated with the heating

excess air not required for combustion. More heat is therefore

transferred to the process fluid per unit of energy input, thus

requiring less fuel to provide the required heat flux. The

actual efficiency improvement obtained for a given heater depends

on the flue gas temperature and on the heat response of the

heater to the reduced flue gas flow under LEA conditions.1-4

The effectiveness of any LEA control system in reducing NOx

emissions from a fired heater depends on (1) the long-term

average excess air level that can be maintained in the heater and

(2) the relationship between NOx emissions and oxygen (O2) in the

heater. The lowest excess air level that can be maintained in a 1

fired heater depends on draft type, fuel type, degree of air
5-63

leakage into the heater, and the ability of the excess air

control system to respond quickly to changes in fuel composition

and heater load. The relationship between NOx emissions and O2

for a particular heater depends on draft type, fuel type, burner

type, and degree of combustion air preheat. Optimal excess O2

levels are therefore different for each heater.

Draft type influences the excess air level attainable in

older heater designs by affecting the degree of fuel/air mixing

in the burner. Mechanical draft (MD) burners generally operate

with a higher pressure drop than natural draft (ND) burners,

resulting in improved fuel/air mixing. Consequently, MD heaters

can achieve complete combustion at lower excess air levels than

ND heaters. This is not necessarily the case in recent burner

designs, however, as one source reports that ND burners can be

operated at excess air levels similar to MD burners.5

The minimum excess air level is also affected by fuel type. 

Fired heaters combust gas, oil, or a combination of gas and oil. 

Gas-fired heaters generally require a lower excess air level than

oil-fired heaters. Variations in fuel composition such as those

often associated with refinery gas may affect the ability of some

LEA control systems to continuously maintain stack O2 levels. 

Data from tests conducted from 1978 through 1982 indicate that,

on average, a 9 percent reduction in NOx accompanies each

1 percent reduction in stack O2 levels when stack O2 levels are

between 2 and 6 percent. For example, reducing the average

long-term stack oxygen level of a heater using LEA control

techniques from 5.5 percent O2 to 2 percent O2 would result in a

32 percent reduction in NOx emissions. Current experience for 1

one source is that NOx reductions of 6 percent are achieved for

every one percent reduction in excess O2. This ratio is lower

than the 9:1 NOx reduction ratio discussed above and probably

reflects recent improvements in heater and burner designs with

reduced excess air levels.

Current practice is to control excess air to improve heater

efficiency. However, retrofitting older heaters that lack LEA

equipment may require a large capital investment to achieve
5-64

optimal excess air operation. Excess O levels of approximately 5

2

2 to 4 percent appear to provide the best balance of maximum

heater thermal efficiency and NOx and CO emission reductions. 

Appendix A presents a refinery process heater inventory and

suggests that excess air is already maintained at or near optimal

conditions. As discussed earlier, O2 optimal conditions are

different for every heater. For this reason, control of excess

air should be viewed as an expected standard operating procedure

and not as a potential retrofit NOx control method for

substantial NOx reductions. 

ii. Combustion Air Preheat

Combustion air preheat is often used in conjunction with MD

heaters to improve heater thermal efficiency. An MD heater with

air preheaters will typically have an exhaust gas temperature of

260EC (500NF). Thermal efficiency for heaters of this type can

be as high as 92 percent. As discussed in Chapter 4, this 1

increase in thermal efficiency with the addition of air preheat

is associated with increases in thermal NOx formation. Reducing

air preheat in MD heaters reduces thermal NOx formation at the

expense of heater efficiency. This loss of heater efficiency can

be partially offset by adding a convection section heat recovery

unit (or increasing the size of the existing one). As discussed

in Section 5.1.7, NOx emissions from radiant burners appear to be

unaffected by combustion air preheat. 
5-65

Figure 5-1 illustrates the typical relationship between 
5-66

Figure 5-1. Effect of combustion air preheat temperature on NOx

emissions.1
5-67

combustion air preheat and NOx emissions. An increase in air

preheat from ambient to 260EC (500EF) increases NOx formation by

a factor of approximately two. This result is supported by the

refinery/inventory survey shown in Appendix A. Those heaters

using inlet air at ambient conditions show significantly lower

emissions than comparable units at elevated preheat levels. Most

heaters equipped with preheaters do not have control of the level

of air preheat.

iii. Use of Air Lances to Achieve Staged Combustion

Early efforts to stage combustion used air lances to

separate the combustion process and limit NOx formation. In the 
5-68

primary combustion zone, a rich mixture is combusted with the air

lances supplying jets of air in the secondary combustion zone to

complete the oxidation of the fuel. A schematic diagram of a

staged combustion system using air lances is presented in

Figure 5-2. The range of uncontrolled and achievable controlled 
5-69

Figure 5-2. Staged combustion air lances installed on a

conventional gas burner.1
5-70

emissions reported in References 2 and 3 is presented in

Table 5-1
5-71

TABLE 5-1. CONTROLLED EMISSIONS FOR STAGED COMBUSTION 

USING AIR LANCES2,3

Fuel

Uncontrolled NO emissions x NOx

reduction,

percent

Controlled NO emissions x

ppmvalb/MMBtu ppmvalb/MMBtu

Refinery gas 138 0.165 12 121 0.144

Refinery gas 125 0.243 71 36.3 0.043

Residual oil and 

refinery gas

265 0.334 25 199 0.251

Residual oil and 

refinery gas

214 0.270 53 101 0.127

At 3 percent O .

a

2
5-72

. Nitrogen oxide reductions from uncontrolled levels using air 2,3

lances for heaters firing refinery gas range from 12 to

71 percent. Reductions for heaters that combine firing of 2,3

No. 6 fuel-oil and refinery gas range from 25 to 54 percent. 

Although staged combustion air (SCA) is potentially

applicable to many fired heaters, its use may be restricted by

several limitations. As the degree of staging is increased, the 1

flame quality and temperature decrease, and the uniformity of the

heat flux provided by the flame is impaired. In process heater

applications in which the process fluid flow may be seriously

affected by variations from the design heat flux distribution,

staged air lances may not be applicable. For example, reforming

heaters and vacuum heaters often have process fluids of more than

one phase or at high temperatures that require a constant heat

flux distribution. Other heater types, such as crude oil

heaters, have been demonstrated to more readily tolerate changes

in heat flux and temperature. Other limitations include the

possibly corrosive environment due to staged combustion within

the heater, which leads to frequent replacement of air lances. A

larger flame zone would be required in some heaters to

accommodate the lengthened flame associated with staged

combustion.

The development of staged burners incorporating air staging

or fuel staging has eliminated the need for extensive air supply

piping and removed many of the flame difficulties associated with

air lance staging. One source reports that no known commercial

applications of air lances exists. For this reason, air staging 6

using air lances should not be considered a current NOx control

approach. 
5-73
5-74

iv. Staged-Air, Low-NOx Burners

Staged-air techniques have been incorporated into the burner

design. Although staging techniques are effective in reducing

NOx emissions, flame shape can be detrimentally affected. 

Staged-air, low-NOx burners (LNBs) are usually larger than

conventional burners and generally require extensive retrofitting

operations. Emission reductions achieved by staged-air LNBs

range from 30 to 40 percent below emissions from conventional

burners. Using the uncontrolled emission factors from 1,7,8,9

Table 4-3 and a 40 percent NOx emission reduction, the expected

controlled NOx emissions for staged-air LNB are presented in

Table 5-2.
5-75

TABLE 5-2. CONTROLLED EMISSION LEVELS FOR STAGED-AIR LNB'S

Fuel Draft type

Uncontrolled NOx emission

factors

Controlled NO emission levels x

b

ppmalb/MMBtu ppmalb/MMBtu

Gas ND 111 0.14 66.6 0.084

Distillate oil ND 159 0.20 95.2 0.120

Residual oil ND 333 0.42 200 0.250

Gas MD 206 0.26 124 0.156

Distillate oil MD 254 0.32 152 0.195

Residual oil MD 421 0.53 253 0.318

@3 percent O a

2

Controlled emissions based on a 40 percent reduction. b
5-76

 The emissions are presented for ND and MD gas-, distillate oil-

, and residual oil-fired heaters. The uncontrolled emissions

range from 0.14 lb/MMBtu for ND gas-fired heaters to

0.42 lb/MMBtu for MD residual oil-fired heaters. The controlled

emissions range from 0.084 lb/MMBtu for ND gas-fired heaters to

0.318 lb/MMBtu for MD residual oil-fired heaters. 
5-77

Table 5-3
5-78

TABLE 5-3. STAGED-AIR BURNER NO CONTROL PERFORMANCE AND EMISSION LEVELS x

NO control performance and emission levels x

Burner name Heater draft Fuel ppmv lb/MMBtu

John ZinkLow-NO HIV x a

MD NG b 40 to 105 0.048 to 0.125

HFOc 250 to 270 0.315 to 0.340

John ZinkLNCa

ND(60EF)

NG 85 0.101HFO

MD(500EF preheat)

NG 105 0.125HFO 270 0.340

McGillNRGRa,b

ND NG 40% reduction 40% reductionMD NG 40% reduction 40% reduction

McGillNCRa,b

ND Combination 40% reduction 40% reductionMD Combination 40% reduction 40% reduction

HamworthyLVa

MD Oil/gas 40% reduction 0.039 to 0.053

AUSCSDFRLow NOxa

MD NG 33 to 44 (no preheat)

54 to 57 (600 EF preheat, lean gas)

0.064 to 0.068

AUSCS200a

ND/MD NG 37 ppmv (without preheat using ND) 0.044

Callidus Staged-Air LNB c ND NG 30% reduction 30% reduction

MD (preheat) d NG 30% reduction 30% reduction

Reference 7. Vendor names are presented as found in the reference and are included only to identify the burner type. Other vendors may offer similar burner types. a

McGill has been purchased by John Zink Company. McGill burners are no longer available, but replacements can be obtained from the John Zink Company. b

Reference 9. Vendor names are included only to identify the burner type. Other vendors may offer similar burner types. c

Preheat temperature is not known. d
5-79

 presents several staged-air burners and estimated performance. 

For heavy fuel oil (HFO) firing (0.3 percent N content), stagedair LNBs produce about 250 ppmv of NOx at 3 percent O2

(0.315 lb/MMBtu). This reflects approximately a 40 percent

reduction in NOx emissions from conventional burners. For gas

fuels, staged-air LNBs produce a lower bound of approximately 80

to 100 ppmv NO2 at 3 percent O2 (0.096 to 0.119 lb/MMBtu) with

260EC (500EF) preheat. 

Most early LNB design efforts centered on bypassing some of

the combustion air around the conventional burner combustion

zone. Typically, as shown in Figure 5-3, 
5-80

Figure 5-3. Schematic of a staged-air low-NOx burner.8
5-81

these "air-staged" designs use a tertiary combustion zone since

most of the standard burners already have primary and secondary

air mixing. Tertiary air, containing the "excess" portion (10 to

20 percent) of combustion air, is introduced around the outside

of the secondary combustion zone so that unburned fuel and O2

mix/react more by diffusion than by turbulent mixing. This

technique maximizes the time during which fuel burns in

substoichiometric conditions.
5-82
5-83
5-84

The theoretical basis for air staging is that the initial

combustion of fuel takes place in a fuel-rich reducing atmosphere

in which N2 is preferentially formed rather than NOx. The flame

temperature in the initial combustion zone is high due to the low

combustion air/fuel ratio, but thermal NOx formation is limited

by the low O2 concentration. 

For heavy fuel oil (HFO) combustion, staged-air burners are

more suitable than staged-fuel burners. The reducing 10

conditions prevailing in certain makes of staged-air burners

(particularly those with longer primary zone residence times) are

thought to have a greater impact on fuel NOx reduction than the

staged-fuel burner, which essentially affects only thermal NOx. 

Fuel NOx reduction is the key issue in overall NOx reduction for

high-nitrogen-content liquid fuels such as HFO. 

The major problem with high-performance LNB retrofitting is

that flames tend to be larger and less well-defined than those of

the standard burners they are replacing. The altered flame

pattern is caused by diffusion mixing and delayed combustion

resulting from the air staging. The tendency for larger, less

well-defined flames is more pronounced for ND than for MD burners

and more so for oil than for gas firing. However, one source

reports that problems resulting from flame pattern alteration can

be minimized or eliminated if the burner system is properly

designed. Design considerations that affect the flame

characteristics include burner tip placement, burner tip hole

sizes and angles, placement of the flue gas recycle ducts, and

burner tile shape.5

Another problem with LNBs is that retrofit operations may

require extensive modifications to the heater. A large number of

process heaters are floor-fired, and limited space under the

heater may increase retrofit cost significantly because LNBs

require larger air plenums than conventional burners. Other 5

typical retrofit operations include multiple fuel header

connections, steam header connections, and flue gas ducting

alterations.5
5-85

Spacing between burner center lines varies appreciably from

one heater design to another, typically within a range of 0.6 to

1.7 meter (m) (2 to 5.6 feet [ft]) (most are greater than 1.0 m

[3.3 ft]). In general, retrofitting heaters that have a spacing

of less than 1 m may not be practical because of potential flame

impingement. In the case of heaters in critical services

(i.e., those with high process temperatures or pressures) such as

catalytic reforming, steam/methane reforming, hydrocracking,

olefin cracking, etc., this minimum spacing may be as high as

1.4 m (4.6 ft) because of the need to minimize heat flux

variations around the tubes.

The NOx emissions from LNBs are much more sensitive to

excess air than are emissions from standard burners. Since

improved control of excess air is more readily achieved with MD

combustion air systems, an effective NOx reduction strategy for

ND process heaters is a retrofit involving conversion to MD,

excess O2 control, and LNBs. The benefits of such a retrofit

are:

1. Improved flame definition relative to an ND heater with

LNBs;

2. Reduced excess air, resulting in energy savings; and

For MD process heaters, an effective LNB retrofit would involve

installing both excess O2 control and LNBs.

Another limitation on LNB applications is the existing

burner design heat release rate. Most LNBs have a minimum design

heat release of about 3,000 to 9,000 MJ/hr (3 to 9 MMBtu/hr). 

Certain heaters, such as steam/methane reformers, are typically

designed with a large number of small burners with duties that

may fall below the minimum LNB heat release.

From the above discussion, it is apparent that not all

process heaters are suitable for LNB retrofitting, although the

majority will qualify. In the case of heaters with multiple

small burners, the cost of a burner retrofit is high even when it

is technically feasible so that alternative low-NOx solutions may

be more attractive.
5-86

v. Staged-Fuel Low-NOx Burners

Staged-fuel LNBs were more recently developed than stagedair LNBs. Designed for gas firing, staged-fuel LNBs separate the

combustion zone into two regions. The first is a lean primary

region in which the total quantity of combustion air is supplied

with a fraction of the fuel. In the second region, the remainder

of the fuel is injected and combusted by the oxygen left over

from the primary region. This technique inhibits the formation

of thermal NOx , but has little effect on fuel NOx formation. 

Figure 5-4 presents a schematic of a typical staged-fuel

LNB. 
5-87

Figure 5-4. Schematic of a staged-fuel low-NOx burner.1
5-88

 In a typical staged-fuel LNB, 40 to 70 percent of the fuel is

bypassed around the primary combustion region. Combustion in 7,11

the primary region, therefore, takes place in the presence of a

large excess of O2 at substantially lower temperatures than the

standard burner. The remaining fuel is introduced around the

outside of the primary combustion zone so that fuel and unburned

O2 mix/react by diffusion rather than turbulent mixing and

substoichiometric reducing conditions are maximized.

For gaseous fuels that do not contain fuel-bound nitrogen,

NOx reduction performance from fuel staging is better than that

from air staging. The low-temperature/high-O2 conditions of the

staged-fuel LNB have a stronger effect on thermal NOx reduction

than do the high-temperature/low-O2 conditions of the staged-air

LNB.7

Staged-fuel LNBs have several advantages over staged-air

LNBs. First, the improved fuel/air mixing due to the pressurized

injection of the secondary region fuel reduces the excess air

operating level necessary to ensure complete combustion. The

lower excess air both reduces NOx formation and improves heater

efficiency. Second, for a given peak flame temperature, stagedfuel LNBs have a more compact flame than staged-air LNBs.1

Staged-fuel burners have been installed as wall-, floor- and

roof-mounted burners and have found use in the full range of

process applications from crude oil heaters to downstream

conversion processes.
5-89

Reductions in NOx emissions of up to 72 percent have been

reported over conventional burners based on vendor test data for

staged-fuel LNBs. The average reduction is approximately 1

60 percent. Table 5-4 presents controlled NO emission 1,7,9,12

x

levels for several staged-fuel LNBs. The controlled emissions

ranged from 40 to 50 ppmv at 3 percent O2 (0.048 to

0.060 lb/MMBtu); uncontrolled emission levels, and therefore

percent reductions, were not available. Table 5-5 7
5-90

TABLE 5-4. STAGED-FUEL LOW-NOx BURNER CONTROLLED

 NOx EMISSION LEVELS7

Burner name Heater draft Fuel

Controlled NO emissions x

ppmvg,h lb/MMBtu

John Zink SFGa NDd Gas 40 to 50 0.048 to 0.060

MD (500EF preheat) Gas 40 to 50 0.048 to 0.060

John Zink SFGa NDd Combinationf

40 NA

MD (500EF preheat) Combinationf

50 NA

McGill SRGRa,b NDd Refinery gas

50 percent H2

45 0.054

MDd Refinery gas

50 percent H2

45 0.054

Callidus CSGc NDd NG 60% reduction 60% reduction

MD (preheat)e NG 60% reduction 60% reduction

Reference 7. Vendor names are presented as found in the reference and are included only to identify the burner a

type. Other vendors may offer similar burner types.

McGill has been purchased by John Zink Company. McGill burners are no longer available, but replacements can b

be obtained from the John Zink Company.

Reference 9 Vendor names are included only to identify the burner type. Other vendors may offer similar burner c

types.

Combustion air at ambient conditions. d

Preheat temperature is not known. e

Combination of oil and gas fuels. f

At 3 percent O .

g

2

Percent reductions were not available for all burners. h

NA = Not available.
5-91

TABLE 5-5. CONTROLLED NOx EMISSION LEVELS FOR STAGED-FUEL

LOW-NOx BURNERSa

Uncontrolled NOx

emissions

Controlled NOx emissionsc

Draft type ppmvb lb/MMBtu ppmvb lb/MMBtu

ND 117 0.14 47 0.056

MD 218 0.26 87 0.104

Gas firing. a

At 3 percent O .

b

2

Controlled emissions based on a 60 percent reduction. c
5-92

 presents controlled emission levels for gas-fired heaters using

uncontrolled emission factors from Table 4-3 and a 60 percent

reduction. The controlled NOx emission levels are 0.056 and

0.104 lb/MMBtu for ND and MD heaters, respectively. The data in

Table 5-4 indicate that the combination fuel burners,

i.e., burners that fire a gas and oil mixture, can achieve

approximately the same emission levels as the gas-fired burners. 

However, it is expected that combination fuels will generally

produce higher NOx emissions than gas-only fuels. The data in

Table 5-4 also indicate that controlled emissions for ND burners

are only 10 ppmv less than MD burners with preheat. As shown in

Table 4-2, NOx emissions for process heaters with preheat are

approximately 1.25 to 2 times that of process heaters without

preheat, so controlled emissions for ND and MD burners in general

would be expected to differ by more than 10 ppmv. It is expected

that the controlled emissions for the MD gas-fired John Zink SFG

LNB in Table 5-4 would have similar emissions as the MD heater in

Table 5-5.

vi. Flue Gas Recirculation

Flue gas recirculation (FGR) generally involves forced

return of flue gas to the burners and introduces the air/flue gas

mixture into the combustion zone. This technique is usually

referred to as external FGR. 

Flue gas recirculation is a NOx emission reduction technique

based on recycling 15 to 30 percent of the essentially inert

products of combustion (flue gas) to the primary combustion

zone. The recirculation of flue gas dilutes the combustion 5

reactants, reduces the peak flame temperature, and reduces the 
5-93
5-94

local oxygen concentrations, thereby inhibiting thermal NOx

formation. However, FGR is believed to have only a small effect

on fuel NOx formation.1,7

Conventional burners can be used with modifications to

accept the increased gas flow. Success with external FGR on

boilers demonstrates the capability of the technique, but FGR has

been used on only a few fired heaters. Several inherent drawbacks

limit its potential use with process heaters. Flue gas

recirculation requires a relatively large capital investment

because of the need for high-temperature fans and ductwork. 

Furthermore, it may not apply to all types of fired heaters. The

low flame temperature and susceptibility to flame instability

limits FGR usage in high-temperature applications. In addition,

FGR can only be used on MD heaters. Since FGR is believed to

have only a small effect on fuel NOx formation, FGR may not be as

effective on oil-fired heaters as on gas-fired heaters.5

The only NOx emission data currently available on a fired

heater using FGR consist of five spot measurements on a 10 MW

(100 MMBtu/hr) crude oil heater with mechanical draft, ambient

combustion air, and unknown fuel and burner type. The average

operating conditions of the heater were 74 percent load, 620EC

(1150EF) FGR temperature, and 14 percent stack gas oxygen

content. The average NOx emissions from the heater were 

78.1 nanograms per Joule (ng/J) (0.012 lb/MMBtu).1

For small heaters, North American Manufacturing Company is

marketing a mass flow, FGR controller. On a 10 MM Btu/hr,

single-burner Dowtherm® heater, NOx emission levels of less than

30 ppmv at 3 percent O2 (0.036 lb/MMBtu) have been achieved.13

This system incorporates LNBs and external FGR.

Based primarily on boiler data, reductions using external

FGR for process heaters are given as 55 percent for both oil and

gas firing when used in combination with LNBs. Also, based on 7

boiler data, FGR used with standard burners on process heaters is

expected to reduce NOx emission levels 30 percent.7
5-95

vii. Ultra-Low NOx Burners

Ultra-low NOx burners refer to a class of burners recently

developed to meet the South Coast Air Quality Management District

(SCAQMD) Rule 1109 NOx emission requirements. These burners may

incorporate a variety of techniques including internal or self

recirculating flue gas (IFGR), steam injection, or a combination

of techniques.

These burners are designed to recirculate hot, O2-depleted

flue gas from the flame or firebox back into the combustion zone.

This reduces the average O2 concentration within the flame

without reducing the flame temperature below temperatures

necessary for optimal combustion efficiency. All designs, as 7

depicted in Figure 5-5, use a venturi effect to 
5-96

Figure 5-5. Cross-section of an internal flue gas recirculation

burner.1
5-97

induce hot flue gas back into the primary combustion zone. Fuel

gas injection via primary or secondary burner tips and steam

injection can be used to create the venturi effect.

Reduced O2 concentrations in the flame have a strong impact

on fuel NOx , so IFGR burners are an effective NOx control

technique for heaters firing nitrogen- bearing fuel oil. This is

especially true when combined with staged-air combustion, as

exemplified in the John Zink MNC and Hague International Transjet

burners.7

Several sources of data indicate that ULNBs are capable of

achieving lower NOx emission levels than LNBs. Emission levels

for NOx reported by one refinery using ULNBs, shown in

Appendix C, range from 0.050 to 0.031 lb/MMBtu. Controlled NO 14

x

emissions of 0.025 lb/MMBtu have been reported for the Selas

ULNx® burner. This emission level is reported for natural gas 15

firing and a firebox temperature of 1250EC (2280EF). In a heater

firing refinery fuel-gas using an Exxon proprietary staged-air

burner incorporating IFGR, NOx emission levels of 55 ppmv at

3 percent O2 (0.066 lb/MMBtu) at 273EC (524NF) preheat are

anticipated. Operating under different firebox conditions than 16

the Exxon burner, the John Zink NDR burner for ND heaters was

designed to meet SCAQMD Rule 1109 emissions (0.03 lb/MMBtu or 25

to 28 ppmv depending on fuel composition). Additional 17
5-98

reductions of 5 to 10 ppmv appear achievable with approximately

0.12 lb steam/lb fuel injection.17

Refinery retrofit experience shows an average reduction

efficiency of 75 percent thermal NOx reduction for ULNBs.14

Supporting this performance, the Callidus LE-CSG burner is

reported to achieve a NOx reduction efficiency of approximately

75 to 80 percent. The manufacturer states that this IFGR ULNB 9

can achieve this reduction firing natural gas with ND or MD

(preheat) operation. Based on available oil-fired process heater

data, fuel NOx reductions of 78 percent for ND and 72 percent for

MD (preheat) are achievable by ULNBs. Therefore, the reduction 7

efficiencies used in this study for ULNBs for low- and mediumtemperature process heaters are 75 percent for thermal NOx,

78 percent for ND fuel NOx and 72 percent for MD (preheat) fuel

NOx.

Retrofit problems with ULNBs are similar to those

encountered with LNB retrofits. Ultra-low-NOx burners, in

general, are larger in size and may require larger air plenums

than do conventional burners. Modifications to the burner mounts

may be required because ULNBs usually do not fit into

conventional burner mounts. However, one manufacturer has

addressed this problem for wall-fired burners. It is reported

that this manufacturer's latest generation ULNB is designed to

fit into other burner mounts without major wall modifications.15

It is expected that this may not always be true because of the

wide variety of burners available and the differing heater

designs.

viii. Radiant Burners

Alzeta offers a gas burner that has a cube of ceramic fibers

at the burner tip. The fibers act as a catalyst in oxidizing the

fuel. As a result, combustion is accomplished at a temperature

of approximately 980EC (1800EF). Thermal NO formation is 7

x

reduced since this temperature is approximately 1000EC (1830EF)

lower than is generated in conventional burners. Radiant burners

do not appear to be affected by high-temperature air preheat, and

NOx is actually decreased by high excess-air operation. This 18
5-99

technique is available for new installations but is not

considered practical in most cases for retrofit installation. The

burner intrudes into the furnace space, and a retrofit would

probably require retubing the process heater. Reported emissions

have been 20 to 25 ppmv at 3 percent O2 (0.024 to 0.030 lb/MMBtu)

of NOx. Table 5-6 18,19
5-100

Table 5-6. RADIANT BURNER APPLICATIONS 20,21

ID No.

Capacity,

heat

absorbed,

MMBtu/hr

Energy input, MMBtu/hr

Capacity

factor

Conventional

MD burner NOx

emissions, ppmv

@ 3% O2

Conventional

MD burner NOx

emissions,

lb/MMBtu input

Radiant burner

NO emissions, x

ppmv @ 3% O2

Radiant burner NOx

emissions,

lb/MMBtu input

MD heater w/

conventional burners

Heater w/ radiant

burners

1 6.0 a 7.50 7.50 0.90 80.0 0.097 20.0 0.0242 6.0 8.28 7.50 0.50 80.0 0.097 20.0 0.0243 6.0 8.28 7.50 0.30 80.0 0.097 20.0 0.0244 8.0 b N/A 3.80 0.48 N/A N/A 12.1 0.0145 8.0 N/A 7.80 0.98 N/A N/A 15.7 0.0196 8.0 c N/A 3.90 0.49 N/A N/A 0.0 0.07 8.0 N/A 8.20 1.02 N/A N/A 10.7 0.013

Heaters numbers 1 through 3 are the same heater operated at different capacity factors. These heaters were modeled heater applications provided by a

Alzeta.

Heaters numbers 4 and 5 are the same heater operated at different capacity factors. b

Heaters numbers 6 and 7 are the same heater operated at different capacity factors. c

N/A = Data not available.
5-101

 presents data from three different radiant burner process heater

applications. The first application is for a natural gas-fired

model 6 MMBtu/hr heater operated at three different capacity

factors. Emission data are shown for the heater using MD

conventional burners and for the heater using radiant burners. 

The NOx emissions from the heater using radiant burners were

approximately 75 percent less than those from the heater using MD

conventional burners. Controlled NOx emission levels of 20 ppmv

at 3 percent O2 (0.024 lb/MMBtu) were reported by the burner

vendor. The second and third applications are retrofits of 20,21

two 8 MMBtu/hr heaters. Data are shown for each heater operated

at two different capacity factors. Data for preretrofit NOx

emissions were not available. The postretrofit NOx emissions

ranged from 0.0 ppmv at 3 percent O2 to 15.7 ppmv at 3 percent O2

(0.0 to 0.019 lb/MMBtu).20,21

Reported problems with the ceramic burners include fouling,

fragility, and somewhat limited capacities. The heater 7

capacity, efficiency, and radiant section heat absorption may be

affected in retrofit applications because radiant burners operate

at lower temperatures than conventional burners. 

5

b. SELECTIVE NONCATALYTIC REDUCTION

Selective noncatalytic reduction (SNCR) involves the direct

injection of a NOx-reducing chemicals into the hot flue gas. At

suitably high temperatures, the injected chemical can convert the

NOx to N2 without a catalyst. Currently there are three 7

chemical reactants that are available for the SNCR process: 

anhydrous ammonia (NH3), aqueous NH3, and aqueous urea solution. 

Other chemicals such as hydrogen, hydrogen peroxide, and methanol

may be added to improve performance and lower the minimum 
5-102

threshold temperature. The SNCR reduces both thermal and fuel- 22

derived NOx.

Development is continuing on new NOx-reducing agents for use

in SNCR applications on boilers and fired heaters. In

particular, development is focused on extending the lower

threshold temperature at which the reaction can occur and

controlling emissions of unreacted reactants, or reactant slip.

The injection point is determined by the allowable

temperature "window" required to carry out the reaction. The

upper limit for all SNCR processes is about 1100EC (2000EF).

Provided that the heater bridgewall temperature is below this

threshold temperature, the chemicals are injected via compressed

air or low-pressure steam into the firebox. Above 1100NC

(2000EF) bridgewall temperatures, the chemicals can be injected

into the appropriate section of the convection bank. This latter

option is common in large utility boilers.

Heaters can be retrofitted for SNCR by installing injection

nozzles through holes cut in the furnace wall. The nozzles are

connected by piping to air or steam and chemical supplies. Bulk

chemical storage is normally remote from the individual heater

and can be used for more than one heater or boiler.

The SNCR systems require rapid chemical diffusion in the

flue gas. The injection point must be selected to ensure

adequate flue gas residence time and to avoid tube impingement. 

Computer modeling provided by the licensor can be used to develop

the optimum injection points. 

Ammonia slip is potentially higher in SNCR systems than in

SCR systems because the chemical reactant injection ratios in

SNCR systems are higher. Heater load variations, such as

startups, shutdowns, and major upsets in heater operation, tend

to change the firebox temperature. These variations can affect

NOx reduction and NH3 slip when operating near the extremes of

the allowable temperature window. Ammonia slip can be minimized

by properly designed control systems that monitor the flue gas on

a continuous or frequent basis for heater load and NOx

concentration.23
5-103

Ammonia slip can also cause ammonium sulfate [(NH4)2SO4]

deposits in the convection section. These deposits can occur if

sulfur trioxide (SO3) is present in the flue gas.7

Postcombustion controls such as SNCR may be used as the sole

NOx control technique or in combination with LNBs. Potential NOx

reduction efficiency for SNCR is approximately 70 percent, but

controlled emission levels at existing installations show similar

NOx reductions for either SNCR or LNBs plus SNCR. This is likely

because the controlled emission levels reflect permit

requirements. It is expected that achievable NOx reductions

using LNBs plus SNCR are greater than the reductions achieved by

using SNCR.5

Selective noncatalytic reduction efficiency is dependent on

the NOx concentration in the flue gas. Therefore, it is expected

that SNCR used on a heater with relatively high uncontrolled NOx

emissions will have a higher reduction efficiency than an SNCR

used on a heater with relatively low uncontrolled NOx emissions. 

This also indicates that for any particular heater the

performance of SNCR used in combination with LNB may have a lower

reduction efficiency than if SNCR was used alone.5

i. Exxon Thermal DeNOx (Ammonia Injection) ®

Thermal DeNOx (TDN), developed by Exxon, is an add-on NOx

®

control technique that reduces NOx to N2 and water (H2O) without

the use of a catalyst. Figure 5-6 shows a process flow diagram

for 
5-104

Figure 5-6. Exxon Thermal DeNOx system.7
5-105

a TDN system applied to a process heater. The TDN process 22

injects anhydrous or aqueous NH3 to react with NOx in the

air-rich flue gas. The NH3-to-NOx injection ratio is generally

between 1:1 and 2:1 for the TDN process. Equation 1 shows the

reaction with a 1:1 ratio, and Equation 2 shows the reaction with

a 2:1 ratio.

2NO + 2NH3 + 2O2 6 2N2 + 3H2O (1)

2NO + 4NH3 + 2O2 6 3N2 + 6H2O (2)
5-106

Using a 2:1 injection ratio, the NH3 and NOx react according to

the following competing reactions:10

2NO + 4NH3 + 2O2 6 3N2 + 6H2O

4NH3 + 5O2 6 4NO + 6H20

(1) Process Description (Thermal DeNOx ). This process has ®

been installed in 75 process heater and nonprocess heater

applications, and 22 more are presently under design or

construction. Table 5-7 presents a partial list of Exxon's 7

Thermal DeNOx process heater installations and NOx control ®

performance. The reactant is mixed with low-pressure air 7,24
5-107

TABLE 5-7. PARTIAL LIST OF EXXON'S THERMAL

DeNOx INSTALLATIONS7,24

Installation

date Fuel

Size, MW

(MMBtu/hr)

Uncontrolled

NO , ppmv at x

3 percent O2

a

Controlled

NO , ppmv at x

3 percent O2

a

Percent

reduction

1975 Gas 151 (515) 130 48 63

1975 Gas/oil 57 (190) 130 48 63

1977 Gas/oil 73 (250) 79 39 51

1977 Gas/oil 73 (250) 85 40 53

1980 Gas/oil 12 (41) 80-165 40-83 50

1980 Gas/oil 13 (44) 80-165 28-58 65

1980 Gas 31 (105) 80-165 38-78 53

1980 Gas 4 (13) 80-165 40-83 50

1980 Gas 19 (65) 80-165 31-64 61

1980 Gas 14 (49) 80-165 40-83 50

1980 Gas 38 (130) 80-165 48-99 40

1980 Gas 8 (27) 80-165 40-83 50

1980 Gas 4 (13) 80-165 54-111 33

1980 Gas 6 (19) 80-165 48-99 40

1980 Gas 10 (35) 80-165 27-56 66

1980 Gas 22 (74) 80-165 28-58 65

1980 Gas 9 (32) 80-165 36-90 55

1980 Gas 7 (25) 100-150 50-75 50

1980 Gas 30 (102) 100-150 50-75 50

1980 Gas 7 (25) 100-150 50-75 50

1980 Gas 49 (167) 100-150 50-75 70

1981 NA 9 (32) 120 65 45

1981 NA 4 (15) 120 42 65

1982 NA 27 (92) 80-125 NA 30-60

1982 NA 8 (28) 80-125 NA 30-60

1982 NA 7 (23) 80-125 NA 30-60

1982 NA 7 (23) 80-125 NA 30-60

1981 Gas 38 (131) 75 38 49

1985 Gas 92 (315) 144 45 69

1991 Oil 7 (23) 70 40 43

NO (lb/MMBtu) = NO (ppmv @ 3% O ) * 0.001194 for gas. a

x x 2
5-108

from a separate air compressor before passing into the top of the

firebox through a number of injection nozzles (or into the

convection bank if the bridgewall temperature is above 1100NC

[2000EF]). The allowable temperature "window" for the reaction

to proceed is 870N to 1100NC (1600E to 2000EF). 

7

Thermal DeNOx systems may either use aqueous or anhydrous ®

NH3. The NH3 in an aqueous solution is at a lower concentration

than in an anhydrous solution and therefore has reduced safety

concerns. For this reason, aqueous NH3 is often used at sites in

close proximity to populated areas. However, refineries are

generally experienced in handling anhydrous NH3, and no

particularly troublesome operational problems are foreseen. 

Location of pressurized anhydrous NH3 storage tanks should be

remote from the heaters served and from other facilities.7

Further discussion of issues relating to NH3 is included in

Section 7.1.2.2.

Hydrogen may be added to the NH3 to extend the allowable

minimum operating temperature from 760E to 700EC (1400E to

1300EF). This H can be supplied from H -rich refinery streams 5

2 2

such as catalytic reformer off-gas. Alternately, the H2 can be

supplied by an electrically heated NH3 dissociator, which

converts a portion of the NH3 to H2 and N2. This approach may be

preferable from a safety standpoint, but H2-rich gas is less 
5-109

expensive and should be acceptable when used with adequate

safeguards.

(2) Factors Affecting Thermal DeNOx Performance. 

®

Temperature is the primary variable for controlling the selective

reaction. The first reaction (Equation 1) dominates in the

temperature range of 870E to 1200EC (1600E to 2200EF), resulting

in a reduction of NOx. The temperature range can be lowered to 8

760E (1400EF) by adding H2, a readily oxidizable gas, to the

reactant. Below 760EC (1400EF), neither reaction is of 5

sufficient activity to either produce or destroy NOx; the result

will be unreacted NH3, or NH3 slip. Above 1200EC (2200EF), the

second reaction (Equation 2) dominates, causing increased NOx

production. 

Without the use of a catalyst to increase the reaction

rates, adequate time at optimum temperatures must be available

for the NOx reduction reaction to occur. Design considerations

should allow ample residence time and good mixing in the required

temperature range. Long residence times (>1 second) at optimum

temperatures tend to promote relatively high NOx reduction

performance even with less-than-optimum initial mixing or

temperature/velocity gradients. However, when the NH3 injection

zone is characterized by low temperatures and/or steep

temperature declines, a loss of process efficiency results.

New process heater installations can incorporate the

location of the SNCR injection points in the design of the

heater, but retrofit performance may be limited by the

accessibility of a location with a suitable temperature window

for the SNCR injection points.

The ratio of NH3:NOx is another parameter used to control

the process. The NH3:NOx ratio is typically from 1.0 to 1.5, but

can be as high as 2.0 when injection is into a high flue gas

temperature region. The ratio must be consistent with the flue

gas temperature and residence time so that the maximum reduction

is obtained with acceptable slip. If excessive NH3 is injected,

the excess NH3 can exit the convective zone, creating possible

corrosive (NH4)2SO3 and a visible NH3 stack plume. The 1
5-110

temperatures and velocity profiles change significantly with

load. This necessitates the use of multiple NH3 injection points

to achieve the desire NOx reduction for a range of operating

loads. Selection of the optimum NH3 injection location also

affects NOx reduction performance and NH3 slip. In most current

Thermal DeNOx applications, the injection grids are being ®

replaced by wall injectors. 

8

(3) NOx Reduction Efficiency Using Thermal DeNOx . Data in ®

Table 5-7 indicate that 30 to 75 percent of the NOx in the flue

gas can be removed with the Thermal DeNOx process. Maximum ®

achievable NOx emission reductions appear to be approximately 70

to 75 percent. However, SNCR systems are usually designed to

meet regulatory limits rather than maximum achievable reductions. 

This explains the wide range of reduction percentages in the

data. The average percent reduction in Table 5-7 is

approximately 60 percent, which is used in this study to

represent the percent reduction by SNCR and to calculate costeffectiveness values.7,24

(4) Ammonia Slip Considerations for Thermal DeNOx . 

®

Ammonia slip is unreacted NH3 that exits the stack. The molar

ratio of the NH3:NOx is not only important to achieve the most

efficient reduction, but the reduction must be balanced with an

acceptable amount of NH3 slip. An excessive NH3:NOx molar ratio

can result in unacceptable NH3 slip.

In a typical refinery heater application, the NH3:NOx ratio

is maintained at about 1.25 to achieve a 70 percent reduction in

NOx emissions with NH3 slip below 20 ppmv in the stack gas.7

ii. Nalco Fuel Tech NOxOUT® (Urea Injection)

In the early 1980's, the Electric Power Research Institute

(EPRI) developed a urea-(CO(NH2)2) based SNCR process with an 870E

to 1100EC (1600E to 2000EF) allowable operating temperature

window. While Nalco Fuel Tech is EPRI's exclusive licensing 7

agent in the United States, Noell KRC and affiliated companies

are using the process in Europe. Nalco Fuel Tech promotes the 23

use of other chemicals to extend the temperature range and

control NH3 slippage to very low levels. Currently, the urea
5-111

injection process has been installed on four process heaters.

Most of the current applications are on coal-, oil-, and gasfired boiler applications. A summary of current and pending

urea-based injection applications is provided in Appendix B.
5-112

(1) Process Description (NOxOUT®). Figure 5-7 shows a 
5-113

Figure 5-7. Nalco Fuel Tech NOxOUT -type reduction system. ® 7
5-114

typical arrangement and major components of the NOxOUT® process.7

The process, as originally developed, involves direct injection

of an aqueous urea solution using air or steam to assist its

distribution in the firebox or convection bank. Nalco Fuel Tech

reports that the higher momentum associated with injecting

nonvolatile solutions requires less energy to obtain good

distribution than is needed with the anhydrous Thermal DeNOx

®

process. Available data, however, suggest that because of the

use of nonvolatile solutions, it appears that more energy is

needed to obtain good distribution than is required with the

anhydrous Thermal DeNOx process. ® 7

In the urea injection SNCR process, urea is injected into

the combustion gas path. In the ensuing reaction, molecules of

NO are converted to N2, H2O, and CO2. The desired chemical

reaction is:

CO(NH2)2 + 2 NO + 1/2 O2 6 2 N2 + CO2 + H2O

The above chemical reaction indicates that 1 mole of urea reacts

with 2 moles of NO. However, greater-than-stoichiometric

quantities of urea can be injected to improve NOx reduction and

to speed the reaction kinetics. This can result in some NH3

slippage and a slight increase in CO; both are generated as

byproducts from the incomplete thermal decomposition of the

excess urea.7

Nalco Fuel Tech has modified the original process in order

to reduce the minimum allowable temperature from 870NC (1600EF)

to as low as 650NC (1200NF) by adding of a variety of

nonhazardous chemicals, which include antifouling and storage

stabilizing agents. In a refinement of the process, different

chemical blends may be added at two different flue gas

temperature levels. More than one chemical package may be needed

in cases where several heaters or boilers are involved, having 
5-115

large variations in firebox temperature. If the firebox

temperature is over 600NC (1110EF), injection can be downstream

of the shock tubes.7

Nalco Fuel Tech has licensed urea producers to blend and

sell NOxOUT chemical packages containing the necessary ®

additives. For new, larger applications, the urea-based

solutions can be prepared onsite from solid chemicals delivered

via bulk transport. Very small users can be supplied with

predissolved solutions. The stored chemicals are further diluted

before being pumped to the heater/boiler for injection using

steam or compressed air as the carrying medium. The number of

injection nozzles may be similar to or greater than those used

for NH3. However, Nalco Fuel Tech indicates that the number of 7

injection nozzles will be less than for NH3 injection. For 23

either NH3- or urea-based processes, the number of injection

nozzles will be site specific.

Since an aqueous solution and distribution air are added to

the firebox flue gas, there will be a heat duty loss of

approximately 0.3 percent in the convection section, which

results in increased fuel consumption. 

(2) Factors Affecting NOxOUT® Performance. As with ammonia

injection, the primary factor that influences the reduction

reaction rate is temperature. The temperature window for

efficient reduction is 870E to 1150EC (1600N to 2100NF), although

H2 and CO injection have been shown to lower the temperature

window. Residence time and the mixing of the urea-based reagent

and NOx also influence the reduction reaction. The molar ratio

of urea to NOx is similar to the Thermal DeNOx molar ratio. A ®

low molar ratio reduces the potential reaction, but a high molar

ratio can result in NH3 slip.7,8

Because sufficient residence time within the temperature

window is necessary for efficient NOx reduction, the injection

point of the urea-based reagent is important. Usually, the

injection point is prior to the convective heat recovery section. 

Load variations affect the flue gas temperature and velocity,

thereby affecting the residence time. At reduced loads, the
5-116

temperature window may not be reached, resulting in a reduction

in NOx efficiency and an increase in NH3 slip. A solution to 1

this problem is the use of additives in the urea solution to

shift or widen the temperature window. One study shows that

additives such as carbon monoxide, methane, and ethylene glycol,

or a combination of these, increase NOx reduction by decreasing

temperature dependence. The study also concludes that the

initial NOx concentrations apparently have some bearing on

NOxOUT® performance and the selection of additives.25,27

(3) NOx Emission Reduction Efficiency Using NOxOUT®. 

Applications of the NOxOUT® process on process heaters are

limited. However, as shown in Appendix B, boiler applications of

the process have been successful, and it appears that NOxOUT® is

a viable alternative control technique. As shown in Table 5-8,

NOx emission reductions guaranteed by the vendor for process

heaters range from 10 to 75 percent.26
5-117

TABLE 5-8. NALCO FUEL TECH NOxOUT® PROCESS

 HEATER APPLICATIONS23

Capacity,

MMBtu/hr

Baseline emissions Reduction

guaranteed by

vendor, percent

Controlled emissions

ppma

lb/MMBtu ppma(lb/MMBtu

177 38-50 0.045-0.060 35-60 15.2-32.5 0.018-0.039

50 65 0.078 50-75 16.3-32.5 0.020-0.039

NA 90 0.107 55 40.5 0.048

NA 30-50 0.038-0.063 10 27-45 0.034-0.057

At 3 percent excess 0 .

a

2

NA = Not available.
5-118

 The NOxOUT® performance appears to be similar to the

performance of Thermal DeNOx , with average NOx reductions for ®

process heater applications of approximately 60 percent.

(4) Ammonia Slip Considerations for NOxOUT®. Unreacted

urea results in NH3 slip in a manner similar to ammonia slip from

the Thermal DeNOx process. Slippages of 10 to 20 ppmv have been ®

reported.7,8

c. SELECTIVE CATALYTIC REDUCTION

In the SCR process, a small amount of anhydrous or aqueous

ammonia (NH3) vapor is mixed with flue gas and passes through a

catalytic reactor so that the NOx (mainly NO) is reduced to N2. 

A wide variety of available catalysts can operate at flue gas

temperature windows ranging from 230E to 600NC (500E to 1100EF),

which usually occur downstream of the fire box. 

The SCR systems introduce flue gas pressure drops ranging

from 23 to 130 mm w.g. (1 in. to 5 in.) that necessitate a new or

replacement induced draft (ID) fan for all heaters. Also, SCR

retrofits require appreciable plot space adjacent to the heater. 

Currently, SCR has been demonstrated on some but not all types of

process heaters. This is not only because permit limits have 27
5-119

been achieved by the use of other control techniques, but because

SCR requires controlled parameters such as sufficient residence

time in the correct temperature window. Where applicable, SCR

offers the highest percent reductions of the available NOx

reduction techniques. 

i. Process Description (SCR)

In this process, NH3, usually diluted with air or steam, is

injected through a grid system into the flue/exhaust gas upstream

of a catalyst bed. On the catalyst surface, the NH3 reacts with

NOx to form N2 and H2O. The major reactions that occur in the 7,8

presence of the catalyst are the following:

6NO + 4NH3 6 5N2 + 6H2O

2NO + 4NH3 + 2O2 6 3N + 6H2O

Figure 5-8 shows major components and control systems

associated with an SCR retrofit using a horizontal reactor. 
5-120

Figure 5-8. Schematic of a selective catalytic reduction

system.7
5-121

 Horizontal and vertical arrangements of the SCR reactor catalyst

chamber are both acceptable, but vertical arrangements use less

space and hence are more common in process plants. Vertical

reactors can be downflow or upflow, with downflow preferable, as

particulate matter tends to drop through the catalyst. The

heater ID fan can be located at either the inlet or outlet of the

reactor containing the catalyst bed.7,28

Ammonia vapor is injected into the flue gas through a

special distributor located upstream of the reactor using

compressed air to distribute the reactant evenly. This

distribution air is delivered at about 21 to 35 kilopascals (kPa)

(3 to 5 gage pounds per square inch [psig]) using a lobe-type air

compressor at a rate equivalent to about 30 times the NH3 rate. 

Ideally, NH3 injection is controlled via a stack gas NOx

analyzer, but control via fuel flow is also satisfactory for many

refinery applications provided that stack gas is analyzed

regularly.7,28

The reactor is located upstream of air preheaters, if

present, so as to maintain the optimal reactor inlet temperature. 

In ND heater retrofits, the existing stack is removed, although 
5-122

possibly a portion can be reused. Ductwork to and from the

reactor is at least as large as the existing stack.

Only one ID fan is necessary and a fail-safe stack damper is

needed to open automatically on either fan failure and/or any

excess pressure in the furnace itself. The fan drive may be

variable-speed to minimize horsepower requirements.

Reactor soot blowers are needed in oil-fired applications to

keep the catalyst surface clean of soot and loose ash. The

system downstream must take soot blowing into account. The

catalyst is contained in special baskets or frames for insertion

and removal. This arrangement requires sufficient free area

beside each reactor for cranes as well as for the catalyst

modules.

A typical 100 GJ/hr (100 MMBtu/hr) furnace application

requires a 4 x 5 m (13.1 x 16.4 ft) plot for the reactor itself

plus approximately 6 m (19.7 ft) to one side for catalyst removal

and replacement.7

ii. Factors Affecting SCR Performance

The reaction of NH3 and NOx is favored by the presence of

excess O2 (air-rich conditions), but the primary variable

affecting NOx reduction is temperature. Optimum NOx reduction 8

occurs at catalyst bed temperatures of 320E to 400EC (600NF to

750NF) for conventional (vanadium- or titanium-based) catalyst

types and 243E to 265EC (470E to 510EF) for platinum catalysts.7,28

Performance for a given catalyst depends largely on the

temperature of the flue gas being treated (see Figure 5-9). A 
5-123

Figure 5-9. Effect of temperature and oxygen on NOx conversion.6
5-124

given catalyst exhibits optimum performance within ±10EC (±50EF)

of its design temperature for applications in which flue gas O2

concentrations are greater than 1 percent. Below this optimum

temperature range, the catalyst activity is greatly reduced,

allowing unreacted NH3 to slip through. Above 450EC (850NF),

ammonia begins to oxidize to form additional NOx. The NH3

oxidation to NOx increases with increasing temperature. 

Depending on the catalyst substrate material, the catalyst may be

quickly damaged due to thermal stress at temperatures in excess

of 450EC (850EF). It is important, therefore, to have stable 
5-125

operations and thus uniform flue gas temperatures within the

optimum temperature range for this process to achieve optimum NOx

control. New process heater installations can accommodate the

location of the reactant injector points and catalyst in the

design of the heater, but retrofit applications may be limited by

the location of a suitable temperature window.7,28

A new family of zeolite catalysts has been developed that is

capable of functioning at higher temperatures than conventional

catalysts. Zeolites are reported to be effective over the range 7

of 320E to 600EC (600E to 1130EF), with the optimum temperature

range stated as 360E to 580EC (675E to 1080EF). In some zeolite 7

catalyst formulations, NH3 oxidation to NOx begins at around 450EC

(850EF) and is predominant at temperatures in excess of 520EC

(960EF). A gas turbine zeolite catalyst installation is 7

reported to be operating in the temperature range of 500E to

520EC (930E to 960EF). The performance is reported to be 11

80 percent NOx reduction with NH3 slip limit of 20 ppmv at

15 percent O2 (61 ppmv at 3 percent O2). No process heater data 11

were available. Although within the operating range, the zeolite

structure may be irreversibly degraded at around 550EC (1020EF)

due to loss of pore density. Zeolites suffer the same

performance and potential damage problems as conventional

catalysts when used outside their optimum temperature range. 

With zeolite catalysts, the NOx reduction reaction takes

place inside a molecular sieve ceramic body rather than on the

surface of a metallic catalyst. This difference is reported to

reduce the effect of particulate matter/soot, sulfur dioxide

(SO2)/SO3 conversion, and/or heavy metals which poison, plug, and

mask metal-type catalysts. These catalysts have been in use in

Europe since the mid-1980's, with approximately 100 installations

onstream. Process applications range from gas to coal fuel. 

Typically, NOx levels are reduced 80 to 90 percent using zeolite

catalysts. Zeolite catalysts are currently being purchased for

U.S. installations.

The optimal effectiveness of the catalytic process also

depends on the NH3:NOx molar ratio. Ammonia injection rates must
5-126

be controlled to give a 1:1 NH3:NOx molar ratio. As the molar

ratio of NH3:NOx increases to approximately 1:1, the NOx reduction

increases. Operating above a 1:1 ratio with insufficient

catalyst volume results in unreacted NH3 slipping through the

catalyst bed. Onstream analyzers and quick feedback controls are

required to optimize NOx removal and minimize NH3 emissions.7,28

Another variable that affects NOx reduction is space

velocity, which is the ratio of flue gas flow rate to catalyst

volume, or the inverse of residence time. For a given catalyst

volume, increased flue gas rate decreases the conversion of NOx. 

Conversely, for a given flue gas flow rate, increased catalyst

volume improves the NOx removal effectiveness.

The bulk of catalysts now in refinery service contain

titanium and/or vanadium. Older formulations of this type of

catalyst tend to convert up to 5 percent of the SO2 present to

SO3. Conversion of SO2 to SO3, in turn, results in the formation 7

and deposition of ammonia salts on relatively cool surfaces. One

source reports that newer catalyst formations using titanium

and/or vanadium convert 5 percent or less SO2-to-SO3. Catalyst 28

formulations with less than one percent SO2-to-SO3 conversion

rates are available, but the catalysts may have lower reduction

efficiencies. As a result, a larger catalyst volume may be

required to achieve a given NOx reduction. Zeolite catalysts

have an SO2-to-SO3 conversion rate of about 1 percent.7

iii. NOx Emission Reduction Efficiency Using SCR

 Catalyst performance and life are normally designed and

guaranteed to suit the specific NOx reduction requirements. 

Ninety percent NOx reductions are achievable when operating at a

stoichiometric NH3:NOx molar ratio of 1.0 to 1.05:1 with the exit

gas containing about 10 to 20 ppmv NH3. At a sub-stoichiometric

ratio of 0.5, about 50 percent NOx reduction is achieved with a

NH3 slip of less than 10 ppmv.7

Selective catalytic reduction is usually used in combination

with LNBs. Table 5-9
5-127

TABLE 5-9. CONTROLLED EMISSION FACTORS FOR SCR

ADDED TO HEATERS WITH LNB'S14

Baseline emission factor Controlled emission level

Heater

capacity,

MMBtu/hr ppmva

lb/MMBtu

Reduction,

percent ppmvalb/MMBtu

457 46.9 0.056 64.3 16.8 0.020

161 64.5 0.077 74.1 16.8 0.020

288 73.7 0.088 77.2 16.8 0.020

220 83.8 0.100 80.0 16.8 0.020

ppmv at 3 percent O .

a

2
5-128

 presents a summary of data from the Mobile Oil refinery in

Torrance, California (Appendix C). These data 14
5-129
5-130

demonstrate reductions achieved by adding SCR to heaters with

existing LNBs. The reductions using SCR range from 64.3 to

80 percent. The controlled emissions range from 16.8 to 42 ppmv

at 3 percent O2 (0.020 to 0.050 lb/MMBtu). The average emission

reduction for these data is 75 percent, and the average

controlled emission level is 16.8 ppmv at 3 percent O2

(0.020 lb/MMBtu).

Appendix D presents a list of 12 Foster Wheeler process

heater SCR installations. One installation was reported using 29

SCR plus LNB. Information regarding what NOx emission controls,

if any, were used in combination with SCR was not available for

the remaining 11 installations. The guaranteed reductions ranged

from 47 to 90 percent, corresponding to NH3:NOx injection ratios

ranging from 0.7 to 1.0. The average percent reduction was

70 percent. Ten of the 12 installations had guaranteed maximum

NH3 emissions of 10 ppmv; the remaining installations had

guaranteed maximum NH3 emissions of 5 ppmv and 20 ppmv,

respectively. Only two of the installations reported excess O2

concentrations. Each reported excess O2 at 3 percent and NH3

emissions of 10 ppmv; corresponding NOx emissions were not

reported. One source reports that current SCR technology, as 29

demonstrated in utility boiler applications, is capable of

maintaining NH3 slip concentrations below 5 ppmv.28

Selective catalytic reduction can be used as a process

heater NOx control technique in combination with MD LNBs or as

the sole control technique. The data in Appendix C show that SCR

is capable of reducing, on average, 75 percent of the NOx in the

flue gas. The data in Appendix C are more complete

(i.e., uncontrolled emissions, preretrofit NOx controls,

postretrofit NOx controls and controlled emissions) than the data

in Appendix D. Therefore, Appendix C data are used as the basis

for SCR performance. For the purposes of this study, the NOx

reduction efficiency for SCR used as the sole control technique

is 75 percent. For natural gas-fired model heaters using LNBs

plus SCR, the thermal NOx reduction by LNBs is 50 percent and the

postcombustion NOx reduction by the SCR is 75 percent. The 
5-131

total effective reduction for natural gas-fired model heaters

using LNBs plus SCR is therefore 88 percent. For oil-fired model

heaters using LNBs plus SCR, the thermal NOx reduction by LNBs is

50 percent, the fuel NOx reduction by the LNBs is 25 percent and

the postcombustion NOx reduction by the SCR is 75 percent. The

total effective reductions for ND oil-fired model heaters using

LNBs plus SCR are therefore 86 and 83 percent for distillate and

residual oil-firing, respectively. The total effective reduction

for the MD oil-fired model heaters using LNBs plus SCR are

therefore 92 and 91 for distillate and residual oil-firing,

respectively.

d. SPECIAL CONSIDERATIONS

In pyrolysis, gaseous hydrocarbons such as ethane, propane,

and butane and heavier hydrocarbons such as naphtha feedstocks

are converted to olefins such as ethylene and propylene. The

basic criteria for pyrolysis furnaces are adequate control of

heat flux from inlet to outlet of the tubes, high heat transfer

rates at high temperatures, short residence times, and uniform

temperature distribution along the tube length. Several designs

are available for pyrolysis furnaces. All designs incorporate a

firebox operating at temperatures ranging from 1050E to 1250EC

(1900E to 2300NF), and most designs use the vertical box heater

configuration. As shown in Table 5-10
5-132

TABLE 5-10. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER APPLICATIONS IN THE

CHEMICAL INDUSTRY1

Chemical Process Heater type Firebox temp., EF

1985 fired heater

energy requirement

*10 Btu/yr 12

Percent of known

chemical industry

heater

requirements

Low- and medium-temperature applications

Benzene Reformate extraction Reboiler 700 64.8 9.9Styrene Ethylbenzene dehydrogenation Steam superheater 1500-1600 32.1 4.9Vinyl chloride monomer Ethylene dichloride cracking Cracking furnace NA 12.6 1.9P-xylene Xylene isomerization Reactor fired preheater NA 13.0 2.0Dimethyl terephthalate Reaction of p-xylene and

methanol

Preheater, hot oil furnace 480-540 a 11.1 1.7

Butadiene Butylene dehydrogenation Preheater, reboiler 1100 2.6 0.4Ethanol(synthetic) Ethylene hydration Preheater 750 1.3 0.2Acetone Various Hot oil furnace NA 0.8 0.1

High-temperature applications

Ethylene/propylene Thermal cracking Pyrolysis furnace 1900-2300 337.9 51.8Ammonia Natural gas reforming Steam hydrocarbon reformer 1500-1600 150.5 23.1Methanol Hydrocarbon reforming Steam hydration 1800-2000 25.7 4.0

Total known fired heater energy requirement 652.4 100

Feedstock outlet temperature. a

NA = Data not available.
5-133

, pyrolysis furnaces use approximately 50 percent of the energy

requirements of major fired heater applications in the chemical

industries.1

Postcombustion control techniques for reducing NOx from

reduction for olefins pyrolysis furnaces are limited because of

convection section designs. Retrofit of SNCR and SCR can be

difficult because of limited access to the optimal temperature

window location. One source reports that there are no known

applications of SNCR and SCR on olefins pyrolysis furnaces.27

However, it is expected that FGR, SNCR and SCR are practical

candidates for new installations. Currently, LNBs and ULNBs are

used in olefins pyrolysis furnaces. 

Selective noncatalytic reduction retrofit requires

considerable convection section reconstruction to allow multiple 
5-134

injection points and to increase the residence time. At full

load operation, the optimal temperature window for both SNCR

processes occur near the bottom of the convection section of

typical pyrolysis furnace designs and in the middle of one of the

reactor coils. The flue gas temperature drops rapidly at this

point in the convection section. Therefore, access to a suitable

temperature window and adequate residence time may be

limited.23,27,30

Similar to SNCR, at full load operations, the optimal

temperature window for SCR processes for olefins pyrolysis

furnaces occurs near the bottom of the convection section and in

the middle of one of the reactor coils. The stack temperatures

(150E to 230EC [300E to 450EF]) are generally too low for SCR

applications. In addition, plot space can be a problem for SCR

retrofit because pyrolysis furnaces are typically built adjoining

each other and are surrounded by feed, steam and fuel piping. To

allow adequate space for maintenance procedures, the SCR unit

would need to be located some distance away from the furnace it

would serve. This would require the flue gas to be routed over

this distance to reach the SCR.27,30

Coke fouling is an additional concern with using SCR on

olefins pyrolysis furnaces. During cracking operations, the

reactor coil can foul with coke deposits. These coke deposits

must be removed periodically to prevent the coil from exceeding

its metallurgical temperature limit and to avoid excessive

pressure drop. Coke is removed by removing the hydrocarbon feed

and purging the coil with steam and a small amount of air for a

period of about 12 to 48 hours to promote oxidation of the coke

deposits. The firing rate is lower than normal during this

operation (approximately 30 percent of the normal firing rate),

while the excess air value is higher (on the order of 150 percent

versus 10 percent during normal operation). The flue gas

temperature during the decoking operation is much lower than

during normal operation and is not in the optimal temperature

range for SCR operation.25
5-135

During the coke removal operation, the coke deposits are

often injected into the heater. The SCR catalyst may be fouled

if these deposits are injected into the firebox and are not

completely combusted. Also, these deposits may be injected above

the SCR unit and fall into the catalyst. Installing an SCR

system would require an alternate method of disposing of the coke

deposits. 

5

Reductions in NOx emissions have been achieved with LNB and

ULNBs in olefins pyrolysis furnaces. The achievable NOx

emission reductions using LNBs and ULNBs, however, are lower 

for pyrolysis furnace applications than for low- and mediumtemperature heater applications. Steam cracker heaters strive to

minimize coking rates in the radiant tubes and to maximize heater

run lengths. Steam reformer heaters strive to avoid exceeding

design heat densities that may either affect catalytic

conversion, sinter catalyst rings, or result in exceeding the

design allowable stress limits for the tubes. Both pyrolysis 31

heater types have process temperature and tube metal temperatures

far exceeding most conventional heaters, and greater attention

has been paid to pyrolysis burner design features than

conventional burner designs. To achieve a uniform heat 31

distribution, pyrolysis furnace burner designs use extended flame

patterns to achieve a maximum uniform heat distribution over the

tube lengths. This extended flame spreads out the combustion

zone, a design feature shared by LNBs and ULNBs. Because an

extended combustion zone is already implemented in existing

pyrolysis burner designs, potential NOx reduction percentages

using LNBs and ULNBs in pyrolysis furnaces are lower than for

low- and medium-temperature process heater applications.

Information for two new installations and several retrofit

applications of LNBs to pyrolysis furnaces was available. The

NOx emission rates for the new furnaces using LNBs were 0.103 

and 0.108 lb/MMBtu for natural gas-fired operation. For 32

retrofit applications, one source reported that the lowest

achievable controlled NOx emission rate is approximately

0.100 lb/MMBtu for natural gas-fired operation. The available 33
5-136

data and information suggest that achievable controlled NOx

emission levels for LNBs used with natural gas-fired pyrolysis

furnaces range from 0.10 to 0.011 lb/MMBtu, which represents a 15

to 30 percent reduction from the uncontrolled range of 0.13 to

0.14 lb/MMBtu. For pyrolysis model heaters with LNBs, a

25 percent NOx reduction from uncontrolled levels is used in this

study for natural gas-and refinery gas-fired applications.

For ULNBs installed in pyrolysis furnaces, one source

reported that controlled NOx emission rates for retrofit

installations are expected to range from 0.06 to 0.07 lb/MMBtu

for their proprietary burner design firing natural gas fuel.33

This controlled range represents a 44 to 59 percent reduction

from the uncontrolled range of 0.13 to 0.14 lb/MMBtu. For

pyrolysis model heaters with ULNBs, a 50 percent NOx reduction

from uncontrolled levels is used in this study for natural gasand refinery gas-fired applications. Applying Exxon's

proprietary ULNBs (not available to non-Exxon installations)

firing natural gas to a pyrolysis furnace (without preheat)

indicates that emission levels of 50 ppmv at 3 percent O2 are

achievable. Permits for five major ethylene plants in Texas 34

and Louisiana limited NOx emissions in the range of approximately

67 to 190 ppmv. 

30

As discussed in Section 4.3.1, NOx emissions increase for

refinery gas-fired operation due to the presence of hydrogen in

the fuel. The expected increase in general for NOx emissions

from refinery gas-fired operation over natural gas-fired levels

is reported by one source to be 20 to 50 percent. A second 32

source estimated the increase in NOx emissions for hydrogen fuels

to be limited 10 to 15 percent for LNB's and no appreciable

increase in NOx emissions for hydrogen fuels for ULNBs.35

e. ACHIEVABLE NOx EMISSION REDUCTIONS

This section summarizes the achievable NOx emission

reductions for those NOx control techniques currently applied to

process heaters in practice. The control techniques and

combinations of control techniques currently in use are LNBs,

ULNBs, SNCR, SCR, LNBs + FGR, LNBs + SNCR, and LNBs + SCR. 
5-137

Natural to mechanical draft conversion and LEA operation are not

considered stand alone NOx control techniques in this study

because they are currently considered operational techniques. 

However, the difference in NOx emissions and the degree of

retrofit or construction between control techniques operated with

ND and control techniques operated with MD is substantial and is

considered. The performance of staged-fuel and staged-air LNB

overlap, and for the purposes of this study all types of LNBs are

collectively referred to as LNBs. Low-NOx burners have replaced

staged combustion using air lances as current burner technology. 

Therefore, staged combustion using air lances is not considered

further. 

To develop NOx emission reductions, each of the current

control techniques was applied to each of the model heaters

developed in Chapter 4. Tables 5-11
5-138

TABLE 5-11. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND, NATURAL

GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS

Model heater

capacity, 

MMBtu/yr

Uncontrolled NOx

emission

factor,

lb/MMBtua

NO control technique x

Total effective

reduction,

percent

Controlled

NOx

emissions, 

lb/MMBtu

ControlledN

Ox

emissions,

ppm @ 3%

O2

NOx

reduction,

ton/yre

17 0.098 (ND) LNB 50b0.049 41 3.65

(ND) ULNB 75c

0.025 21 5.47

(ND) SNCR 60d

0.039 33 4.38

(ND) LNB + (ND) SNCR 80b,d 0.020 16 5.84

36 0.098 (ND) LNB 50b

0.049 41 7.73

(ND) ULNB 75c

0.025 21 11.6 

(ND) SNCR 60d

0.039 33 9.27

(ND) LNB + (ND) SNCR 80b,d 0.020 16 12.36

77 0.098 (ND) LNB 50b

0.049 41 16.5

(ND) ULNB 75c

0.025 21 24.8

(ND) SNCR 60d

0.039 33 19.8

(ND) LNB + (ND) SCNR 80b,d 0.020 16 26.44

121 0.098 (ND) LNB 50b

0.049 41 26.0 

(ND) ULNB 75c

0.025 21 39.0 

(ND) SNCR 60d

0.039 33 31.2 

(ND) LNB + (ND) SNCR 80b,d 0.020 16 41.55

186 0.098 (ND) LNB 50b

0.049 41 39.9

(ND) ULNB 75c

0.025 21 60.0 

(ND) SNCR 60d

0.039 33 47.9 

(ND) LNB + (ND) SNCR 80b,d 0.020 16 63.87

Uncontrolled emissions for natural gas-fired heaters are from thermal NO formation. a

x

Reductions from LNB's represent a 50 percent reduction of thermal NO . This reduction was adopted from b

x

 Reference 5.

Reductions from ULNB's represent a 75 percent reduction of thermal NO . This reduction was adapted from c

x

 Reference 14.

Postcombustion NO reduction by SNCR is 60 percent. This reduction was adopted from Reference 7. d

x

Reduction (tons/yr) equals the Capacity (MMBtu/hr) x NO reduced (lb NO /MMBtu) x 1 ton per 2,000 lb x e

x x

 8,760 hr/yr; where NO reduced is equal to uncontrolled emission factor minus the controlled emission factor. x
5-139

TABLE 5-12. MODEL HEATERS: CONTROLLED EMISSIONS FOR MD,

NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS

Model heater

capacity,

MMBtu/hr

Uncontrolled NOx

emission factor,

lb/MMBtua

NO control technique x

Total effective

reduction,

percent

Controlled

NOx

emissions, 

lb/MMBtu

Controlled NOx

emissions, 

ppmv

@ 3% O2

tion, NO reduc x

tons/yrg

40 0.197 (MD) LNB 50b0.099 82 17.3

(MD) ULNB 75c

0.049 41 25.9

(MD) SNCR 60d

0.079 66 20.7

(MD) SCR 75e

0.049 41 25.9

(MD) LNB + FGR 55f

0.089 74 19.0

(MD) LNB + SNCR 80b,d 0.039 33 27.6

(MD) LNB + SCRg

88b,e 0.025 21 30.2

77 0.197 (MD) LNB 50b

0.099 82 33.2

(MD) ULNB 75c

0.049 41 49.8

(MD) SNCR 60d

0.079 66 39.9

(MD) SCR 75e

0.049 41 49.8

(MD) LNB + FGR 55f

0.089 74 36.5

(MD) LNB + SNCR 80b,d 0.039 33 53.2

(MD) LNB + SCR 88b,e 0.025 21 58.1

114 0.197 (MD) LNB 50b

0.099 82 49.2

(MD) ULNB 75c

0.049 41 73.8

(MD) SNCR 60d

0.079 66 59.0

(MD) SCR 75e

0.049 41 73.8

(MD) LNB + FGR 55f

0.089 74 54.1

(MD) LNB + SNCR 80b,d 0.039 33 78.7

(MD) LNB + SCR 88b,e 0.025 21 86.1

174 0.197 (MD) LNB 50b

0.099 82 75.1

(MD) ULNB 75c

0.049 41 113

(MD) SNCR 60d

0.079 66 90.1

(MD) SCR 75e

0.049 41 113

(MD) LNB + FGR 55f

0.089 74 82.6

(MD) LNB + SNCR 80b,d 0.039 33 120

(MD) LNB + SCR 88b,e 0.025 21 131

263 0.197 (MD) LNB 50b

0.099 82 113

(MD) ULNB 75c

0.049 41 170

(MD) SNCR 60d

0.079 66 136

(MD) SCR 75e

0.049 41 170

(MD) LNB + FGR 55f

0.089 74 125

(MD) LNB + SNCR 80b,d 0.039 33 182

(MD) LNB + SCR 88b,e 0.025 21 199

Uncontrolled emissions for natural gas-fired heaters are from thermal NO formation. a

x

Reductions from LNB's represent a 50 percent reduction of thermal NO . This reduction was adopted from b

x

Reference 5.

Reductions from ULNB's represent a 75 percent reduction of thermal NO . This reduction was adapted from c

x

Reference 14.
5-140

TABLE 5-13. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND OIL-FIRED HEATERS

Model

heater

capacity,

MMBtu/hr

Fuel

Uncontrolled

emission factor,

lb/MMBtu

technique

NO control x

NO emission reduction, percent x Controlled

NOx

emission,

lb/MMBtu

Controlled

NOx

emissions,

ppmv

NOx

reduction,

tons/yrc

Thermal

NOxa

Fuel

NOxb Thermal

NOx

Fuel

NOx

Post- combus- tion Total effective reduction

69 Distillate oil 0.14 0.06 (ND) LNB d 50 15 N/A 40 0.121 101 23.9

(ND) ULNBe 75 78 N/A 76 0.048 40.4 45.9(ND) SNCRf N/A N/A 60 60 0.080 67.0 36.3(ND) LNB + (ND) SNCRd,f 50 15 60 76 0.048 40.5 45.8

69 Residual oil 0.14 0.28 (ND) LNB d 50 15 N/A 27 0.308 258 33.8

(ND) ULNBe 75 78 N/A 77 0.097 80.9 97.7(ND) SNCRf N/A N/A 60 60 0.168 140 76.2(ND) LNB + (ND) SNCRd,f 50 15 60 71 0.123 103 89.7

N/A = Not applicable.

Uncontrolled emission factor for thermal NO represents the NO from thermal NO formation. a x x x

Uncontrolled emission factor for fuel NO represents the NO from fuel NO formation. b x x x

Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NO reduced (lb NO /MMBtu) * 1 ton per 2000 lb * 8,760 hr/yr, c x x

where NO reduced is equal to the uncontrolled emission factor minus the controlled emission factor. x

These reductions were adopted from References 5 and 7. d

These reductions were adapted from References 7 and 14. e

These reductions were adopted from Reference 7. f

 through 5-15 
5-141

TABLE 5-14. MODEL HEATERS: CONTROLLED EMISSIONS FOR MD

OIL-FIRED HEATERS

Model heater

capacity,

MMBtu/hr

Fuel

Uncontrolled

emission factor,

lb/MMBtu

NO control x

technique

NO emission reduction, percent x

Controlled

NOx

emissions,

lb/MMBtu

Controlled NOx

emissions, ppmv

NO reduction, x

tons/yrc

Thermal

NOxa

Fuel

NOxb

Thermal NOx Fuel NOx Postcombustion

Total

effective

reduction

135 Distillate oil 0.26 0.06 LNB d 50 25 N/A 45 0.175 139 85.7

ULNBe 75 72 N/A 74 0.082 64.9 141SNCRf N/A N/A 60 60 0.128 102 114SCRg N/A N/A 75 75 0.080 63.5 142LNB + FGRh 55 15 N/A 48 0.168 133 89.9LNB + SNCRd,f 50 25 60 78 0.070 55.6 148LNB + SCRd,g 50 25 75 92 0.026 20.8 174

135 Residual 0.26 0.28 LNB d 50 25 N/A 37 0.340 270 118

ULNBe 75 72 N/A 73 0.143 114 235SNCRf N/A N/A 60 60 0.216 171 192SCRg N/A N/A 75 75 0.135 107 240LNB + FGRh 55 15 N/A 34 0.355 282 109LNB + SNCRd,f 50 25 60 75 0.136 108 239LNB + SCRd,g 50 25 75 91 0.051 40.5 289

N/A = Not applicable.

Uncontrolled emission factor for thermal NO represents the NO from thermal NO formation. a x x x

Uncontrolled emission factor for fuel NO represents the NO from fuel NO formation. b x x x

Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NO reduced (lb NO /MMBtu) * 1 ton per 2000 lb * 8,760 hr/yr; where NO reduced is equal to the c x x x

uncontrolled emission factor minus the controlled emission factor.

These reductions were adopted from References 5 and 7. d

These reductions were adapted from References 7 and 14. e

These reductions were adopted from Reference 7. f

These reductions were adapted from Reference 14. g
5-142

TABLE 5-15. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND OLEFINS PYROLYSIS HEATERS

Model heater

capacity, M

MBtu/hr Fuel

Uncontrolled N

Ox

emission factor,

lb/M

MBtu

a N

O control technique x

Total effective

reduction, percent

Controlled N

Ox

emissions, lb/M

MBtu Controlled N

O x

emissions, ppmv

N

O reduction, ton/yr x

h

84 Natural gas 0.135 (N

D) L

NB 25 0.101 85 12.4

(M

D) L

NB

b

25

c

0.101 85 12.4

(N

D) U

L

NB 50

d

0.068 57 24.8

(M

D) U

L

NB

b

50

d

0.068 57 24.8

(N

D) SN

C

R 60

e

0.054 45 29.8

(M

D) SN

C

R

b

60

e

0.054 45 29.8

SC

R

b

75

f

0.034 28 37.3

L

NB + FG

R

b

55

g

0.061 51 27.3

(N

D) L

NB + SN

C

R

b

70

c,e

0.041 34 34.8

(M

D) L

NB + SN

C

R

b

70

c,e

0.041 34 34.8

L

NB + SC

R

b

81

c,f

0.026 21 40.4

84 High-hydrogen

fuel gas

0.162 (N

D) L

NB 25

c

0.123 343 14.9

(M

D) L

NB

b

25

c

0.123 343 14.9

(N

D) U

L

NB 50

d

0.081 229 29.8

(M

D) U

L

NB

b

50

d

0.081 229 29.8

(N

D) SN

C

R 60

e

0.065 183 35.8

(M

D) SN

C

R

b

60

e

0.065 183 35.8

(SC

R)

b

75

f

0.041 114 44.7

L

NB + FG

R

b

55

g

0.073 206 32.8

(N

D) L

NB + SN

C

R

b

70

c,e

0.049 137 41.7

(M

D) L

NB + SN

C

R

b

70

c,e

0.049 137 41.7

L

NB + SC

R

b

81

c,f

0.031 86 48.4

Uncontrolled emissions for natural gas-fired heaters are from thermal N

O formation.

a

x

E

mission reductions are based on N

D emission factors using a 100 percent capacity utilization.

b

Reductions from

L

NB's represent a 25 percent reduction of thermal N

O .

c

x

Reductions from

U

L

NB's represent a 50 percent reduction of thermal N

O .

d

x

Postcombustion N

O reduction by SN

C

R is 60 percent. This reduction was adapted from

Reference 7.

e

x

Postcombustion N

O reduction by SC

R is 75 percent. This reduction was adapted from

Reference 14.

f

x

Reductions from

L

NB + FG

R represent a 55 percent reduction of thermal N

O . This reduction was adapted from

Reference 7.

g

x

Reduction (ton/yr) equals the Capacity (M

MBtu/hr) * N

O reduced (lb N

O /M

MBtu) * 1 ton per 2000 lb * 8,760 hr/yr, where N

O reduced is equal to the uncontrolled emission factor minus the

h

x x x

present achievable NOx reductions, controlled emissions, and
5-143

emission reductions for 8,760 hours of operation per year

(capacity factor of 1.0). The percent reductions used in

Tables 5-11 through 5-15 represent reductions derived from

available data or published information concerning process

heaters. The controlled emissions were calculated by applying

the percent reductions of each control technique to the

uncontrolled emission factors of each model heater. The total

effective reduction percentage is listed for each control

technique. Thermal, fuel and postcombustion NOx percent

reductions are listed for the control techniques applied to the

oil-fired model heaters because it is necessary to apply the

appropriate percent reductions to the uncontrolled emission

factors. For example, the thermal NOx percent reductions should

be applied to the thermal NOx uncontrolled emission factors and

the fuel NOx percent reductions should be applied to the fuel NOx

uncontrolled emission factors. The postcombustion NOx percent

reductions refer to the reductions achieved by SNCR and SCR. 

Because these reductions occur downstream of the firebox, the

postcombustion NOx percent reductions should be applied to the 
5-144
5-145
5-146
5-147
5-148

amount of NOx remaining after reductions of combustion controls

have been applied. 

Table 5-11 presents the performance of the available control

techniques applied to the ND, natural gas-fired, low- and medium

temperature model heaters. The controlled NOx emissions range

from 0.021 lb/MMBtu for LNB plus SCR to 0.072 lb/MMBtu for LNB.

Table 5-12 presents the performance of the available control

techniques applied to the MD, natural gas-fired, low- and mediumtemperature model heaters. The controlled NOx emissions range

from 0.021 lb/MMBtu for LNBs plus SCR to 0.089 lb/MMBtu for LNBs

plus FGR.

The percent reductions in Table 5-13 for the ND oil-fired

model heater are listed for thermal, fuel and postcombustion NOx

reductions. The controlled NOx emissions for the distillate

oil-fired model heater range from 0.048 lb/MMBtu for ULNBs to

0.121 lb/MMBtu for LNBs. The controlled NOx emissions for the

residual oil-fired model heater range from 0.097 lb/MMBtu for

ULNB to 0.308 lb/MMBtu for LNBs.

The percent reductions in Table 5-14 for the MD oil-fired

model heater are listed for thermal, fuel, and postcombustion NOx

reductions. The controlled NOx emissions for the distillate

oil-fired model heater range from 0.026 lb/MMBtu for LNBs plus

SCR to 0.175 lb/MMBtu for LNBs. The controlled NOx emissions for

the residual oil-fired model heater range from 0.051 lb/MMBtu for

LNBs plus SCR to 0.319 lb/MMBtu for LNBs plus FGR.

Table 5-15 presents the performance of the available control

techniques applied to the olefins pyrolysis model heaters. The

controlled NOx emissions for the natural gas-fired model heater

range from 0.026 lb/MMBtu for LNBs plus SCR to 0.101 lb/MMBtu for

LNBs. The controlled NOx emissions for the high-hydrogen fuelfired model heater range from 0.031 lb/MMBtu for LNBs plus SCR to

0.123 lb/MMBtu for LNBs.

Again, it is important to recognize that the percent

emission reductions listed in Tables 5-11 through 5-15 represent

the available data collected and in some cases corresponds to a

specified emission limit rather than the maximum achievable
5-149

percent emission reduction. For example, the use of LNB plus SCR

is likely capable of an overall NOx emissions reduction of over

90 percent; however, available data show an average reduction of

75 percent for SCR, which represents the level of control needed

to meet an emission limit.

f. REFERENCES FOR CHAPTER 5

 1 Shareef, A., C. Anderson, and L. Keller (Radian

Corporation). Fired Heaters: Nitrogen Oxides Emissions and

Controls. June 29, 1988.

 2 Project Summary. Evaluation of Natural- and Forced-Draft

Staging Air Systems for Nitric Oxide Reduction in Refinery

Process Heaters. EPA-600/S7-84-080. September 1984.

 3 Project Summary. Guidelines for the Reduction of Emissions

& Efficiency Improvements for Refinery Process Heaters. 

EPA-600/S8-83-017. June 1983.

 4 Project Summary. Thirty-Day Field Test of a Refinery

Process Heater Equipped with Low-NOx Burners. 

EPA-600/S7-83-010. April 1983.

 5 Letter and attachments from Eichamer, P., Exxon Chemical

Company, to Neuffer, W., EPA/ISB. September 2, 1992. 

Comments on Draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

 6 Letter and attachments from Laffly, G., American Petroleum

Institute, to Neuffer, W., EPA/ISB. August 10, 1992. 

Comments on Draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

 7 A Study to Assess the Available Technology and Associated

Costs of Reducing NOx Emissions From the Canadian Petroleum

Refining Industry. Canadian Petroleum Products Institute. 

CPPI Report No. 91-1. November 28, 1990.

 8 Campbell, L., D. Stone, and G. Shareef (Radian Corporation). 

EPA-600/2-91-029. July 1991. Sourcebook: NOx Control

Technology Data. 

 9 Letter from Martin, R., Callidus Technologies Incorporated,

to Neuffer, W., EPA/ISB. January 26, 1993. Comments on

Draft Alternative Control Techniques Document--Control of

NOx Emissions from Process Heaters.

10 Waibel, R. (John Zink Company). Low Emission Burners for 

Steam Generation. IGT Conference and Exhibition. April 13

and 14, 1988.
5-150

11 Letter from Craig, R. Unocal Science and Technology

Division, to Lee, L., California Air Resources Board. 

July 24, 1991. Information concerning NOx reduction in a

cogeneration facility.

12 Waibel, R. (John Zink Company). Advanced Burner Technology

for Stringent NOx Regulations. Presented at American

Petroleum Institute Midyear Refining Meeting. May 8, 1990.

13 Letter and attachments from Quiel, J., North American

Manufacturing Company, to Neuffer, W., EPA/ISB. May 1991. 

Low NOx burner and FGR information from manufacturer.

14 Letter and attachments from Britt, J., Mobil Oil

Corporation, to Jordan, B., EPA/ESD. April 29, 1992. 

Process heater NOx emission control retrofit experience at

Mobil's Torrance, CA, petroleum refinery.

15 Letter and attachments from Grever, A., Selas, to Neuffer,

W., EPA/ISB. December 29, 1992. Comments on Draft

Alternative Control Techniques Document--Control of NOx

Emissions from Process Heaters.

16 Letter and attachments from Davis, L., Exxon, Baton Rouge to

Harris, R., MRI. February 7, 1992. Refinery Inventory of

Process Heaters.

17 Letter and attachments from Johnson, W., John Zink Company, 

to Hamilton, R., Texas Air Control Board. December 5, 1990.

Meeting SCAQMD Rules 1109 and 1146 with Low-NOx Burners. 

Presented by Waibel, R., PhD. 

18 Minden, A., and P. Gilmore. NOx Control in Gas-Fired

Refinery Process Heaters Using Pyrocore Radiant Burners. 

Paper presented at 1988 Fall Meeting of Western States

Section/The Combustion Institute. October 17-18, 1988.

19 Minden, A., D. Perkins, J. Kennedy (Alzeta Corp.). Premixed

Radiant Burners: Improved Process Performance with UltraLow NOx Emissions. Combustion Institute. 1990.

20 Letter and attachments from Moreno, F., Alzeta Corporation,

to Sanderford, E., MRI. July 1992. Cost comparison between

ND and MD conventional burners versus Alzeta burners.

21 Letter and attachments from Moreno, F., Alzeta Corporation,

to Sanderford, E., MRI. June 3, 1992. Control of NOx using

Alzeta burners.

22 McInnes, R., and M.B. Van Wormer. Cleaning Up NOx

Emissions. Chemical Engineering. Vol. 130-135. 

September 1990.
5-151

23 Letter and attachments from Pickens, R., Nalco Fuel Tech, to

Neuffer, W., EPA/ISB. August 7, 1992. Comments on Draft

Alternative Control Techniques Document--Control of NOx

Emissions from Process Heaters.

24 Letter and attachments from Haas, G., Exxon Research and

Engineering Company, to Lazzo, D., MRI. January 14, 1991. 

Thermal DeNOx installation list. ®

25 Teixeira, D. Widening the Urea Temperature Window. 

Pacific Gas and Electric Company. Paper presented at 1991

EPA\EPRI Joint Symposium.

26 Letter and attachments from Pickens, R., Nalco Fuel

Technologies, to Snyder, R., MRI. February 5, 1992. Data

for NOxOUT® installations.

27 Letter and attachments from Strickland, G., Chemical

Manufacturers Association, to Neuffer, W., EPA/ISB. 

September 9, 1992. Comments on Draft Alternative Control

Techniques Document--Control of NOx Emissions from Process

Heaters.

28 Letter and attachments from Wax, M., Institute of Clean Air

Companies, to Neuffer, W., EPA/ISB. August 27, 1992. 

Comments on Draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

29 Letter and attachments from Franklin, H., Foster Wheeler

Energy Corporation, to Neuffer, W., EPA/ISB. April 27,

1992. Process heater SCR experience.

30 Gomma H., L. Hackemesser, and D. Cindric. NOx/CO Emissions

and Control in Ethylene Plants. Environmental Progress.

10(4). November 1991.

31 Letter and Eichamer, P. D., and N. L. Morrow, Exxon Chemical

Company, to Neuffer, W. J., EPA/ISB. July 7, 1993. NOx

reductions in pyrolysis furnaces. 

32 Letter from Moran, E. J., Chemical Manufacturers

Association, to Neuffer, W. J., EPA/ISB. July 22, 1993. 

NOx reductions in pyrolysis furnaces using low-NOx burners.

33 Letter from Eichamer, P. D., and N. L. Morrow, Exxon

Chemical Company, to Neuffer, W. J., EPA/ISB. June 7, 1993. 

NOx reductions in pyrolysis furnaces.
5-152

34 Letter and attachments from Morrow, N., Exxon Chemical

Group, to Harris, R., MRI. February 24, 1992. Low-NOx

burner experience at basic chemicals plant.

35 Letter from Eichamer, P. D., and N. L. Morrow, Exxon

Chemical Company, to Neuffer, W. J., EPA/ISB. July 19,

1993. Effect of hydrogen fuel content on NOx reductions in

pyrolysis furnaces.
6..0 CONTROL COSTS

This chapter presents capital and annual costs and cost

effectiveness for the NOx emission control techniques described

in Chapter 5. These control techniques are applied to the model

heaters presented in Chapters 4 and 5. The NOx control

techniques are low-NOx burners (LNBs), ultra low-NOx burners

(ULNBs), selective noncatalytic reduction (SNCR), selective

catalytic reduction (SCR), LNBs combined with flue gas

recirculation (FGR), LNBs combined with SNCR, and LNBs combined

with SCR. These control techniques were selected because they

are currently used to control NOx emissions.

Cost estimates are highly variable, and accurate estimates

can only be made on a case-by-case basis. The costs presented in

this study give approximate costs of implementing the available

control techniques. Costing methodologies from References 1 and

2 are used to estimate the costs. These methodologies estimate

the costs of retrofitting control techniques on process

heaters. It is expected that the cost of incorporating a 1,2

control technique in the design of a new process heater is less

than retrofitting a similar heater with the same control

technique.

Capital and annual cost methodologies for NOx control

techniques applied to the model heaters are presented in

Section 6.1. The total annual costs (TAC) for the NOx control

techniques applied to the model heaters are presented in

Section 6.2. The cost effectiveness of the NOx control

techniques applied to the model heaters is presented in

Section 6.3. Radiant burner costs are discussed in Section 6.4;

radiant burners are not included in the model heater cost
6-2

analysis due to limited costing information. Section 6.5 lists

the references used in this chapter. 

a. CAPITAL AND ANNUAL COSTS METHODOLOGIES

The methodology used to develop capital costs is essentially

the same for each NOx control technique. Because available cost

data for this study were limited, capital cost methodologies from

References 1 and 2 were used to develop capital costs for each

individual control technique. The capital costs were updated to

1991 U.S. dollars using the Chemical Engineering plant cost

index. Capital costs for combinations of controls are the sum 3

of the capital costs of the individual control techniques.

The TAC for the NOx control techniques comprises the annual

operating costs of chemicals, electricity, fuel, and maintenance. 

The costs, in 1991 dollars, for electricity, fuel, chemical

reactants, and maintenance are shown in Table 6-1
6-3

TABLE 6-1. UTILITY, CHEMICAL, AND MAINTENANCE COSTS

Electricitya $0.06/kWh

Natural gasb $2.00/MMBtu

Distillate fuel oilc $5.54/MMBtu

Residual fuel oilc $3.00/MMBtu

Ammoniad $0.125/lb

Maintenancee 2.75% of capital cost

Reference 4, Table 5-10. a

Reference 5. b

Reference 6. c

Reference 2. d

Reference 1. e
6-4

. Capital and annual costs for LNBs, ULNBs, SNCR, SCR, FGR, LNBs

plus SNCR, and LNBs plus SCR are presented in Sections 6.1.1

through 6.1.7, respectively. Each of these sections presents the

methodology used to develop capital and annual costs. Natural

draft (ND)-to-mechanical draft (MD) conversion is not considered

a stand-alone control technique but is required to implement some

control techniques. The capital and annual costs of ND-to-MD

conversion are considerable and are presented in Section 6.1.8. 

i. Costs of LNBs

(1) Capital Costs of LNBs. The LNB capital cost

methodology from Reference 1 was used to calculate the capital

cost of applying LNBs to process heaters. The primary parameters

affecting the capital cost include the following:

1. Heater capacity;

2. Number of burners;

3. Burner heat release rate; and

4. Natural or forced draft combustion air delivery system.1

The capital cost methodology from Reference 1 for ND heaters is:

TIC = 30,000 + HQ [5,230 - (622 x BQ) + (26.1 x BQ )] 2
6-5

where:

TIC = total capital installed cost;

 HQ = heater capacity (GJ/hr); and

 BQ = burner heat release rate (GJ/hr)

and

BQ = HQ/NB x (1.158 + 8/HQ)

where:

NB = number of burners.

The LNB capital cost for MD heaters is calculated to be

50 percent higher than the capital cost for ND heaters. This

additional cost is added to account for the following:

1. Increased LNB cost;

2. Additional excess air control equipment; and

3. Combustion air plenum modification.1

The capital cost methodology for MD LNBs is:

TIC = 1.5 x {30,000 + HQ x [5,230 - (622 x BQ) + 

(26.1 x BQ )]}. 2

The cost methodologies give costs in Canadian average 1990

dollars. For this analysis, the capital costs have been

escalated to U.S. average 1991 dollars using the Chemical

Engineering plant cost index and an exchange rate of 1 U.S.

dollar to 1.15 Canadian dollars.3

The cost of the burners, although substantial, represents a

fraction of the actual installed costs. Large cost variations

for LNB retrofit installations can occur when floor rebuilding is

required and space limitations below the heater exist. Typical

LNBs do not fit standard burner mounts and may require complete

floor rebuilds and refractory replacement. Not all heaters can

be retrofitted with current LNB designs. The primary variable

influencing the feasibility of an LNB retrofit is the space

requirement below the heater necessary to install the combustion

air plenums.8,9

(2) Operating Costs of LNBs. Maintenance costs of 

LNBs are calculated as 2.75 percent of the LNBs capital 

costs. Installation of LNBs can improve heater efficiency, 1,2

although this effect (if any) will be strongly heater-dependent. 
6-6

The potential increase in heater efficiency may lower fuel costs. 

Operational costs may be marginally increased due to the decrease

in flame stability and the potential for flame-out. These 1,8

operational impacts will tend to offset one another in the cost

analysis associated with LNB installation and minimize the effect

of the current analysis. These costs are site-specific and are 1

not included in the cost analysis.

ii. Cost of ULNBs

(1) Capital Costs of ULNBs. The capital costs of ULNBs are

affected by the same parameters as LNBs. The primary parameters

that affect the capital costs include:

1. Heater capacity;

2. Number of burners;

3. Burner heat release rate; and

4. Natural or mechanical draft combustion air delivery

system.

The capital cost methodology for ND ULNBs is:

TIC = 35,000 + {HQ x [5,230 - (622 x BQ) + (26.1 x BQ )]}. 2

In the case of MD heaters, an additional 50 percent is added

to the capital cost to account for the following:

1. Additional excess air control equipment; and

2. Increased combustion air plenum construction.

The capital cost methodology for MD ULNBs is:

TIC = 1.5 x {35,000 + HQ x [5,230 - (622 x BQ) +

(26.1 x BQ )]}. 2

The cost methodologies give costs in Canadian average

1990 dollars. For this analysis, the capital costs have been

escalated to U.S. average 1991 dollars using the Chemical

Engineering plant index and an exchange rate of 1 U.S. dollar to

1.15 Canadian dollars.3

Similar to LNBs, large cost variations for ULNBs retrofit

can exist. The cost variations and variables influencing the use

of LNBs described in Section 6.1.1.1 also apply to ULNBs.

(2) Operating Costs of ULNBs. Maintenance costs of ULNBs

are calculated as 2.75 percent of the ULNBs capital costs.1,2
6-7

Operating costs for LNBs described in Section 6.1.1.2 also apply

to ULNBs.

iii. Costs of SNCR

(1) Capital Costs of SNCR. The SNCR capital cost

methodology from Reference 1 has been used to calculate the

capital cost of installing SNCR in process heaters. The cost

methodology in Reference 1 uses data from Exxon's Thermal DeNOx®

(TDN®) process because Nalco Fuel Tech's process to date has been

installed on only a limited number of refinery heaters. The

major capital costs for SNCR systems are for the ductwork,

reactant storage tank and injection system, insulation, control

instrumentation, engineering, and installation. The capital cost

methodology for SNCR from Reference 1 is:

TIC = 31,850 (HQ)0.6

where: 

HQ is the heater capacity, in gigajoules 

per hour (GJ/hr).

The cost methodology gives costs in Canadian average 1990

dollars. For this analysis, capital costs have been escalated to

U.S. average 1991 dollars using the Chemical Engineering plant

index and an exchange rate of 1 U.S. Dollar to 1.15 Canadian

dollars.3

(2) Operating Costs of SNCR. The SNCR annual operating

cost models from References 1 and 2 are used to calculate the

annual operating costs of SNCR operation. Maintenance costs of

SNCR are calculated as 2.75 percent of the SNCR capital costs.1,2

The operating costs include the cost of ammonia reactant,

additional electricity, and additional fuel. The Reference 2

cost model was used to calculate the operating costs for NH3 and

electricity. The fuel penalty results from a loss of heater

thermal efficiency due to dilution of the hot flue gas with steam

or cold distribution air, which lowers the convection section

heat recovery. The loss in efficiency is estimated to require a 1

0.3 percent increase in fuel firing. The cost of the fuel

penalty is calculated as a 0.3 percent increase in firing rate.9
6-8

The cost methodologies for the annual operating costs of

SNCR are:

NH3 cost = (Q) x (lb NOx/MMBtu) x (1 mole

NO2/46 lb NO2) x (17 lb NH3/1 mole

NH3) x (mole NH3/mole NOx) x

($0.125/lb NH3) x (8,760 hr/yr) x CF,

Electricity cost = (0.3 kWh/ton NH3) x (ton NH3/yr) x

($0.06/kWh) x CF

Fuel penalty cost = (0.03) x (Q) x (8,760 hr/yr) x (fuel

cost $/MMBtu) x CF,

where: 

Q = heater capacity, MMBtu/hr, and 

CF = capacity factor expressed in decimal form.1,2,10

iv. Costs of SCR

(1) Capital Costs of SCR. The SCR capital cost methodology

from Reference 2 was used to calculate the capital cost of

installing SCR in process heaters. The major capital costs for

SCR systems are for the reactor section (including catalyst),

ductwork, ammonia storage tank and injection system, foundation,

insulation, control instrumentation, engineering, and

installation. Selective catalytic reductions systems require 2,11

mechanical draft operation due to the pressure drop across the

catalyst. The costs for SCR applied to the ND model heaters

includes the costs of converting to MD operation in addition to

the SCR costs.2

The capital cost model from Reference 2 is:

TIC = 1,373,000 x (Q/48.5) + 49,000 x (Q/485), 0.6

where:

Q = heater capacity, MMBtu/hr.2

The cost methodology gives costs in U.S. average 1986

dollars. For this analysis, capital costs have been escalated to

U.S. average 1991 dollars using the Chemical Engineering plant

index.3

(2) Operating Costs of SCR. The SCR annual operating costs

were calculated using the methodologies from Reference 2. The

operating costs include the cost of the ammonia reactant,
6-9

catalyst replacement, additional electricity and additional fuel. 

The Reference 2 cost methodology was used to calculate the NH3,

catalyst replacement, and electricity costs. A 1 to 2 percent

loss of heater thermal efficiency can be expected due to dilution

of the hot flue gas with cold distribution air, which lowers

convection section heat recovery. This loss of efficiency is

represented by a fuel penalty; the cost of the fuel penalty is

estimated to require a 1.5 percent increase in fuel consumption.1

The cost methodology for annual operating costs of SCR:

NH3 cost = (Q) x (lb NOx/MMBtu) x (1 mole

NO2/46 lb NO2) x (17 lb NH3/1 mole

NH3) x (mole NH3/mole NOx) x

($0.125/lb NH3) x (8,760 hr/yr) x

CF;

Catalyst replacement cost = 49,000 x (Q/48.5)/5 yr

Electricity cost = (0.3 kWh/ton NH3) x (ton NH3) x

($0.06/kWh) x CF, and

Fuel penalty cost = (0.015) x (Q) x (8,760 hr/yr) x

(fuel cost $/MMBtu) x CF,

where:

Q = heater capacity, MMBtu/hr, and 

CF = capacity factor expressed in decimal form. 

Maintenance costs for SCR are calculated as 2.75 percent of

the SCR capital cost.1,2

v. Costs of FGR

(1) Capital Costs of FGR. The FGR capital cost methodology

from Reference 1 is used to calculate the capital cost of

installing an FGR system in process heaters. The capital cost

model for FGR from Reference 1 is:

TIC = 12,800 (HQ)0.6

where:

HQ = heater capacity, GJ/hr.1

The cost methodology gives cost in Canadian average

1990 dollars. For this analysis, the capital costs have been

escalated to U.S. average 1991 dollars using the Chemical
6-10

Engineering plant index and an exchange rate of 1 U.S. dollar to

1.15 Canadian dollars.3

As discussed in Chapter 5, FGR is not considered to be a

stand-alone NOx control technique but is typically combined with

LNBs. Flue gas recirculation requires an MD combustion air

supply. For ND heaters, implementing FGR as a NOx control

technique incurs the following capital costs: ND-to-MD

conversion, MD LNBs, and the FGR system.

The cost methodology is based on boiler data because process

heater applications of FGR are limited. An additional

consideration for FGR is the high-temperature flue gas associated

with process heaters. Boilers use economizers to recover a large

amount of thermal energy from the flue gas in boilers. Process

heaters do not have economizers and therefore have higher flue

gas temperatures than do boilers. Flue gas recirculation fans

capable of handling the high-temperature flue gas from process

heaters may increase the cost of implementing FGR over the costs

presented in this chapter.

(2) Operating Costs of FGR. The FGR annual operating cost

model from Reference 2 has been used to calculate the annual

operating costs of FGR operation. The primary cost associated

with FGR operation is the additional electrical energy required

to operate the FGR fan. The annual cost model for FGR from

Reference 2 is presented below:

Electric power cost = (motor hp) x (0.75 kW/hp) x

(8,760 hr/yr) x ($0.06/kWh) x CF

where:

motor hp = FGR fan motor horsepower, (1/5) x (Q);

Q = process heater capacity in MMBtu/hr, and

CF = heater capacity factor.

Maintenance costs for FGR are calculated as 2.75 percent of

the capital cost.1,2

vi. Costs of LNBs Plus SNCR

(1) Capital Costs of LNBs Plus SNCR. The capital cost of

LNBs plus SNCR is the sum of the capital cost of LNBs, presented

in Section 6.1.1.1, and the capital cost of SNCR, presented in
6-11

Section 6.1.3.1. Selective noncatalytic reduction systems may be

applied to ND or MD systems without modifications to the draft

system. Therefore, either ND LNBs or MD LNBs may be combined

with SNCR.

(2) Operating Costs of LNBs Plus SNCR. The operating and

maintenance costs of LNBs plus SNCR are the sum of the operating

and maintenance costs for LNBs, presented in Section 6.1.1.2, and

the operating and maintenance costs for SNCR, presented in

Section 6.1.3.2.

vii. Costs of LNBs Plus SCR

(1) Capital Costs of LNBs Plus SCR. The capital cost of

LNBs plus SCR is the sum of the capital cost of LNBs, presented

in Section 6.1.1.1, and the capital cost of SCR, presented in

Section 6.1.4.1. Selective catalytic reduction systems require

MD operation. Therefore, ND heaters must be converted to MD

operation for SCR. 

(2) Operating Costs of LNBs Plus SCR. The operating and

maintenance costs of LNBs plus SCR are the sum of the operating

and maintenance costs for LNBs, presented in Section 6.1.1.2, and

the operating and maintenance costs for SCR, presented in

Section 6.1.4.2. 

viii. Costs of ND-to-MD Conversion

(1) Capital Costs of ND-to-MD Conversion. The ND-to-MD

conversion capital cost methodology from Reference 1 is applied

to calculate the capital cost of converting process heaters from

ND to MD. The capital cost model for ND-to-MD conversion from

Reference 1 is:

TIC = 21,350 (HQ)0.6

where:

HQ = heater capacity, GJ/hr.1

The cost methodology gives costs in Canadian average 1991

dollars. For this analysis, capital costs have been escalated to

U.S. 1991 dollars using the Chemical Engineering plant indexes

and an exchange rate of 1 U.S. dollar to 1.15 Canadian dollars.3

As discussed in Chapter 5, ND-to-MD conversion is generally

not performed as a stand-alone NOx control technique. The
6-12

capital costs of converting ND heaters to MD heaters is added to

the costs of control techniques where conversion from ND to MD is

required. The control techniques that require ND heater

conversion to MD are MD LNBs, MD ULNBs, MD SNCR, SCR, MD LNBs

plus FGR, MD LNBs plus SNCR, and MD LNBs plus SCR.

(2) Operating Costs of ND-to-MD Conversion. Maintenance

costs for MD heaters are greater than for ND heaters. 

Maintenance costs associated with ND-to-MD conversion are

calculated as 2.75 percent of the ND-to-MD capital cost.1,2

Conversion from ND-to-MD increases heater thermal efficiency. 

Potential fuel reductions of 1.5 percent can lead to a yearly

savings equivalent to about 4 to 8 percent of the capital cost to

retrofit a medium sized heater ND heater to MD LNBs. This 1

efficiency gain is site-specific, however, and has not been

included in the cost analysis. 

b. TOTAL ANNUAL COST FOR MODEL HEATERS

The TAC for applying NOx control techniques to model heaters

is presented in this section. The TAC is the sum of the capital

recovery cost and the annual cost. The capital recovery cost is

estimated for each NOx control technique by multiplying the

capital costs by the capital recovery factor (CRF). The CRF is

estimated by the following method:

CRF = [i x (1+i) ]/[(1+i) ]

n n-1

where:

i = pretax marginal rate of return (10 percent), and

n = equipment economic life (15 years).4

The capital and annual cost methodologies are presented in

Section 6.1.

Sections 6.2.1 through 6.1.5 present the capital costs,

capital recovery, annual costs, and TACs for NOx control

techniques applied to the model heaters. Total annual costs are

calculated for capacity factors of 0.1, 0.5, and 0.9. However,

only TAC for the capacity factor of 0.9 are discussed in these

sections. Sections 6.2.1 and 6.2.2 present these costs for the

ND low- and medium-temperature and MD low- and medium-temperature

gas-fired model heaters, respectively. Sections 6.2.3 and 6.2.4
6-13

present these costs for the ND low- and medium-temperature and MD

low- and medium-temperature oil-fired model heaters,

respectively. Section 6.2.5 presents the capital costs, capital

recovery, annual costs, and TACs for the olefins pyrolysis model

heaters. The ND-to-MD conversion costs are presented in

Section 6.2.6.

i. Control Costs for the ND Gas-Fired, Low- and Medium-

 Temperature Model Heaters

Table 6-2 presents the capital costs, annual costs, and TACs

for the ND gas-fired, low-and medium-temperature model heaters. 

The capital costs of the control techniques range from $58,200

for ND LNBs used on the 17 MMBtu/hr heater to $4,650,000 for MD

LNBs plus SCR used on the 186 MMBtu/hr heater. The TACs range

from $9,250/yr for ND LNBs on the 17 MMBtu/hr heater to

$835,000/yr for MD LNBs plus SCR on the 186 MMBtu/hr heater.

ii. Control Costs for MD Gas-Fired, Low- and MediumTemperature Model Heaters

Table 6-3 presents the capital costs, annual costs, and TACs

for the MD gas-fired, low- and medium-temperature model heaters.

The capital costs of the control techniques range from $130,000

for LNBs used on the 40 MMBtu/hr heater to $5,360,000 for LNBs

plus SCR used on the 236 MMBtu/hr heater. The TACs range from

$20,700/yr for LNBs used on the 40 MMBtu/hr heater to $988,000/yr

for LNBs plus SCR used on the 263 MMBtu/hr heater.

iii. Control Costs for ND Oil-Fired, Low- and Medium-

 Temperature Model Heaters

Table 6-4 presents the capital costs, annual costs, and TACs

for the ND oil-fired, low- and medium-temperature model heaters. 

The capital costs of the control techniques range from $227,000

for ND LNBs to $2,580,000 for MD LNBs plus SCR. The TACs range

from $36,100/yr for ND LNBs to $463,000/yr for the MD LNBs plus

SCR. These costs are the same for both distillate and residual

oil-fired ND model heaters.
6-13

TABLE 6-2. COSTS OF CONTROL TECHNIQUES FOR ND

NATURAL GAS-FIRED MODEL HEATERS (1991 $)

Model heater

capacity, Capital

MMBtu/hr NOx control technique Capital costs, $ recovery 0.1 0.5 0.9 0.1 0.5 0.9

Annual costs, $/yr

Operating and maintenance costs @ Total annual costs, $/yr @ capacity

capacity factors: factors:c

a

b

17 (ND) LNB 58,200 7,650 1,600 1,600 1,600 9,250 9,250 9,250 

(MD) LNB 191,000 25,100 5,250 5,250 5,250 30,400 30,400 30,400 

(ND) ULNB 62,500 8,220 1,720 1,720 1,720 9,940 9,940 9,940 

(MD) ULNB 249,000 32,800 6,850 6,850 6,850 39,600 39,600 39,600 

(ND) SNCR 155,000 20,300 4,490 5,420 6,360 24,800 25,700 26,700 

(MD) SNCR 258,000 34,000 7,480 9,000 10,500 41,400 43,000 44,500 

(MD) SCR 951,000 125,000 30,200 32,600 34,900 155,000 158,000 160,000 

(MD) LNB + FGR 253,000 33,300 7,090 7,630 8,170 40,400 40,900 41,400 

(ND) LNB + SNCR 213,000 28,000 6,090 7,020 7,960 34,100 35,000 35,900 

(MD) LNB + SNCR 346,000 45,400 9,880 11,400 12,900 55,300 56,800 58,400 

(MD) LNB + SCR 1,040,000 137,000 32,600 35,000 37,300 169,000 172,000 174,000 

36 (ND) LNB 92,600 12,200 2,550 2,550 2,550 14,700 14,700 14,700 

(MD) LNB 302,000 39,600 8,290 8,290 8,290 47,900 47,900 47,900 

(ND) ULNB 96,900 12,700 2,670 2,670 2,670 15,400 15,400 15,400 

(MD) ULNB 308,000 40,500 8,470 8,470 8,470 49,000 49,000 49,000 

(ND) SNCR 243,000 31,900 7,160 9,150 11,100 39,000 41,000 43,000 

(MD) SNCR 405,000 53,300 11,900 14,400 16,900 65,200 67,700 70,100 

(MD) SCR 1,500,000 198,000 49,900 54,900 59,900 247,000 252,000 257,000 

(MD) LNB + FGR 399,000 52,500 11,300 12,400 13,500 63,700 64,800 66,000 

(ND) LNB + SNCR 335,000 44,100 9,710 11,700 13,700 53,800 55,800 57,700 

(MD) LNB + SNCR 544,000 71,500 15,800 19,000 22,200 87,300 90,500 93,700 

(MD) LNB + SCR 1,640,000 216,000 53,700 58,700 63,700 270,000 275,000 280,000 

77 (ND) LNB 133,000 17,500 3,670 3,670 3,670 21,200 21,200 21,200 

(MD) LNB 457,000 60,000 12,600 12,600 12,600 72,600 72,600 72,600 

(ND) ULNB 138,000 18,100 3,790 3,790 3,790 21,900 21,900 21,900 

(MD) ULNB 463,000 60,900 12,700 12,700 12,700 73,600 73,600 73,600 

(ND) SNCR 383,000 50,300 11,600 15,800 20,100 61,900 66,100 70,400 

(MD) SNCR 639,000 84,000 19,300 24,600 29,800 103,000 109,000 114,000 

(MD) SCR 2,390,000 315,000 84,100 94,800 106,000 399,000 410,000 420,000 

(MD) LNB + FGR 610,000 80,300 17,400 19,800 22,300 97,600 100,000 103,000 

(ND) LNB + SNCR 516,000 67,900 15,300 19,500 23,700 83,100 87,300 91,600 

(MD) LNB + SNCR 839,000 110,000 24,800 31,700 38,600 135,000 142,000 149,000 

(MD) LNB + SCR 2,590,000 341,000 89,600 100,000 111,000 431,000 441,000 452,000 
TABLE 6-2. (continued)

Model heater

capacity, Capital

MMBtu/hr NO control technique Capital costs, $ recovery 0.1 0.5 0.9 0.1 0.5 0.9 x

Annual costs, $/yr

Operating and maintenance costs @ Total annual costs, $/yr @ capacity

capacity factors: factors:c

a

b

6-14

121 (ND) LNB 232,000 30,500 6,390 6,390 6,390 36,900 36,900 36,900 

(MD) LNB 685,000 90,100 18,800 18,800 18,800 109,000 109,000 109,000 

(ND) ULNB 237,000 31,100 6,510 6,510 6,510 37,600 37,600 37,600 

(MD) ULNB 691,000 90,900 19,000 19,000 19,000 110,000 110,000 110,000 

(ND) SNCR 502,000 66,000 15,500 22,100 28,800 81,500 88,100 94,800 

(MD) SNCR 838,000 110,000 25,800 34,000 42,300 136,000 144,000 153,000 

(MD) SCR 3,160,000 416,000 116,000 133,000 149,000 532,000 548,000 565,000 

(MD) LNB + FGR 887,000 117,000 25,300 29,200 33,000 142,000 146,000 150,000 

(ND) LNB + SNCR 734,000 96,500 21,900 28,500 35,200 118,000 125,000 132,000 

(MD) LNB + SNCR 1,190,000 156,000 35,300 46,200 57,000 191,000 202,000 213,000 

(MD) LNB + SCR 3,510,000 462,000 125,000 142,000 159,000 587,000 604,000 621,000 

186 (ND) LNB 346,000 45,500 9,520 9,520 9,520 55,000 55,000 55,000 

(MD) LNB 955,000 126,000 26,300 26,300 26,300 152,000 152,000 152,000 

(ND) ULNB 351,000 46,100 9,640 9,640 9,640 55,700 55,700 55,700 

(MD) ULNB 961,000 126,000 26,400 26,400 26,400 153,000 153,000 153,000 

(ND) SNCR 650,000 85,400 20,400 30,700 40,900 106,000 116,000 126,000 

(MD) SNCR 1,090,000 143,000 34,000 46,700 59,400 177,000 189,000 202,000 

(MD) SCR 4,130,000 543,000 158,000 183,000 209,000 700,000 726,000 752,000 

(MD) LNB + FGR 1,220,000 160,000 34,900 40,800 46,600 195,000 201,000 207,000 

(ND) LNB + SNCR 996,000 131,000 29,900 40,200 50,400 161,000 171,000 181,000 

(MD) LNB + SNCR 1,600,000 211,000 48,300 64,900 81,500 259,000 276,000 292,000 

(MD) LNB + SCR 4,650,000 611,000 172,000 198,000 224,000 783,000 809,000 835,000 

Capital recovery = Capital cost x capital recovery factor. a

Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent. b

Total annual cost = Capital recovery + operating and maintenance cost. c

iv. Control Costs for MD Oil-Fired, Low- and Medium-

 Temperature Model Heaters
6-15

TABLE 6-3. COSTS OF CONTROL TECHNIQUES FOR MD NATURAL

GAS-FIRED MODEL HEATERS (1991 $)

Model heater

capacity, NO control technique Capital costs,

MMBtu/hr $

x

Annual costs, $/yr

Total annual costs, $/yr @ capacity factors:c

Capital factors:

recovery

a

Operating and maintenance costs @ capacity

b

0.1 0.5 0.9 0.1 0.5 0.9

40 LNB 130,000 17,100 3,570 3,570 3,570 20,700 20,700 20,700 

ULNB 136,000 17,900 3,750 3,750 3,750 21,700 21,700 21,700 

SNCR 258,000 34,000 8,000 11,600 15,100 42,000 45,500 49,100 

SCR 1,430,000 188,000 48,800 54,400 59,900 237,000 242,000 248,000

LNB + FGR 234,000 30,700 6,740 8,010 9,270 37,500 38,700 40,000 

LNB + SNCR 388,000 51,000 11,600 15,100 18,700 62,600 66,200 69,800 

LNB + SCR 1,560,000 205,000 52,400 57,900 63,500 257,000 263,000 269,000

77 LNB 282,000 37,100 7,750 7,750 7,750 44,800 44,800 44,800 

ULNB 288,000 37,900 7,930 7,930 7,930 45,800 45,800 45,800 

SNCR 383,000 50,300 12,200 19,100 26,000 62,600 69,400 76,300 

SCR 2,140,000 281,000 77,000 87,800 98,500 358,000 369,000 380,000

LNB + FGR 436,000 57,300 12,600 15,000 17,400 69,900 72,300 74,700 

LNB + SNCR 665,000 87,400 20,000 26,900 33,800 107,000 114,000 121,000

LNB + SCR 2,420,000 318,000 84,800 95,500 106,000 403,000 414,000 424,000

114 LNB 507,000 66,700 14,000 14,000 14,000 80,700 80,700 80,700 

ULNB 514,000 67,600 14,100 14,100 14,100 81,700 81,700 81,700 

SNCR 484,000 63,700 15,900 26,100 36,200 79,500 89,700 99,900 

SCR 2,720,000 358,000 102,000 118,000 134,000 460,000 476,000 492,000

LNB + FGR 702,000 92,300 20,200 23,800 27,400 113,000 116,000 120,000

LNB + SNCR 992,000 130,000 29,800 40,000 50,200 160,000 170,000 181,000

LNB + SCR 3,230,000 425,000 116,000 132,000 148,000 541,000 557,000 573,000

174 LNB 541,000 71,200 14,900 14,900 14,900 86,100 86,100 86,100 

ULNB 548,000 72,000 15,100 15,100 15,100 87,100 87,100 87,100 

SNCR 624,000 82,100 21,100 36,600 52,200 103,000 119,000 134,000

SCR 3,540,000 466,000 139,000 163,000 187,000 604,000 629,000 653,000

LNB + FGR 792,000 104,000 23,200 28,600 34,100 127,000 133,000 138,000

LNB + SNCR 1,170,000 153,000 35,900 51,500 67,000 189,000 205,000 220,000

LNB + SCR 4,080,000 537,000 154,000 178,000 202,000 690,000 715,000 739,000
Model heater

capacity, NO control technique Capital costs,

MMBtu/hr $

x

Annual costs, $/yr

Total annual costs, $/yr @ capacity factors:c

Capital factors:

recovery

a

Operating and maintenance costs @ capacity

b

0.1 0.5 0.9 0.1 0.5 0.9

6-16

263 LNB 777,000 102,000 21,400 21,400 21,400 123,000 123,000 123,000

ULNB 783,000 103,000 21,500 21,500 21,500 124,000 124,000 124,000

SNCR 800,000 105,000 27,900 51,400 74,900 133,000 157,000 180,000

SCR 4,580,000 603,000 188,000 225,000 262,000 791,000 828,000 864,000

LNB + FGR 1,100,000 144,000 32,300 40,600 48,900 177,000 185,000 193,000

LNB + SNCR 1,580,000 207,000 49,200 72,700 96,200 256,000 280,000 303,000

LNB + SCR 5,360,000 705,000 210,000 246,000 283,000 915,000 951,000 988,000

Capital recovery = Capital cost x capital recovery factor. a

Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent. b

Total annual cost = Capital recovery + operating and maintenance cost. c
TABLE 6-4. COSTS OF CONTROL TECHNIQUES FOR ND OIL-FIRED MODEL HEATERS (1991 $)

Model heater capacity and

fuel type, M

MBtu/hr

NO control technique x Capital costs,

$

Annual co sts, $/yr

b

Total annual costs, $/yr @ capacity factors:

c

Capital recovery

a

Operating and maintenance costs @ capacity factors:

0.1 0.5 0.9 0.1 0.5 0.9

69 (ND) LNB 227,000 29,900 6,250 6,250 6,250 36,100 36,100 36,100

Distillate oil-fired (MD) LNB 581,000 76,400 16,000 16,000 16,000 92,400 92,400 92,400

(ND) ULNB 232,000 30,500 6,370 6,370 6,370 36,800 36,800 36,800(MD) ULNB 588,000 77,300 16,200 16,200 16,200 93,400 93,400 93,400(ND) SNCR 358,000 47,100 31,100 20,900 29,700 78,300 68,000 76,800(MD) SNCR 598,000 78,700 19,400 31,100 42,700 98,100 110,000 121,000(MD) SCR 2,240,000 294,000 81,500 105,000 129,000 376,000 400,000 424,000(MD) LNB + FGR 725,000 95,300 20,500 22,700 24,800 116,000 118,000 120,000(ND) LNB + SNCR 586,000 77,000 18,300 27,100 35,900 95,300 104,000 113,000(MD) LNB + SNCR 939,000 124,000 28,800 40,400 52,100 152,000 164,000 176,000(MD) LNB + SCR 2,580,000 339,000 90,900 115,000 139,000 430,000 454,000 478,000

69 (ND) LNB 227,000 29,900 6,250 6,250 6,250 36,100 36,100 36,100

Residual oil-fired (MD) LNB 581,000 76,400 16,000 16,000 16,000 92,400 92,400 92,400

(ND) ULNB 232,000 30,500 6,370 6,370 6,370 36,800 36,800 36,800(MD) ULNB 588,000 77,300 16,200 16,200 16,200 93,400 93,400 93,400(ND) SNCR 358,000 47,100 12,900 25,100 37,400 60,000 72,300 84,500(MD) SNCR 598,000 78,700 20,200 33,200 46,100 98,900 112,000 125,000(MD) SCR 2,240,000 294,000 79,800 97,200 115,000 374,000 391,000 409,000(MD) LNB + FGR 725,000 95,300 20,500 22,700 24,800 116,000 118,000 120,000(ND) LNB + SNCR 586,000 77,000 19,200 31,400 43,600 96,200 108,000 121,000(MD) LNB + SNCR 939,000 124,000 29,400 43,800 58,200 153,000 167,000 182,000(MD) LNB + SCR 2,580,000 339,000 89,200 107,000 124,000 428,000 446,000 463,000

Capital recovery =

Capital cost * capital recovery factor.

a

Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent.

b

Total annual cost =

Capital recovery + operating and maintenance cost.

c
TABLE 6-3. (continued)

6-18
TABLE 6-3. (continued)

6-19

Table 6-5 presents the capital costs, annual costs, and TACs

for the MD oil-fired, low- and medium-temperature model heaters. 

The capital cost of the control techniques range from $319,000

for LNBs to $3,340,000 for LNBs plus SCR. The capital cost for

both MD oil-fired heaters are the same. The TACs range from

$50,700/yr for LNBs used on the distillate oil-fired heater to

$570,000 for LNBs plus SCR used on the residual oil-fired heater. 

v. Control Costs for the Olefins Pyrolysis Model Heaters

Table 6-6 present the capital costs, annual costs, and TAC

for the ND olefins pyrolysis model heaters. The capital costs of
TABLE 6-3. (continued)

6-20

TABLE 6-5. COSTS OF CONTROL TECHNIQUES FOR MD OIL-FIRED HEATERS (1991 $)

Model heater

capacity and

fuel type,

MMBtu/hr

NO control x

technique

Capital costs,

$

Annual costs, $/yr

Total annual costs, $/yr @ capacity factors: c

Capital recoverya

Operating and maintenance costs @ capacity

factors:b

0.1 0.5 0.9 0.1 0.5 0.9

135 (MD) LNB 319,000 42,000 8,780 8,780 8,780 50,700 50,700 50,700

Distillate (MD) ULNB 326,000 42,800 8,960 8,960 8,960 51,800 51,800 51,800

oil-fired SNCR 536,000 70,500 20,500 43,300 66,200 90,900 114,000 137,000

SCR 3,130,000 411,000 89,900 105,000 121,000 501,000 516,000 532,000LNB + FGR 535,000 70,300 15,800 20,000 24,300 86,100 90,300 94,600LNB + SNCR 855,000 112,000 29,200 52,100 74,900 142,000 165,000 187,000LNB + SCR 3,340,000 440,000 95,800 111,000 127,000 536,000 551,000 566,000

135 (MD) LNB 319,000 42,000 8,780 8,780 8,780 50,700 50,700 50,700

Residual

oil-fired

(MD) ULNB 326,000 42,800 8,960 8,960 8,960 51,800 51,800 51,800SNCR 536,000 70,500 22,100 51,700 81,200 92,600 122,000 152,000SCR 3,130,000 411,000 90,200 107,000 124,000 501,000 518,000 535,000LNB + FGR 535,000 70,300 15,800 20,000 24,300 86,100 90,300 94,600LNB + SNCR 855,000 112,000 30,900 60,500 90,000 143,000 173,000 202,000LNB + SCR 3,340,000 440,000 96,200 113,000 130,000 536,000 553,000 570,000

Capital recovery = Capital cost * capital recovery factor. a

Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent. b

Total annual cost = Capital recovery + operating and maintenance cost. c
TABLE 6-3. (continued)

6-21

TABLE 6-6. COSTS OF CONTROL TECHNIQUES FOR ND OLEFINS PYROLYSIS MODEL HEATERS (1991

$)

Model heater

capacity and

fuel type,

MMBtu/hr NO control technique x

Capital costs,

$

Annual costs, $/yr

Total annual costs, $/yr @ capacity factors:

Capital

recoverya

Operating and maintenance costs @ capacity factors: b

0.1 0.5 0.9 0.1 0.5 0.9

84 (ND) LNB 248,000 32,600 6,810 6,810 6,810 39,400 39,400 39,400

Natural

gas-fired

(MD) LNB 642,000 84,400 17,700 17,700 17,700 102,000 102,000 102,000(ND) ULNB 252,000 33,100 6,930 6,930 6,930 40,100 40,100 40,100(MD)ULNB 648,000 85,300 17,800 17,800 17,800 103,000 103,000 103,000(ND) SNCR 403,000 53,000 12,300 17,100 21,900 65,300 70,100 74,900(MD) SNCR 673,000 88,500 19,700 24,500 29,300 108,000 113,000 118,000SCR 2,520,000 331,000 89,600 103,000 117,000 421,000 434,000 448,000(MD) LNB + FGR 804,000 106,000 22,800 25,400 28,100 128,000 131,000 134,000(ND) LNB + SNCR 651,000 85,600 19,100 23,900 28,700 105,000 109,000 114,000(MD) LNB + SNCR 1,050,000 137,000 29,900 34,700 39,500 167,000 172,000 177,000(MD) LNB + SCR 2,900,000 381,000 100,000 114,000 127,000 481,000 495,000 508,000

84 (ND) LNB 248,000 32,600 6,810 6,810 6,810 39,400 39,400 39,400

High-hydrogen

fuel gas-fired

(MD) LNB 642,000 84,400 17,700 17,700 17,700 102,000 102,000 102,000(ND) ULNB 252,000 33,100 6,930 6,930 6,930 40,100 40,100 40,100(MD) ULNB 648,000 85,300 17,800 17,800 17,800 103,000 103,000 103,000(ND) SNCR 403,000 53,000 12,500 18,400 24,200 65,600 71,400 77,300(MD) SNCR 673,000 88,500 20,000 25,800 31,700 109,000 114,000 120,000SCR 2,520,000 331,000 90,100 105,000 121,000 421,000 436,000 452,000(MD) LNB + FGR 804,000 106,000 22,800 25,400 28,100 128,000 131,000 134,000(ND) LNB + SNCR 651,000 85,600 19,400 25,200 31,100 105,000 111,000 117,000(MD) LNB + SNCR 1,050,000 137,000 30,200 36,100 41,900 168,000 173,000 179,000(MD) LNB + SCR 2,900,000 381,000 100,000 116,000 131,000 481,000 497,000 512,000

Capital recovery = Capital cost * capital recovery factor. a
TABLE 6-3. (continued)

6-22

the control techniques range from $248,000 for LNBs to $2,900,000

for LNBs plus SCR on both pyrolysis model heaters. The TACs

range from $39,400/yr for LNB's on the natural gas-fired heater

to $512,000 for LNB's plus SCR on the high- hydrogen fuel gasfired heater.

vi. Costs for ND-to-MD Conversion
TABLE 6-3. (continued)

6-23

Table 6-7
TABLE 6-3. (continued)

6-24

TABLE 6-7. ND-TO-MD CONVERSION COSTS FOR THE ND MODEL

HEATERS (1991 $)

Model heater

capacity,

MMBtu/hr

Capital cost, 1991

US $

Capital recovery,

1991 US $/yr

Annual operating

costs, 1991 US $/yr

Total annual

costs, 1991

US $/yr

ND NATURAL GAS-FIRED HEATERS

17 104,000 13,600 2,860 16,500

36 163,000 21,400 4,480 25,900

77 257,000 33,800 7,070 40,900

121 336,000 442,000 9,240 53,400

185 434,000 57,100 11,900 69,000

ND OIL-FIRED HEATERS

69 240,000 31,600 6,400 38,000

ND OLEFINS PYROLYSIS HEATERS

84 270,000 35,500 7,430 42,900
TABLE 6-3. (continued)

6-25

 presents the capital, annual operating, and TAC of the ND-to-MD

conversion for the model heaters. The capital costs range from

$104,000 to $434,000; the annual operating cost range from

$2,860/yr to $11,900/yr; and the TACs range from $16,500/yr to

$69,000/yr for the 17 and 185 MMBtu/hr natural gas-fired low- and

medium-temperature heaters, respectively.

c. COST EFFECTIVENESS OF NOx CONTROLS FOR PROCESS HEATERS

This section presents the cost effectiveness for the control

techniques presented in Section 6.2. The cost effectiveness, in

dollars per ton of NOx removed ($/ton), is calculated by dividing

the TACs by the annual NOx emission reduction, in tons.

Capacity factors of 0.1, 0.5, and 0.9 of heater operation,

were included in the cost-effectiveness analysis. The capacity

factor affects the operating costs but not the capital costs. 

The capacity factor also influences the tons per year of NOx

produced by a process heater. For example, approximately 
TABLE 6-3. (continued)

6-26
TABLE 6-3. (continued)

6-27
TABLE 6-3. (continued)

6-28

90 percent less NOx is produced by a heater operating at a

capacity factor of 0.1 as opposed to 1.0.

Cost effectiveness for ND natural gas-fired heaters is

presented in Table 6-8. The cost-effectiveness range at a

capacity factor of 0.9 is from $981/ton for ND ULNBs on the

77 MMBtu/hr heater to $16,200/ton for SCR on the 17 MMBtu/hr

heater. The cost-effectiveness range for MD natural gas-fired

heaters is shown in Table 6-9. At a capacity factor of 0.9, the

cost effectiveness ranges from $813/ton for ULNBs on the

263 MMBtu/hr heater to $10,600/ton for SCR on the 40 MMBtu/hr

heater.

The cost-effectiveness range for oil-fired ND heaters is

shown in Table 6-10. For a capacity factor of 0.9, the cost

effectiveness ranges from $419/ton for ND ULNBs on the residual

oil-fired heater to $6,490/ton for SCR on the distillate oilfired heater. The cost-effectiveness range for oil-fired MD

heaters, shown in Table 6-11, is from $245/ton for ULNBs on the

residual oil-fired heater to $4,160/ton for SCR on the distillate

oil-fired heater at a capacity factor of 0.9.

The cost-effectiveness range for the ND olefins pyrolysis

model heaters is shown in Table 6-12. At a capacity factor of

0.9, the cost effectiveness ranges from $1,490/ton for MD ULNBs

on the high-hydrogen fuel gas-fired heater to $14,100/ton for

LNB+SCR on the natural gas-fired heater.

The cost effectiveness of each control technique for the

model heaters generally increases from ULNB to LNB, to LNB plus

FGR, to SNCR, to LNB plus SNCR, to LNB plus SCR, to SCR. The

cost-effectiveness values for the control techniques applied to

the smaller model heaters are generally higher in comparison to

the same control techniques applied to the larger heaters. This

difference represents an economy of scale because for a given

percent reduction, the quantity of NOx emissions removed per year

(tons/yr) from the smaller model heaters was lower than from

other model heaters. 
TABLE 6-3. (continued)

6-29

Table 6-13 is a summary of the cost effectiveness of

selected NOx emission control techniques as presented by the 
TABLE 6-3. (continued)

6-30

TABLE 6-8. COST EFFECTIVENESS OF CONTROL TECHNIQUES FOR

ND NATURAL GAS-FIRED MODEL HEATERS (1991 $)

Model heater Uncontrolled NO emissions, ton/yr Total effective NO reduction, ton/yr @ capacity Cost effectiveness, $/ton @ capacity factors:

capacity, @ capacity factors: reduction, factors: Total annual costs, $/yr @ capacity factors:

MMBtu/hr NO control technique percent

x

x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

17 (ND) LNB 0.730 3.65 6.57 50 0.365 1.82 3.28 9,250 9,250 9,250 25,400 5,070 2,820 

(MD) LNB 1.47 7.33 13.2 50 0.733 3.67 6.60 30,400 30,400 30,400 41,400 8,280 4,600 

(ND) ULNB 0.730 3.65 6.57 75 0.547 2.74 4.93 9,940 9,940 9,940 18,200 3,630 2,020 

(MD) ULNB 1.47 7.33 13.2 75 1.10 5.50 9.90 39,600 39,600 39,600 36,000 7,200 4,000 

(ND) SNCR 0.730 3.65 6.57 60 0.438 2.19 3.94 24,800 25,700 26,700 56,700 11,800 6,770 

(MD) SNCR 1.47 7.33 13.2 60 0.880 4.40 7.92 41,400 43,000 44,500 47,100 9,760 5,610 

(MD) SCR 1.47 7.33 13.2 75 1.10 5.50 9.90 155,000 158,000 160,000 141,000 28,700 16,200 

(MD) LNB + FGR 1.47 7.33 13.2 55 0.807 4.03 7.26 40,400 40,900 41,400 50,000 10,100 5,710 

(ND) LNB + SNCR 0.730 3.65 6.57 80 0.584 2.92 5.25 34,100 35,000 35,900 58,400 12,000 6,840 

(MD) LNB + SNCR 1.47 7.33 13.2 80 1.17 5.87 10.6 55,300 56,800 58,400 47,100 9,690 5,530 

(MD) LNB + SCR 1.47 7.33 13.2 88 1.28 6.42 11.6 169,000 172,000 174,000 132,000 26,700 15,100 

36 (ND) LNB 1.55 7.73 13.9 50 0.773 3.86 6.95 14,700 14,700 14,700 19,100 3,810 2,120 

(MD) LNB 3.11 15.5 28.0 50 1.55 7.77 14.0 47,900 47,900 47,900 30,900 6,170 3,430 

(ND) ULNB 1.55 7.73 13.9 75 1.16 5.79 10.4 15,400 15,400 15,400 13,300 2,660 1,480 

(MD) ULNB 3.11 15.5 28.0 75 2.33 11.6 21.0 49,000 49,000 49,000 21,000 4,200 2,330 

(ND) SNCR 1.55 7.73 13.9 60 0.927 4.64 8.34 39,000 41,000 43,000 42,100 8,850 5,150 

(MD) SNCR 3.11 15.5 28.0 60 1.86 9.32 16.8 65,200 67,700 70,100 35,000 7,260 4,180 

(MD) SCR 3.11 15.5 28.0 75 2.33 11.6 21.0 247,000 252,000 257,000 106,000 21,700 12,300 

(MD) LNB + FGR 3.11 15.5 28.0 55 1.71 8.54 15.4 63,700 64,800 66,000 37,300 7,590 4,290 

(ND) LNB + SNCR 1.55 7.73 13.9 80 1.24 6.18 11.1 53,800 55,800 57,700 43,500 9,020 5,190 

(MD) LNB + SNCR 3.11 15.5 28.0 80 2.49 12.4 22.4 87,300 90,500 93,700 35,100 7,280 4,190 

(MD) LNB + SCR 3.11 15.5 28.0 88 2.72 13.6 24.5 270,000 275,000 280,000 99,200 20,200 11,400 
TABLE 6-8. (continued)

Model heater Uncontrolled NO emissions, ton/yr Total effective NO reduction, ton/yr @ capacity Cost effectiveness, $/ton @ capacity factors:

capacity, @ capacity factors: reduction, factors: Total annual costs, $/yr @ capacity factors:

MMBtu/hr NO control technique percent

x

x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

6-31

77 (ND) LNB 3.31 16.5 29.7 50 1.65 8.26 14.9 21,200 21,200 21,200 12,800 2,570 1,430 

(MD) LNB 6.64 33.2 59.8 50 3.32 16.6 29.9 72,600 72,600 72,600 21,900 4,370 2,430 

(ND) ULNB 3.31 16.5 29.7 75 2.48 12.4 22.3 21,900 21,900 21,900 8,830 1,770 981 

(MD) ULNB 6.64 33.2 59.8 75 4.98 24.9 44.8 73,600 73,600 73,600 14,800 2,950 1,640 

(ND) SNCR 3.31 16.5 29.7 60 1.98 9.92 17.8 61,900 66,100 70,400 31,200 6,670 3,940 

(MD) SNCR 6.64 33.2 59.8 60 3.99 19.9 35.9 103,000 109,000 114,000 25,900 5,450 3,170 

(MD) SCR 6.64 33.2 59.8 75 4.98 24.9 44.8 399,000 410,000 420,000 80,100 16,400 9,370 

(MD) LNB + FGR 6.64 33.2 59.8 55 3.65 18.3 32.9 97,600 100,000 103,000 26,700 5,480 3,120 

(ND) LNB + SNCR 3.31 16.5 29.7 80 2.64 13.2 23.8 83,100 87,300 91,600 31,400 6,610 3,850 

(MD) LNB + SNCR 6.64 33.2 59.8 80 5.32 26.6 47.8 135,000 142,000 149,000 25,400 5,340 3,110 

(MD) LNB + SCR 6.64 33.2 59.8 88 5.81 29.1 52.3 431,000 441,000 452,000 74,100 15,200 8,640 

121 (ND) LNB 5.19 26.0 46.7 50 2.60 13.0 23.4 36,900 36,900 36,900 14,200 2,840 1,580 

(MD) LNB 10.4 52.2 94.0 50 5.22 26.1 47.0 109,000 109,000 109,000 20,900 4,170 2,320 

(ND) ULNB 5.19 26.0 46.7 75 3.90 19.5 35.1 37,600 37,600 37,600 9,660 1,930 1,070 

(MD) ULNB 10.4 52.2 94.0 75 7.83 39.2 70.5 110,000 110,000 110,000 14,000 2,810 1,560 

(ND) SNCR 5.19 26.0 46.7 60 3.12 15.6 28.0 81,500 88,100 94,800 26,100 5,660 3,380 

(MD) SNCR 10.4 52.2 94.0 60 6.26 31.3 56.4 136,000 144,000 153,000 21,700 4,610 2,710 

(MD) SCR 10.4 52.2 94.0 75 7.83 39.2 70.5 532,000 548,000 565,000 67,900 14,000 8,020 

(MD) LNB + FGR 10.4 52.2 94.0 55 5.74 28.7 51.7 142,000 146,000 150,000 24,700 5,080 2,890 

(ND) LNB + SNCR 5.19 26.0 46.7 80 4.16 20.8 37.4 118,000 125,000 132,000 28,500 6,020 3,520 

(MD) LNB + SNCR 10.4 52.2 94.0 80 8.35 41.8 75.2 191,000 202,000 213,000 22,900 4,840 2,830 

(MD) LNB + SCR 10.4 52.2 94.0 88 9.14 45.7 82.2 587,000 604,000 621,000 64,300 13,200 7,550 
TABLE 6-8. (continued)

Model heater Uncontrolled NO emissions, ton/yr Total effective NO reduction, ton/yr @ capacity Cost effectiveness, $/ton @ capacity factors:

capacity, @ capacity factors: reduction, factors: Total annual costs, $/yr @ capacity factors:

MMBtu/hr NO control technique percent

x

x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

6-32

186 (ND) LNB 7.98 39.9 71.9 50 3.99 20.0 35.9 55,000 55,000 55,000 13,800 2,760 1,530 

(MD) LNB 16.0 80.2 144 50 8.02 40.1 72.2 152,000 152,000 152,000 18,900 3,780 2,100 

(ND) ULNB 7.98 39.9 71.9 75 5.99 29.9 53.9 55,700 55,700 55,700 9,310 1,860 1,030 

(MD) ULNB 16.0 80.2 144 75 12.0 60.2 108 153,000 153,000 153,000 12,700 2,540 1,410 

(ND) SNCR 7.98 39.9 71.9 60 4.79 24.0 43.1 106,000 116,000 126,000 22,100 4,850 2,930 

(MD) SNCR 16.0 80.2 144 60 9.63 48.1 86.7 177,000 189,000 202,000 18,300 3,930 2,330 

(MD) SCR 16.0 80.2 144 75 12.0 60.2 108 700,000 726,000 752,000 58,200 12,100 6,940 

(MD) LNB + FGR 16.0 80.2 144 55 8.83 44.1 79.4 195,000 201,000 207,000 22,100 4,550 2,600 

(ND) LNB + SNCR 7.98 39.9 71.9 80 6.39 31.9 57.5 161,000 171,000 181,000 25,200 5,360 3,150 

(MD) LNB + SNCR 16.0 80.2 144 80 12.8 64.2 116 259,000 276,000 292,000 20,200 4,300 2,530 

(MD) LNB + SCR 16.0 80.2 144 88 14.0 70.2 126 783,000 809,000 835,000 55,700 11,500 6,600 

Cost effectiveness = Total annual cost/NO reductions. a

x
6-33

TABLE 6-9. COST EFFECTIVENESS OF CONTROL TECHNIQUES 

FOR MD NATURAL GAS-FIRED MODEL HEATERS (1991 $)

Model heater capacity factors: factors: factors: factors:

capacity, NO control technique Total effective reductions,

MMBtu/hr percent

x

Uncontrolled NO emissions, ton/yr @ NO reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

40 LNB 3.45 17.3 31.1 50 1.73 8.63 15.5 20,700 20,700 20,700 12,000 2,390 1,330 

ULNB 3.45 17.3 31.1 75 2.59 12.9 23.3 21,700 21,700 21,700 8,380 1,680 931 

SNCR 3.45 17.3 31.1 60 2.07 10.4 18.6 42,000 45,500 49,100 20,300 4,400 2,640 

SCR 3.45 17.3 31.1 75 2.59 12.9 23.3 237,000 242,000 248,000 91,500 18,700 10,600

LNB + FGR 3.45 17.3 31.1 55 1.90 9.49 17.1 37,500 38,700 40,000 19,700 4,080 2,340 

LNB + SNCR 3.45 17.3 31.1 80 2.76 13.8 24.9 62,600 66,200 69,800 22,700 4,790 2,810 

LNB + SCR 3.45 17.3 31.1 88 3.02 15.1 27.2 257,000 263,000 269,000 85,200 17,400 9,880 

77 LNB 6.64 33.2 59.8 50 3.32 16.6 29.9 44,800 44,800 44,800 13,500 2,700 1,500 

ULNB 6.64 33.2 59.8 75 4.98 24.9 44.8 45,800 45,800 45,800 9,200 1,840 1,020 

SNCR 6.64 33.2 59.8 60 3.99 19.9 35.9 62,600 69,400 76,300 15,700 3,480 2,130 

SCR 6.64 33.2 59.8 75 4.98 24.9 44.8 358,000 369,000 380,000 71,900 14,800 8,460 

LNB + FGR 6.64 33.2 59.8 55 3.65 18.3 32.9 69,900 72,300 74,700 19,100 3,960 2,270 

LNB + SNCR 6.64 33.2 59.8 80 5.32 26.6 47.8 107,000 114,000 121,000 20,200 4,300 2,530 

LNB + SCR 6.64 33.2 59.8 88 5.81 29.1 52.3 403,000 414,000 424,000 69,300 14,200 8,110 

114 LNB 9.84 49.2 88.5 50 4.92 24.6 44.3 80,700 80,700 80,700 16,400 3,280 1,820 

ULNB 9.84 49.2 88.5 75 7.38 36.9 66.4 81,700 81,700 81,700 11,100 2,210 1,230 

SNCR 9.84 49.2 88.5 60 5.90 29.5 53.1 79,500 89,700 99,900 13,500 3,040 1,880 

SCR 9.84 49.2 88.5 75 7.38 36.9 66.4 460,000 476,000 492,000 62,400 12,900 7,410 

LNB + FGR 9.84 49.2 88.5 55 5.41 27.1 48.7 113,000 116,000 120,000 20,800 4,290 2,460 

LNB + SNCR 9.84 49.2 88.5 80 7.87 39.3 70.8 160,000 170,000 181,000 20,400 4,330 2,550 

LNB + SCR 9.84 49.2 88.5 88 8.61 43.0 77.5 541,000 557,000 573,000 62,800 12,900 7,390 

174 LNB 15.0 75.1 135 50 7.51 37.5 67.6 86,100 86,100 86,100 11,500 2,290 1,270 

ULNB 15.0 75.1 135 75 11.3 56.3 101 87,100 87,100 87,100 7,730 1,550 859 

SNCR 15.0 75.1 135 60 9.01 45.0 81.1 103,000 119,000 134,000 11,400 2,630 1,660 

SCR 15.0 75.1 135 75 11.3 56.3 101 604,000 629,000 653,000 53,700 11,200 6,440 
TABLE 6-9. (continued)

Model heater capacity factors: factors: factors: factors:

capacity, NO control technique Total effective reductions,

MMBtu/hr percent

x

Uncontrolled NO emissions, ton/yr @ NO reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

6-34

LNB + FGR 15.0 75.1 135 55 8.26 41.3 74.3 127,000 133,000 138,000 15,400 3,220 1,860 

LNB + SNCR 15.0 75.1 135 80 12.0 60.1 108 189,000 205,000 220,000 15,700 3,410 2,040 

LNB + SCR 15.0 75.1 135 88 13.1 65.7 118 690,000 715,000 739,000 52,600 10,900 6,250 

263 LNB 22.7 113 204 50 11.3 56.7 102 123,000 123,000 123,000 10,900 2,180 1,210 

ULNB 22.7 113 204 75 17.0 85.1 153 124,000 124,000 124,000 7,310 1,460 813 

SNCR 22.7 113 204 60 13.6 68.1 123 133,000 157,000 180,000 9,770 2,300 1,470 

SCR 22.7 113 204 75 17.0 85.1 153 791,000 828,000 864,000 46,500 9,730 5,640 

LNB + FGR 22.7 113 204 55 12.5 62.4 112 177,000 185,000 193,000 14,200 2,960 1,720 

LNB + SNCR 22.7 113 204 80 18.2 90.8 163 256,000 280,000 303,000 14,100 3,080 1,860 

LNB + SCR 22.7 113 204 88 19.9 99.3 179 915,000 951,000 988,000 46,100 9,580 5,530 

Cost effectiveness = Total annual cost/NO reductions. a

x
TABLE 6-10. COST EFFECTIVENESS OF CONTROL TECHNIQUES FOR 

ND OIL-FIRED MODEL HEATERS (1991 $)

Model heater capacity NO control technique Uncontrolled NO emission, ton/yr @ Total effective NO reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity

and fuel type, capacity factors: reduction, factors: factors: factors:

MMBtu/hr percent

x x x

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

69 (ND) LNB 6.04 30.2 54.4 40 2.39 11.9 21.5 36,100 36,100 36,100 15,100 3,030 1,680 

Distillate oil-fired (MD) LNB 9.67 48.4 87.0 45 4.38 21.9 39.4 92,400 92,400 92,400 21,100 4,220 2,340 

(ND) ULNB 6.04 30.2 54.4 76 4.59 22.9 41.3 36,800 36,800 36,800 8,030 1,610 892 

(MD) ULNB 9.67 48.4 87.0 74 7.20 36.0 64.8 93,400 93,400 93,400 13,000 2,600 1,440 

(ND) SNCR 6.04 30.2 54.4 60 3.63 18.1 32.6 78,300 68,000 76,800 16,300 3,750 2,350 

(MD) SNCR 9.67 48.4 87.0 60 5.80 29.0 52.2 98,100 110,000 121,000 16,900 3,780 2,330 

(MD) SCR 9.67 48.4 87.0 75 7.25 36.3 65.3 376,000 400,000 424,000 51,800 11,000 6,490 

(MD) LNB + FGR 9.67 48.4 87.0 48 4.59 23.0 41.3 116,000 118,000 120,000 25,200 5,140 2,910 

(ND) LNB + SNCR 6.04 30.2 54.4 76 4.58 22.9 41.2 95,300 104,000 113,000 20,800 4,540 2,740 

(MD) LNB + SNCR 9.67 48.4 87.0 78 7.56 37.8 68.0 152,000 164,000 176,000 20,200 4,340 2,580 

(MD) LNB + SCR 9.67 48.4 87.0 86 8.35 41.7 75.1 430,000 454,000 478,000 51,500 10,900 6,360 

69 (ND) LNB 12.7 63.5 114 27 3.38 16.9 30.5 36,100 36,100 36,100 10,700 2,140 1,190 

Residual oil-fired (MD) LNB 16.3 81.6 147 37 6.04 30.2 54.4 92,400 92,400 92,400 15,300 3,060 1,700 

(ND) ULNB 12.7 63.5 114 77 9.77 48.9 88.0 36,800 36,800 36,800 3,770 753 419 

(MD) ULNB 16.3 81.6 147 73 12.0 59.9 108 93,400 93,400 93,400 7,790 1,560 866 

(ND) SNCR 12.7 63.5 114 60 7.62 38.1 68.5 60,000 72,300 84,500 7,880 1,900 1,230 

(MD) SNCR 16.3 81.6 147 60 9.79 49.0 88.1 98,900 112,000 125,000 10,100 2,280 1,420 

(MD) SCR 16.3 81.6 147 75 12.2 61.2 110 374,000 391,000 409,000 30,600 6,400 3,710 

(MD) LNB + FGR 16.3 81.6 147 34 5.59 28.0 50.3 116,000 118,000 120,000 20,700 4,220 2,390 

(ND) LNB + SNCR 12.7 63.5 114 71 8.97 44.8 80.7 96,200 108,000 121,000 10,700 2,420 1,490 

(MD) LNB + SNCR 16.3 81.6 147 75 12.2 61.0 110 153,000 167,000 182,000 12,500 2,740 1,650 

(MD) LNB + SCR 16.3 81.6 147 84 13.8 68.8 124 428,000 446,000 463,000 31,200 6,480 3,740 

Cost effectiveness = Total annual cost/NO reductions. a

x
TABLE 6-11. COST EFFECTIVENESS OF CONTROL TECHNIQUES 

FOR MD OIL-FIRED MODEL HEATERS (1991 $)

Model heater

capacity,

M

MBtu/hr NO control technique x

Uncontrolled NO emissions,

x

ton/yr @ capacity factors: Total effective

reduction,

percent

NO reductions, ton/yr @ capacity x

factors: Total annual costs, $/yr @ capacity factors:

Cost effectiveness, ton/yr @ capacity factors:

a

0.1 0.5 0.9

0.1 0.5 0.9

0.1 0.5 0.9 0.1 0.5 0.9

135 (MD) LNB 18.9 94.6 170 45 8.57 42.9 77.2 50,700 50,700 50,700 5,920 1,180 658

(MD) ULNB 18.9 94.6 170 74 14.1 70.4 127 51,800 51,800 51,800 3,680 735 408SNCR 18.9 94.6 170 60 11.4 56.8 102 90,900 114,000 137,000 8,010 2,000 1,340SCR 18.9 94.6 170 75 14.2 71.0 128 501,000 516,000 532,000 35,300 7,280 4,160LNB + FGR 18.9 94.6 170 48 8.99 44.9 80.9 86,100 90,300 94,600 9,570 2,010 1,170LNB + SNCR 18.9 94.6 170 78 14.8 73.9 133 142,000 165,000 187,000 9,580 2,230 1,410LNB + SCR 18.9 94.6 170 92 17.4 86.8 156 536,000 551,000 566,000 30,800 6,340 3,620

135 (MD) LNB 31.9 160 287 37 11.8 59.1 106 50,700 50,700 50,700 4,290 858 477

(MD) ULNB 31.9 160 287 73 23.5 117 211 51,800 51,800 51,800 2,210 442 245SNCR 31.9 160 287 60 19.2 95.8 172 92,600 122,000 152,000 4,830 1,280 880SCR 31.9 160 287 75 23.9 120 216 501,000 518,000 535,000 20,900 4,330 2,480LNB + FGR 31.9 160 287 34 10.9 54.7 98.5 86,100 90,300 94,600 7,870 1,650 961LNB + SNCR 31.9 160 287 75 23.9 119 215 143,000 173,000 202,000 6,000 1,450 942LNB + SCR 31.9 160 287 91 28.9 145 260 536,000 553,000 570,000 18,500 3,820 2,190

Cost effectiveness = Total annual cost/NO reductions.

a

x

TABLE 6-12. COST EFFECTIVENESS OF CONTROL TECHNIQUES 

FOR ND PYROLYSIS MODEL HEATERS (1991 $)

Model heater

capacity and

fuel type,

M

MBtu/hr NO control technique x

Uncontrolled emissions, ton/yr

@ capacity factors: Total

effective

reduction,

percent

Controlled emissions, ton/yr @

capacity factors:

Reduction, ton/yr

@ capacity factors:

Total annual costs, $/yr @ capacity

factors:

Cost effectiveness,

$/ton removed,

@ capacity factors:

a

0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9

84 (ND) LNB 4.97 24.8 44.7 25 3.73 18.6 33.5 1.24 6.21 11.2 39,400 39,400 39,400 31,700 6,350 3,530

(MD) LNB 4.97 24.8 44.7 25 3.73 18.6 33.5 1.24 6.21 11.2 102,000 102,000 102,000 82,200 16,400 9,130

natural gas (ND) ULNB 4.97 24.8 44.7 50 2.48 12.4 22.4 2.48 12.4 22.4 40,100 40,100 40,100 16,100 3,230 1,790

(MD)ULNB 4.97 24.8 44.7 50 2.48 12.4 22.4 2.48 12.4 22.4 103,000 103,000 103,000 41,500 8,300 4,610(ND) SNCR 4.97 24.8 44.7 60 1.99 9.93 17.9 2.98 14.9 26.8 65,500 71,200 76,900 22,000 4,780 2,870(MD) SNCR 4.97 24.8 44.7 60 1.99 9.93 17.9 2.98 14.9 26.8 108,000 114,000 120,000 36,400 7,660 4,470SCR 4.97 24.8 44.7 75 1.24 6.21 11.2 3.73 18.6 33.5 421,000 436,000 451,000 113,000 23,400 13,500(MD) LNB + FGR 4.97 24.8 44.7 55 2.24 11.2 20.1 2.73 13.7 24.6 128,000 131,000 134,000 47,000 9,600 5,440(ND) LNB + SNCR 4.97 24.8 44.7 70 1.49 7.45 13.4 3.48 17.4 31.3 105,000 111,000 116,000 30,200 6,360 3,720(MD) LNB + SNCR 4.97 24.8 44.7 70 1.49 7.45 13.4 3.48 17.4 31.3 168,000 173,000 179,000 48,200 9,970 5,720(MD) LNB + SCR 4.97 24.8 44.7 81 0.93 4.66 8.38 4.04 20.2 36.3 481,000 497,000 512,000 119,000 24,600 14,100

84 (ND) LNB 5.96 29.8 53.6 25 4.47 22.4 40.2 1.49 7.45 13.4 39,400 39,400 39,400 26,400 5,290 2,940

(MD) LNB 5.96 29.8 53.6 25 4.47 22.4 40.2 1.49 7.45 13.4 102,000 102,000 102,000 68,500 13,700 7,610(ND) ULNB 5.96 29.8 53.6 50 2.98 14.9 26.8 2.98 14.9 26.8 40,100 40,100 40,100 13,400 2,690 1,490(MD) ULNB 5.96 29.8 53.6 50 2.98 14.9 26.8 2.98 14.9 26.8 103,000 103,000 103,000 34,600 6,920 3,840

high hydrogen (ND) SNCR 5.96 29.8 53.6 60 2.38 11.9 21.5 3.58 17.9 32.2 65,700 72,200 78,700 18,400 4,040 2,450

fuel gas (MD) SNCR 5.96 29.8 53.6 60 2.38 11.9 21.5 3.58 17.9 32.2 109,000 115,000 122,000 30,400 6,440 3,780

SCR 5.96 29.8 53.6 75 1.49 7.45 13.4 4.47 22.4 40.2 421,000 438,000 454,000 94,300 19,600 11,300(MD) LNB + FGR 5.96 29.8 53.6 55 2.68 13.4 24.1 3.28 16.4 29.5 128,000 131,000 134,000 39,200 8,000 4,530(ND) LNB + SNCR 5.96 29.8 53.6 70 1.79 8.94 16.1 4.17 20.9 37.5 105,000 112,000 118,000 25,200 5,350 3,140(MD) LNB + SNCR 5.96 29.8 53.6 70 1.79 8.94 16.1 4.17 20.9 37.5 168,000 174,000 181,000 40,200 8,350 4,810(MD) LNB + SCR 5.96 29.8 53.6 81 1.12 5.59 10.1 4.84 24.2 43.6 482,000 498,000 514,000 99,500 20,600 11,800

Cost effectiveness = Total annual cost/NO reductions.

a

x

TABLE 6-13. CARB COST EFFECTIVENESS FOR NOx EMISSION

CONTROL TECHNIQUES (1991 $)12

Control technology

Annual capacity factor,

percent

Unit size range,

MMBtu/hr

Cost effectiveness range,

thousand/ton NOx

a

Low-NO burners x 10

50

90

3.5 to 150 2.61 to 30.6

0.570 to 7.25

0.340 to 4.53

Flue gas recirculation 10

50

90

3.5 to 350 7.71 to 32.9

1.81 to 7.71

1.13 to 4.19

Selective noncatalytic reduction 10

50

90

50 to 375 2.61 to 22.7

1.70 to 6.80

1.47 to 4.31

Selective catalytic reduction 10

50

90

50 to 350 27.2 to 74.8

6.80 to 15.9

4.53 to 10.2

Escalated from 1986 $ to 1991 $ using the Chemical Engineering plant cost index. a 3
California Air Resources Board (CARB). The accuracy of the 12

cost methodologies used in this study is estimated to be

30 percent plus or minus the actual cost. The cost- 1

effectiveness values of the control techniques for the model

heaters are generally consistent with the ranges given in

Table 6-13.

When comparing the cost effectiveness of combination control

techniques in Table 6-13 to those in Tables 6-8 through 6-12, it

is necessary to add the cost effectiveness of each component in

Table 6-13. For example, the cost effectiveness of LNBs and SCR

should be added to yield the total cost effectiveness of LNBs

combined with SCR.

d. COST EFFECTIVENESS OF RADIANT BURNERS

This section presents the costs and cost-effectiveness

values for a process heater using radiant burners. Data are

insufficient to allow the development of model heaters with

radiant burners. However, cost data for a new installation were

provided for a 6 MMBtu/hr process heater using radiant burners. 

Retrofit costs are expected to be much higher for most process

heater applications due to the major construction cost of

modifying existing process heaters to accept radiant burners.5

Refer to Section 5.1.8 for a discussion of radiant burners. 

Emission reduction data for the 6 MMBtu/hr heater were

presented in Table 5-6. The capital costs, capital recovery,

annual costs, and cost-effectiveness values are presented in
TABLE 6-14. RADIANT BURNER COST EFFECTIVENESS5

Heater

capacity,

MMBtu/hr

Capacity

factor

Emission

reduction,

tons/yra

Cost, $ 1991

Cost

effectiveness,

$/ton Capital

Capital

recoveryb

Annual

operating

Total

annual

6 0.9 2.46 38,000 6,150 12,600 18,700 7,600

6 0.5 1.36 38,000 6,150 9,700 15,900 11,700

6 0.3 0.82 38,000 6,150 8,280 14,400 17,600

Emission reduction compared to an MD heater with conventional burners. a

The capital recovery factor is 0.131. b

Table 6-14. The capital cost for radiant burners for this heater

is $38,000. The annual costs range from $12,600/yr to $8,280/yr

for capacity factors of 0.9 and 0.3, respectively. The cost

effectiveness range from $7,600/ton to $17,600/ton for capacity

factors of 0.9 and 0.3, respectively.5

e. REFERENCES FOR CHAPTER 6

 1 A Study to Assess the Available Technology and Associated

Costs of Reducing NOx Emissions From the Canadian Petroleum

Refining Industry. Canadian Petroleum Products Institute. 

CPPI Report No. 91-1. November 28, 1990.

 2 Technical Support Document for a Suggested Control Measure

for the Control of Emissions of Oxides of Nitrogen From

Industrial, Institutional, and Commercial Boilers, Steam

Generators, and Process Heaters. Air Resources Board and

South Coast Air Quality Management District. April 29,

1987.

 3 Economic Indicators: Chemical Engineering Plant Cost Index. 

Chemical Engineering. Vol. 99(3):206. March 1992.

 4 OAQPS Control Cost Manual. United States Environmental

Protection Agency, Office of Air Quality Planning and

Standards. EPA 450/3-90-006. January 1990.

 5 Letter and attachments from Moreno, F., Alzeta Corporation,

to Sanderford, E., MRI. May 22, 1992. Cost comparison

between ND and MD conventional burners versus Alzeta

burners.

 6 Annual Energy Review 1990. Department of Energy/Energy

Information Administration-0384(90). May 1991. p. 157.

 7 Letter and attachments from Smith, J., Institute of Clean

Air Companies, to W. Neuffer, EPA/ESD. May 14, 1992. Use

of catalyst systems with stationary combustion sources.

 8 Telecon. Harris, R., MRI, with Davis, L., Exxon, Baton

Rouge. February 7, 1992. Low-NOx burner retrofits.

 9 Letter and attachments from Morrow, N., Exxon Chemical

Group, to Harris, R., Midwest Research Institute. Low-NOx

burner experience at Basic Chemicals plant.

10 Letter and attachments from Pickens, R., Nalco Fuel Tech, to

Neuffer, W., EPA/ISB. August 7, 1992. Comments on Draft

Alternative Control Techniques Document--Control of NOx

Emissions from Process Heaters.
11 Letter and attachments from Strickland, G., Chemical

Manufacturers Association, to Neuffer, W., EPA/ISB. 

September 9, 1992. Comments on Draft Alternative Control

Techniques Documents--Control of NOx Emissions from Process

Heaters.

12 California Clean Air Act Guidance. Determination of

Reasonably Available Control Technology and Best Available

Retrofit Control Technology for Industrial, Institutional,

and Commercial Boilers, Steam Generators, and Process

Heaters. California Air Resources Board. July 18, 1991.

7-1

7..0 ENVIRONMENTAL AND ENERGY IMPACTS

This chapter presents the environmental and energy impacts

for the NOx control techniques described in Chapter 5 for process

heaters. The impacts of low-NOx burners (LNBs), ultra low-NOx

burners (ULNBs), flue gas recirculation (FGR), selective

noncatalytic reduction (SNCR), and selective catalytic reduction

(SCR) on air pollution, solid waste disposal, and energy

consumption are discussed. These NOx reduction techniques

produce no water pollution impacts. Low excess air (LEA),

discussed in Section 5.1.1, reduced air preheat (RAP), discussed

in Section 5.1.8, and natural draft- (ND) to-mechanical draft

(MD) conversion are considered to be operational controls and can

have environmental and energy impacts. However, they are not

considered NOx control techniques and are not discussed

separately in this chapter.1

This chapter is organized into four sections. Section 7.1

presents air pollution impacts; Section 7.2 presents solid waste

impacts; and Section 7.3 presents energy consumption impacts; and

Section 7.4 presents the references for this chapter. 

a. AIR POLLUTION IMPACTS

i. NOx Emission Reductions

A summary of the achievable NOx emission reductions and

controlled emission levels for the process heater control

techniques is presented in Tables 5-11 through 5-15. The percent

reductions shown in these tables represent average reductions for

the combustion control techniques. Average reductions are

presented because the reductions from baseline emissions vary 
7-2

depending on the uncontrolled emission level, draft type, fuel

type and whether the heater has an air preheater. 

Low-NOx burners are designed for ND and MD operation and

achieve NOx reductions by staged-air or staged-fuel techniques. 

Emissions reductions for LNBs are approximately 50 percent over

conventional burners for both ND and MD LNBs, although one

manufacturer reports a 72 percent reduction for a staged-fuel MD

LNB. Staged-fuel LNBs, discussed in Section 5.1.4, yield the 1,2

highest NOx reductions for LNBs and are designed for firing

natural gas or refinery gas. Staged-air LNBs are utilized for

fuel oil-firing and are discussed in Section 5.1.3. 

Ultra low-NOx burners, discussed in Section 5.1.6, are

capable of reductions of 52 to 80 percent with an average of

approximately 75 percent. The highest reductions by burner

technologies are achieved with ULNBs. Ultra low-NOx burners

usually incorporate internal FGR or steam injection and are

designed for natural or refinery gas firing. 

Flue gas recirculation, discussed in Section 5.1.5, is

usually used in combination with LNBs with total NOx reductions

of approximately 55 percent over uncontrolled emissions.3

Heaters using conventional burners and FGR are expected to

achieve approximately a 30 percent reduction in NOx emissions. 

Selective noncatalytic reduction can be used as a sole NOx

control technique or in combination with LNBs. The reduction

efficiency of SNCR ranges from 30 to 75 percent. Selective

noncatalytic reduction systems are designed to achieve

site-specific permit limits, which accounts for the wide range of

reduction efficiencies. Temperature and the ratio of reactant to

NOx are the factors that affect SNCR reductions the most and are

further discussed in Section 5.2. According to Thermal DeNOx®

data in Table 5-7 and NOx OUT® data in Table 5-8, the maximum NOx

reduction for SNCR on process heaters is approximately

75 percent. A 60 percent NOx reduction was used in this study

for SNCR performance, based on current literature and average

reductions cited in data. 
7-3

Selective catalytic reduction can be used as a sole NOx

control technique or in combination with LNBs. Reported

reduction efficiencies for SCR range from 64 to 90 percent. 

Selective catalytic reduction systems are designed to achieve

site-specific permit limits, which accounts for the wide range of

reduction efficiencies. Temperature and the ratio of reactant to

NOx strongly affect the performance of SCR and are further

discussed in Section 5.3.

 According to the data in Appendix D, reductions of

90 percent with LNBs + SCR are achievable. However, on average,

SCR provides a 75 percent reduction of NOx in the flue gas. 

4,5

For the purposes of this study, this 75 percent reduction is used

for SCR.

ii. Emissions Trade-Offs

The formation of thermal and fuel NOx depend upon combustion

conditions. Combustion controls modify the combustion conditions

to reduce the amount of NOx formed. These modifications may

increase carbon monoxide (CO) and unburned hydrocarbon (HC)

emissions. Flue gas treatments (SNCR and SCR) reduce NOx by

injecting a reactant into the flue gas stream. Ammonia (NH3),

nitrous oxide (N2O), CO, and particulate matter (PM) emissions

can be produced by SNCR. Ammonia and PM emissions are also

produced with SCR. These air pollution impacts are described in

the following two sections.

(1) Impacts on HC and CO Emissions from the Use of LNBs,

ULNBs, and FGR. The extent to which NOx emissions can be reduced

by combustion controls may be limited by the maximum acceptable

increase in CO and HC emissions. Combustion controls for NO 7

x

reduction discussed in this chapter are LNBs, ULNBs and FGR.

The air pollution impacts for ULNBs and LNBs are similar and

are discussed collectively in this chapter as LNBs. Low-NOx

burners reduce NOx formation by reducing the peak flame

temperature and/or O2 concentrations in the flame zone. These

burners are more sensitive to LEA controls than conventional

burners. Improper control can cause incomplete combustion and

result in increased CO and HC emissions.6,7
7-4

In a test involving a process heater with LNBs, the effects

of excess air on operation, gaseous emissions, and heater

efficiency were evaluated. After testing each process heater in

the "as-found" condition to establish an emissions baseline,

burner registers and/or stack dampers were adjusted to produce

different O2 levels. Figure 7-1 plots the NOx emission factors

as a 
7-5

Figure 7-1. NOx emission factor for 10 process heaters equipped

with low-NOx burners as a function of stack oxygen.8
7-6

function of flue gas O2 content for the heaters tested. The

level of NOx decreases as the level of excess O2 decreases, but

below approximately 3 percent excess O2, significant CO emissions

or visible smoke occurred, and these points are marked in the

figure as "CO limits."8
7-7

Table 7-1
7-8

TABLE 7-1. OPTIMUM LOW-EXCESS-AIR, GASEOUS EMISSIONS

AND EFFICIENCIES FOR SIX PROCESS HEATERS WITH LOW-NO BURNERS x 8

As-found Optimum low-NO x

Capacity,

MMBtu/

hr

Heater

configurationa

NO,

ng/J

NO,

ppm

O ,2

percent

CO,

ppmb

Heater

efficiency,

percent

NO,

ng/J

NO,

ppm

O ,2

percent

CO,

ppmb

Heater

efficiency,

percent

16 211 92.4 168 5.1 11 64.0 80.4 145 4.0 11 64.022 121 39.0 77 6.2 0 79.9 24.0 48 3.0 20 83.030 121 51.6 102 6.7 13 73.1 32.9 65 2.8 10 74.4

320 132 57.9 114 4.8 11 69.8 38.1 75 3.5 11 71.3320 132 65.8 130 5.3 11 68.0 35.4 70 2.3 33 68.5320 132 60.2 119 8.4 0 66.4 32.9 65 3.3 10 68.8

Heater configuration designations as follows: a

1st digit 2nd digit 3rd digitFuel burned Draft type Air temp.1 = gas 1 = natural 1 = ambient2 = dist. oil 2 = forced 2 = preheater

3 = balanced

Dry, corrected to 3 percent O . b 2
7-9

 presents a summary of gaseous emissions and efficiencies for

each heater tested. A comparison of emissions at the as-found

conditions and at optimum low-NOx conditions (i.e., lowest NOx

emissions without adverse effects on flame stability or unit

efficiency) is provided in this table. The level of excess air

was adjusted to reduce NOx emissions with the additional benefit

of possibly increasing heater efficiency while maintaining

acceptable CO emissions. The lowest as-found NOx emission

concentration was 77 ppmv with 79.9 percent heater efficiency and

0 ppmv (corrected to 3 percent O2) CO emissions. By decreasing

the excess O2 level from 6.2 to 3.0 percent, NOx emissions were

reduced to 48 ppmv, heater efficiency was increased to

83.0 percent, and CO emissions increased to 20 ppmv (corrected to

3 percent O2). The highest as-found NOx emission concentration

was 168 ppmv with 64.0 percent heater efficiency and 11 ppmv CO

emissions (corrected to 3 percent O2). By reducing the O2 level

from 5.1 to 4.0, NOx emissions were reduced to 145 ppmv, heater

efficiency remained at 64.0 percent, and CO emissions remained at

11 ppmv (corrected to 3 percent O2).

At most sites, NOx emission reductions were achieved with

small increases or, at worst, no change, in thermal or fuel

efficiency. At the optimum low-NOx conditions, flame stability,

product flows and temperatures, and emissions of CO and HC, unit 
7-10
7-11

operations were generally unchanged from the as-found

conditions. The study showed that emissions reductions with 8

LNBs are optimized by controlling the excess air. Furthermore,

efficiency gains were achieved by lowering excess O2 levels to

approximately 3 percent. High CO emissions indicate incomplete

combustion, which would result in an efficiency loss.

Table 7-2 is a summary of a test with a John Zink PSRF-16M

burner that demonstrates the effects of excess air control on the

newer generation of LNBs. 

2
7-12

TABLE 7-2. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS

FOR A 20 MMBtu/hr REFINERY HEATER WITH LNB OPERATION 

(REFINERY FUEL GAS)2

O2, % NOx, ppma NOx, lb/MMBtu CO, ppmb

2.0 29 0.033 41

3.5 32 0.040 0

4.2 34 0.044 0

4.6 35 0.046 0

5.3 35 0.048 0

5.9 35 0.050 0

Heater is operated with an LEA system. a

Corrected to 3 percent O .

b

2
7-13

The data indicate that with proper control there were no CO

emissions for excess air levels at or above 3.5 percent. The

inverse relationship between NOx formation and CO formation is

evident at 2 percent excess O2, where NOx decreased to 29 ppmv

but CO increased to 41 ppmv (corrected to 3 percent O2). 

2

Data in Tables 7-1 and 7-2 indicate that LNBs are capable of

reducing NOx without causing excessive CO emissions. The highest

CO emissions in Table 7-1 were 33 ppmv at 3 percent O2. The

highest CO emissions in Table 7-2 were 41 ppmv at 3 percent O2. 

California Air Resources Board's best available retrofit control

technology specifies a CO emission limit of 400 ppmv for process

heaters with capacities of 5 MMBtu/hr or greater.2,6,9

Flue gas recirculation injects relatively inert flue gas

into the combustion air, thereby lowering the peak flame

temperature and diluting the O2 concentration. These effects

promote CO and HC emissions, but these effects can be minimized

with properly designed FGR and excess O2 systems. As discussed 6

in Chapter 5, data for process heater FGR is limited. However,

boiler data indicate that FGR is a viable control technique for

process heaters because boilers and process heaters use similar

burners and combustion systems. The primary limitation to FGR

use on process heaters is the recirculation of high-temperature

flue gas. Fans used on process heaters are required to withstand

higher temperatures than FGR fans on boilers with economizers. 

Table 7-3
7-14

TABLE 7-3. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS FOR A

6.7 MMBtu/hr (200 hp) BOILER WITH LNB + FGR10

Fuel Load, % % FGR % O2 NOx, ppma

lb NOx/

MMBtu CO, ppma

lb CO/

MMBtu

NG 66 0 4.22 74 0.106 11 0.062

NG 66 16.9 4.30 24 0.035 29 0.017

NG 100 0 4.00 80 0.117 16 0.014

NG 100 12.5 4.67 33 0.048 13 0.012

FOb 68 0 3.80 138 0.199 13 0.007

FOb 68 18.9 3.70 109 0.158 20 0.012

FOb 100 0 4.33 158 0.336 16 0.014

FOb 100 14.3 4.07 123 0.265 14 0.012

Corrected to 3 percent O .

a

2

No. 2 distillate fuel oil. b
7-15

 presents data on the impact of FGR on emissions for a 200-hp

firetube boiler. The boiler was operated at 66 and 100 percent 10

load firing natural gas. It was also operated at 
7-16
7-17

68 and 100 percent load firing distillate fuel oil. Emissions

were recorded with FGR and without FGR. Firing natural gas at

66 percent load, 0 percent FGR corresponded to NOx emissions of

74 ppmv (corrected to 3 percent O2) and CO emissions of 11 ppmv

(corrected to 3 percent O2). Using 16.9 percent FGR, NOx

emissions decreased to 24 ppmv (corrected to 3 percent O2), but

CO emissions increased to 29 ppmv (corrected to 3 percent O2). 

Firing natural gas at 100 percent load, 0 percent FGR

corresponded to NOx emissions of 80 ppmv (corrected to 3 percent

O2) and CO emissions of 16 ppmv (corrected to 3 percent O2). 

Using 12.5 percent FGR, NOx emissions decreased to 33 ppmv

(corrected to 3 percent O2) and CO emissions decreased to 13 ppmv

(corrected to 3 percent O2). The use of FGR while firing

distillate oil resulted in trends for NOx and CO emissions

similar to those for natural gas firing. As the percent of

recirculated flue gas was increased at partial load, NOx

decreased, but CO increased. As FGR was increased at full load,

NOx decreased, and CO decreased. For either natural gas or oil

firing, CO decreased at full load because the boiler's combustion

efficiency at 100 percent load is greater than at partial load.

(2) Impacts on NH3, N2O, CO, and PM Emissions from the Use

of SNCR and SCR. Currently, SNCR and SCR are the only

postcombustion NOx control techniques available for process

heaters. Combustion controls reduce NOx emissions by inhibiting

NOx formation, but SNCR and SCR utilize reactants injected into

the flue gas stream to reduce NOx that was formed during the

combustion process. Air pollution impacts associated with SNCR

and SCR are discussed below. 

Two SNCR processes for process heaters are currently in use. 

The processes are based on different reactants. Thermal DeNOx®

utilizes NH3 injection and NOxOUT® utilizes urea injection.

Emission of unreacted NH3, or NH3 slip, is the primary air

pollution impact with the Thermal DeNOx® and NOxOUT® SNCR

processes because of the high reactant-to-NOx injection ratio

(1.25 to 2.0:1). Figure 7-2 6
7-18

Figure 7-2. Pilot-scale test results, NH3 emissions. 

 Inlet NO = 700 ppm.12
7-19

 shows that at higher temperatures, when NH3 and urea are more

reactive, NH3 slip is reduced. In a 
7-20

typical refinery heater application, a 70 percent NOx reduction

is achievable with an NH3:NOx ratio of 1.25 and ammonia slip less

than 20 ppmv, the present SCAQMD limit. Therefore, NH slip 3

3

problems are not expected with properly designed SNCR systems. 

Oil-fired heaters have an additional concern with NH3

slip. Ammonium sulfate [(NH4)2SO3] deposits in the convection

section of the heater and PM emissions may result from NH3 slip

with the use of sulfur-bearing fuel oil.7

Leaks and spills from NH3 storage tanks and piping are

safety concerns because liquid or highly concentrated ammonia

vapor is hazardous. The Occupational Safety and Health 3,10

Administration standard limits occupational exposure of 50 ppmv

for an 8 hour period. However, NH handling is not expected to 7

3

present a problem as long as proper safety procedures are

followed.

Nitrous oxide and CO have been shown to be byproducts of 

urea injection. Nitrous oxide formation has been shown to be 11,12

a byproduct of ammonia injection, but studies show these

emissions to be less than 20 ppmv. While N O emissions from 1,12

2

conventional combustion equipment are low (less than 15 ppmv for

boilers) advanced combustion and emission control techniques

could increase N2O emissions. Nitrous oxide is the largest

source of stratospheric NO. The following reactions describe 12

the formation of N2O and CO, where the intermediate species HCNO

is a precursor:

OH + HNCO 6 NCO + H2O

NCO + NO 6 N2O + CO.12

Reduction of NOx with SNCR processes increases with

temperature up to approximately 980EC (1800EF) as demonstrated by

the results of a pilot scale test presented in Figure 7-3a. 
7-21

Figure 7-3. Pilot-scale test results; NOx reduction and N20

production versus temperature.12
7-22

 Formation of N2O also increases with temperature as shown in

Figure 7-3b. This pilot test showed the potential for N20

production by SNCR systems on combustion equipment such as

boilers and process heaters. For NH3 injection, the highest NOx

reductions occurred at about 980EC (1800EF) and the peak N2O

emissions (21 ppmv) occurred at about 880EC (1620EF). Urea 
7-23

injection resulted in peak NOx reductions and peak N2O emissions

(43 ppmv) occurred at about 980EC (1800EF).12

Ammonia slip concentrations of less than 10 ppmv are

expected using SCR for process heaters under steady state

conditions. The ratios of NH :NO (1.00:1 or less to 1.05:1) 6,7,9,13

3 x

for SCR are lower than for SNCR, which reduces the potential for

unreacted NH3 emissions. As with NH3 SNCR, ammonia storage and 11

transport safety procedures must be followed.

The bulk of catalysts used in SCR systems in refinery

service process heaters contain titanium and vanadium oxides.3

Catalysts older than 10 years tend to convert up to 5 percent of

any SO2 present in sulfur-bearing fuels to SO3. Catalysts 3

installed in the last 10 years are designed to convert less SO2

to SO3. Utility boilers firing sulfur-bearing fuels and using

SCR have demonstrated that conversions of less than one percent

are achievable. Sulfuric acid condensation in the flue gas may 13

result from SO3 emissions. In addition, formation of (NH4)2SO3

14

from SO3 and unreacted NH3 can result in deposits in the heater

exhaust ducting and PM emissions.7

b. SOLID WASTE IMPACTS

Current combustion controls and SNCR applied to process

heaters generate no solid waste. Catalyst materials used in SCR

units for process heaters include heavy metal oxides (e.g.,

vanadium or titanium) precious metals (e.g., platinum), and

zeolites. Vanadium pentoxide, the most commonly used SCR

catalyst in the United States, is identified as an acute

hazardous waste under RCRA Part 261, Subpart D - Lists of

Hazardous Wastes. However, the Best Demonstrated Available

Technology Treatment Standards for Vanadium P119 and P120 states

that spent catalyst containing vanadium pentoxide are not

classified as hazardous waste. States and local regulatory 15

agencies are authorized to establish their own hazardous waste

classification criteria, and spent catalyst containing vanadium

pentoxide may be classified as a hazardous waste in some areas. 

Although the actual amount of hazardous waste contained in the

catalyst bed is small, the volume of the catalyst unit containing
7-24

this material is quite large and disposal can be costly. Where

classified by State or local agencies as a hazardous waste, this

waste is subject to the Land Disposal Restrictions in 40 CFR

Part 268, which allow land disposal only if the hazardous waste

is treated in accordance with Subpart D - Treatment Standards. 

Such disposal problems are not encountered with the other

catalyst materials, such as precious metals and zeolites, because

these materials are not hazardous wastes. Currently, catalyst

vendors accept spent catalyst thereby alleviating disposal

considerations by SCR operators for all catalyst types.

c. ENERGY IMPACTS

The energy impacts of NOx control techniques applied to

process heaters may include additional electrical energy for fans

or blowers and lower thermal efficiency. The impacts of LNBs,

FGR, SNCR, and SCR are described in the following paragraphs. 

Currently, no information concerning the energy impacts of ULNBs

is available. These impacts are expected to be similar to LNBs.

The electrical energy impacts of NOx control techniques

include the additional power consumed by fans or blowers and air

compressors or pumps. Low-NOx burners, in general, do not have

any electrical energy impacts. An electric fan to recirculate

flue gas in addition to MD operation is required by FGR systems. 

The aqueous and anhydrous SNCR process require either a

compressed or steam carrier system. Air compressors for these

processes are electric motor driven, therefore having an

electrical energy impact. Selective catalytic reduction systems

cause flue gas pressure drops in the order of 25 to 130 mm w.g.

(1 to 5 in.) and require additional MD horsepower to overcome the

resistance to flow. The additional fan horsepower requirement 7

increases electrical energy usage slightly.

Combustion control techniques may affect the thermal

efficiency of process heaters. Reduction of flame temperature

generally reduces thermal NOx formation, but may decrease the

combustion efficiency. Reductions in combustion efficiency

usually indicate a reduction in the heater thermal efficiency. 
7-25

Current LNBs and FGR systems are balanced between optimum NOx

reduction and acceptable thermal efficiency.

As discussed in Section 7.1.2.1, heaters using LNBs were

tested to determine the effects of reducing excess air levels. 

Maximum combustion efficiency for process heaters is achieved

with excess O2 levels at approximately 3 percent. Thermal energy

is absorbed by excess air levels above 3 percent O2, which

decreases thermal efficiency because the heated excess air

carries thermal energy out of the heater with the flue gas. At

excess O2 levels below 3 percent, insufficient O2 concentrations

exist for complete fuel oxidation.

Low-NOx burners with LEA are typically slightly more fuel

efficient than conventional burners, as is shown in Table 7-1.4

However, flame instability associated with LNBs can require

reduced firing rates and loss of thermal efficiency. Loss of

thermal efficiency negates fuel credits derived from burner

efficiency gains.3

Utilization of FGR systems can affect the thermal efficiency

of process heaters, although recirculation of less than

approximately 20 percent flue gas does not adversely affect

thermal efficiency. The dilution of the combustion air supply 7

with inert products of combustion decreases the thermal

efficiency. Losses in efficiency are compensated for by 6

increased fuel firing. 

A thermal efficiency penalty of approximately 0.3 percent is

associated with SNCR. The NOxOUT® and aqueous Thermal DeNOx

®

process heat duty losses are due to the injection of the aqueous

reactant and distribution air in the convection section. The

anhydrous Thermal DeNOx process heat duty losses are also due to ®

the dilution of the flue gas with distribution air or steam. 

1

These losses result in increased fuel consumption.3

A thermal efficiency penalty of approximately 1.5 percent is

associated with SCR. Injection of the NH3 causes heat duty

losses similar to those described for SNCR. The pressure drop

across the catalyst also causes a thermal efficiency loss. These

losses result in increased fuel consumption.
7-26

d. REFERENCES FOR CHAPTER 7

1 Letter and attachments from Eichamer, P., Exxon Chemical

Company, to Neuffer, W., EPA/ISB. September 2, 1992. 

Comments on Draft Alternative Control Techniques Documents--

Control of NOx Emissions from Process Heaters. 

 2 Waibel, R., PhD. Advanced Burner Technology for Stringent

NOx Regulations. John Zink Company. Presented at American

Petroleum Institute Midyear Refining Meeting. May 8, 1990.

 3 A Study to Assess the Available Technology and Associated

Costs of Reducing NOx Emissions From the Canadian Petroleum

Refining Industry. Canadian Petroleum Products Institute. 

CPPI Report No. 91-1. November 28, 1990.

 4 Letter and attachments from Britt, J. Mobil Oil Corporation

to Jordan, B., EPA/ESD. April 29, 1992. Process heater NOx

emission control retrofit experience at Mobil's Terrance, CA

petroleum refinery.

 5 Letter and attachments from Franklin, H., Foster Wheeler

Energy Corporation, to Neuffer, W., EPA/ISB. 

April 27, 1992. Process heater SCR experience.

 6 Gomma, H., L. Hackemesser, and D. Cindric. NOx/CO Emissions

and Control in Ethylene Plants. Environmental Progress.

10(4):267-272. November 1991.

 7 A Suggested Control Measure for the Control of Emissions of

Oxides of Nitrogen From Industrial, Institutional, and

Commercial Boilers, Steam Generators and Process Heaters. 

Energy Section, Strategy Assessment Branch, Stationary

Source Division Air Resources Board and Rule Development

Division, South Coast Air Quality Management District. 

April 29, 1992.

 8 Research and Development, Emissions from Refinery Process

Heaters Equipped with Low-NOx Burners. Industrial

Environmental Research Laboratory. EPA-600/7-81-169. 

October 1981.

 9 California Clean Air Act Guidance. Determine of Reasonably

Available Control Technology and Best Available Retrofit

Control Technology for Industrial, Institutional and

Commercial Boilers, Steam Generators, and Process Heaters 

California Resources Board. July 18, 1991.

10 Letter and attachments from Erickson, W., Industrial

Products, Inc. to Hamilton, R., Texas Air Control Board. 

June 22, 1990. Flue gas recirculation for NOx control.
7-27

11 Teixeira, D. Widening the Urea Temperature Window. Paper

presented at 1991 Joint Symposium on Stationary Combustion

NOx Control. Washington, D.C. November 1991.

12 Muzio, L., and T. Montgomery. N2O Formation in Selective

Non-Catalytic NOx Reduction Processes. Paper presented at

1991 Joint Symposium on Stationary Combustion NOx Control. 

Washington, D.C. November 1991.

13 Letter and attachments from Wax, M., Institute of Clean Air

Companies, to Neuffer, W., EPA/ISB. August 27, 1992. 

Comments on Draft Alternative Control Techniques Document--

Control of NOx Emissions from Process Heaters.

14 Letter and attachments from Chichanowicz, J., Electric

Power Research Institute, to Bradley, M., NESCAUM. 

November 21, 1991. Comments on the draft document

"Evaluation and Costing of NOx Controls for Existing Utility

Boilers in the NESCAUM Region."

15 55 FR 22276, June 1, 1990.
7-28

APPENDIX A. REFINERY PROCESS HEATER INVENTORYa

Heater Heater Capacity No. of burners Heater preheat, content, % % rated capacity emission factor, Method of

No. type MMBtu/hr in heater installed date Draft type Fuel type EF 0 Dry at time of test lb NO /MMBtu determination b c d e f

Air Oxygen Heater load, Uncontrolled NO

c

2

c

10a 10b 10d

x

x

11 DWB 186 32-WF 1942 ND/MD HPBL 450 3.8 101.7 0.224 CALC

12 HC 96 14-WF 1942 ND/MD HPBL 510 3.8 70.3 0.296 CALC

13 DWB 189 32-WF 1945 ND/MD HPBL 500 3.8 75.6 0.241 TEST

14 SWB 56 12-WF 1948 ND/MD HPBL 560 3.8 95.9 0.257 CALC

15 HC 251 36-FF 1953 ND/MD HPBL 463 3.8 83.5 0.223 CALC

(0.121)

16 HC 76 24-FF (18) 1953 ND/MD HPBL 570 3.8 118.7 0.323 CALC

(0.121)

17 HC 251 36-FF 1953 ND/MD HPBL 463 3.8 108.7 0.223 CALC

19 HC 76 24-FF 1953 ND/MD HPVL 570 3.8 119.2 0.323 TEST

18 HC 289 24-FF 1967 ND/MD HPBL 611 3.8 78.6 0.278 TEST

20 HC 117 16-FF 1967 ND/MD HPBL 615 3.8 96.8 0.279 CALC

65 HCHW 171 48-FF 1963 ND/MD NSPS 488 3.8 107.3 0.130 CALC

66 HCHW 150 48-FF 1968 ND/MD NSPS 540 3.8 92.4 0.140 TEST

126 HCHW 113 48-FF 1978 ND/MD NSPS 524 3.8 107.3 0.137 CALC

(0.065)

127 HCHW 113 48-FF 1978 ND/MD NSPS 524 3.8 107.3 0.137 CALC

41 VC-P 97 8-FF 1958 ND/MD HPBL 625 3.8 110.9 0.241 TEST

42 VC 29 4-FF 1958 MD/ND HPBL 794 3.8 125.1 0.308 CALC

47 HC 61 18-FF 1966 MD/ND HPBL 670 3.8 92.1 0.189 TEST

118 VTB 255 10-FF 1976 MD NSPS 725 3.8 84.3 0.167 CALC

119 VTB 255 10-FF 1977 MD NSPS 725 3.8 79.5 0.167 TEST

128 VC 161 12-FF 1979 MD/ND NSPS 500 3.8 64.2 0.128 TEST

131 VC 80 12-FF 1978 MD/ND NSPS 640 3.8 66.7 0.157 CALC
APPENDIX A. (continued)

Heater Heater Capacity No. of burners Heater preheat, content, % % rated capacity emission factor, Method of

No. type MMBtu/hr in heater installed date Draft type Fuel type EF 0 Dry at time of test lb NO /MMBtu determination b c d e f

Air Oxygen Heater load, Uncontrolled NO

c

2

c

10a 10b 10d

x

x

7-29

129 VC 50 8-FF 1979 MD/ND NSPS 640 3.8 106.2 0.157 CALC

72 SHTC 164 24-FF 1969 MD/ND HPBL 762 3.8 86.2 0.076 CALC

73 SHTC 196 24-FF 1969 MD/ND HPBL 773 3.8 73.9 0.077 TEST

74 SHTC 111 24-FF 1969 MD/ND HPBL 625 3.8 120.1 0.062 CALC

21 HC 40 20-FF 1950 ND HPBL -AMB- 3.8 50.0 0.111 CALC

43 VC 14 4-FF 1958 ND HPBL -AMB- 3.8 69.3 0.085 CALC

45 VC 35 7-FF 1958 ND HPBL -AMB- 3.8 64.9 0.111 CALC

46 VC 20 4-FF 1958 ND HPBL -AMB- 3.8 35.0 0.111 CALC

75 SHTC 151 18-FF 1969 ND HPBL -AMB- 3.8 67.5 0.111 CALC

76 VC 45 4-FF 1969 ND HPBL -AMB- 3.8 23.3 0.111 CALC

77 VC 23 3-FF 1969 ND HPBL -AMB- 3.8 24.8 0.111 CALC

78 VC 38 6-FF 1969 ND NSPS -AMB- 3.8 66.3 0.083 CALC

81 VC 100 12-FF 1969 ND HPBL -AMB- 3.8 87.3 0.071 CALC

82 VC 191 20-FF 1969 ND HPBL -AMB- 3.8 80.6 0.071 CALC

48 VTB 120 20-FF 1966 ND HPBL -AMB- 3.8 52.8 0.071 TEST

100 VC 40 4-FF 1972 ND HPBL -AMB- 3.8 26.8 0.071 CALC

105 VC 33 4-FF 1972 ND HPBL -AMB- 3.8 64.8 0.083 CALC

116 VC 48 4-FF 1974 ND NSPS -AMB- 3.8 95.0 0.083 CALC

133 VC 52 4-FF 1980 ND NSPS -AMB- 3.8 27.1 0.077 CALC

117 VC 72 6-FF 1974 ND NSPS -AMB- 3.8 66.3 0.083 CALC

84 VTB 148 42-FF 1969 ND HPBL -AMB- 3.8 56.0 0.064 CALC

85 VC 20 4-FF 1970 ND HPBL -AMB- 3.8 72.5 0.111 CALC
APPENDIX A. (continued)

Heater Heater Capacity No. of burners Heater preheat, content, % % rated capacity emission factor, Method of

No. type MMBtu/hr in heater installed date Draft type Fuel type EF 0 Dry at time of test lb NO /MMBtu determination b c d e f

Air Oxygen Heater load, Uncontrolled NO

c

2

c

10a 10b 10d

x

x

7-30

24 DWB 24 4-FF 1934 ND HPBL -AMB- 3.8 64.5 0.111 CALC

108 VC 15 3-FF 1972 ND HPBL -AMB- 3.8 27.3 0.111 CALC

110 VC 82 8-FF 1973 ND HPBL -AMB- 3.8 55.9 0.083 CALC

107 VC 122 20-FF 1972 ND HPBL -AMB- 3.8 58.9 0.083 CALC

28 HC 186 28-FF 1958 ND HPBL -AMB- 3.8 52.4 0.094 CALC

60 VC 121 16-FF 1966 ND HPBL -AMB- 3.8 116.4 0.111 TEST

58 HC 76 12-FF 1953 ND HPBL 250 3.8 72.8 0.105 CALC

59 HC 61 9-FF 1954 ND HPBL 250 3.8 81.3 0.105 CALC

55 HC 40 12-WF 1949 ND HPBL -AMB- 3.8 67.5 0.111 CALC

49 VC-P 93 7-FF 1973 ND HPBL -AMB- 3.8 37.8 0.111 CALC

51 SWB 20 4-WF 1943 ND HPBL -AMB- 3.8 103.5 0.071 CALC

83 VC 28 4-FF 1972 ND HPBL -AMB- 3.8 17.1 0.106 CALC

109 VC 14 3-FF 1973 ND HPBL -AMB- 3.8 62.9 0.106 CALC

22 VC 16 4-FF 1958 ND HPBL -AMB- 3.8 18.8 0.083 CALC

40 COB 576 15-WF 1966 MD HPBL/CO -AMB- 6.7 99.1 0.21 CALC

Reference 16 from Chapter 5. a

VC = Vertical cylinder, VC P = vertical cylinder, petrochem; SWB = single wing box, DWB = double wing box, HC = horizontal cabin with hot wall, b

 HCHW = horizontal cabin with hot wall; SHTC = single hoop tube cabin; VTB = vertical tube box; and COB = carbon monoxide boiler. 

Design basis, actual varies. c

WF = wall-fired and FF = floor-fired. d

ND = Natural draft and MD = mechanical draft. e

HPBL = High pressure burner line fuel gas; and NSPS = new source performance standard fuel gas. f
B-1

APPENDIX B. CURRENT AND FUTURE NOxOUT® APPLICATIONSa

Unit type Fuel Size MW ppm reduction EF removed/year b

NOx baseline Guaranteed % Temperature $/ton NOx

Tang-fired Bituminous 75 200 30 1800-2000 913

T-fired Coal 75 200 30 1800-2000 913

Tower #6 fuel oil 150 200 75 1300-2100 NA

Zurn stoker Wood waste 44 150 60 1850 NA

Pulverized coal Bituminous 2 200 85 1200-1850 NA

test unit coal

Cell-fired Wood waste 13 200 60 1700-2000 955

Hydrograte Bark CH 39.5 85-125 35 1700-1800 NA

Detroit Stoker

1 4

Incinerator Waste gas 8 130-260 60-80 1600-1800 NA

Front-fired #6 fuel oil 30 300 65 1500-2000 NA

CE stoker Coal 200 356 40 1950-2070 591

Incinerator Contaminated 1.9 600-1000 60 2190 NA

Thermal soil

Moving grate MSW 264 TPD 200 68 1200-1800 NA

incinerator

On-going utility Oil 325 220 60 2100 NA

boiler

Ethylene cracker Natural gas NA 90 55 1922 NA

Cat cracker Crude 30-50 10 1400 NA

Detroit Stoker MSW 300 TPD 110 60 1300-1600 NA

Pilot unit Coal 0.47 220 50 1520-1580 NA

Moving grate MSW 360 TPD 200 70 1600-2000 NA

incinerator

Front-fired Ind. Paper 7.2 392 50 1890-1910 670

boiler #3

Front-fired Ind. Fiber waste 17.2 526 50 1884-1962 670

boiler #4

Moving grate MSW 528 TPD 183 62 1650 NA

Stoker-fired Wood 35 140 52 1850-1950

Grate-fired Wood 19 145 30 NA 1258

CFB Wood waste 0.341 125 60 1575-1650 NA
APPENDIX B: (continued)

Unit type Fuel Size MW ppm reduction EF removed/year b

NOx baseline Guaranteed % Temperature $/ton NOx

B-2

Bottom-fired Refinery gas, 17.7 38-50 35-60 1800-2000 1180

process heater CH4

Side-fired Refinery gas, 5 65 50-75 1800-2000 1180

process heater CH4

CFB Coal 45 250 54 1200-1600 629

GT/HRSG Refinery Gas 63 75 50 1650 660

Volund grate- MSW 10.8 300 50 NA 778

fired

Front-fired #6 Fuel Oil 850 450 50 1300-1900 NA

CFB Bituminous 40 130 70-80 1580 NA

Coal

Moving grate Tires 7.5 85 40 1800-2000 NA

incinerator

Sludge Paper sludge, 6 570 50 1800 865

Combustor CH4

CFB/limestone Coal 29.8 40 33 1700-1850 NA

CFB Low sulfur coal 0.256 150 67 1400-1500 NA

CFB Bituminous 12 175 88 1600 NA

coal

Package boiler #6 fuel oil 10.3 105 27-40 1700-1800 NA

Riley Stoker Wood 22.5 NA 25 1800 2229

Pulverized coal Brown coal 150 250 70 1200-2100 NA

corner-fired

Pulverized coal Brown coal 75 150 65 1200-1950 NA

corner-fired

Front-fired Natural gas 110 150 45 1600-1900 NA

Front-fired #6 fuel oil 110 240 70 1600-1900 NA

Grate fired Hog fuel oil, 90 270 50 1900-2200 580

bark

Glass furnace Natural gas NA 1000 55 1675 NA

Waste heat Refinery gas 66.5 230 65 NA 439

boiler

Pulverized coal Bituminous 50 650 83 1300-2000 NA

front-fired Coal
APPENDIX B: (continued)

Unit type Fuel Size MW ppm reduction EF removed/year b

NOx baseline Guaranteed % Temperature $/ton NOx

B-3

Industrial #6 fuel oil 8.53 120 60 1500-2000 NA

Pilot/CFB Coal 1 178 54 1715 NA

CFB Wood 28 150 70 NA NA

Grate type Wood waste 190 70-120 42-78 1680 NA

(MMBtu/hr)

NA Coal 5 NA NA NA NA

Moving grate MSW 32.5 240 65 1700-1900 NA

incinerator

Grate-fired Tires 17 80 50 1,418

Future Oil 185 200 50 1950-2100 863

tangentially

fired utility

boiler

Stoker boiler Biomass 44 150 50 1850 614

Cell-fired Wood waste 13 200 60 1700-2000 955

Grate-fired Tires 17 80 50 1900-2050 1418

Package boiler Landfill gas 17 25 NA NA NA

Recovery boiler Black liquor 72 60 60 NA NA

Fluidized bed Organic gases 1.6 130-160 50-60 1800 3,373

furnace (contains

nitrogen)

Calciner Heat coke NA NA 50 NA NA

NA = Not available

Reference 26 from Chapter 5. a

Rated power output. b
C-1

APPENDIX C. LIST OF PROCESS HEATER NOx CONTROL RETROFITS FOR

MOBIL TORRANCE REFINERYa

Heater hr nology lb/MMBtu nology lb/MMBtu tions, %

Capacity, Preretrofit Preretrofit NO Post-retrofit Post-retrofit NO NO

MMBtu/ control tech- emissions, control tech- emissions, emission reducx x x

IF-1 457 LNB 0.056 SCR 0.02 64.3

IF-2 161 LNB 0.0773 SCR 0.05 74.1

2F-2 108 LNB 0.0553 ULNB 0.05 9.6

3F-1A 17.2 None 0.15 ULNB 0.0327 78.2

3F-18 17.2 None 0.15 ULNB 0.035 76.7

3F-2A 21.1 None 0.15 UNLB 0.040 73.3

3F-2B 21.1 None 0.15 ULNB 0.031 79.3

3F-3 129 LNB 0.0819 ULNB 0.07 14.5

3F-4 73 LNB 0.1127 ULNB 0.07 37.9

4F-1 527 None 0.2288 ULNB 0.06 73.8

6F-1 39.6 None 0.07 ULNB 0.032 54.3

6F-2 64 None 0.1607 ULNB 0.06 62.7

19F-1 288 LNB 0.0877 SCR 0.020 77.2

20F-2 220 LNB 0.1002 SCR 0.020 80.0

22F-2 91 LNB 0.0793 LNB 0.10

22F-3 91 None 0.115 LNB 0.10 13.0

50F-1 12 None 0.12 UNLB 0.0375 68.8

Reference 14 from Chapter 5. a
APPENDIX D. FOSTER WHEELER PROCESS HEATER SCR INSTALLATIONSa

Date of 11/82 6/83 8/83 1/86 7/86 8/86 8/86 10/90 8/90 12/93 12/92 12/92

installation

Type PH PH PH PH PH PH PH PH PH PH PH PH

Fuel Gas Gas Gas, SO = Gas Gas, SO = Gas Gas Gas, SO = Gas Gas Gas Gas x

12 ppm 17 ppm 23 ppm

x x

Additional NOx N/A N/A N/A N/A N/A N/A N/A LNB N/A N/A N/A N/A

Control

b

Inlet gas flow, 3.6 x 10 3.2 x 10 1.0 x 10 11.8 x 10 1.9 x 10 0.5 x 10 0.7 x 10 8 x 10 5 x 10 2.3 x 10 15 x 10 5 x 10

ft /hr 3

6 6 6 6 6 6 6 6 6 6 6 6

Inlet 680 700-750 700-750 580 630 725 720 625 680 700 695 600

temperature, EF

Catalyst material V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5 V O2 5

Support material T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2 T O2 2

Support Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb Honeycomb

configuration

Pressure drop, 2.5 2.0 3.5 0.9 0.8 0.7 0.1 1.3 1.5 2.6 3.3 3.0

in. H2O

Inlet condi- 105 100 80 267 38 45 45 96 60 65 80 74

tions--NOx ppm

Guaranteed 90 90 75 55 47 56 56 90 N/A <50 ppm N/A N/A

percent NOx

reduction

Guaranteed NH3 10 10 10 10 10 10 10 10 20 5 10 @ 3% O 10 @ 3% O

SLIP, ppm

2 2

Design NH3/ 1.0 1.0 0.9 0.6 0.7 0.8 0.8 1.0 N/A 1.0 1.02 1.01

NOx

Guaranteed 2 2 2 3 3 3 3 3 3 3 3 3

catalyst life,

years

Reference 29 from Chapter 5 a

N/A = not available.