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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
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.
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
iii
TABLE OF CONTENTS (continued)
Section Page
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
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
iv
Section Page
6.1.3 Costs ofSNCR . . . . . . . . . . . . . . 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 ofSCR . . . . . . . . . . . . . . . 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 ofFGR . . . . . . . . . . . . . . . 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 ofLNBs 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
6.2.4 Control Costs for MD Oil-Fired, Low- and
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
7.0 ENVIRONMENTAL AND ENERGY IMPACTS . . . . . . . . . . . 7-1
7.1 AIR POLLUTION IMPACTS . . . . . . . . . . . . . . 7-1
7.1.1 NOx Emission Reductions . . . . . . . . . 7-1
v
Section Page
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
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
vi
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 MEDIUM-
TEMPERATURE HEATERS . . . . . . . . . . . . . 2-9
CAPITAL COSTS, AND COST EFFECTIVENESS FOR
MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-
CAPITAL COSTS, AND COST EFFECTIVENESS FOR ND,
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE
HEATERS . . . . . . . . . . . . . . . . . . . 2-14
CAPITAL COSTS, AND COST EFFECTIVENESS FOR MD,
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE
HEATERS . . . . . . . . . . . . . . . . . . . 2-15
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
vii
LIST OF TABLES (continued)
Page
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 OIL-
FIRED, LOW- AND MEDIUM-TEMPERATURE ND
WITHOUT PREHEAT . . . . . . . . . . . . . . . 4-31
FACTORS: DISTILLATE AND RESIDUAL
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE MD
WITH PREHEAT . . . . . . . . . . . . . . . . . 4-31
FACTORS: NATURAL GAS-FIRED AND HIGH-
HYDROGEN 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
viii
Page
TABLE 5-5. CONTROLLED NOx EMISSION LEVELS FOR STAGED-
FUEL 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 MEDIUM-
MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-
ND OIL-FIRED HEATERS . . . . . . . . . . . . . 5-54
MD OIL-FIRED HEATERS . . . . . . . . . . . . . 5-55
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
OIL-FIRED MODEL HEATERS . . . . . . . . . . . 6-17
TABLE 6-5. COSTS OF CONTROL TECHNIQUES FOR MD OIL-FIRED
MODEL HEATERS . . . . . . . . . . . . . . . . 6-19
OLEFINS PYROLYSIS MODEL HEATERS . . . . . . . 6-20
ix
Page
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
FOR MD NATURAL GAS-FIRED MODEL HEATERS . . . . 6-26
FOR ND OIL-FIRED MODEL HEATERS . . . . . . . . 6-28
FOR MD OIL-FIRED MODEL HEATERS . . . . . . . . 6-29
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
FOR A 6.7 MMBtu/hr (200 hp) BOILER WITH
LNB PLUS FGR . . . . . . . . . . . . . . . . . 7-9
x
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
capacity factor of 0.9 for MD, natural
gas-fired, low- and medium-temperature
heaters . . . . . . . . . . . . . . . . . . . 2-18
capacity factor of 0.9 for ND, oil-fired,
low- and medium-temperature heaters . . . . . 2-19
capacity factor of 0.9 for MD, oil-fired,
low- and medium-temperature heaters . . . . . 2-20
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
xi
LIST OF FIGURES (continued)
Page
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 gas-
fired refinery process heaters with known
burner configuration, draft type, and air
preheat conditions . . . . . . . . . . . . . . 4-20
Figure 4-8. Uncontrolled NOx emission rates for gas-
fired 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
xii
LIST OF FIGURES (continued)
Page
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
xiii
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
1-1
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.
1-2
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.
2-1
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.
2-2
2-3
TABLE 2-1. UNCONTROLLED EMISSION FACTORS FOR MODEL HEATERS
Uncontrolled emission factor,

lb/MMBtu
Model heater type Thermal NOx Fuel NOx Total NOxa
ND, natural gas-firedb 0.098 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 0.162 d N/A 0.140
a
Total NOx = Thermal NOx + Fuel NOx
b
Heaters firing refinery fuel gas with up to 50 mole percent hydrogen can have up to 20 percent higher NOx
emissions than similar heaters firing natural gas.
c
High-hydrogen fuel gas is fuel gas with 50 mole percent or greater hydrogen content.
d
Calculated assuming approximately 50 mole percent hydrogen.
N/A = Not applicable.
2-4
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
2-5
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
2-6
reduction efficiencies and the reduction efficiencies for FGR,
and SNCR are based on a Canadian Petroleum Products Institute
report. Tables 2-2
2-7
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 NOx reduction,a percent
LNB 50
ULNB 75
SNCR 60
SCR 75
LNB + FGR 55
LNB + SNCR 80
LNB + SCR 88
Control technique - pyrolysis furnaces Total effective NOx reduction,a percent

LNB 25
ULNB 50
SNCR 60
SCR 75
LNB + FGR 55
LNB + SNCR 70
LNB + SCR 81
a
Further discussion on the NOx reduction efficiencies of each control technique is included in Chapter 5.
2-8
and 2-3
TABLE 2-3.
present
REDUCTION
the reduction
EFFICIENCIES
efficiencies
FOR CONTROL
for each
TECHNIQUES
NOx control
APPLIED
TO ND AND MD, DISTILLATE AND RESIDUAL OIL-FIRED PROCESS HEATERS
Draft and fuel type Control technique Total effective NOx reduction,a percent
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
a
Further discussion on the NOx reduction efficiencies of each control technique is included in Chapter 5.
b
Reduction efficiencies for ND or MD SNCR are equal.
2-9
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
2-10
2-11
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. Low-
NOx 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 oil-
fired 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.
2-12
TABLE 2-4. MODEL HEATERS: NOx EMISSION REDUCTIONS, CAPITAL COSTS, AND COST EFFECTIVENESS
FOR ND, NATURAL GAS-FIRED LOW- AND MEDIUM-TEMPERATURE HEATERS
Cost effectiveness, $/ton @ capacity

Model heater Uncontrolled NOx factors:c
capacity, MMBtu/hr emission factor, lb/MMBtu Total effective NOx NOx reduction,
0.1 0.5 0.9
NOx control technique reduction, percent tons/yra,b Capital cost, $
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)

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

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
a
NO x reductions = Uncontrolled emission factor (lb/MMBtu) * Capacity(MMBtu/hr) * Effective reduction (%) * 1 ton/2,000lb * 8,760 hr/yr * Capacity factor.
b
NOx 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
above equation.
c
Cost effectiveness is calculated by dividing the total annual cost (TAC) by the NOx reductions. Refer to Chapter 6 for the TAC.
TABLE 2-5. MODEL HEATERS: NOx EMISSION REDUCTIONS, CAPITAL COSTS, AND COST EFFECTIVENESS
FOR MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS
Cost effectiveness, $/ton @ capacity factors:c

Uncontrolled NOx
Model heater emission factor, NOx control Total effective NOx NOx reduction, 0.1 0.5 0.9
capacity, MMBtu/hr lb/MMBtu technique reduction, percent tons/yra,b Capital cost, $
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
Cost effectiveness, $/ton @ capacity factors:c

Uncontrolled NOx
Model heater emission factor, NOx control Total effective NOx NOx reduction, 0.1 0.5 0.9
capacity, MMBtu/hr lb/MMBtu technique reduction, percent tons/yra,b Capital cost, $
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
a
NO x reductions = Uncontrolled emission factor (lb/MMBtu) * Capacity(MMBtu/hr) * Effective reduction (%) * 1 ton/2,000lb * 8,760 hr/yr * Capacity factor.
b
NOx 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
above equation.
c
Cost effectiveness is calculated by dividing the total annual cost (TAC) by the NOx reductions. Refer to Chapter 6 for the TAC.
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.
costs, and cost effectiveness at a capacity factor of 0.9 for MD,
natural gas-fired, low- and medium-temperature heaters.
costs, and cost effectiveness at a capacity factor of 0.9 for ND,
oil-fired, low- and medium-temperature heaters.
costs, and cost effectiveness at a capacity factor of 0.9 for MD
oil-fired, low- and medium-temperature heaters.
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
(N2O) 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.1 Detailed technical descriptions of design
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.1 Process
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.
3.1.1 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.1 This type of process
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.2 Fired heaters are used in a wide variety of
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 set-
ups, 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
3-2
flows. A typical process heater displaying this equipment is
shown in Figure 3-1.4
3-3
3-4
Figure 3-1. Cross-section of a typical process heater.4
3-5
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.4 This
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.7 Extended tubes can reduce
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
3-6
between the hot flue gas in the stack and the significantly
cooler ambient air surrounding the stack.6 Approximately
90 percent of all gas-fired heaters and 76 percent of all oil-
fired 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).8 Though combustion air is supplied to the burners
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.8 Combustion air preheat has limited
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
3-7
Preheaters allow heat to be transferred to the combustion air
from flue gas, steam, condensate, hydrocarbon, or other hot
streams.6 The preheater increases the efficiency of the process
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.4,6 Figure 3-2
3-8
Figure 3-2. Examples of radiant section tube orientations.10
3-9
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.11 The burner chosen must provide a radiant heat
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.6,11 Long conical
flames are used in cases where a uniform heat distribution is
needed in the radiant section.11
3-10
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
3-11
Figure 3-3. Typical burners by type of fuel burned.14
3-12
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
3-13
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.16 In general, the
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, 1991.17 Most of the heaters in
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/hr2.
Figure 3-4
3-14
Figure 3-4. Size distribution of the existing fired heater
population.18
3-15
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
3-16
494,000 bbl/d.19 As of January 1, 1991, the capacity range was
2,500 bbl/d to 433,000 b/d.17 This lower capacity range, coupled
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
3-17
TABLE 3-1. SURVEY OF OPERATING REFINERIES IN THE U.S.17
(State capacities as of January 1, 1991)
Crude capacity,
State No. of plants bbl/d
Alabama 4 166,000
Alaska 6 243,000
Arizona 2 14,200
Arkansas 3 60,500
California 30 2,210,000
Colorado 3 91,200
Delaware 1 140,000
Georgia 2 35,500
Hawaii 2 143,000
Illinois 7 973,000
Indiana 4 427,000
Kansas 8 351,000
Kentucky 2 219,000
Louisiana 19 2,330,000
Michigan 4 124,000
Minnesota 2 286,000
Mississippi 5 359,000
Montana 4 136,000
Nevada 1 4,500
New Jersey 6 494,000
New Mexico 4 77,300
New York 1 39,900
North Dakota 1 58,000
Ohio 4 454,000
Oklahoma 7 409,000
Oregon 1 N/A
Pennsylvania 7 731,000
Tennessee 1 60,000
Texas 31 3,880,000
Utah 6 155,000
Virginia 1 53,000
Washington 7 521,000
West Virginia 2 29,700
Wisconsin 1 32,000
Wyoming 5 165,000
TOTAL 194 15,500,000
N/A = Not available.
3-18
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 3,200.20 The number of process heaters at
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 1014 MMBtu/yr) by the
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
3-19
TABLE 3-2. MAJOR REFINERY PROCESSES REQUIRING A FIRED HEATER22
Feedstock
Process heat requirements temperature
Heaters outlet of
KJ/liter 103 Btu/bbl feed
Process Process description used heater, EF
Distillation
Atmospheric Separates light hydrocarbons from crude in a Preheater, 590 89 700
distillation column under atmospheric conditions. reboiler
Vacuum Separates heavy gas oils from atmospheric Preheater, 418 63 750-830
distillation bottoms under vacuum. reboiler
Thermal processes
Thermal cracking Thermal decomposition of large molecules into Fired 4,650 700 850-1,000
lighter, more valuable products. reactor
Coking Cracking reactions allowed to go to completion. Preheater 1,520 230 900-975
Lighter products and coke produced.
Visebreaking Mild cracking of residuals to improve their Fired 961 145 850-950
viscosity and produce lighter gas oils. reactor
Catalytic cracking
Fluidized catalytic Cracking of heavy petroleum products. A catalyst Preheater 663 100 600-885
cracking is used to aid the reaction.
Catalytic Cracking heavy feedstocks to produce lighter Preheater 1,290 195 400-850
hydrocracking products in the presence of hydrogen and a
catalyst.
Hydroprocessing
Hydrodesul- Remove contaminating metals, sulfur, and Preheater 431 65a 390-850
furization nitrogen from the feedstock. Hydrogen is added
and reacted over a catalyst.
Hydrotreating Less severe than hydrodesulfurization. Removes Preheater 497 75b 600-800
metals, nitrogen, and sulfur from lighter
feedstocks. Hydrogen is added and reacted over a
catalyst.
Hydroconversion
Alkylation Combination of two hydrocarbons to produce a Reboiler 2,500 377c 400
higher molecular weight hydrocarbon. Heater
used on the fractionator.
Catalytic Low-octane napthas are converted to high-octane, Preheater 1,790 270 850-1,000
reforming aromatic napthas. Feedstock is contacted with
hydrogen over a catalyst.
aHeavy gas oils and middle distillates.

bLight distillate.
cBtu/bbl of total alylate.
3-20
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 1015 Btu/yr, and in 1985 it
increased to 2.2 x 1015 Btu/yr.23 Because the most current
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 1015 Btu/yr. Figure 3-5
3-21
Figure 3-5. Annual energy consumption projection for process
heaters used in petroleum refining.23
3-22
displays the growth estimate for the petroleum refining industry
energy consumption, based on the 1985 information.
3-23
3-24
3-25
The known energy requirement of the major chemical industry
fired heater applications in 1985 was 6.5 x 1014 Btu/yr and is
shown in Table 3-3
3-26
TABLE 3-3. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER APPLICATIONS IN THE
CHEMICAL INDUSTRY 24
1985 fired heater energy % of known chemical
requirement, industry heater
Chemical Process Heater type Firebox temperature ( EF) 10 12 Btu/yr requirements
Low- and medium-temperature applications
Benzene Reformate extraction Reboiler 700 64.8 9.9
Styrene Ethylbenzene Steam superheater 1,500 - 1,600 32.1 4.9

dehydrogenation
Vinyl chloride monomer Ethylene dichloride Cracking furnace N/A 12.6 1.9
cracking
P-Xylene Xylene isomerization Reactor fired preheater N/A 13.0 2.0
Reaction of p-xylene and Preheater, hot oil furnace

Dimethyl terephthalate methanol 480 - 540 11.1 1.7
Butylene
3-27
Butadiene dehydrogenation Preheater, reboiler 1,100 2.6 0.4
Ethanol (synthetic) Ethylene hydration Preheater 750 1.3 0.2
Acetone Various Hot oil furnace N/A 0.8 0.1
Others See Table 3-7
High-temperature applications
Ethylene/propylene Thermal cracking Pyrolysis furnace 1,900 - 2,300 337.9 51.8
Ammonia Natural gas reforming Steam hydrocarbon 1,500 - 1,600 150.5 23.1
reformer
Methanol Hydrocarbon reforming Steam hydrocarbon 1,000 - 2,000 25.7 4.0
TOTAL KNOWN FIRED HEATER ENERGY REQUIREMENT 652.4 100

.3 As discussed earlier, the estimated energy requirement for
1985 was 6.8 x 1014 Btu/yr.21 Thirty organic and seven inorganic
operations require process heaters in the chemical manufacturing
industry.3 Table 3-4
3-28
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
3-29
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-firebox-
temperature 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.3 High-firebox-temperature heaters represent
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.
3-30
3-31
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.
4. Reference 1, pp. 10-12.
5. 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. 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.
9. Reference 5, pp. 5-35 through 5-36.
17. Thrash, L.A. Annual Refining Survey. Oil and Gas Journal.
March 18, 1991. pp. 86-105.
3-32
20. Cherry, S.S., and S.C. Hunter (KVB-A Research-Cottrell
Company). Cost and Cost-Effectiveness of NOx Control in
Petroleum Industry Operations. Prepared for the American
Petroleum Institute. Washington, D.C. API Publication
No. 4331. October 1980. pp. 2-68 through 2-73.
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.
3-33
3-34
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.1 Formation of thermal NOx is
greatest in regions where the highest local flame temperatures
occur.2 The thermal NOx formation mechanism is commonly
described using the Zeldovich mechanism, which is described by
the following simplified reactions:3
4-1
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.4 At high combustion
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]1/2 t
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.1 Variables that affect
these three parameters are discussed in Section 4.2. Figure 4-1
4-2
Figure 4-1. Impact of temperature on NOx formation.4
4-3
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
4-4
4-5
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.6 Several studies, however, indicate that two
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-nitrogen-
content 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
4-6
Figure 4-2. Effect of fuel-bound nitrogen on NOx emissions.1
4-7
shows the increase in NOx emissions due to the increase in
nitrogen content of the fuel.1
4-8
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
4-9
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 107 to 8.2 x 107 Joules per cubic meter (J/m3)
(700 to 2,200 British thermal units per standard cubic feet
[Btu/scf]). High hydrogen fuel gas, which contains up to
4-10
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 107 to 2.22 x 107 J/m3 (400 to 600 Btu/scf).
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.15 Because NOx formation is affected by the flame
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.11 Most fired heaters, until recently, have used burners
capable of firing oil or gas.11 However, the current trend is to
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
4-11
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. High-
intensity 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
4-12
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.9 The staged-air,
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).9 Tests show that the higher the
temperature of air preheat, the greater the formation of NOx.
Figure 4-3
4-13
Figure 4-3. Effect of combustion air preheat temperature on NOx
emissions.15
4-14
shows the effect of combustion air preheat on NOx emissions from
a test-scale, mechanical draft (MD) heater.15 Preheating the
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
4-15
is determined by the process requirements.9 Therefore,
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.9 In general, heaters with high volumetric
heat release rates have high flame and firebox temperatures.
Figure 4-4
4-16
Figure 4-4. Effect of firebox temperature on thermal NOx
formation for gas-fired heaters with constant excess air.11
4-17
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).15 One source reports that below 1100EC (2100EF) thermal
NOx increases a nominal 10 percent for every 40EC (100EF)
increase in firebox temperature, which is consistent with the
above data.16 The same source reports that increasing the
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.20 The effect of increased firebox temperature on fuel NOx
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
4-18
below ambient pressure. Process heater construction does not
tolerate large variations in firebox pressures like those in
boilers.16 In ND heaters, the pressure difference between the
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.16 The term "excess oxygen" is sometimes
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.14 The effect of excess air
on NOx formation in gas-fired heaters using these data is shown
4-19
in Figure 4-5. Another source reports a NOx emissions increase
4-20
Figure 4-5. Effect of excess air on NOx formation in gas-fired
process heaters at various combustion air preheat temperatures.22
4-21
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.2 One
source indicates that increased fuel firing is generally required
when excess oxygen levels are above 6 percent as a result of
decreased fuel efficiency.16 However, radiant burners are
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 well-
defined, 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.13 However, burner
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
4-22
4-23
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.23 These
emission factors, shown in Table 4-1,
4-24
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
a
ng/J = nanogram per Joule
b
Distillate oils include Nos. 1 and 2 fuel oils.
c
Residual oils include Nos. 4, 5, and 6 fuel oils.
4-25
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.24 Figure 4-6
4-26
Figure 4-6. Uncontrolled NOx emission data versus heat input for
gas-fired refinery process heaters of various design types.24
4-27
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
4-28
Figure 4-7. Uncontrolled NOx emission factors for gas-fired
refinery process heaters with known burner configuration, draft
type, and air preheat conditions.
4-29
shows the NOx emission factors versus heat input for the gas-
fired 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
4-30
4-31
4-32
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.
4-33
TABLE 4-2. AVERAGE UNCONTROLLED NOx EMISSIONS FROM REFINERY
PROCESS HEATERS BASED ON EMISSION DATA FROM API24 (lb/MMBtu)
Fuel Natural drafta Mechanical draftb

Gaseous 0.14 0.26
Distillate oilc 0.20 0.32
Residual oild 0.42 0.54
a
Using ambient combustion air.
b
Using air preheated to 200EC (390EF), on average.
c
Fuel nitrogen content of 0.04 percent. Fuel NOx contributes
0.06 lb/MMBtu to total uncontrolled emissions.
d
Fuel nitrogen content of 0.29 percent. Fuel NOx contributes
0.28 lb/MMBtu to total uncontrolled emissions.
4-34
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.24 The emission factors increase
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
4-35
Figure 4-8. Uncontrolled NOx emission rates for gas-fired
process heaters at one refinery installation.25
4-36
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.
4-37
TABLE 4-3. AVERAGE UNCONTROLLED NOx EMISSIONS FROM PROCESS
HEATERS AT ONE REFINERY INSTALLATION25
NOx emissions, lb/MMBtu
Natural drafta Mechanical draftb
No. of No. of
Fuel heaters Range Average heaters Range Average
Gaseous 32 .064 - .011 .098 26 .062 - .323 .197
a
Using ambient combustion air.
b
Using air preheated to 310EC (595EF), on average.
4-38
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.
4-39
4-40
4-41
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.26 Limited data for natural gas-fired pyrolysis
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.27 A second source indicated that
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.28 These
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, low-
and medium-temperature ND without preheat; (4) oil-fired, low-
and 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.
4-42
TABLE 4-4. MODEL HEATERS AND UNCONTROLLED NOx EMISSION FACTORS:
NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE ND
WITHOUT PREHEAT25
Uncontrolled
Model heater NOx emission
capacity, Size range, No. of factors,
MMBtu/hr MMBtu/hr burners 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
Uncontrolled
Model heater NOx emission
capacity, Size range, factors,
MMBtu/hr MMBtu/hr No. of burners 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
4-43
Figure 4-9 presents a graphical representation of the heat rates
Figure 4-9. Natural draft process heater refinery inventory.25
4-44
of the ND heaters in Figure 4-8. Several natural
4-45
4-46
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 medium-
temperature model heaters are presented in Table 4-5.
Figure 4-10
4-47
Figure 4-10. Mechanical draft process heater refinery
inventory.25
4-48
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
4-49
the average size of ND process heaters reported in an API
study.24 Two MD with preheat model heaters, one distillate and
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
4-50
FACTORS: DISTILLATE AND RESIDUAL OIL-FIRED, LOW-
AND MEDIUM-TEMPERATURE ND WITHOUT PREHEAT24
Uncontrolled NOx
emission factor,
lb/MMBtu
Model heater No. of Thermal Fuel NOx
capacity, MMBtu/hr Fuel burners NOx
69 Distillate oila 24 0.140 0.060
69 Residual oilb 24 0.140 0.280
a
0.04 percent N
b
0.29 percent N
TABLE 4-7. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS:

DISTILLATE AND RESIDUAL OIL-FIRED, LOW- AND MEDIUM-
TEMPERATURE MD WITH PREHEAT24
Uncontrolled NOx
emission factor,
lb/MMBtu
Model heater No. of Thermal Fuel NOx
capacity, MMBtu/hr Fuel burners NOx
135 Distillate oila 14 0.26 0.060
135 Residual oilb 14 0.26 0.280
a
0.04 percent N
b
0.29 percent N
4-51
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.
4-52
Table 4-8
4-53
TABLE 4-8. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS:
NATURAL GAS-FIRED AND HIGH-HYDROGEN FUEL GAS-FIRED
OLEFINS PYROLYSIS FURNACES28
Uncontrolled NOx
Model heater capacity, No. of emission factor,
MMBtu/hr Fuel burners lb/MMBtu
84 Natural gas 24 0.135
84 High-hydrogen 24 0.162
fuel gas
4-54
presents two model heaters representing olefins pyrolysis
furnaces. The model pyrolysis heaters are an ND natural gas-
fired 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 gas-
fired 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.
4-55
4-56
4-57
4.4 REFERENCES FOR CHAPTER 4
1. Shareef, S. A., C. L. Anderson, and L. E. Keller (Radian
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.
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.
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.
12. Martin, R. R. Burner Design Parameters for Flue Gas NOx
Control. John Zink Company. Tulsa, Oklahoma. Undated.
39 pp.
4-58
16. Letter and attachments from Eichamer, P., Exxon Chemical
Comments on Draft Alternative Control Techniques Document--
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.
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.
4-59
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.
4-60
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
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.1 The lowest excess air level that can be maintained in a
fired heater depends on draft type, fuel type, degree of air
5-62
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.1 Current experience for
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
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optimal excess air operation.5 Excess O2 levels of approximately
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.1 As discussed in Chapter 4, this
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.
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Figure 5-1 illustrates the typical relationship between
5-65
Figure 5-1. Effect of combustion air preheat temperature on NOx
emissions.1
5-66
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
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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
5-68
Figure 5-2. Staged combustion air lances installed on a
conventional gas burner.1
5-69
emissions reported in References 2 and 3 is presented in
Table 5-1
5-70
TABLE 5-1. CONTROLLED EMISSIONS FOR STAGED COMBUSTION
USING AIR LANCES2,3
Uncontrolled NOx emissions NOx Controlled NOx emissions

reduction,
Fuel ppmv a lb/MMBtu percent ppmv a lb/MMBtu
Refinery gas 138 0.165 12 121 0.144
Refinery gas 125 0.243 71 36.3 0.043
Residual oil and 265 0.334 25 199 0.251

refinery gas
Residual oil and 214 0.270 53 101 0.127

refinery gas
a
At 3 percent O2.
5-71
.2,3 Nitrogen oxide reductions from uncontrolled levels using air
lances for heaters firing refinery gas range from 12 to
71 percent.2,3 Reductions for heaters that combine firing of
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.1 As the degree of staging is increased, the
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.6 For this reason, air staging
using air lances should not be considered a current NOx control
approach.
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5-73
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.1,7,8,9 Using the uncontrolled emission factors from
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.
5-74
TABLE 5-2. CONTROLLED EMISSION LEVELS FOR STAGED-AIR LNB'S
Uncontrolled NOx emission Controlled NOx emission levelsb

factors
Fuel Draft type
ppma lb/MMBtu ppma lb/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
a
@3 percent O2
b
Controlled emissions based on a 40 percent reduction.
5-75
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.
5-76
Table 5-3
5-77
TABLE 5-3. STAGED-AIR BURNER NO x CONTROL PERFORMANCE AND EMISSION LEVELS
NO x control performance and emission levels
Burner name Heater draft Fuel ppmv lb/MMBtu

b
John Zink MD NG 40 to 105 0.048 to 0.125
Low-NO x HIV a
HFO c 250 to 270 0.315 to 0.340
John Zink ND NG 85 0.101

LNC a
(60EF) HFO
MD NG 105 0.125
(500EF preheat)
HFO 270 0.340
McGill ND NG 40% reduction 40% reduction

NRGR a,b
MD NG 40% reduction 40% reduction
McGill ND Combination 40% reduction 40% reduction
5-78
NCR a,b
MD Combination 40% reduction 40% reduction
Hamworthy MD Oil/gas 40% reduction 0.039 to 0.053

LV a
AUSCS MD NG 33 to 44 (no preheat) 0.064 to 0.068

DFR 54 to 57 (600 EF preheat, lean gas)
Low NO x a
AUSCS ND/MD NG 37 ppmv (without preheat using ND) 0.044

200 a
c
Callidus Staged-Air LNB ND NG 30% reduction 30% reduction
MD (preheat) d NG 30% reduction 30% reduction
a
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.
b
McGill has been purchased by John Zink Company. McGill burners are no longer available, but replacements can be obtained from the John Zink Company.
c
Reference 9. Vendor names are included only to identify the burner type. Other vendors may offer similar burner types.
d
Preheat temperature is not known.
presents several staged-air burners and estimated performance.
For heavy fuel oil (HFO) firing (0.3 percent N content), staged-
air 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,
5-79
Figure 5-3. Schematic of a staged-air low-NOx burner.8
5-80
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.
5-81
5-82
5-83
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.10 The reducing
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.5 Other
typical retrofit operations include multiple fuel header
connections, steam header connections, and flue gas ducting
alterations.5
5-84
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.
5-85
v. Staged-Fuel Low-NOx Burners
Staged-fuel LNBs were more recently developed than staged-
air 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.
5-86
Figure 5-4. Schematic of a staged-fuel low-NOx burner.1
5-87
In a typical staged-fuel LNB, 40 to 70 percent of the fuel is
bypassed around the primary combustion region.7,11 Combustion in
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, staged-
fuel 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.
5-88
Reductions in NOx emissions of up to 72 percent have been
reported over conventional burners based on vendor test data for
staged-fuel LNBs.1 The average reduction is approximately
60 percent.1,7,9,12 Table 5-4 presents controlled NOx emission
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.7 Table 5-5
5-89
TABLE 5-4. STAGED-FUEL LOW-NOx BURNER CONTROLLED
NOx EMISSION LEVELS7
Controlled NOx emissions
Burner name Heater draft Fuel ppmv g,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 Combination f 40 NA
MD (500EF preheat) Combination f 50 NA
McGill SRGRa,b NDd Refinery gas 45 0.054

50 percent H2
MDd Refinery gas 45 0.054

50 percent H2
Callidus CSGc NDd NG 60% reduction 60% reduction
MD (preheat)e NG 60% reduction 60% reduction
a
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.
b
McGill has been purchased by John Zink Company. McGill burners are no longer available, but replacements can
be obtained from the John Zink Company.
c
Reference 9 Vendor names are included only to identify the burner type. Other vendors may offer similar burner
types.
d
Combustion air at ambient conditions.
e
Preheat temperature is not known.
f
Combination of oil and gas fuels.
g
At 3 percent O2.
h
Percent reductions were not available for all burners.
NA = Not available.
5-90
TABLE 5-5. CONTROLLED NOx EMISSION LEVELS FOR STAGED-FUEL
LOW-NOx BURNERSa
Uncontrolled NOx Controlled NOx emissionsc

emissions
Draft type ppmvb lb/MMBtu ppmvb lb/MMBtu
ND 117 0.14 47 0.056
MD 218 0.26 87 0.104
a
Gas firing.
b
At 3 percent O2.
c
Controlled emissions based on a 60 percent reduction.
5-91
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.5 The recirculation of flue gas dilutes the combustion
reactants, reduces the peak flame temperature, and reduces the
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5-93
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.7 Also, based on
boiler data, FGR used with standard burners on process heaters is
expected to reduce NOx emission levels 30 percent.7
5-94
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.7 All designs, as
depicted in Figure 5-5, use a venturi effect to
5-95
Figure 5-5. Cross-section of an internal flue gas recirculation
burner.1
5-96
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.14 Controlled NOx
emissions of 0.025 lb/MMBtu have been reported for the Selas
ULNx® burner.15 This emission level is reported for natural gas
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.16 Operating under different firebox conditions than
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).17 Additional
5-97
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.9 The manufacturer states that this IFGR ULNB
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.7 Therefore, the reduction
efficiencies used in this study for ULNBs for low- and medium-
temperature 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).7 Thermal NOx formation is
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.18 This
5-98
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.18,19 Table 5-6
5-99
Table 5-6. RADIANT BURNER APPLICATIONS 20,21
Capacity, Energy input, MMBtu/hr Conventional Conventional

heat MD burner NOx MD burner NOx Radiant burner Radiant burner NOx
absorbed, MD heater w/ Heater w/ radiant Capacity emissions, ppmv emissions, NOx emissions, emissions,
ID No. MMBtu/hr conventional burners burners factor @ 3% O2 lb/MMBtu input ppmv @ 3% O2 lb/MMBtu input
a
1 6.0 7.50 7.50 0.90 80.0 0.097 20.0 0.024
2 6.0 8.28 7.50 0.50 80.0 0.097 20.0 0.024
3 6.0 8.28 7.50 0.30 80.0 0.097 20.0 0.024

b
4 8.0 N/A 3.80 0.48 N/A N/A 12.1 0.014
5 8.0 N/A 7.80 0.98 N/A N/A 15.7 0.019
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c
6 8.0 N/A 3.90 0.49 N/A N/A 0.0 0.0
7 8.0 N/A 8.20 1.02 N/A N/A 10.7 0.013
a
Heaters numbers 1 through 3 are the same heater operated at different capacity factors. These heaters were modeled heater applications provided by
Alzeta.
b
Heaters numbers 4 and 5 are the same heater operated at different capacity factors.
c
Heaters numbers 6 and 7 are the same heater operated at different capacity factors.
N/A = Data not available.
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.20,21 The second and third applications are retrofits of
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.7 The heater
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.7 Currently there are three
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
5-101
threshold temperature.22 The SNCR reduces both thermal and fuel-
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
5-102
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
5-103
Figure 5-6. Exxon Thermal DeNOx system.7
5-104
a TDN system applied to a process heater.22 The TDN process
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)
5-105
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.7 Table 5-7 presents a partial list of Exxon's
Thermal DeNOx® process heater installations and NOx control
performance.7,24 The reactant is mixed with low-pressure air
5-106
TABLE 5-7. PARTIAL LIST OF EXXON'S THERMAL
DeNOx INSTALLATIONS7,24
Uncontrolled Controlled
Installation Size, MW NOx, ppmv at NOx, ppmv at Percent
date Fuel (MMBtu/hr) 3 percent O2a 3 percent O2a 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
a
NOx (lb/MMBtu) = NOx (ppmv @ 3% O2) * 0.001194 for gas.
5-107
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).5 This H2 can be supplied from H2-rich refinery streams
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
5-108
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.8 The temperature range can be lowered to
760E (1400EF) by adding H2, a readily oxidizable gas, to the
reactant.5 Below 760EC (1400EF), neither reaction is of
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.1 The
5-109
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 cost-
effectiveness 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.7 While Nalco Fuel Tech is EPRI's exclusive licensing
agent in the United States, Noell KRC and affiliated companies
are using the process in Europe.23 Nalco Fuel Tech promotes the
use of other chemicals to extend the temperature range and
control NH3 slippage to very low levels. Currently, the urea
5-110
injection process has been installed on four process heaters.
Most of the current applications are on coal-, oil-, and gas-
fired boiler applications. A summary of current and pending
urea-based injection applications is provided in Appendix B.
5-111
(1) Process Description (NOxOUT®). Figure 5-7 shows a
5-112
Figure 5-7. Nalco Fuel Tech NOxOUT®-type reduction system.7
5-113
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
5-114
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 NH3.7 However, Nalco Fuel Tech indicates that the number of
injection nozzles will be less than for NH3 injection.23 For
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
5-115
temperature window may not be reached, resulting in a reduction
in NOx efficiency and an increase in NH3 slip.1 A solution to
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
5-116
TABLE 5-8. NALCO FUEL TECH NOxOUT® PROCESS
HEATER APPLICATIONS23
Baseline emissions Reduction Controlled emissions

Capacity, guaranteed by
MMBtu/hr ppm a lb/MMBtu vendor, percent ppm a (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
a
At 3 percent excess 02.
NA = Not available.
5-117
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.27 This is not only because permit limits have
5-118
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.7,8 The major reactions that occur in the
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.
5-119
Figure 5-8. Schematic of a selective catalytic reduction
system.7
5-120
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
5-121
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.8 Optimum NOx reduction
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
5-122
Figure 5-9. Effect of temperature and oxygen on NOx conversion.6
5-123
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
5-124
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.7 Zeolites are reported to be effective over the range
of 320E to 600EC (600E to 1130EF), with the optimum temperature
range stated as 360E to 580EC (675E to 1080EF).7 In some zeolite
catalyst formulations, NH3 oxidation to NOx begins at around 450EC
(850EF) and is predominant at temperatures in excess of 520EC
(960EF).7 A gas turbine zeolite catalyst installation is
reported to be operating in the temperature range of 500E to
520EC (930E to 960EF).11 The performance is reported to be
80 percent NOx reduction with NH3 slip limit of 20 ppmv at
15 percent O2 (61 ppmv at 3 percent O2).11 No process heater data
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
5-125
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
SO3.7 Conversion of SO2 to SO3, in turn, results in the formation
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-SO3.28 Catalyst
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
5-126
TABLE 5-9. CONTROLLED EMISSION FACTORS FOR SCR
ADDED TO HEATERS WITH LNB'S14
Baseline emission factor Controlled emission level
Heater
capacity, Reduction,
MMBtu/hr ppmv a lb/MMBtu percent ppmv a lb/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
a
ppmv at 3 percent O2.
5-127
presents a summary of data from the Mobile Oil refinery in
Torrance, California (Appendix C).14 These data
5-128
5-129
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.29 One installation was reported using
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.29 One source reports that current SCR technology, as
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
5-130
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
5-131
TABLE 5-10. ENERGY REQUIREMENTS OF MAJOR FIRED HEATER APPLICATIONS IN THE
CHEMICAL INDUSTRY 1
Percent of known
1985 fired heater chemical industry
energy requirement heater
Chemical Process Heater type Firebox temp., EF *10 12 Btu/yr requirements
Low- and medium-temperature applications
Benzene Reformate extraction Reboiler 700 64.8 9.9
Styrene Ethylbenzene dehydrogenation Steam superheater 1500-1600 32.1 4.9
Vinyl chloride monomer Ethylene dichloride cracking Cracking furnace NA 12.6 1.9
P-xylene Xylene isomerization Reactor fired preheater NA 13.0 2.0
a
Dimethyl terephthalate Reaction of p-xylene and Preheater, hot oil furnace 480-540 11.1 1.7
methanol
Butadiene Butylene dehydrogenation Preheater, reboiler 1100 2.6 0.4
Ethanol(synthetic) Ethylene hydration Preheater 750 1.3 0.2
5-132
Acetone Various Hot oil furnace NA 0.8 0.1
High-temperature applications
Ethylene/propylene Thermal cracking Pyrolysis furnace 1900-2300 337.9 51.8
Ammonia Natural gas reforming Steam hydrocarbon reformer 1500-1600 150.5 23.1
Methanol Hydrocarbon reforming Steam hydration 1800-2000 25.7 4.0
Total known fired heater energy requirement 652.4 100
a
Feedstock outlet temperature.
NA = Data not available.
, 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
5-133
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
5-134
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 medium-
temperature 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.31 Both pyrolysis
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.31 To achieve a uniform heat
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.32 For
retrofit applications, one source reported that the lowest
achievable controlled NOx emission rate is approximately
0.100 lb/MMBtu for natural gas-fired operation.33 The available
5-135
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 gas-
and 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.34 Permits for five major ethylene plants in Texas
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.32 A second
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.
5-136
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
5-137
TABLE 5-11. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND, NATURAL
GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS
Uncon- ControlledN
Model heater trolled NOx Controlled Ox
capacity, emission Total effective NOx emissions, NOx
MMBtu/yr factor, NOx control technique reduction, emissions, ppm @ 3% reduction,
lb/MMBtua percent lb/MMBtu O2 ton/yre
17 0.098 (ND) LNB 50 b 0.049 41 3.65
c
(ND) ULNB 75 0.025 21 5.47
d
(ND) SNCR 60 0.039 33 4.38
b,d
(ND) LNB + (ND) SNCR 80 0.020 16 5.84
b
36 0.098 (ND) LNB 50 0.049 41 7.73
c
(ND) ULNB 75 0.025 21 11.6
d
(ND) SNCR 60 0.039 33 9.27
b,d
(ND) LNB + (ND) SNCR 80 0.020 16 12.36
b
77 0.098 (ND) LNB 50 0.049 41 16.5
c
(ND) ULNB 75 0.025 21 24.8
d
(ND) SNCR 60 0.039 33 19.8
b,d
(ND) LNB + (ND) SCNR 80 0.020 16 26.44
b
121 0.098 (ND) LNB 50 0.049 41 26.0
(ND) ULNB 75 c 0.025 21 39.0
(ND) SNCR 60 d 0.039 33 31.2
b,d
(ND) LNB + (ND) SNCR 80 0.020 16 41.55
b
186 0.098 (ND) LNB 50 0.049 41 39.9
c
(ND) ULNB 75 0.025 21 60.0
d
(ND) SNCR 60 0.039 33 47.9
b,d
(ND) LNB + (ND) SNCR 80 0.020 16 63.87
a
Uncontrolled emissions for natural gas-fired heaters are from thermal NOx formation.
b
Reductions from LNB's represent a 50 percent reduction of thermal NOx. This reduction was adopted from
Reference 5.
c
Reductions from ULNB's represent a 75 percent reduction of thermal NOx. This reduction was adapted from
Reference 14.
d
Postcombustion NOx reduction by SNCR is 60 percent. This reduction was adopted from Reference 7.
e
Reduction (tons/yr) equals the Capacity (MMBtu/hr) x NOx reduced (lb NOx/MMBtu) x 1 ton per 2,000 lb x
8,760 hr/yr; where NOx reduced is equal to uncontrolled emission factor minus the controlled emission factor.
5-138
TABLE 5-12. MODEL HEATERS: CONTROLLED EMISSIONS FOR MD,
NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS
Uncon-
Model heater trolled NOx Controlled Controlled NOx
capacity, emission factor, Total effective NOx emissions,
MMBtu/hr lb/MMBtua reduction, emissions, ppmv NOx reduction,
NOx control technique percent lb/MMBtu @ 3% O2 tons/yrg
40 0.197 (MD) LNB 50b 0.099 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
f
(MD) LNB + FGR 55 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
b
114 0.197 (MD) LNB 50 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
b
174 0.197 (MD) LNB 50 0.099 82 75.1
(MD) ULNB 75c 0.049 41 113
(MD) SNCR 60d 0.079 66 90.1
e
(MD) SCR 75 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
d
(MD) SNCR 60 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
b,e
(MD) LNB + SCR 88 0.025 21 199
a
Uncontrolled emissions for natural gas-fired heaters are from thermal NOx formation.
b
Reductions from LNB's represent a 50 percent reduction of thermal NOx. This reduction was adopted from
Reference 5.
c
Reductions from ULNB's represent a 75 percent reduction of thermal NOx. This reduction was adapted from
Reference 14.
5-139
TABLE 5-13. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND OIL-FIRED HEATERS
Uncontrolled
emission factor,
lb/MMBtu NOx emission reduction, percent
Model technique Controlled Controlled
Thermal Fuel Post- Total
through 5-15
heater NOx control NOx NOx NOx

capacity, Fuel NOxa NOxb Thermal Fuel combus- effective emission, emissions, reduction,
MMBtu/hr NOx NOx tion reduction lb/MMBtu ppmv tons/yrc
d
69 Distillate oil 0.14 0.06 (ND) LNB 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

d
69 Residual oil 0.14 0.28 (ND) LNB 50 15 N/A 27 0.308 258 33.8
(ND) ULNBe 75 78 N/A 77 0.097 80.9 97.7
5-140
(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
a
Uncontrolled emission factor for thermal NOx represents the NOx from thermal NOx formation.
b
Uncontrolled emission factor for fuel NOx represents the NOx from fuel NOx formation.
c
Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NOx reduced (lb NOx/MMBtu) * 1 ton per 2000 lb * 8,760 hr/yr,
where NOx reduced is equal to the uncontrolled emission factor minus the controlled emission factor.
d
These reductions were adopted from References 5 and 7.
e
These reductions were adapted from References 7 and 14.
f
These reductions were adopted from Reference 7.
TABLE 5-14. MODEL HEATERS: CONTROLLED EMISSIONS FOR MD
OIL-FIRED HEATERS
Uncontrolled
emission factor, NO x emission reduction, percent
Model heater lb/MMBtu Controlled
capacity, NO x
MMBtu/hr Thermal Fuel NO x control Total emissions, Controlled NO x NO x reduction,
Fuel NO x a NO x b technique effective lb/MMBtu emissions, ppmv tons/yrc
Thermal NO x Fuel NO x Postcombustion reduction
d
135 Distillate oil 0.26 0.06 LNB 50 25 N/A 45 0.175 139 85.7
e
ULNB 75 72 N/A 74 0.082 64.9 141
f
SNCR N/A N/A 60 60 0.128 102 114
g
SCR N/A N/A 75 75 0.080 63.5 142
h
LNB + FGR 55 15 N/A 48 0.168 133 89.9
d,f
LNB + SNCR 50 25 60 78 0.070 55.6 148
d,g
LNB + SCR 50 25 75 92 0.026 20.8 174
d
135 Residual 0.26 0.28 LNB 50 25 N/A 37 0.340 270 118
e
ULNB 75 72 N/A 73 0.143 114 235
5-141
f
SNCR N/A N/A 60 60 0.216 171 192
g
SCR N/A N/A 75 75 0.135 107 240
h
LNB + FGR 55 15 N/A 34 0.355 282 109
d,f
LNB + SNCR 50 25 60 75 0.136 108 239
LNB + SCR d,g 50 25 75 91 0.051 40.5 289
a
Uncontrolled emission factor for thermal NOx represents the NOx from thermal NOx formation.
b
Uncontrolled emission factor for fuel NOx represents the NOx from fuel NOx formation.
c
Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NO xreduced (lb NO /MMBtu)
x * 1 ton per 2000 lb * 8,760 hr/yr; where NO xreduced is equal to the
uncontrolled emission factor minus the controlled emission factor.
d
These reductions were adopted from References 5 and 7.
e
These reductions were adapted from References 7 and 14.
f
These reductions were adopted from Reference 7.
g
These reductions were adapted from Reference 14.
TABLE 5-15. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND OLEFINS PYROLYSIS HEATERS
Uncontrolled NO x Controlled NO x
h
Model heater emission factor, Total effective emissions, lb/MMBtu Controlled NO NO x reduction, ton/yr
x
capacity, MMBtu/hr Fuel lb/MMBtu a NO x control technique reduction, percent emissions, ppmv
84 Natural gas 0.135 (ND) LNB 25 0.101 85 12.4
(MD) LNB b 25c 0.101 85 12.4
d
(ND) ULNB 50 0.068 57 24.8
(MD) ULNB b 50d 0.068 57 24.8
e
(ND) SNCR 60 0.054 45 29.8
b e
(MD) SNCR 60 0.054 45 29.8
SCR b 75f 0.034 28 37.3
b g
LNB + FGR 55 0.061 51 27.3
(ND) LNB + SNCR b 70c,e 0.041 34 34.8
b c,e
(MD) LNB + SNCR 70 0.041 34 34.8
LNB + SCR b 81c,f 0.026 21 40.4
c
84 High-hydrogen 0.162 (ND) LNB 25 0.123 343 14.9
fuel gas (MD) LNB b 25c 0.123 343 14.9
d
5-142
(ND) ULNB 50 0.081 229 29.8
(MD) ULNB b 50d 0.081 229 29.8
e
(ND) SNCR 60 0.065 183 35.8
(MD) SNCR b 60e 0.065 183 35.8
b f
(SCR) 75 0.041 114 44.7
LNB + FGR b 55g 0.073 206 32.8
b c,e
(ND) LNB + SNCR 70 0.049 137 41.7
(MD) LNB + SNCR b 70c,e 0.049 137 41.7
b c,f
LNB + SCR 81 0.031 86 48.4
a
Uncontrolled emissions for natural gas-fired heaters are from thermal NO x formation.
b
Emission reductions are based on ND emission factors using a 100 percent capacity utilization.
c
Reductions from LNB's represent a 25 percent reduction of thermal NO x .
d
Reductions from ULNB's represent a 50 percent reduction of thermal NO x .
present achievable NOx reductions, controlled emissions, and
e
Postcombustion NO x reduction by SNCR is 60 percent. This reduction was adapted from Reference 7.
f
Postcombustion NO x reduction by SCR is 75 percent. This reduction was adapted from Reference 14.
g
Reductions from LNB + FGR represent a 55 percent reduction of thermal NO x . This reduction was adapted from Reference 7.
h
Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NO xreduced (lb NO /MMBtu)
x * 1 ton per 2000 lb * 8,760 hr/yr, where NO reduced is equal to the uncontrolled emission factor minus the
x
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
5-143
5-144
5-145
5-146
5-147
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.
techniques applied to the MD, natural gas-fired, low- and medium-
temperature 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.
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 fuel-
fired 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
5-148
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
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
6 Letter and attachments from Laffly, G., American Petroleum
Institute, to Neuffer, W., EPA/ISB. August 10, 1992.
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.
5-149
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
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 Ultra-
Low 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.
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.
5-150
23 Letter and attachments from Pickens, R., Nalco Fuel Tech, to
Neuffer, W., EPA/ISB. August 7, 1992. Comments on Draft
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.
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.
5-151
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.
5-152
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.1,2 It is expected that the cost of incorporating a
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
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.3 Capital costs for combinations of controls are the sum
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
6-2
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
a
Reference 4, Table 5-10.
b
Reference 5.
c
Reference 6.
d
Reference 2.
e
Reference 1.
6-3
. 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 BQ2)]
6-4
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 BQ2)]}.
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.1,2 Installation of LNBs can improve heater efficiency,
although this effect (if any) will be strongly heater-dependent.
6-5
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.1,8 These
operational impacts will tend to offset one another in the cost
analysis associated with LNB installation and minimize the effect
of the current analysis.1 These costs are site-specific and are
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 BQ2)]}.
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 BQ2)]}.
The cost methodologies give costs in Canadian average
1990 dollars. For this analysis, the capital costs have been
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
6-6
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.1 The loss in efficiency is estimated to require a
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
6-7
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.2,11 Selective catalytic reductions systems require
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)0.6 + 49,000 x (Q/485),
where:
Q = heater capacity, MMBtu/hr.2
The cost methodology gives costs in U.S. average 1986
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,
6-8
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
6-9
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
6-10
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
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
6-11
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.1 This
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)n]/[(1+i)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
6-12
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 Medium-
for the MD gas-fired, low- and medium-temperature model heaters.
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-
for the ND oil-fired, low- and medium-temperature model heaters.
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
NATURAL GAS-FIRED MODEL HEATERS (1991 $)
Annual costs, $/yr
Operating and maintenance costs @ Total annual costs, $/yr @ capacity

Model heater capacity factors:b factors:c
capacity, Capital
MMBtu/hr NO x control technique Capital costs, $ recoverya 0.1 0.5 0.9 0.1 0.5 0.9
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
6-13
Annual costs, $/yr
Operating and maintenance costs @ Total annual costs, $/yr @ capacity

Model heater capacity factors:b factors:c
capacity, Capital
MMBtu/hr NO x control technique Capital costs, $ recoverya 0.1 0.5 0.9 0.1 0.5 0.9
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
a
Capital recovery = Capital cost x capital recovery factor.
b
Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent.
c
Total annual cost = Capital recovery + operating and maintenance cost.
iv. Control Costs for MD Oil-Fired, Low- and Medium-
6-14
TABLE 6-3. COSTS OF CONTROL TECHNIQUES FOR MD NATURAL
GAS-FIRED MODEL HEATERS (1991 $)
Annual costs, $/yr

Total annual costs, $/yr @ capacity factors:c
Operating and maintenance costs @ capacity
Model heater
Capital factors:b
capacity, NO x control technique Capital costs,
recoverya
MMBtu/hr $ 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
6-15
Annual costs, $/yr
Total annual costs, $/yr @ capacity factors:c
Model heater
Capital factors:b
capacity, NO x control technique Capital costs,
recoverya
MMBtu/hr $ 0.1 0.5 0.9 0.1 0.5 0.9
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
a
Capital recovery = Capital cost x capital recovery factor.
b
c
6-16
TABLE 6-4. COSTS OF CONTROL TECHNIQUES FOR ND OIL-FIRED MODEL HEATERS (1991 $)
Annual co sts, $/yr b
Operating and maintenance costs @ capacity factors: c

Total annual costs, $/yr @ capacity factors:
Model heater capacity and NO x control technique Capital costs,
Capital recovery a 0.1 0.5 0.9 0.1 0.5 0.9
fuel type, MMBtu/hr $
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
a
Capital recovery = Capital cost * capital recovery factor.
b
c
6-18
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
6-19
TABLE 6-5. COSTS OF CONTROL TECHNIQUES FOR MD OIL-FIRED HEATERS (1991 $)
Annual costs, $/yr

Model heater Total annual costs, $/yr @ capacity factors: c
factors:b
capacity and NO x control Capital costs,
Capital recoverya
fuel type, technique $ 0.1 0.5 0.9 0.1 0.5 0.9
MMBtu/hr
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 89,900 105,000 121,000 501,000 516,000 532,000
LNB + FGR 535,000 70,300 15,800 20,000 24,300 86,100 90,300 94,600
LNB + SNCR 855,000 112,000 29,200 52,100 74,900 142,000 165,000 187,000
LNB + SCR 3,340,000 440,000 95,800 111,000 127,000 536,000 551,000 566,000
TABLE 6-3.
135 (MD) LNB 319,000 42,000 8,780 8,780 8,780 50,700 50,700 50,700
6-20
Residual (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 22,100 51,700 81,200 92,600 122,000 152,000
SCR 3,130,000 411,000 90,200 107,000 124,000 501,000 518,000 535,000
LNB + FGR 535,000 70,300 15,800 20,000 24,300 86,100 90,300 94,600
(continued)
LNB + SNCR 855,000 112,000 30,900 60,500 90,000 143,000 173,000 202,000
LNB + SCR 3,340,000 440,000 96,200 113,000 130,000 536,000 553,000 570,000
a
b
c
TABLE 6-6. COSTS OF CONTROL TECHNIQUES FOR ND OLEFINS PYROLYSIS MODEL HEATERS (1991
$)
Annual costs, $/yr

Model heater
b
capacity and Operating and maintenance costs @ capacity factors: Total annual costs, $/yr @ capacity factors:
fuel type, Capital costs, Capital
recoverya 0.1 0.5 0.9 0.1 0.5 0.9
MMBtu/hr NO control technique
x $
84 (ND) LNB 248,000 32,600 6,810 6,810 6,810 39,400 39,400 39,400
Natural (MD) LNB 642,000 84,400 17,700 17,700 17,700 102,000 102,000 102,000
gas-fired
(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 29,300 108,000 113,000 118,000
SCR 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
TABLE 6-3.
(ND) LNB + SNCR 651,000 85,600 19,100 23,900 28,700 105,000 109,000 114,000
6-21
(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 (MD) LNB 642,000 84,400 17,700 17,700 17,700 102,000 102,000 102,000
fuel gas-fired
(ND) ULNB 252,000 33,100 6,930 6,930 6,930 40,100 40,100 40,100
(continued)
(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 31,700 109,000 114,000 120,000
SCR 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
a
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 gas-
fired heater.
vi. Costs for ND-to-MD Conversion
6-22
Table 6-7
6-23
TABLE 6-7. ND-TO-MD CONVERSION COSTS FOR THE ND MODEL

HEATERS (1991 $)
Model heater Total annual

capacity, Capital cost, 1991 Capital recovery, Annual operating costs, 1991
MMBtu/hr US $ 1991 US $/yr costs, 1991 US $/yr 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
6-24
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
6-25
6-26
6-27
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 oil-
fired 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.
6-28
Table 6-13 is a summary of the cost effectiveness of

selected NOx emission control techniques as presented by the
6-29
TABLE 6-8. COST EFFECTIVENESS OF CONTROL TECHNIQUES FOR

ND NATURAL GAS-FIRED MODEL HEATERS (1991 $)
Model heater Uncontrolled NOx emissions, ton/yr Total effective NO x reduction, ton/yr @ capacity Cost effectiveness, $/ton @ capacity factors:a
capacity, @ capacity factors: reduction, factors: Total annual costs, $/yr @ capacity factors:
MMBtu/hr NO x control technique percent
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
6-30
0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9
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
6-31
0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9
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
a
Cost effectiveness = Total annual cost/NOx reductions.
6-32
FOR MD NATURAL GAS-FIRED MODEL HEATERS (1991 $)
Uncontrolled NOx emissions, ton/yr @ NO x reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity
Model heater capacity factors: factors: factors: factors:a
capacity, NO x control technique Total effective reductions,
MMBtu/hr percent
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
6-33
Uncontrolled NOx emissions, ton/yr @ NO x reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity
Model heater capacity factors: factors: factors: factors:a
capacity, NO x control technique Total effective reductions,
MMBtu/hr percent
0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9 0.1 0.5 0.9
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
a
6-34
TABLE 6-10. COST EFFECTIVENESS OF CONTROL TECHNIQUES FOR
ND OIL-FIRED MODEL HEATERS (1991 $)
Model heater capacity NO x control technique Uncontrolled NOx emission, ton/yr @ Total effective NO x reductions, ton/yr @ capacity Total annual costs, $/yr @ capacity Cost effectiveness, $/ton @ capacity
and fuel type, capacity factors: reduction, factors: factors: factors:a
MMBtu/hr percent
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
a
FOR MD OIL-FIRED MODEL HEATERS (1991 $)
a
Uncontrolled NO x emissions, NO x reductions, ton/yr @ capacity Cost effectiveness, ton/yr @ capacity factors:
Model heater ton/yr @ capacity factors: Total effective factors: Total annual costs, $/yr @ capacity factors:
capacity, reduction,
0.1 0.5 0.9
x percent
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 3,680 735 408
SNCR 18.9 94.6 170 60 11.4 56.8 102 90,900 114,000 137,000 8,010 2,000 1,340
SCR 18.9 94.6 170 75 14.2 71.0 128 501,000 516,000 532,000 35,300 7,280 4,160
LNB + FGR 18.9 94.6 170 48 8.99 44.9 80.9 86,100 90,300 94,600 9,570 2,010 1,170
LNB + SNCR 18.9 94.6 170 78 14.8 73.9 133 142,000 165,000 187,000 9,580 2,230 1,410
LNB + 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 2,210 442 245
SNCR 31.9 160 287 60 19.2 95.8 172 92,600 122,000 152,000 4,830 1,280 880
SCR 31.9 160 287 75 23.9 120 216 501,000 518,000 535,000 20,900 4,330 2,480
LNB + FGR 31.9 160 287 34 10.9 54.7 98.5 86,100 90,300 94,600 7,870 1,650 961
LNB + SNCR 31.9 160 287 75 23.9 119 215 143,000 173,000 202,000 6,000 1,450 942
LNB + SCR 31.9 160 287 91 28.9 145 260 536,000 553,000 570,000 18,500 3,820 2,190
a
Cost effectiveness = Total annual cost/NO x reductions.
FOR ND PYROLYSIS MODEL HEATERS (1991 $)
Cost effectiveness,
Uncontrolled emissions, ton/yr Controlled emissions, ton/yr @ Reduction, ton/yr Total annual costs, $/yr @ capacity $/ton removed,
Model heater @ capacity factors: Total capacity factors: @ capacity factors: factors: @ capacity factors: a
capacity and effective
fuel type, reduction,
x 0.1 0.5 0.9 percent 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 4,470
SCR 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
a
Cost effectiveness = Total annual cost/NO x reductions.
TABLE 6-13. CARB COST EFFECTIVENESS FOR NOx EMISSION
CONTROL TECHNIQUES (1991 $)12
Annual capacity factor, Unit size range, Cost effectiveness range,

Control technology percent MMBtu/hr thousand/ton NOxa
Low-NOx burners 10 3.5 to 150 2.61 to 30.6

50 0.570 to 7.25
90 0.340 to 4.53
Flue gas recirculation 10 3.5 to 350 7.71 to 32.9

50 1.81 to 7.71
90 1.13 to 4.19
Selective noncatalytic reduction 10 50 to 375 2.61 to 22.7

50 1.70 to 6.80
90 1.47 to 4.31
Selective catalytic reduction 10 50 to 350 27.2 to 74.8

50 6.80 to 15.9
90 4.53 to 10.2
a
Escalated from 1986 $ to 1991 $ using the Chemical Engineering plant cost index.3
California Air Resources Board (CARB).12 The accuracy of the
cost methodologies used in this study is estimated to be
30 percent plus or minus the actual cost.1 The cost-
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
Cost
Cost, $ 1991
Heater Emission effec-
capacity, Capacity reduction, Capital Annual Total tiveness,
MMBtu/hr factor tons/yr a Capital recoveryb operating annual $/ton
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
a
Emission reduction compared to an MD heater with conventional burners.
b
The capital recovery factor is 0.131.
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
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.
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
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..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
7-1
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.1,2 Staged-fuel LNBs, discussed in Section 5.1.4, yield the
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 NOxOUT® 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.
7-2
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.7 Combustion controls for NOx
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
7-3
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
7-4
Figure 7-1. NOx emission factor for 10 process heaters equipped
with low-NOx burners as a function of stack oxygen.8
7-5
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
7-6
Table 7-1
7-7
TABLE 7-1. OPTIMUM LOW-EXCESS-AIR, GASEOUS EMISSIONS
AND EFFICIENCIES FOR SIX PROCESS HEATERS WITH LOW-NO x BURNERS 8
As-found Optimum low-NO x
Capacity, Heater Heater

MMBtu/ Heater NO, NO, O2, CO, efficiency, NO, NO, O2, CO, efficiency,
hr configurationa ng/J ppm percent ppmb percent ng/J ppm percent ppmb percent
16 211 92.4 168 5.1 11 64.0 80.4 145 4.0 11 64.0
22 121 39.0 77 6.2 0 79.9 24.0 48 3.0 20 83.0
30 121 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 71.3
320 132 65.8 130 5.3 11 68.0 35.4 70 2.3 33 68.5
320 132 60.2 119 8.4 0 66.4 32.9 65 3.3 10 68.8
7-8
a
Heater configuration designations as follows:
1st digit 2nd digit 3rd digit
Fuel burned Draft type Air temp.
1 = gas 1 = natural 1 = ambient

2 = dist. oil 2 = forced 2 = preheater
3 = balanced
b
Dry, corrected to 3 percent O2.
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
7-9
7-10
operations were generally unchanged from the as-found
conditions.8 The study showed that emissions reductions with
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
7-11
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
a
Heater is operated with an LEA system.
b
Corrected to 3 percent O2.
7-12
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.6 As discussed
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
7-13
TABLE 7-3. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS FOR A
6.7 MMBtu/hr (200 hp) BOILER WITH LNB + FGR10
lb NOx/ lb CO/
Fuel Load, % % FGR % O2 NOx, ppma MMBtu CO, ppma 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
b
FO 68 0 3.80 138 0.199 13 0.007
FOb 68 18.9 3.70 109 0.158 20 0.012
b
FO 100 0 4.33 158 0.336 16 0.014
b
FO 100 14.3 4.07 123 0.265 14 0.012
a
Corrected to 3 percent O2.
b
No. 2 distillate fuel oil.
7-14
presents data on the impact of FGR on emissions for a 200-hp
firetube boiler.10 The boiler was operated at 66 and 100 percent
load firing natural gas. It was also operated at
7-15
7-16
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).6 Figure 7-2
7-17
Figure 7-2. Pilot-scale test results, NH3 emissions.
Inlet NO = 700 ppm.12
7-18
shows that at higher temperatures, when NH3 and urea are more
reactive, NH3 slip is reduced. In a
7-19
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.3 Therefore, NH3 slip
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.3,10 The Occupational Safety and Health
Administration standard limits occupational exposure of 50 ppmv
for an 8 hour period.7 However, NH3 handling is not expected to
present a problem as long as proper safety procedures are
followed.
Nitrous oxide and CO have been shown to be byproducts of
urea injection.11,12 Nitrous oxide formation has been shown to be
a byproduct of ammonia injection, but studies show these
emissions to be less than 20 ppmv.1,12 While N2O emissions from
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.12 The following reactions describe
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.
7-20
Figure 7-3. Pilot-scale test results; NOx reduction and N20
production versus temperature.12
7-21
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
7-22
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.6,7,9,13 The ratios of NH3:NOx (1.00:1 or less to 1.05:1)
for SCR are lower than for SNCR, which reduces the potential for
unreacted NH3 emissions.11 As with NH3 SNCR, ammonia storage and
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 SO3.3 Catalysts
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.13 Sulfuric acid condensation in the flue gas may
result from SO3 emissions.14 In addition, formation of (NH4)2SO3
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.15 States and local regulatory
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
7-23
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.7 The additional fan horsepower requirement
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.
7-24
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.7 The dilution of the combustion air supply
with inert products of combustion decreases the thermal
efficiency.6 Losses in efficiency are compensated for by
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.
7-25
d. REFERENCES FOR CHAPTER 7
1 Letter and attachments from Eichamer, P., Exxon Chemical

Comments on Draft Alternative Control Techniques Documents--
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.
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.
7-26
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.
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.
7-27
APPENDIX A. REFINERY PROCESS HEATER INVENTORYa
10a 10b 10d
Air Oxygen Heater load, Uncontrolled NOx

Heater Heater Capacity No. of burners Heater preheat, content, % % rated capacity emission factor, Method of
No. typeb MMBtu/hrc in heaterd installed date Draft typee Fuel typef EFc 02 Dryc at time of test lb NOx /MMBtu determination
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)
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
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
(0.065)
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
7-28
APPENDIX A. (continued)
10a 10b 10d

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
75 SHTC 151 18-FF 1969 ND HPBL -AMB- 3.8 67.5 0.111 CALC
78 VC 38 6-FF 1969 ND NSPS -AMB- 3.8 66.3 0.083 CALC
48 VTB 120 20-FF 1966 ND HPBL -AMB- 3.8 52.8 0.071 TEST
84 VTB 148 42-FF 1969 ND HPBL -AMB- 3.8 56.0 0.064 CALC
7-29
APPENDIX A. (continued)
10a 10b 10d

24 DWB 24 4-FF 1934 ND HPBL -AMB- 3.8 64.5 0.111 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
40 COB 576 15-WF 1966 MD HPBL/CO -AMB- 6.7 99.1 0.21 CALC
a
Reference 16 from Chapter 5.
b
VC = Vertical cylinder, VC P = vertical cylinder, petrochem; SWB = single wing box, DWB = double wing box, HC = horizontal cabin with hot wall,
HCHW = horizontal cabin with hot wall; SHTC = single hoop tube cabin; VTB = vertical tube box; and COB = carbon monoxide boiler.
c
Design basis, actual varies.
d
WF = wall-fired and FF = floor-fired.
e
ND = Natural draft and MD = mechanical draft.
f
HPBL = High pressure burner line fuel gas; and NSPS = new source performance standard fuel gas.
7-30
APPENDIX B. CURRENT AND FUTURE NOxOUT® APPLICATIONSa
NOx baseline Guaranteed % Temperature $/ton NOx

Unit type Fuel Size MWb ppm reduction EF removed/year
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 Bark1 CH4 39.5 85-125 35 1700-1800 NA

Detroit Stoker
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
B-1
APPENDIX B: (continued)

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
B-2
APPENDIX B: (continued)

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
a
b
Rated power output.
B-3
APPENDIX C. LIST OF PROCESS HEATER NOx CONTROL RETROFITS FOR
MOBIL TORRANCE REFINERYa
Capacity, Preretrofit Preretrofit NOx Post-retrofit Post-retrofit NOx NOx

MMBtu/ control tech- emissions, control tech- emissions, emission reduc-
Heater hr nology lb/MMBtu nology lb/MMBtu tions, %
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
a
C-1
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, SOx = Gas Gas, SOx = Gas Gas Gas, SOx = Gas Gas Gas Gas
12 ppm 17 ppm 23 ppm
Additional NOx N/Ab N/A N/A N/A N/A N/A N/A LNB N/A N/A N/A N/A
Control
Inlet gas flow, 3.6 x 106 3.2 x 106 1.0 x 106 11.8 x 106 1.9 x 106 0.5 x 106 0.7 x 106 8 x 106 5 x 106 2.3 x 106 15 x 106 5 x 106
ft3 /hr
Inlet 680 700-750 700-750 580 630 725 720 625 680 700 695 600
temperature, EF
Catalyst material V2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5 V 2 O5
Support material T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2 T2 O2
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. H2 O
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% O2 10 @ 3% O2
SLIP, ppm
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
a
Reference 29 from Chapter 5
N/A = not available.

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Emission Standards Division

U.S. ENVIRONMENTAL PROTECTION AGENCY

TABLE 4-2. AVERAGE UNCONTROLLED NOX EMISSIONS FROM

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

This chapter presents a summary of the information contained

Uncontrolled emission factor,

Model heater type Thermal NOx Fuel NOx Total NOxa

ND, natural gas-firedb 0.098 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 0.162 d N/A 0.140

Control technique - low and medium

Control technique - pyrolysis furnaces Total effective NOx reduction,a percent

ND, distillate (ND) LNB 40

ND, residual (ND) LNB 27

MD, distillate (MD) LNB 45

MD, residual (MD) LNB 37

Cost effectiveness, $/ton @ capacity

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

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

Cost effectiveness, $/ton @ capacity

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

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

Cost effectiveness, $/ton @ capacity

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

Cost effectiveness, $/ton @ capacity factors:c

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

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

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

Cost effectiveness, $/ton @ capacity factors:c

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

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

This chapter describes process heaters and characterizes the

N/A = Not available.

aHeavy gas oils and middle distillates.

Low- and medium-temperature applications

Benzene Reformate extraction Reboiler 700 64.8 9.9

Styrene Ethylbenzene Steam superheater 1,500 - 1,600 32.1 4.9

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

Reaction of p-xylene and Preheater, hot oil furnace

Ethanol (synthetic) Ethylene hydration Preheater 750 1.3 0.2

Acetone Various Hot oil furnace N/A 0.8 0.1

Others See Table 3-7

Ethylene/propylene Thermal cracking Pyrolysis furnace 1,900 - 2,300 337.9 51.8

Methanol Hydrocarbon reforming Steam hydrocarbon 1,000 - 2,000 25.7 4.0

TOTAL KNOWN FIRED HEATER ENERGY REQUIREMENT 652.4 100

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

4.0 CHARACTERIZATION OF NOx EMIS

A discussion of uncontrolled NOx emissions from process

NOx emission factor

Fuel Natural drafta Mechanical draftb

NOx emissions, lb/MMBtu

Natural drafta Mechanical draftb