xvEPA
United States Office of Air Quality
Environmental Protection Planning and Standards
Agency Research Triangle Park NC 27711
EPA-453/R-93-034
September 1993
Air
Alternative Control
Techniques Document -
NOx Emissions from
Process Heaters (Revised)
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EPA-453/R-93-034
Alternative Control
Techniques Document-
NO> 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
on Agency
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TABLE OF CONTENTS
Section Page
1.0 INTRODUCTION 1-1
2.0 SUMMARY 2-1
2.1 UNCONTROLLED NOy EMISSIONS 2-1
2.2 AVAILABLE NOy 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 NOy 4-1
4.1.1 Thermal NOX Formation 4-1
4.1.2 Fuel NO Formation 4-4
4.1.3 Prompt NO Formation 4-6
4.2 FACTORS AFFECTING UNCONTROLLED NOX EMISSIONS . . 4-6
4.2.1 Heater Design Parameters 4-6
4.2.1.1 Fuel Type 4-7
4.2.1.2 Burner Type 4-8
4.2.1.3 Combustion Air Preheat 4-10
4.2.1.4 Firebox Temperatures 4-10
4.2.1.5 Draft Type 4-12
4.2.2 Heater Operating Parameters 4-14
4.2.2.1 Excess Air 4-14
4.2.2.2 Burner Adjustments 4-15
4.3 UNCONTROLLED NOX EMISSION FACTORS AND MODEL
HEATERS 4-15
4.3.1 Uncontrolled NOX Emissions 4-17
4.3.2 Model Heaters 4-25
4.4 REFERENCES FOR CHAPTER 4 4-30
ill
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TABLE OF CONTENTS (continued)
Section Page
5.0 NO 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-NO Burners 5-9
5.1.5 Staged-Fuel, Low-NO Burners 5-15
5.1.6 Flud 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 NO Reduction Efficiency Using
Thermal DeNOx® 5-32
5.2.1.4 Ammonia Slip Considerations For
Thermal DeNO ® 5-32
5.2.2 Nalco Fuel Tech NOXOUT® (Urea Injection) . 5-32
5.2.2.1 Process Description (NO OUT®) . . 5-33
5.2.2.2 Factors Affecting NOXOUT®
Performance 5-35
5.2.2.3 NO Emission Reduction
Efficiency Using NOXOUT® .... 5-36
5.2.2.4 Ammonia Slip Considerations For
NO OUT® 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 NO Emission Reduction Efficiency Using
SCR 5-43
5.4 SPECIAL CONSIDERATIONS 5-46
5.5 ACHIEVABLE NO EMISSION REDUCTIONS 5-50
5.6 REFERENCES FOR CHAPTER 5 5-58
6.0 CONTROL COSTS 6-1
6.1 CAPITAL AND ANNUAL COSTS METHODOLOGIES 6-2
6.1.1 Costs of LNB's 6-2
6.1.1.1 Capital Costs of LNB's 6-2
6.1.1.2 Operating Costs of LNB's .... 6-4
6.1.2 Cost Of ULNB'S 6-5
6.1.2.1 Capital Costs of ULNB's 6-5
6.1.2.2 Operating Costs of ULNB's .... 6-5
IV
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TABLE OF CONTENTS (continued)
Section Page
6.1.3 Costs of SNCR 6-6
6.1.3.1 Capital Costs of SNCR 6-6
6.1.3.2 Operating Costs of SNCR 6-6
6.1.4 Costs of SCR 6-7
6.1.4.1 Capital Costs of SCR 6-7
6.1.4.2 Operating Costs of SCR 6-7
6.1.5 Costs of FGR 6-8
6.1.5.1 Capital Costs of FGR 6-8
6.1.5.2 Operating Costs of FGR 6-9
6.1.6 Costs of LNB's Plus SNCR 6-9
6.1.6.1 Capital Costs of LNB's Plus
SNCR 6-9
6.1.6.2 Operating Costs of LNB's
Plus SNCR 6-10
6.1.7 Costs of LNB's Plus SCR 6-10
6.1.7.1 Capital Costs of LNB's
Plus SCR 6-10
6.1.7.2 Operating Costs of LNB's
Plus SCR 6-10
6.1.8 Costs of ND-to-MD Conversion 6-10
6.1.8.1 Capital Costs of ND-to-MD
Conversion 6-10
6.1.8.2 Operating Costs of ND-to-MD
Conversion 6-11
6.2 TOTAL ANNUAL COST FOR MODEL HEATERS 6-11
6.2.1 Control Costs for the ND Gas-Fired,
Low- and Medium-Temperature Model
Heaters 6-12
6.2.2 Control Costs for MD Gas-Fired, Low- and
Medium-Temperature Model Heaters 6-12
6.2.3 Control Costs for ND Oil-Fired, Low- and
Medium-Temperature Model Heaters 6-12
6.2.4 Control Costs for MD Oil-Fired, Low- and
Medium-Temperature Model Heaters 6-18
6.2.5 Conrol 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 NOy CONTROLS FOR PROCESS
HEATERS 6-18
6.4 COST EFFECTIVENESS OF RADIANT BURNERS 6-32
6.5 REFERENCES FOR CHAPTER 6 6-34
7.0 ENVIRONMENTAL AND ENERGY IMPACTS 7-1
7.1 AIR POLLUTION IMPACTS 7-1
7.1.1 NOX Emission Reductions 7-1
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TABLE OF CONTENTS (continued)
Section Page
7.1.2 Emissions Trade-Offs 7-3
7.1.2.1 Impacts on HC and CO Emissions
from the Use of LNB's, ULNB's
and FOR 7-3
7.1.2.2 Impacts on NH-,, N20, CO, and
PM Emissions from the Use
of SNCR and SCR 7-10
7.2 SOLID WASTE IMPACTS 7-14
7.3 ENERGY IMPACTS 7-15
7.4 REFERENCES FOR CHAPTER 7 7-17
APPENDIX A: REFINERY PROCESS HEATER INVENTORY A-l
APPENDIX B: CURRENT AND FUTURE NOXOUT® APPLICATIONS ... B-l
APPENDIX C: LIST OF PROCESS HEATER NOX CONTROL RETROFITS
FOR MOBIL TORRANCE REFINERY C-l
APPENDIX D: FOSTER WHEELER PROCESS HEATER SCR
INSTALLATIONS D-l
VI
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LIST OF TABLES
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: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR
ND, NATURAL GAS-FIRED LOW- AND MEDIUM-
TEMPERATURE HEATERS 2-9
TABLE 2-5. MODEL HEATERS: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR
MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-
TEMPERATURE HEATERS 2-12
TABLE 2-6. MODEL HEATERS: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR ND,
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE
HEATERS 2-14
TABLE 2-7. MODEL HEATERS: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR MD,
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE
HEATERS 2-15
TABLE 2-8. MODEL HEATERS: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR ND
OLEFINS PYROLYSIS HEATERS 2-16
TABLE 3-1. SURVEY OF OPERATING REFINERIES IN THE U.S. . . 3-13
TABLE 3-2. MAJOR REFINERY PROCESSES REQUIRING A FIRED
HEATER 3-14
TABLE 3-3.
TABLE 3-4.
ENERGY REQUIREMENTS OF MAJOR FIRED HEATER
APPLICATIONS IN THE CHEMICAL INDUSTRY .... 3-17
REPORTED APPLICATIONS OF FIRED HEATERS
IN THE CHEMICAL MANUFACTURING INDUSTRY .... 3-18
Vll
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LIST OF TABLES (continued)
Page
TABLE 4-1. AP-42 ESTIMATES FOR UNCONTROLLED NO 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 NO 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
TABLE 4-7. MODEL HEATERS AND UNCONTROLLED EMISSION
FACTORS: DISTILLATE AND RESIDUAL
OIL-FIRED, LOW- AND MEDIUM-TEMPERATURE MD
WITH PREHEAT 4-31
TABLE 4-8. MODEL HEATERS AND UNCONTROLLED EMISSION
FACTORS: NATURAL GAS-FIRED AND 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
LNB'S 5-10
TABLE 5-3. STAGED-AIR BURNER NOX CONTROL PERFORMANCE
AND EMISSION LEVELS 5-11
TABLE 5-4. STAGED-FUEL LOW-NO BURNER CONTROLLED
NOX EMISSION LEVELS 5-18
Vlll
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LIST OF TABLES (continued)
TABLE 5-5.
TABLE 5-6.
TABLE 5-7.
TABLE 5-8.
TABLE 5-9.
TABLE 5-10.
TABLE 5-11.
TABLE 5-12.
TABLE 5-13.
TABLE 5-14.
TABLE 5-15.
TABLE 6-1.
TABLE 6-2.
TABLE 6 - 3.
TABLE 6-4.
TABLE 6-5.
CONTROLLED NO EMISSION LEVELS FOR STAGED-
FUEL LOW-NO.. BURNERS
RADIANT BURNER APPLICATIONS
PARTIAL LIST OF EXXON'S THERMAL DeNO ®
INSTALLATIONS
NALCO FUEL TECH NOXOUT® PROCESS HEATER
APPLICATIONS
CONTROLLED EMISSION FACTORS FOR SCR ADDED TO
HEATERS WITH LNB's
ENERGY REQUIREMENTS OF MAJOR FIRED HEATER
APPLICATIONS IN THE CHEMICAL INDUSTRY . .
MODEL HEATERS: CONTROLLED EMISSIONS FOR
ND, NATURAL GAS-FIRED, LOW- AND MEDIUM-
TEMPERATURE HEATERS
MODEL HEATERS: CONTROLLED EMISSIONS FOR
MD, NATURAL GAS-FIRED, LOW- AND MEDIUM-
TEMPERATURE HEATERS
MODEL HEATERS: CONTROLLED EMISSIONS FOR
ND OIL-FIRED HEATERS
MODEL HEATERS: CONTROLLED EMISSIONS FOR
MD OIL-FIRED HEATERS
MODEL HEATERS: CONTROLLED EMISSIONS FOR
ND OLEFINS PYROLYSIS HEATERS
UTILITY, CHEMICAL, AND MAINTENANCE COSTS . .
COSTS OF CONTROL TECHNIQUES FOR ND
NATURAL GAS-FIRED MODEL HEATERS
COSTS OF CONTROL TECHNIQUES FOR MD
NATURAL GAS-FIRED MODEL HEATERS .
COSTS OF CONTROL TECHNIQUES FOR ND
OIL-FIRED MODEL HEATERS
COSTS OF CONTROL TECHNIQUES FOR MD OIL-FIRED
MODEL HEATERS
Page
5-19
5-25
5-30
5-37
5-44
5-47
5-52
5-53
5-54
5-55
5-56
6-3
6-13
6-15
6-17
6-19
IX
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LIST OF TABLES (continued)
Page
TABLE 6-6. COSTS OF CONTROL TECHNIQUES FOR ND
OLEFINS PYROLYSIS MODEL HEATERS 6-20
TABLE 6-7. ND-TO-MD CONVERSION COSTS FOR THE ND MODEL
HEATERS 6-21
TABLE 6-8. COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR ND NATURAL GAS-FIRED MODEL HEATERS .... 6-23
TABLE 6-9. COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR MD NATURAL GAS-FIRED MODEL HEATERS .... 6-26
TABLE 6-10. COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR ND OIL-FIRED MODEL HEATERS 6-28
TABLE 6-11. COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR MD OIL-FIRED MODEL HEATERS 6-29
TABLE 6-12. COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR ND PYROLYSIS MODEL HEATERS 6-30
TABLE 6-13. CARB COST EFFECTIVENESS FOR NOX EMISSION
CONTROL TECHNIQUES 6-31
TABLE 6-14. RADIANT BURNER COST EFFECTIVENESS 6-33
TABLE 7-1. OPTIMUM LOW-EXCESS-AIR, GASEOUS EMISSIONS AND
EFFICIENCIES FOR SIX PROCESS HEATERS WITH
LOW-NO,.. BURNERS 7-6
.A.
TABLE 7-2. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS
FOR A 20 MMBtu/hr REFINERY HEATER WITH LNB
PLUS LEA OPERATION (REFINERY FUEL GAS) .... 7-8
TABLE 7-3. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS
FOR A 6.7 MMBtu/hr (200 hp) BOILER WITH
LNB PLUS FGR 7-9
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LIST OF FIGURES
Page
Figure 2-1,
Figure 2-2
Figure 2-3
Figure 2-4
Figure 2-5
Figure 3-1.
Figure 3-2.
Figure 3-3.
Figure 3-4.
Figure 3-5,
Figure 4-1,
Figure 4-2.
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
Model heaters: NOX emission reductions,
capital costs, and cost effectiveness at a
capacity factor of 0.9 for MD, natural
gas-fired, low- and medium-temperature
heaters
Model heaters: NOX emission reductions,
capital costs, and cost effectiveness at a
capacity factor of 0.9 for ND, oil-fired,
low- and medium-temperature heaters . . .
Model heaters: NO emission reductions,
capital costs, and cost effectiveness at a
capacity factor of 0.9 for MD, oil-fired,
low- and medium-temperature heaters . . .
Model heaters: NO emission reductions,
capital costs, and cost effectiveness at a
capacity factor of 0.9 for ND olefins
pyrolysis heaters
2-17
2-18
2-19
2-20
Cross-section of a typical process heater
Examples of radiant section tube orientations
Typical burners by type of fuel burned . . .
Size distribution of the existing fired
heater population
Annual energy consumption projection for
process heaters used in petroleum refining .
Impact of temperature on NOV formation . . .
J\.
Effect of fuel-bound nitrogen on NOX
emissions
Figure 4-3. Effect of combustion air preheat temperature
on NOX emissions
2-21
3-4
3-7
3-9
3-11
3-15
4-3
4-5
4-11
XI
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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 NOV emissions 5-5
Jt
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
XI1
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LIST OF FIGURES (continued)
Page
Figure 5-9. Effect of temperature and oxygen on NOX
conversion 5-41
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 N70 production versus temperature .... 7-13
Xlll
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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
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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
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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 204°C (400°F) in the radiative and convective sections of the
heaters. Flue gas entering the convective section is usually in
excess of 800°C (1500°F) 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 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
2-1
-------
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 NO... Post combustion
Jv
techniques reduce NOX in the flue gas regardless of the formation
mechanism.
Thermal NOX formation increases rapidly at temperatures
exceeding 1540°C (2800°F) and is the primary source of NO., in
Jv
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 NOY emissions in heaters burning nitrogen-bearing fuels,
J\.
such as distillate and residual oils.
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
(Ib/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 Ib/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 Ib/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
2-2
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TABLE 2-1. UNCONTROLLED EMISSION FACTORS FOR MODEL HEATERS
Model heater type
ND, natural gas-fired"
MD, natural gas-fired'3
ND, distillate oil-fired
ND, residual oil-fired
MD, distillate oil-fired
MD, residual oil-fired
ND. pyrolysis, natural gas-fired
ND, pyrolysis, high-hydrogen fuel gas-firedc
Uncontrolled emission factor,
Ib/MMBtu
Thermal NOX
0.098
0.197
0.140
0.140
0.260
0.260
0.135
0.162d
Fuel NOX
N/A
N/A
0.060
0.280
0.060
0.280
N/A
N/A
Total N0xa
0.098
0.197
0.200
0.420
0.320
0.540
0.104
0.140
aTota! NOV = Thermal NOV + Fuel NOV
v A XX
DHeaters firing refinery fuel gas with up to 50 mole percent hydrogen can have up to 20 percent higher NOV
A
emissions than similar heaters firing natural gas.
cHigh-hydrogen fuel gas is fuel gas with 50 mole percent or greater hydrogen content.
Calculated assuming approximately 50 mole percent hydrogen.
N'A = Not applicable.
2-3
-------
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
(ULNB's), selective noncatalytic reduction (SNCR), and selective
catalytic reduction (SCR). Also, LNB's are used in combination
with flue gas recirculation (FOR), 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 (NHj) 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
2-4
-------
reduction efficiencies and the reduction efficiencies for FGR,
and SNCR are based on a Canadian Petroleum Products Institute
report. Tables 2-2 and 2-3 present the reduction efficiencies
for each NO., control technique. The total effective reduction
.A.
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 NO..
Jt
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 NOV
J\-
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
2-5
-------
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
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB + SNCR
LNB + SCR
Total effective NOX reduction,3 percent
50
75
60
75
55
80
88
Control technique - pyrolysis furnaces
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB + SNCR
LNB + SCR
Total effective NOX reduction,3 percent
25
50
60
75
55
70
81
aFurther discussion on the NOY reduction efficiencies of each control technique is included in Chapter 5.
2-6
-------
TABLE 2-3. REDUCTION EFFICIENCIES FOR CONTROL TECHNIQUES APPLIED
TO ND AND MD, DISTILLATE AND RESIDUAL OIL-FIRED PROCESS HEATERS
Draft and fuel type
ND. distillate
ND, residual
MD, distillate
VI D, residual
Control technique
(ND) LNB
(MD) LNB
(ND) ULNB
(MD) ULNB
SNCRb
(MD) SCR
(MD) LNB + FOR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
(ND) LNB
(MD) LNB
(ND) ULNB
(MD) ULNB
SNCR
(MD)SCR
(MD) LNB + FGR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
Total effective NOX reduction,8 percent
40
43
76
74
60
75
43
76
77
86
27
33
77
73
60
75
28
71
73
83
45
74
60
75
48
78
92
37
73
60
75
34
75
91
aFurther discussion on the NOX reduction efficiencies of each control technique is included in Chapter 5.
Deduction efficiencies for ND or MD SNCR are equal
2-7
-------
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, eind
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-
NOV burners plus FGR have higher cost effectiveness than SNCR in
.A.
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) $l,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.
2-8
-------
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2-13
-------
W
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O
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capacity, M
MBtu/hr
g
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2-14
-------
TABLE 2-7. MODEL HEATERS: NO EMISSION REDUCTIONS,
CAPITAL COSTS, AND COST EFFECTIVENESS FOR MD, OIL-FIRED,
LOW- AND MEDIUM-TEMPERATURE HEATERS
Model heater
capacity,
MMBtu/hr
135
135
Fuel
Distillate oil
Residual oil
Uncontrolled NOX
emission
factor, Ib/MMbtu
Thermal NOX
0.26
0.26
Fuel NOX
0.06
0.28
NOX control
technique
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB i- SCR
Total
effective
NOX
reduction,
percent
45
74
60
75
48
78
92
37
73
60
75
34
75
91
NOX
reduction,
ton/yt*-b
85.7
141
114
142
89.9
148
174
118
235
192
239
109
239
289
Capital
cost,
$
319,000
326,000
536,000
2,780,000
535,000
855,000
3,010,000
319,000
326,000
536,000
2,780,000
535,000
855,000
3,010,000
Cost effectiveness,
$/ton capacity
factors :c
0.1
5,920
3,680
8,010
35,300
9,570
9,580
30,800
4,290
2,210
4,830
20,900
7,870
6,000
18,500
0.5
1,180
735
2,000
7,280
2,010
2,230
6,340
858
442
1,280
4,330
1,650
1,450
3,820
0.9
658
408
1,340
4,160
1,170
1,410
3,620
477
245
880
2,480
961
942
3,190
*NOX reductions = Uncontrolled emission factor (Ib/MMBtu) * Capacity(MMBtu/hr) * Effective reduction (ft) * 1 ton/2,0001b '
8.760 hr/yr * capacity factor.
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.
cCost effectiveness is calculated by dividing the total annual cost (TAC) by the NOX reductions. Refer to Chapter 6 for the
TAC.
2-15
-------
TABLE 2-8. MODEL HEATERS: NO EMISSION REDUCTIONS, CAPITAL
COSTS, AND COST EFFECTIVENESS FOR ND OLEFINS PYROLYSIS HEATERS
Model
heater
capacity,
MMBtu/hr
84
84
Fuel
natural gas
high-
hydrogen
fuel
gas
Uncont rolled
NOX omiMion
factor,
Ib/MMBtu
0.135
0.162
N0y control
technique
(ND) LNB
(MD) LNB
(ND) ULNB
(MD) ULNB
(ND) SNCR
(MD) SNCR
SCR
LNB + FOR
(NDI LNB + SNCR
(MDI LNB + SNCR
LNB + SCR
(ND) LNB
(MD) LNB
(ND) ULNB
(MD) ULNB
(ND) SNCR
(MDISCNR
SCR
LNB +FGR
(ND) LNB -f SNCR
(MD) LNB + SNCR
LNB + SCR
Total
•ff»ctiv» NOX
reduction,
percent
25
25
50
50
60
60
75
55
70
70
81
25
25
50
50
60
60
75
55
70
70
81
Reduction,
ton/yra'b
37.2
37.2
24.9
24.9
19.9
19.9
12.4
22.3
14.9
14.9
9.3
44.7
44.7
29.8
29.8
23.9
23.9
14.9
26.8
17.9
17.9
11.2
Capital
cost, $
248,000
642,000
252,000
648,000
403,000
673,000
2,520,000
804,000
651,000
1,050,000
2,900,000
248,000
642,000
252,000
648,000
403,000
673,000
2,520,000
804,000
651,000
1,050,000
2,900,000
Cost effectiveness, $/ton @
capacity factors:0
0.1
31,700
82,200
16,100
41,500
22,000
36,400
113,000
47,000
30,200
48,200
119,000
26,400
68,500
13,400
34,600
18,400
30,400
94,300
39,200
25,200
40,200
99,500
0.5
6,350
1 6,400
3,230
8,300
4,780
7,660
23,400
9,600
6,360
9,970
24,600
5,290
13,700
2,690
6,920
4,040
6,440
19,600
8,000
5,350
8,350
20,600
0.9
3,530
9,130
1,790
4,610
2,870
4,470
13,500
5,440
3,720
5,720
14,100
2,940
7,610
1,490
3,840
2,450
3,780
11,300
4,530
3,140
4 810
1 1 ,800
aNO reductions = Uncontrolled emission factor (Ib/MMBtu) * Capacity(MMBtu/hr) * effective reduction (%)
* 1 ton/2,000 Ib * 8,760 hr/yr * Capacity factor.
^NOX reductions in this column are calculated at a capacity factor of 1.0. To obtain reductions corresponding to other
capacity factors, substitute the desired capacity factor into the above equation.
cCost effectiveness is calculated by dividing the total annual cost (TAC) by the NOX reductions. Refer to Chapter 6 for the
TAG.
2-16
-------
TIVENESS,
)N
Lut;
LL
LU
O
0
(f)
o
CAPITAL C
20,000
18.000
16.000
14,000
12,000
10,000
8,000
6.000
4.000
2,000
0
5,000000
4 500 000
4,000,000
3,500,000
3 000 000
2.500 000
2,000000
1 500 000
1 000,000
500.000
0
16,200
6.940
6.770 1
4,600 • 1 6610|
• 4,000 1 1 I
2820 1 2,M | 1 2'93° "*>•
1,430| 2,020« i 41o I
4,130,000
^""•""l 961 .000
955,000 1 961 •000| 650,000 | 1
346 000 _ 191 goo I 351 .000 • 249,000 | 155 QQO I •
58 200 • • 62 500 1 •
15,100
6,600
5,710 • 3.150J 5.530J
4,460,000
1 ,600,000 g
1, 220,000 1 T995,000-|
1 996,000 1 1
253,000 1 1 46'000(
• 2130001
C/5
LU
O
u5Q 100
O LU
[TO 75
U. =)
LU O
Z LU 50
f- ^ 25
O
D
• • « • • 1
^ ^P
* *
P. MD ND MD MD
£ LNB LNB LNB LNB
ND MD ND MD ND MD MD
LNB LNB ULNB ULNB SNCR SNCR SCR
FGR SNCR SNCR SCR
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
-------
mVENESS,
)N
LUC
LL
LU
in
O
O
*t
(f>
O
o
_l
£
O
(^
LU
0
z
y Q
O LU
LL ^
u. r>
LU a
"7 ' ' '
I?
t- e-
O
LU
a:
10,000
9,000
8.000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
5,000,000
4.500,000
4,000,000
3,500,000
3.000,000
2,500.000
2.000,000
1 ,500,000
1 ,000,000
500,000
100
75
50
25
10.600 •
5.130 •
2,640 •
1,820 •
• . ... 1,470 •
1,210 « 1'23° •
813
4,090,000 •
H
^i
^H
•
1
I
1 ,270,000 I
777.000 • 783'°°° • 80°-000 I
1 30,000 1 136,000 I
9 w
^
LNB ULNB SNCR SCR
2,460 2,810 •
• 1,860 •
1,720 • •
158,000 •
1,100,000 • •
• 388,000 •
234,000 ™
0
^
LNB + FOR LNB + SNCR
9,880 •
5,530™
4.860,000 •
I
•
•
•
^1
^H
•
1
I
1,400,000 |
^k
LNB + SCR
Figure 2-2. Model heaters: NOX emission reductions, capital
costs, and cost effectiveness at a capacity factor of 0.9 for MD,
natural gas-fired, low- and medium-temperature heaters.
2-18
-------
co"
CO
LU
2
LU
P2
Lut;
LL
LU
CO
o
U
w.
CO
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o
1
(—
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<;
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co"
LU
o
2
LU j—
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i ^
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2 ^
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1 1 1
LLJ
CE
10.000
9.000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
3 000 000
2,800,000
2,600.000
2,400.000
2,200,000
2.000,000
1,800,000
1,600.000
1.40O.OOO
1,200,000
1.0OO.OOO
800,000
600.000
400,000
200,000
100
75
50
25
6,490 • _
__ _ M 6J60_B -
I 1
1 1
1 1
3,710 1 3,740 |
2,340« 2.350J 2,330— 2'390 2< *° • 2,580 •
1 680 • 1700* 1440. I 1 420 I ' '49° i 1 1650 •
1.190B • 1.230B
892 • seel
419 •
2.480.000
2.240,000 *
•
939.000
*
581.000 588000 598^000 5S8.0OO 586000
227,000 232000 358^000
86-
77m 83 •
76 74 76 • 77B
73l 75» ?1 | 73 i
60 • 60 •
27 • 3^i «•
MD NO MD MD
LNB LNB LNB LNB
ND MD ND MD ND MD MD + + * +
LNB LNB ULNB ULNB SNCR SNCR SCR FGR SNCR SNCR SCR
Figure 2-3. Model heaters: NOX emission reductions, capital
costs, and cost effectiveness at a capacity factor of 0.9 for ND,
oil-fired, low- and medium-temperature heaters.
2-19
-------
CO
CO
UJ
LLJ
is
tut:
LL
LLJ
CO
o
o
**.
CO
o
o
_l
^
bl
-------
en
C/5
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t~I f~\
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tut:
LL
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1—
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rr\
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LU
O
z
^ Q
O LU
LL O
Lt =>
LU Q
o =
1- 5s
O
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D
LU
or
20.000
18,000
16.000
14.000
12.000
10,000
8,000
6,000
4,000
2,000
0
3 000 000
2 BOO 000
2 600 000
2 400 000
2 200 000
2 000 000
1 BOO 000
1 600 000
1 400 000
1 .200 000
1 000 000
800 000
600000
400 000
200 000
0
100
75
SO
25
14 100 •
""!.. I
11.300 I 11.BOOB
9 130 •
7.610 I
5,440 • 5-720-—
4610— _ 4,530 1 4.810 •
3540— 3B*OB 3780B 3,720«
2,940 • 2,870 • 3 140>
2450 •
1 790 •
1 490 •
2 900 000
•
2 520 000
•
1 050 000
9
804 000
673 000 *
642000 ^S00 * 65T0
403,000
pc? 000 A
248000 <:3^.uuu m
0
• ^ ^
9 9
a •
• • * •
» •
MD ND MD MD
LNB LNB LNB LNB
ND MD ND MD ND MD MD + » , »
LNB LNB ULNB ULNB SNCR SNCR SCR FGR SNCR SNCR SCR
Figure 2-5. Model heaters: NOX emission reductions, capital
costs, and cost effectiveness at a capacity factor of 0.9 for ND
olefins pyrolysis heaters.
2-21
-------
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
(N20) emissions with the use of SNCR; NH3 and sulfite (S03)
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 NOY formed.
J\.
Combustion controls are usually operated in such a manner that
reduces NOX without producing unacceptable levels of CO and HC.
Combustion controls reduce NOV formation by reducing the peak
* .A.
flame temperature and/or 02 concentrations in the flame zone.
Reductions in NOY formation achieved by reducing flame
.A.
temperature and 02 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 N20 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 N00 have been shown to be byproducts of urea injection.
^
Unreacted NH3 and N20 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
2-22
-------
dioxide (802) present in high-sulfur fuels to S03, resulting in
S03 emissions. Newer catalyst formulations that convert less
than I percent S02 to S03 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.
2-23
-------
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. 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 90° to 204°C (200° to 400°F). 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
-------
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
Q
hydroconversion. 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.
3.1.2 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. •L
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
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 800° to 1000°C (1500° to 2000°F).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 800° to 1010°C (1500° to 2000°F) to
120° to 260°C (250° to 500°F).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 H20 [in. 1^0]) 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
3-3
-------
StacJt
Oamcer
Tube
Inlet Lf ra
Refractory
Ffreoox
Tube
Outlet
t
'/'
\
/J
' • • N
-** •+-
I
1
Y////////////////A Y//////////////////
Tube
Outlet
Ccnvecffon
Sec":on
Rad-iant
S*c:::on
Burners
Figure 3-1. Cross-section of a typical process heater.'
3-4
-------
between the hot flue gas in the stack and the significantly
cooler ambient air surrounding the stack. Approximately
90 percent of all gas-fired heaters and 76 percent of all oil-
f-t
fired heaters use ND combustion air supply.
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. H^O). 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
3-5
-------
Preheaters allow heat to be transferred to the combustion air
from flue gas, steam, condensate, hydrocarbon, or other hot
streams. The preheater increases the efficiency of the process
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 tc
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 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
3-6
-------
«. Cibtn
C. Cibin witti
bndftwatl
d. V*moM-«vlindrieal with
eentrwtion MCTMH
•. Artoor or wMkn type
Figure 3-2. Examples of radiant section tube orientations.10
3-7
-------
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 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
3-8
-------
'(Ml Jit
Id I ft
•frtetarj
nltt
a. Prefflix Surner
b. Raw Gas Burner
[nltt
c. 011 Burner
d. Combination 011 and Gas Burner
Figure 3-3. Typical burners by type of fuel burned.14
3-9
-------
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 l 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 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
3-10
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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 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 hydr©conversion. Table 3-2 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 displays the growth estimate for
the petroleum refining industry energy consumption, based on
the 1985 information.
3-12
-------
TABLE 3-1. SURVEY OF OPERATING REFINERIES IN THE U.S.17
(State capacities as of January 1, 1991)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Delaware
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Minnesota
Mississippi
Montana
Nevada
New Jersey
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
No. of plants
4
6
2
3
30
3
1
2
2
7
4
8
2
19
4
2
5
4
1
6
4
1
1
4
7
1
7
1
31
6
1
7
2
1
5
194
Crude capacity,
bbl/d
166,000
243,000
14,200
60,500
2,210,000
91,200
140,000
35,500
143,000
973,000
427,000
351,000
219,000
2,330,000
124,000
286,000
359,000
136,000
4,500
494,000
77,300
39,900
58,000
454,000
409,000
N/A
731,000
60,000
3,880,000
155,000
53,000
521,000
29,700
32,000
165,000
15,500,000
N/A = Not available.
3-13
-------
TABLE 3-2. MAJOR REFINERY PROCESSES REQUIRING A FIRED HEATER
22
Process
Process description
Heaters
used
Process heat requirements
lU/liter
103 Btu/bbl
feed
Feedstock
temperature
outlet ol
heater, °F
Distillation
Atmospheric
Vacuum
Separates light hydrocarbons from crude in a
distillation column under atmospheric
conditions.
Separates heavy gas oils from atmospheric
distillation bottoms under vacuum.
Preheater,
reboiler
Preheater,
reboiler
590
418
89
63
700
750-830
Thermal processes
Thermal cracking
Coking
Visebreaking
Thermal decomposition of large molecules into
lighter, more valuable products.
Cracking reactions allowed to go to completion.
Lighter products and coke produced.
Mild cracking of residuals to improve their
viscosity and produce lighter gas oils.
Fired
reactor
Preheater
Fired
reactor
4,650
1,520
961
700
230
145
850-1,000
900-975
850-950
Catalytic cracking
Fluidized
catalytic cracking
Catalytic
hydroc racking
Cracking of heavy petroleum products. A
catalyst is used to aid the reaction.
Cracking heavy feedstocks to produce lighter
products in the presence of hydrogen and a
catalyst.
Preheater
Preheater
663
1,290
100
195
600-885
400-850
Hydrop recessing
Hydrodesul-
funzation
Hydrotreating
Remove contaminating metals, sulfur, and
nitrogen from the feedstock. Hydrogen is added
and reacted over a catalyst.
Less severe than hydrodesulfunzation
Removes metals, nitrogen, and sulfur from
lighter feedstocks. Hydrogen is added and
reacted over a catalyst.
Preheater
Preheater
431
497
65"
75b
390-850
600 800
Hydroconversion
Alkylation
Catalytic
reforming
Combination of two hydrocarbons to produce a
higher molecular weight hydrocarbon. Heater
used on the fractionator.
Low-octane napthas are converted to
high-octane, aromatic napthas. Feedstock is
contacted with hydrogen over a catalyst.
Reboiler
Preheater
2,500
1,790
377°
270
400
850-1 ,000
aHeavy gas oils and middle distillates.
Light distillate.
cBtu/bbl of total alylate.
3-14
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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 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 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 1050° to 1250°C (1900° to 2300°F).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 590°C
(1100°F) and proceed more favorably as the temperature increases.
3-16
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Ethylene hydration
1 Ethanol (synthetic)
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EATER ENERGY R
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3-17
-------
TABLE 3-4. REPORTED APPLICATIONS OF FIRED HEATERS
IN THE CHEMICAL MANUFACTURING INDUSTRY25
Category
Organic chemicals manufacturing
Inorganic chemicals
manufacturing
Others
Applications
Acetone, acetic anhydride, acetylene, acrylic acids, alkyl benzene,
ally] chloride, amines, ammonia, benzenes, benzoic acid and other
aromatic acids, biphenyl, butadiene, chlorinated hydrocarbon solvents,
cumene, cyclohexane, dimethyl tereph thai ate, 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, polyvhiyl chloride, pyridine, salicyclic acid, toluene
diamine, toluene dissocyanate, xylene
Carbon bisulfite, carbon disulfide, carbon monoxide, caustic soda,
hydrogen, silicones, sulfur chloride
Additives, agricultural products, asphalt, carbon black, elastomers,
fabrics, finishes, Pharmaceuticals photo products, pigments,
plasticizers, polyamide adhesives, synthetic fibers
3-18
-------
The firebox temperature of steam-hydrocarbon reformers ranges
from about 980° to 1100°C (1800° to 2000°F).21
3.3 REFERENCES FOR CHAPTER 3
1. Shareef, S.A., C.L. Anderson, and L.E. Keller (Radian
Corporation). Fired Heaters: Nitrogen Oxides Emissions and
Controls. Prepared for the U. S. Environmental Protection
Agency. Research Triangle Park, NC. EPA Contract
No. 68-02-4286. June 1988. pp. 9-10.
2. Reference 1, p. 25.
3. Reference 1, p. 32.
4. Reference 1, pp. 10-12.
5. Control Techniques for 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.
8. Reference 1, p. 14.
9. Reference 5, pp. 5-35 through 5-36.
10. Reference 1, p. 13.
11. Reference 1, p. 16.
12. Reference 1, p. 18.
13. Reference 5, p. 5-38.
14. Reference 1, p. 17.
15. Reference 1, p. 19.
16. Reference 1, pp. 19-20.
17. Thrash, L.A. Annual Refining Survey. Oil and Gas Journal.
March 18, 1991. pp. 86-105.
18. Reference 1, p. 31.
19. Reference 1, p. 22.
3-19
-------
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.
21. Reference 1, p. 36.
22. Reference 1, p. 28.
23. Letter from Crockett, B.P., American Petroleum Institute, to
Crowder, J.U., EPA/ISB. July 23, 1984. Review of
Chapters 3 through 6 of NSPS BID draft.
24. Reference 1, p. 34.
25. Reference 1, p. 33.
3-20
-------
4.0 CHARACTERIZATION OF NO.. EMISSIONS
J\f
A discussion of uncontrolled NO., emissions from process
Jt
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 N02, are considered important in atmospheric
pollution. In this document, NO and N02 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
1540°C (2800°F) -and is more sensitive to local flame temperatures
than oxygen concentrations.1 Formation of thermal NOV is
J\.
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 ** NO + N (Reaction 1)
N + 02 ^ NO + 0 (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
T *?
Zeldovich mechanism in the following simplified equation: '
[NO] = kx exp (-k2/T) [N2] [02]1/2 t
where:
[ ] = mole fraction;
k-]_, k2 = constants;
T = peak flame temperature (°K); 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
shows the sensitivity of NOX formation to temperature. Note that
for an increase in temperature of less than 55°C (130°F), the
concentration of NO,, increases by one order of magnitude.
4-2
-------
c
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to
^
0)
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to
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0)
Cn
-H
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4-3
-------
4.1.2 Fuel NOX Formation
The role of fuel-bound nitrogen as a source of NO., emissions
JC
from combustion sources was recognized in 1968. Fuel NOX is the
result of .the reactions between fuel-bound nitrogen and oxygen in
the combustion air. The bond in liquid and solid fuels between
individual nitrogen atoms and other atoms, such as carbon, is not
as strong as the N « N bond found in molecular nitrogen. In the
combustion process, organically bound nitrogen atoms contained in
the fuel are released and are rapidly oxidized to NO.5
The mechanisms by which chemically bound fuel nitrogen
compounds are converted to NOX emissions are not yet fully
understood. Several studies, however, indicate that two
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
fj
characteristics of the char also influence the reaction rate.'
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, s.uch 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 NCL. than 80 percent conversion of the nitrogen in a fuel with
J\.
a nitrogen content of 0.1 percent by weight. Figure 4-2 shows
the increase in NO,, emissions due to the increase in nitrogen
Jx
content of the fuel.1
4-4
-------
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-------
4.1.3 Prompt NOX Formation
Prompt NO is a newly recognized mechanism of NOY formation.
•"• J*L
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
Q
reduce fuel efficiency.
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.
2.
3.
4.
5.
CH +
CH2
HCN
N +
NH +
N2
+ N2
+ °X
°x
0Y
— *
— '
-»
— >
—*.
HCN +
HCN +
NO +
NO
NO +
N;
NH;
. . • 1
+ . .
and
where Ox indicates oxides such as 0 or 02.9|1°
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
NO,, emissions.
J\.
4.2.1 Heater Design Parameters
Heater design parameters that affect the level of
uncontrolled NOX emissions from process heaters include the
4-6
-------
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.1
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 NOV emissions higher than
Jt
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
NOY, which accompanies the combustion of fuel oils.11
j\.
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
4-7
-------
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.
Burners can be divided into conventional and low-NOx
burners. Conventional burners are designed for high combustion
4-8
-------
efficiency and low hydrocarbon (HC) and carbon monoxide (CO)
emissions. Low-N0x 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-NO..,
J\.
formation. The combustion reaction is cooled in the secondary
zone by the secondary air, which inhibits thermal-NOY formation.
Jt
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
4-9
-------
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 1000°C (1830°F) , which yields low NO., formation
J\.
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 NOV
Jv
formation (Section 4.1.I).9 Tests show that the higher the
temperature of air preheat, the greater the formation of NOX.
Figure 4-3 shows the effect of combustion air preheat on NO..
Jv
emissions from a test-scale, mechanical draft (MD) heater.15
Preheating the combustion air temperature from ambient (21°C
[70°F]) to 204°€ (400°F) increases NOX emissions by a factor of
1.4 and more than doubles emissions when the air is preheated to
316°C (600°F),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
4-10
-------
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4-11
-------
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 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 700°C (1300°F) to
1040°C (1900°F).15 One source reports that below 1100°C (2100°F)
thermal NOX increases a nominal 10 percent for every 40°C (100°F)
increase in firebox temperature, which is consistent with the
above data.16 The same source reports that increasing the
temperature from 700° to 1000°C (1300° to 1900°F) 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 NO., formation at temperatures above 930°C (1700°F)
.A.
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.
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. H20), but
process heaters operate with radiant firebox pressures slightly
4-12
-------
1.6 -I
1.5 -
1.4 -
1.3 -
1.1 -
1,0 -
0.9
Excess Air « Constant
1300
1400
1500 1600 1700
FIREBOX TEMPERATURE, (3F)
1800
1900
Figure 4-4. Effect of firebox temperature on thermal
NOX formation for gas-fired heaters with constant excess air.11
4-13
-------
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 NO., formation in gas-fired heaters using these data is shown
Jv
4-14
-------
in Figure 4-5. Another source reports a NOX emissions increase
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. " 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 NOV levels than the long, low-intensity
J\.
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
4-15
-------
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5
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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 NO., emission control techniques and the
J^
cost effectiveness of available NOX emission control techniques.
Uncontrolled NOY emission factors are presented in Section 4.3.1.
•A.
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, are based on test data for
boilers. Three ranges of heat rates were defined for gas-fired
units, two ranges of heat rates were defined for distillate oil-
fired units, and three ranges of heat rates were defined for
residual oil-fired units. Uncontrolled NOX emission factors were
reported for each of the ranges of heat rates for each fuel.
Average emission factors for natural gas-, distillate
oil-, and residual oil-fired operation for ND and MD refinery
heaters were developed in a 1979 API-sponsored study.
Figure 4-6 presents uncontrolled NOV emission factors versus heat
Jt
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 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
4-17
-------
TABLE 4-1. AP-42 ESTIMATES FOR UNCONTROLLED NOy EMISSIONS
FROM BOILERS AND PROCESS HEATERS23
Heat rate,
MMBtu/hr
<10
10-100
>100
<10
10-100
>100
Fuel
Natural gas
Natural gas
Natural gas
Distillate oilb
Residual oilc
Distillate oilb
Residual oilc
Residual oil°
NOV emission factor
ng/Ja
41
58
228
63
162
63
162
197
Ib/MMBtu
0.10
0.14
0.53
0.15
0.38
0.15
0.38
0.46
-,, _ = nanogram per Joule
"Distillate oils include Nos. 1 and 2 fuel oils.
GResidual oils include Nos. 4, 5, and 6 fuel oils.
4-18
-------
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increases in the nitrogen content of the fuel being burned as a
result of the formation of fuel NOX,
Uncontrolled NOV emission factors developed by averaging the
Jt
data shown in Figures 4-6 and 4-7 are presented in Table 4-2.
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
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. 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 Ib/MMBtu for ND heaters and 0.197 Ib/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.
4-21
-------
TABLE 4-2. AVERAGE UNCONTROLLED NO EMISSIONS FROM REFINERY
PROCESS HEATERS BASED ON EMISSION DATA FROM API24 (Ib/MMBtu)
Fuel
Gaseous
Distillate oilc
Residual oild
Natural drafta
0.14
0.20
0.42
Mechanical draftb
0.26
0.32
0.54
aUsing ambient combustion air.
•'Using air preheated to 200°C (390°F) , on average.
GFuel nitrogen content of 0.04 percent.
0.06 Ib/MMBtu to total uncontrolled emissions.
^Fuel nitrogen content of 0.29 percent. Fuel NOX
0.28 Ib/MMBtu to total uncontrolled emissions.
Fuel NOX contributes
contributes
4-22
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TABLE 4-3. AVERAGE UNCONTROLLED NO EMISSIONS FROM PROCESS
HEATERS AT ONE REFINERY INSTALLATION25
Fuel
Gaseous
NOX emissions, Ib/MMBtu
Natural draft3
No. of
heaters
32
Range
.064- .011
Average
.098
Mechanical draft"
No. of
heaters
26
Range
.062 - .323
Average
.197
aUsing ambient combustion air.
air preheated to 310°C (595°F), on average.
4-24
-------
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 Ib/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 Ib/MMBtu
range for natural gas.27 A second source indicated that
controlled burner tests showed increases in uncontrolled NOV
Jv
emissions for high-hydrogen refinery gas fuel ranging from 15 to
9 ft
20 percent over natural gas-fired emission levels. ° These
estimates indicate that uncontrolled NOX emission rates range
from 0.150 to 0.210 Ib/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. Figure 4-9 presents a graphical representation of the
heat rates of the ND heaters in Figure 4-8. Several natural
4-25
-------
TABLE 4-4. MODEL HEATERS AND UNCONTROLLED NO EMISSION FACTORS:
NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE ND
WITHOUT PREHEAT25
Model heater
capacity,
MMBtu/hr
17
36
77
121
185
Size range,
MMBtu/hr
x < 20
20 < X < 50
50 < X <. 100
100 < X < 150
^50 < X
No. of
burners
4
7
8
19
29
Uncontrolled
NO emission
factors,
Ib/MMBtu
0.098
0.098
0.098
0.098
0.098
TABLE 4-5. MODEL HEATERS AND UNCONTROLLED NO EMISSION FACTORS
NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE MD
WITH PREHEAT25
Model heater
capacity,
MMBtu/hr
40
77
114
174
263
Size range,
MMBtu/hr
x < 50
50 < x <. 100
100 < X < 150
150 < X < 200
200 < X
No. of burners
6
16
34
31
20
Uncontrolled
NOX emission
factors,
Ib/MMBtu
0.197
0.197
0.197
0.197
0.197
4-26
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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
Ib/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 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 Ib/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
4-28
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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 NO., and a fuel NO..
Jt JC
factor are presented in Tables 4-6 and 4-7 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 NOV emission factor is 0.140 Ib/MMBtu
.A.
for both distillate and residual oil firing. Fuel NOX factors
were calculated as the difference between the uncontrolled NCLr
A.
factors in Table 4-2 for gaseous and oil fuels, and are 0.060 and
0.280 Ib/MMBtu for distillate and residual oil firing,
respectively. For the oil-fired MD with preheat heaters the
uncontrolled thermal NOY emission factor is 0.260 Ib/MMBtu for
.A.
both distillate and residual oil firing. Fuel NOY factors are
Jt
0.060 and 0.280 Ib/MMBtu for distillate and residual oil firing,
respectively.
Table 4-8 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 furna-ce is 0.135 Ib/MMBtu, which is the average of the
0.130 to 0.140 Ib/MMBtu range discussed in Section 4.3.1. The
uncontrolled NO., emission factor for the high-hydrogen gas-fired
J\.
pyrolysis model furnace is 0.162 Ib/MMBtu, which is 20 percent
higher than the natural gas-fired pyrolysis model furnace.
4-30
-------
TABLE 4-6. MODEL HEATERS AND UNCONTROLLED EMISSION
FACTORS: DISTILLATE AND RESIDUAL OIL-FIRED, LOW-
AND MEDIUM-TEMPERATURE ND WITHOUT PREHEAT24
Model heater
capacity, MMBtu/hr
69
69
Fuel
Distillate oila
Residual oil"
No. of
burners
24
24
Uncontrolled NOX
emission factor,
Ib/MMBtu
Thermal
NOX
0.140
0.140
Fuel NOX
0.060
0.280
10.04 percent N
30.29 percent N
TABLE 4-7. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS:
DISTILLATE AND RESIDUAL OIL-FIRED, LOW- AND MEDIUM-
TEMPERATURE MD WITH PREHEAT24
Model heater
capacity, MMBtu/hr
135
135
Fuel
Distillate oila
Residual oilb
No. of
burners
14
14
Uncontrolled NOX
emission factor,
Ib/MMBtu
Thermal
NOX
0.26
0.26
Fuel NOX
0.060
0.280
a0.04 percent N
b0.29 percent N
4-31
-------
TABLE 4-8. MODEL HEATERS AND UNCONTROLLED EMISSION FACTORS:
NATURAL GAS-FIRED AND HIGH-HYDROGEN FUEL GAS-FIRED
OLEFINS PYROLYSIS FURNACES28
Model heater capacity,
MMBtu/hr
84
84
Fuel
Natural gas
High- hydrogen
fuel gas
No. of
burners
24
24
Uncontrolled NOX
emission factor,
Ib/MMBtu
0.135
0.162
4-32
-------
4.4 REFERENCES FOR CHAPTER 4
1. Shareef, S. A., C. L. Anderson, and L. E. Keller (Radian
Corporation). Fired Heaters: Nitrogen Oxides Emissions and
Controls. Prepared for U. S. Environmental Protection
Agency. Research Triangle Park, NC. EPA Contract
No. 68-02-4286. June 1988. pp. 42-48.
2. Control Techniques for NOX Emissions from Stationary
Sources - Revised Second Edition. U. S. Environmental
Protection Agency. Research Triangle Park, NC. Publication
No. EPA-450/3-83-002. January 1983. p. 2-1.
3. Standard Support and Environmental Impact Statement
Volume 2: Proposed Standards of Performance for Stationary
Gas Turbines. U. S. Environmental Protection Agency.
Research Triangle Park, NC. Publication
No. EPA-450/2-77-017a. September 1977. pp. 3-71 to 3-73.
4. Letter from Nichols, K., Chemical Recovery Group, to
Safriet, D.; EPA/ISB. January 9, 1992. NOX emissions from
recovery furnaces.
5. Newman, C. R. (GCA Corporation). Assessment of NOX Emission
Factors For Direct-Fired Heaters. Prepared for U. S.
Environmental Protection Agency. Research Triangle Park,
NC. EPA Contract No. 68-02-2693. January 1984. pp. 16-19.
6. Reference 2, p. 3-4.
7. Campbell, L. M., D. K. Stone, and G. S. Shareef (Radian
Corporation). Sourcebook: NOX Control Technology Data.
Prepared for U. S. Environmental Protection Agency.
Research Triangle Park, NC. EPA-600/2-91-029. July 1991.
8. Letter and attachments from Pam, R., Alzeta Corporation, to
Neuffer, W., EPA/ISB. September 2, 1992. Comments on Draft
Alternative Control Techniques Document--Control of NOX
Emissions from Process Heaters.
9. Reference 7, p. 5.
10. Malte, P. C. Perspective on NOX Formation and Control for
Gas Turbine Engines. University of Washington (Seattle, WA)
and Energy International (Bellevue, WA). Presented at
General Electric Research Center. Schenectady, NY.
October 10, 1988. 46 pp.
11. Reference 1, pp. 48-52.
12. Martin, R. R. Burner Design Parameters for Flue Gas NOX
Control. John Zink Company. Tulsa, Oklahoma. Undated.
39 pp.
4-33
-------
13. Reference 5, p. 20.
14. Reference 1, pp. 57-59.
15. Reference 1, pp. 53-56.
16. Letter and attachments from Eichamer, P., Exxon Chemical
Company, to Neuffer, W., EPA/ISB. September 2, 1992.
Comments on Draft Alternative Control Techniques Document--
Control of NOX Emissions from Process Heaters.
17. Reference 1, pp. 18-19.
18. Letter and attachments from Pam, R., Alzeta Corporation, to
Lyons, J., MRI. February 26, 1992. Alzeta product
literature.
19. Energy Section, Strategy Assessment Branch, Stationary
Source Division Air resources Board and Rule Development
Division, South Coast Air Quality Management District. A
Suggested Control Measure for the Control of Emissions of
Oxides of Nitrogen from Industrial, Institutional, and
Commercial Boilers, Steam Generators and Process Heaters.
Prepared for the Statewide Technical Review Group.
Sacramento, CA. April 29, 1987. p. 51.
20. Letter and attachments from Martin, R., Aztec Environmental
and Combustion Engineers, to Neuffer, W., EPA/ISB.
January 26, 1993. Comments on Draft Alternative Control
Techniques Document--Control of NOX Emissions from Process
Heaters.
21. Padgett Process Services Ltd. A Study to Assess the
Available Technology and Associated Costs of Reducing N0.x
Emissions from the Canadian Petroleum Refining Industry.'
Prepared for Canadian Petroleum Products Institute.
Toronto, Canada. CPPI Report No. 91-1. November 28, 1990.
p. 56.
22. Reference 1, p. 44.
23. Compilation of Air Pollutant Emission Factors Volume 1:
Stationary.Point and Area Sources, Fourth Edition (AP-42).
U. S. Environmental Protection Agency. Research Triangle
Park, NC. October 1986. pp. 1.3-2, 1.4-2.
24. Hunter, S. C., and S. S. Cherry (KVB-A Research-Cottrell
Company). NOX Emissions from Petroleum Industry Operations
Prepared for the American Petroleum Institute. Washington,
D.C. API Publication No. 4331. October 1979. pp. 27-30.
4-34
-------
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.
26. Letter from Eichamer, P. D., and N. L. Morrow, Exxon
Chemical Company, to Neuffer, W. J., EPA/ISB. June 7, 1993.
Pyrolysis furnace NOV emission rates.
Jt
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 NO emission rates.
4-35
-------
5.0 NOY CONTROL TECHNIQUES
Jt
In this chapter, NO., control techniques for process heaters
Jv
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 NOY control techniques as applied to
JV
model process heaters. References for Chapter 5 are presented in
Section 5.6.
5.1 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 NOY formation
J^
by either reducing available oxygen or providing excess oxygen to
cool the combustion process. Combustion air preheat is often
used in process heaters to improve thermal efficiency. Because
preheated combustion air increases combustion temperatures,
thermal NOX formation is increased. Combustion air preheat is
discussed in Section 5.1.2. Staged combustion incorporating air
lancing is discussed in Section 5.1.3. The technique of staging
5-1
-------
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 (FOR) 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.
5.1.1 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 (02) 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
5-2
-------
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 02
for a particular heater depends on draft type, fuel type, burner
type, and degree of combustion air preheat. Optimal excess 02
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.
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 02 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 02 levels when stack 02 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 02 to 2 percent 02 would result in a
32 percent reduction in NOX emissions. Current experience for
one source is that NOX reductions of 6 percent are achieved for
every one percent reduction in excess 02. This ratio is lower
than the 9:1 NOX reduction ratio discussed above and probably
reflects recent improvements in heater and burner designs with
reduced excess air levels.
Current practice is to control excess air to improve heater
efficiency. However, retrofitting older heaters that lack LEA
equipment may require a large capital investment to achieve
5-3
-------
optimal excess air operation.5 Excess 02 levels of approximately
2 to 4 percent appear to provide the best balance of maximum
heater thermal efficiency and NOY and CO emission reductions.
Jv
Appendix A presents a refinery process heater inventory and
suggests that excess air is already maintained at or near optimal
conditions. As discussed earlier, 02 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.
5.1.2 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
260°C (500°F). 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.
Figure 5-1 illustrates the typical relationship between
combustion air preheat and NOX emissions. An increase in air
preheat from ambient to 260°C (500°F) 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.
5.1.3 Use of Air Lances to Achieve Staged Combustion
Early efforts to stage combustion used air lances to
separate the combustion process and limit NOX formation. In the
5-4
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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
emissions reported in References 2 and 3 is presented in
Table 5-l.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.
5-6
-------
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5-7
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TABLE 5-1. CONTROLLED EMISSIONS FOR STAGED COMBUSTION
USING AIR LANCES2'3
Fuel
Refinery gas
Refinery gas
Residual oil and
refinery gas
Residual oil and
refinery gas
Uncontrolled NOX emissions
ppmv3
138
125
265
214
Ib/MMBtu
0.165
0.243
0.334
0.270
NOX
reduction,
percent
12
71
25
53
Controlled NOX emissions
ppmva
121
36.3
199
101
Ib/MMBtu
0.144
0.043
0.251
0.127
aAt 3 percent
5-8
-------
5.1.4 Staged-Air. Low-NO.. Burners
-^ ~ ^™" jt
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 (LNB's) are usually larger than
conventional burners and generally require extensive retrofitting
operations. Emission reductions achieved by staged-air LNB's
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. The emissions are presented for ND and MD gas-,
distillate oil-, and residual oil-fired heaters. The
uncontrolled emissions range from 0.14 Ib/MMBtu for ND gas-fired
heaters to 0.42 Ib/MMBtu for MD residual oil-fired heaters. The
controlled emissions range from 0.084 Ib/MMBtu for ND gas-fired
heaters to 0.318 Ib/MMBtu for MD residual oil-fired heaters.
Table 5-3 presents several staged-air burners and estimated
performance. For heavy fuel oil (HFO) firing (0.3 percent
N content), staged-air LNB's produce about 250 ppmv of NOX at
3 percent 02 (0.315 Ib/MMBtu). This reflects approximately a
40 percent reduction in NOV emissions from conventional burners.
.A.
For gas fuels, staged-air LNB's produce a lower bound of
approximately 80 to 100 ppmv N02 at 3 percent 02 (0.096 to
0.119 Ib/MMBtu) with 260°C (500°F) 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, 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 02 mix/react more by
diffusion than by turbulent mixing. This technique maximizes the
time during which fuel burns in substoichiometric conditions.
5-9
-------
TABLE 5-2. CONTROLLED EMISSION LEVELS FOR STAGED-AIR LNB'S
Fuel
Gas
Distillate oil
Residua] oil
Gas
Distillate oil
Residual oil
Draft type
ND
ND
ND
MD
MD
MD
Uncontrolled NOX emission
factors
ppma
111
159
333
206
254
421
Ib/MMBtu
0.14
0.20
0.42
0.26
0.32
0.53
Controlled NO. emission
levels^
ppma
66.6
95.2
200
124
152
253
Ib/MMBtu
0.084
0.120
0.250
0.156
0. 195
0.318
a@3 percent C>2
^Controlled emissions based on a 40 percent reduction.
5-10
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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 02 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 NO...
Jt
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 LNB's 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 LNB's
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
5-13
-------
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 LNB's 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 02 control, and LNB's. The benefits of such a retrofit:
are:
1. Improved flame definition relative to an ND heater with
LNB's;
2. Reduced excess air, resulting in energy savings; and
For MD process heaters, an effective LNB retrofit would involve
installing both excess 02 control and LNB's.
Another limitation on LNB applications is the existing
burner design heat release rate. Most LNB's 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.
5-14
-------
5.1.5 Staged-Fuel Low-NO.. Burners
Jt
Staged-fuel LNB's were more recently developed than staged-
air LNB's. Designed for gas firing, staged-fuel LNB's 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. 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 02 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
02 mix/react by diffusion rather than turbulent mixing and
substoichiometric reducing conditions are maximized.
For gaseous fuels that do not contain fuel-bound nitrogen,
NOY reduction performance from fuel staging is better than that
Jv
from air staging. The low-temperature/high-02 conditions of the
staged-fuel LNB have a stronger effect on thermal NOX reduction
than do the high-temperature/low-02 conditions of the staged-air
LNB.7
Staged-fuel LNB's have several advantages over staged-air
LNB's. 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 LNB's have a more compact flame than
staged-air LNB's.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.
5-15
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SECONDARY COMBUSTION
HIGH AIR TO FUEL
RATIO IN PRIMARY ZONE
SECONDARY FUEL
COMBUSTION
AIR.
SECONDARY FUEL
CONNECTION
PRIMARY FUEL
CONNECTION
Figure 5-4. Schematic of a staged-fuel low-NOx burner.1
5-16
-------
Reductions in NOX emissions of up to 72 percent have been
reported over conventional burners based on vendor test data for
staged-fuel LNB's.1 The average reduction is approximately
60 percent.1'7'9'12 Table 5-4 presents controlled NOX emission
levels for several staged-fuel LNB's. The controlled emissions
ranged from 40 to 50 ppmv at 3 percent 02 (0.048 to
0.060 Ib/MMBtu); uncontrolled emission levels, and therefore
percent reductions, were not available.7 Table 5-5 presents
controlled emission levels for gas-fired heaters using
uncontrolled emission factors from Table 4-3 and a 60 percent
reduction. The controlled NOV emission levels are 0.056 and
JV
0.104 Ib/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 NOV emissions than gas-only fuels. The data in
J\.
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.
5.1.6 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
5-17
-------
TABLE 5-4. STAGED-FUEL LOW-NO BURNER CONTROLLED
NOV EMISSION LEVELS7
Burner name
John Zink SFGa
John Zink SFGa
McGill SRGRa-b
Callidus CSGC
Heater draft
NDd
MD (500°F preheat)
NDd
MD (500°F preheat)
NDd
MDd
NDd
MD (preheat)6
Fuel
Gas
Gas
Combination
Combination*
Refinery gas
50 percent ^
Refinery gas
50 percent H^
NG
NG
Controlled NOX emissions
o h
ppmvS'"
40 to 50
40 to 50
40
50
45
45
60% reduction
60% reduction
Ib/MMBtu
0.048 to 0.060
0.048 to 0.060
NA
NA
0.054
0.054
60% reduction
60% reduction
aReference 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.
^McGi!! has been purchased by John Zink Company. McGill burners are no longer available, but replacements
can be obtained from the John Zink Company.
cReference 9 Vendor names are included only to identify the burner type. Other vendors may offer similar
burner types.
^Combustion air at ambient conditions.
ePreheat temperature is not known.
^Combination of oil and gas fuels.
3 percent O2-
"Percent reductions were not available for all burners.
NA = Not available.
5-18
-------
TABLE 5-5. CONTROLLED NOX EMISSION LEVELS FOR STAGED-FUEL
LOW-NO^ BURNERS3
Draft type
ND
MD
Uncontrolled NOX
emissions
pprmr-1
117
218
Ib/MMBtu
0.14
0.26
Controlled NOX
emissions0
ppmvk
47
87
Ib/MMBtu
0.056
0.104
f-Gas firing.
bAt 3 percent 02.
cControlled emissions based on a 60 percent reduction.
5-19
-------
local oxygen concentrations, thereby inhibiting thermal NOV
J\.
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 tc
have only a small effect on fuel NOX formation, FGR may not be as
effective on oil-fired heaters as on gas-fired heaters.
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, 620°C
(1150°F) 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 Ib/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 02 (0.036 Ib/MMBtu) have been achieved.13
This system incorporates LNB's 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 LNB's.7 Also, based on
boiler data, FGR used with standard burners on process heaters is
expected to reduce NOX emission levels 30 percent.7
5-20
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5.1.7 Ultra-Low N0_c_ 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, 02-depleted
flue gas from the flame or firebox back into the combustion zone.
This reduces the average 02 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 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 02 concentrations in the flame have a strong impact
on fuel NO.., so IFGR burners are an effective NO., control
J\. -A.
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 ULNB's are capable of
achieving lower NOX emission levels than LNB's. Emission levels
for NOX reported by one refinery using ULNB's, 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 1250°C (2280°F). 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 02 (0.066 lb/MMBtu) at 273°C (524°F) 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
5-21
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5-22
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reductions of 5 to 10 ppmv appear achievable with approximately
0.12 Ib steam/lb fuel injection.17
Refinery retrofit experience shows an average reduction
efficiency of 75 percent thermal NOX reduction for ULNB's.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 ULNB's.7 Therefore, the reduction
efficiencies used in this study for ULNB's 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
NOY.
J\,
Retrofit problems with ULNB's 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 ULNB's 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.
5.1.8 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 980°C (1800°F).7 Thermal NOX formation is
reduced since this temperature is approximately 1000°C (1830°F)
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.1** This
5-23
-------
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 02 (0.024 to 0.030 Ib/MMBtu)
of NOX.18'19 Table 5-6 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 02 (0.024 Ib/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 02
to 15.7 ppmv at 3 percent 02 (0.0 to 0.019 Ib/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.
5.2 SELECTIVE NONCATALYTIC REDUCTION
Selective noncatalytic reduction (SNCR) involves the direct
injection of a NO..-.reducing chemicals into the hot flue gas. At
Jt
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
5-24
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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 1100°C (2000°F).
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 1100°C
(2000°F) 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.2^
5-26
-------
Ammonia slip can also cause ammonium sulfate [(NH4)2S04]
deposits in the convection section. These deposits can occur if
sulfur trioxide (S03) is present in the flue gas.7
Postcombustion controls such as SNCR may be used as the sole
NOV control technique or in combination with LNB's. Potential
Jt
NOX reduction efficiency for SNCR is approximately 70 percent,
but controlled emission levels at existing installations show
similar NOX reductions for either SNCR or LNB's plus SNCR. This
is likely because the controlled emission levels reflect permit
requirements. It is expected that achievable NC- reductions
Jt
using LNB's 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 NC-
Jt
emissions will have a higher reduction efficiency than an SNCR "
used on a heater with relatively low uncontrolled NO,, emissions.
A.
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
®
5.2.1 Exxon Thermal DeNO.. (Ammonia Injection)
®
Thermal DeNOx (TDN), developed by Exxon, is an add-on NOX
control technique that reduces NOX to N2 and water (H20) without
the use of a catalyst. Figure 5-6 shows a process flow diagram
for 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-lfl ratio, and Equation 2 shows the reaction with
a 2:1 ratio.
2NO + 2NH3 + 202 •* 2N2 + 3H20 (1)
2NO + 4NH3 + 202 -» 3N2 + 6H20 (2)
5-27
-------
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5-28
-------
Using a 2:1 injection ratio, the NH3 and NOX react according to
the following competing reactions:1
2NO + 4NH, + 209 •* 3N9 + 6H90
J £ £ £t
4NH3 + 502 •* 4NO + 6H20
®
5.2.1.1 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
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 1100°C
[2000°F]). The allowable temperature "window" for the reaction
to proceed is 870° to 1100°C (1600° to 2000°F).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 760° to 700°C (1400° to
1300°F) .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
5-29
-------
TABLE 5-7. PARTIAL LIST OF EXXON'S THERMAL
DeNOv INSTALLATIONS7'24
Installation
date
1975
1975
1977
1977
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1980
1981
1981
1982
1982
1982
1982
1981
1985
1991
Fuel
Gas
Gas/oil
Gas/oil
Gas/oil
Gas/oil
Gas/oil
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
NA
NA
NA
NA
NA
NA - "
Gas
Gas
Oil
Size, MW
(MMBtu/hr)
151 (515)
57 (190)
73 (250)
73 (250)
12 (41)
13 (44)
31 (105)
4(13)
19 (65)
14 (49)
38 (130)
8(27)
4(13)
6(19)
10 (35)
22 (74)
9(32)
7(25)
30 (102)
7(25)
49 (167)
9(32)
4(15)
27 (92)
8(28)
7(23)
7(23)
38(131)
92 (315)
7(23)
Uncontrolled
NOX, ppmv at
3 percent Q-f
130
130
79
85
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
80-165
100-150
100-150
100-150
100-150
120
120
80-125
80-125
80-125
80-125
75
144
70
Controlled
NOX, ppmv at
3 percent O2a
48
48
39
40
40-83
28-58
38-78
40-83
31-64
40-83
48-99
40-83
54-111
48-99
27-56
28-58
36-90
50-75
50-75
50-75
50-75
65
42
NA
NA
NA
NA
38
45
40
Percent
reduction
63
6.3
51
53
50
6:5
53
50
61
50
40
50
33
40
66
6:5
5:5
50
50
50
70
45
65
30-60
30-60
30-60
30-60
49
69
43
aNOx (Ib/MMBtu) = NOX (ppmv @ 3% O2) * 0.001194 for gas.
NOX (Ib/MMBtu) = NOX (ppmv @ 3% O2) * 0.001260 for oil.
NA = Not available
5-30
-------
expensive and should be acceptable when used with adequate
safeguards.
®
5.2.1.2 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 870° to 1200°C (1600° to 2200°F), resulting
in a reduction of NOX.8 The temperature range can be lowered to
760° (1400°F) by adding H2, a readily oxidizable gas, to the
reactant.5 Below 760°C (1400°F), neither reaction is of
sufficient activity to either produce or destroy NOX; the result
will be unreacted NH3, or NH3 slip. Above 1200°C (2200°F), 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 NO., reduction reaction to occur. Design considerations
J^
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)2S03 and a visible NH3 stack plume.1 The
5-31
-------
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
®
5.2.1.3 NOX Reduction Efficiency Using Thermal DeNOx .
Data in Table 5-7 indicate that 30 to 75 percent of the NC» in
®
the flue gas can be removed with the Thermal DeNO^. process.
J\.
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
®
5.2.1.4 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
5.2.2 Nalco Fuel Tech NO^OUT® (Urea Injection)
In the early "1980's, the Electric Power Research Institute
(EPRI) developed a urea-(CO(NH2)2) based SNCR process with an
870° to 1100°C (1600° to 2000°F) 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
5-32
-------
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.
5.2.2.1 Process Description (NC^Ol^r®) . Figure 5-7 shows a
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, H20, and C02. The desired chemical
reaction is:
CO(NH2)2 + 2 NO + 1/2 02 •* 2 N2 + C02 + H20
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 NO., reduction and
J\-
to speed the reaction kinetics. This can result in some NH^
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 870°C (1600°F)
to as low as 650°C (1200°F) 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
5-33
-------
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5-34
-------
large variations in firebox temperature. If the firebox
temperature is over 600°C (1110°F), 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 NHj.7 However, Nalco Fuel Tech indicates that the number of
injection nozzles will be less than for NH^ injection.2^ For
either NHj- 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.
5.2.2.2 Factors Affecting NCL.OUT® Performance^ As with
Jv
ammonia injection, the primary factor that influences the
reduction reaction rate is temperature. The temperature window
for efficient reduction is 870° to 1150°C (1600° to 2100°F),
although H2 and CO injection have been shown to lower the
temperature window. Residence time and the mixing of the
urea-based reagent and NO., also influence the reduction reaction.
»
The molar ratio of-.urea to NOV is similar to the Thermal DeNO..
Jv Jt
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
5-35
-------
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
NO..OUT® performance and the selection of additives.25'27
A.
5.2.2.3 NO,. Emission Reduction Efficiency Using NO..OUTg>.
Jt Jt
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.2° 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.
5.2.2.4 Ammonia Slip Considerations for NOXOUT®. Unreacted
urea results in NH^ slip in a manner similar to ammonia slip from
the Thermal DeNOv process. Slippages of 10 to 20 ppmv have been
Jt
reported.7'8
5.3 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 230° to 600°C (500° to 1100°F),
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
5-36
-------
TABLE 5-8. NALCO FUEL TECH NO OUT® PROCESS
HEATER APPLICATIONS23
Capacity,
MMBtu/hr
177
50
NA
NA
Baseline emissions
ppma
38-50
65
90
30-50
Ib/MMBtu
0.045-0.060
0.078
0.107
0.038-0.063
Reduction
guaranteed by
vendor, percent
35-60
50-75
55
10
Controlled emissions
ppma
15.2-32.5
16.3-32.5
40.5
27-45
(Ib/MMBtu
0.018-0.039
0.020-0.039
0.048
0.034-0.057
aAt 3 percent excess
NA = Not available.
5-37
-------
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 NC>
J*L
reduction techniques.
5.3.1 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 H20.7'8 The major reactions that occur in the
presence of the catalyst are the following:
6NO + 4NH3 -» 5N2 + 6H20
2NO + 4NH3 + 202 •* 3N + 6H20
Figure 5-8 shows major components and control systems
associated with an SCR retrofit using a horizontal reactor.
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
5-38
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5-39
-------
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
5.3.2 Factors Affecting SCR Performance
The reaction of NH3 and NOX is favored by the presence of
excess 02 (air-rich conditions), but the primary variable
affecting NOX reduction is temperature. Optimum NOX reduction
occurs at catalyst bed temperatures of 320° to 400°C (600°F to
750°F) for conventional (vanadium- or titanium-based) catalyst
types and 243° to 265°C (470° to 510°F) 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 given catalyst exhibits optimum performance
within ±10°C (±50°F) of its design temperature for applications
in which flue gas 02 concentrations are greater than 1 percent.
Below this optimum temperature range, the catalyst activity is
greatly reduced, allowing unreacted NH-j to slip through. Above
450°C (850°F), 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 450°C (850°F). It is important, therefore, to have stable
5-40
-------
100.
60-
40-
20-
Vtfoety • 10,0001/h
• lOOppm
200
I I
250 900
I I I
380 400 480 100
Figure 5-9. Effect of temperature and oxygen on NO conversion.
5-41
-------
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 irange
of 320° to 600°C (600° to 1130°F), with the optimum temperature
range stated as 360° to 580°C (675° to 1080°F).7 In some zeolite
catalyst formulations, NH^ oxidation to NOX begins at around
450°C (850°F) and is predominant at temperatures in excess of
520°C (960°F).7 A gas turbine zeolite catalyst installation is
reported to be operating in the temperature range of 500° to
520°C (930° to 960°F).1:L The performance is reported to be
80 percent NOX reduction with NH3 slip limit of 20 ppmv at
15 percent 02 (61 ppmv at 3 percent 02)-11 No process heater
data were available. Although within the operating range, the
zeolite structure may be irreversibly degraded at around 550CC
(1020°F) due to loss of pore density. Zeolites suffer the sajne
performance and potential damage problems as conventional
catalysts when used outside their optimum temperature range.
With zeolite catalysts, the NOY reduction reaction takes
Jt
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
(S02)/S03 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
5-42
-------
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
1 TO
emissions.''^°
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 S02 present to
S03.7 Conversion of S02 to S03, 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 S02-to-
S03.28 Catalyst formulations with less than one percent S02-to-
S03 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 S02-to-S03 conversion rate of about 1 percent.7
5.3.3 NO.^ 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 NO., reduction is achieved with a
.A.
NH3 slip of less than 10 ppmv.7
Selective catalytic reduction is usually used in combination
with LNB's. Table 5-9 presents a summary of data from the Mobile
Oil refinery in Torrance, California (Appendix C),14 These data
5-43
-------
TABLE 5-9. CONTROLLED EMISSION FACTORS FOR SCR
ADDED TO HEATERS WITH LNB'S14
Heater
capacity,
MMBtu/hr
457
161
288
220
Baseline emission factor
ppmv*
46.9
64.5
73.7
83.8
Ib/MMBtu
0.056
0.077
0.088
0.100
Reduction,
percent
64.3
74.1
77.2
80.0
Controlled emission level
ppmv8
16.8
16.8
16.8
16.8
Ib/MMBtu
0.020
0.020
0.020
0.020
at 3 percent
5-44
-------
demonstrate reductions achieved by adding SCR to heaters with
existing LNB's. The reductions using SCR range from 64.3 to
80 percent. The controlled emissions range from 16.8 to 42 ppmv
at 3 percent 02 (0.020 to 0.050 Ib/MMBtu). The average emission
reduction for these data is 75 percent, and the average
controlled emission level is 16.8 ppmv at 3 percent 02
(0.020 Ib/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 02
concentrations. Each reported excess 02 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
O Q
maintaining NH^ slip concentrations below 5 ppmv. °
Selective catalytic reduction can be used as a process
heater NOX control technique in combination with MD LNB's 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 NOY controls,
J\.
postretrofit NOV controls and controlled emissions) than the data
Jt
in Appendix D. Therefore, Appendix C data are used as the basis
for SCR performance. For the purposes of this study, the NOV
Jt
reduction efficiency for SCR used as the sole control technique
is 75 percent. For natural gas-fired model heaters using LNB's
plus SCR, the thermal NO., reduction by LNB's is 50 percent and
Jt
the postcombustion NOX reduction by the SCR is 75 percent. The
5-45
-------
total effective reduction for natural gas-fired model heaters
using LNB's plus SCR is therefore 88 percent. For oil-fired
model heaters using LNB's plus SCR, the thermal NOX reduction by
LNB's is 50 percent, the fuel NOX reduction by the LNB's 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 LNB's 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 LNB's plus SCR are therefore 92 and 91 for distillate and
residual oil-firing, respectively.
5.4 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 1050° to 1250°C
(1900° to 2300°F), and most designs use the vertical box heater
configuration. As shown in Table 5-10, pyrolysis furnaces use
approximately 50 percent of the energy requirements of major
fired heater applications in the chemical industries.^
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, LNB's and ULNB's
are used in olefins pyrolysis furnaces.
Selective noncatalytic reduction retrofit requires
considerable convection section reconstruction to allow multiple
5-46
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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
(150° to 230°C [300° to 450°F]) 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 e.
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
5-48
-------
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 NOV emissions have been achieved with LNB and
Jt
ULNB's in olefins pyrolysis furnaces. The achievable NOX
emission reductions using LNB's and ULNB's, 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. 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 LNB's and ULNB's. Because an
extended combustion zone is already implemented in existing
pyrolysis burner designs, potential NOX reduction percentages
using LNB's and ULNB's in pyrolysis furnaces are lower than for
low- and medium-temperature process heater applications.
Information for two new installations and several retrofit
applications of LNB's to pyrolysis furnaces was available. The
NOX emission rates for the new furnaces using LNB's were 0.103
and 0.108 Ib/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 Ib/MMBtu for natural gas-fired operation.33 The available
5-49
-------
data and information suggest that achievable controlled NOV
X
emission levels for LNB's used with natural gas-fired pyrolysis
furnaces range from 0.10 to 0.011 Ib/MMBtu, which represents a 15
to 30 percent reduction from the uncontrolled range of 0.13 to
0.14 Ib/MMBtu. For pyrolysis model heaters with LNB's, a
25 percent NOX reduction from uncontrolled levels is used in this
study for natural gas-and refinery gas-fired applications.
For ULNB's installed in pyrolysis furnaces, one source
reported that controlled NCX, emission rates for retrofit
Jt
installations are expected to range from 0.06 to 0.07 Ib/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 Ib/MMBtu. For
pyrolysis model heaters with ULNB's, a 50 percent NOV reduction
./*»
from uncontrolled levels is used in this study for natural gas-
and refinery gas-fired applications. Applying Exxon's
proprietary ULNB's (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 Cu are
achievable. 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 LBN's and no appreciable
increase in NOV emissions for hydrogen fuels for ULNB's.35
Jv
5.5 ACHIEVABLE NOV EMISSION REDUCTIONS
Jt
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 LNB's,
ULNB's, SNCR, SCR, LNB's + FGR, LNB's + SNCR, and LNB's + SCR.
5-50
-------
Natural to mechanical draft conversion and LEA operation are not
considered stand alone NO... control techniques in this study
Jt
because they are currently considered operational techniques.
However, the difference in NO., emissions and the degree of
Jx.
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 LNB's
are collectively referred to as LNB's. Low-N0x burners have
replaced staged combustion using air lances as current burner
technology. Therefore, staged combustion using air lances is not
considered further.
To develop NOY emission reductions, each of the current
Jt
control techniques was applied to each of the model heaters
developed in Chapter 4. Tables 5-11 through 5-15 present
achievable NOV reductions, controlled emissions, and emission
J\.
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
5-51
-------
TABLE 5-11. MODEL HEATERS: CONTROLLED EMISSIONS FOR ND, NATURAL
GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS
Model heater
capacity,
MMBtu/yr
17
36
77
121
186
Uncon-
trolled NOX
emission
factor,
lb/MMBtua
0.098
0.098
0.098
0.098
0.098
NOX control technique
(ND) LNB
(ND) ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
(ND) LNB
(ND) ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
(ND) LNB
(ND) ULNB
(ND) SNCR
(ND) LNB + (ND) SCNR
(ND) LNB
(ND) ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
(ND) LNB
(ND) ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
Total effective
reduction,
percent
50b
75C
60d
80b'd
50b
75C
60d
80b'd
50b
75C
60d
80b'd
50b
75C
60d
80b'd
50b
75C
60d
80b'd
Controlled
NOX
emissions,
Ib/MMBtu
0.049
0.025
0.039
0.020
0.049
0.025
0.039
0.020
0.049
0.025
0.039
0.020
0.049
0.025
0.039
0.020
0.049
0.025
0.039
0.020
ControlledN
°*
emissions,
ppm @ 3%
09
41
21
33
16
41
21
33
16
41
21
33
16
41
21
33
16
41
21
33
16
NOj,
reduction,
ton/yre
3.65
5.47
4.38
5.84
7.73
11.6
9.27
12.3(.
16.5
24.8
19.8
26.4^.
26.0
39.0
31.2
41.55
39.9
60.0
47.9
63.87
Uncontrolled emissions for natural gas-fired heaters are from thermal NOX formation.
^Reductions from LNB's represent a 50 percent reduction of thermal NOX. This reduction was adopted from
Reference 5.
^Reductions from ULNB's represent a 75 percent reduction of thermal NOX. This reduction was adapted from
Reference 14.
dPostcombustion NOX reduction by SNCR is 60 percent. This reduction was adopted from Reference 7.
Deduction (tons/yr) equals the Capacity (MMBtu/hr) x NOX reduced (Ib NOx/MMBtu) x 1 ton per 2,000 1'b x
8,760 hr/yr; where NOX reduced is equal to uncontrolled emission factor minus the controlled emission factor.
5-52
-------
TABLE 5-12. MODEL HEATERS: CONTROLLED EMISSIONS FOR MD,
NATURAL GAS-FIRED, LOW- AND MEDIUM-TEMPERATURE HEATERS
Model heater
capacity,
MMBtu/hr
40
77
114
174
263
Uncon-
trolled NOX
emission
factor,
lb/MMBtua
0.197
0.197
0.197
0.197
0.197
NO control technique
(MD)LNB
(MD) ULNB
(MD) SNCR
(MD)SCR
(MD) LNB + FOR
(MD) LNB + SNCR
(MD) LNB -t- SCR*
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FGR
(MD) LNB + SNCR
(MD) LNB + SCR
Total effective
reduction,
percent
50"
75C
60"
75e
551
80D,o
ggD.e
50"
75C
60a
75e
55'
80b,d
88D'e
50°
75C
60°
75e
551
80D,a
88b-e
50"
75C
60a
75e
551
80b,d
88D,e
50D
75C
60°
75e
55T
80b,d
88"'e
Controlled
NOX
emissions,
Ib/MMBtu
0.099
0.049
0.079
0.049
0.089
0.039
0.025
0.099
0.049
0.079
0.049
0.089
0.039
0.025
0.099
0.049
0.079
0.049
0.089
0.039
0.025
0.099
0.049
0.079
0.049
0.089
0.039
0.025
0.099
0.049
0.079
0.049
0.089
0.039
0.025
Controlled NOX
emissions,
ppmv
@3% O2
82
41
643
41
74
33
21
82
41
66
41
74
33
21
82
41
66
41
74
33
21
82
41
66
41
74
33
21
82
41
66
41
74
33
21
NOX reduction,
tons/yi*
17.3
25.9
20.7
25.9
19.0
27.6
30.2
33.2
49.8
39.9
49.8
36.5
53.2
58.1
49.2
73.8
59.0
73.8
54.1
78.7
86.1
75.1
113
90.1
113
82.6
120
131
113
170
136
170
125
182
199
Uncontrolled emissions for natural gas-fired heaters are from thermal NOX formation.
''Reductions from LNB's represent a 50 percent reduction of thermal NOX. This reduction was adopted from
Reference 5.
Deductions from ULNB's represent a 75 percent reduction of thermal NOX. This reduction was adapted from
Reference 14.
"Postcombustion NOX reduction by SNCR is 60 percent. This reduction was adopted from Reference 7.
^Postcombustion NGL reduction by SCR is 75 percent. This reduction was adapted from Reference 14.
^Reductions from LNB + FGR represent a 55 percent reduction of thermal NOX. This reduction was ac
from Reference 7.
^Reduction (ton/yr) equals the Capacity (MMBtu/hr) * NO reduced (Ib NOx/MMBtu) * 1 ton per 2000 Ib
8,760 hr/yr; where NOX reduced is equal to the uncontrolled emission factor minus the controlled emission
factor.
adopted
5-53
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5-56
-------
amount of NOY remaining after reductions of combustion controls
Jt
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 Ib/MMBtu for LNB plus SCR to 0.072 Ib/MMBtu for LNB.
Table 5-12 presents the performance of the available control
techniques applied to the MD, natural gas-fired, low- and medium-
temperature model heaters. The controlled NOX emissions range
from 0.021 Ib/MMBtu for LNB's plus SCR to 0.089 Ib/MMBtu for
LNB's 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 Ib/MMBtu for ULNB's to
0.121 Ib/MMBtu for LNB's. The controlled NOX emissions for the
residual oil-fired model heater range from 0.097 Ib/MMBtu for
ULNB to 0.308 Ib/MMBtu for LNB's.
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 Ib/MMBtu for LNB's plus
SCR to 0.175 Ib/MMBtu for LNB's. The controlled NOX emissions
for the residual oil-fired model heater range from 0.051 Ib/MMBtu
for LNB's plus SCR to 0.319 Ib/MMBtu for LNB's plus FGR.
Table 5-15 presents the performance of the available control
techniques applied to the olefins pyrolysis model heaters. The
controlled NOX emissions for the natural gas-fired model heater
range from 0.026 Ib/MMBtu for LNB's plus SCR to 0.101 Ib/MMBtu
for LNB's. The controlled NOX emissions for the high-hydrogen
fuel-fired model heater range from 0.031 Ib/MMBtu for LNB's plus
SCR to 0.123 Ib/MMBtu for LNB's.
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
5-57
-------
percent emission reduction. For example, the use of LNB plus SCR
is likely capable of an overall NO., emissions reduction of over
Jv
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.
5.6 REFERENCES FOR CHAPTER 5
1. Shareef, A., C. Anderson, and L. Keller (Radian
Corporation). Fired Heaters: Nitrogen Oxides Emissions and
Controls. June 29, 1988.
2. Project Summary. Evaluation of Natural- and Forced-Draft
Staging Air Systems for Nitric Oxide Reduction in Refinery
Process Heaters. EPA- 600/S7- 84-080 . September 1984.
3. Project Summary. Guidelines for the Reduction of Emissions
& Efficiency Improvements for Refinery Process Heaters.
EPA-600/S8-83-017. June 1983.
4. Project Summary. Thirty-Day Field Test of a Refinery
Process Heater Equipped with Low-NO Burners.
EPA-600/S7-83-010. April 1983.
5. Letter and attachments from Eichamer, P., Exxon Chemical
Company, to Neuffer, W. , EPA/ISB. September 2, 1992.
Comments on Draft Alternative Control Techniques Document --
Control of NOV Emissions from Process Heaters .
J\.
6. Letter and attachments from Laffly, G., American Petroleum
Institute, to Neuffer, W. , EPA/ISB. August 10, 1992.
Comments on Draft Alternative Control Techniques Document- -
Control of NOV Emissions from Process Heaters.
J\.
7 . A Study to Assess the Available Technology and Associated
Costs of Reducing NO 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
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.
5-58
-------
11. Letter from Craig, R. Unocal Science and Technology
Division, to Lee, L., California Air Resources Board.
July 24, 1991. Information concerning NOX reduction in a
cogeneration facility.
12. Waibel, R. (John Zink Company). Advanced Burner Technology
for Stringent NOX Regulations. Presented at American
Petroleum Institute Midyear Refining Meeting. May 8, 1990.
13. Letter and attachments from Quiel, J., North American
Manufacturing Company, to Neuffer, W., EPA/ISB. May 1991.
Low NOX burner and FGR information from manufacturer.
14. Letter and attachments from Britt, J., Mobil Oil
Corporation, to Jordan, B., EPA/ESD. April 29, 1992.
Process heater NOX emission control retrofit experience at
Mobil's Torrance, CA, petroleum refinery.
15. Letter and attachments from Grever, A., Selas, to Neuffer,
W., EPA/ISB. December 29, 1992. Comments on Draft
Alternative Control Techniques Document--Control of NOX
Emissions from Process Heaters.
16. Letter and attachments from Davis, L., Exxon, Baton Rouge to
Harris, R. , MRI. February 7, 1992. Refinery Inventory of
Process Heaters.
17. Letter and attachments from Johnson, W., John Zink Company,
to Hamilton, R., Texas Air Control Board. December 5, 1990.
Meeting SCAQMD Rules 1109 and 1146 with Low-N0x Burners.
Presented by Waibel, R., PhD.
18. Minden, A., and P. Gilmore. NO 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.
21. Letter and attachments from Moreno, F., Alzeta Corporation,
to Sanderford, E., MRI.
Alzeta burners.
June 3, 1992. Control of NO using
22. Mclnnes, R., and M.B. Van Wormer.
Emissions. Chemical Engineering.
September 1990.
Cleaning Up NO
Vol. 130-135.
5-59
-------
23. Letter and attachments from Pickens, R., Nalco Fuel Tech, to
Neuffer, W., EPA/ISB. August 7, 1992. Comments on Draft
Alternative Control Techniques Document--Control of NOX
Emissions from Process Heaters.
24. Letter and attachments from Haas, G., Exxon Research and
Engineering Cgmpany, 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 NO^OUT® installations.
J\.
27. Letter and attachments from Strickland, G., Chemical
Manufacturers Association, to Neuffer, W., EPA/ISB.
September 9, 1992. Comments on Draft Alternative Control
Techniques Document--Control of NOX Emissions from Process
Heaters.
28. Letter and attachments from Wax, M., Institute of Clean Air
Companies, to Neuffer, W., EPA/ISB. August 27, 1992.
Comments on Draft Alternative Control Techniques Document--
Control of NOV Emissions from Process Heaters.
Jv
29. Letter and attachments from Franklin, H., Foster Wheeler
Energy Corporation, to Neuffer, W., EPA/ISB. April 27,
1992. Process heater SCR experience.
30. Comma H., L. Hackemesser, and D. Cindric. NO /CO Emissions
and Control in Ethylene Plants. Environmental" Progress.
rp_(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.
NOV reductions in pyrolysis furnaces using low-NO burners.
JC *»•
33. Letter from Eichamer, P. D., and N. L. Morrow, Exxon
Chemical Company, to Neuffer, W. J., EPA/ISB. June 7, 1993.
NO reductions in pyrolysis furnaces.
5-60
-------
34. Letter and attachments from Morrow, N. , Exxon Chemical
Group, to Harris, R., MRI. February 24, 1992. Low-N0x
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.
5-61
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6.0 CONTROL COSTS
This chapter presents capital and annual costs and cost
effectiveness for the NOV emission control techniques described
Jv
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 (LNB's), ultra low-NOx burners
(ULNB's), selective noncatalytic reduction (SNCR), selective
catalytic reduction (SCR), LNB's combined with flue gas
recirculation (FGR), LNB's combined with SNCR, and LNB's 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
i *?
heaters. ' 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 NOV control
Jt
techniques applied to the model heaters are presented in
Section 6.2. The cost effectiveness of the NOV control
J\.
techniques applied to the model heaters is presented in
Section 6.3. Radiant burner costs are discussed in Section 6.4;
radiant burners are not included in the model heater cost
6-1
-------
analysis due to limited costing information. Section 6.5 lists
the references used in this chapter.
6.1 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 TAG 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. Capital and
annual costs for LNB's, ULNB's, SNCR, SCR, FGR, LNB's plus SNCR,
and LNB's 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.
6.1.1 Costs of LNB's
6.1.1.1 Capital Costs of LNB's. The LNB capital cost
methodology from Reference 1 was used to calculate the capital
cost of applying LNB's 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.^
The capital cost methodology from Reference 1 for ND heaters is:
TIC = 30,000 + HQ [5,230 - (622 x BQ) + (26.1 x BQ2)]
6-2
-------
TABLE 6-1. UTILITY, CHEMICAL, AND MAINTENANCE COSTS
Electricity3
Natural gasb
Distillate fuel oilc
Residual fuel oilc
Ammonia
Maintenance6
$0.06/kWh
$2.00/MMBtu
$5.54/MMBtu
$3.00/MMBtu
$0.125/lb
2.75% of capital cost
^Reference 4
Reference 5
^Reference 6
^Reference 2
eReference 1
Table 5-10,
6-3
-------
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:
l. Increased LNB cost;
2. Additional excess air control equipment; and
3. Combustion air plenum modification.1
The capital cost methodology for MD LNB's 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
LNB's 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.^'9
6.1.1.2 Operating Costs of LNB's. Maintenance costs of
LNB's are calculated as 2.75 percent of the LNB's capital
costs.1'2 Installation of LNB's can improve heater efficiency,
although this effect (if any) will be strongly heater-dependent.
6-4
-------
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.
6.1.2 Cost of ULNB's
6.1.2.1 Capital Costs of ULNB's. The capital costs of
ULNB's are affected by the same parameters as LNB's. The primary
parameters that affect the capital costs include:
l. 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 ULNB's 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 ULNB's 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
escalated to U.S. average 1991 dollars using the Chemical
Engineering plant index and an exchange rate of 1 U.S. dollar to
1.15 Canadian dollars.3
Similar to LNB's, large cost variations for ULNB's retrofit
can exist. The cost variations and variables influencing the use
of LNB's described in Section 6.1.1.1 also apply to ULNB's.
6.1.2.2 Operating Costs of ULNB's. Maintenance costs of
ULNB's are calculated as 2.75 percent of the ULNB's capital
6-5
-------
costs.1'2 Operating costs for LNB's described in Section 6.1.1.2
also apply to ULNB's.
6.1.3 Costs of SNCR
6.1.3.1 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 DeNO. ®
.A.
(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)°'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.^
6.1.3.2 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."'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 arid
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
6-6
-------
The cost methodologies for the annual operating costs of
SNCR are:
NH3 cost = (Q) x (Ib NOx/MMBtu) x (l mole
N02/46 Ib N02) x (17 Ib 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.1'2'1*"1
6.1.4 Costs of SCR
6.1.4.1 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
dollars. For this analysis, capital costs have been escalated to
U.S. average 1991 dollars using the Chemical Engineering plant
index.
6.1.4.2 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,
6-7
-------
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 (Ib NOx/MMBtu) x (1 mole
NCU/46 Ib N09) x (17 Ib
f-t ^i
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
6.1.5 Costs of FGR
6.1.5.1 Capital Costs of FGR. The FGR capital cost
methodology from Reference 1 is used to calculate the capital
cost of installing an FGR system in process heaters. The capital
cost model for FGR from Reference 1 is:
TIC = 12,800 (HQ)0-6
where:
HQ = heater capacity, GJ/hr.1
The cost methodology gives cost in Canadian average
1990 dollars. For this analysis, the capital costs have been
escalated to U.S. average 1991 dollars using the Chemical
6-8
-------
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
LNB's. 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 LNB's, 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.
6.1.5.2 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
6.1.6 Costs of LNB'S Plus SNCR
6.1.6.1 Capital Costs of LNB's Plus SNCR. The capital cost
of LNB's plus SNCR is the sum of the capital cost of LNB's,
presented in Section 6.1.1.1, and the capital cost of SNCR,
6-9
-------
presented in 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 LNB's or MD LNB's may
be combined with SNCR.
6.1.6.2 Operating Costs of LNB's Plus SNCR. The operating
and maintenance costs of LNB's plus SNCR are the sum of the
operating and maintenance costs for LNB's, presented in
Section 6.1.1.2, and the operating and maintenance costs for
SNCR, presented in Section 6.1.3.2.
6.1.7 Costs of LNB's Plus SCR
6.1.7.1 Capital Costs of LNB's Plus SCR. The capital ccst
of LNB's plus SCR is the sum of the capital cost of LNB's,
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.
6.1.7.2 Operating Costs of LNB's Plus SCR. The operating
and maintenance costs of LNB's plus SCR are the sum of the
operating and maintenance costs for LNB's, presented in
Section 6.1.1.2, and the operating and maintenance costs for SCR,
presented in Section 6.1.4.2.
6.1.8 Costs of ND-to-MD Conversion
6.1.8.1 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 l is:
TIC = 21,350 (HQ)0-6
where:
HQ = heater capacity, GJ/hr.1
The cost methodology gives costs in Canadian average 1991
dollars. For this analysis, capital costs have been escalated to
U.S. 1991 dollars using the Chemical Engineering plant indexes
and an exchange rate of 1 U.S. dollar to 1.15 Canadian dollars.3
As discussed in Chapter 5, ND-to-MD conversion is generally
not performed as a stand-alone NOX control technique. The
6-10
-------
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 LNB's, MD ULNB's, MD SNCR, SCR, MD LNB's
plus FGR, MD LNB's plus SNCR, and MD LNB's plus SCR.
6.1.8.2 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 LNB's.1 This
efficiency gain is site-specific, however, and has not been
included in the cost analysis.
6.2 TOTAL ANNUAL COST FOR MODEL HEATERS
The TAG for applying NO control techniques to model heaters
jt
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 (l + i)n]/[ (1 + i)11'1]
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 TAC's for NOV control
J\.
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
6-11
-------
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 TAC's for the olefins pyrolysis model
heaters. The ND-to-MD conversion costs are presented in
Section 6.2.6.
6.2.1 Control Costs for the ND Gas-Fired, Low- and Medium-
Temperature Model Heaters
Table 6-2 presents the capital costs, annual costs, and
TAC's for the ND gas-fired, low-and medium-temperature model
heaters. The capital costs of the control techniques range from
$58,200 for ND LNB's used on the 17 MMBtu/hr heater to $4,650,000
for MD LNB's plus SCR used on the 186 MMBtu/hr heater. The TAC's
range from $9,250/yr for ND LNB's on the 17 MMBtu/hr heater to
$835,000/yr for MD LNB's plus SCR on the 186 MMBtu/hr heater.
6.2.2 Control Costs for MD Gas-Fired, Low- and Medium-
Temperature Model Heaters
Table 6-3 presents the capital costs, annual costs, and
TAC's for the MD gas-fired, low- and medium-temperature model
heaters. The capital costs of the control techniques range from
$130,000 for LNB's used on the 40 MMBtu/hr heater to $5,360,000
for LNB's plus SCR used on the 236 MMBtu/hr heater. The TAC's
range from $20,700/yr for LNB's used on the 40 MMBtu/hr heater to
$988,000/yr for LNB's plus SCR used on the 263 MMBtu/hr heater,.
6.2.3 Control Costs for ND Oil-Fired. Low- and Medium-
Temperature Model Heaters
Table 6-4 presents the capital costs, annual costs, and
TAC's for the ND oil-fired, low- and medium-temperature model
heaters. The capital costs of the control techniques range from
$227,000 for ND LNB's to $2,580,000 for MD LNB's plus SCR. The
TAC's range from $36,lOO/yr for ND LNB's to $463,000/yr for the
MD LNB's plus SCR. These costs are the same for both distillate
and residual oil-fired ND model heaters.
6-12
-------
TABLE 6-2.
NATURAL
COSTS OF CONTROL TECHNIQUES FOR ND
GAS-FIRED MODEL HEATERS (1991 $)
Model healer
capacity,
MMBtu/hr
17
36
77
NOX control technique
(ND)LNB
(MD) LNB
(ND)ULNB
(MD)ULNB
(ND) SNCR
(MD)SNCR
(MD)SCR
(MD) LNB + FOR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
(ND)LNB
(MD) LNB
(ND)ULNB
(MD)ULNB
(ND) SNCR
(MD) SNCR
(MD)SCR
(MD) LNB + FOR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
(ND)LNB
(MD)LNB
(ND)ULNB
(MD)ULNB
(ND) SNCR
(MD) SNCR
(MD)SCR
(MD) LNB + FOR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
Capital costs,
$
58.200
191.000
62,500
249.000
155.000
258.000
951.000
253.000
213.000
346.000
1.040.000
92.600
302.000
96.900
308.000
243,000
405.000
1.500.000
399,000
335.000
544.000
1.640,000
133.000
457.000
138,000
463.000
383,000
639,000
2.390,000
610.000
516.000
839.000
2.590,000
Annual costs, S'yr
Capital
recovery*
7,650
25.100
8.220
32,800
20,300
34,000
125.000
33.300
28.000
45.400
137,000
12.200
39.600
12,700
40.500
31.900
53.300
198,000
52.500
44.100
71,500
216.000
17.500
60.000
18.100
60.900
50.300
84,000
315.000
80.300
67,900
110.000
341,000
Operating and maintenance costs @
capacity factor»:b
0.1
1,600
5.250
1.720
6,850
4,490
7,480
30,200
7,090
6,090
9.880
32,600
2.550
8.290
2.670
8,470
7,160
11.900
49.900
11,300
9.710
15.800
53.700
3.670
12,600
3.790
12.700
11.600
19.300
84.100
17.400
15,300
24.800
89.600
0.5
1.600
5.250
1.720
6.850
5.420
9.000
32.600
7.630
7.020
11.400
35.000
2.550
8.290
2.670
8.470
9.150
14.400
54.900
12,400
11.700
19.000
58.700
3.670
12.600
3.790
12,700
15.800
24.600
94.800
19.800
19.500
31.700
100.000
0.9
1,600
5.250
1.720
6.850
6,360
10.500
34.900
8.170
7.960
12,900
37.300
2.550
8.290
2,670
8.470
11.100
16.900
59.900
13.500
13.700
22.200
63.700
3.670
12.600
3.790
12.700
20,100
29,800
106.000
22.300
23,700
38,600
111.000
Total annual cost>. $/yr © capacity
factor* :c
0.1
9,250
30.400
9.940
39,600
24,800
41.400
155.000
40.400
34.100
55.300
169,000
14.700
47,900
15.400
49,000
39.000
65.200
247,000
63,700
53.800
87.300
270.000
21,200
72.600
21.900
73.600
61,900
103,000
399,000
97,600
83.100
135,000
431.000
0.5
9.250
30.400
9.940
39.600
25.700
43.000
158.000
40.900
35.000
56,800
172.000
14,700
47,900
15.400
49,000
41.000
67,700
252,000
64,800
55,800
90.500
275.000
21,200
72,600
21,900
73,600
66,100
109,000
410.000
100.000
87,300
142.000
441,000
0.9
9,250
30.400
9.940
39,600
26.700
44.500
160.000
41.400
35.900
58.400
174,000
14,700
47,900
15.400
49,000
43.000
70.100
257,000
66.000
57.700
93.700
280.000
21,200
72,600
21.900
73,600
70.400
114.000
420,000
103,000
91.600
149.000
452.000
6-13
-------
TABLE 6-2. (continued)
Model heater
capacity,
MMBtu/hr
121
186
NOX control technique
(ND)LNB
(MD) LNB
(ND)ULNB
(MD)ULNB
(ND) SNCR
(MD) SNCR
(MD)SCR
(MD) LNB + FOR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
(ND)LNB
(MD)LNB
(ND)ULNB
(MD)ULNB
(ND) SNCR
(MD) SNCR
(MD)SCR
(MD) LNB + FGR
(ND) LNB + SNCR
(MD) LNB + SNCR
(MD) LNB + SCR
Capital coite,
$
232,000
685.000
237,000
691,000
502.000
838.000
3.160,000
887.000
734,000
1.190.000
3.510.000
346,000
955.000
351.000
961,000
650.000
1.090,000
4,130.000
1.220.000
996.000
1.600.000
4,650.000
Annual costs, $/yr
Capital
recovery*
30.500
90.100
31,100
90.900
66.000
110.000
416.000
117.000
96.500
156.000
462.000
45.500
126.000
46.100
126.000
85.400
143,000
543.000
160.000
131.000
211.000
611.000
Operating and maintenance costs @
capacity factors:'1
0.1
6.390
18.800
6.510
19.000
15.500
25.800
116.000
25.300
21.900
35.300
125.000
9.520
26.300
9,640
26.400
20.400
34,000
158,000
34.900
29,900
48.300
172.000
0.5
6.390
18.800
6.510
19.000
22.100
34.000
133.000
29,200
28.500
46,200
142,000
9.520
26.300
9.640
26.400
30.700
46.700
183.000
40.800
40.200
64,900
198.000
0.9
6,390
18.800
6.510
19.000
28,800
42.300
149.000
33,000
35.200
57.000
159,000
9,520
26,300
9.640
26.400
40.900
59.400
209.000
46.600
50.400
81.500
224.000
Total annual costs. S/yr @ capacity
factors:0
0.1
36.900
109.000
37.600
110.000
81.500
136.000
532.000
142,000
118,000
191,000
587,000
55.000
152.000
55,700
153.000
106.000
177.000
700.000
195.000
161.000
259.000
783,000
0.5
36,900
109.000
37.600
110.000
88.100
144,000
548.000
146.000
125.000
202,000
604.000
55.000
152.000
55.700
153.000
116,000
189,000
726,000
201,000
171.000
276.000
809.000
0.9
36900
109.000
37 600
110.000
94 800
153,000
565.000
ISC .000
132.000
213.000
621.000
55 000
152.000
55,700
153.000
126.000
202,000
752,000
207.000
181.000
292.000
835.000
aCapital recovery = Capital cost x capital recovery factor.
Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent.
cTotal annual cost = Capital recovery + operating and maintenance cost.
6-14
-------
TABLE 6 - 3. COSTS OF CONTROL TECHNIQUES FOR MD NATURAL
GAS-FIRED MODEL HEATERS (1991 $)
Model heater
capacity,
MMBtu/hr
40
77
114
174
NOX control
technique
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB + SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB + SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB -t- SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB -f SNCR
LNB + SCR
Capital co*tR,
S
130,000
136.000
258,000
1,430,000
234,000
388.000
1.560,000
282.000
288.000
383.000
2.140.000
436,000
665.000
2.420.000
507.000
514.000
484.000
2.720.000
702.000
992.000
3.230.000
541,000
548.000
624.000
3.540.000
792,000
1,170.000
4,080.000
Annual cocti. S/yr
Capital
recovery*
17,100
17.900
34.000
188.000
30.700
51.000
205.000
37.100
37.900
50.300
281.000
ST.3QO
87.400
318.000
66.700
67.600
63.700
358.000
92.300
130.000
425.000
71,200
72,000
82,100
466.000
104.000
153.000
537.000
Operating and maintenance ccxtt ®
capacity facton b
0.1
3.570
3.750
8.000
48.800
6.740
11.600
52.400
7.750
7.930
12.200
77,000
12.600
20,000
84.800
14.000
14.100
15.900
102.000
20.200
29,800
116.000
14.900
15.100
21,100
139.000
23.200
35.900
154.000
0.5
3.570
3.750
11.600
54.400
8,010
15.100
57.900
7.750
7.930
19.100
87.800
15,000
26.900
95.500
14.000
14.100
26.100
118.000
23.800
40.000
132.000
14.900
15.100
36.600
163,000
28.600
51.500
178.000
0.9
3.570
3,750
15,100
59,900
9.270
18.700
63,500
7,750
7.930
26.000
98.500
17.400
33,800
106,000
14,000
14.100
36,200
134,000
27,400
50.200
148.000
14.900
15.100
52,200
187.000
34.100
67,000
202.000
Total annual coflU. S/yr & capacity
racton:0
0.1
20,700
21,700
42.000
237.000
37,500
62.600
257,000
44.800
45.800
62.600
358,000
69.900
107.000
403,000
80.700
81.700
79.500
460,000
113,000
160.000
541.000
86,100
87,100
103.000
604.000
127.000
189.000
690,000
0.5
20.700
21,700
45.500
242,000
38,700
66.200
263,000
44.800
45.800
69,400
369.000
72.300
114.000
414.000
80.700
81.700
89.700
476.000
116.000
170.000
557.000
86.100
87.100
119.000
629.000
133.000
205.000
715,000
0.9
20.700
21.700
49,100
248.000
40.000
69,800
269.000
44.800
45.800
76.300
380.000
74.700
121.000
424,000
80.700
81.700
99.900
492.000
120.000
181.000
573.000
86,100
87,100
134,000
653.000
138.000
220.000
739.000
6-15
-------
TABLE 6-3. (continued)
Model heater
capacity .
MMBtu/hr
263
NOX control
technique
LNB
ULNB
SNCR
SCR
LNB + FGR
LNB + SNCR
LNB + SCR
Capital coits.
$
777.000
783.000
800,000
4.580.000
1.100.000
1.580.000
5.360.000
Annual costs. $'yr
Capital
recovery*
102.000
103.000
105.000
603.000
144.000
207,000
705.000
Operating and maintenance costs @
capacity factors:
0.1
21.400
21.500
27,900
188.000
32.300
49,200
210.000
0.5
21.400
21.500
51,400
225.000
40.600
72.700
246.000
0.9
21.400
21.500
74,900
262.000
48.900
96.200
283.000
Total annual costs. $/yr Q capacity
factors:0
0.1
123.000
124,000
133,000
791.000
177,000
256.000
915.000
0.5
123.000
124.000
157.000
828.000
185.000
280.000
951.000
0.9
123,000
124.000
180,000
86-1.000
19J.OOO
305.000
9815.000
aCapital recovery = Capital cost x capital recovery factor.
Operating and maintenance costs at operating capacities of 10 percent, 50 percent, and 90 percent.
cTotal annual cost = Capital recovery + operating and maintenance cost.
6-16
-------
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6-17
-------
6.2.4 Control Costs for MD Oil-Fired. Low- and Medium-
Temperature Model Heaters
Table 6-5 presents the capital costs, annual costs, and
TAC's for the MD oil-fired, low- and medium-temperature model
heaters. The capital cost of the control techniques range from
$319,000 for LNB's to $3,340,000 for LNB's plus SCR. The capital
cost for both MD oil-fired heaters are the same. The TAC's range
from $50,700/yr for LNB's used on the distillate oil-fired heater
to $570,000 for LNB's plus SCR used on the residual oil-fired
heater.
6.2.5 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
the control techniques range from $248,000 for LNB's to
$2,900,000 for LNB's plus SCR on both pyrolysis model heaters.
The TAC's range from $39,400/yr for LBN's on the natural
gas-fired heater to $512,000 for LBN's plus SCR on the high-
hydrogen fuel gas-fired heater.
6.2.6 Costs for ND-to-MD Conversion
Table 6-7 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 $ll,900/yr; and the TAC's range from $16,500/yr
to $69,000/yr for the 17 and 185 MMBtu/hr natural gas-fired low-
and medium-temperature heaters, respectively.
6.3 COST EFFECTIVENESS OF NOV CONTROLS FOR PROCESS HEATERS
J\.
This section presents the cost effectiveness for the control
techniques presented in Section 6.2. The cost effectiveness, in
dollars per ton of NOX removed ($/ton), is calculated by dividing
the TAC's 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
6-18
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-------
TABLE 6-7. ND-TO-MD CONVERSION COSTS FOR THE ND MODEL
HEATERS (1991 $)
Model heater
capacity,
MMBtu/hr
Capital cost, 1991
US$
Capital recovery,
1991 US $/yr
Annual operating
costs, 1991 US $/yr
Total annual
costs, 1991
US $/yr
ND NATURAL GAS-FIRED HEATERS
17
36
77
121
185
104,000
163,000
257,000
336,000
434,000
13,600
21,400
33,800
442,000
57,100
2,860
4,480
7,070
9,240
11,900
16,500
25,900
40,900
53,400
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
6-21
-------
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 ULNB's 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 ULNB's 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 ULNB's 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 ULNB's 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 $l,490/ton for MD ULNB's
on the high-hydrogen fuel gas-fired heater to $14,lOO/ton for
LNB+SCR on the natural gas-fired heater.
The cost effectiveness of each control technique for the
model heaters generally increases from ULNB to LNB, to LNB plus
FGR, to SNCR, to LNB plus SNCR, to LNB plus SCR, to SCR. The
cost-effectiveness values for the control techniques applied to
the smaller model heaters are generally higher in comparison to
the same control techniques applied to the larger heaters. This
difference represents an economy of scale because for a given
percent reduction, the quantity of NOX emissions removed per year
(tons/yr) from the smaller model heaters was lower than from
other model heaters.
Table 6-13 is a summary of the cost effectiveness of
selected NO emission control techniques as presented by the
6-22
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6-30
-------
TABLE 6-13. CARB COST EFFECTIVENESS FOR NO EMISSION
CONTROL TECHNIQUES (1991 $)12
Control technology
Low-NOx burners
Flue gas recirculation
Selective noncatalytic reduction
Selective catalytic reduction
Annual capacity factor,
percent
10
50
90
10
50
90
10
50
90
10
50
90
Unit size range,
MMBtu/hr
3.5 to 150
3.5 to 350
50 to 375
50 to 350
Cost effectiveness range,
thousand/ton NOxa
2.61 to 30.6
0.570 to 7.25
0.340 to 4.53
7.71 to 32.9
1.81 to 7. 71
1.13 to 4.19
2.61 to 22.7
1.70 to 6. 80
1.47 to 4.31
27.2 to 74.8
6.80 to 15.9
4.53 to 10.2
aEscalated from 1986 $ to 1991 $ using the Chemical Engineering plant cost index.
6-31
-------
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 LNB's and SCR
should be added to yield the total cost effectiveness of LNB's
combined with SCR.
6.4 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.
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. 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
6-32
-------
TABLE 6-14. RADIANT BURNER COST EFFECTIVENESS'
Heater
capacity,
MMBtu/hr
6
6
6
Capacity
factor
0.9
0.5
0.3
Emission
reduction,
tons/yra
2.46
1.36
0.82
Cost, $ 1991
Capita]
38,000
38,000
38,000
Capital
recovery
6,150
6,150
6,150
Annual
operating
12,600
9,700
8,280
Total
annual
18.700
15,900
14,400
Cost
effec-
tiveness,
$/ton
7,600
11,700
17,600
aEmission reduction compared to an MD heater with conventional burners.
'•'The capital recovery factor is 0.131.
6-33
-------
6.5 REFERENCES FOR CHAPTER 6
l. A Study to Assess the Available Technology and Associated
Costs of Reducing NO Emissions From the Canadian Petroleum
Refining Industry. Canadian Petroleum Products Institute.
CPPI Report No. 91-1. November 28, 1990.
2. Technical Support Document for a Suggested Control Measure
for the Control of Emissions of Oxides of Nitrogen From
Industrial, Institutional, and Commercial Boilers, Steam
Generators, and Process Heaters. Air Resources Board and
South Coast Air Quality Management District. April 29,
1987.
3. Economic Indicators: Chemical Engineering Plant Cost Index.
Chemical Engineering. Vol. 99(3):206. March 1992.
4. OAQPS Control Cost Manual. United States Environmental
Protection Agency, Office of Air Quality Planning and
Standards. EPA 450/3-90-006. January 1990.
5. Letter and attachments from Moreno, F., Alzeta Corporation,
to Sanderford, E., MRI. May 22, 1992. Cost comparison
between ND and MD conventional burners versus Alzeta
burners.
6. Annual Energy Review 1990. Department of Energy/Energy
Information Administration-0384(90). May 1991. p. 157.
7. Letter and attachments from Smith, J., Institute of Clean
Air Companies, to W. Neuffer, EPA/ESD. May 14, 1992. Use
of catalyst systems with stationary combustion sources.
8. Telecon. Harris, R., MRI, with Davis, L., Exxon, Baton
Rouge. February 7, 1992. Low-N0x burner retrofits.
9. Letter and attachments from Morrow, N., Exxon Chemical
Group, to Harris, R., Midwest Research Institute. Low-N0x
burner experience at Basic Chemicals plant.
10. Letter and attachments from Pickens, R., Nalco Fuel Tech, to
Neuffer, W., EPA/ISB. August 7, 1992. Comments on Draft
Alternative Control Techniques Document--Control of NOX
Emissions from Process Heaters.
6-34
-------
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.
6-35
-------
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 (LNB's), ultra low-NOx
burners (ULNB's), 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 NC> control techniques and are not discussed
J*L
separately in this chapter.
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.
7.1 AIR POLLUTION IMPACTS
7.1.1 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-N0x burners are designed for ND and MD operation and
achieve NOX reductions by staged-air or staged-fuel techniques.
Emissions reductions for LNB's are approximately 50 percent over
conventional burners for both ND and MD LNB's, although one
manufacturer reports a 72 percent reduction for a staged-fuel MD
LNB.1'2 Staged-fuel LNB's, discussed in Section 5.1.4, yield the
highest NOX reductions for LNB's and are designed for firing
natural gas or refinery gas. Staged-air LNB's 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 ULNB's. Ultra low-NO,, burners
J^-
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 LNB's with total NOX reductions
of approximately 55 percent over uncontrolled emissions.
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 LNB's. 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 reactan" to
NOY are the factors that affect SNCR reductions the most and are
J\.
further discussed in Section 5.2. According to Thermal DeNOxlS)
data in Table 5-7 and NCL.OUT® data in Table 5-8, the maximum NOV
J\. . J\.
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 LNB's. 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
NC> strongly affect the performance of SCR and are further
Jv
discussed in Section 5.3.
According to the data in Appendix D, reductions of
90 percent with LNB's + 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.
7.1,2 Emissions Trade-Offs
The formation of thermal and fuel NOV depend upon combustion
J\.
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 NC> by
J\-
injecting a reactant into the flue gas stream. Ammonia (NH3),
nitrous oxide (^0), 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.
7.1.2.1 Impacts on HC__and CO Emissions from the Use of
LNB's, ULNB's. and FGR. The extent to which NOV emissions can be
Jv
reduced by combustion controls may be limited by the maximum
acceptable increase in CO and HC emissions. Combustion controls
for NOX reduction discussed in this chapter are LNB's, ULNB's and
FGR.
The air pollution impacts for ULNB's and LNB's are similar
and are discussed collectively in this chapter as LNB's. Low-NOY
J\.
burners reduce NOX formation by reducing the peak flame
temperature and/or Q^ concentrations in the flame zone. These
burners are more sensitive to LEA controls than conventional
7-3
-------
burners. Improper control can cause incomplete combustion and
result in increased CO and HC emissions.^'7
In a test involving a process heater with LNB's, 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 02 levels. Figure 7-1 plots the NOX emission factors
as a function of flue gas 02 content for the heaters tested. The
level of NOX decreases as the level of excess 02 decreases, but
below approximately 3 percent excess 02, significant CO emissions
or visible smoke occurred, and these points are marked in the
figure as "CO limits."8
Table 7-1 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 NOV emissions with the
.X.
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 02) CO emissions.
By decreasing the excess 02 level from 6.2 to 3.0 percent, N0y
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 02). 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 02). By
reducing the 02 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 02).
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
7-4
-------
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it* 2
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RACK OXTCD> %. OR
10
Figure 7-1. NO., emission factor for 10 process heaters eguipped
with low-NOx burners as a function of stack oxygen.®
7-5
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7-6
-------
operations were generally unchanged from the as-found
conditions. The study showed that emissions reductions with
LNB's are optimized by controlling the excess air. Furthermore,
efficiency gains were achieved by lowering excess 02 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 LNB's.2 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 02,
where NOX decreased to 29 ppmv but CO increased to 41 ppmv
(corrected to 3 percent 02).2
Data in Tables 7-1 and 7-2 indicate that LNB's are capable
of reducing NOX without causing excessive CO emissions. The
highest CO emissions in Table 7-1 were 33 ppmv at 3 percent 02 .
The highest CO emissions in Table 7-2 were 41 ppmv at 3 percent
02 . 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 02 concentration. These effects
promote CO and HC emissions, but these effects can be minimized
with properly designed FGR and excess 02 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 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
7-7
-------
TABLE 7-2. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS
FOR A 20 MMBtu/hr REFINERY HEATER WITH LNB OPERATION
(REFINERY FUEL GAS)2
09, %
2.0
3.5
4.2
4.6
5.3
5.9
NOY, ppma
29
32
34
35
35
35
NOY/ Ib/MMBtu
0.033
0.040
0.044
0.046
0.048
0.050
CO, ppmb
41
0
0
0
0
0
aHeater is operated with an LEA system.
^Corrected to 3 percent 02.
7-8
-------
TABLE 7-3. NITROGEN OXIDE AND CARBON MONOXIDE EMISSIONS FOR A
6.7 MMBtu/hr (200 hp) BOILER WITH LNB + FGR10
Fuel
NG
NG
NG
NG
F0b
F0b
F0b
F0b
Load, %
66
66
100
100
68
68
100
100
% FGR
0
16.9
0
12.5
0
18.9
0
14 .3
% 0,
4.22
4.30
4.00
4.67
3.80
3 .70
4.33
4 .07
NOV, ppma
74
24
80
33
138
109
158
123
lb NOX/
MMBtu
0.106
0.035
0.117
0.048
0.199
0.158
0.336
0.265
CO , ppma
11
29
16
13
13
20
16
14
lb CO/
MMBtu
0.062
0.017
0.014
0.012
0.007
0.012
0 . 014
0.012
"Corrected to 3 percent O,
bNo. 2 distillate fuel oil.
7-9
-------
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 cf
74 ppmv (corrected to 3 percent O2) and CO emissions of 11 ppir.v
(corrected to 3 percent 02). Using 16.9 percent FGR, NOX
emissions decreased to 24 ppmv (corrected to 3 percent 02), but
CO emissions increased to 29 ppmv (corrected to 3 percent 02).
Firing natural gas at 100 percent load, 0 percent FGR
corresponded to NOX emissions of 80 ppmv (corrected to 3 percent
02) and CO emissions of 16 ppmv (corrected to 3 percent 02).
Using 12.5 percent FGR, NOX emissions decreased to 33 ppmv
(corrected to 3 percent 02) and CO emissions decreased to 13 ppmv
(corrected to 3 percent 02). 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, NOV
J\.
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.
7.1.2.2 Impacts on NH3, N20. 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 DeNOxs
utilizes NH3 injection and NOXOUT® utilizes urea injection.
Emission of unreacted NH3, or NH^ slip, is the primary air
pollution impact with the Thermal DeNOx® and NOXOUT® SNCR
processes because of the high reactant-to-NOY injection ratio
J^.
(1.25 to 2.0:1).6 Figure 7-2 shows that at higher temperatures,
when NH3 and urea are more reactive, NH3 slip is reduced. In a
7-10
-------
1 UUU™
800-
c.
? 60°"
c
'3*
« 400-
ac
200-
n^
•
^K$^
r-
I
^^
AMMONIA
CZ3
UREA
CYANURICACID
877 977
Temperature, °C
1097
Figure 7-2.
Pilot-scale test results, NH3 emissions
Inlet NO = 700 ppm.12
7-11
-------
typical refinery heater application, a 70 percent NOV reduction
Jt
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)2S03] 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 N20 emissions from
conventional combustion equipment are low (less than 15 ppmv for
boilers) advanced combustion and emission control techniques
could increase N20 emissions. Nitrous oxide is the largest
source of stratospheric NO.12 The following reactions describe
the formation of N20 and CO, where the intermediate species HCNO
is a precursor:
OH + HNCO -» NCO + H20
NCO + NO -» N20 + CO.12
Reduction of NOY with SNCR processes increases with
«?v
temperature up to approximately 980°C (1800°F) as demonstrated by
the results of a pilot scale test presented in Figure 7-3a.
Formation of N20 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 980°C (1800°F) and the peak N20
emissions (21 ppmv) occurred at about 880°C (1620°F). Urea
7-12
-------
877 927 977
Temperature, °C
1097
a) NOX reduction versus temperature for SNCR processes
I
c.
100-
90-
80-
70-
60-
AMWONIA
; UREA
CYAMUR'C ACiD
^j 30-
20
877 927 977
Temperature, °C
1097
b) N20 production versus temperature
Figure 7-3. Pilot-scale test results; NOX reduction
and N70 production versus temperature.12
7-13
-------
injection resulted in peak NOX reductions and peak N20 emissions
(43 ppmv) occurred at about 980°C (1800°F).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.
Catalysts older than 10 years tend to convert up to 5 percent of
any S02 present in sulfur-bearing fuels to S03.3 Catalysts
installed in the last 10 years are designed to convert less S02
to S03 . 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 S03 emissions. In addition, formation of (NH^^SCK
from SO-j and unreacted NH3 can result in deposits in the heater
exhaust ducting and PM emissions.7
7.2 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 arecis.
Although the actual amount of hazardous waste contained in the
catalyst bed is small, the volume of the catalyst unit containing
7-14
-------
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.
7.3 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 LNB's,
FGR, SNCR, and SCR are described in the following paragraphs.
Currently, no information concerning the energy impacts of ULNB's
is available. These impacts are expected to be similar to LNB's.
The electrical energy impacts of NOX control techniques
include the additional power consumed by fans or blowers and air
compressors or pumps. Low-N0x burners, in general, do not have
any electrical energy impacts. An electric fan to recirculate
flue gas in addition to MD operation is required by FGR systems.
The aqueous and anhydrous SNCR process require either a
compressed or steam carrier system. Air compressors for these
processes are electric motor driven, therefore having an
electrical energy impact. Selective catalytic reduction systems
cause flue gas pressure drops in the order of 25 to 130 mm w.g.
(1 to 5 in.) and require additional MD horsepower to overcome the
resistance to flow. The additional fan horsepower requirement
increases electrical energy usage slightly.
Combustion control techniques may affect the thermal
efficiency of process heaters. Reduction of flame temperature
generally reduces thermal NC< formation, but may decrease the
JC
combustion efficiency. Reductions in combustion efficiency
usually indicate a reduction in the heater thermal efficiency.
7-15
-------
Current LNB's and FGR systems are balanced between optimum NC>
J*v
reduction and acceptable thermal efficiency.
As discussed in Section 7.1.2.1, heaters using LNB's were
tested to determine the effects of reducing excess air levels.
Maximum combustion efficiency for process heaters is achieved
with excess 02 levels at approximately 3 percent. Thermal energy
is absorbed by excess air levels above 3 percent 02, which
decreases thermal efficiency because the heated excess air
carries thermal energy out of the heater with the flue gas. At
excess 02 levels below 3 percent, insufficient 02 concentrations
exist for complete fuel oxidation.
Low-NO.... burners with LEA are typically slightly more fuel
Jv
efficient than conventional burners, as is shown in Table 7-1.^
However, flame instability associated with LNB's can require
reduced firing rates and loss of thermal efficiency. Loss of
thermal efficiency negates fuel credits derived from burner
efficiency gains.
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. 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.
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.
7-16
-------
7.4 REFERENCES FOR CHAPTER 7
1. Letter and attachments from Eichamer, P., Exxon Chemical
Company, to Neuffer, W., EPA/ISB. September 2, 1992.
Comments on Draft Alternative Control Techniques Documents--
Control of NOX Emissions from Process Heaters.
2. Waibel, R. , PhD. Advanced Burner Technology for Stringent
NOX Regulations. John Zink Company. Presented at American
Petroleum Institute Midyear Refining Meeting. May 8, 1990.
3. A Study to Assess the Available Technology and Associated
Costs of Reducing NOX Emissions From the Canadian Petroleum
Refining Industry. Canadian Petroleum Products Institute.
CPPI Report No. 91-1. November 28, 1990.
4. Letter and attachments from Britt, J. Mobil Oil Corporation
to Jordan, B., EPA/ESD. April 29, 1992. Process heater NO
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. Comma, 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.
7-17
-------
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. N20 Formation in Selective
Non-Catalytic NOX Reduction Processes. Paper presented at
1991 Joint Symposium on Stationary Combustion NOX Control.
Washington, D.C. November 1991.
13. Letter and attachments from Wax, M., Institute of Clean Air
Companies, to Neuffer, W., EPA/ISB. August 27, 1992.
Comments on Draft Alternative Control Techniques Document--
Control of NO.. Emissions from Process Heaters.
Jv
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.
7-18
-------
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-------
APPENDIX B. CURRENT AND FUTURE NO..OUT® APPLICATIONSa
Unit type
Tang-fired
T-fired
Tower
Zurn stoker
Pulverized coal
test unit
Cell-fired
Hydrograte
Detroit Stoker
Incinerator
Front-fired
CE stoker
Incinerator
Thermal
Moving grate
incinerator
On-going utility
boiler
Ethylene
cracker
Cat cracker
Detroit Stoker
Pilot unit
Moving grate
incinerator
Front-fired Ind.
boiler #3
Front-fired Ind.
boiler #4
Moving grate
Stoker-fired
Grate-fired
CFB
Bottom-fired
process heater
Fuel
Bituminous
Coal
#6 fuel oil
Wood waste
Bituminous
coal
Wood waste
Barkj CH4
Waste gas
#6 ruel oil
Coal
Contaminated
soil
MSW
Oil
Natural gas
Crude
MSW
Coal
MSW
Paper
Fiber waste
MSW
Wood
Wood
Wood waste
Refinery gas,
CH4
SizeMWb
75
75
150
44
2
13
39.5
8
30
200
1.9
264 TPD
325
NA
300 TPD
0.47
360 TPD
7.2
17.2
528 TPD
35
19
0.341
17.7
NO, baseline
ppm
200
200
200
150
200
200
85-125
130-260
300
356
600-1000
200
220
90
30-50
110
220
200
392
526
183
140
145
125
38-50
Guaranteed %
reduction
30
30
75
60
85
60
35
60-80
65
40
60
68
60
55
10
60
50
70
50
50
62
52
30
60
35-60
Temperature
°F
1800-2000
1800-2000
1300-2100
1850
1200-1850
1700-2000
1700-1800
1600-1800
1500-2000
1950-2070
2190
1200-1800
2100
1922
1400
1300-1600
1520-1580
1600-2000
1890-1910
1884-1962
1650
1850-1950
NA
1575-1650
1800-2000
$/ton NOX
removed /year
913
913
NA
NA
NA
955
MA
NA
MA
591
NA
NA
NA
NA
NA
NA
NA
NA
(370
670
NA
1258
NA
1180
B-l
-------
APPENDIX B: (continued)
Unit type
Side- fired
process heater
CFB
GT/HRSG
Volund grate-
fired
Front-fired
CFB
Moving grate
incinerator
Sludge
Combustor
CFB limestone
CFB
CFB
Package boiler
Riley Stoker
Pulverized coal
comer-fired
Pulverized coal
corner-fired
Front-fired
Front-fired
Grate fired
Glass furnace
Waste heat
boiler
Pulverized coal
front-fired
Industrial
PUot/CFB
Fuel
Refinery gas,
CH4
Coal
Refinery Gas
MSW
#6 Fuel Oil
Bituminous
Coal
Tires
Paper sludge,
CH4
Coal
Low sulfur
coal
Bituminous
coal
#6 fuel oil
Wood
Brown coal
Brown coal
Natural gas
*6 fuel oil
Hog fuel oil,
bark
Natural gas
Refinery gas
Bituminous
Coal
#6 fuel oil
Coal
SizeMWb
5
45
63
10.8
850
40
7.5
6
29.8
0.256
12
10.3
22.5
150
75
110
110
90
NA
66.5
50
8.53
1
NOX baseline
ppm
65
250
75
300
450
130
85
570
40
150
175
105
NA
250
150
150
240
270
1000
230
650
120
178
Guaranteed %
reduction
50-75
54
50
50
50
70-80
40
50
33
67
88
27-40
25
70
65
45
70
50
55
65
83
60
54
Temperature
°F
1800-2000
1200-1600
1650
NA
1300-1900
1580
1800-2000
1800
1700-1850
1400-1500
1600
1700-1800
1800
1200-2100
1200-1950
1600-1900
1600-1900
1900-2200
1675
NA
1300-2000
1500-2000
1715
$/ton NOX
removed/year
1180
629
660
778
NA
NA
NA
865
NA
NA
NA
NA
2229
NA
NA
NA
NA
580
NA
439
NA
NA
NA
B-2
-------
APPENDIX B: (continued)
Unit type
CFB
Grate type
NA
Moving grate
incinerator
Grate-fired
Future
tangenti ally
fired utility
boiler
Stoker boiler
Cell-fired
Grate-fired
Package boiler
Recovery boiler
Fluidized bed
furnace
Calcmer
Pud
Wood
Wood waste
Coal
MSW
Tires
Oil
Biomass
Wood waste
Tires
Landfill gas
Black liquor
Organic gases
(contains
nitrogen)
Heat coke
SizeMWb
28
190
(MMBtu/hr)
5
32.5
17
185
44
13
17
17
72
1.6
NA
NOX baseline
ppm
150
70-120
NA
240
80
200
150
200
80
25
60
130-160
NA
Guaranteed %
reduction
70
42-78
NA
65
50
50
50
60
50
NA
60
50-60
50
Temperature
°F
NA
1680
NA
1700-1900
1950-2100
1850
1700-2000
1900-2050
NA
NA
1800
NA
$/ton NO,
removed/year
NA
NA
NA
NA
1,418
:363
(514
055
1418
NA
NA
3,:i73
NA
NA = Not available
aReference 26 from Chapter 5.
''Rated power output.
B-3
-------
APPENDIX C.
LIST OF PROCESS HEATER NO CONTROL RETROFITS FOR
MOBIL TORRANCE REFINERY*
Heater
IF-1
IF-2
2F-2
3F-1A
3F-18
3F-2A
3F-2B
3F-3
3F-4
4F-1
6F-1
6F-2
19F-1
20F-2
2"'F-">
22F-3
50F-1
Capacity,
MMBtu/
hr
457
161
108
17.2
17.2
21.1
21.1
129
73
527
39.6
64
288
220
91
91
12
Preretrofit
control tech-
nology'
LNB
LNB
LNB
None
None
None
None
LNB
LNB
None
None
None
LNB
LNB
LNB
None
None
Preretrofit NOX
emissions,
ib/MMBtu
0.056
0.0773
0.0553
0.15
0.15
0.15
0.15
0.0819
0.1127
0.2288
0.07
0.1607
0.0877
0.1002
0.0793
0.115
0.12
Post-retrofit
control tech-
nology
SCR
SCR
ULNB
ULNB
ULNB
UNLB
ULNB
ULNB
ULNB
ULNB
ULNB
ULNB
SCR
SCR
LNB
LNB
UNLB
Post-retrofit
NOX emissions,
Ib'MMBtu
0.02
0.05
0.05
0.0327
0.035
0.040
0.031
0.07
0.07
0.06
0.032
0.06
0.020
0.020
0.10
0.10
0.0375
NOX
emission reduc-
tions, %
64.3
74.1
9.6
78.2
76.7
73.3
79.3
14.5
37.9
73.8
54.3
62.7
77.2
80.0
13.0
68.8
aReference 14 from Chapter 5.
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TECHNICAL REPORT DATA
(Please read Instructions on the reiene before complenng;
1 p£poRT NO 2
EPA-453/R-93-034
4 TITLE AND SUBTITLE
Alternative Control Techniques Docurrment — NOX Emissions
from Process Heaters
7 A^THORiS)
Ed B. Sanderford, Jr.
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Midwest Research Institute
401 Harrison Oaks Boulevard, Suite 350
Gary, North Carolina 27513-2412
12 SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Emission Standards Division (MD-13)
Office of Air Quality Planning and Standards
Research Triangle Park, N. C. 27711
3 RECIPIENT'S ACCESSION NO
5. REPORT DATE
September, 1993
6. PERFORMING ORGANIZATION CODE
8 PERFORMING ORGANIZATION REPOST \C
10 PROGRAM ELEMENT NO
11 CONTRACT GRANT NO
68-D1-0115
13. TYPE OF REPORT AND PERIOD COVERED
14 SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
EPA Work Assignment Manager: William Neuffer (919) 541-5435
16 ABSTRACT
This Alternative Control Techniques document describes available
control techniques for reducing NOX emission levels from refinery
and chemical industry process heaters. This document contains
information on the formation of NO and uncontrolled NOX
emissions from process heaters. The following NO control
techniques for process heaters are discussed: low-NO burners
(LNB), ultra-low NOX burners (ULNB), flue gas recirculation
(FGR), selective noncatalytic reduction (SNCR), and selective
catalytic reduction (SCR). For each control technique,
achievable controlled NOX emission levels, capital and annual
costs, cost effectiveness, and environmental and energy impacts
are presented.
17 - KEY WORDS AND DOCUMENT ANALYSIS
a OESCmPTOKS
Rtfmry and ClwMeal Muttrr PTKM* HM(M
Contra! TachBiiuai far NOX EMMNM
Low-N0x Burntn (LNB)
Ultra-low NOX Bunwn (ULNB)
Salectiva Noncatalytic Reduction (SNCR)
Silwtiv* CftWytic Reduction (SCR)
Flu Gas RtcircuMon (F6R)
Cost* of NOX EmMwn Cafttral
18 DISTRIBUTION STATEMEN, ~
b IDENTIFIERS/OPEN ENDED TERMS
19 SECURITY CLASS iThisReporti
20 SECURITY CLASS iTha pagt )
c. COSATI 1 ieid Group
21 NO OF PAGES
190
22. PRICE
EPA Fo,m 2220-1 (R.v. 4-77)
CfiEVIOUS EDITION >S
------- |