&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-79-178f
December 1979
Technology Assessment
Report for Industrial
Boiler Applications:
NOX Combustion
Modification
nteragency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-178f
December 1979
Technology Assessment Report
for Industrial Boiler Applications:
NOX Combustion Modification
by
KJ. Lim, R.J. Milligan, H.I. Lips,
C. Castaldini, R.S. Merrill,
and H.B. Mason
Acurex Corporation
485 Clyde Avenue
Mountain View, California 94042
Contract No. 68-02-3101
Task No. B
Program Element No. INE624
EPA Project Officer: Robert E. Hall
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ACKNOWLEDGMENT
The work presented in this report was performed as part of the
NO Control Technology Assessment Program under Contract 68-02-3101 to
J\
the U.S. Environmental Protection Agency, Industrial Environmental
Research Laboratory (Research Triangle Park). The support and assistance
of lERL-RTP's Robert E. Hall and J. David Mobley are most gratefully
acknowledged. In addition, the information and helpful comments provided
by the American Boiler Manufacturers Association, Council of Industrial
Boiler Owners, and numerous other organizations and individuals are much
appreciated.
ii
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PREFACE
The 1977 Amendments to the Clean Air Act required that emission
standards be developed for fossil-fuel-fired steam generators.
Accordingly, the U.S. Environmental Protection Agency (EPA) recently
promulgated revisions to the 1971 new source performance standard (NSPS)
for electric utility steam generating units. Further, EPA has undertaken
a study of industrial boilers with the intent of proposing a NSPS for this
category of sources. The study is being directed by EPA's Office of Air
Quality Planning and Standards, and technical support is being provided by
EPA's Office of Research and Development. As part of this support, the
Industrial Environmental Research Laboratory at Research Triangle Park,
N.C., prepared a series of technology assessment reports to aid in
determining the technological basis for the NSPS for industrial boilers.
This report is part of that series. The complete report series is listed
below:
Title Report No.
The Population and Characteristics of Industrial/ EPA-600/7-79-178a
Commercial Boilers
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178b
Applications: Oil Cleaning
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178c
Applications: Coal Cleaning and Low Sulfur Coal
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178d
Applications: Synthetic Fuels
-------
Title Report No.
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178e
Applications: Fluidized-Bed Combustion
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178f
Applications: NOX Combustion Modification
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178g
Applications: NOX Flue Gas Treatment
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178h
Applications: Particulate Collection
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178i
Applications: Flue Gas Desulfurization
These reports will be integrated along with other information in
the document, "Industrial Boilers -- Background Information for Proposed
Standards," which will be issued by the Office of Air Quality Planning and
Standards.
IV
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TABLE OF CONTENTS
Section Page
Acknowledgment ii
Preface ±±±
I EXECUTIVE SUMMARY 1-1
1.1 Introduction 1-1
1.2 NOX Formation Mechanisms and Principles
of Control 1-2
1.3 Systems of NOX Emissions Reduction for
Coal-Fired Boilers 1-5
1.3.1 Candidate Best Systems of Control for
Coal-Fired Boilers 1-5
1.3.2 Best Systems of Control for Coal-Fired
Boilers 110
1.4 Systems of NOX Emission Reduction for
Oil-Fired Boilers 1-15
1.4.1 Candidate Best Systems of Control for
Oil-Fired Boilers 1-15
1.4.2 Best Systems of Control for Oil-Fired
Boilers 1-18
1.5 Systems of NOX Emission Reduction for
Gas-Fired Boilers 1-21
1.6 Energy Impact 1-22
1.7 Cost Impact 1-22
1.8 Environmental Impact 1-24
2 EMISSIONS CONTROL TECHNIQUES 2-1
2.1 NOX Formation Mechanism and Principles
of Control 2-2
2.1.1 Thermal NOX 2-2
2.1.2 Fuel NOX 2-4
2.1.3 Principles of Control 2-9
2.2 Coal-Fired Boilers 2-10
2.2.1 Applicable Control Techniques for
Pulverized Coal-Fired Boilers 2-14
2.2.2 Applicable Control Techniques for Stokers . . . 2-26
-------
TABLE OF CONTENTS (Continued)
Section Page
2.3 Oil-Fired Boilers 2-31
2.3.1 Low Excess Air (LEA) 2-36
2.3.2 Staged Combustion 2-37
2.3.3 Flue Gas Recirculation (FGR) 2-43
2.3.4 Combined Flue Gas Recirculation and
Staged Combustion 2-47
2.3.5 Reduced Air Preheat (RAP) 3-47
2.3.6 Load Reduction 2-48
2.3.7 Low NOX Burners (LNB) 2-49
2.3.8 Ammonia Injection 2-60
2.4 Gas-Fired Boilers 2-63
2.4.1 Low Excess Air (LEA) 2-63
2.4.2 Staged Combustion Air (SCA) 2-67
2.4.3 Flue Gas Recirculation (FGR) 2-69
2.4.4 Combined Flue Gas Recirculation and
Staged Combustion 2-71
2.4.5 Load Reduction 2-71
2.4.6 Reduced Air Preheat (RAP) 2-72
2.4.7 Low NOX Burners (LNB) 2-72
2.4.8 Ammonia Injection 2-73
3 CANDIDATES FOR BEST SYSTEMS OF EMISSION REDUCTION ... 3-1
3.1 Criteria for Selection *~L
3.2 Candidate Control Systems for Coal-Fired
Industrial Boilers 3
3.2.1 Pulverized Coal-Fired Boilers 3-15
3.2.2 Spreader Stoker Boilers *-f'
3.2.3 Chain Grate and Underfeed Stokers 3-19
3.3 Candidate Best Control Systems for Residual
Oil-Fired Industrial Boilers 3-19
3.3.1 Firetube Boilers 3-20
3.3.2 Watertube Boilers 3-22
3.3.3 Effects of Fuel Nitrogen 3-25
3.4 Candidate Best Control Systems for Distillate
Oil-Fired Industrial Boilers 3-26
3.4.1 Firetube Boilers 3-29
3.4.2 Watertube Boilers Without Air Preheaters .... 3-30
3.4.3 Watertube Boilers Equipped with Preheaters . . . 3-32
-------
TABLE OF CONTENTS (Continued)
Section
3.5 Candidate Best Control System for Natural
Gas-Fired Industrial Boilers 3.33
3.5.1 Firetube Boilers 3.34
3.5.2 Watertube Boilers Without an Air Preheater . . . 3-34
3.5.3 Watertube Boilers with Air Preheater 3.35
3.6 Summary 3_38
COST IMPACT 4-1
4.1 Cost Analysis 4-1
4.1.1 Components of Control Costs 4-1
4.1.2 Cost Basis 4-3
4.2 Control Costs for Coal-Fired Boilers 4.7
4.2.1 New Facilities 4-19
4.2.2 Modified and Reconstructed Facilities 4-20
4.3 Control Costs for Oil-Fired Boilers 4-20
4.3.1 New Facilities 4-41
4.3.2 Modified and Reconstructed Facilities 4.42
4.4 Control Costs for Natural Gas-Fired Boilers . . . 4-43
4.4.1 New Facilities 4-43
4.4.2 Modifed and Reconstructed Facilities 4-43
4.5 Summary 4-55
ENERGY IMPACT 5-1
5.1 Introduction 5-1
5.2 Energy Impact of Controls for Coal-Fired
Boilers 5-4
5.2.1 New Facilities 5-4
5.2.2 Modified and Reconstructed Facilities 5-8
5.3 Energy Impact of Controls for Oil-Fired
Boilers 5-9
vii
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TABLE OF CONTENTS (Concluded)
Section Page
5.3.1 New Units 5-9
5.3.2 Retrofitted Facilities 5-17
5.4 Energy Impact of Controls for Gas-Fired
Boilers 5-17
5.4.1 New Facilities 5-17
5.4.2 Retrofitted Facilities 5-22
5.5 Summary 5-22
6 ENVIRONMENTAL IMPACTS OF CANDIDATES FOR BEST
EMISSION CONTROL SYSTEMS 6-1
6.1 Identification of the Major Environmental
Concerns 6-1
6.2 Formation Mechanisms of Major Pollutants 6-4
6.2.1 Criteria Pollutants ~ Formation Mechanisms . . 6-5
6.2.2 Noncriteria Pollutants — Formation
Mechanisms 6-8
6.3 Environmental Impacts of NOX Controls for
Coal-Fired Boilers 6-11
6.4 Environmental Impacts of NOX Controls for
Residual Oil-Fired Boilers 6-24
6.5 Environmental Impacts of NOX Controls for
Distillate Oil and Natural Gas-Fired Boilers . . . 6-48
6.6 Other Pollution Sources . . . 6-64
6.7 Summary 6-68
7 EMISSION SOURCE TEST DATA 7-1
7.1 Criteria for Selection 7-1
7.1.1 Data Selection 7-1
7.1.2 Test Methods 7-2
7.2 Emission Source Test Data for Coal-Fired
Boilers 7-5
7.3 Emission Source Test Data for Oil-Fired
Industrial Boilers 7-5
7.4 Emission Source Test Data for Gas-Fired
Boilers 7-24
7.5 Developing Emission Source Test Data 7-24
APPENDIX A -- COST DETAILS A-l
APPENDIX B - LIST OF COMMON ABREVIATIONS B-l
viii
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LIST OF ILLUSTRATIONS
Figure Page
1-1 Estimated Annualized Control Cost versus NOX Level
for Coal-Fired Boilers 1-25
1-2 Estimated annualized Control Cost versus NOX Emission
Level for Residual Oil-Fired Boilers 1-26
1-3 Estimated Annualized Control Cost versus NOX
Emission Levels for Distillate Oil and Natural
Gas-Fired 4.4 MW Firetube Boilers 1-27
2-1 Nitrogen and Sulfur Content of U.S. Coal Reserves . . . 2-6
2-2 Nitric Oxide Emission as Measured vs. Coal
Nitrogen Content 2-7
2-3 Distributed Fuel/Air Mixing Concept 2-21
2-4 Typical Fuel Gas Recirculation System for NOX
Control 2-22
2-5 Schematic Diagram of the NH3 Injection System 2-24
2-6 Air Injection in a Traveling-Grade Spreader Stoker . . . 2-29
2-7 Schematic of Staged Combustion Air Injection for an
Oil- and Gas-Fired Firetube Boiler 2-38
2-8 Schematic of Staged Air System Installed for Single
Burner Packaged Watertube Oil-Fired Boilers 2-40
2-9 Schematic of Stage Air System Installed on "D"
Type Packaged Watertube Boiler 2-41
2-10 Layout of Flue Gas Recirculation System for a
Firetube Boiler 2-44
2-11 Layout of Flue Gas Recirculation System for a
Packaged Watertube Boiler 2-45
2-12 Alternate Layout of Flue Gas Recirculation System for a
Packaged Watertube Boiler 2-46
2-13 The Nippon/TRW Burner 2-52
2-14 Performance Results of the Nippon/TRW Low NOX
Burner 2-53
ix
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LIST OF ILLUSTRATIONS (Continued)
Figure
2-15
2-16
2-17.
2-18
2-19
2-20
2-21
2-22
2-23
2-24
3-1
4-1
4-2
4-3
6-1
6-2
Ishikawajima-Harima Divided Flame Burner
Effect of Flame Division on NOX and Dust
Concentrations (Ishikawajima-Harima Burner)
Effect of Combined Combustion Modifications NOX
Control of the Performance of the Ishikawajima-Harima
Low NOX Burner
Schematic of Tokoyo Gas Company Two-Stage Combustion
Type Burner for Low NOX Formation
Kawasaki Two-Stage Combustion-Type Burner for Oil ...
Effect of Kawasaki Low NOX Burner on NOX
Emissions
Ammonia Injection System Performance on Commerical
Units as Functions of Temperatures
Schematic of Ammonia Injection System on a Firetube
Boiler
Schematic of the Windbox Burner Arrangement of a
Firetube Burner
Schematic of Register Burner Installed in a
Watertube Boiler
Effect of Fuel Nitrogen Content on NOX Emissions
from Residual Oil-Fired Industrial Boilers
Estimated Annualized Control Cost versus NOX Level
for Coal-Fired Boilers
Estimated Annualized Control Cost versus NOX Emission
Level for Residual Oil-Fired Boilers
Estimated Annualized Control Cost Versus NOX
Emission Levels for Distillate Oil and Natural
Gas-Fired 4.4 MW Firetube Boiler
Change in Incremental Emissions from Coal-Fired
Industrial Boilers >29 MW
Change in Incremental Emissions from Coal-Fired
Industrial Boilers <29 MW
£age
2-55
2-55
2-57
2-58
2-58
2-59
2-61
2-62
2-70
2-71
3-27
4-8
4-9
4-10
6-20
6-21
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LIST OF ILLUSTRATIONS (Continued)
Figure Page
6-3 Partitioning of Elements Based on Effluent Location
for a Coal-Fired Industrial Boiler 6-23
6-4 Trace Element Concentration in Fine Particulate .... 6-25
6-5 Change in Incremental Emissions with Low Excess
NOX Control for Residua" Oil-Fired Watertube
Industrial Boilers 6-32
6-6 Changes in CO and NOX Emission with Reduced Excess
Oxygen for a Residual Oil-Fired Watertube Industrial
Boiler 6-33
6-7 Change in Incremental Emissions with Overfire Air
NOX Control for Residual Oil-Fired Watertube
Industrial Boilers 6-34
6-8 Change in CO and NOX Emissions with Decreasing
Excess Oxygen for a Residual Oil-Fired Firetube
Industrial Boiler 6-35
6-9 Effect of Low Excess Air NOX Control on Particle
Size Distribution for a Residual Oil-Fired Watertube
Industrial Boiler 6-39
6-10 Effect of NOX Controls on Particle Size
Distribution for a Residual Oil-Fired Watertube
Industrial Boiler 6-40
6-11 Effect of NOX Controls on Particle Size
Distribution for a Residual Oil-Fired Watertube
Industrial Boiler 6-41
6-12 Change in CO Emission Rate with NOX Control for
Distillate Oil-Fired Industrial Boiler 6-60
6-13 Change in UHC Emission Rate with NOX Control for
Distillate Oil-Fired Industrial Boiler 6-61
6-14 Change in CO Emissions with NOX Control for a
Gas-Fired Industrial Boiler 6-62
6-15 Changes in CO and NOX Emissions with Reduced
Excess Oxygen for a Gas-Fired Watertube Industrial
Boiler 6-63
xi
-------
LIST OF ILLUSTRATIONS (Concluded)
Figure Page
6-16 Change in Unburned Hydrocarbon Emissions with NOX
Control for Gas-Fired Industrial Boilers 6-65
6-17 Change in Particulate Emissions with N0« Control
for a Distillate Oil-Fired Watertube Industrial
Boiler 6-66
xii
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LIST OF TABLES
Table Page
1-1 Major Industrial Boiler/Fuel Categories and
Baseline NOX Emission Levels 1-3
1-2 Summary of Combustion Process Modification Concepts . . 1-4
1-3 Candidates for Best Systems of NOX Emissions
Reduction: Pulverized Coal-Fired Boilers 1-8
1-4 Candidates for Best Systems of NOX Emissions
Reduction: Stoker Coal-Fired Boilers 1-9
1-5 Best Control Systems for Coal-Fired Industrial
Boilers with Heat Input < 29 MW 1-11
1-6 Best Control Systems for Coal-Fired Industrial
Boilers with Heat Input >29 MW 1-12
1-7 Candidates for Best System of NOX Emissions
Reduction: Residual Oil-Fired Boilers 1-16
1-8 Candidates for Best Systems of NOX Emissions
Reduction: Distillate Oil- and Gas-Fired Boilers . . . 1-17
1-9 Best Control System for Residual Oil-Fired
Industrial Boilers 1-19
1-10 Best Control Systems for Distillate Oil-Fired
Industrial Boilers 1-20
1-11 Best Control Systems for Natural Gas-Fired
Industrial Boilers 1-23
1-12 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Coal-Fired Industrial
Boilers 1-29
1-13 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Residual Oil-Fired
Industrial Boilers . 1-30
1-14 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Distillate Oil-Fired
Industrial Boilers 1-31
1-15 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Gas-Fired Industrial
Boilers 1-32
xiii
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LIST OF TABLES (Continued)
Table Page
2-1 Summary of Combustion Process Modification
Concepts 2-11
2-2 Applicability of Combustion Modification NOX
Controls for Major Industrial Boiler Equipment/Fuel
Types 2-12
2-3 Combustion Modification NOX Controls for
Pulverized Coal-Fired Industrial Boilers 2-15
2-4 Combustion Modification NOX Controls for
Stoker Coal-Fired Industrial Boilers 2-28
2-5 NOX Emissions at Baseline and Low Excess Air from
Oil-Fired Industrial Boilers 2-33
2-6 Combustion Modification NOX Controls for
Oil-Fired Industrial Boilers 2-34
2-7 Low NOX Burners for Oil and Gas Firing 2-51
2-8 Baseline NOX Emission from Natural Gas-Fired
Industrial Boilers 2-64
2-9 Combustion Modification NOX Controls for
Gas-Fired Industrial Boilers 2-65
3-1 Comparison of Baseline NOX Emission Levels 3-4
3-2 Candidates for Best Systems of NOX Emissions
Reduction: Pulverized Coal-Fired Boilers 3-6
3-3 Candidates for Best Systems of NOX Emissions
Reduction: Stoker Coal-Fired Boilers 3-7
3-4 Candidates for Best Systems for NOX Emissions
Reduction: Residual Oil-Fired Boilers 3-8
3-5 Candidates for Best Systems of NOX Emissions
Reduction: Distillate Oil- and Gas-Fired Boilers . . . 3-9
3-6 Suggested NOX Control Levels for Industrial
Boilers 3-11
3-7 Best Control Systems for Coal-Fired Industrial
Boilers with Heat Input >29 MW 3-13
xiv
-------
LIST OF TABLES (Continued)
Table Page
3-8 Best Control Systems for Coal-Fired
Industrial Boilers with Heat Input <29 MW 3-14
3-9 Best Control System for Residual
Oil-Fired Industrial Boilers 3-21
3-10 Best Control Systems for Distillate
Oil-Fired Industrial Boilers 3-28
3-11 Best Control Systems for Natural
Gas-Fired Industrial Boilers 3-35
4-1 Cost Basis for Evaluating NOX Controls 4-4
4-2 Estimated Costs of Candidate NOX Control Techniques
for New Coal-Fired Boilers 4-11
4-3 Estimated Cost-Effectiveness and Impact of Candidate
NOX Control Techniques for New Coal-Fired Boilers . . . 4-13
4-4 Estimated Costs of Candidate Control Techniques for
Retrofitted Coal-Fired Boilers 4-15
4-5 Estimated Cost-Effectiveness and Impacts of Candidate
NOX Control Techniques for Retrofitted Coal-Fired
Boilers. 4-17
4-6 Estimated Costs of Candidate NOX Control Techniques
for New Residual Oil-Fired Boilers 4-21
4-7 Estimated Cost-Effectiveness and Impacts of Candidate
NOX Control Techniques for New Residual Oil-Fired
Boilers 4-23
4-8 Estimated Costs of Candidate NOX Control Techniques
for New Distillate Oil-Fired Boilers 4-25
4-9 Estimated Cost-Effectiveness and Impacts of Candidate
NOX Control Techniques for New Distillate Oil-Fired
Boilers 4-28
4-10 Estimated Costs of Candidate NOX Control Techniques
for Retrofitted Residual Oil-Fired Boilers 4-31
4-11 Estimated Cost Effectiveness and Impacts of Candidate
NOX Control Techniques for Retrofitted Residual
Oil-Fired Boilers 4-33
XV
-------
LIST OF TABLES (Continued)
Table
Page
4-12 Estimated Costs of Candidate NOX Techniques for
Retrofitted Distillate Oil-Fired Boilers 4-35
4-13 Estimated Cost Effectiveness and Impacts of Candidate
NOX Control Techniques for Retrofitted Distillate
Oil-Fired Boilers 4-38
4-14 Estimated Costs of Candidate NOX Control Techniques
for New Natural Gas-Fired Boilers 4-44
4-15 Estimated Cost Effectiveness and Impacts of
Candidate NOX Control Techniques for New Natural
Gas-Fired Boilers 4-46
4-16 Estimated Costs of Candidate NOX Control
Techniques for Retrofitted Natural Gas Boilers 4-49
4-17 Estimated Cost Effectiveness and Impacts of
Candidate NOX Control Techniques for Retrofitted
Natural Gas-Fired Boilers 4-52
5-1 Average State Implementation Plan Requirements 5-1
5-2 Energy Consumption Due to NOX Control Techniques
for Coal-Fired Boilers 5-5
5-3 Energy Consumption for NOX Control Techniques
for Residual Oil-Fired Boilers 5-10
5-4 Energy Consumption Due to NOX Control Techniques
for Distillate Oil-Fired Boilers 5-12
5-5 Energy Consumption due to NOX Control Techniques
for Natural Gas-Fired Boilers 5-18
6-1 Postulated Effect of Combustion Modifications on
Incremental Emissions from Industrial Boilers 6-2
6-2 Incremental Emissions from Pulverized Coal-Fired
Industrial Boilers 6-13
6-3 Incremental Emissions from Stoker Coal-Fired
Industrial Boilers 6-15
6-4 Effect of Overfire Air NOX Control on Particle
Size Distribution for a Coal-Fired Chain Grate
Stoker 6_22
XVI
-------
LIST OF TABLES (Continued)
Table Page
6-5 Emission Rates of Polycyclic Organic Matter (POM)
from a Coal-Fired Chain-Grate Stoker Boiler 6-26
6-6 Incremental Emissions from Residual Oil-Fired
Boilers 6-27
6-7 Effect of Overfire Air NOX Control on Particle
Size Distribution for a Residual Oil-Fired
Watertube Boiler 6-38
6-8 Effect of Combined Low Excess Air, Staged Combustion,
and Flue Gas Recirculation on Polycyclic Organic
Matter (POM) Emissions from a Residual Oil-Fired
Industrial Boiler 6-42
6-9 Effect of NOX Control on Polycyclic Organic
Matter (POM) Emissions from a Residual Oil-Fired
Boiler: XAD-2 Resin Test Only 6-44
6-10 Effect of Combined Low Excess Air, Staged Combustion,
and Flue Gas Recirculation on Trace Species Emissions
from a Residual Oil-Fired Industrial Boiler 6-45
6-11 Trace Species Emissions from a Residual Oil-Fired
Industrial Boiler under Baseline Conditions
(Test 2) 6-46
6-12 Trace Species Emission from a Residual Oil-Fired
Industrial Boiler under Low NOX Conditions
(Test 3) 6-47
6-13 Incremental Emission from Distillate Oil-Fired
Industrial Boilers 6-49
6-14 Incremental Emission for Natural Gas-Fired
Industrial Boilers 6-53
6-15 Effect of Overfire Air NOX Control on Particle
Size Distribution for a Distillate Oil-Fired
Watertube Industrial Boiler . 6-67
6-16 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Coal-Fired Industrial
Boilers 6-69
XVll
-------
LIST OF TABLES (Continued)
Table Page
6-17 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Residual Oil-Fired
Industrial Boilers 6-70
6-18 Postulated Effect of Candidate NOX Control Systems
on Incremental Emission from Distillate Oil-Fired
Industrial Boilers 6-71
6-19 Postulated Effect of Candidate NOX Control Systems
on Incremental Emissions from Gas-Fired Industrial
Boilers 6-72
7-1 Emission Measurement Instrumentation 7-4
7-2 NOX Emission Test Data from Pulverized Coal-Fired
Industrial Boilers with Low Excess Air (LEA) 7-6
7-3 NOX Emission Test Data from Pulverized Coal-Fired
Industrial Boilers with Burners Out-Of-Service
(BOOS) 7-7
7-4 NOX Emission Test Data from Pulverized Coal-Fired
Indusdrial Boilers with Load Reduction (LR) 7-8
7-5 NOX Emission Test Data from Coal-Fired Industrial
Stokers with Low Excess Air (LEA) 7-9
7-6 NOX Emission Test Data from Coal-Fired Industrial
Stokers with Overfire Air (OFA) 7-11
7-7 NOX Emission Test Data from Coal-Fired Industrial
Stokers with Load Reduction (LR) 7-12
7-8 NOX Emission Test Data from Coal-Fired Industrial
Stokers with Reduced Air Preheat (RAP) 7-14
7-9 NOX Emission Test Data from Residual Oil-Fired
Industrial Boilers with low Excess Air (LEA) 7-15
7-10 NOX Emission Test Data from Residual Oil-Fired
Industrial Boilers with Staged Combustion Air (SCA) . . 7-17
7-11 NOX Emission Test Data from Residual Oil-Fired
Industrial Boilers with Burners Out of Service
(BOOS) 7-18
xvlii
-------
LIST OF TABLES (Continued;
Tab1e Page
7-12. NOX Emission Test Dat? f'-or Residual Oil-Fired
Industrial Boilers with Flue Gas Recirculation (FGR) . . 7-19
7-13. NOX Emission Test Data from Residual Oil-Fired
Industrial Boilers with Combined Flue Gas
Recirculation and StagH Combustion Air (FGR/SCA) . . . 7-20
7-14. NOX Emission Test Data from Residual Oil-Fired
Industrial Boilers with Reduced Air Preheat (RAP) . . . 7-21
7-15. NOv Emission Test Data from Residual Oil-Fired
Industrial Boilers with Load Reduction (LR) 7-22
7-16. NOX Emission Test Data from Distillate (No. 2)
Oil-Fired Industrial Boilers with Low Excess Air
(LEA) 7-25
7-17. NOX Emission Test Data from Distillate (No. 2)
Oil-Fired Industrial Boilers with Flue Gas
Recirculation (FGR) 7-26
7-18. NOX Emission Test Data from Distillate (No. 2)
Oil-Fired Industrial Boilers with Staged Combustion
Air (SCA) 7-27
7-19. NOX Test Data from Distillate (No. 2) Oil-Fired
Industrial Boilers with Combined Flue Gas
Recirculation and Staged Combustion Air (FGR/SCA) . . . 7-28
7-20. NOX Emission Test Data from Distillate (No. 2)
Oil-Fired Industrial Boilers with Load Reduction
(LR) 7-29
7-21. NOX Emission Test Data from Gas-Fired Industrial
Boiler with Low Excess Air (LEA) 7-29
7-22. NOX Emission Test Data from Natural Gas-Fired
Industrial Boilers with Staged Combustion Air (SCA) . . 7-33
7-23. NOX Emission Test Data from Natural Gas-Fired
Industrial Boilers with Flue Gas Recirculation (FGR) . . 7-34
7-24. NOX Test Data from Natural Gas-Fired Industrial
Boilers with Combined Flue Gas Recirculation and
Staged Combustion (FGR/SCA) 7-35
xix
-------
LIST OF TABLES (Concluded)
Table Page
7-25. NOv Emission Test Data from Natural Gas-Fired
Industrial Boilers with Load Reduction (LR) 7-35
7-26. NOv Emission Test Data from Natural Gas-Fired
Industrial Boilers with Reduced Air Preheat (RAP) . . . 7-37
7-27. NOX Emission Test Data from Natural Gas-Fired
Industrial Boilers with Burners Out of Service
(BOOS) 7-38
xx
-------
SECTION 1
EXECUTIVE SUMMARY
Industrial boilers produce more than 20 percent of all stationary
combustion source nitrogen oxides (NO ) emissions.* Combustion
A
modification control techniques represent potentially viable means of
controlling NO . The objective of this report is to assess combustion
A
modification NO control technology in order to supply background
/\
information for the EPA Office of Air Quality Planning and Standards in
their evaluation of alternative control systems for industrial boilers.
1.1 INTRODUCTION
This report evaluates the effectiveness, applicability, and
limitations of specific combustion modification NO controls for each
y\
major equipment/fuel category in the industrial boiler sector. The
current baseline or normal operating level NO emission factors for
A
these major boiler/fuel categories are compiled and the effectiveness of
combustion modifications in reducing these NOX emission levels are
reviewed. Only limited, short term field test results (though well
documented) are available to date, as N0x controls are not currently
widely practiced in the industrial boiler sector. This summary highlights
some of the general trends observed after a thorough review of available,
well documented, published data. These observations are meant to be only
guidelines; there will certainly be exceptions, and much research and
development work remains before NO control technology is well
y\
characterized for all of the diverse industrial boiler design and
equipment types. Indeed, EPA's Industrial Environmental Research
Laboratory at Research Triangle Park, N.C., is currently expanding the
*Reference 2-10
-------
existing data base through a number of control development programs,
including 30-day continuous monitoring field tests.
Industrial boilers are defined here as coal-, oil-, or natural
gas-fired steam generators in the industrial sector with heat input
capacities greater than 3 MW (10 x 10° Btu/hr). Major equipment/fuel
categories for industrial boilers have been identified and are listed in
Table 1-1, along with typical heat input capacities and average baseline
NO emission levels.
/\
1.2 NOX FORMATION MECHANISMS AND PRINCIPLES OF CONTROL
Oxides of nitrogen (NO ) formed in combustion processes are
A
usually due either to thermal fixation of atmospheric nitrogen in the
combustion air, leading to "thermal NO " or to the conversion of
A
chemically bound nitrogen in the fuel, leading to "fuel NO ." For
A
natural gas and distillate oil firing, nearly all NOX emissions result
from thermal fixation. With residual oil and coal, the contribution from
fuel-bound nitrogen can be significant and, under certain operating
conditions, predominate.
Both thermal and fuel NO appear to be kinetically or
A
aerodynamically limited because emission rates are far below the levels
which would prevail at equilibrium. Thus, the rate of formation of both
thermal and fuel NO is dominated by combustion conditions and is
A
amenable to suppression through combustion process modifications.
Although the mechanisms are different, both thermal and fuel NO are
A
promoted by rapid mixing of oxygen with the fuel. Additionally, thermal
NOX is greatly increased by long residence time at high temperature.
The modified combustion conditions and control concepts which have been
tried or suggested to limit NOX formation are as follows:
• Decrease primary flame zone 02 level by:
— Decreased overall 0? level
— Controlled mixing of fuel and air
-- Use of fuel-rich primary flame zone
• Decrease time of exposure at high temperature by:
— Decreased peak temperature
— Decreased adiabatic flame temperature through dilution
— Decreased combustion intensity
— Increased flame cooling
1-2
-------
TABLE 1-1. MAJOR INDUSTRIAL BOILER/FUEL CATEGORIES AND
BASELINE NOX EMISSION LEVELS
I
co
Fuel
Pulverized Coal
Stoker Coal
Residual Oil9
Distillate Oil
Natural Gas
Boiler Type
Single Wall
and Tangential
Spreader
Underfeed
Chain Grate
Firetube
Matertube
Watertube
Firetube
Uatertube
Hatertube
Firetube
Matertube
Uatertube
Typical Size
(Heat input
Capacity)
MH(10» Btu/hr)
59(200)
114(400)
44(150), 25(85)
9(30)
22(75)
4.4(15)
8.8(30)
44(150)
4.4(15)
29(100)
44(150)
4.4(15)
29(100)
44(150)
No. of
Boilers
Tested
4
2
7,5
2
2
5.
10
7
6
4,3
1
8
9,11
7
Average
NOjj Baseline
Emission Level
ng N02/J(lb/lo6 Btu)
285(0.663)
285(0.663)
265(0.616)
150(0.349)
140(0.326)
115(0.267)
160(0.372)
160(0.372)
75(0.175)
55b, 90c(0.128b, 0.209C)
90C(0.209C)
40(0.093)
45b, 110c(0.105b, 0.255°)
120C(0.280)C
AP-42 (Ref. 3-2)
N0,j Baseline
Emission-Level
ng NOz/JOb/lO6 Btu)
328(0.763)
328(0.763)
273(0.635)
273(0.635)
273(0.635)
--
171(0.398)
171(0.398)
68(0.158)
—
-
75(0.174)
--
Sources of Data
Used for
Selected Baseline
Emissions
Ref. 3-3, 3-4, 3-5
Ref. 3-3, 3-4, 3-5
Ref. 3-2 through 3-6
Ref. 3-3
Ref. 3-4, 3-5
Ref. 3-3, 3-4, 3-8
Ref. 3-3, 3-4, 3-8, 3-9
Ref. 3-3, 3-4
Ref. 3-3, 3-4
Ref. 3-3, 3-4, 3-9
Ref. 3-3, 3-4
Ref. 3-3, 3-4, 3-10
Ref. 3-3, 3-4, 3-9
Ref. 3-3, 3-4
•"Includes No. 5 and No. 6 fuel oils.
"From boilers not equipped with air preheaters.
cFrom boilers equipped with air preheaters.
-------
TABLE 1-2. SUMMARY OF COMBUSTION PROCESS MODIFICATION CONCEPTS
Combustion
Conditions
Decrease
primary
flame zone
02 level
Decrease
peak
flame
temperature
Chemically
reduce NOX
in post
flame region
Control Concept
Decrease overall
02 level
Delayed mixing
of fuel and air
Primary fuel -rich
flame zone
Decrease
adiabatic flame
temperature
Decrease
combustion
intensity
Increased flame
zone cooling/
reduce residence
time
Inject reducing
agent
Effect on
Thermal NOX
Reduces 02 rich,
high NOX pockets
in the flame
Flame cooling and
dilution during
delayed mixing re-
duces peak temp.
Flame cooling in
low 62, low temp.
primary zone re-
duces peak temp.
Direct suppression
of thermal NOX
mechanism
Increased flame
zone cooling
yields lower peak
temperature
Increased flame
zone cooling
yields lower peak
temperature
Reduction
Effect on
Fuel NOX
Reduces exposure
of fuel nitrogen
intermediaries to
02
Volatile fuel N
reduces to N?
in the absence of
oxygen
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Ineffective
Minor direct
effect; indirect
effect on mixing
Ineffective
Reduction
Primary Applicable Controls
Operational
Adjustments
Low excess air
firing
Burner
adjustments
Burners out of
service; biased
burner firing
Reduced air
preheat
Load reduction
Burner tilt
Hardware
Modification
Flue gas
recirculation
(FGR)
Low NOX
burners
Overfire air
ports
Water injection,
FGR
Ammonia injec-
tion possible
on some units
Major Redesign
Optimum burner/
firebox design
Burner/firebox
design for two
stage combus-
tion
Enlarged firebox,
increased burner
spacing
Redesign heat
transfer sur-
faces, firebox
aerodynamics
Redesign convec-
tive section for
NH3 injection
T-1836
-------
Controlled mixing of fuel and air or use of fuel-rich
primary flame zone
— Decreased primary flame zone residence time
• Chemically reduced NO in postflame region by:
A
— Injection of reducing agent
Table 1-2 relates these control concepts to applicable combustion
process modifications and equipment types. The process modifications are
further categorized according to their role in the control development
sequence: operational adjustments, hardware modifications of existing
equipment or through factory installed controls, and, major redesigns of
new equipment. The controls for decreased 0? are also generally
effective for peak temperature reduction but have not been repeated.
1.3 SYSTEMS OF NOX EMISSIONS REDUCTION FOR COAL-FIRED BOILERS
The combustion modification controls reviewed for possible
application to industrial boilers included
• Low excess air (LEA)
• Staged combustion air (SCA)
~ Burners out of service (BOOS), not applicable to stokers
— Overfire (OFA) or sidefire (SFA) air
• Low NOV burners (LNB)
A
• Flue gas recirculation (FGR)
• Reduced air preheat (RAP)
• Load reduction (LR) or reduced combustion intensity (furnace
redesign)
• Ammonia injection
The following subsections discuss the selection of the best control
systems for coal-fired boilers.
1.3.1 Candidate Best Systems of Control for Coal-Fired Boilers
In selecting the best system of NO emissions reduction, many
A
factors have to be considered, including:
• Control effectiveness and applicability
• Reliability and availability
• Process impacts
t Capital and operating costs
• Energy impacts
• Environmental impacts
1-5
-------
The effectiveness of controls in reducing NOV emissions, and their
X
applicability to industrial boilers as well as their reliability, were
used to select preliminary candidate control systems. Techniques were
considered if they were expected to be available for new boilers sold in
1983 or sooner. Performance data for these preliminary candidates were
then carefully reviewed to identify any demonstrated or expected process
or environmental impacts. For example, major impacts such as severe
derating of the boiler can make a control option no longer viable.
Environmental impacts were evaluated through the analysis of measured or
postulated incremental emissions, other than NO , when controls are
/\
implemented. Finally, capital and operating costs, including energy
impacts, were considered. These costs were used to decide between
favorable alternative control options, or in the case of costly but highly
effective techniques, to defer application until stringent control levels
are absolutely necessary.
All of the above listed factors were considered by evaluating
detailed field test results when available and through discussions with
major equipment manufacturers and users, and control R&D groups.
Throughout this report there is much attention directed toward retrofit
field test applications. This is so because retrofit data are the only
documented information currently available.
In the ensuing discussion of emission control technologies,
candidate technologies were compared using three emission control levels
labelled "moderate, intermediate, and stringent." These control levels
were chosen only to encompass all candidate technologies and form bases
for comparison of technologies for control of specific pollutants
considering performance, costs, energy, and environmental effects.
From these comparisons, candidate "best" technologies for control
of individual pollutants are recommended for consideration in subsequent
industrial boiler studies. These "best technology" recommendations do not
consider combinations of technologies to remove more than one pollutant
and have not undergone the detailed environmental, cost, and energy impact
assessments necessary for regulatory action. Therefore, the levels of
"moderate, intermediate, and stringent" and the recommendation of "best
technology" for individual pollutants are not to be construed as
indicative of the regulations that will be developed for industrial
1-6
-------
boilers. EPA will perform rigorous examination of several comprehensive
regulatory options before any decisions are made regarding the standards
for emissions from industrial boilers.
Tables 1-3 and 1-4 list the candidates for best systems of NO
X
emissions reduction for pulverized coal-fired and stoker coal-fired
boilers, respectively. Also summarized in these tables are the control
effectiveness (percent NO reduction), operational impact, cost impact
which includes energy impact, environmental impact, and commercial
availabil ity.
Low Excess Air
Reducing the excess air level in the furnace has generally been
found to be an effective method of NO control for all fuels. In this
A
technique, the combustion air is reduced to the minimum amount required
for complete combustion, maintaining acceptable furnace cleanliness and
steam temperature. With less oxygen available in the flame zone, both
thermal and fuel NO formation are reduced. In addition, the reduced
A
airflow reduces the quantity of flue gas released per unit time resulting
in an improvement in boiler efficiency.
Overfire Air
Staged combustion through overfire air seeks to control NO by
/\
carrying out initial combustion in a primary, fuel-rich, combustion zone,
then completing combustion, at lower temperatures, in a second, fuel lean
zone. The overfire air technique involves firing the burners (or the
combustion bed in the case of stokers) more fuel rich than normal while
admitting the remaining combustion air through overfire air ports.
Overfire air is very effective for NO reduction and may be used with
A
all fuels.
Reduced Combustion Intensity
Reducing combustion intensity generally lowers thermal NO
A
formation. Reduced combustion intensity can be brought about by load
reduction (reduced firing rate) in existing units and by use of an
enlarged firebox in new units. NOX reduction field tests on industrial
boilers have been mixed, on a retrofit basis, but the technique is
probably best implemented as increased furnace plan area in new designs,
based on results for new utility boilers.
1-7
-------
TABLE 1-3. CANDIDATES FOR BEST SYSTEMS OF NOX EMISSIONS REDUCTION:
PULVERIZED COAL-FIRED BOILERS
Technique
Effectiveness4
(X NOX Reduction)
Operational Impact
Cost Impact0
Environmental Impact
Availability
oo
Low Excess Air
Over fire Air
Reduced
Combustion
Intensity
Low NOX
Burners
NH3 Injection
5-25
5-30
5 - 25
45 - 60
40 - 60
Increased boiler efficiency.
Possible Increased slagging,
corrosion. Perhaps slight
decrease In boiler
efficiency.
None. Best implemented as
increased furnace plan area
In new designs.
None expected. .
Possible Implementation dif-
ficulties. Fouling problems
with high sulfur fuels, load
restrictions. Close operator
attention required.
Increased efficiency offsets
capital and operating costs.
Major modification. Marginal
increase in cost for new
units.
Major modification. Marginal
Increase in cost for new
units.
Potentially most cost-
effective.
Several fold higher than
conventional combustion
modifications.
Possible Increased CO
and organic emissions.
Possible Increased
paniculate and
organic emissions.
None
None expected.
Possible emissions of
NH-, and byproducts.
Available
Commercially offered but
not demonstrated for this
boiler/fuel category
Technology transfer
required from utility
Industry
1981 - 1983C
Commercially offered
but not demonstrated
Effectiveness based on control applied singly
b
Incremental cost impact noting capacity/cost of boiler to which control is applied.
Deferences 2-79, 3-30
-------
TABLE 1-4. CANDIDATES FOR BEST SYSTEMS OF NOY EMISSIONS REDUCTION:
STOKER COAL-FIRED BOILERS
Technique
Effectiveness*
(I NOX Reduction)
Operational Impact
Cost Impact"
Environmental Impact
Availability
Low Excess Air
Over fire Air
5 - 25
5 - 25
NH, Injection
40 - 60
Possible grate overheat.
clinker formation. Increased
corrosion. Close operator
attention required.
Possible grate overheat.
clinker formation. Increased
corrosion. Close operator
attention required. Perhaps
slight decrease In boiler
efficiency.
Possible Implementation dif-
ficulties. Fouling problems
with high sulfur fuels, load
restrictions. Close operator
attention required.
Increased efficiency should
partially offset costs.
Major modification of grate
and OFA. probably costly.
Present units have OFA for
smoke control only.
Several fold higher than
conventional combustion
modifications.
Possible Increased CO.
organic, and panicu-
late emissions.
Possible Increased CO.
organic, and panicu-
late emissions.
Possible emissions of
NH and byproducts.
Available
RAO
Commercially offered
but not demonstrated
'Effectiveness based on control applied singly.
''incremental cost impact noting capacity/cost of boiler to which control is applied.
-------
Low NO Burners
Low NO burners are generally designed to reduce flame
A
turbulence, delay fuel air mixing, and establish fuel-rich zones where
combustion initially takes place. The longer, less intense flames
produced with low NO burners, as compared to those of conventional
A
burners, result in lower flame temperatures which reduce thermal NO
A
generation. Moreover, the reduced availability of oxygen in the initial
combustion zone inhibits fuel NO conversion. Low NO burners
A A
represent a developing technology that promises highly effective NO
A
control at relatively low cost.
Ammonia Injection
The technique reduces NO to N2 and ^0 with injection of
anmonia (NH.J at flue gas temperatures ranging from 1070 to 1270K (1470
to 1830°F). However, the method is very temperature sensitive with
maximum NO reductions occurring in a very narrow temperature window
around 1240 + 50K (1770 + 90°F). An elaborate NH3 injection,
monitoring and control system is required. The application of this
technique, especially to the severe flue gas environment from coal
combustion, is still several years away.
1.3.2 Best Systems of Control for Coal-Fired Boilers
The best systems of control were selected based on the criteria
discussed in the previous subsection, and are summarized in Table 1-5 for
boilers with heat input capacity >£9 MW (100 x 106 Btu/hr) and Table 1-6
for boilers <29 MW (100 x 106 Btu/hr). Best systems were selected by
boiler equipment type and suggested moderate, intermediate and stringent
level of control. Control effectiveness, operational impact, cost
including energy impact, environmental impact, and commercial availability
have already been summarized in Tables 1-3 and 1-4. It should be noted
that the suggested moderate control levels for the boiler/fuel categories
considered are generally conservative in the sense that demonstrated
control techniques have, in specific instances, achieved controlled NO
levels lower than the suggested moderate levels.
Spreader stoker boilers are listed in both Tables 1-5 (>_ 29 MW) and
1-6 ( <29 MW) because this design type is offered over a large range of
heat input capacities. However, because their average baseline emission
levels are relatively higher than those from other stoker designs, it is
1-10
-------
TABLE 1-5. BEST CONTROL SYSTEMS FOR COAL-FIRED INDUSTRIAL BOILERS WITH
HEAT INPUT >29 MW (100 x 106 Btu/Hr)a
Boiler Equipment Type
Pulverized Coal-Fired
Spreader Stoker
Baseline
NOX Emissions
ng/J (lb/106 Btu)
285 (0.663)b
265 (0.616)
Moderate
301 ng/J (0.7 lb/106 Btu)
No control necessary0
No control necessary
Level of Control
Intermediate
258 ng/J (0.6 lb/106 Btu)
1. Low excess air
2. Overfire air
Low excess air
Stringent
215 ng/J (0.5 lb/106 Btu)
1. Overfire air*
2. Low NOX burner***
3. Ammonia injectiond**
Low excess air/
Overfire air***
aLow excess air operation is recommended practice whenever controls are required. However combination of LEA and OFA
is not recommended for pulverized coal tangential units (see Section 3.2.1.2).
bWide range of baseline emissions reported (see Section 3.2.1.1)
^Some units may require low excess air.
°NH3 injection required only for those units with unusually high baseline emissions.
Commercially offered but not demonstrated for this boiler/fuel category.
**Commerc1ally offered buy not demonstrated.
***Under research and development.
T-1759
-------
TABLE 1-6. CANDIDATE BEST CONTROL SYSTEMS FOR COAL-FIRED INDUSTRIAL BOILERS WITH
HEAT INPUT <29 MW (100 x 106 Btu/Hr)
Boiler Equipment Type
Spreader Stoker
Chain Grate
Underfeed
Baseline
NOx Emissions
ng/J (lb/106 Btu)
265(0.616)
140(0.326)
150(0.349)
Moderate
215 ng/J (0.5 lb/106 Btu)
Low excess air/overfire air***
No control necessary
No control necessary
Level of Control
Intermediate
172 ng/J (0.4 lb/106 Btu)
Ammonia injection**
No control necessary
No control necessary
Stringent
129 ng/J (0.3 lb/106 Btu)
Ammonia injection**
Low excess air
Low excess air
**Commercially offered but not demonstrated.
***Under research and development.
i
i—•
ro
-------
recommended that spreader stokers be grouped with pulverized coal units as
far as potentially achievable emission control levels are concerned.
Spreader stokers are listed together with other stoker types in Table 1-6
solely because of similarities in designs and hence in applicable control
techniques.
Pulverized Coal-Fired Boilers
Low excess air or overfire air form the best system for moderate
(301 ng/J, 0.7 lb/106 Btu ) and intermediate (258 ng/J, 0.6 lb/106 Btu)
NO control for pulverized coal-fired industrial boilers. The moderate
/\
control level was not set lower than 301 ng/J because of the broad range
in baseline NO emissions for the six units tested, ranging from 174 to
/\
563 ng/J with most data from 201 to 296 ng/J, yielding an average baseline
of 285 ng/J. No significant correlation of emission levels with
(pulverized coal) boiler type or coal properties were evident from the
limited data.
Staged combustion with low excess air and overfire air should
achieve the stringent control level of 215 ng/J (0.5 lb/106 Btu). The
low excess air and overfire air control system has the primary advantage
over the other control systems because of its commercial availability and
its effectiveness. The cost of the system is not prohibitive when overfire
air ports are designed as a part of new boilers. In addition, careful
operation of staged air injection is not expected to seriously affect
emissions of other criteria pollutants. Burner stoichiometries in the
range of 100 to 110 percent would be adequate to achieve a 20 percent
NO reduction. At these stoichiometry levels, oxidizing atmospheres
A
would prevail in the furnace, thus minimizing concern over possible
furnace slagging and boiler tube wastage. However, achieving the stringent
NO emission level of 215 ng/J with combined low excess air and overfire
/\
air may require burner stoichiometries be reduced below 100 percent in
some cases. This low burner stoichimetry level would cause reducing
atmospheres in parts of the furnace, thus creating the potential for
corrosion of water tubes. Generally boiler manufacturers do not recommend
burner operation with stoichimetry levels below 100 percent primarily
because of increased corrosion potential. Therefore, low excess
1-13
-------
overfire air is recommended as the stringent control technique with the
provision that further field testing and demonstrations may be necessary.
Because of the possible operational problems associated with
overfire air, low NO burners were selected as the first backup
A
candidate for achieving the stringent control level. Reported NO
A
reduction efficiencies for utility size units are of the order of 45 to
60 percent. Similar reduction efficiencies are projected for the
industrial low NO burners under development. Therefore low NO
A A
burners are expected to easily meet the 215 ng/J control level, a
25 percent reduction from the average baseline level. Once developed, low
NO coal-fired burners for industrial boilers could become the best
A
control system because of the expected lower cost and other operational
advantages over the staged combustion method of overfire air.
If low NO burners are not commercialized by 1983, ammonia
A
injection is the alternative stringent contol system. However, NH3
injection is several times more costly than conventional combustion
modification controls. In addition, as a developing technology, there are
several implementation and operational problems that need to be resolved.
The optimal effectiveness for noncatalytic reduction of NO by NH, occurs
O
over a very narrow temperature range, around 1240 + 50K (1770 + 90 F).
Hence, precise location of the NH- injection ports is crucial. Since
the temperature profile in a boiler changes with load, NO control with
A
NH- may dictate load restrictions on the boiler. Other potential
problems include fouling and emissions of NH3 and byproducts. However,
a major strength of the technique is its potential for high NO removal
(40 to 60 percent).
Stoker Coal-Fired Boilers
Spreader stokers are the only major stoker boiler types with
average uncontrolled NO emissions above 258 ng/J (0.6 lb/106 Btu).
A
Low excess air and overfire air constitute the best candidate control
system capable of reductions to 215 ng/J (0.5 lb/10 Btu). However,
close operator attention will be required to avoid the problems of grate
overheat, clinker formation, and corrosion associated with firing at too
low excess air levels. Potential environmental impacts as increased
carbon monoxide, particulate, and organic emissions warrant further
testing. Any NO reduction below 215 ng/J (0.5 lb/10 Btu) can only
A
1-14
-------
be achieved with NH^ injection (an unproven technique), possibly down to
129 ng/J (0.3 lb/10° Btu).
The other major stoker types, chain grate and underfeed, have
average uncontrolled NO emissions below 172 ng/J (0.4 lb/10 Btu).
fi
Control of these units to 129 ng/J (0.3 lb/10 Btu) is possible with low
excess air. It should be emphasized that control data for stokers are
limited, and low excess air and overfire air represent the only
significant controls tested on stokers.
1.4 SYSTEMS OF N0x EMISSIONS REDUCTION FOR OIL-FIRED BOILERS
The combustion modification NO control techniques considered for
/\
oil-fired boilers are the same as those for coal-fired units, as listed at
the beginning of Subsection 1.3.
1.4.1 Candidate Best Systems of Control for Oil-Fired Boilers
Using the selection procedure discussed earlier, candidate best
control systems were identified and are listed in Table 1-7 for residual
oil-fired boilers and Table 1-8 for distillate oil-fired boil^s units.
Also summarized in these tables are the control effectiveness (percent
NOX reduction), operational impact, cost impact which includes energy
impact, environmental impact, and commercial availability. All of these
candidates, except for flue gas recirculation and reduced air preheat have
been described in the previous subsection on coal-firing.
Flue gas recirculation for NO control consists of extracting a
A
portion of the flue gas and returning it to the furnace, admitting the
flue gas through the burner windbox. Flue gas recirculation lowers the
bulk furnace gas temperature and reduces oxygen concentration in the
combustion zone. The former effect is probably dominant since flue gas
recirculation has been found to be most effective in reducing thermal
NO . Addition of flue gas recirculation to a boiler is a major
/\
modification: the fan, ductwork, dampers, and controls as well as
possibly having to increase existing fan capacity due to increased draft
loss, can represent a large investment.
Reducing the amount of combustion air preheat lowers the primary
combustion zone peak temperature, generally lowering thermal NO
production as a result. It is an effective technique applicable to the
clean fuels: distillate oil and natural gas. However, to prevent severe
energy penalties, an economizer should be substituted as a flue gas heat
recovery device.
1-15
-------
TABLE 1-7. CANDIDATES FOR BEST SYSTEMS OF N0y EMISSIONS REDUCTION:
RESIDUAL OIL-FIRED BOILERS X
Technique
Lou Excess Air
Staged
Coabustion
Lo« NO
Burners
HHj Injection
Effectiveness*
(S NO, Reduction)
S - 20
20 - 40
20 - SO
40 - 70
Operation*! lapact
Increased boiler efficiency.
Perhaps slight decrease In
boiler efficiency.
None expected.
Possible implementation dif-
ficulties. Fouling problem
with high sulfur fuels. load
restrictions. Close operator
attention required.
Cost l«paclb
Increased efficiency par-
tially offsets costs.
Hajor Modification, perhaps
costly.
Potentially aost cost-
effective.
Several fold higher than
conventional conbustion
•edification.
EnvlroejKntal Impact
Possible increased CO
and organic emissions.
Possible increased
partlculate and organic
Missions.
MM expected.
Possible enissions of
NHj and byproducts.
Availability
Available
Conmercidlly offered but
not demonstrated for
this boiler/fuel category
Conmerc tally offered but
not deaonstrated
Conmercially offered but
not deaonstrated
Effectiveness based on control applied singly.
blncreaental cost inpact noting capacity/cost of boiler to which control is applied.
CT>
-------
TABLE 1-8. CANDIDATES FOR BEST SYSTEMS OF NO EMISSIONS REDUCTION:
DISTILLATE OIL- AND GAS-FIRED BOlCERS
lec Unique
LM licess Air
Stayed
Combustion
flue Gas
Reclrculatlon
Reduced Air
Preheat
tow NO
Burner?
Effectiveness*
(I NOM Reduction)
5-15 (oil),
5 - 10 (gas)
20 - 40 (oil).
2S - 45 (gas)
40 - 70 (oil)
4S - 75 (gas)
20 - 55 (oil)
20 - 55 (gas)
20 - SO
Operational Impact
Increased boiler efficiency.
Perhaps slight decrease in
boiler efficiency.
Possible flaw Instability.
Can be eliminated with proper
engineering/ test Ing.
Replacing air preheater with
economizer In MO designs.
None expected.
Cost impact
Increased efficiency should
offset some of costs.
Major modification, probably
costly.
Major modification, probably
costly.
None, other than engineering
redesign of new units (If
necessary).
Potentially most cost-
eflecti»e.
Environmental Impact
Passible increased CO
and organic emissions.
Possible increased
organic emissions.
Possible increased
organic emissions.
None
None eipected.
Availability
Available
Commercially offered but not demonstrated
for this boiler/fuel catetory
Available
Availably
Commercially offered but not demonstrated
'Effectiveness based on control applied singly.
"incremental cost impact noting capacity/cost of boiler to xhich control is applied.
-------
1.4.2 Best Systems of Control for Oil-Fired Boilers
Best systems of control for residual oil- and distillate oil-fired
boilers are summarized in Tables 1-9 and 1-10, respectively. Best systems
were selected by boiler equipment type and suggested moderate,
intermediate, and stringent level of control.
Residual Oil-Fired Boilers
Since baseline NO emissions from residual oil-fired firetube
c
boilers averaged only 115 ng/J (0.267 lb/10 Btu) no controls are
generally necessary to meet the moderate control level of 129 ng/J
(0.3 lb/106 Btu). Low excess air firing should achieve the intermediate
level of control, 108 ng/J (0.25 lb/106 Btu). Low excess air operation
should also increase boiler efficiency. The same caution about possible
increased CO and organic emissions discussed for coal-firing under low
excess air apply here also. Stringent control, 86 ng/J (0.2 lb/106 Btu),
will require either low NO burners or staged combustion, neither one of
/\
which is demonstrated technology for the small firetube designs. Low NO
A\
burners were selected as the first choice because of their potential for being
the most cost-effective, high-reduction combustion modification technique.
The generally larger watertube boilers with higher NO emissions
n
will also need the same controls, low excess air, low NO burners, and
A
staged combustion, only sooner (e.g., moderate level). Staged combustion
is a demonstrated technique for the large multiburner watertube boilers.
However, if low NO burners are commercialized in time for stringent
fi
control, 86 ng/J (0.2 lb/10° Btu), they should prove more cost-effective.
The only other alternative for stringent control is ammonia injection.
Although demonstrated and in limited commercial operation for oil- and
gas-firing in Japan, this control system represents a severalfold more
costly alternative for NO reduction than the other two systems. In
/\
addition, operational problems and potential emissions of NH3 and
byproducts cause environmental concern.
It should be noted that the above discussed controlled emission
levels for residucl oil firing may be difficult to achieve for boilers
firing high nitrogen content fuel (e.g., >0.3 weight percent nitrogen).
Indeed there is a possible trend of increasing total NO emissions with
A
fuel nitrogen content, unlike the behavior exhibited by coal-fired
1-18
-------
TABLE 1-9. BEST CONTROL SYSTEM FOR RESIDUAL OIL-FIRED INDUSTRIAL BOILERS3
Boiler Equipment Type
Baseline
NOX Emissions
ng/J (lb/106 Btu)
Level of Control
Moderate
129 ng/J (0.3 1b/l()6 Btu)
Intermediate
106 ng/J (0.25 lb/l()6 Btu)
Stringent
86 ng/J (0.2 lb/10.6 Btu)
Firetube
Watertube
115 (0.267)
160 (0.372)
No control necessary
1. Low excess air
2. Low NOX burners**
3. Staged combustion*
Low excess air
1. Low NOX burners**
2. Staged combustion*
1. Low NOX burners**
2. Staged combustion***
1. Low NOX burners**
2. Ammonia injection**
aLow excess air is recommended practice whenever controls are required.
Commercially offered but not demonstrated for this boiler/fuel category.
"Commercially offered but not demonstrated.
***Research and development.
T-1760
-------
TABLE 1-10. BEST CONTROL SYSTEMS FOR DISTILLATE OIL-FIRED INDUSTRIAL BOILERSa
Boiler Equipment Type
Baseline
NOX Emissions
ng/J (lb/106 Btu)
Level of Control
Moderate
86 ng/J (0.2 lb/l()6 Btu)
Intermediate
65 ng/J (0.15
Btu)
Stringent
43 ng/J (0.1 Ib/lO* Btu)
Firetube
Watertube not equipped
with air preheater
Watertube equipped with
air preheater
75 (0.175)
55 (0.128)
90 (0.209)
No control necessary
No control necessary
Low excess air
Low excess air
No control necessary
1. Reduced air preheat
2. Flue gas recirculation
3. Low NOX burners**
4. Staged combustion*
1. Flue gas recirculation
2. Low NOX burners**
1. Flue gas recirculation
2. Low NOX burners**
3. Staged combustion air*
1. Reduced air preheat
+ flue gas recirculation
2. Reduced air preheat
+ Low NOX burners**
ro
O
aLow excess air operation is recommended practice whenever controls are required
Commercially offered but not demonstrated for this boiler/fuel category.
"Commercially offered but not demonstrated.
T-1761
-------
boilers. A possible controlled (low excess air operation) N0v level is
200 ng/J (0.47 lb/106 Btu) ft
Distillate Oil-Fired Boilers
fi x
200 ng/J (0.47 lb/10 Btu) for high nitrogen content residual oil.
NO emissions from distillate oil combustion are primarily from
A
thermal NO formation. The relatively low uncontrolled baseline NO
/\ /\
emissions of distillate oil-fired boilers permit achievement of very low
controlled NO levels: 86, 65, and 43 ng/J (0.2, 0.15, and 0.1 lb/106 Btu),
/\
These control levels can in most cases be met with commercially available
techniques. Table 1-10 lists the best control systems for moderate,
intermediate, and stringent control of distillate oil-fired boilers. The
preferred control systems are low excess air, reduced air preheat, flue
gas recirculation, and low NOV burners, in that order, lowering NO
(\
down to 65 ng/J (0.151b/10 Btu). Distillate oil- and natural gas-fired
boilers not equipped with air preheaters (all firetubes, some watertubes)
exhibited significantly lower NO emissions than those with air
X
preheaters, irrespective of boiler heat input capacity. Those boilers
without air preheat can reach 43 ng/J (0.1 lb/10 Btu) with just flue
gas recirculation, while air preheater- equipped boilers require combined
reduced air preheat and flue gas recirculation.
Replacing the air preheater with an economizer in a new boiler is
the best way to implement reduced air preheat with no energy loss. Flue
gas recirculation, combined with reduced air preheat, is the best
stringent control technique because of its demonstrated high effectiveness
for clean fuels (distillate oil and natural gas). Potential operational
problems such as flame instability should be eliminated with proper
engineering and testing. Environmental impacts such as possible increased
organic emissions are expected to be minimal, although further
investigation is definitely called for.
1.5 SYSTEMS OF NOV EMISSION REDUCTION FOR GAS-FIRED BOILERS
/\
The NO emissions characteristics and control strategies for
A
gas-fired boilers are nearly identical to those for distillate oil-fired
units. Therefore, the discussion in the previous subsection on distillate
oil-firing is directly relevant here and will not be repeated. Table 1-8
1-21
-------
summarizes the candidates for best system of reduction, while Table 1-11
summarizes the best control systems and levels of control achievable.
1.6 ENERGY IMPACT
Although energy considerations were certainly included in the
selection of best controls discussed in Sections 1.3 through 1.5, a
general summary of energy impacts of combustion modification NO
/\
controls is useful here. Of the control methods reviewed, low excess air
is the most fuel efficient. Low excess air should be used with most
control methods to increase thermal efficiency and reduce NO
/\
emissions. Staged combustion air ports can be located so that thermal
efficiency is not decreased if they are used with low excess and only one
type of fuel is burned. For boilers that burn several fuels, several air
ports would be needed and these ports may not always be in just the
optimal location. Except for increased fan power use, boilers could be
designed so that flue gas recirculation would not decrease thermal
efficiency significantly. In some tests this was not always the case.
Low NO burners are the most promising new technology. Ignoring NH,
X j
and carrier gas, ammonia injection appears to have only a minor energy
impact though for raw material consumption, operational, and environmental
reasons it might not be desirable. For new distillate oil- and gas-fired
boilers, economizers are recommended over air preheaters as energy saving
devices.
In summary, combustion modification NO controls for new
X
industrial boilers should only have a minor energy impact. In fact, with
proper boiler design and control implementation, it might even be possible
in some cases to significantly lower N0x emissions and use less energy.
1.7 COST IMPACT
Although cost considerations were certainly included in the selection
of best controls discussed in Sections 1.3 through 1.5, a general summary
of cost impacts of combustion modification NO controls is useful here.
rt
The primary contributions of combustion modification NO controls
/\
to steam costs changes are the equipment modification costs and changes in
thermal efficiency and fan power demand. For firetube boilers annualized
equipment costs are usually higher than costs due to efficiency or fan
power demand changes. For watertube boilers, the opposite is usually
true. For both firetube and watertube boilers, all costs are important
and any factors that can lower any of these costs will be beneficial. In
1-22
-------
TABLE 1-11. BEST CONTROL SYSTEMS FOR NATURAL GAS-FIRED INDUSTRIAL BOILERSa
Boiler Equipment Type
Firetube
Water tube not equipped
with air heater
Watertube equipped with
air heater
Baseline
NOX Emissions
ng/J (lb/10& Btu)
40 (0.093)
45 (0.105)
110 (0.256)
Level of Control
Moderate
86 ng/J (0.2 Ib/lO^ Btu)
No control necessary
No control necessary
1 . RAPb
2. FGR
3. SCA*
4. LNB**
Intermediate
65 ng/J (0.15 lb/K)6 Btu)
No control necessary
No control necessary
1. RAP + FGRb
2. RAP + LNB**
3. RAP + SCA*
Stringent
43 ng/J (0.1 lb/10& Btu)
No control necessary
Low excess air
1. RAP + FGRb
2. RAP + LNB**
3. RAP + NH3**
injection
I
ro
oo
aLow excess air operation is recommended practice whenever controls are required.
bRAP = Reduced Air Preheat
FGR = Flue Gas Recirculation
SCA = Staged Combustion Air
LNB — -
Low NOX Burners
Commercially offered but not demonstrated for this boiler/fuel category.
^Commercially offered but not demonstrated.
T-1762
-------
many cases, using the lowest possible excess air will lower the cost
impact. Of course, the boiler should be designed to give the highest
possible thermal efficiency and lowest fan power requirements. Careful
design can result in better fuel efficiency than was assumed in the
economic analysis presented in this report.
Figures 1-1, 1-2, and 1-3 summarize the cost effectiveness of
typical combustion modification NO controls for representative coal-,
/\
residual oil-, and distillate oil-/natural gas- fired industrial boilers.
The estimated annualized control cost is plotted as a function of
achievable NO control level.
A
Of the NO controls covered in this report, low excess air is the
A
method recommended to be considered first since it can reduce fuel costs.
Low NO burners are a promising technique since they should allow both
low NO and low excess air operation, and thus save fuel while lowering
A
NO emissions. Staged combustion is the next best method, unless fuel
A
switching problems make it impractical. If staged combustion cannot be
used, flue gas recirculation is the next most cost-effective technique.
Ammonia injection is the least cost effective technique and load changing
may make it very impractical. Also, whenever possible, an economizer is
preferred over an air preheater as a fuel saving device since it does not
raise NO levels.
A
In sunmary, combustion modification NO controls, once proven and
A
demonstrated, should be a cost effective means of control for industrial
boilers raising steam costs up to only 1 to 2 percent in most cases.
However, the initial investment required, especially for small boilers,
may be a large fraction of the cost of the boiler itself, up to 25 percent
when controls are installed on a new boiler and up to 50 percent when
retrofitting the controls on an existing boiler. Factory installed
controls on new boilers should prove more cost effective than retrofit
controls.
1.8 ENVIRONMENTAL IMPACT
Although environmental considerations were certainly included in
the selection of best control discussed in Sections 1.3 through 1.5, a
general sunmary of environmental impacts of combustion modification NO
J\
controls is useful here.
1-24
-------
[ ] Indicates larger uncertainty
0 59 MW Pulverized Coal
X 44 MW Spreader Stoker
D 22 MW Chain Grate Stoker
O 9 MW Underfeed Stoker
8 60
0
o
i« 40
C 3
o o.
(_ > C
"Sli 20
TM (O
.1- 01
IB
=^ o
C l/>
4-1
LU
®[NH3 InJ,]
1
1
1
1
- -. I
^N. ®S^A> LNLEA
CK<^^ SCA ^^^^^ta
Baseline LEA
i I 1 I 1 I I I i i I i i 1 i i i I i I i I I i I i
0 50 100 150 200 250
NO ng/J Heat Input
Baseline
t___© Basel
I I 1 1
300
II)
n
Figure 1-1. Estimated annualized control cost versus NOX level for coal
fired boilers (costs are only first estimates).
1-25
-------
[ ] Indicates large
uncertainty
® 4.4 MW Firetube
o
o
120
90
o 3
o o.
HI. 60
• r~ 1C
r— IT
*Z
•3
C O
c-~
< I/I
•o^ 30
M\\ X SCA
LNB
Baseline /Baseline
X 44 MW Watertube
s
(I
rt
-30
I I I I I I I I I I I I I I I I I I
50 100 150 200
NO ng/J Heat Input
Figure 1-2. Estimated annualized control cost versus NOX emission level for
residual oil-fired boilers (costs are only first estimates).
1-26
-------
I/)
o
o
4-> O
c c
o >—
<_)
4.1
w— nl
(O (,!
3 o:
O
I
ro
100
90
80
70
60
50
40
30
20
10
0
FGR
0
Baseline
Natural Gas
[ ] Indicates large uncertainty
0 Distillate oil-fired
Nature 1 gcs-fired
Distillate Oil
00
in
u»
rl
N
LEA
Baseline
1 I I I 1 1 I I l I 1 I I I
10 20 30 40 50 60
NO nc/J Heat Input
70
Figure 1-3. Estimated annualized control cost versus NOX emission levels for distillate
oil and natural gas fired 4.4 MW firetube boiler (costs are first estimates
only).
-------
In general, no serious environmental impacts are expected for the
control techniques recommended in this report. However, more field
testing is required to quantify and establish that statement.
Tables 1-12 through 1-15 compare the recommended NOV control
A
techniques, the levels of control achievable, and the resulting
incremental changes in other pollutant emissions. Where actual data are
not available, a postulated effect is presented.
Carbon monoxide levels generally increase with NO control,
A
although this can be minimized if not eliminated with judicious
application of the control. Actual test data shows unburned hydrocarbon
emissions to be decreased more often than increased, though the data are
variable. Sulfate emissions decrease with decreasing oxygen content;
particulate emissions decrease due to an (assumed) increase in particulate
control device collection efficiency. The best NO control device for
A
industrial boilers firing coal appear to be low excess air and staged
combustion (overfire air), but information is too limited to be conclusive.
Low excess air and staged combustion (overfire air) appears to have
little effect on incremental emissions from residual oil-fired boilers.
For distillate oil- and natural gas-fired boilers, flue gas recirculation,
staged combustion, and reduced air preheat appear to be the best methods
available.
Incremental emissions are potentially increased by NO controls.
A
More data are needed to quantify the incremental emissions for each
control technique and to determine if any significant environmental impact
may result.
1-28
-------
TABLE 1-12. POSTULATED EFFECT OF CANDIDATE NO CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM COAL-FtRED INDUSTRIAL BOILERS
I
ro
Boiler
Coal-Fired Boiler ^29 MM
Coal-Fired Boilers < 29 MM
NOX Control
Technique
Low Excess Air
Overflre Air
Low NOX Burners
Aimonla Injection
Low Excess Air
Level of
Control
Moderate
Intermediate
Stringent
Intermediate
Stringent
Stringent
' Stringent
Intermediate
Stringent
Change in Incremental Emissions
CO
+
*
+
*
+
(*)
(NE)
-
V
UHC
-
-
V
(*)
+
(*)
(NE)
+
(*)
S03
(-)
-
-
(-)
-
(-)
(+)
(-)
(-)
Participate
(-)*
-
-
Ha
(-)a
(-)»
(NE)
-
(-)*
( ) No data available
Some decrease
* Some increase
+* Significant increase
v Variable results
NE No effect
^Assuming dust control devices are utilized, otherwise (+)
bAmnon1a injection may cause amnonia and byproduct emissions
T-1453
-------
TABLE 1-13. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM RESIDUAL OIL-FIRED
INDUSTRIAL BOILERS
NOX Control
Technique
Low Excess Air
Overfire Air
Low NOX
Burners
Ammonia
Injection*5
Level of
Control
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Intermediate
Stringent
Stringent
Change in Incremental Emissions
CO
+
4
•H-
( + )
+
•f
(*)
(NE)
UHC
( + )
V
V
(+)
+
+
(+)
(NE)
so3
(-)
-
-
(-)
(-)
-
M
(+)
Particulate
-
-
-
(-)*
-
-
(.)a
(NE)
( ) No data available
Some decrease
+ Some increase
•H- Significant increase
a Assuming dust control devices are utilized. Otherwise (+)
b Ammonia injection may cause ammonia and byproduct emissions
v Variable results
NE No Effect
1-30
-------
TABLE 1-14. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM DISTILLATE OIL-FIRED
INDUSTRIAL BOILERS
NOv Control
Technique
Low Excess Air
Flue Gas
Recirculation
Overfire Air
Reduced Air
Preheat
Low NOX
Burners
Level of
Control
Moderate
Intermediate
Stringent
Moderate
Intermedi ate
Stringent
Moderate
Intermediate
Change in Incremental Emissions
CO
(+)
•H-
(+*)
(+)
( + )
+
UHC
(+)
-
(+)
(+)
( + )
+
(+) (+)
A
Stringent j +
Intermediate
Stringent
Stringent
(NE)
(NE)
(*)
+
S03
(-)
(-)
(-)
(-)
(-)
(-)
(-)
(-)
Particulate
(_)a
(_)a
(•)•
(-)a
(_)a
(-)•
(-)a
+ I
(NE)
(NE)
(+)
(-)
(-)
(+)
(+)
(.)«
( ) No data available
Some decrease
+ Some increase
++ Significant increase
a Assuming dust control devices are utilized.
NE No Effect
Otherwise (+)
1-31
-------
TABLE 1-15. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM GAS-FIRED INDUSTRIAL BOILERS
NOX Control
Technique
Low Excess Air
Flue Gas
Recirculation
Overfire
Air
Reduced Air
Preheat
Low NOX
Burners
Level of
Control
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Stringent
Change in Incremental Emissions3
CO
+
+
+
(+)
(*)
-
+
+
-
+
+
+
(+)
UHC
( + )
-
( + )
(+)
(+)
( + )
( + )
( + )
-
(+)
(+)
(+)
( ) No data available
Some decrease
+ Some increase
•H- Significant increase
a $03 and particulate not present in natural gas
combustion products
1-32
-------
SECTION 2
EMISSION CONTROL TECHNIQUES
This section presents a survey of applicable combustion
modifications to reduce NO emissions from industrial boilers.
A
Industrial boilers can be defined as coal-, oil- or natural gas-fired
steam generators with heat input capacities usually ranging from 3 to 73
MW (10 to 250 x 105 Btu/hr). In fact, the current New Source
Performance Standards (NSPS) for utility boilers cover units >73 MW
(>250 x 106 Btu/hr) input (Reference 2-1). However, for the purposes of
this study, industrial units larger than 73 MW (250 x 10 Btu/hr) are
also covered. Indeed, nearly 14 percent of the total population of steam
generators in the industrial sector have capacities greater than 73 MW
(250 x 106 Btu/hr).
This section provides a review of current available knowledge of
the effectiveness, applicability and limitations of specific combustion
modifications for each major equipment/fuel category in the industrial
boiler sector. Major equipment and fuel categories for industrial boilers
have been identified as follows:
• Coal-fired
~ Pulverized coal, field-erected watertube
— Packaged and field erected stoker-fed watertube
t Oil-fired
— Residual oil, packaged and field erected watertube
~ Residual oil, packaged firetube
— Distillate oil, packaged and field erected watertube
~ Distillate oil, packaged firetube
2-1
-------
• Gas-fired
— Packaged and field erected watertube
— Packaged firetube
The category of stokers includes packaged underfeed units and field
erected spreader and chain grate units. These boiler categories include
the standard boiler types identified in the current EPA study of which
this work is a part (Reference 2-3).
However, the above list contains three additional industrial boiler
categories. These are gas- and distillate oil-fired watertube units and
residual oil-fired firetube units. These additional boiler types have
been selected primarily on two criteria. First, these boiler types have
different NO emissions characteristics and hence have different control
A
options. Second, a significant number of boilers within these three
categories have been extensively tested with combustion modifications.
This will be borne out in the subsequent sections. Thus a separate
discussion of these units is warranted.
The main discussion on combustion modifications for NO control
A
of industrial boilers is preceded by a brief overview of the mechanisms of
NO formation and the basic concepts for its reduction.
2.1 NO FORMATION MECHANISM AND PRINCIPLES OF CONTROL
A
Oxides of nitrogen formed in combustion processes are usually due
either to thermal fixation of atmospheric nitrogen in the combustion air,
leading to "thermal NO ", or to the conversion of chemically bound
A
nitrogen in the fuel, leading to "fuel NO ".* For natural gas and light
A
distillate oil firing, nearly all NO emissions result from thermal
A
fixation. With residual oil, crude oil, and coal, the contribution from
fuel-bound nitrogen can be significant and, under certain operating
conditions, predominant. A brief discussion of each of these two
mechanisms of NO formation follows.
2.1.1 Thermal N0v
A
The detailed chemical mechanism by which molecular nitrogen in the
combustion air is converted to nitric oxide is not fully understood.
*The term NOX includes all oxides of nitrogen, primarily NO and N02-
However, field test data have shown that over 95 percent of the NOX
formed in steam generators leaves the stack as NO (Reference 2-4).
2-2
-------
In practical combustion equipment, particularly for liquid or solid fuels,
the kinetics of the N^-O^ system are coupled to the kinetics of
hydrocarbon oxidation and both are influenced, if not dominated, by
effects of turbulent mixing in the flame zone. It is, however, generally
accepted that thermal NO forms at high temperatures in an excess of
/\
0?. The most widely accepted set of reactions that describes this
phenomenon is the chain mechanism proposed by Zeldovich (Reference 2-5):
N2 + 0 £ NO + N (2-1)
N + 02 Z NO + 0 (2-2)
N + OH Z NO + H (2-3)
Reaction (2-1) has a large activation energy (317 kJ/mol) and is generally
believed to be rate determining. Oxygen atom concentrations are assumed
to have reached equilibrium according to:
02 + MtO + 0 + M (2-4)
where M denotes any third substance (usually N_).
Experimental measurements of NO formation in heated mixtures of
N2, Oy and Ar at atmospheric pressures have shown that NO
concentration is strongly dependent on temperature (Reference 2-6).
Thermal NO formation is also dependent on the N9 concentration, the
/> L-
residence time, and the square root of 02 concentration according to the
following equation (Reference 2-6):
(-k?/T\ , /?
[NO] =4 e^ 2 I [N2] [02]1/21
where: [] = mole fraction
T = temperature (K)
t = residence time
k,, k2 = constants
Therefore, the formation of thermal NOV can be reduced by four
J\
tactics: (1) reduce nitrogen level, (2) reduce oxygen level, (3) reduce
peak temperature, and (4) reduce time of exposure at peak temperature. In
2-3
-------
typical hydrocarbon-air flames, the N2 mole fraction is of the order 0.7
and is relatively difficult to modify. Therefore, field practice has
focused on reducing oxygen level, peak temperature, and time of exposure
in the NO -producing region of the combustor (Reference 2-7): These
parameters are in turn dependent on secondary combustion variables such as
combustion intensity and internal mixing in the flame zone -- effects
which are ultimately determined by primary equipment and fuel parameters
over which the combustion engineer has some control.
Combustion modification techniques such as lowered excess air and
staged combustion have been used to lower local CL concentrations. Flue
gas recirculation and reduced air preheat have been used in boilers to
lower peak flame temperatures. Flue gas recirculation reduces residence
time at peak temperatures, although the primary effect is through
temperature reduction and lowered 0~ concentration.
Controlling the mixing between fuel, combustion air and
recirculated products has also been found to reduce thermal NO
A
formation. Burner swirl, combustion air velocity, fuel injection angle
and velocity, burner divergent angle and confinement ratio all affect the
mixing between fuel combustion air and recirculated products.
Unfortunately, generalizing these effects is difficult, because the
interactions are complex. Increasing swirl, for example, may both
increase entrainment of cooled combustion products (hence lowering peak
temperatures) but it may also increase fuel/air mixing (raising local
combustion intensity). Thus, the net effect of increasing swirl can be to
either raise or lower NO emissions, depending on other system
A
parameters (Reference 2-10).
2.1.2 Fuel NO
A
The role of fuel-bound nitrogen as a source of NO emissions from
A
combustion sources has been recognized since 1968 (Reference 2-8).
Although the relative contribution of fuel and thermal NOX to total
NO emissions fiom sources firing nitrogen-containing fuels has not been
A
definitively established, recent estimates indicate that fuel NO is
A
significant and may even predominate. In fact, laboratory studies under
controlled operating conditions have shown that fuel NO can account for
A
50 percent of the total NO for residual oil and up to 80 percent for
A
2-4
-------
coal (Reference 2-9). Therefore, as coal is increasingly used as a
national energy source, the control of fuel NO will become more
/x
important.
The following discussion is directed mainly toward fuel NO
n
formation from coal, though fuel NO is also a problem with other
A
nitrogen-containing fuels as well. A recent review of published data
indicated that, in general, anywhere from 20 to 90 percent of fuel
nitrogen in oil is converted to NO while the percentage of fuel
/\
nitrogen converted to NO in coal ranges from 5 to 60 (Reference 2-10).
/\
Figure 2-1 illustrates the nitrogen content of various U.S. coals,
expressed as ng N02 produced per Joule for 100 percent conversion of the
fuel nitrogen. The figure clearly shows that if all coal-bound nitrogen
was converted to NO , emissions for all coals would exceed the
coal-fired utility boiler NSPS of 301 ng/J (0.7 lb/106 Btu) implemented
in 1971. Fortunately, only a fraction of the fuel nitrogen is converted
to NO for both oil and coal firing (Reference 2-11, 2-12).
A
Furthermore, the percentage of fuel nitrogen conversion appears to
decrease as the fuel nitrogen content increases. Recent data from
combustion of coal in utility boilers exhibited fuel nitrogen conversion
ranging from 6.5 percent to 15 percent, with the possible correlation of
conversion increasing with the ratio of coal oxygen to coal nitrogen
(References 2-72 and 2-73). An EPA field test program on industrial
boilers confirmed the trend of increasing fractional conversion of fuel
nitrogen with decreasing nitrogen content. An average conversion of 46
percent was found for residual oil, and nearly 100 percent for distillate
oil (Reference 2-20).
Thus, although fuel N0x emissions undoubtedly increase with
increasing fuel nitrogen content, the emissions increase is not
proportional (Reference 2-11). In fact, data on tangential coal-fired
boilers indicate only a slight increase in total NO emissions as fuel
n
nitrogen increases. This is shown in Figure 2-2 (Reference 2-13). One
recent report comparing two similar wall-fired utility boilers claimed a
23 percent reduction in fuel NO with a 15 percent reduction in fuel
A
nitrogen, on a ng nitrogen/J heat input basis (Reference 2-70). However
the lower NO producing coal also had a higher moisture content which
/\
would have tended to reduce NO emissions. The data collected on
/\
2-5
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Figure 2-2. Nitric oxide emission as measured vs. coal nitrogen content (Reference 2-13).
-------
industrial boilers by KVB under an EPA sponsored field test program
indicated that no direct correlation between total NOX emissions and
coal fuel nitrogen, per se, exists (Reference 2-20). The tentative
generalizations that can be made at this time are that the higher nitrogen
fuels do produce more NO in the order coal, residual oil, distillate
A
oil, natural gas, but within a given fuel category, e.g. coal, no definite
conclusions can be drawn. Since field experience is not definitive, a
review of the current fundamental theories of fuel NO formation may be
A
profitable in developing control strategy.
In general, fuel NO formation is the product of oxidation of the
A
nitrogen in the volatiles and in the char of the coal. The oxidation of
char nitrogen to NO proceeds much more slowly than the oxidation of
volatilized nitrogen. In fact, based on a combination of experimental and
empirical modeling studies, it is now believed that 60 to 80 percent of
the fuel NO results from volatile nitrogen oxidation (References 2-11
A
and 2-14). Conversion of the char nitrogen to NO is in general lower, by
factors of two to three, than conversion of total coal nitrogen
(Reference 2-15).
Regardless of the precise mechanism of fuel NO formation,
A
several general trends are evident, particularly for coal combustion. As
expected, fuel nitrogen conversion to NO is highly dependent on the
fuel/air ratio for the range existing in typical combustion equipment
(Reference 2-16). This behavior is due largely to volatile NO formation,
while oxidation of the char nitrogen is relatively insensitive to fuel/air
changes.
In contrast to thermal NO , fuel NO production is relatively
A X
insensitive to small changes in combustion zone temperature (Reference
2-15). Char nitrogen oxidation appears to be a very weak function of
temperature, and although the amount of nitrogen volatiles appears to
increase as temperature increases, this is believed to be partially offset
by a decrease in oercentage conversion (Reference 2-15). Furthermore,
operating restrictions severely limit the magnitude of actual temperature
changes attainable in current systems.
As described above, fuel NO emissions are a strong function of
A
fuel/air mixing. In general, any change which increases the mixing
between the fuel and air during coal devolatilization will dramatically
2-8
-------
increase volatile nitrogen conversion and increase fuel NO. In contrast,
char NO formation is only weakly dependent on initial mixing and therefore
may represent a lower limit on the emission level which can be achieved
through burner modifications (Reference 2-10).
In principle, the best strategy for fuel NO abatement combines
/\
low excess air firing, optimum burner design, and staged combustion.
Assuming suitable stage separation, low excess air (LEA) may have little
effect on fuel NO, but it increases system efficiency. Before using LEA
firing, the need to get good carbon burnout and low CO emissions must be
considered.
Optimum burner design ensures locally fuel-rich conditions during
devolatilization, which promotes reduction of volatilized nitrogen
compounds to N~. Staged combustion produces overall fuel-rich
conditions during the first 1 to 2 seconds and promotes the reduction of
NO to N~ through reburning reactions. High secondary air preheat also
appears desirable, because it promotes more complete nitrogen
volatilization in the fuel-rich initial combustion stage. This leaves
less char nitrogen to be subsequently oxidized in the fuel-lean second
stage. Unfortunately, it also tends to favor thermal NO formation, and at
present there is no general agreement on which effect dominates
(Reference 2-10).
2.1.3 Principles of Control
In summary of the above discussion, both thermal and fuel NO are
/\
far below the levels which would prevail at equilibrium at peak
temperature. Thus, the rate of formation of both thermal and fuel NO
x
is dominated by combustion conditions and is amenable to suppression
through combustion process modifications. Although the mechanisms are
different, both thermal and fuel NO are promoted by rapid mixing of
/\
oxygen with the fuel. Additionally, thermal NO is greatly increased by
/\
increased residence time at high temperature. The modified combustion
conditions and control concepts which have been tried or suggested to
combat the formation mechanisms are as follows:
• Decrease primary flame zone 0^ level by:
— Decreased overall 02 level
— Controlled mixing of fuel and air
— Use of fuel-rich primary flame zone
2-9
-------
• Ufccr^ase time of exposure at high temperature by:
— Decreased peak temperature:
• Decreased adiabatic flame temperature through dilution
• Decreased combustion intensity
• Increased flame cooling
• Controlled mixing of fuel and air or use of fuel-rich
primary flame zone
~ Decreased primary flame zone residence time
• Chemically reduce NO in post-flame region by:
/\
-- Injection of reducing agent
Table 2-1 relates these control concepts to applicable combustion
process modifications and equipment types. The process modification are
further categorized according to their role in the control development
sequence: operational adjustments, hardware modifications of existing
equipment or through factor installed controls, and, major redesigns of
new equipment. The controls for decreased Op are also generally
effective for peak temperature reduction but have not been repeated.
Table 2-2 summarizes the availability and status of the primary
controls shown in Table 2-1 as applicable to the major boiler fuel type
categories identified earlier. The following subsections review the
status and performance of each of these applicable controls.
2.2 COAL-FIRED BOILERS
Industrial coal-fired boilers are of both the pulverized and stoker
types. Pulverized coal-fired boilers are usually limited to sizes greater
than 29 MW heat input (100 x 106 Btu/hr) (Reference 2-17) and account
for 3.9 percent of the total industrial boiler population (Reference 2-2).
Stokers, instead/ range from less than 0.3 MW to 120 MW of heat input (1 to
400 x 106 Btu/hr) and account for 11.25 percent of the total industrial
boiler population (Reference 2-2).
Two basic designs exist for industrial boilers burning pulverized
coal: single wall and tangential. However, cyclone boilers are often
included in this fuel type category even through the coal they burn is not
pulverized but crushed.
As already discussed in Subsection 2.1 on NO formation
/\
mechanisms, and will be further elaborated in this subsection as well as
Section 3, there are insufficient emissions data on coal-fired industrial
2-10
-------
TABLE 2-1. SUMMARY OF COMBUSTION PROCESS MODIFICATION CONCEPTS (REFERENCE 2-10)
Combustion
Conditions
Decrease
primary
flame zone
02 level
Decrease
peak
flame
temperature
Chemically
reduce NOX
in post
flame region
Control Concept
Decrease overall
0? level
Delayed mixing
of fuel and air
Primary fuel -rich
flame zone
Decrease
adiabatic flame
temperature
Decrease
combustion
intensity
Increased flame
zone cooling/
reduce residence
time
Inject reducing
agent
Effect on
Thermal NOX
Reduces 02 rich,
high NOX pockets
in the flame
Flame cooling and
dilution during
delayed mixing re-
duces peak temp.
Flame cooling in
low 02, low temp.
primary zone re-
duces peak temp.
Direct suppression
of thermal NOX
mechanism
Increased flame
zone cooling
yields lower peak
temperature
Increased flame
zone cooling
yields lower peak
temperature
Decomposition
Effect on
Fuel NOX
Reduces exposure
of fuel nitrogen
intermediaries to
02
Volatile fuel N
reduces to N2
in the absence of
oxygen
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Ineffective
Minor direct
effect; indirect
effect on mixing
Ineffective
Decomposition
Primary Alplicable Controls
Operational
Adjustments
Low excess air
firing
Burner
adjustments
Burners out of
service; biased
burner firing
Reduced air
preheat
Load reduction
Burner tilt
Hardware
Modification
Flue gas
recirculation
(FGR)
Low NOX
burners
Overfire ait
ports
Water injection,
FGR
Ammonia injec-
tion possible
on some units
Major Redesign
Optimum burner/
firebox design
Burner/firebox
design for two
stage combus-
tion
Enlarged firebox,
increased burner
spacing
Redesign heat
transfer sur-
faces, firebox
aerodynamics
Redesign convec-
tive section for
NH3 injection
ro
T-1836
-------
TABLE 2-2. APPLICABILITY OF COMBUSTION MODIFICATION NO CONTROLS FOR
MAJOR INDUSTRIAL BOILER EQUIPMENT/FUEL TYPES
Fuel
Coal
Oil and Natural Gas
Equipment Type
Combustion
Modification
Low Excess Air
(LEA)
Load Reduction
(LR)
Staged Combustion
with Overfire Air
Injection (OFA)
Staged Combustion
with Burners out
of Service (BOOS)c
Flue gas Recircu-
1 at ion (FOR)
Low NO, Burners
(LNB)
Imnonia Injection
Reduced Air Preheat
(RAP)
New Furnace Design
(Decreased Heat
Release Rate)
Packaged and Field
Erected Stokers
Available but not
implemented9
Available but
not implemented
Available but
not implemented
Not applicable
Not applicable
Not applicable
Not available.
Limited research
Not available.
Limited research
Not available.
Limited research
Field Erected
Pulverized Coal
Available,
implemented on
limited basis
Available but
not implemented
Implemented on
limited basis
Available but
not implemented
Not available.
limited research
Not available.
RiDb status
Commercially
offered but not
demonstrated
Not available.
Fuel penalty
too high
Available but
not implemented
Field Erected
Water-tube
Available.
implemented on
limited basis
Available but
not implemented
Available but
not implemented
Available but
not implemented
Available
Commercially
offered but not
demonstrated
Commercially
offered but not
demonstrated
Available
Not available.
Limited research
Packaged
Water-tube
Available but
not implemented
Available but
not implemented
Not available
.R&Db status
Not applicable
for single
burner boilers
Available
Commercially
offered but not
demonstrated
Commercially
offered but not
demonstrated
Available
Not available.
Limited research
Packaged
Firetube
Available but
not implemented
Available but
not implemented
Not available
R4Db status
Not applicable
Available
Commercially
offered but not
demonstrated
Commercially
offered but not
demonstrated
Not applicable
Not available.
Limited research
'Means that control technique 1s commercially available, but is not presently being implemented
for emission control.
bRlrD, Research and Development.
c BOOS is considered a retrofit NOX control measure.
T-1746
2-12
-------
boilers to warrant a breakdown of baseline or achievablfe dontrol levels
based on coal type. The few boiler and coal types tested are not adequate
to establish the significance of any trends. In fact, as discussed
earlier, some of the so-called data trends are conflicting. Variations in
emissions from boiler to boiler (of the same firing type, etc.) are often
greater than possible variations due to coal type (see, for example,
Table 7-2).
Of the four single wall pulverized coal-fired boilers analyzed,
three showed baseline (normal operation) emissions of 174, 216 and 244 ng/J
(0.405, 0.502, and 0.567 lb/106 Btu) as N02 and the fourth showed baseline
emissions of 563 ng/J (1.31 lb/106 Btu) as N02 (References 2-18 and
2-19).* These boilers ranged in size from 46.7 to 117 MW (160 to 400 x
10 Btu/hr) with the fourth boiler having an input capacity of 76.2 MW
(260 x 106 Btu/hr). The large baseline emissions of the fourth unit
could not be explained by any significant differences in fuel properties,
boiler characteristics, or operating conditions. One cyclone boiler
tested emitted 494 ng/J (1.15 lb/106 Btu) as N02 at baseline
(References 2-18 and 2-20). Cyclone boilers are generally large NO
J\
producers; thus these high N0x levels are not surprising. A 66 MW
(225 x 106 Btu/hr) and a 94 MW (320 x 106 Btu/hr) tangential
coal-fired boiler were also tested. Baseline emissions were 234 and
296 ng/J (0.544 and 0.688 lb/106 Btu) as N02, respectively
(Reference 2-18). Because of the small number of boilers tested and the
small difference in the average NO emissions from tangential and single
/\
wall industrial boilers, their NO emissions will be averaged together
J\
in this study.
Emission data from industrial boilers burning pulverized coal are
limited to the six units above. However, large industrial boilers are
similar in design to utility boilers. Based on this similarity in design,
a direct comparison of NOX emissions can be made. Control techniques
applicable to utility boilers can often be applied to large industrial
boilers.
*Note: NOX emission data discussed in this report are all listed in
Section 7 along with boiler and fuel characteristics.
2-13
-------
Stojcers are classified according to the method of feeding fuel to
the furnace (Reference 2-17). The four major types are:
• Spreader
• Underfeed
0 Chain grate or traveling grate
• Vibrating grate
The type of stoker used in a given application is usually dependent
on the type of coal burned and the response time required for load
changes. For example underfeed stokers are best equipped to burn caking
coals and spreader stokers most easily follow fluctuating loads.
Generally stokers emit lower uncontrolled NO emissions than
A
pulverized coal-fired boilers. Reported baseline NO emissions vary
from 153 to 336 ng/J (0.356 to 0.781 lb/106 Btu) as N02 for spreader
stokers, 136 to 163 ng/J (0.317 to 0.379 lb/106 Btu) as N0? for
underfeed stokers and 100 ng/J to 178 ng/J (0.233 to 0.414 ng/J) as NO
for chain grate stokers (Reference 2-18 through 2-21).
The following subsections summarize the NO control techniques
A
via combustion modifications for these two major coal-fired industrial
boiler types: pulverized coal and stokers.
2.2.1 Applicable Control Techniques for Pulverized Coal-Fired Boilers
Field test data on combustion modifications to reduce NO
x
emissions from industrial boilers firing pulverized coal are very
limited. However, due to the basic similarity in equipment design between
the industrial and utility size boilers, applicable combustion
modifications estalbished for the smaller utility steam generators are
also applicable for the larger industrial size units. Added limitations
are present though when implementing these controls on the smaller
boilers. These limitations are discussed for each of the control
techniques.
Table 2-3 lists the combustion modifications which are applicable
to pulverized coal-fired boilers. Combustion modifications for which no
actual data exist for the industrial boiler size range have also been
included. The effectiveness and limitations of these individual
techniques are based on data reported for utility size boilers. The
information on the number of industrial size boilers tested clearly shows
that the data on control techniques for these units are indeed very
2-14
-------
TABLE 2-3. COMBUSTION MODIFICATION NO* CONTROLS FOR PULVERIZED COAL-FIRED INDUSTRIAL BOILERS
ro
i
Control
Technique
Low Excess Air
(LEA)
Burners Out of
Service (BOOS)
Overfire Air
Injection (OFA)
Flue Gas
Recirculation
Low NOX
Burners (LNB)
Ammonia
Injection
Reduced Load
Description of
Technique
Reduction of combus-
tion air.
One or more burners
on air only. Re-
mainder firing fuel
rich.
Secondary air from
OFA ports above fuel
rich firing burners
Recirculation of flue
gas to burner windbox
New burner designed
utilizing controlled
air-fuel mixing
Injection of NHj in
con vec live section of
boiler.
Reduction of fuel
and air flow to the
boiler.
Number of
Industrial
Boilers Tested
6
2
Effectiveness of
Control (Percent
NOX Reduction)
0-25
(avg. 8.9)
27-39
(avg. 33)
5-30
0-20
45-60
40-60
Varies from 45X
reduction to 41
increase in NOX
Range of
Application
Excess oxygen
reduced to 5.2% on
the average
Applicable only for
boilers with mini-
mum of 4 burners.
Burner stoichiometry
as low as 100X
Up to 25* of the flue
gas recirculated.
Prototype LNB limited
to size ranges above
100 MBtu/hr
Limited i>y furnace
geometry. NH3
injection rate
limited to 1.5
NH3/NO
Applicable to all
boilers. Load can
be reduced to 25*
of capacity.
Commercial
Availability/
R&D Status
Available
Available.
However, ex-
tensive engin-
eering work
necessary prior
to implementa-
tion.
Commercially
offered but not
demonstrated for
industrial size
boilers.
Not offered
because
relatively
Ineffective.
Still in the
development
stage. Proto-
type LNB availa-
ble from major
boiler mfrs.
Commercially
offered but not
demonstrated
Available now
but not imple-
mented because
of ddve- se
operational
impacts
Comments
Added benefits of tech-
nique include increase
in boiler efficiency,
limited by increase in
CO. HC and smoke
emissions. ,
Limited by the number
of burners available.
Load reduction required
in most cases. Pos-
sible increased slag-
ging, corrosion.
R -tuires installation
of OFA ports, etc.
Possible increased
slagging, corrosion.
Requires installation of
F6R ducts, fan, etc. Can
cause combustion insta-
bility. Burner windbox
may need extensive
modifications.
Active RID efforts
underway.
Probably best suited as
a new design feature
than a retrofit applica-
tion. Possible implemen-
tation and operational
problems.
Load reduction not ef-
fective because of in-
crease in excess 0?.
Best implemented with
increase in furnace
size for new boilers.
-------
limited. In fact/, the boilers that were tested were only tested for a
short period of time (generally <3 hours).
2.2.1.1 Low Excess Air
Reducing the excess air level in the furnace has generally been
found to be an effective method for NO control. In this technique, the
A
combustion air is reduced to the minimum amount required for complete
combustion, while maintaining acceptable furnace cleanliness, and steam
temperature. With less oxygen available in the flame zone, both thermal
and fuel NO formation are reduced. In addition, the reduced airflow
A
lowers the quantity of flue gas released resulting in an improvement in
boiler efficiency.
Low excess air operation is a relatively simple technique to
implement. It is applicable to all boiler types and requires only
reducing airflow to the burner windbox. However, in a multiburner unit,
modifications to the windbox might be necessary to improve air
distribution to individual burners during low excess air operation.
Lowering excess air reduces the safety margin for complete :combustion.
Therefore, close monitoring of flue gas 0? and CO may be necessary.
Baseline excess oxygen levels for single wall and tangential
pulverized coal-fired boilers investigated ranged from 4.5 to 8.6 percent
and averaged 6.3 percent (References 2-18 and 2-19). In these boilers
excess oxygen was reduced to 5.2 percent lowering NO emission by 8.6
J\
percent on the average.
The lone cyclone boiler (117 MW, 400 x 106 Btu/hr) tested was the
least amenable to excess oxygen reduction because of the initial low
baseline Op level. The excess oxygen measured 3.4 percent at baseline
and was reduced only to 3.1 percent for LEA firing. NO emissions were
A
reduced 5 percent for this test (References 2-4 and 2-18).
These excess oxygen levels were probably not representative of the
actual excess oxygen in the flue gas leaving the furnace. Air infiltration
into the boiler ducts for balanced draft boilers can dilute the flue gas
and cause oxygen readings to be higher than actual. However, field
investigations found that these units were, in general, being fired with
more than adequate excess air in order to assume complete combustion and
provide a margin of safety.
2-16
-------
Combustion with low excess air is a favorite NO' jtontrol
technique because it not only reduces NO by 25 ppm on the average for
each percent reduction in excess oxygen, but it also increases boiler
efficiency and furthermore is relatively easy to implement.
2.2.1.2 Overfire Air Injection (OFA)
The injection of air above the top burner level through OFA ports
together with a reduction in air flow to the burners is one of two
techniques used to obtain staged combustion in industrial size pulverized
coal-fired boilers. The other technique, burners out of service, is
discussed below in Section 2.2.1.3.
New utility tangential coal-fired boilers currently come equipped
with overfire air ports to help meet 1971 NSPS for NO emissions.
A
Overfire air ports on wall-fired boilers are not as common as for the
tangentially fired units. However, Babcock and Wilcox (B&W) has recently
installed two 190 MW (650 x 10 Btu/hr) pulverized coal-fired industrial
boilers equipped with OFA ports and compartmented windboxes to limit NO
emissions to 300 ng/J (0.7 lb/106 Btu) (References 2-22 and 2-23). In
these boilers, 105 percent of the total air requirement is added to the
burners, 10 percent through the OFA ports. Automatic controls determine
the difference between the total air requirements for the total fuel flow
to the furnace and the total air flow to the individual burner
compartments. This difference in air flow is then fed through the OFA
ports.
The combination of the compartmented windbox and careful airflow
control also improves the thermal efficiency of these new B&W units. B&W
provides oxygen analyzers on all new coal-fired industrial boilers.
Overfire air cannot be implemented on cyclone boilers because the cyclone
furnace cannot be fired substoichiometrically.
No detailed OFA test data have been reported for pulverized
coal-fired industrial boilers. Therefore the information listed in
Table 2-3 reflects results from utility boiler data (Reference 2-24).
Overfire air has been very effective in reducing NO for boilers of this
/\
size. In fact, 30 percent reductions have been reported for utility
2-17
-------
boilers of the tangential firing type. Potential limitations of the
technique include (References 2-25 and 2-26):
• Furnace tube wastage due to local reducing conditions when
firing high sulfur coal
• Tendency for slag accumulation in the furnace
• Additional excess air may be required to ensure complete
combustion resulting in a decrease in boiler efficiency.
Experience with utility boilers indicates, however, that these potential
problems can be overcome with proper implementation of staged combustion
(Reference 2-24.)
Overfire air is more attractive in original designs than in
retrofit applications. Additional duct work, furnace penetration, and
extra fan capacity may be required. In addition, physical obstructions
outside of the boiler may make retrofit installation difficult and
costly. There may also be insufficient height between the top row of
burners and the furnace exit to permit accommodation of overfire air ports
and the enlarged combustion zone created by the staged combustion
technique (Reference 2-25).
2.2.1.3 Burners Out of Service (BOOS)
Burners out of service is the other technique used to obtain staged
combustion in industrial pulverized coal-fired boilers. It is primarily
employed as a retrofit NO control measure for existing utility sized
J\
boilers. Ideally, all of the fuel flow is diverted from a selected number
of burners to the remaining firing burners. Since airflow is maintained
relatively unchanged among all burners a staged combustion effect is
obtained. For the technique to be significantly effective the top burners
must be set on air only. The technique, however, has several limitations
for pulverized coal-fired boilers. These limitations can be summarized as
follows:
1. Individual burners cannot be shut off because coal flow must be
terminated at a pulverizer. Since each pulverizer serves a
minimum of two burners, at least two burners must be removed
from service.
2. Indiscriminate selection of burners out of service is often not
possible because pulverizers may serve burners located on two
separate levels
2-18
-------
3. In many cases burners/pulverizers which operate Curing BOOS
cannot handle increased coal flow necessitating a significant
reduction in the boiler steam rating
4. Register adjustments are often necessary to divert some airflow
from top burners to lower burners. If satisfactory staging
conditions cannot be obtained simply by adjusting burner
registers, a compartmental windbox becomes necessary.
These limitation were clearly evident in the tests conducted on one
pulverized coal-fired industrial size boiler (76 MW heat input) equipped
with 4 burners in square matrix (Reference 2-20). To implement the BOOS
technique the pulverizer serving the top two burners was shut off
necessitating a 50 percent reduction in boiler load. In addition, airflow
could not be easily controlled to individual burners so that burner swirl
and coal air mixing were affected. The resultant NO reduction was
n
39 percent.
From this experience, it is evident that to implement the BOOS
technique with this burner pattern and the number of available burners
necessitates a reduction in the capacity of the boiler by up to 50 percent.
It is expected that this will often be the case for industrial boilers
because of the limited number of burners and pulverizers.
Since a reduction in boiler load is not desirable and often not
feasible, BOOS is not always a viable technique. A potential alternative
involves the installation of overfire air ports above existing burners if
there is space for the overfire air ports (already discussed in
Section 2.2.1.2).
2.2.1.4 Low NO Burners (LNB)
A
Prototype low NO pulverized coal-fired burners have been
3\
developed primarily for reducing NO emissions from utility boilers.
A
Their principal characteristics are reduced flame turbulance, delayed fuel
air mixing, and establishment of fuel-rich zones where combustion
initially takes place (Reference 2-24). Prototype dual register burners
developed by Babcock and Wilcox (B&W) (References 2-27 and 2-28) and the
dual throat burners developed by Foster Wheeler (FW) (References 2-29 and
2-30) are being installed in new utility size coal-fired boilers. This
technology applies only to wall-fired boilers. NO reductions reported
A
2-19
-------
in Table 2-3 are basedJon results from B&W and FW utility application
testing because no industrial size low NO coal burner has yet been
A
developed.
Energy and Environmental Research Corporation (EER), under a
research contract to EPA, is developing advanced low NO burner concepts
A
such as distributed fuel/air mixing, as illustrated in Figure 2-3
(References 2-31 and 2-32). Field evaluation programs, also sponsored by
EPA, involving several manufacturers and R&D groups, are being planned
(Reference 2-79).
A low NO burner for industrial boiler application is under
rt
commercial development by Peabody Engineering Corporation. Peabody is
constructing a variation of a standard dual register type burner. The 50
x 10 Btu/hr burner may become one of several burners to be tested in an
EPA test program. Basically, the burner is designed to reduce the air in
the primary combustion zone. The resultant reduced flame temperatures
also serve to lower NO emissions. Once completed, the burner
A
presumably will not be restricted in size range and may be: suitable for
many pulverized coal facilities (Reference 2-33).
In some applications low N0x burners may have several advantages
over other combustion modifications such as staged combustion with OFA or
BOOS. For example, one utility boiler manufacturer claims that low NO
A
burners will maintain the furnace in an oxidizing environment, hence,
minimizing slagging and reducing the potential for furnace corrosion when
firing high sulfur coal (Reference 2-27). Also, more complete carbon
utilization may be achieved due to better coal/air mixing in the furnace.
Finally, lower oxygen levels may be obtained with all the combustion air
admitted through the burners (Reference 2-24).
Since the burners generally alter the flame configuration, care
must be taken when applying the burners to existing boilers. For
instance, the dual register coal burners have a longer flame length. The
burner can be installed only in those boilers which are large enough to
avoid cold wall impingement.
It is estimated that low NO burners will not be fully
/\
commercialized for the utility boilers for two more years. Its
application for industrial size pulverized coal-fired steam generators is
also a few years away.
2-20
-------
TERTIARY AIR
DIVIDED SECONDARY
AIR STREAM
COAL + PRIMARY AIR
ro
i
no
BURNOUT- ZONE
PROGRESSIVE
LEANING OUT
RICH HOT
RECIRCULATION ZONE
Figure 2-3. Distributed fuel/air mixing concept (Reference 2-31).
-------
2.2.1.5 Flue GaslReqirculation (FGR)
Flue gas recirculation for NO control consists of extracting a
portion of the flue gas from the economizer outlet and returning it to the
furnace, admitting the flue gas through the burner windbox. Figure 2-4
shows a schematic of a typical FGR installation. Flue gas recirculation
lowers the bulk furnace gas temperature and reduces oxygen concentration .
in the combustion zone (Reference 2-24).
Flue gas recirculation through the windbox and, to a lesser degree,
through the furnace hopper has been found to be very effective for NO
control on gas- and oil-fired utility boilers (References 2-26 and 2-34).
However, the technique was relatively ineffective on coal-fired units
because FGR mainly affects thermal NO , not fuel NO (Reference 2-35).
* X
Table 2-3 gives performance data on FGR with low excess air (LEA) on
opposed wall coal-fired utility boiler. These data show that for this
boiler, combined flue gas recirculation and low excess air can only reduce
NOX emissions by 20 percent (Reference 2-35). Similar results have been
reported elsewhere (Reference 2-10). The technique of low excess air
alone can often achieve similar reductions, as discussed earlier.
Burners
Air
Forced draft fan
Apportioning
dampers Flue gas recirculating
fan
Figure 2-4. Typical flue gas recirculation system for NOX control.
2-22
-------
No data are available for pulverized coal-f:|rejd industrial units
but as large industrial boilers are similar in design to utility boilers,
performance of F6R is not expected to vary greatly from this result.
Flue gas recirculation for NO control is less costly for new
A
designs than as a retrofit application. Retrofit installation of flue gas
recirculation can be quite costly. The fan, ductwork, dampers, and
controls as well as possibly having to increase existing fan capacity due
to increased draft loss, can represent a large investment. In addition,
the flue gas recirculation system itself may require a substantial
maintenance program due to the high temperature environment experienced
and potential erosion from entrained ash. Thus, the cost effectiveness of
this method of NO control for pulverized coal-fired boilers has to be
A
examined carefully when comparing it to other control techniques.
As a new design feature, the furnace and convective surfaces can be
sized for the increase in mass flow and change in furnace temperatures.
In retrofit applications, however, the increased mass flow increases
turbulence and mixing in the burner zone, and alters the convective
section heat absorption. Erosion and vibration problems may result
(References 2-34 and 2-74) and flame detection can be difficult. In
addition, controls must be employed to regulate the proportion of flue gas
to air so that sufficient concentration of oxygen is available for
combustion (Reference 2-75). In summary, the relatively small NO
t\
reductions obtained with FGR when firing coal may not warrant the large
investment for both a retrofit case or installation of FGR on new
industrial units.
2.2.1.6 Ammonia Injection
The process of injecting amnonia in the hot flue gas to reduce
NO emissions has been patented under the trade name Thermal DeNO by
A X
Exxon Research and Engineering Company (Reference 2-36). Experimental
data have shown that NH~ injection under well controlled laboratory
conditions, can result in NOV reductions as high as 90 percent
A
(Reference 2-37). Figure 2-5 (Reference 2-38) shows a schematic of a
retrofit application of a Thermal DeNO injection system on a large
A
industrial size boiler. The technique acts by reducing NO to elemental
nitrogen and oxygen with NHg at flue gas temperatures ranging from
2-23
-------
BOILER CIRCULATING
WATER FOR NOZZLE
COOLING (NOT A
STANDARD FEATURE)
INJECTIOr
NOZZLES
AIR HEATER
J n—&-
IKING CHAMBER
o
FORCED
DRAFT FAN
AIR FOR CARRIER BOOSTER FAN
Figure 2-5. Schematic diagram of the NH3 injection system
(Reference 2-38).
approximately 1070 to 1290K (1470 to 1856°F). However, optimal NO
reduction occurs over a very narrow temperature range, around 1240 + 50K
(1770 + 90°F).
The NO reduction effectiveness reported in Table 2-3 reflects
results from full-scale application of the ammonia injection process in gas-
and oil-fired industrial boilers in Japan (Reference 2-39). No full- scale
retrofit on a coal-fired unit has been accomplished so far. However, in
subscale tests it was found that the flue gas environment from coal
combustion does not markedly affect the effectiveness of the process any
more than that relative to gas and oil combustion products (Reference 2-40).
Ammonia injection has numerous limitations which have so far
prevented its full-scale commericalization as a NO reduction technique
2-24
-------
on coal-fired boilers. These limitations can be summarized is follows:
(References 2-37, 2-39 and 2-41).
• Performance is very sensitive to flue gas temperature, and is
maximized only within a 50K temperature gradient from the
optimum temperature of about 1240K. This temperature
sensitivity may require special procedures for load following
boilers.
• Performance is very sensitive to flue gas residence time at
optimum temperatures. High flue gas quench rates are expected
to reduce process performance.
• Costs of the process can be much higher than for other
combustion controls
• Successful retrofit application is highly dependent on the
geometry of convective section
• Byproduct emissions such as ammonium bisulfate might cause
operational problems, especially in coal-fired boilers
Although NH3 injection is currently being commercially offered,
it is not demonstrated technology. Therefore, it should be considered to
be still at the development stage (Reference 2-76). This technique might
prove to be, however, the only alternative in controlling NO emission
A
from cyclone-fired boilers which are not amenable to other combustion
modifications. Therefore, its use can potentially achieve NO emission
A
levels which would otherwise not be obtainable with current
state-of-the-art controls (Reference 2-39).
2.2.1.7 Load Reduction
Thermal NO formation generally increases as the volumetric heat
A
release rate or combustion intensity increases (Reference 2-10). Reduced
combustion intensity can be brought about by load reduction, or derating,
in existing units and by use of an enlarged firebox in new units.
However, during field tests on industrial boilers burning
pulverized coal, NO emissions were found to increase in some instances
A
when these boilers were operated below 60 percent of capacity (Reference
2-20). A load reduction of approximately 30 percent from the baseline
rating of 80 percent capacity increased NO emissions from three boilers
A
by 13 percent on the average. The reduced heat input was accompanied in
all cases by an increase in excess oxygen averaging 0.7 percent. One
2-25
-------
cyclone units/ however, showed a drop in NO emissions by 6 percent for
A
a load reduction of 25 percent (Reference 2-4). Thus, it seems that in
many cases any beneficial effects resulting from load reduction were
offset, by the increase in excess air required at the reduced load.
Reduced firing rate often leads to several operating problems.
Aside from the limiting of capacity, low load operation usually requires
higher levels of excess air to maintain steam temperature and to control
smoke and CO emissions. The steam temperature control range is also
reduced substantialy for those industrial boilers producing superheated
steam. This will reduce the operating flexibility of the unit and its
response to changes in load. The combined .results are reduced operating
efficiency due to higher excess air and reduced load following capability
due to a reduction in control range (Reference 2-10).
When the unit is designed for a reduced heat release rate, the
problems associated with derating are largely avoided. The use of an
enlarged firebox produces NO reductions similar to load reduction on
J\
existing units. This technique of larger firebox has been implemented on
new coal-fired utility boilers since about 1970 (Reference 2-24).
Generally, the size of these fireboxes has increased 30 percent partly in
response to 1971 NSPS for utility boilers and partly to facilitate
combustion of lower grade coals (Reference 2-42). Therefore, the
technique can also be considered available for large industrial size
pulverized coal-fired boilers. Babcock and Wilcox (B&W) is currently
considering power furnace loading as one of several techniques for
reducing NO emissions from their industrial boilers (Reference 2-43).
X
2.2.2 Applicable Control Techniques for Stokers
NO emissions from stokers are significantly lower than those
/\
from pulverized coal. These lower emissions have been attributed to the
lower combustion intensity and to the partial staged combustion that
naturally occurs during combustion on fuel beds (Reference 2-17).
Four methods have been used to modify the combustion of a stoker in
order to reduce NO emissions. These methods are (1) reduced undergrate
/\
air or low excess air, (2) overfire air, (3) reduced air preheat, and
(4) reduced heat input (References 2-4, 2-18, 2-19 and 2-21). Ammonia
injection is potentially applicable although it has not yet been
demonstrated on an industrial stoker. The boiler geometry and the flue
2-26
-------
gas temperature profile in a stoker should permit the implementation of
the NH~ injection process in a similar manner as for a pulverized
coal-fired unit. Table 2-4 lists information on the performance and
limitation of each of these techniques.
The information is based on limited data. A search for additional
data from boiler manufacturers and researchers has not revealed any other
applicable combustion modification for NO control for stokers
(References 2-44 through 2-48).
2.2.2.1 Low Excess Air (LEA)
Figure 2-6 is a schematic of a spreader stoker furnace showing
where combustion air is introduced in this type of boiler. Overfire air
is generally controlled independently from undergrate air. Low excess air
tests performed in the field consisted of reducing the undergrate airflow
while maintaining the OFA flow approximately as in normal operation.
Recently EPA field tests of 17 stokers indicate that the excess
oxygen levels at baseline operating conditions averaged about 9 percent
(References 2-4, 2-18 through 2-21). During low excess air tests, the
average excess oxygen level was reduced to 6.4 percent. Such reduction
lowered NO emission levels approximately 10 percent for each 1 percent
J\
reduction in excess oxygen (Reference 2-4, 2-20, 2-21, 2-48, and 2-49).
The minimum achievable excess air is limited by several factors.
Except for the water-cooled vibrating grate, the only cooling of the grate
is by the flow of air past it. If this air is cut back too much, the
grate can overheat. There is also the danger of creating local reducing
zones as the air is cut back and forming harmful corrosion products.
Another problem noticed during field tests has been the formation of
clinkers as the excess oxygen was reduced, the CO emissions tend to rise.
However, test results indicate that if excess oxygen levels are maintained
above 5 percent, CO emissions will tend to stay below 150 ppm (Reference 2-18,
2-20 2-21 and 2-49). Limited data show CO emissions for underfeed stokers
to be less sensitive to excess air levels than for spreader stokers
(References 2-4, 2-18 and 2-20).
Fuel combustion with lowest possible levels of excess air assures
maximum boiler efficiency unless the air is decreased to the point where
unburned carbon losses are greatly increased. From the limited amount of
data it can be tentatively generalized that if the airflow is maintained
2-27
-------
TABLE 2-4.
COMBUSTION MODIFICATION NOX CONTROLS FOR STOKER COAL-FIRED INDUSTRIAL BOILERS
Control
Technique
Low Excess
Air (LEA)
Staged
Combustion
(LEA + OFA)
Reduced Load
Reduced Air
Preheat (RAP)
Ammonia
I n j ec t i on
Description of
Technique
Reduction of air
flow under stoker
bed.
Reduction of under
grate air flow and
increase of over-
fire air flow.
Reduction of coal and
air feed to the
stoker.
Reduction of combus-
tion air temperature
Injection of NH3
in convective section
of boiler.
Number of
Industrial
Boilers Tested
15
5
13
1
Effectiveness of
Control (Percent
NOX Reduction)
5-25
5-25
Varies from 49X
decrease to 25X
increase in NOX
(average 15%
decrease)
8
40-60 (from gas-
and oil-fired
boiler exper-
ience).
Range of
Application
Excess 02 limited
to 5-6X minimum
Excess 02 limited
5t minimum.
Has been used down
to 25X load.
Combustion air
temperature reduced
from 473K to 453K.
Limited by furnace
geometry. Feasible
NHj injection rate
limited to 1.5 NH3/
NO
Commerical
Availability/
R&D Status
Available now
but need R&O
on lower limit
of excess air.
Most stokers
have OFA ports
as smoke control
devices but may
need better air
flow control
devices.
Available
Available now if
boiler has com-
bustion air
heater.
Not available.
Needs investiga-
tion of full
scale applica-
tion.
Comments
Danger of overheating
grate, clinker forma-
tion, corrosion, and
high CO emissions.
Need research to deter-
mine optimal location
and orientation of OFA
ports for NOX emission
control. Overheating
grate, corrosion and high
CO emission can occur if
under grate air flow is
reduced below acceptable
level as in LEA.
Only for stokers that
can reduce load without
increasing excess air.
Not a desirable tech-
nique because of loss in
boiler efficiency.
Not a desirable tech-
nique because of loss
in boiler efficiency.
Probably best suited as
a new design feature
than a retrofit applica-
tion. Possible implemen-
tation and operational
problems
ro
CO
T-1748
-------
Coil hoppv
Figure 2-6. Air injection in a traveling-grade spreader stoker
(Reference 2-17).
such that the excess oxygen level measures approximately 6 percent, no
serious optional or emission problem should result. Of course, this
generalization would require verification. Indeed, the minimum'excess
oxygen level for a particular boiler could be higher than 6 percent.
NOX emission reductions of about 5-25 percent and increases in boiler
efficiency of one percent can be expected with LEA provided fuel burnout
does not change during the process (References 2-4 and 2-20).
Research and developmental work on redesigning the grate and stoker
would be necessary if lower excess oxygen levels are required. In
addition a solution to the clinker formation problem will also be needed
for this type of operation.
2.2.2.2 Staged Combustion
One of the reasons N0x emission from stokers is lower than those
from pulverized coal-fired boilers is the partial staged combustion nature
of combustion of fuel beds (Reference 2-50). Volatile matter leaves the
2-29
-------
fuel bed as the coal is fed into the grate and burns above the bed level.
The solids are subsequently burned with lower combustion intensity.
An increased staged combustion effect beyond what seems to occur
naturally in the stoker furnace seems difficult to obtain. However,
augmented staged combustion control can be effected by injecting air above
the fuel bed through the overfire air ports (OFA) and reducing the
undergrate airflow.
Figure 2-6 shows the relative location of these airflows. A
reduction of 10 to 25 percent in NO has been achieved by this method
A
without increasing CO emission (References 2-4, 2-18, 2-20 and 2-49).
Most stokers have OFA ports as smoke control devices. Therefore, the
location or orientation of the OFA ports may not be the optimum in order
to achieve best NO reductions. For example, one test showed a
A
25 percent reduction in NO emissions by using two oil burners as
A
overfire air ports (Reference 2-4). However, these burner ports were
located far above the existing stoker OFA ports. Other OFA tests, using
only the existing OFA ports located closer to the fuel bed rather than
the burner ports, lowered NO emission only 10 percent.
A
This method suffers from the same disadvantages of LEA because
reduced undergrate airflow is absolutely necessary to achieve any staging
effect. Therefore limitations applicable to the technique of LEA such as
grate overheating, corrosion, and clinker formation can also limit the
application of the staged combustion technique.
2.2.2.3 Reduced Load
Underfeed stokers tend to produce lower NO emissions than
A
spreader stokers. One reason has been attributed to the fact that
underfeed stokers generally have larger fireboxes and consequently lower
volumetric and surface heat release rates (References 2-4 and 2-20).
Reducing the boiler load will lower the volumetric and surface heat
release rate; therefore it is equivalent to having a larger firebox. One
test on a spreader stoker shows a 10 percent reduction in NO emission
A
by reducing the load from 70 to 60 percent of maximum continuous rating
(References 2-18 and 2-20). On most other tests as the load was reduced,
the excess air had to be increased, causing a net rise in NO
A
emissions. These results suggest that the technique will be effective in
2-30
-------
reducing NO emissions only if the excess air can be maintained at the
/\
original level measured during the higher load condition.
The technique, although an applicable one, has numerous possible
disadvantages. These include derating of the boiler and loss in boiler
efficiency as a consequence of the requirements to increase the excess air
level (Reference 2-20).
2.2.2.4 Reduced Air Preheat (RAP)
There is only limited data on reduced air preheat applied to
industrial stokers. Based on ttjts on only one boiler, a small reduction
of the combustion air temperature from approximately 366 to 355K (200°F
to 180°F) reduced NO emissions by an average of 8 percent (References 2-18
/\
and 2-20). Some researchers claim that the coal bed preheats the air
before the combustion occurs and thus defeats the purpose of the method
(Reference 2-50). This technique is of course limited to stokers equipped
with combustion air preheaters. Only larger (>29 MW, 100 x 10 Btu/hr)
stokers tend to have air preheaters. In addition, significant losses in
boiler efficiencies will occur if flue gas temperatures leaving the stack
are increased as a consequence of bypassing air preheaters. Economizers
could be added to avoid efficiency losses.
2.2.2.5 Ammonia Injection
Ammonia injection should be applicable to stoker boilers as well as
pulverized coal-fired units. However, the geometry of the ducting in the
convective section is crucial. The ammonia injection ports must be
located in that portion of the furnace where the flue gas temperature
ranges from 1070 to 1290K (1470 to 1860°F).
The information on ammonia injection listed in Table 2-4 is the
same as that in Table 2-3. The performance of the ammonia injection
process has not been investigated on stokers; therefore the potential
NO reductions listed in Table 2-4 are based on reported results on gas-
/\
and oil-fired industrial boilers (References 2-39).
2.3 OIL-FIRED BOILERS
Oil-fired industrial boilers fall into two major categories:
firetube and watertube. Firetube boilers can be further divided into
Scotch, horizontal return, tubular and firebox designs. Watertube boilers
are identified as either packaged or field-erected units. Packaged
boilers, both watertube and firetube, are usually equipped with a single
2-31
-------
burner. Field-erected units are usually equipped with an array of burners
and are generally of larger capacity than the packaged units.
Oil-fired firetube boilers are designed with a maximum of 9 MW heat
input (30 x 10 Btu/hr). These boilers account for 7.2 percent of the
total industrial boiler population (Reference 2-2). Industrial watertube
boilers can be as large as utility boilers, however the packaged watertube
units are usually limited to 73 MW (250 x 106 Btu/hr) of heat input
(Reference 2-51). Oil-fired watertube boilers account for 35.3 percent of
total industrial boiler population ~ 8.7 percent are packaged units and
26.6 percent are field-erected boilers (Reference 2-2).
Table 2-5 lists the baseline NO emissions from oil-fired
A
industrial boilers measured during an EPA test program (Reference 2-4
and 2-20). Regardless of the boiler type, it is evident that boilers
burning residual oil produce more NO emissions than the ones firing
3\
distillate oil. Also for any particular class of boilers the range of
NO emissions for residual oil is often wider than the range of
A
emissions for distillate oil. The larger amount and variation of fuel
nitrogen in the residual oil accounts for both these observations. Fuel
analyses performed as a part of this test program showed that residual oil
generally contained 0.10 to 1.0 percent fuel nitrogen while distillate oil
contains less then 0.05 percent on the average (Reference 2-20).
Combustion modification NO control techniques for oil-fired
/\
boiler are as follows:
0 Low excess air (LEA)
• Staged combustion air (SCA)
• Burners out of service (BOOS)
• Flue gas recirculation (FGR)
• Reduced air preheat (RAP)
t Load reduction (LR)
t Low NO burners (LNB)
/\
• Armenia injection
These techniques can be applied singly or in appropriate combination,
especially for ammonia injection which can be implemented with any other
combustion modification. Also, the BOOS technique can only be applied to
multiburner units and is usually confined to retrofit applications.
Table 2-6 surnnarizes the information on the performance, applicability and
2-32
-------
TABLE 2-5. NOX EMISSIONS AT BASELINE AND AT LOW EXCESS AIR FROM OIL-FIRED
INDUSTRIAL BOILERS (REFERENCES 2-4, 2-20, 2-52 AND 2-53)
Equipment
Type
Firetube
Water-tube
W/0 Air
Preheat
Watertube
W/ Air
Preheat
All Boiler
Types
No.
Boilers
Tested
5
9
8
22
Residual Oil
Baseline
02
X
5.2
5.9
5.8
5.7
NOx Emissions
ng/ja
95.5 - 170
(115.0)
87.5 - 362
(190)
66.8 - 188
(134)
66.8 - 362
(155)
NOX Emissions
lb/106 Btua
0.222 - 0.395
(0.275)
0.203 - 0.843
(0.442)
0.155 - 0.438
(0.312)
0.155 - 0.843
(0.360)
Low Excess Air
02
X
3.2
4.0
4.6
4.0
NOX Reductions
X
7
13
12
11
Equipment
Type
Firetube
Watertube
W/0 Air
Preheat
Watertube
W/ Air
Preheat
All Boiler
Types
No.
Boilers
Tested
2
3
2
7
Distillate Oil
Baseline
02
X
5.4
5.5
5.4
5.8
NOX Emissions
ng/ja
96.5 - 107
(102)
44.7 - 59.5
(51.8)
69.0 - 102
(86.5)
44.7 - 107
(72.6)
NOX Emissions
lb/10& Btua
0.224 - 0.248
(0.236)
0.103 - 0.138
(0.120)
0.160 - 0.237
(0.199)
0.104 - 0.248
(0.169)
Low Excess Air
02
X
3.2
3.2
4.5
3.7
NOX Reductions
18
6
12
11
*NOX emissions are given as a range, with the average in parentheses.
T-1749
2-33
-------
TABLE 2-6. COMBUSTION MODIFICATION N0y CONTROLS FOR OIL-FIRED INDUSTRIAL BOILERS
Control
Technique
Low Excess Air
(LEA)
Staged
Combustion Air
Burners Out of
Service (BOOS)
Flue Gas
Recirculation
(FGR)
Flue Gas
Recirculation
plus staged
combustion
Description of
Technique
Reduction of combus-
tion air
Fuel rich firing
burners with secon-
dary combustion air
ports
One or more burners
on air only. Re-
mainder firing fuel
rich.
.
Recirculation of
portion of flue gas
to burners
Combined techniques
of FGR and staged
combustion
No. of
Boilers
Tested
22 residual
oil boilers.
7 distillate
oil boilers
3 residual
boilers, 1
distillate
oil boilers
8 boilers
One distil-
late oil
boilers. Two
residual
boilers.
Only one
package
watertube
Effectiveness of Control
(Percent NOX Reduction)
Residual
0 to 28
11 average
or 10 ng/J/
1 02 reduc-
tion.
20-50
10 to 30
15 - 30
25 to 53
Distillate
Oil
0 to 24
11 average
or 10 ng/J-1/
X 0;> reduc-
tion.
17-44
N/A
58 to 73
73 to 77
Range of
Application
Generally excess 0?
can be reduced to
2.51 representating
a 3X drop from base-
line.
70-90X burner stoich-
iometries can be
used with proper in-
stallation of secon-
dary air ports
Applicable only for
boilers with minimum
of 4 burners. Best
suited for square
burner pattern with
top burner as BOOS.
Only for retrofit
application.
Up to 25-30X of flue
gas recycled. Can
be implemented on all
design types.
Max. FGR rates set
at ?5t for distillate
oil and 201 for re-
sidual oil.
Availability/
R&D Status
Available.
Technique is
applicable on
packaged and
field-erected
units. However,
not commercial-
ly available
for all design
types
Available.
Retrofit re-
quires careful
selection of
BOOS pattern
and control of
air flow.
Available.
Requires exten-
sive modifica-
tions to the
burner and
windbox.
Combined tech-
niques are
still at
experimental
stage. Needs
more R&D fea-
sibile only for
new units.
Comments
Added benefits in-
cluded increase in
boiler efficiency.
Limited by increase
in CO, HC, and
smoke emissions.
Best implemented on
new units. Retrofit
is probably not
feasible for most
units especially
packaged ones.
Retrofit often re-
quires boiler de-
rating unless fuel
delivery system is
modified.
Best suited for
new units. Costly
to retrofit.
Possible flame
instability at
high FGR rates.
Retrofit may not
be feasible.
Best implemented
on new units
IN5
CO
Continued
T-175?
-------
TABLE 2-6. CONCLUDED
Control
Technique
Load Reduction
(LR)
Low NOX
Burners (LNB)
Amnonia
Injection
Reduced Air
Preheat (RAP)
Description of
Technique
Reduction of air and
fuel flow to all
burners in service
New burner designs
with controlled air/
fuel mixing and
increased heat dis-
sipation.
Injection of NH3
as a reducing agent
in the flue gas.
Bypass of combustion
air preheater
No. of
Boilers
Tested
17 residual
oil-fired
boilers, 7
distillate
oi-1-fired
boilers
Large number
tested in
Japan
5
(4 Japanese
installa-
tions, 1
domestic)
2 residual
oil-fired
boilers
Effectiveness of Control
(Percent NOX Reduction)
Residual
33* decrease
to 25* in-
crease in NOX
20-50*
40-70*
S-16S
Distillate
Oil
31X decrease
to 17* in-
crease in NOX
20- SO*
40-70*
„
Range of
Application
Applicable to all
boiler types and
sizes. Load can be
reduced to 25* of
maximum
New burners described
generally applicable
to all boilers. More
specific information
needed.
Applicable for large
package and field-
erected watertube
boilers. Not feasible
for firetube boilers.
Combustion air temp.
can be reduced to am-
bient conditions
(340K)
Availabil ity/
RIO Status
Available now
as a retrofit
application.
Better imple-
mentated with
improved fire-
box design
Commercial 1>
offered but not
demonstrated
Commercially
offered but not
demonstrated
Available. Not
implemented be-
cause of sig-
ficant loss in
thermal effic-
iency.
Comments
Technique not ef-
fective when it
necessitates an
increase in excess
0? levels, LR
possible implemen-
ted in new designs
as reduced combu-
stion intensity
(enlarged furnace
plan area)
Specific emissions
data from indus-
trial boilers
equipped with LNB
are lacking
Some increased
maintenance of air
heater/economizer
parts might be
necessary when
burning high sulfur
oil. Technique is
very costly.
Application of this
technique on new
boilers necessita-
ted installation of
heat recovery
systems in the flue
gas
I
CO
T-1752
-------
availability of these techniques for oil-fired industrial boilers. The
following subsections high-light the major points of interest for each of
the controls considered.
2.3.1 Low Excess Air (LEA)
Low excess air, as for coal-fired boilers, is an effective means of
achieving reductions in NO with increased boiler efficiency for
A
oil-fired units. The technique is applicable to all oil-fired industrial
boilers and is easy to implement both in a retrofit case and in new
boilers.
Firetube and small watertube industrial boilers are generally
equipped with constant speed forced draft fans which supply air to the
windbox. Air control is achieved by adjusting the vanes at the inlet to
the fan. A reduction in air flow to the burner(s) is achieved by closing
these vanes. The reduced air-fuel ratio lowers the excess air level in
the furnace. Large oil-fired multiburner watertube boilers are equipped
with variable speed forced draft and induced fans which can be controlled
to vary the amount of air flow to the boiler. However, these units will
probably require the use of compartmental windboxes in addition to fan
control for even distribution of air flow to each burner.
Table 2-5 summarizes the performance of the LEA technique on
specific industrial boiler equipment types burning fuel oil. In general,
the data show that LEA is equally effective for residual and distillate
oil-fired boilers. NO was reduced by approximately 11 percent for both
/\
fuels. The data also show that for residual oil-fired boilers LEA is
slightly more effective when applied on watertube than on firetube units.
The reverse is true for distillate oil-fired boilers. However, the data
base is not sufficiently large to verify the significance of these trends.
Reducing the excess oxygen in the flue gas by decreasing the air
flow to the burner can lead to a rapid increase in CO, hydrocarbon and
smoke emissions. However, the field test data for many boilers has shown
that as long as the excess Op is maintained above 3.0 percent these
emissions were not increased (Reference 2-18).
In addition to reducing NO emissions the technique of LEA is
s\
cost effective because it increases boiler efficiency. In fact, the
thermal efficiency of all oil-fired units tested increased 0.7 percent on
the average with LEA combustion (Reference 2-20).
2-36
-------
Application of low excess air combustion requires not only means of
adjusting air flow at various boiler loads, but also installation of flue
gas Op and CO monitors. Attempts to adjust for LEA without controls may
lead to a loss rather than a gain in efficiency. Alarms should also be
installed to provide a safety system in case the air flow to the boiler is
inadequate.
Low excess air combustion should be considered a standard operating
practice for industrial boilers. In fact, because of the increased fuel
efficiency the technique is often implemented strictly as a fuel economy
device.
2.3.2 Staged Combustion
The concept of staged combustion consists of injecting secondary
air downstream of a first stage combustion zone which is characterized by
substoichiometric levels of combustion air. Stage combustion can be
effected by use of secondary air ports/injectors or by burners out of
service. Which of these techniques can be implemented on oil-fired
boilers will depend on the type of. furnace design.
The diversity of air injection systems designs applicable to
oil-fired industrial boilers warrants a separate discussion for each of
the major equipment design types previously identified.
2.3.2.1 Firetube Boilers
Figure 2-7 shows a schematic of an experimental retrofit
application of the staged combustion technique, staged combustion air
injection (SCA), on a firetube boiler burning residual oil.
The retrofit design consists of eight stainless steel pipes
connected through a ring mainfold to a forced draft fan. The air
injection pipes penetrate the furnace opposite from the burner and are
equipped with "fish tail" orifice to assist in mixing the air with the
combustion products. A separate fan provides air to the manifold
independent of the burner air. This technique assures control of burner
stoichiometry while supplying enough air downstream of the burner to
complete combustion. The retractable injection nozzles permitted the
analysis of the effect of injection air location on the performance of the
staged combustion technique at various burner air-fuel ratios.
2-37
-------
PLAN VIEW
BURNER
WINDBOX
- - iy.-r-.-m-. t !
'-. t *_« j« t f* f f f I 3 1 •. •.«.«
STAGED AIR
FAN AND MOTOR 0
PLAN
DETAILS OF STAGING NOZZLE
STACK
\
RETRACTABLE
INJECTION
AIR MANIFOLD
ELEVATION
Figure 2-7. Schematic of staged combustion air injection for an oil-
and gas-fired firetube boiler (Reference 2-54).
The retrofit design shown in Figure 2-7 represents a possible way
of implementing SCA on firetube boilers. Alternate solutions would be to
perforate the front or the side of the boiler to accomodate the injection
nozzles.
Staged combustion test results are available only for residual
oil. NOX was reduced from 96.2 to 49 ng/J (0.224 to 0.114 lb/106 Btu)
with a burner stoichiometry of 76 percent and the injection air ports
located 2.5 firebox diameters downstream of the burner oil tip. The
overall excess oxygen level was 4 percent. The boiler load was, however,
reduced to 50 percent of capacity because combustion instabilities were
encountered at high loads as the air flow through the windbox was reduced
(References 2-52 and 2-53). It should be noted that these instabilities
2-38
-------
could be partly attributed to removal of burner baffles under the staged
combustion tests. The significant NO reduction achieved indicates that
A
the staged combustion technique can be very effective in reducing NO
emissions from firetube boilers burning residual oil. This technique is
expected to be less effective for distillate oil combustion because of the
lower fuel NO formation with this fuel.
A
Staged combustion air (SCA) injection should be considered still in
the development stage. More testing is required to resolve the combustion
instability at the high boil,: loads and to establish the reliability of
the system for long-term operation. In addition, the design of the SCA
system as shown in Figure 2-7 might not be feasible altogether because of
operational complexity and incremental cost.
2.3.2.2 Packaged Watertube
Two retrofit designs of the staged combustion technique have been
investigated for single burner packaged watertube boilers. Figures 2-8
and 2-9 show the schematic of two secondary air injection systems.
In the first retrofit application (Figure 2-8), the staged
combustion air was injected from the side of the furnace. The application
was possible because the configuration of the waterwalls was not of the
tangent type. That is, refractory brick spacing existed between furnace
waterwall tubes. Consequently air could be injected without having to
modify or remove any of the furnace tubes. This type of waterwall tube
design is typical of oil boiler furnaces. Modern manufacturing methods
utilize tangent tube construction for better radiant heat transfer.
Figure 2-9 shows an alternate method of injecting staged air
combustion in a modern design "D" type package watertube boiler. Holes
were drilled in the windbox and four retractable air injection lances were
installed directly in the furnace. The tangent tube design of this
furnace did not permit side air injection. The movable lances permitted
injection of air at varying distances downstream of the burner. This
injection system was designed for the purpose of conducting experimental
tests and should not be considered as an established method of injecting
secondary air in this boiler type. However, it may be possible to design
the tube arrangement in new boilers such that air injection ports could be
installed on the side of the furnace.
2-39
-------
PORT NOS.
T
183 cm
I
j" J®)I3.I5
FURNACE
II
11
E
wiNoeox
—249cm
-166cm—».
— 86
cm
1!
II
PORT
NOS.
/
36cm
DIAMETER
MANIFOLD
ct
(o) TOP VIEW
320cm
FAN
FURNACE
14 J5
86cm
80cmj 83cm 61cm
e—
PORT6'7 8,9 10,11 12,13
NOS.
WINDBOX
366
cm
\.
DIVIDING
WALL
(b) SIDE VIEW
Figure 2-8. Schematic of staged air system installed for single burner
packaged watertube oil-fired boilers (Reference 2-55).
2-40
-------
>— Retractable Air
/- Staged Air Lances / Injection Lance
Windbox
^
(
\\ fi
Furnace !
i
t
•
)
Direction of
Injected Air
45° Angle
Staged
Air Lances
To Forced
Draft Fan
i/indbox
(a) Top View
Stack
(b) Side View
Retractable
Air Injection
Lances
Direction of
Injected A1r
45° Anqle
Figure 2-9. Schematic of stage air system installed on "D" type packaged
watertube boiler (Reference 2-55).
2-41
-------
Results on the performance of staged combustion on single burner
watertube boilers suggest that two conditions are required to achieve
substantial NO reductions (References 2-20 and 2-55).
/\
• Burner stoichiometries must be set between 90 and 100 percent.
That is, air flow to the burner windbox must be below
theoretical air needed for complete combustion.
• Secondary air must be injected sufficiently downstream from the
burner exit to allow for cooling of combustion gases. This
downstream distance varies with burner type and size.
Carefully installed and operated staged injection air will result
in significant N0x reductions (40-45 percent) from residual oil-fired
package boilers. However, as in the case with firetube boilers it is
estimated that more field data on the long term effects of SCA in these
units is necessary before this technique can be considered demonstrated.
2.3.2.3 Field Erected Watertube
For field erected watertube boilers, normally equipped with more
than one burner, staged combustion can be obtained with the techniques of
overfire air (OFA) or burners out of service (BOOS).
The technique of OFA has already been described for coal-fired
boilers (Section 2.2.1.2). Overfire air injection above the top burner
level is applicable to new as well as existing oil-fired boilers.
However, as in the case for coal-fired units the technique is more
attractive in original designs than in retrofit applications for cost
considerations. Information on N0x reduction from oil-fired industrial
boilers using OFA is very limited. However, application of the technique
on utility boilers burning oil has resulted in 24 percent NO reduction
^
(Reference 2-24). Overfire air is a viable NO reduction technique for
/\
new multiburner industrial units burning oil. Furthermore, it is
considered demonstrated and commercially available.
Burners out of service is the simplest method of achieving staged
combustion with these units. However, this technique is usually limited
to retrofit applications. The method of implementing BOOS has already
been described in Section 2.2.1.3 for coal-fired units. The application
to oil-fired units is essentially the same except that oil-fired units
have better control over the number or location of the burner(s) to be
used as air injection ports. This is possible for oil and also gas units
2-42
-------
because the fuel flow can be terminated at each individual burner and not
at a set of burners as in the pulverized coal-fired units. Furthermore,
fuel feed rates to the active burners can be adjusted over a broader range
for oil- and gas-fired boilers. Numerous field test data on burners out
of service have been gathered on industrial boilers. NO emissions were
A
reduced 25-40 percent during these tests (References 2-4 and 2-20).
On existing units, operation with BOOS requires that the unit be
derated unless modification to the fuel delivery system is made. In
addition, adjustments to the air flow controls, such as burner registers,
might also be required to achieve the required burner stoichiometry
without increasing smoke and combustible emissions. Furthermore, there is
no optimum BOOS pattern applicable to all existing boilers (Reference 2-20).
2.3.3 Flue Gas Recirculation (FGR)
Recycling a portion of the flue gas back to the primary combustion
zone reduces NO formation by lowering the bulk furnace gas temperature and
reducing oxygen concentration. Figures 2-10 through 2-12 show schematics
of typical FGR retrofit applications on a firetube and two packaged
watertube boilers, respectively. The systems are nearly identical
consisting of an FGR fan assembly and associated ducting connecting the
stack to the windbox.
One investigator reported that the technique is more effective for
watertube boilers than for firetube boilers when burning the same fuel
because of the generally higher combustion intensity of the watertubes
(Reference 2-52). However, NO reductions for both firetube and
A
watertube reached a maximum of 20 percent when burning a residual oil.
Another investigator reported that FGR is more effective for steam
atomized oil combustion than for air atomized oil combustion (References 2-20
and 2-55). In fact, in a watertube boiler burning steam atomized residual
oil, maximum NO reduction was 20 percent. When burning the same oil
A
with air atomization only 16 percent NO reduction was achieved.
A
For oil-fired boilers FGR is more effective when burning light
distillate oil because thermal NO predominates. In fact, NO
A X
reductions of up to 73 percent were obtained with FGR when burning a No. 2
distillate oil (Reference 2-55).
In a retrofit application, flue gas recirculation rates approaching
or above 30 percent can cause severe flame instability, flame pulsation,
2-43
-------
„ 9
1 J
PLAN
ro
i
STACK
BURNER
WINDBOX
FGR FAN
AND MOTOR
FRONT ELEVATION
SIDE ELEVATION
Figure 2-10. Layout of flue gas recirculation system for a firetube
boiler (Reference 2-54).
-------
Furnace
Flue Gas
Recirculation
Duct
Damper
Fan
Stack
(a) Top View
Stack
?lue Gas Recirculation Duct
(b) Side View
3)
Figure 2-11. Layout of flue gas recirculation system for a packaged
watertube boiler (Reference 2-55).
2-45
-------
I
FGR MOTOR
AND FAN
BURNER
WINDBOX
PLAN VIEW
STACK
4
JTN
.0
FGR
DUCT
SIDE VIEW
FRONT VIEW
Figure 2-12. Alternate layout of flue gas recirculation system for a
packaged watertube boiler (Reference 2-54).
2-46
-------
equipment vibration and blowouts. These problems were found to be
significantly alleviated by extensive burner and windbox modifications
(References 2-20 and 2-52).
In general, FGR is definitely an applicable control technique for
oil-fired industrial boilers. It is most effective on boilers burning
distillate oil. When burning residual oil, steam atomization is
preferred. The technique is commercially available for new boilers for
which burners have been designed to accomodate the additional flue gas
flow. In fact, one manufacturer has recently installed two 14.7 MW
(50 x 10° Btu/hr) units equipped with FGR systems in Southern California
(References 2-56 and 2-57). No information on the performance on these
units has been reported. However, the NO emissions of these units are
/\
designed to meet the stringent regulations of the South Coast Air Basin of
225 ppm at 3 percent 02 for oil combustion (approximately 126 ng NO^/J).
2.3.4 Combined Flue Gas Reclrculation and Staged Combustion
The packaged watertube boiler shown in Figure 2-9 was also tested
with combined SCA and FGR. Tests were run to determine whether the
effectiveness of the two techniques are additive (References 2-20 and
2-55). Combining SCA with FGR gave no increased reduction over that with
FGR or SCA alone when burning distillate oil. However, the combined
techniques had a pronounced effect when burning residual oil. Thus staged
combustion alone reduced NO emissions of residual oil 42 percent, FGR
/\
alone reduced NO emissions 11 percent while FGR with SCA reduced the
A
NO emission 55 percent.
A
Fitting a boiler with both SCA and FGR may not prove to be cost
effective. The combined technique is not considered commercially
available because staged combustion is still experimental for firetube and
packaged watertube boilers.
2.3.5 Reduced Air Preheat (RAP)
Reducing the amount of combustion air preheat lowers the primary
combustion zone peak temperature, generally lowering thermal NO
/\
production as a result. The technique can be implemented only on boilers
equipped with air preheaters. These boilers are of the watertube type and
generally have designed heat input capacities of greater then 15 MW (50 x
106 Btu/hr) (Reference 2-20). No retrofit work is required in some
instances.
2-47
-------
As evidenced by the data contained in Table 2-5, baseline NO
^
emission data from distillate oil-fired watertube boilers equipped with
air preheaters had greater NO emissions than those units not equipped
/\
with air preheaters. Unit capacity was not a factor. No similar
reduction occured for those units burning residual oil, perhaps because of
the greater variation in fuel nitrogen content of the various oils being
burned.
The data reported in Table 2-6 reflects results of RAP tests on two
residual oil-fired boilers. For one boiler where the initial baseline
NO emissions was below 200 ppm at 3 percent 0? (112 ng/J) the
A ^
technique was ineffective. For the other boiler with initial baseline
emissions over 330 ppm at 3 percent 0? (185 ng/J), RAP reduced NO
fl
emissions at a rate of 33 ppm (19 ng/J) per 50K (90 F) reduction in
combustion air temperature (Reference 2-20).
Although available, the technique is rarely applied because very
few industrial size oil-fired boilers are equipped with air preheaters.
Furthermore, when RAP can be implemented, the fuel penalty involved due to
loss in efficiency makes the technique very unattractive. Reducing the
air preheat temperatures as a means of reducing nitrogen oxide emissions
from oil-firing will result in a decrease in boiler efficiency by about
2.5 percent per 50K (90°F) increase in stack temperature (Reference 2-20
and 2-58). Because of this significant loss in boiler efficiency, the
heat loss would have to be recovered if RAP is to be used as a NO
A
control technique. Enlarging the surface area of existing economizers or
installation of an economizer in place of an air preheater can be used to
recover the heat loss due to the RAP technique for NO control. For new
A
boilers, installation of an economizer is technically feasible and also
offers economic advantages over the air preheater (Reference 2-59).
2.3.6 Load Reduction
Reducing boiler load is accomplished by reducing the heat input
into the fun ace. Both heat release rate (also known as combustion
intensity) and peak flame temperature are lowered, reducing the themal
NO formation. However, the reduced mass flow through the burners at
the reduced load condition can cause improper fuel-air mixing, thus
creating CO and soot emission with additional operational problems. This
situation is alleviated by increasing the air flow to excess air levels
2-48
-------
higher than normally maintained at the higher boiler loads. This increase
in air flow causes more oxygen availability, thus favoring increase in
fuel NO formation. The net effect of reduced thermal NO and increased
A
fuel NO is often no change in NO concentration in the flue gas.
A
This was essentially the result of the load reduction tests
conducted in an EPA program on 24 oil-fired industrial boilers
(References 2-4, 2-20 and 2-53). The data often show a split with some
boilers increasing NO emissions at reduced loads and other boilers
A
decreasing them. For firetube boilers burning distillate oil, the NO
A
emissions ranged from a 10 percent decrease to a 7 percent increase for
each 10 percent load reduction. Five distillate oil-fired boilers without
air preheat shown an average increase in NO emission of 3.8 percent
A
while the remaining two with air preheat showed an average decrease in
NO emissions of 26 percent. NO emissions from firetube and
A A
watertube units burning residual oil showed average decreases in NO
A
emission factors regardless of whether the air was preheated or not.
Reducing boiler load will usually reduce the thermal efficiency of
the boiler because of the increase in excess air needed to maintain good
fuel air mixing. A more desirable way to achieve a reduction in
combustion intensity would be to increase the size of the firebox. The
enlarged firebox would provide reduced heat release rates without
necessitating an increase in excess air levels. Naturally, the increased
firebox design will only apply to new boilers. This technique is being
implemented on utility size boilers (Reference 2-24).
2.3.7 Low NO Burners (LNB)
A
Low NO burners firing fuel oil can generally be classified by
A
the method of fuel injection and the method of combustion air delivery. A
recent EPA study (Reference 2-60) further classifies the burners as:
t Good-mixing*
• Divided flame
• Self-recirculating
*Controlled-mixing is probably a less confusing term, but "good-mixing"
was the term used by the EPA report and will be retained here.
2-49
-------
• Staged-combustion
— Two stage combustion
— Off stoichiometric combustion
The good-mixing and dividea flame type burners primarily reduce
thermal NO , either by rapid quenching of the flame, or by an increase
A
in the surface area of the flame for increased heat dissipation. The
self-recirculation and various staged-combustion type burners reduce both
thermal and fuel N0x> This is accomplished through the recycling of
combustion gas, which is lean in oxygen, or substoichiometric air injected
in the primary combustion zone with stoichiometric and excess air added at
the point of fuel discharge into the furnace.
Seven types of low NO burners for industrial boilers are
A
presently under development or in commerical use in Japan. A summary of
the limited information regarding each of these burners is presented in
Table 2-7. Available information on the operations, performance,
applicability and availability of each of these burners is discussed in
the following sections. Unfortunately, actual emissions data for low
NOX burners for industrial boilers are generally not available. The
percentage NO reductions presented here are only the expected
/\
performance as cited in the references, usually with no baseline emission
levels given.
Nippon/TRW Burner
The Nippon/TRW burner is designed to allow for an initial fuel-air
mixing zone, established through precise control of the radial injection
and atomization of the fuel into the combustion air. A second mixing zone
allows for heterogenerous mixing of fuel droplets, followed by the primary
flame front and post combustion zone (Reference 2-61).
The intermixing of fuel and air produces a radial conical flame
pattern as shown in Figure 2-13. The combination of the recirculation of
combustion products and good-mixing of fuel and air leads to reduced NO
emissions by rapid quenching of the flame with cooler combustion gases.
Figure 2-13 also shows the flame as being a thin annular configuration for
increased heat dissipation and lower flame temperatures. Both phenomena
reduce thermal NO production.
A
Figure 2-14 presents the results of the demonstration/commercialzation
tests performed by Nippon/TRW. The sensitivity of NO emission
A
2-50
-------
TABLE 2-7. LOW NO BURNERS FOR OIL AND GAS FIRING
/\
r\>
en
Manufacturer
Developer
Nippon/TRW
TRW/Civil tech
Ishikawajima-
Narima
Tokoyo Gas
Kawasaki
Coen
Energy and
Environmental
Research/EPA
Burner Type
Good mixing9
Good mixing9
Divided flame
Staged
Combustion
Staged
Combustion
Staged
Combustion
Staged
Combustion
Effectiveness of
(Percent NOX
Reduction)
17-23* w/heavy
oil, fuel nitrogen
content o.f 0.3*
17-23% w/heavy
oil , fuel nitrogen
content of 0.3%
30-50* reduction
depending on
application
50* reduction
20-50* depending
on fuel rate
N/A
Up to 50*
Applicability
Oil & gas
Oil fc gas
Oil 6 gas
Gas
Oil & gas
Oil & gas
Oil
Availability
Commercialized
early 1975 in
Japan
Late 1979
Cornier ically
available in
Japan (1973)
Continuing
development
N/A
Available on
a very limited
basis
Still at R&D
stage
Comments
Lower steam atonriza-
tion but higher
burner throat dP,
High excess 02
First generation
burner tested in
Japan. Second genera-
tion being developed
for U.S.
Requires burner tip
modification only
Flame stability
problems
N/A
Staged combustion
design. All proprie-
tary data
Currently being
tested in a field
operating firetube
'Controlled mixing is probably a better term, but "good mixing" was the
term used by the EPA study (Reference 2-60) and will be retained here.
T-1753
-------
\\SA\\\\\\\\\\\\\\\\\\\\\\\\\A
FURNACE WALL
FRONT HAL
CYLINDRICAL AIR SHEET
FUEL
RECIRCULATION ZONE
01ANT RADIATION
RECIRCULATION ^ ZONE
Y//////////////
V//////////////////777
Figure 2-13. The Nippon/TRW burner (Reference 2-62).
2-52
-------
30C
280
260
240
220
20C
O^ 18C
O 160
o
UJ
u 140
8 120
IOC
80
60
40
2C
0
r
10
?6 Oil
CONV£N7]ONA
LNE, '6 OIL
LNE, '2 Oil
OH
LNB-G/kS/#2 Oil
TEST FURMA.CE
_L
LNB - Low NO Burner
A
I
20 SO 4C
EXCESS AIR-«*CENT
50
6C
Figure 2-14. Performance results of the Nippon/TRW low NOX burner
(LNB) (Reference 2-61).
2-53
-------
concentrations as affected by fuel nitrogen is clearly seen. Figure 2-14
also demonstrates the low NO burner capabilities compared to a
A
conventional burner. These tests were conducted after the burner was
installed in an existing packaged boiler without modification to the
safety control equipment, combustion air or fuel-handling system. The
test results show a 35 percent decrease in NO emissions for No. 2 fuel
/\
oil and a 30 percent decrease for heavy oil (analysis unknown). When the
low N0x burner was in operation, all NO emissions were below 220 ppm
corrected at 3 percent excess oxygen (123 ng/J, 0.287 lb/106 Btu). The
burner has been commercially available in Japan since early 1975
(Reference 2-62).
TRW/Civiltech Burner
The TRW/Civiltech burner represents the second generation burner
being developed based on experience obtained with the Nippon/TRW LNB
(Reference 2-63). Problems experienced during testing in Japan have led
to a program to refine the original burner design. The second generation
burner is being designed to achieve:
• Reasonably low excess air requirements during partial load
operations
• Wider range of applicability, with burner heat input capacities
of 3 to 73 MW (10 to 250 x 106 Btu/hr)
As of this writing, the TRW burner is being commercially offered,
though as yet undemonstrated. A preliminary timetable calls for
commercial application near the end of 1979 (References 2-61, 2-63, and
2-77). An EPA sponsored field demonstrated is currently underway and
actual operating data should soon be available (Reference 2-78).
Ishikawajima-Harima Heavy Industries (IHI) Burner
Ishikawajima-Harima Heavy Industries developed several burner
configurations which are effective in reducing NO . The basic principle
of the burners is a divided flame, as shown in Figure 2-15. The flame
produced has a radial conical pattern which increases the radiation
surface area and ^he rate of heat dissipation. The reduced flame
temperature results in reductions in NO emissions.
A
The burner variations shown in Figure 2-15 were tested on a furnace
simulator. The results are shown in Figure 2-16. NO concentrations
A
are shown to be reduced by 30 to 50 percent of the emissions from
2-54
-------
N-l
Pressure
atoaizing
(Divided flame)
N-2
Steam
atomizing
(Divided flame)
Figure 2-15. Ishikawajima-Harima divided flame burner (Reference 2-64)
200
150
K
O
z
50
25
Ordinary Burner
(Pressure Atomizing)
Ordinary Burner
(Steam Atomizing)
Low NOX Burner
(Pressure Atomizing)
ft. 2
l-ow
Burner
(Steam Atomizing)
0 2 fc 6
BACHARACH SMOKE NUMBER
NOTE: Enclosed regions represent data bands.
Figure 2-16. Effect of flame division on NOX and smoke concentrations
(Ishikawajima-Harima burner) (Reference 2-64).
2-55
-------
conventional burners. Field tests on large boilers, 130 MW (400 x 106
Btu/hr) and larger have also been conducted and the results are presented
in Figure 2-17. It is significant to note that combinations of NO
reduction capability of the IHI burner are reduced as the use of other
control methods, such as flue gas recirculation or staged combustion is
increased.
The burner is commercially available for oil and gas fuel
applications. The primary advantage to this burner is that it requires
only the replacement of the conventional burner tip with the IHI flame
divider, a minor modification.
Tokoyo Gas Company Burner
Tokoyo Gas company developed one of the first two-stage combustion
type burners (Reference 2-65). The principle of the burner is shown in
Figure 2-18. The primary air ports admit a predetermined air volume
followed by stoichiometric addition as shown.
Experimental test results showed the presence of HCN and NFL
*3
intermediates, the radicals which Fenimore determined were precursors to
the formation of "prompt NO" (Reference 2-66). To reduce the
concentration of these radicals, a catalyst was inserted between the first
and second combustion zones. The burner operates at the limit of
fuel-rich combustion, resulting in some flame stability problems
(Reference 2-65).
Tests conducted on a firetube boiler with a capacity of 5.5 MW
(18.6 x 10 Btu/hr) resulted in N0x emissions approximately 50 percent
of those from conventional burners. Because of the flame stability
problems, however, the burner is still in the development stages
(Reference 2-65).
Kawasaki Heavy Industries Burner
A two-staged combustion burner, utilizing a precombustion zone, has
been designed by Kawasaki Heavy Industries (Reference 2-60). The
precombustion chamber is placed in the windbox with secondary combustion
air added at the point of discharge into the furnace, as shown in
Figure 2-19. The injection of the fuel oil results in an eddy effect, as
in self-recirculating burners, resulting in fuel rich combustion. The
fuel is vaporized and partially combusted. Secondary air is added, at the
desired overall stoichiometry, at the burner tip. Reportedly, this
2-56
-------
—LNB Alone
• Combined LNB + FGR = Pressure Atomized Oil
o Combined LNB + FGR = Steam Atomized Oil
D Combined LNB + SCA = Pressure Atomized Oil
ACombined LNB + Water Injection = Pressure Atomized Oil
I Combined LNB + FGR + Water Injection = Pressure Atomized Oil
^/Combined LBN + FGR + SCA = Pressure Atomized Oil
Reduction by Other NOV Controls (Percent)
/\
LNB = Low NOX Burner
FGR = Flue Gas Recirculation
SCA = Staged Combustion Air
Figure 2-17. Effect of combined combustion modifications NOX controls
on the performance of the Ishikawajima-Harima low NOX
burner) (Reference 2-64).
2-57
-------
GAS OR
FIRST STAGE
SECOND STAGE
GAS PRE-
MIXED WITH
AIR
CI,
AIR
Figure 2-18. Schematic of Tokoyo Gas Company two-stage combustion type
burner for low NOX formation (Reference 2-60).
WIND BOX
ATOMIZER
FIRST-STAGE AIR SECOND-STAGE AIR
Figure 2-19. Kawasaki two-stage combustion-type burner for oil
(Reference 2-60).
2-58
-------
configuration reduces both thermal and fuel NO . The degree of
A
reduction is shown in Figure 2-20.
Coen Burner
All test and descriptive information regarding the Coen low NO
burner is considered proprietary (Reference 2-67). The information given
was limited to burner concept (staged combustion) and applicable fuels
(gas and oil). It was also stated that the burner was commercially
available on an extremely limited basis. The flame is elongated, making
the application to existing boilers difficult without substantial
derating. All burners sold will be tested as part of a burner development
program. Widespread commerical availability is not expected in the near
future (Reference 2-67).
300
Q.
Q.
200
O
O
QC
I 10°
Grade C Heavy Oil
with 0.206% nitrogen
content
Conventional
Burner
Low-NO Burner
A
0 1000 2000
FUCL PLOW RATE, liter/hr
Figure 2-20. Effect of Kawasaki low NOX burner on NOX emissions
(Reference 2-60).
2-59
-------
Energy and Environmental Research Co. (EER) EPA Burner
EER recently tested an oil-fired low NOX burner in a
firetube boiler. Reductions in NOX emission levels of greater than 50
percent have been achieved without the need to modify the boiler in any
way (Reference 2-68). Apparently the burner has not been fully
demonstrated because additional testing is underway to investigate the
effect of oil atomization. Preliminary results with this burner have been
very encouraging; however there is no indication on future availability.
2.3.8 Ammonia Injection
The non-catalytic reduction of NO in the flue gas with NH_ is
commercially available in Japan. Four industrial steam generators ranging
in size from 41 to 252 MW (140 to 860 x 106 Btu/hr) have been
successfully retrofitted in Japan. Reported NO reductions ranging from
/\
approximately 40 to 65 percent depending on the temperature of the
injection location (Figure 2-21).
Since the commercial application of ammonia injection process in
Japan, one domestic application on an oil recovery boiler in Southern
California has taken place. Reported NO reductions ranged from 50 to
/\
70 percent with the unit burning a heavy crude oil (Reference 2-69). The
technique is particularly attractive because it can be in combination with
any other combustion modification. Thus, significant NO reductions can
n
be achieved.
For firetube boilers the injection system would need to be placed
in the firebox as it is shown in Figure 2-22 because optimum temperatures
occur at this location. The system represents an experimental retrofit
application for a pilot scale test program. For watertube boilers the
injection system will have to be located at the entrance of the convective
section where flue gas temperatures are optimum for the NO reduction
reaction to occur.
Due to the expected high cost of this technique compared with other
combustion molifications, the ammonia injection process will probably not
be feasible on small size boilers such as firetubes and package
watertubes. In addition, since these industrial units are generally not
base loaded, that is they do not operate at a steady continuous load, the
variable heat input will cause significant flue gas temperature
fluctuations which will reduce the performance of the control technique.
2-60
-------
1787
Flue Gas Temp., F
1967 2147
975
1075 1175
FLUE GAS TEMPERATURE, K
2327
/u
60
50
«*•
§ 40
o
0
*x 30
p
20
10
r
. i
"
v
n
„ D o
D
w
V
- A O O
V
cP
o
0 V
,- o
D
O
- —
SIZE DESCRIPTION
B 25 t/hr Packaged Boiler _
O 70 t/hr ) . . . . , D ..
0120 t/hr f lndlislnal Boiler
A 100 MWatt \ nr,.t _ .,
v 100 MWatt / Utlllty Boiler
° 150 kbb!/d } Crudc Heaters
1 1
1275
Figure 2-21.
Ammonia injection system performance on commercial units
as functions of temperature (Reference 2-70).
2-61
-------
ro
i
ro
"V -v -v -V -v i -v -v -\. -V
•HI"
Combustion
Products
NH, Injectors
, -j • -
S. X X XX X XXX \\X x X N \\
Rotampter
Panel
Support r>tand
42"
Figure 2-22. Schematic of ammonia injection system on a firetube boiler
(Reference 2-18).
-------
From an operational standpoint, the ammonia injection process is best
suited for units burning low sulfur oil. The absence of SCL in the flue
gas will eliminate the concern for corrosive deposits caused by the
formation of anmonium sulfates.
2.4 GAS-FIRED BOILERS
Gas-fired industrial boilers are of the same basic design as
oil-fired boilers. In fact, approximately one-fourth of all industrial
boilers are capable of burning gas and oil individually or in combination
(Reference 2-44). Gas-fired boiler designs are categorized as firetubes,
and packaged or field-erected watertubes. Of the total population of
installed units, gas-fired firetubes comprise 11.3 percent, packaged
watertubes 8.6 percent and field-erected watertubes 13.6 percent
(Reference 2-2).
Table 2-8 lists baseline NO emission from gas-fired industrial
/\
boilers tested by EPA (References 2-4, 2-20 and 2-53). The data show a
definite increase in NO emissions for boilers equipped with air
rt
preheaters. There appears to be no difference between NO emissions of
A
firetube boilers and those of small single burner watertube boilers
without air preheat.
All of the combustion modifications applicable for oil-fired units
are also applicable to boilers burning natural gas. Table 2-9 summarizes
the available information on the performance, applicability and
availability of these techniques for gas-fired units.
The following subsections highlight the major points of interest
for each of the techniques considered.
2.4.1 Low Excess Air (LEA)
Implementation of LEA firing on gas-fired units is similar to that
on oil-fired units because the boiler equipment is essentially the same.
Low excess air reduces NOX emissions approximately 12 percent for
firetube boilers, 8 percent for watertube boilers, without preheated air
and about 15 percent for watertube boilers with preheated air. Test data
also shows that excess oxygen level could in general be reduced to around
3.0 percent without excessive emissions of CO or HC (References 2-4 and
2-20 and 2-53).
2-63
-------
TABLE 2-8. BASELINE NOX EMISSION FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS
Type
of
Boiler
Flretube
Watertube
without
air preheat
Watertube
with
air preheat
Number
of
Boilers
8
9
11
Excess 03
(Weighted Average)
3.6 - 11.5
(6.5)
2.9 - 8.9
(5.3)
1.9 - 13.1
(5.7)
Range of NOv
Emissions ng/J
(Weighted Average)
28.6 - 55.1
(41)
30.1 - 97.9
(47)
49.0 - 190.1
(113)
Range of NOX
Emissions lb/10^ Btu '
(Weighted Average)
0.066 - 0.128
(0.095)
0.070 - 0.228
(0.116)
0.114 - 0.444
(0.263)
ro
i
T-1754
-------
TABLE 2-9. COMBUSTION MODIFICATION NOX CONTROLS FOR GAS-FIRED INDUSTRIAL BOILERS
Control
Technique
Low Excess Air
(LEA)
Staged com-
bustion air
(SCA)
Burners out of
Service (BOOS)
Flue Gas Re-
circulation
(FGR)
Staged combus-
tion and Flue
Gas Recircula-
tion (FGR)
Description of
Technique
Reduction in air-fuel
ratio by reducing air
flow to the windbox
Injection of secon-
dary air downstream
of the burner(s) in
the direction of the
flue gas path
One or more burners
on air only. Re-
mainder firing fuel
rich.
Recirculation of
flue gas to the
burner windbox.
Requires Motor, fan
and connecting duct-
Ing.
Combined techniques
of staged combustion
air and FGR
Number of
Industrial
Boilers Tested
28
3
3
3
1
Effectiveness of
Control (Percent
NOX Reduction)
5 to 35
5 to 46
17 to 44
48 to 86
76
Range of
Application
Generally excess 0;>
can be safely reduced
to 3. OX. This reduc-
tion represents a
2.5X drop from base-
line.
70-90* burner
stoichiometries can
be maintained.
Applicable to all
units, however re-
quires extensive
equipment modifica-
tion.
Applicable only to
multiburner units.
Best suited for
square burner
pattern.
Flue gas rectrcula-
tion rates possible
up to 45X. Technique
is applicable to all
boiler types except
ones equipped with
ring burners
Applicable to all
boilers with some re-
strictions as indivi-
dual techniques.
Commerical
Aval labil ity/
R&D Status
Method and con-
trol equipment
current ly
available.
Technique is
still experimen-
tal especially
for small fire-
tube and water-
tube units.
Technique is
available.
Retrofit appli-
cation only.
Requires careful
selection of
BOOS and control
of air flow.
Available now.
Best suited for
new boilers.
Retrofit appli-
cation would
result tn exten-
sive burner
modifications.
FGR is an avail-
able technique.
SCA for small
package units is
still at R&D
stage.
Comments
Generally practiced be-
cause of incrpased
boiler efficiency. Best
NOX reductions report-
ed for large multiburner
units.
Found to be less effec-
tive on firetube boilers
than watertube boilers.
Generally less effective
for gas-fired units.
May require modification
of gas delivery system
and burners to avoid
derating.
Flame Instability pro-
blem 1s not severe
except for ring burners.
Minor burner modifica-
tions can guarantee
stable flames. Most
effective on watertube
units.
No added benefit of SCA
to FGR performance.
Combined methods are not
additive in their
effect.
en
Continued
T-17S5
-------
TABLE 2-9. CONCLUDED
a*
cr>
Control
Technique
Load Reduction
(LR)
Reduced Air
Preheat
(RAP)
Low NOX
Burners (LNB)
Amaonia
Injection
Description of
Technique
Reduction of both
fuel and air flow to
burners. Or design
with enlarged fire-
box.
Bypass of combustion
air preheater.
New burner designs
with controlled air/
fuel mixing and in-
creased heat dissipa
tion.
Injection of NH3
as a reducing agent
in the flue gas.
Number of
Industrial
Boilers Tested
21
2
N/A
5
(4 Japanese,
installations,
1 domestic)
Effectiveness of
Control (Percent
NO, Reduction)
32X decrease to
821 increase in
(10.51 average
reduction)
20-55 ng/J-1/
temperature per
50K reduction
in air temp.
20-50
40-70
Range of
Application
Tests to 20t of rated
capacity. Applicable
to all units.
Applicable only on
units equipped with
air preheaters
(large watertube
units). This appli-
cation is very
limited.
New burners generally
applicable to all
boilers. More in-
formation is needed.
Applicable for large
package and field-
erected watertube
boilers. Not cost
effective for fire-
tube boilers be-
cause of size.
Conner ical
Availability/
R&O Status
Technique avail-
able. However.
retrofit appli-
cation is not
feasible due to
initial low load
factor of indus-
trial units.
Technique avail-
able but not
implemented be-
cause of signi-
ficant loss in
efficiency.
Commercially
offered but not
demonstrated
Conrnercially
offered but not
demonstrated
Comments
Least effective on fire-
tube boilers because of
lower combustion inten-
sity. Applicable for new
watertube units with in-
creased firebox size.
Implementation would re-
quire other designs to
recover loss of heat.
Technique is not de-
sirable because of loss
in efficiency.
Specific emissions data
from industrial boilers
equipped with LNB are
lacking.
Should be fewer problems
than with coal- or oil-
firing technique very
costly.
T-1755
-------
In summary, LEA is not a uniformly effective NO control
A
technique for gas-fired boilers. However, combustion with LEA remains
desirable because of increased boiler efficiency.
2.4.2 Staged Combustion Air (SCA)
Staged combustion air on gas-fired boilers is applied in the same
manner as on oil-fired boilers. The firetube and single burner watertubes
for which SCA was implemented with oil firing were also used to
investigate the effectiveness of the technique for gas firing. SCA on
gas-fired mtiltiburner watertub- as also investigated implementing the
BOOS technique. The following sections summarize the performance,
applicability and availabil ty of the various methods of implementing SCA
on the major gas-fired industrial boilers.
2.4.2.1 Firetube Boilers
A schematic of the staged air injection system for firetube boilers
is shown in Figure 2-7. In the EPA study, NO emissions were reduced
A
25 percent at a burner stoichiometry of 90 percent and overa1"1 excess air
of 2.9 percent (Reference 2-53). Secondary air was most effective when
injected downstream of the burner at.a distance equivalent to 1.5 firebox
diameters.
As in the case for oil-fired firetubes, more testing is needed to
assess the feasibility of this technique. The probable high cost both as
a retrofit and a new boiler design feature associated with the modest
NO reductions make SCA unattractive for gas-fired firetube boilers.
A
2.4.2.2 Packaged Uatertube Boilers
NO emissions from the "D" type watertube boiler (Figure 2-9)
A
with staged combustion averaged 6 percent of baseline levels. The optimum
location of the injected air was found to be at a distance of at least
1.2 m (4 feet) from a gas gun burner. Only marginally better NO
A
reduction was achieved by increasing this distance to 2.1 m (7 feet)
(References 2-20 and 2-55).
NO reductions for the other single burner watertube boiler
A
(Figure 2-8) averaged only approximately 30 percent when the secondary air
was injected at approximately 1 m (3 feet) and 3 m (9 feet) from the
burner exit plane. Injection of secondary air between 1 and 3 meters from
the ring burner caused only a slight reduction in NO emissions
A
(References 2-20 and 2-55).
2-67
-------
Staged combustion was less effective for the second watertube
boiler because the combustion air was preheated. The high preheat
temperatures reduced the effectiveness of SCA in lowering thermal NO .
A
When the primary combustion air temperature was reduced, NO emissions
A
were reduced 69 percent with staged air injection (Reference 2-55). This
indicates that NO emissions from gas-fired boilers are more sensitive
A
to combustion air temperature than oil-fired boilers.
The same study also indicated that the type of gas burner -- gun or
ring ~ influenced the location of the secondary injection air for optimum
NO reductions. For the gun type burner, NO emissions decreased as
X «
the air was injected further away from the burner exit plane. This
reduction levels off at a distance corresponding to approximately 7 cm per
thousand Joules of heat input. For the ring type burner, NO reduction
A
peaked at two staged air injection locations: 0.8 and 3.0 meters
approximately. These distances correspond to approximately 2 and 7 cm per
thousand Joules of heat input respectively. Thus, for the ring burner, it
seems that the staged air could also be injected much closer to the burner
with similar NO reduction results (References 2-20 and 2-55).
A
Staged combustion air for small gas-fired watertube boilers is
still at the experimental stage. If ever developed for these units, SCA
will be used with new units burning oil instead of gas because the
technique is more effective for the liquid fuels containing nitrogen.
More pilot and field studies are necessary to confirm some of the trends
described above to define safe operating limits of the technique when the
boiler is operating at various loads.
2.4.2.3 Multiburner Watertube
Staged combustion can be implemented on multiburner units by
utilizing secondary air ports or by the BOOS method. For gas-fired
boilers BOOS reduced NO emissions to a maximum of 30 percent by
A
terminating the fuel flow to half of the available burners
(Reference 2-20).
As in the case with oil firing the optimum BOOS selection varies
for all existing boilers. Similarly, limitations such as boiler derate
when many burners are set on air only are also applicable to gas-fired
units as for oil-fired units. Operational impact such as corrosion and
soot formation are very much reduced with gas-fired boilers.
2-68
-------
2.4.3 Flue Gas Recirculation (FGR)
Three natural gas-fired boilers were retrofitted with FGR, two by
Ultrasystems (Reference 2-53) and the third by KVB (References 2-20 and
2-55). Figures 2-10 through 2-12 show schematics of the FGR system in two
applications. In all cases the burner windbox was breached to install the
FGR duct. The recycled flue gas was mixed with both primary and secondary
air.
The firetube boiler has a gas "ring" burner embedded in the
refractory throat (see Figure 2-23). Apparently, this burner permitted
flue gas recirculation rates up to 55 percent without flame instability.
Nitrogen oxide reductions were approximately 50 percent for 25 percent FGR
and 70 percent for 50 percent FGR. Excess carbon monoxide emissions
reached significant levels only at very low (less than 1.5 percent) excess
02 levels (Reference 2-53).
For the 73 MW (250 x 106 Btu/hr) "D" type boiler, NOV reductions
A
on the order of 70 percent were achieved with FGR rates as high as
45 percent. Flame stability could apparently be maintained with the
typical gas fired "ring" burner installed in this watertube unit. Figure
2-24 shows a schematic of the burner (Reference 2-53).
The third package watertube boiler retrofitted with FGR was a 5 MW
"D" type unit equipped with a ring burner similar to the one shown in
Figure 2-24. Installation of FGR caused severe flame stability problems
even at low recirculation rates. These problems were alleviated by using
a gas gun burner instead of the ring type. However, flue gas
recirculation rates were still limited to 20 percent. Using the gas
burner, NO emissions were reduced 52 percent with 8 percent FGR and 75
A
percent with 20 percent FGR (Reference 2-55).
There seems to be no clear trend between gas burner type and flame
stability with FGR. However, it is evident that FGR installation will
necessitate, in most cases, extensive burner modifications to alleviate
the flame instability. There is some indication that the burner shown in
Figure 2-23 may not require any modification.
Flue gas recirculation for gas-fired industrial boilers is
definitely available and is an effective technique. However, use of FGR
may necessitate use of different burner configuration.
2-69
-------
Oil Nozzle
Stabilization Vanes
Combustion
Air
Figure 2-23. Schematic of the windbox burner arrangement of a
firetube burner (Reference 2-53).
2-70
-------
Register
Dlffuser
Atomizer Tip
Gas Ring
Furnace Wall
Figure 2-24. Schematic of register burner installed in a watertube boiler
(Reference 2-53).
2.4.4 Combined Flue Gas Recirculation and Staged Combustion
Data for natural gas are limited to only one boiler, the 5 MW
(17.5 x 106 Btu/hr) "D" type packaged unit retrofitted with FGR and SCA
in an EPA Test Program (References 2-20 and 2-55). These data indicate
that the addition of staged air injection does not further decrease NO
A
emissions beyond the levels achieved with FGR (76 percent).
The combined FGR and SCA does not present any operational impact in
addition to those caused by the single application of either technique.
There is no incentive in adding SCA to FGR when there is no additional
NO reduction.
A
2.4,5 Load Reduction
Load reduction gave an average NO emission reduction of
J\
3.4 percent for firetubes; 6.4 percent for watertube boilers without air
preheaters and 35 percent for boilers with air preheat (References 2-20
2-71
-------
and 2-55). In these latter cases, with air preheat, the reduction in
boiler load also produced a reduction in combustion air temperature.
In general, reduced boiler load is not as effective for gas-fired
boilers as for oil-fired units. Reduced heat release rates via larger
firebox design or new units does not appear promising based on these
results. Reduced load often requires the need of increased (L which
virtually negates any drop in N0x emissions.
2.4.6 Reduced Air Preheat (RAP)
Measurements of the effects of windbox temperature on gas-fired
boilers were conducted in an EPA study (Reference 2-20). The following
general conclusions were drawn:
1. NO emissions decrease significantly with reduced combustion
^
air temperature
2. The effect of air temperature is more pronounced for larger
burners
3. The overall thermal efficiency of the boiler is reduced, with
reduced air preheat
Reduction of combustion air temperature is a very effective NO
control technique for gas-fired boilers. Emissions were reduced 20 ng/J
for each 50K reduction in combustion air temperature for two watertube
boilers.
The application of RAP is limited to boilers equipped with air
preheaters. These units are all of the watertube design type and are
usually greater than 15 MW of heat input (50 x 106 Btu) (Reference
2-20). Overall efficiency of the unit may be maintained by adding an
economizer (Reference 2-59).
2.4.7 Low NO Burners (LNB)
A
Available Tow NO burners are applicable on gas-fired as well as
A
oil-fired boilers. Detailed performance data of the burners described in
Section 2.3.7 are very limited for natural gas combustion.
The goo-l mixing and divided flame burners which primarily reduce
thermal NO could perform better with natural gas combustion. However,
no data are available to quantify this.
Since the oil-fired LNB can also operate with natural gas, this
NO control technique can be considered commercially available.
^
However, the commercialization has been limited to Japanese installations.
2-72
-------
Continuing research and development effort in U.S. is directed primarily
toward oil-fired burners. Commercial application of these burners is
targeted for late 1979 and beyond.
2.4.8 Ammonia Injection
The design and application of the ammonia injection process does
not vary significantly with the fuel burned. Therefore, the basic design
of the injection system shown in Figure 2-5 for a coal-fired watertube
boiler is also applicable to gas-fired boilers. Application to the
smaller firetube units would be similar to that of Figure 2-22, as
discussed in Section 2.3.8 for oil-fired units.
The ammonia injection process is easier to operate and maintain
with gas firing. This advantage is due primarily to the less severe flue
gas environment from combustion of natural gas. For example, the absence
of sulfur oxides eliminates the possibility of sulfate formation with
unreacted ammonia. In addition, the absence of particulate emissions will
reduce the maintenance of the injection grid to remove accumulated
deposits. Finally, gas-fired boilers do not produce water wall deposits
like those in coal- and residual oil-fired boilers and thus the
fluctuation in flue gas temperatures caused by these deposits is
eliminated.
Ammonia injection is a control technology which is commercially
offered but not demonstrated. The effectiveness varies from 40 to 70
percent NO reduction depending on the application (Figure 2-21). As in
A
the case of oil-fired units, ammonia injection will probably not be
suitable for small units such as firetubes and package watertubes because
of the significant incremental cost to the equipment and to its
operation. In addition, many small units operate at continuously changing
loads depending on plant steam demand. The variation in load will cause
temperature fluctuations which degrade the performance of the process.
2-73
-------
REFERENCES FOR SECTION 2
2-1. "Electric Utility Steam Generating Units, Proposed Standards of
Performance and Announcement of Public Hearings on Proposed
Standards," Federal Register 43 (182), September 19, 1978.
2-2. "Task 2 Summary Report -- Preliminary Summary of Industrial Boiler
Population," prepared by PEDCo in support of OAQPS work on NSPS
for industrial boilers, June 29, 1978. Also Section 3 of Task 2
Report, "The Industrial Steam Generator Industry," August 1978.
2-3. "Task 7 Summary Report -- Technical and Economic Bases for
Evaluation of Emission Reduction Technology," prepared by PEDCo in
support of OAQPS work on NSPS for industrial boilers,
June 2, 1978. Also as revised August 3, 1978.
2-4. Cato, G. A., et al.. "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers — Phase I," EPA-600/2-74-078a, NTIS-PB 238 920/AS,
October 1974.
2-5. Zeldovich, J., "The Oxidation of Nitrogen in Combustion and
Explosions," Acta Physicochim. U.S.S.RT (Moscow). Vol. 21 DD 4
1946. ' '
2-6. Mackinnon, D. J., "Nitric Oxide Formation at High Temperature,"
Journal of the Air Pollution Control Association. Vol. 24, No' 3
March 1974.
2-7. Bartz, D. R., et al.. "Control of Oxides of Nitrogen from
Stationary Sources in the South Coast Air Basin," California
ARB 2-1471, September 1974.
2-8. Shaw, J. T., and A. C. Thomas, "Oxides of Nitrogen in Relation to
the Combustion of Coal," presented at the Seventh International
Conference on Coal Science, Prague, June 1968.
2-9 Pershing, D. W., et al.. "Influence of Design Variables on the
Production of Thermal and Fuel NO from Residual Oil and Coal
Combustion," AIChE Symposium Series. No. 148, Vol. 71, pp. 12-29,
1975.
2-10. Mason, H. B., et al.. "Preliminary Environmental Assessment of
Combustion Modification Techniques: Volume II. Technical
Results," EPA-600/7-77-119b, NTIS-PB 276 681/AS, October 1977.
2-11. Pohl, J. H., and A. F. Sarofim, "Devolatilization and Oxidation of
Coal Nitrogen," presented at 16th International Symposium on
Combustion, M.I.T., Cambridge, Massachusetts, August 1976.
2-74
-------
2-12. United btates Senate, co^-ii tLee on Public Works, "Air Quality and
Stationary Source tmissiuns ontrol," Serial No. 94-4, March 1975.
2-13. Habelt, W. W., and B. M Howell, "Control of NO Formation in
Tangentially Coal-Fired Steam Generators," in Proceedings of the
NOy Control Technology Seminar. EPRI SR-39, NTIS-PB 253 611,
February 1976.
2-14. Pershing, D. W. and J. 0. L. Wendt, "The Effect of Coal Combustion
on Thermal and Fuel NOX Production from Pulverized Coal
Combustion," presented at Central States Section, The Combustion
Institute, Columbus, Ohio, April 1976.
2-15. Pershing, D. W., "Nitrogen Oxide Formation in Pulverized Coal
Flames," PhD Dissertation, University of Arizona, 1976.
2-16. Pohl, J. H. and A. F. Sarofim, "Fate of Coal Nitrogen During
Pyrolysis and Oxidation," in Proceedings of the Stationary Source
Combustion Symposium, Vol. I, Fundamental Research.
EPA 600/2-76-152a, NIIS-P3 256 320/AS, June 1976.
2-17. Giammar, R. D. and R. B. Engdahl, "Technical, Economic and
Environmental Aspects of Industrial Stoker -- Fuel Boilers,"
presented at 71st Annual Meeting of the Air Pollution "ontrol
Association, Houston, Texas, June 25-30, 1978.
2-18. Hunter, S. C. and J. J. Buening, "Field Testing: Application of
Combustion Modifications to Control Pollutant Emissions from
Industrial Boilers -- Phase I and II (Data Supplement),"
EPA-600/2-77-122, NTIS-PB 270 112/6BE, June 1977.
2-19. Maloney, K. L., et al., "Low Sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers," EPA-600/7-78-153a,
NTIS-PB 287-937/AS, July 1978.
2-20. Cato, G. A., et a!.. "Field Testing: Application of Combustion
Modification to Control Pollutant Emissions from Industrial
Boilers - Phase II," EPA-600/2-76-086a, NTIS-PB 253 500/AS, April
1976.
2-21. Gabrielson, J. E., et al.. "Field Test of Industrial Stoker
Coal-Fired Boilers for Emissions Control and Efficiency
Improvement — Site A," EPA-600/7-78-136a, NTIS-PB 285-172/AS,
July 1978.
2-22. Harstine, G. E., and D. C. Williams, "Industrial Pulverized
Coal-Fired Boiler Designed to Meet Today's Challenge," paper
presented at American Power Conference, Chicago, Illinois,
April 24-26, 1978.
2-75
-------
2-23. Schwieger, R. G., et al.. "Plant Design Today -- A New Challenge,"
Power Magazine, pp. 34, November 1976.
2-24. Lim, K. J., et al., "Environmental Assessment of Utility Boiler
Combustion Modification NOX Controls," Acurex Draft Report
TR-78-105, EPA Contract No. 68-02-2160, April 1978.
2-25. Campobenedetto, E. J., Babcock & Wilcox Co., Letter to K. J. Lim,
Acurex Corporation, November 15, 1977.
2-26. Rawdon, A. H. and S. A. Johnson, "Control of NOX Emissions from
Power Boilers," presented at Annual Meeting of the Institute of
Fuel, Adelaide, Australia, November 1974.
2-27. Brackett, C. E. and J. A. Barsin, "The Dual Register Pulverized
Coal Burner, a NOX Control Device," in Proceedings of the N0y
Control Technology Seminar. EPRI SR-39, NTIS-PB 253 661,
February 1976.
2-28. Campobenedetto, E. J., "The Dual Register Pulverized Coal
Burner — Field Test Results," presented to Engineering Foundation
Conference on Clean Combustion of Coal, New Hampshire, July 31 -
August 5, 1977.
2-29. Vatsky, J. and R. P. Wai den, "NOX — A Progress Report," Heat
Engineering, Volume 47, No. 8, July-September 1976.
2-30. Vatsky, J., "Attaining Low NOX Emissions by Combining Low
Emission Burners and Off-Stoichiometric Firing," presented at the
70th Annual AIChE Meeting, New York, November 15, 1977.
2-31. Gershman, R., et al.. "Design and Scale-up of Low Emission
Burners for Industrial and Utility Boilers," in Proceedings of the
Second Stationary Source Combustion Symposium Vol. V. Addendum.
EPA-6oO/7-77-073e, NTIS-PB 274 897/AS, July 1977. '
2-32. "Low NOX Burner Development," in NOV Control Review, D. G.
Lachapelle, ed., Volume 3, No. 2,~pp. 1, Spring 1978.
2-33. Fletcher, R. J., Peabody Engineering Corp., Telecommunication with
R. S. Merril, Acurex Corp., July 21, 1978.
2-34. Norton, D. M., et al., "Status of Oil-Fired NOX Control
Technology," in Proceedings of the NOX Control Technology
Seminar. EPRI SR-39, NTIS-PB 253 661, February 1976.
2-35. Thompson, R. E., and M. W. McElroy, "Effectiveness of Gas
Recirculation and Staged Combustion in Reducing NOX on a 560-MW
Coal-Fired Boiler," EPRI FP-257, NTIS-PB 260 582, September 1976.
2-76
-------
2-36. Lyon, R. K., "Method for the Reduction of Concentrations on NO in
Combustion Effluents Using Ammonia," United States Patent
No. 3.900.554. August 1975.
2-37. Muzio, L. J., et al., "Homogenous Gas Phase Decomposition of
Oxides of Nitrogen," EPRI Report FP-253, NTIS-PB 257 555,
August 1976.
2-38. "Non-Catalytic NOX Reduction Process Applied to Large Utility
Boilers," Mitsubishi Heavy Industries, Ltd., November 1977.
2-39. Bartok, W., "Non-Catalytic Reduction of NOX with NH3"
Proceedings of the Second Stationary Source Combustion Symposium
Volume II. EPA-600/7-77-073b, NTIS-PB 271 756. July 1977.
2-40. Muzio, L. J., et al.. "Non-Catalytic NO Removal with Ammonia,"
EPRI Final Report FP-735, Research Project 835-1, April 1978.
2-41. Lyon, R. K., and J. P. Longwell, "Selective Non-Catalytic
Reduction of NOX by NHs," in Proceedings of the N0¥ Control
Technology Seminar. EPRI SR-39, NTIS-PB 253 661, February 1976.
2-42. Copeland, J. 0., Draft of "Standards Support and Environmental
Impact Statement, Volume I: Proposed Standards of Performance for
Electric Utility Steam Generating Units (Nitrogen Oxides)," EPA,
December 1977.
2-43. Broz, L. D., Acurex Corp., Trip Report to D. Blann, Acurex Corp.,
Tour of Babcock & Wilcox Co. plant in Wilmington, N.C. arranged by
ABMA and EPA/IERL-RTP, September 21, 1978.
2-44. Giammar, R. D., Battelle Columbus Laboratory, Columbus, Ohio,
Telecommunication with H. I. Lips, Acurex Corp., July 19, 1978.
2-45. Axtman, W. H., ABMA, Arlington, Va., Telecommunication with H. I.
Lips, Acurex Corp., July 21, 1978.
2-46. Broz., L. D., Acurex Corp., Raleigh, N.C., Telecommunication with
H. I. Lips, Acurex Corp., Mtn. View, Ca., July 21, 1978.
2-47. Jordan, J., Worley Equipment Inc., Chicago, 111.,
Telecommunication with H. I. Lips, Acurex Corp., July 18, 1978.
2-48. Reschly, Detroit Stoker Co., Monroe, Michigan, Telecommunication
with H. I. Lips, Acurex Corp., July 18, 1978.
2-49. Higginbotham, E. B., Acurex Corp., Unpublished data supplied to
H. I. Lips, Acurex Corp., December 1978.
2-50. Fennelly, P. F., et al.. "Screening Study to Obtain Information
Necessary for the Development of Standards of Performance for
Solid-Fueled Boilers ( 63 x 106 kcal/hr Input),"
GCA-TR-76-23-G, July 1^76.
2-77
-------
2-51. Locklin, D. W., et al., "Design Trends and Operating Problems in
Combustion Modification of Industrial Boilers," EPA-650/2-74-032
NTIS-PB 235 712, April 1974.
2-52. Heap, M. P., et al., "Reduction of Nitrogen Oxide Emissions from
Field Operating Package Boilers, Phase III," EPA-600/2-77-025,
NTIS-PB 269 277, January 1977.
2-53. Cichanowicz, J. E., et al.. "Pollutant Control Technique for
Packaged Boilers. Phase I, Hardward Modifications and Alternate
Fuels," Ultrasystems Draft "Report, EPA Contract No. 68-02-1498,
November 1976.
2-54. Muzio, L. J., et al.. "Package Boiler Flame Modification for
Reducing Nitric Oxide Emissions — Phase II of III,"
EPA-R2-73-292, NTIS-PB 236 752/2BA, June 1974.
2-55. Carter, W. A., et al.. "Emissions Reduction on Two Industrial
Boiler with Major Combustion Modifications," EPA 600/7-78-099a
NTIS-PB 283 109, June 1978.
2-56. Morton, W., E. Keeler Co., Williamsport, Pa., Telecommunication
with R. J. Milligan, Acurex Corp., July 26, 1978'.
2-57. Hester, C., Acurex Corp., Raleigh, N.C., Trip Report to D. Blann,
Acurex Corp., Raleigh, N.C., Tour of E. Keeler Co. plant in
Williamsport, Pa., September 20, 1978.
2-58. Cato, G. A., et al., "Reference Guideline for Industrial Boiler
Manufacturers to Control Pollution with Combustion Modification,"
EPA-600/8-77-003b, NTIS-PB 276 715/AS, November 1977.
2-59. Schwieger, B., "Industrial Boilers: What's Happening Today,"
Power Magazine. Vol. 121, No. 2 pp. S.1-S.24, February 1977 and
Vol. 122, No. 2 pp. S.l-S-24, February 1978.
2-60. Ando, J., et al., NOX Abatement for Stationary Sources in
Japan," EPA-600/7-77-103b, NTIS-PB 276 948/AS, September 1977.
2-61. Koppang, R. R., "A Status Report on the Commercialization and
Recent Development History of the TRW Low NOX Burner," TRW
Internal Report, January 1976.
2-62. Ando, J., et al.. "NOX Abatement for Stationary Source in
Japan," EP7f^OD72-76-013b, NTIS-PB 250 586/AS, January 1976.
2-63. Koppang, R. R., TRW, Inc., Redondo Beach, California,
Telecommunication with R. S. Merrill, Acurex Corp., July 21, 1978.
2-64. Ando, J., et al., "Nitrogen Oxide Abatement Technology in Japan —
1973," EPA3?Z^7T-284, NTIS-PB 222 143, June 1974.
2-78
-------
2-65. Kido, N., Japan National Research Institute for Pollution and
Resources, Unpublished data supplied to K. J. Lim, Acurex Corp.,
August 1978.
2-66. Fenimore, C. P., "Formation of Nitric Oxide in Premixed
Hydrocarbon Flames," Proceedings of the 13th Symposium
(International) on Combustion, The Combustion Institute,
Pittsburg, Pa., 1971.
2-67. Eaton, S., Coen Company, Telecommunications with R. S. Merrill,
Acurex Corp., July 10, 1978 and August 8, 1978.
2-68. Cichanowicz, J. E., et al., "NOX Control Techniques for Package
Boiler: Comparison of Burner Design, Fuel Modification and
Combustion Modification," in Proceedings of the Second Stationary
Source Combustion Symposium. EPA-600/7-77-073e, NTIS-PB 274 897/AS,
July 1977.
2-69. Air and Water Pollution Report, "Exxon Corp. Stationary NOX
Emissions Significantly Reduced at Plant," February 20, 19/8.
2-70. Barsin, J. A., "Pulverized Coal Firing NOX Control," presented
at Second EPRI NOX Control Technology Seminar, Denver, Colorado,
November 8-9, 1978.
2-71. Commercial Application of Exxon Thermal DeNOx Process, Sales
Brochure, Exxon Inc., 1978.
2-72. Habelt, W. W., "The Influence of the Coal Oxygen to Coal Nitrogen
Ratio on NOX Formation," presented at the 70th Annual AIChE
Meeting, New York, November 13-17, 1977.
2-73. Marshall, J. J., and A. P. Selker, "The Role of Tangential Firing
and Fuel Properties in Attaining Low NOX Operation for NOX
Control Technology Seminary, Denver, Colorado, November 8-9, 1978.
2-74. Krippene, B. C., "Burner and Boiler Alternations for NOX
Control," presented to Central States Section, The Combustion
Institute, Madison Wisconsin, March 26-27, 1974.
2-75. Barr, W. H., et a!.. "Modifying Large Boilers to Reduce Nitric
Oxide Emissions, Chem. Eng. Prog., Vol. 73, pp. 59-68, July 1977.
2-76. Castaldini, C., et al.. "Technical Assessment of Exxon"s Thermal
DeNOx Process," Acurex Final Report 79-301, EPA Contract
68-02-2611, April 1979.
2-77. Boughton, M., TRW, Inc., Redondo Beach, CA, Telecommunication with
K. J. Lim, Acurex Corp., May 21, 1979.
2-78. Matthews, B. J., TRW, Inc., Redondo Beach, CA, letter to W. Peters,
EPA, IERL-RTP, NC, March 23, 1979.
2-79
-------
2-79. Martin, G. B., "Field Evaluation of Low N0« Coal Burners on
Industrial and Utility Boilers," in Proceedings of the Third
Stationary Source Symposium. Volume I, EPA-600/7-79-050a, February
T979T
2-80
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SECTION 3
CANDIDATES FOR BEST SYSTEMS OF EMISSION REDUCTION
This section identifies and discussed alternative combustion
modification control techniques capable of achieving moderate,
intermediate, and stringent levels of NO control. These control levels
rt
are based on uncontrolled baseline emission levels and the capabilities of
combustion modification controls. Candidate systems of emission reduction
may involve either single or combined applications of the techniques
characterized in Section 2. The selection of candidate control systems
for each industrial boiler/fuel category was based on an assessment of the
effectiveness, commercial availability or R&D status, operational impact
and reliability of each control system. Energy, environmental, and cost
impacts are also considered; however detailed evaluation is deferred to
later sections of this report.
3.1 CRITERIA FOR SELECTION
In selecting the best system of NO emission reduction, many
/\
factors have to be considered, including
• Control effectiveness and applicability
• Reliability and availability
• Process impacts
• Environmental impacts
• Capital and operating costs, including energy impacts
The effectiveness of controls in reducing NO emissions, and their
A
applicability to industrial boilers as well as their reliability, were
used to select preliminary candidate control systems. Techniques were
considered if they were expected to be available for new boilers sold in
1983 or sooner (Reference 3-1). Performance data for these preliminary
candidates were than carefully reviewed to identify any demonstrated or
3-1
-------
expected process or environmental impacts. For example, major impacts
such as severe derating of the boiler can make a control option no longer
viable. Environmental impacts were evaluated through the analysis of
measured or postulated incremental emissions, other than NO , when
^
controls are implemented. Finally, capital and operating costs, including
energy impacts, were considered. These costs were used to decide between
favorable alternative control options, or in the case of costly but highly
effective techniques, to defer application until stringent control levels
are absolutely necessary.
All of the above listed factors were considered by evaluating
detailed field test results when available and through discussions with
major equipment manufacturers and users, and control R&D groups.
In the ensuing discussion of emission control technologies,
candidate technologies were compared using three emission control levels
labelled "moderate, intermediate, and stringent." These control levels
were chosen only to encompass all candidate technologies and form bases
for comparison of technologies for control of specific pollutants
considering performance, costs, energy, and environmental effects.
From these comparisons, candidate "best" technologies for control
of individual pollutants are recommended for consideration in subsequent
industrial boiler studies. These "best technology" recommendations do not
consider combinations of technologies to remove more than one pollutant
and have not undergone the detailed environmental, cost, and energy impact
assessments necessary for regulatory action. Therefore, the levels of
"moderate, intermediate, and stringent" and the recommendation of "best
technology" for individual pollutants are not to be construed as
indicative of the regulations that will be developed for industrial
boilers. EPA will perform rigorous examination of several comprehensive
regulatory options before any decisions are made regarding the standards
for emissions from industrial boilers.
Two factors were primarily considered in selecting these levels of
control. The first criterion is the baseline uncontrolled emission level
for each industrial boiler/fuel category. The second is the recorded or
estimated NOX reduction effectiveness of each combustion modification
control. Careful consideration of the uncontrolled baseline NOX level
3-2
-------
and the percent reduction in emissions that is attributable to selected
control systems determines the degree of control.
Baseline emission factors are extremely important because they
ultimately determine what control levels are achievable and which control
are appropriate. For example, if a conservative or high baseline emission
level is used, then the selected control levels based on reported NO
A
reduction will also be conservative and easier to obtain. On the other
hand, if a low baseline NO level is used, a selected moderate control
A
level may prove difficult to achieve. As a review of the limited emission
data will show (see Section 7), baseline (and controlled) emissions levels
were quite variable in some cases and well defined in other cases. So the
general caution is that the baseline (and controlled) emission levels
should be considered only tentative because of the limited data. However,
it should be noted that the moderate control levels suggested here for the
boiler/fuel catergories considered are generally conservative in the sense
that demonstrated control techniques have, in specific instances, achieved
controlled NO levels lower than the suggested moderate levels.
A
Table 3-1 lists the baseline NO emission factors selected after
A
review of all available data. The table also compares these selected
levels to the previously suggested emission factors (Reference 3-29)
contained in EPA Document AP-42 (Reference 3-2). Emissions data for
pulverized coal-fired industrial boilers are limited to six units
(References 3-3 through 3-5). These emissions ranged from 174 ng/J to 563
ng/J and the size of the units ranged from 47 MW to 147 MW (160 to 500 x
10 Btu/hr) of heat input3. There was no general correlation between
NO emission levels and boiler size/type-or coal characteristics.
The NO emission levels given in AP-42 (Reference 3-2) for
A
coal-fired stokers consist of only one number (273 ng/J) which was derived
from data on spreader stokers only. That number is in good agreement with
the NO baseline level (265 ng/J) selected in this study for spreader
A
stokers, as shown in Table 3-1. However, the AP-42 number is in very poor
agreement with the reported averages for the underfeed and the chain grate
aNote: NOX emission data dicussed in this report are all listed in
Section 7, along with boiler and fuel characteristics.
3-3
-------
TABLE 3-1. COMPARISON OF BASELINE NOX EMISSION LEVELS
OJ
Fuel
Pulverized Coal
Stoker Coal
Residual Oil*
Distillate Oil
Natural Gas
Boiler T>pe
Single Mall
and Tangential
Spreader
Underfeed
Chain Grate
Flretube
Hatertube
Hatertube
Flretube
Hatertube
Uatertube
Flretube
Uatertube
Uatertube
Typical Size
(Heat Input
Capacity)
M(1(P Btu/hr)
59(200)
114(400)
44(150). 25(85)
9(30)
22(75)
4.4(15)
8.8(30)
44(150)
4.4(15)
29(100)
44(150)
4.4(15)
29(100)
44(150)
No. Of
Boilers
Tested
4
2
7,5
2
2
5.
10
7
6
4,3
1
8
9.11
7
Average
NO. Baseline
Eimslon Level
ng ND2/J(lb/10* Btu)
285(0.663)
285(0.663)
265(0.616)
150(0.349)
140(0.326)
115(0.267)
160(0.372)
160(0.372)
75(0.175)
55b, 90C(Q.12&, 0.209°)
90C(0.209C)
40(0,093)
45b, 110c(0.105b. 0.255C)
120C(0.280)C
AP-42 (Ref. 3-2)
NO. Baseline
'Emission -Level
ng N02/J(lb/I06 Btu)
328(0.763)
328(0.763)
273(0.635)
273(0.635)
273(0.635)
—
171(0.398)
171(0.398)
68(0.158)
—
75(0.174)
--
Sources of Data
Used for
Selected Baseline
Emissions
Ref. 3-3, 3-4. 3-5
Ref. 3-3. 3-4. 3-5
Ref. 3-2 through 3-6
Ref. 3-3
Ref. 3-4. 3-5
Ref. 3-3, 3-4. 3-8
Ref. 3-3, 3-4, 3-8. 3-9
Ref. 3-3, 3-4
Ref. 3-3, 3-4
Ref. 3-3, 3-4, 3-9
Ref. 3-3. 3-4
Ref. 3-3, 3-4, 3-10
Ref. 3-3, 3-4, 3-9
Ref. 3-3, 3-4
•includes No. 5 «id No. 6 fuel oils.
''Fro* boilers not equipped with air preheaters.
boilers equipped with air preheaters.
-------
units. This stands to reason as spreader stokers are known to be higher
NO emitters than underfeed units (Reference 3-3). This study
A
incorporates new data made available since Document AP-42 and updates were
published.
All other selected NO baseline emission data generally agree
A
with the AP-42 emission levels except that for natural gas-fired firetube
boilers which show a difference of 35 ng/J. This disparity is due to two
reasons. The first is that Document AP-42 gives a range for natural
gas-fired firetube boilers and the final value chosen by that document is
from the high end of that range. The second reason is that the AP-42
emission factor is derived from a more limited data base than that
reviewed in this study. This, as well as other emission data, is well
documented in Section 7 of this report.
The NO emission factors selected in this study agree with the
A
results for industrial boilers from a recent study to update EPA Document
AP-42 emission factors (Reference 3-14).
In addition to the original seven standard boiler/fuel categories
recommended by PEDCo (Reference 3-28), three other categories were
considered: residual oil-fired firetube boilers and distillate oil- and
gas-fired watertube boilers. Furthermore, for the latter two categories,
a distinction was made between boilers equipped with air preheaters and
those that are not. The baseline NO emissions for these three
A
additional categories are clearly different from the original seven;
therefore they should be treated separately when assessing the feasibility
of reducing emissions to a predetermined control level. Finally, four
additional size variations of the above 10 standard boiler/fuel categories
were requested by EPA to further aid in the economic assessment of
controls, bringing the total boiler/fuel cases treated to 14
(Reference 3-32).
With the baseline emission levels of each industrial boiler/fuel
category established (to the extent possible as limited data permitted),
the capabilities of the available control techniques were carefully
reviewed to select the best control options and establish achievable
control levels. Tables 3-2 through 3-5 summarize the performance of the
candidate control systems for pulverized coal-, stoker coal-, residual
oil-, distillate oil-, and gas-fired boilers, respectively. These
3-5
-------
TABLE 3-2. CANDIDATES FOR BEST SYSTEMS OF NOX EMISSIONS REDUCTION:
PULVERIZED COAL-FIRED BOILERS
Technique
Effectiveness*
(I NOK Reduction)
Operational Impact
Cost Impact"
Environmental Impact
Availability
GO
en
Low Excess Air
Over fire Air
Reduced
Combustion
Intensity
Low NO,
Burners
NH3 Injection
5 - 25
5-30
5 - 25
45-60
40-60
Increased boiler efficiency.
Possible Increased slagging.
corrosion. Perhaps slight
decrease In boiler
efficiency.
None. Best Implemented as
Increased furnace plan area
in MM designs.
None expected.
Possible Implementation dif-
ficulties. Fouling problems
with high sulfur fuels, load
restrictions. Close operator
attention required.
Increased efficiency offsets
capital and operating costs.
Hijor Modification. Narglnal
increase In cost for new
units.
H*jor modification. Narglnal
Increase In cost for new
units.
Potentially most cost-
effective.
Several fold higher than
conventional combustion
Modifications.
Possible Increased CO
and organic emissions.
Possible Increased
parttculate and
organic emissions.
None
None expected.
Possible emissions of
NH3 and byproducts.
Available
Commercially offered but
not demonstrated for this
boiler/fuel category
Technology transfer
required from utility
Industry
1981 - 1983C
Commercially offered
but not demonstrated
"Effectiveness based on control applied singly
Incremental cost impact noting capacity/cost of boiler to which control is applied.
cReferences 2-79, 3-30
-------
TABLE 3-3. CANDIDATES FOR BEST SYSTEMS OF NOX EMISSIONS REDUCTION:
STOKER COAL-FIRED BOILERS
Technique
Effectiveness*
(I NOX Reduction)
Operational Impact
Cost Impact0
Environmental Impact
Availability
co
i
Low Excess Air
Overfire Air
5-25
5 - 25
NH} Injection
40-60
Possible grate overheat.
clinker formation. Increased
corrosion. Close operator
attention required.
Possible grate overheat.
clinker formation. Increased
corrosion. Close operator
attention required. Perhaps
slight decrease in boiler
efficiency.
Possible Implementation dif-
ficulties. Fouling problems
with high sulfur fuels, load
restrictions. Close operator
attention required.
Increased efficiency should
partially offset costs.
Major modification of grate
and OFA, probably costly.
Present units have OFA for
smoke control only.
Several fold higher than
conventional combustion
modifications.
Possible Increased CO.
organic, and particu-
late emissions.
Possible Increased CO.
organic, and panicu-
late emissions.
Possible emissions of
NH and byproducts.
Available
R40
Commercially offered
but not demonstrated
'Effectiveness based on control applied singly.
''incremental cost Impact noting capacity/cost of boiler to which control is applied.
-------
TABLE 3-4. CANDIDATES FOR BEST SYSTEMS OF N0¥ EMISSIONS REDUCTION:
RESIDUAL OIL-FIRED BOILERS x
CO
CO
Technique
Loo Excess Air
Staged
Combustion
Lo« NO
Burners
NHj Injection
Effectiveness*
(S NOg Reduction)
5 - 20
20 - 40
20 - SO
40 - 70
Operation*! Impact
Increased boiler efficiency.
Perhaps slight decrease in
boiler efficiency.
None expected.
Possible implementation dif-
ficulties. Fouling problem
with high sulfur fuels, load
restrictions. Close operator
attention required.
Cost Impact*
Increased efficiency par-
tially offsets costs.
Major Modification, perhaps
costly.
Potentially east cost-
effective.
Several fold higher than
conventional embus t ton
Modification.
Environment*) Impact
Possible increased CO
and organic emissions.
Possible Increased
paniculate and organic
emissions.
None expected.
Possible emissions of
NMj and byproducts.
Availability
Available
Commercially offered but
not demonstrated for
this boiler/fuel category
Coawrclally offered but
not demonstrated
Commercially offered but
not demonstrated
'Effectiveness based on control applied singly.
Incremental cost impact noting capacity/cost of boiler to which control is applied.
-------
TABLE 3-5. CANDIDATES FOR BEST SYSTEMS OF NOY EMISSIONS REDUCTION:
DISTILLATE OIL- AND GAS-FIRED BOICERS
Technique
LOM Excess Air
Staged
Combustion
Flue C*s
Reclrculatlon
Reduced Air
Preheat
LOM NO
Burners
Effectiveness*
(I NOg Reduction)
5 - IS (oil).
5 - 10 (9*s)
20 - 40 (oil).
25 - 45 (gas)
40 - 70 (oil)
45 - 75 (gas)
20 - 55 (oil)
20 - 55 (gas)
20 - 50
Operational Impact
Increased boiler efficiency.
Perhaps slight decrease in
boiler efficiency.
Possible flaw Instability.
Can be eliminated with proper
engineering/ testing.
Replacing air preheater with
economizer In new designs.
None expected.
Cost Impact1*
Increased efficiency should
offset some of costs.
Major modification, probably
costly.
Major modification, probably
costly.
None, other than engineering
redesign of new units (if
necessary).
Potentially most cost-
effective.
Environmental Impact
Possible increased CO
and organic emissions.
Possible Increased
organic emissions.
Possible increased
organic emissions.
None
None expected.
Availability
Available
Commercially offered but not demonstrated
for this boiler/fuel catetory
Available
Available
Commercially offered but not demonstrated
oo
'Effectiveness based on control applied singly.
Incremental cost impact noting capacity/cost of boiler to which control is applied.
-------
candidate systems are the result of the preliminary review in Section 2.
Table 3-6 summarizes suggested emission levels for moderate, intermediate,
and stringent control.
For moderate control levels the NO reduction required from
A
baseline emissions varies from approximately 5 to 20 percent, depending on
the boiler/fuel category. For example, in the case where fully
demonstrated and commercially available control systems could only reduce
NO emission by 5 percent, this reduction was used to establish the
A
moderate control level. However, if the demonstrated and commercially
available control system was very effective in reducing NO by
A
20 percent without foreseeable operational problems, this reduction was
used in selecting the moderate control level. For example, by replacing
air preheaters with economizers on new watertube boilers firing natural
gas, the NO emissions may be reduced at least 20 percent from the
A
average baseline level of 110 ng/J.
For intermediate control levels, the NO reduction required from
A
baseline emissions varies from approximately 20 to 40 percent. Control
systems include both commercially available and developing combustion
modification techniques. For example, new pulverized coal-fired boilers
can operate with staged combustion using overfire air ports thus reducing
NO emissions 20 to 30 percent from the respective baseline levels. An
example of developing technology for intermediate control of residual
oil-fired boilers would be low NOY burners.
A
For stringent control levels, the NO reduction required from
A
baseline emissions varies up to approximately 60 percent. Often the same
control system which is capable of achieving the intermediate control
level can also achieve the stringent level by simply increasing the degree
of control. For example, flue gas recirculation (F6R) can reduce NO
A
emissions up to 75 percent for natural gas combustion by increasing the
FGR rate up to 40 percent (References 3-4, 3-8 and 3-9). In some cases,
the stringent control level requires technology still under development,
such as ammonia injection for residual oil-fired watertube boilers.
Occasionally the control system capable of achieving drastic NOX
reductions combines two or more combustion modification techniques. For
3-10
-------
TABLE 3-6. SUGGESTED NOV CONTROL LEVELS FOR INDUSTRIAL BOILERS
A
Fnol
rue 1
Coal: Units _>29 MW Heat Input3
Coal: Units <29 MW Heat Input
Residual Oil
Distillate Oil and Gas
Control Level, ng N02/J (lb N02/106 Btu)
Moderate
301 (0.7)
215 (0.5)
129 (0.3)
86 (0.2)
Intermediate
258 (0.6)
172 (0.4)
108 (0.25)
65 (0.15)
Stringent
215 (0.5)
129 (0.3)
86 (0.2)
43 (0.1)
CO
I
It is suggested that spreader stokers be placed at these moderate, intermediate, and
stringent levels, regardless of heat input capacity.
-------
example, reduced air preheat and FGR are required for distillate oil- and
gas-fired watertube boilers with air preheaters.
The following sections discuss the alternative NO emission
A
control systems for industrial boilers necessary to reduce emissions to
the three levels of control. For each boiler/fuel category, the best
candidate NOX control systems are identified for the moderate,
intermediate, and stringent control levels.
3.2 CANDIDATE CONTROL SYSTEMS FOR COAL-FIRED INDUSTRIAL BOILERS
NO formation from coal combustion is primarily from fuel NO .
A J\
In fact, laboratory studies under controlled operating conditions have
shown that fuel NO can account for up to 80 percent of the total NO
« X
from combustion of coal (Reference 3-11). In principle, the best strategy
for fuel NO abatement combines low excess air firing, optimum burner
A
design, and staged combustion.
Tables 3-7 and 3-8 list the candidates for best control system for
coal-fired industrial boilers with heat inputs greater than and less than
29 MW (100 x 10 Btu/hr) heat input, respectively. These control
systems were selected from the candidates summarized in Tables 3-2 and
3-3. Coal-fired units are divided at 29 MW (100 x 106 Btu/hr) heat
input since the larger units tend to have higher NO emissions levels.
A
Pulverized coal-fired boilers and spreader stokers are generally larger
than 29 MW (100 x 106 Btu/hr) of heat input (References 3-3, 3-11).
However, spreader stoker units smaller than 29 MW are not uncommon.
Underfeed and chain grate stokers generally have heat input capacities of
less than 29 MW, and generally produce lower NO emission levels than
A
the larger spreader stokers and pulverized coal units. Cyclone boilers
have not been included since sales of these units have halted since 1974
(Reference 3-31). Their baseline N0x emisions are extremely high
(approximately 650 ng/J, 1.51 lb/106 Btu), and not easily amenable to
control (Reference 3-13).
The folKrfing subsections present the criteria for selecting the
control systems presented in Tables 3-7 and 3-8 and the order in which
they were selected. Each subsection pertains to the individual boiler
equipment type identified.
3-12
-------
TABLE 3-7. BEST CONTROL SYSTEMS FOR COAL-FIRED INDUSTRIAL BOILERS
WITH HEAT INPUT > 29 MW (100 x 106 Btu/Hr)a
Boiler Equipment Type
Pulverized Coal-Fired
Spreader Stoker
Baseline
NOX Emissions
ng/J (lb/106 Btu)
285 (0.663)b
265 (0.616)
Moderate
301 ng/J (0.7 lb/106 Btu)
No control necessary0
No control necessary
Level of Control
Intermediate
258 ng/J (0.6 lb/106 Btu)
1. Low excess air
2. Overflre air
Low excess air
Stringent
215 ng/J (0.5 lb/106 Btu)
1. Overfire air*
2. Low NOX burner***
3. Ammonia Injection0**
Low excess air/
Overflre air***
aLow excess air operation is recommended practice whenever controls are required. However combination of LEA and OFA
is not recommended for pulverized coal tangential units (see Section 3.2.1.2).
btflde range of baseline emissions reported (see Section 3.2.1.1)
*-Some units may require low excess air.
^3 Injection required only for those units with unusually high baseline emissions.
*Comnerc1ally offered but not demonstrated for this boiler/fuel category.
**Cownerdaily offered buy not demonstrated.
***Under research and development.
T-1759
-------
TABLE 3-8. BEST CONTROL SYSTEMS FOR COAL-FIRED INDUSTRIAL BOILERS
WITH HEAT INPUT <29 MW (100 x 106 Btu/Hr)
Boiler Equipment Type
Spreader Stoker
Chain Grate
Underfeed
Baseline
NOx Emissions
ng/J (lb/10* Btu)
265(0.616)
140(0.326)
150(0.349)
Moderate
215 ng/J (0.5 1b/106 Btu)
Low excess alr/overflre air***
No control necessary
No control necessary
Level of Control
Intermediate
172 ng/J (0.4 lb/106 Btu)
Amnonla Injection**
No control necessary
No control necessary
Stringent
129 ng/J (0.3 lb/106 Btu)
Amonla Injection**
Low excess air
Low excess air
**Con»erdally offered but not demonstrated.
***Under research and development.
co
i
-------
3.2.1 Pulverized Coal-Fired Boilers
Industrial size pulverized coal-fired boilers can be subdivided
into two categories based on the firing mode of the burners in the
furnace: tangential and single wall firing. No significant differences
in NO emission levels were observed between these two firing types (see
A
Section 7) although recent data indicated difference in NO emissions
/\
for utility size units of these two firing types (References 3-14 and
3-15).
As stated earlier, information on baseline as well as controlled
NO emissions from pulverized coal-fired industrial size boilers is very
/\
limited. Therefore the selection of the applicable control systems for
each of the three control levels relied heavily on utility boiler
experience with combustion modifications (Reference 3-13).
3.2.1.1 Moderate Control Level
No control should be necessary to achieve the moderate control
level of 301 ng/J as the selected baseline NO emission leve is 285
ng/J. The moderate control level was set at 301 ng/J and not any lower
because of the broad range in baseline NO emissions for the six units
A
tested, ranging from 174 to 563 ng/J with most data between 201 and
296 ng/J, yielding an average baseline of 285 ng/J. No significant
correlation of emission levels with boiler type or size or coal
characteristics were evident from a review of the data presented in
Table 7-2 (see Section 7).
3.2.1.2 Intermediate Control Level
Combustion modifications capable of reducing NO emission from
/v
285 to the intermediate control level of 258 ng/J (10 percent reduction)
include low excess air and overfire air. Low excess air (LEA) operation
should be capable of achieving the intermediate control level in all but a
few cases. Overfire air (OFA) should satisfy the remaining cases.
Combination of LEA with OFA has been known to reduce N0x emissions from
utility boilers by 30 percent; however it is not recommended for
tangential boilers (Reference 3-13). Combustion Engineering, the
manufacturer of tangential boilers, recommends using normal overall
furnace excess air levels with OFA operation to ensure no coincident
increase of unburned carbon in the flyash or carbon monoxide emissions
from their units (References 3-33 and 3-34).
3-15
-------
The LEA and OFA control system has the primary advantage over the
other control systems because of its commercial availability and its
effectiveness. The cost of the system is not prohibitive when NO ports
A
are designed as a part of new boilers. In addition, careful operation of
staged air injection is not expected to seriously affect emissions of
other criteria pollutants3. Burner stoichiometries in the range of 100
to 110 percent would be adequate to achieve a 20 percent NO reduction
A
(Reference 3-15). At these stoichiometry levels the oxidizing atmospheres
would prevail in the furnace, thus minimizing concern over possible
furnace slagging and boiler tube wastage.
3.2.1.3 Stringent Control Level
Achieving the stringent NOX emission level of 215 ng/J represents
a 25 percent reduction from baseline. Combined low excess air and
overfire air operation can achieve this level of control. However, burner
stoichiometries would have to be reduced below 100 percent in some cases
(Reference 3-13). This low burner stoichiometry level would cause
reducing atmospheres in parts of the furnace, thus creating the potential
for corrosion of water tubes (Reference 3-13). Generally boiler
manufacturers do not recommend burner operation with stoichiometry levels
below 100 percent primarily because of increased corrosion potential.
Therefore LEA/OFA is recommended as the stringent control technique with
the proviso that further field testing and demonstrations may be necessary.
Because of the possible operational problems associated with OFA,
low NO burners (LNB) were selected as the first backup candidate for
A
achieving the stringent control level. Reported NO reductions for
A
utility size units are of the order of 45 to 60 percent (References 3-16
and 3-17). Similar reduction efficiencies are projected for industrial
low NO burners under development. Therefore LNB is expected to easily
A
meet the 215 ng/J control level, a 25 percent reduction from the average
baseline level. Once developed, low N0x coal-fired burners for
industrial joilers could become the candidate control system because of
the expected lower cost and other operational advantages over the staged
aThe effect of combustion modifications on other criteria pollutants is
discussed in Section 6.
3-16
-------
combustion method of OFA. One such burner is being developed by Peabody
Engineering Corporation and will be tested by Energy and Environmental
Research Corp. (EER) (Reference 3-18).
If low NO burners are not commercialized by 1983, ammonia
A
injection is the alternative stringent control system. Also ammonia
injection may be required for those pulverized coal-fired units with
unusually high baseline NOX emissions. However, NH3 injection is
several times more costly than conventional combustion modification
controls. In addition, as a developing technology, there are several
implementation and operational problems that need to be resolved. The
optimal effectiveness for noncatalytic reduction of NO by NH, occurs in
a very narrow temperature range, approximately 1240 +_ 50K (1770
_+ 90°F). Hence, precise location of the NH- injection ports is
crucial. Since the temperature profile in a boiler changes with load,
NOX control with NH^ may dictate load restrictions on the boiler.
Other potential problems include fouling and emissions of NH3 and
byproducts. However, the major strengths of the technique are its
potential for high NO removal (40 to 60 percent), and its applicability
A
as an additional control that can be combined with conventional combustion
techniques for extremely large NO reductions (Reference 3-19).
A
3.2.2 Spreader Stoker Boilers
Field test data of NOX combustion modifications on spreader
stoker fed coal-fired boilers come from four EPA-sponsored programs
(References 3-3 through 3-7, and 3-35). The coal in a spreader stoker
boiler burns partly in a suspended state and partly on a moving or
vibrating grate. The combustion of coal in the suspended state apparently
causes NO emissions to be generally higher than for other stoker types
/\
which feed and combust coal directly on a moving grate. Baseline
uncontrolled NO emission averaged 265 ng/J for twelve spreader stoker
A
industrial boilers (References 3-3 through 3-7, and 3-35). No significant
correlation was observed between NO emission levels and unit capacity
or fuel properties (e.g., coal type, fuel nitrogen), as a review of the
data in Section 7 will show.
Spreader stokers generally range in size from 2.9 MW
(10 x 106 Btu/hr) to 146 MW (500 x 106 Btu/hr) heat input
3-17
-------
(Reference 3-14). The smaller units, i.e., those under 29 MW (100 x
10^ Btu/hr), may have to meet stricter control levels than the larger
units, according to Table 3-6. The candidate control systems are
summarized in Tables 3-7 and 3-8).
Spreader stoker boilers are listed in both Tables 3-7 (> 29 MW) and
3-8 ( <29 MW) because this design type is offered over a large range of
heat input capacities. However, because their average baseline emission
levels are relatively higher than those from other stoker designs, it is
recommended that spreader stokers be grouped with pulverized coal units as
far as potentially achievable emission control levels are concerned.
Spreader stokers are listed together with other stoker types in Table 3-8
solely because of similarities in designs and hence in applicable control
techniques.
No control is necessary for meeting the moderate control level of
301 ng/J for spreader stokers larger than 29 MW. The intermediate control
level (258 ng/J) may be easily achieved by low excess air (LEA) firing.
Operating with LEA would result in increased boiler efficiency. Such
problems as grate overheat, clinker formation, and corrosion should be
minimized by limiting excess oxygen to 6 percent or more. For stringent
control (215 ng/J), LEA and overfire air operation will probably be
required. This can be accomplished by reducing undergrate air and
increasing overfire airflow through the OFA ports normally installed in
stokers. However, close operator attention will be required to avoid the
problems of grate overheat, clinker formation, and corrosion associated
with firing at too low excess air levels. Presently installed OFA ports
were intended only for smoke control. New units should incorporate OFA
ports designed for NO control. Potential environmental impacts as
/\
increased CO, particulate, and organic emissions warrant further testing.
To date, LEA and OFA represent the only significant NOX controls tested
on stokers.
According to Table 3-8, smaller spreader stokers ( <29 MW heat
input) are faced with stricter control levels, 215, 172, and 129 ng/J
(0.5, 0.4 and 0.3 lb/106 Btu) for moderate, intermediate, and stringent
control, respectively. The moderate level can be met with LEA and OFA.
However, the only control option for the intermediate and stringent level
3-18
-------
is ammonia injection, which as described earlier, is not demonstrated
technology for coal-firing. Therefore, it is recommended that spreader
stokers, regardless of capacity, be aligned with pulverized coal units as
far as potentially achievable control levels are concerned, as illustrated
in Table 3-7.
3.2.3 Chain Grate and Underfeed Stokers
Chain grate and underfeed stokers have generally less than 29 MW
(100 x 106 Btu/hr) heat input capacity. Neither stoker type requires
any controls until the stringent level of 129 ng/J is needed. This can be
achieved for chain grate (baseline 140 mg/J) and underfeed (baseline
150 ng/J) by reducing the excess air. Tests on new units indicate that
NO reductions of 10 to 30 percent are possible with low excess air.
/\
Hence LEA is the recommended technique (and the only effective technique
tested for underfeed stokers).
Stricter levels of control for chain grate and underfeed stokers
were not suggested in Table 3-8 because of the very limited number of
units tested (two each), and the lack of availability of effective control
techniques (besides low excess air operation).
3.3 CANDIDATE BEST CONTROL SYSTEMS FOR RESIDUAL OIL-FIRED INDUSTRIAL
BOILERS
Residual oil contains varying amounts of fuel bound nitrogen.
During an extensive EPA-sponsored industrial boiler field test program the
nitrogen found in residual oils (No. 5 and No. 6) varied from 0.1 to
0.52 percent (Reference 3-4). However, residual oils used in industrial
boilers may have nitrogen contents as high as 1.0 percent. Baseline NO
^
emissions from boilers burning residual oil are strongly affected by the
nitrogen content of the fuel. Boiler design factors such as heat input
capacity and combustion air temperature do not affect total NO
y\
emissions as much as nitrogen content of the oil.
Thus the contribution of fuel NO to total NO emissions is
^
comparable to the contribution from thermally generated NO . Combustion
^
modification controls which are most effective in reducing fuel NO are
A
essentially the same used for coal-fired units. These are primarily low
excess air firing and staged combustion. Both these controls limit the
oxygen availability in the primary combustion zone, thus reducing the
3-19
-------
formation of both fuel and thermal N0x. Table 3-9 lists the best
systems of combustion modification for residual oil-fired industrial
boilers. These units have been separated into two main categories,
firetube and watertube, based on the uncontrolled baseline emission
factors. Firetube boilers are generally lower than 9 MW heat input (30 x
106 Btu/hr) (Reference 3-12). These units usually have lower combustion
intensities than watertube units of the same size, contributing to lower
thermal NO formation (Reference 3-8). Baseline NO emissions for
A
firetube boilers averaged 115 ng/J while watertube units averaged 160 ng/J.
The following subsections summarize the candidate NO combustion
/\
modification control systems shown in Table 3-9.
3.3.1 Firetube Boilers
Since baseline NOX emissions from firetube boilers burning
residual oil averaged only 115 ng/J, no controls are generally necessary
for these units to meet the moderate control level of 129 ng/J. However,
controls are necessary to reduce N0y emissions to the intermediate and
stringent levels of 108 and 86 ng/J respectively.
3.3.1.1 Intermediate Control Level
Since firetube boilers require only a 6 percent NOV reduction to
J\
reach the intermediate level of control (108 ng/J), low excess air firing
should easily be adequate. Low excess air operation should also increase
boiler efficiency. The same caution about possible increased CO and
organic emissions discussed earlier for coal-firing under LEA apply here
also.
3.3.1.2 Stringent Control Level
To meet the stringent control level of 86 ng/J, low NO burners
A
are the most attractive method of control. Staged combustion has been
investigated on one (3.5 MW, 12 x 106 Btu/hr) firetube boiler with
reductions in NO emissions of up to 50 percent (References 3-8 and
A
3-20). However, staged combustion cannot be easily implemented on these
small packaged "iretubes, and no feasible air injection system is under
development for commercial application.
3-20
-------
TABLE 3-9. BEST CONTROL SYSTEM FOR RESIDUAL OIL-FIRED INDUSTRIAL BOILERSa
co
i
ro
t— '
Boiler Equipment Type
Firetube
Water tube
Baseline
NOX Emissions
ng/J (lb/10b Btu)
115 (0.267)
160 (0.372)
Level of Control
Moderate
129 ng/J (0.3 lb/106 Btu)
No control necessary
1. Low excess air
2. Low NOX burners**
3. Staged combustion*
Intermediate
108 ng/J (0.25 Ib/lflS Btu)
Low excess air
1. Low NOX burners**
2. Staged combustion*
Stringent
86 ng/J (0.2 lb/106 Btu)
1. Low NOX burners**
2. Staged combustion***
1. Low NOX burners**
2. Ammonia injection**
aLow excess air is recommended practice whenever controls are required.
Commercially offered but not demonstrated for this boiler/fuel category.
**Commerc1ally offered but not demonstrated.
***Research and development.
T-1760
-------
Thus low NOX burners (LNB) remain as a potentially viable
technique. Low N0x burners reduce NOX emissions primarily by
operating on one of the following principles:
• Controlled mixing (to permit rapid quenching of the flame and
reduce residence time at peak flame temperature)
t Divided flame (to provide more rapid cooling of flame)
t Self-recirculation (to dilute combustion gases and reduce peak
flame temperature)
• Staged combustion (to reduce available excess oxygen)
As expected from the discussion in Section 2, the
self-recirculation and staged combustion burner types are more effective
with residual oil (high fuel nitrogen) combustion. Reductions in NO
ranging from 20 to 50 percent have been reported with commercialized
Japanese LNB and experimental domestic LNB. The Kawasaki two-stage
combustion type LNB and the LNB being developed by EER, as discussed in
Section 2, are two candidate burners for controlling NO from residual
oil-fired boilers. However, neither burner is presently commercially
available. The TRW burner which is commercially offered but not
demonstrated may prove to be effective. Note, though, that the heat input
capacity per burner of these LNBs may be too large for application to the
smaller packaged firetubes. However, they represent potentially the most
cost-effective method of high N0x reduction with little expected adverse
operational or environmental impact.
3.3.2 Watertube Boilers
As shown in Table 3-9 the baseline uncontrolled NO emissions
/\
from packaged and field erected watertube boilers averaged approximately
160 ng/J. The capacity of the boiler and the temperature of the
combustion air did not have a significant effect on the baseline emission
level (References 3-3, 3-4, 3-9). Combustion modification NO controls
A
are necessary to reduce emissions to all three levels of control.
The following subsections discuss the criteria for selecting the
control systems listed in order of priority in Table 3-9 for each of the
control levels investigated.
3.3.2.1 Moderate Control Level
The moderate NOX control level of 129 ng/J can be obtained by
operating the watertube boiler with a 3 percent excess oxygen level or
3-22
-------
lower. Section 2 indicated that NO emissions were reduced 18 to
A
23 percent by reducing excess oxygen to the range of 3.1 to 4.2 percent.
Achieving the moderate emission level represents a 19 percent reduction.
Operation of watertube boilers with excess oxygen levels in the
flue gas on the order of 3 percent is a feasible and demonstrated method
of achieving NO reductions. The technique has additional advantages
A
such as increased boiler thermal efficiency, reduced fan power
requirements and reduced sulfur trioxide formation for both residual oil
and coal combustion ~ a cause of acid smut emissions, corrosion and
fouling (Reference 3-21). Furthermore, low excess air operation also
seems to reduce particulate emissions. One EPA study reported
approximately 30 percent drop in particulate emissions when burning
residual oil (Reference 3-4). Operation at low excess air levels (less
than 15 percent) is not favored by industrial boiler operators because of
possible smoke emissions during rapid heat changes and possible formation
of combustibles with unburned fuel creating a safety hazard. These
disadvantages of LEA operation can be avoided by installing controls and
implementing a comprehensive maintenance program. The increased costs due
to more sophisticated controls and increased maintenance can be balanced
by the fuel savings through increased boiler efficiency.
Burner manufacturers currently offer burners that can operate at
very low excess oxygen levels (3 to 5 percent). These burners are of the
axial flow type. Windbox air distribution is carefully controlled, and
low-turbulent air is mixed with the fuel. The carefully controlled air
flow eliminates the necessity of high excess air to assure complete mixing
and combustion (Reference 3-21).
Alternative control systems include low NO burners and staged
A
combustion. Low NOX burners represent a better alternative for package
single burner watertube units because staged air injection is not
feasible. The two staged air injection designs presented in Section 2 are
considered experimental. In fact, one boiler manufacturer indicated that
operation of such a system would be too complicated for a packaged
industrial unit (Reference 3-21).
Staged air injection for multiburner field erected watertube
boilers might be the next best control system after the LEA technique.
3-23
-------
Overfire air Injection through NOX ports is a demonstrated technology
and fully capable of achieving 20 percent NO reductions. Low NO
X A
burners for multiple burner industrial size boilers could be undesirable
because of possible flame interaction between burners and potential loss
in NO reduction effectiveness.
A
In general, LEA is the best candidate NOV control system capable
A
of achieving 129 ng/J emissions for watertube boilers burning residual oil
with a nitrogen content less than 0.5 percent. Of course, higher nitrogen
content oils increase baseline emissions, necessitating larger emissions
reductions to achieve the moderate control level.
3.3.2.2 Intermediate Control Level
The intermediate control level of 108 ng/J (0.25 lb/106 Btu)
necessitates reductions greater than 30 percent. Technologies potentially
capable of achieving these reductions include low NO burners and staged
/\
combustion. As in the case for moderate control level, LNB is probably
preferred for packaged boilers while overfire air (one form of staged
combustion) is preferred for multiburner units. Several low NO burner
A
designs are still at the R&D stage; however, full demonstrations and
commercialization are expected in the near future. In fact, one
manufacturer (TRW) is currently offering an LNB system, with field
demonstrations underway or imminent. Overfire air is currently being
implemented on utility size units as a staged combustion technique. Since
overfire air (OFA) for packaged single burner units has been used only
experimentally, its feasibility is questionable.
In general, then, the best candidate NOY emission control systems
A
for watertube residual oil-fired boilers are low NOV burners for
A
packaged single burner units and OFA for multiburner boilers. Adverse
process and environmental impacts are expected to be minimal; however,
these suppositions warrant further verification.
3.3.2.3 Stringent Control Level
NO red ctions as high as 50 percent have been reported for low
A
NOX burners and staged combustion control systems (References 3-3, 3-4,
3-8, 3-9, 3-23, and 3-24). The stringent control levels of 86 ng/J (0.2
lb/106 Btu) represents a required NOX reduction of 46 percent.
Therefore, maximum reduction efficiencies must be obtained from these
3-24
-------
control techniques if they are to achieve the stringent control level when
operating singly. It is difficult to predict whether low NOX burners
like the Kawasaki, EER, or TRW units can achieve 50 percent reduction for
all watertube boilers. With little information available on these and
other developing burners, such assurance does not exist at the present
time. However, LNBs were still chosen as the best stringent control
system based on their potential for cost-effective control with little
expected adverse impacts.
For staged combustion to achieve 46 percent NO reduction, it
would mean burner operation with 70 to 90 percent stoichiometry. However,
prolonged tests with areas of the boilers in severe reducing atmospheres
caused by 70 percent burner stoichiometries have not been conducted. But
based on utility boiler experience, burner stoichiometries less than 90
percent may not be acceptable because of increased corrosion and tube
wastage. Therefore, staged combustion as a single technique control
system would probably not be feasible considering operational problems.
The only other alternative to low NOX burners for stringent
control would be ammonia injection. Although the technique has seen
limited commercial operation in Japan, this control system represents a
several fold more costly alternative for NO reduction than the other
rt
two previously described systems. In addition, ammonia emissions will
inevitably create some operational problems for high sulfur oil-fired
boilers. These problems would lead to increased boiler maintenance,
increasing operating cost over and above expected control costs.
Furthermore potential emissions of NH^ and byproducts cause
environmental concern.
3.3.3 Effects of Fuel Nitrogen
It should be noted that the above discussed controlled emission
levels for residual oil firing may be difficult to achieve for boilers
firing high nitrogen content fuel (e.g., >0.3 weight percent nitrogen).
Indeed, Figure 3-1 indicates a possible trend of increasing total NO
/\
emissions with fuel nitrogen content, unlike the behavior exhibited by
coal-fired boilers. A possible explanation may be the following: (1) the
fractional conversion of fuel nitrogen to fuel NO increases with
A
decreasing fuel nitrogen content, and (2) residual oil generally has much
3-25
-------
lower fuel nitrogen content than does coal (Reference 3-4). For high
nitrogen content residual oil, a possible moderate controlled (low excess
air operation) N0¥ level is 200 ng/J (0.47 lb/106 Btu). Note in
A
Figure 3-1 that combustion air preheat appears to have no effect on NO
A
emissions from residual oil-fired boilers, as expected.
3.4 CANDIDATE BEST CONTROL SYSTEMS FOR DISTILLATE OIL-FIRED INDUSTRIAL
BOILERS
NOX emissions from distillate oil combustion are primarily from
thermal NO formation. Distillate oils generally contain less than
/\
0.05 percent of fuel bound nitrogen. The emissions data used here are
primarily from an EPA sponsored study in which fuel nitrogen content of
the oil varied from 0.013 to 0.045 percent (Reference 3-4).
Combustion modifications which are primarily effective in reducing
thermal NO formation are:
A
• Flue gas recirculation (FGR)
• Reduced air preheat (RAP)
a Load reduction with reduced oxygen
• Low NOV burners
rt
t Staged combustion
The relatively low uncontrolled baseline NO emissions of
A
distillate oil-fired industrial boilers are reflected in the suggested
NO control levels of 86, 65, and 43 ng/J for moderate, intermediate,
^
and stringent control, respectively.
As will be observed in the following subsections, these control
levels can in most cases be met with commercially available techniques.
Table 3-10 lists the best candidates for N0x emission control for each
of the three control levels. However, it is interesting to note that
watertube boilers with preheated combustion air tend to have significantly
higher NO emissions than those without preheated air. Furthermore,
A
this behavior was irrespective of unit capacity (Reference 3-3).
Firetube boilers usually have lower combustion intensities than
watertube units; consequently, the formation of thermal NOX would be
expected to be lower (Reference 3-3). However, this was not the case for
the boilers tested, though the differences measured were not large.
3-26
-------
ffi
0
£
^
7»
C
«o
"55
1
Ul
X
0
•o
.2
1
c
o
0
c
D
350
(0.82)
300
(0.70)
250
(0.58)
200
(0.47)
150
(0.35)
100
(0.23)
50
(0.12)
n
D
D
D
E ^ on
/\ i i
FP!
|
^D ^ ^J A Firetube Boiler
Q Watertube Boiler
OS P Indicates Boiler Equipped
With Air Preheater
i i i i i i i
0.1 0.2 0.3 0.4 0.5 0.6 0.7
Nitrogen Content in Oil (Percent by Weight)
0.8
Figure 3-1. Effect of fuel nitrogen content on NOX emissions
from residual oil-fired industrial boilers.
3-27
-------
TABLE 3-10. BEST CONTROL SYSTEMS FOR DISTILLATE OIL-FIRED
INDUSTRIAL BOILERS*
Boiler Equipment Type
Firetube
Hater tube not equipped
with air preheater
Water tube equipped with
air preheater
Baseline
NOX Emissions
ng/J (1b/10& Btu)
75 (0.175)
55 (0.128)
90 (0.209)
Level of Control
Moderate
86 ng/J (0.2 lb/10& Btu)
No control necessary
No control necessary
Low excess air
Intermediate
65 ng/J (0.15 Ib/lO^ Btu)
Low excess air
No control necessary
1. Reduced air preheat
2. Flue gas recirculation
3. Low NOX burners**
4. Staged combustion*
Stringent
43 ng/J (0.1 Ib/lO^ Btu)
1. Flue gas recirculation
2. Low NOX burners**
1. Flue gas recirculation
2. Low NOX burners** ,
3. Staged combustion air*
1. Reduced air preheat
+ flue gas recirculation
2. Reduced air preheat
+ Low NOX burners**
u>
I
CO
aLow excess air operation is recommended practice whenever controls are required
Commercially offered but not demonstrated for this boiler/fuel category.
**Commerc1ally offered but not demonstrated.
T-1761
-------
The following subsections discuss the criteria for relating the
candidates for best NO control systems and the priority in which they
/\
have been listed in Table 3-10.
3.4.1 Firetube Boilers
Emissions from six firetube boilers burning distillate oil averaged
approximately 75 ng/J (Reference 3-3). However, only two of these boilers
were tested with combustion modifications. In addition, the combustion
modifications used were limited to low excess air and load reduction. The
effectiveness of other combustion modification control systems selected
for firetube boilers is based on results obtained on watertube boilers.
The effectiveness of the controls does not vary significantly between
these two equipment types.
With such a low average baseline NO level (75 ng/J), firetube
A
boilers should not need any controls to meet the moderate control level
(86 ng/J) for distillate oil firing.
3.4.1.1 Intermediate Control Level
Low excess air combustion on two firetube boilers reduced NO
A
emissions 18 percent on the average (Reference 3-3). Excess oxygen was
reduced in both cases from the baseline level of approximately 5.7 percent
to 3.2 percent. Operation of the boiler burning distillate oil with a
3 percent excess oxygen level allows complete fuel-air mixing which in
turn keeps combustible emissions at a minimum. This expected 18 percent
NO reduction should be sufficient for the firetube boilers to meet the
A
65 ng/J intermediate control emission level. Operation of distillate oil
burners below 3 percent excess oxygen is often feasible especially with
today's designed LEA burners (Reference 3-21). The increased boiler
efficiency and subsequent fuel saving due to LEA operation would also
compensate for the cost of the system. Expenditures caused by LEA
operation include the installation and operation of control equipment,
including CO and 0~ monitors.
Thus, LEA is the best candidate control for NO reduction for
/v
firetube boilers required to meet the intermediate NO emission control
/\
level of 65 ng/J. Other, more elaborate and costly techniques are not
necessary.
3-29
-------
3.4.1.2 Stringent Control Level
The 40 percent NOX reduction from baseline emissions required by
the stringent control level eliminates the use of LEA, although LEA is
still desirable because of increased boiler efficiency. The best control
system for this NOX reduction performance is flue gas recirculation.
Flue gas recirculation is a very effective control system with reported
NOX reductions of up to 73 percent for watertube boilers (References 3-3
and 3-4, and 3-9). Potential operational problems such as flame
instability should be eliminated with proper engineering and testing.
Environmental impacts such as possible increased organic emissions are
expected to be minimal, although further investigation is definitely
desirable.
Flue gas recirculation was selected over low NO burners
A.
primarily because of the commercial availability of FGR. However, LNB
designs capable of 40 percent NOX reduction, once commercially available
and demonstrated, will be much more cost effective. Reductions in NO
emissions for low N0x burners have been reported in the 20 to 50 percent
range.
Additional NO control candidates would be ammonia injection and
/\
staged combustion. Although both of these techniques are feasible, they
may prove to be inapplicable to firetube boilers because of equipment
limitations. In addition, the cost of ammonia injection might prove to be
more than the cost of the boiler itself.
In summary, flue gas recirculation is the preferred stringent
control technique with low NO burners as the second option for
A
distillate oil-fired firetube boilers.
3.4.2 Watertube Boilers Without Air Preheaters
Watertube boilers firing distillate oil and not equipped with air
preheaters are usually smaller than 15 MW (50 x 10 Btu) heat input,
although a 58 MW unit has been tested (References 3-3 and 3-4). NO
x
emissions from these equipment types averaged approximately 55 ng/J
(References 3-3 and 3-4). This baseline emission level is lower than both
the moderate and intermediate control levels of 86 and 65 ng/J,
respectively, so no controls are needed. However, to meet stringent
levels some form of NO control will be needed.
3-30
-------
NOX reduction to 43 ng/J Zc^ be met by reducing the baseline
level of 55 ng/J by 22 percent. Th.s reduction should be easily
achievable with flue gas recirculation (up to 70 percent NO reduction)
A
or low N0x burners (20 to 50 percent). Low excess air combustion
reduced NO emissions from watertube boilers only about 4 to 12 percent
A
when excess oxygen was lowered from approximately 5.5 to 3.5 percent.
Although burner operation with excess oxygen lower than 3.5 percent is
possible (Reference 3-21) it is unclear whether higher NO reductions
A
could be achieved.
Flue gas recirculation was selected as the best candidate for
stringent control based on its commercial availability and recorded
performance. Recirculation rates of less than 30 percent are deemed
sufficient to achieve this control level. At this rate, no major
operational impacts are expected if the burner is modified to allow for
the increased excess flowrate.
Low NO burners will probably be more cost effective c :e they
J\
are commercially available and demonstrated. They may become the
candidate best system of control for reducing NO emissions to 43 ng/J.
A
Low NO burners are especially attractive for single burner units such
A
as packaged watertubes because the incremental cost for one LNB is
considered minimal. However, the prototype low NOV burners under
A *„
current development may be of too large capacity for the smaller package
units.
Staged combustion is another alternative control system. Staged
combustion may prove to be more attractive than LNB for multiburner
units. However, watertube boilers not equipped with air preheaters are
generally of the package type with only one burner. For these units, air
injection by means of ports down stream from the burner can be used to
achieve staged combustion (see Section 2). Control of NO with this
A
type of staged combustion is considered still at the experimental stage
and more costly than control with LNB.
In summary, flue gas recirculation is considered the preferred
method for stringent control of distillate oil-fired watertubes not
equipped with air preheaters.
3-31
-------
3.4.3 Uatertube Boilers Equipped with Preheaters
Watertube boilers with preheated combustion air are generally
larger than 15 MW (50 x 106 Btu/hr) heat input (Reference 3-3).
Baseline NO emissions from a limited number of these units averaged
about 90 ng/J (Reference 3-4). Currently available combustion
modification control systems are capable of achieving the moderate,
intermediate, and stringent control levels for distillate oil firing.
3.4.3.1 Moderate Control Level
Low excess air firing should be more than adequate to reduce the
baseline NO emissions of 90 ng/J to the moderate control level of 86
A
ng/J with increased boiler efficiency and minimal adverse impacts.
3.4.3.2 Intermediate Control
Combustion air temperature were not be reduced during the test
program on the watertube boilers equipped with air preheaters. Therefore
the effect of reduced air preheat (RAP) on these units cannot be clearly
defined. However, based on results with natural gas, another clean fuel,
it is speculated that RAP can reduce NO emissions by the 30 percent
A
required by the intermediate control level of 65 ng/J. The loss in
efficiency caused by the increased flue gas temperature can be averted for
new units by installing an economizer instead of an air preheater.
Economizers offer some operational advantages over air preheaters as well
as reduced NO emissions (Reference 3-21). The primary advantage is the
A
lower capital cost, sometimes nearly one-half of that of an air preheater
(Reference 3-25).
Therefore, RAP or arv.bient temperature combustion air for new
watertube boilers designed to fire distillate oil was selected as the best
system for intermediate control. Alternative controls include flue gas
recirculation, low NO burners, and staged combustion.
A
Flue gas recirculation is a very effective and available technique,
but is also very costly, therefore it should be considered as an
alternative to RAP only if replacing the air preheater with an economizer
in a new unit is not feasible.
3-32
-------
The remaining alternatives are low NO burners and staged
J^
combustion. For single burner packaged units, LNB is probably considered
more desirable. However, LNB performance and operation have not been
thoroughly demonstrated. Similarly, overfire air injection for
multiburner units is a very attractive control system, probably more so
than LNB. Staged combustion can reduce NO from watertube boilers
}\
firing distillate oil by 30 to 40 percent on the average (References 3-4
and 3-9).
In general, watertube boilers with ambient combustion air
temperature are capable of meeting the intermediate emission level of 65
ng/J with minimal adverse impacts. Therefore it is recommended that new
units be designed with an economizer instead of an air preheater.
Alternative control candidates include FGR or LNB for packaged single
burner boilers and OFA for multiburner units. Staged combustion for
packaged watertube boilers is also a candidate, although, this control
system is still at the experimental stage.
3.4.3.3 Stringent Control Level
The stringent control level of 43 ng/J can be obtained by combining
reduced air preheat (RAP) with another combustion modification such as FGR
or LNB. The RAP plus FGR control system was selected as the best
candidate again based on availability, even though its cost is generally
expected to be higher than for RAP plus LNB control systems.
Alternative control systems include the use of ammonia injection
combined with one other combustion modification. Reduced air preheat is
preferred because it is expected to have the least operational and cost
impact considering the flue gas heat recovery with an economizer. For
boilers which must be equipped with air preheaters, FGR or LNB may still
be adequate. Otherwise, costly NH, injection may also be required.
3.5 CANDIDATE BEST CONTROL SYSTEMS FOR NATURAL GAS-FIRED INDUSTRIAL
BOILERS
Formation of NO from the combustion of natural gas is entirely
/\
from thermal fixation of nitrogen in the combustion air. Combustion
parameters primarily affecting thermal NO formation are peak flame
/\
temperature, oxygen concentration and exposure time at peak flame
3-33
-------
temperatures. The following are applicable combustion modification
controls which effectively reduce thermal NO :
/\
• Flue gas recirculation
• Reduced air preheat
t Staged combustion and low excess air
• Load reduction with reduced oxygen
• Low NO burners
A
Table 3-11 lists the candidate best systems of combustion
modification for natural gas-fired industrial boilers. Natural gas-fired
boilers have been categorized into three main types: firetubes,
watertubes not equipped with air preheaters, and watertubes equipped with
air preheaters. This characterization was made because the baseline NO
emissions of each of these types were significantly different, as well as
because of alternate available control strategies.
Firetube boilers are the lowest emitters with approximately 40 ng/j
emission level. These boilers are usually not equipped with air
preheaters because of their small size, making heat recovery too costly to
implement. Watertube boilers without preheated combustion air exhibited
average NO emissions of 45 ng/J, while those units with air preheaters
/\
emitted significantly higher NO , 110 ng/J.
A
The following discussion summarizes the reasons for the selection
and the order of the combustion modification systems for each of these
major natural gas-fired industrial boilers, as shown in Table 3-11.
3.5.1 Firetube Boilers
The low baseline NOX emissions (40 ng/J) from firetube boilers
require no controls for meeting the moderate, intermediate, or stringent
levels for gas-fired boilers.
It is not considered cost-effective to require further control
beyond the stringent level of 43 ng/J because of the firetube boiler's
small size with very low baseline NO emissions level.
A
3.5.2 Uatertube Boilers Without an Air Preheater
Watertube boilers not equipped with air preheaters usually have
heat input capacities lower than 15 MW (50 x 10 Btu/hr), although some
larger units do exist (Reference 3-4). However, increasing concern about
energy saving and fuel economy has resulted in numerous industrial boiler
3-34
-------
TABLE 3-11. BEST CONTROL SYSTEMS FOR NATURAL GAS-FIRED
INDUSTRIAL BOILERS*
Boiler Equipment Type
Firetube
Water tube not equipped
with air heater
Watertube equipped with
air heater
Baseline
NOX Emissions
ng/J (lb/106 Btu)
40 (0.093)
45 (0.105)
\
110 (0.256)
Level of Control
Moderate
86 ng/J (0.2 lb/K)6 Btu)
No control necessary
No control necessary
1. RAPb
2. FOR
3. SCA*
4. LNB**
Intermediate
65 ng/J (0.15 lb/106 Btu)
No control necessary
No control necessary
1. RAP + FGRb
2. RAP + LNB**
3. RAP + SCA*
Stringent
43 ng/J (0.1 lb/106 Btu)
No control necessary
Low excess air
1. RAP + FGRb
2. RAP + LNB**
3. RAP + NH3**
injection
CO
en
aLow excess air operation is recommended practice whenever controls are required.
bRAP » Reduced Air Preheat
FGR * Flue Gas Redrculation
SCA * Staged Combustion Air
LNB - Low NOX Burners
T-1762
*Commer daily offered but not demonstrated for this boiler/fuel category.
**Commerc1ally offered but not demonstrated.
-------
manufacturers offering flue gas heat recovery devices such as air
preheaters or economizers (Reference 3-21). This section addresses only
those boilers not equipped with air preheaters.
Baseline N0x emissions from these boiler types were found to be
very low (45 ng/J), requiring no combustion modification to meet the
moderate or intermediate NOX control levels of 86 and 65 ng/J,
respectively. With such a low baseline NOX level, low excess air firing
should certainly be adequate for meeting the stringent control level of
43 ng/J.
3.5.3 Watertube Boilers with Air Preheaters
Baseline NOX emissions from gas-fired watertube boilers equipped
with combustion air preheaters are significantly higher than similar
boilers using ambient temperature combustion air (110 versus 45 ng/J).
Section 2 has shown that if the air preheater is bypassed, NO
3\
reductions of up to 55 percent can be obtained, thus reducing the emission
level from approximately 110 to 50 ng/J, nearly the level of units without
air preheaters.
Therefore, substantial control levels can be achieved by bypassing
air preheaters on existing units and building new boilers without air
preheaters. However, in both cases the flue gas heat loss must be
recovered by some other means; otherwise the control becomes very
unattractive due to large boiler efficiency losses (one percent for every
20K or 42°F increase in stack temperature). One alternate flue gas heat
recovery device is the economizer. As is the case for distillate
oil-fired boilers, the economizer offers smaller capital investment and
lower fan power requirements than an air preheater.
The following subsections describe the criteria used in selecting
the order of control systems shown in Table 3-11 for gas-fired boilers
with combustion air preheaters.
3.5.3.1 Moderate Control Level
As disci, ssed above, replacement of air preheaters with economizers
helps to reduce NOX levels, and is also cost effective. Therefore, for
new gas-fired watertube boilers the best system of control to achieve an
emission level of 86 ng/J (or lower) is to install economizers in place of
air preheaters. Retrofit changes are not considered viable due to boiler
design differences as well as high costs.
3-36
-------
If an air preheater is installed, three other options can be
considered. These are flue gas recirculation, staged combustion, and low
NO burners. Flue gas recirculation is a very effective and available
/\
technique, but also very costly, and should be considered as an
alternative to RAP only if replacing the air preheater with an economizer
in a new unit is not feasible. Staged combustion together with low excess
air was selected as another option because it is a demonstrated technology
and is cormiercially available for utility size units. However, the choice
between LNB or staged combustion highly depends on the boiler
configuration. Single burner units might be more amenable to LNB than
staged combustion because of the lower expected cost (see Section 4).
However, staged combustion technology is presently available while LNB
technology for natural gas combustion still needs demonstration in the
U.S. (References 3-26, 3-27).
In summary, reduced air preheat through replacement of the air
preheater with an economizer is the preferred, cost-effective method for
moderate control of gas-fired watertube boilers. For a new unit, there
should be no adverse process, cost, or environmental impact.
3.5.3.2 Intermediate Control Level
When combined with no air preheat, flue gas recirculation, low
NO burners, and staged combustion are candidate control systems to
n
achieve the intermediate control level of 65 ng/J. Flue gas recirculation
(F6R) was again selected as the best candidate control as for distillate
oil-firing because of its significant effectiveness and its commercial
availability. For single burner units, however, low NO burners may
A
prove to be much more cost effective and would be selected as the best
control even though demonstrated gas-fired low NO burners are not yet
A
commercially available. For multiburner units, staged combustion combined
with LEA might be preferred over low NO burners primarily because of
A
its known effectiveness (25 to 45 percent NO reduction) and its
X
nearer-term availability.
3.5.3.3 Stringent Control Level
NOX emissions from gas-fired industrial boilers can be reduced to
43 ng/J only if the combustion air is not preheated. In most cases the
combination of no air preheat and flue gas recirculation can reduce the
NO emissions to this level because of the high effectiveness of flue
^
3-37
-------
gas recirculation with natural gas fuel (up to 75 percent). This control
system of RAP and flue gas recirculation is the preferred one because of
its current availability and effectiveness.
Low NOV burners are not yet demonstrated. In addition, their
A
performance (up to 50 percent NO reduction) would not be sufficient to
A
lower NO emissions to 43 ng/J. However, when low NO burners are
A X
combined with reduced air preheat, the stringent control level may be
achievable. There are no reported tests to verify this.
A third alternative is ammonia injection combined with reduced air
preheat. But this system is not thoroughly demonstrated and furthermore
is significantly more costly than the flue gas recirculation/reduced air
preheat system. In addition, there are environmental concerns with
possible ammonia and byproduct emissions. Furthermore implementation and
operational problems need to be resolved.
3.6 SUMMARY
Alternative emission control systems which achieve moderate,
intermediate, and stringent levels of NO control have been selected.
A
These control levels were based on uncontrolled baseline emission levels
and the capabilities of combustion modification controls. Tables 3-7
through 3-11 summarize the candidates for best control systems and
emission levels achievable for each of the major industrial boiler/fuel
categories. Tables 3-2 through 3-5 highlight the main performance
characteristics of candidate control systems. Selection criteria for
these candidate best control systems were based on the effectiveness,
commercial availability or R&D status, operational impact, and reliability
of each system. Energy, environmental, and cost impacts were also
considered.
Results to date indicate that low excess air (LEA) or overfire air
(OFA) form the best system for moderate (301 ng/J) and intermediate
(258 ng/J) NO control for pulverized coal-fired industrial boilers.
However, those boilers with high baseline NO emissions may need to use
A
a combination of OFA and LEA to achieve the intermediate control level.
Staged combustion combined with low excess air can achieve the stringent
control level of 215 ng/J. Alternative controls include low NO burners
A
(LNB) and ammonia injection; both techniques are under development.
3-38
-------
Spreader stokers are the only major stoker boiler types with
average uncontrolled NO emissions above 258 ng/J. Low excess air and
A
overfire air constitute the best candidate control system capable of
reductions to 215 ng/J. Any NO reduction beyond this level can only be
A
achieved with NHU injection (an unproven technique), possibly down to
129 ng/J. The other major stoker types, chain grate and underfeed, have
average uncontrolled NO emissions below 172 ng/J. Control of these
}\
units to 129 ng/J is possible with LEA.
The candidate best control systems for residual oil-fired
industrial boilers are low excess air, low NO burners, and staged
A
combustion. The low NO burners under development are projected to
A
reduce NO emissions to the stringent level (86 ng/J). An alternative
A
control is NHL injection (an unproven technique). Candidate best
control systems for distillate oil- or gas-fired boilers are reduced air
preheat, flue gas recirculation, and low NO burners, in that order,
A
lowering NO to 65 ng/J. Reduced air preheat combined wi'' flue gas
A
recirculation or with low NOY burners may potentially reduce NO,
emissions to 43 ng/J.
3-39
-------
REFERENCES FOR SECTION 3
3-1 Sedman, C, EPA/OAQPS, and R. Stern, EPA/IERL-RTP, Comments to
Industrial Boiler Contractors at RTP Program Review, August 30,
1978, as transcribed by C. Hester, Acurex Corp., "Minutes of
August 30 Industrial Boiler Status Assessment Meeting,"
October 2, 1978.
3-2 "Compilation of Air Pollution Emission Factors," U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards,
Publication AP-42, NTIS-PB 275-525, April 1973 and Supplements and
No. 3, NTIS-PB 235-736, July 1974, and No. 6, NTIS-PB 254 274,
April 1976.
3-3 Cato, 6. A., et iL., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers - Phase I," EPA-650/2-74-078a, NTIS-PB 238 920/AS,
October, 1974.
3-4 Cato, G. A., et al^, "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial Boilers
- Phase II," EPA-600/2-76-086a, NTIS PB-253 500/AS, April 1976.
3-5 Maloney, K. L., et iL., "Low-Sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers," EPA-600/7-78-153a, NTIS-PB
287-937/AS, July 1978.
3-6 Goldberg, P. M., and E. B. Higginbotham, "Field Testing of an
Industrial Stoker Coal-Fired Boiler ~ Effects of Combustion
Modification NOX Control on Emissions — Site A," Acurex Report
TR-79-25/EE, EPA Contract No. 68-02-2160, Acurex Corporation,
Mountain View, California, August 1979.
3-7 Gabrielson, J.E., "Field Tests of Industrial Stoker Coal-Fired
Boilers for Emissions Control and Efficiency Improvement-Site A,"
EPA-600/7-78-136a, NTIS-PB 285-172/AS, July 1978.
3-8 Heap, M. P., et al., "Reduction of Nitrogen Oxide Emissions from
Field Operatifvg Package Boilers, Phase III," EPA-600/2-77-025,
NTIS-PB 269 277, January 1977.
3-9 Carter, W. A., et al., "Emissions Reduction on Two Industrial
Boilers with Major~C~o>nbustion Modifications," EPA 600/7-78-099a,
NTIS-n 283-109, June 1978.
3-10 Cichanowicz, J. E., et aj^, "Pollutant Control Techniques for
Package Boilers. Phase I Hardware Modification and Alternate
Fuels," EPA Draft Report under EPA Contract No. 68-02-1498,
November, 1976.
3-40
-------
3-11 Pershing, D. W., et ^1^, "Influence of Design Variables on the
Production of Thermal and Fuel NO from Residual Oil and Coal
Combustion," AIChE Symposium Series, No. 148, Vol. 71, pp. 12-29,
1975.
3-12 "Task 2 Summary Report — Preliminary Summary of Industrial Boiler
Population," prepared by PEDCo in support of OAQPS work on NSPS for-
industrial boilers, June 29, 1978. Also Section 3 of Task 2
Report, "The Industrial Steam Generator Industry," August 1978.
3-13 Lim, K. J., et al., "Environmental Assessment of Utility Boiler
Combustion MoiJifTcation NOX Controls," Acurex Draft Report
TR-78-105 under EPA Contract No. 68-02-2160, April, 1978.
3-14 Milligan, R. J., £t ^1_._, "Update of NOX Emission Factors for
AP-42," Acurex Draft Report TR-78-306 under EPA Contract No.
68-02-2611, Task 34, October 1978.
3-15 Crawford, A. R., et al^, "Field testing: Application of Combustion
Modifications to Control NOX Emissions for Utility Boilers," EPA
650/2-74-066, NTIS-PB 237 344/AS, June 1974.
3-16 Vatsky, J., "Attaining Low NOX Emissions by Combining Low
Emission Burners and Off-Stoichiometric Firing," Paper No. 51d,
70th Annual AIChE Meeting, New York, November 1977.
3-17 Compobenedetto, E. J., "The Dual Register Pulverized Coal Burner -
Field Test Results," presented to Engineering Foundation Conference
on Clean Combustion of Coal, New Hampshire, August 1977.
3-18 Fletcher, R. J., Peabody Engineering Corp., Telecommunication with
R. S. Merrill, Acurex Corp., July 21, 1978.
3-19 Bartok, W., "Non-Catalytic Reduction of NOX with NH^,"
Proceedings of the Second Stationary Source Combustion Symposium
Volume II, EPA-600/7-77-073b, NTIS-PB 271 756/AS, July 1977.
3-20 Muzio, L. J., et al., "Package Boiler Flame Modification for
Reducing Nitric OxT3e Emissions — Phase II of III,"
EPA-R2-73-292-B, NTIS-PB 236 752, June 1974.
3-21 Schwieger, B., "Industrial Boilers — What's Happening Today,"
Power Magazine, Vol. 121, No. 2, pp. S.1-S.24, February 1977, and
Vol. 122, No. 2 pp. S.1-S.24, February 1978.
3-22 Morton, B., F. Keeler Co., Williamsport, PA, Telecommunication with
H. I Lips, Acurex Corp., August 8, 1978.
3-23 Ando, J., et ^l^, "NOX Abatement for Stationary Sources in
Japan," EPA-600/7-77-103b, NTIS-PB 276 948/AS, September 1977.
3-24 Ando, J., et al., "NOX Abatement for Stationary Sources in
Japan," EPA-600/2-76-013b, NTIS PB 250 586/AS, January 1976.
3-41
-------
3-25 Lindsay, J., Zurn Industries, Telecommunication with C. Castaldini,
Acurex Corp., August 17, 1978.
3-26 Koppang, R. R., TRW, Telecomunication with R. S. Merrill, Acurex
Corp., July 21, 1978.
3-27 Eaton, S., Coen Co., Telecomunication with R. S. Merrill, Acurex
Corp., August 9, 1978.
3-28 "Recommendation for Standard Boilers," prepared by PEDCo in support
of OAQPS work on NSPS for industrial boilers, August 30, 1978.
3-29 Broz, L. D., Acurex Corp., C. B. Sedman, EPA/OAQPS, and J. D.
Mobley, EPA/IERL-RTP, letter to Industrial Boiler Contractors,
September 26, 1978.
3-30 Fletcher, R. J., Peabody Engineering Corp, Telecommunication with
R. S. Merrill, Acurex Corp., July 21, 1978
3-31 Mason, H. 8., et jil^, "Preliminary Environmental Assessment of
Combustion ModTFication Techniques: Volume II. Technical
Results," EPA-600/7-77-119b, NTIS-PB 276 681/AS, October 1977.
3-32 Mobley, J. D., EPA IERL-RTP, N.C., Letter to Industrial Boiler
Contractors, April 27, 1979.
3-33 Habelt, W. W., Howel, B. M., "Control of NOX Formation in
Tangentially Coal-Fired Steam Generators," presented at Electric
Power Research Institute NOX Control Technology Seminar,
San Francisco, California, February, 1976.
3-34 Marshall, J. J., and A. P. Selker, "The Role of Tangential Firing
and Fuel Properties in Attaining Low NOX Operation for Coal-Fired
Steam Generation", presented at Second Electric Power Research
Institute NOX Control Technology Seminar, Denver, Colorado,
November 1978.
3-35 Lips, H. I., and E. B. Higginbotham, "Field Testing of an
Industrial Stoker Coal-Fired Boiler — Effects of Combustion
Modifcation NOX Control on Emissions — Site B," Acurex Report
TR-79-18/EE, EPA Contract No. 68-02-2160, Acurex Corporation,
Mountain View, California, August 1979.
3-42
-------
SECTION 4
COST IMPACT
The cost impact of combustion modification techniques for
controlling NO emissions from industrial boilers is discussed in this
/\
section. The controls considered are those discussed in Section 3 as
candidates for best NO emissions control system. Selection criteria
A
for the best control system were based on the effectiveness, commercial
availability or R&D status, operational impact, and reliability of each
system. Estimates of the energy, environmental, and cost impacts were
also considered. This section examines the cost impacts in greater detail.
4.1 COST ANALYSIS
In the evaluation of NO controls for industrial boilers, the
A
cost of boiler systems with controls are compared to the costs of
uncontrolled and State Implementation Plan (SIP) controlled systems. (SIP
control levels are summarized in Table 5-1.) Section 4.1.1 reviews the
components that go into control costs, while Section 4.1.2 reviews the
cost basis and assumptions.
4.1.1 Components of Control Costs
Nitrogen oxides control techniques can have two major cost
components. First, the control methods will usually require additional
hardware, increasing the cost of the boiler to the user. Second, the cost
of producing steam will probably be increased due both to the increased
capital charge to be annualized (referred to as annualized capital cost)
and any changes in operating, maintenance, and energy costs (referred to
collectively as annualized operating costs). The price of steam will not
always rise with addition of controls; for example, as will be shown
later, low excess air operation can decrease the cost of steam in some
cases.
The capital and operating costs of NO controls discussed here
A
are engineering estimates based on limited published costs and discussions
4-1
-------
with equipment vendors. The largest component of operating costs are
often due to increased energy consumption. These changes in energy
consumption are discussed in Section 5 and those values are used in
estimating the changes in steam cost due to NO controls.
A
Indeed, it has been found for NO controls for utility boilers
A
that losses in boiler efficiency (increased fuel consumption) can add up
to over half the cost-to-control (Reference 4-1). For example, a 0.25
percent loss in boiler efficiency with staged combustion can translate to
one third of the control cost. Unfortunately, these changes in boiler
efficiency with NO controls have not been precisely established for
^
utility or industrial boilers. Therefore, although equipment and
operating costs are discussed here in as great detail as available data
permit, the large unknown in energy costs should be noted when discussing
control costs. In other works, a very small variation in boiler
efficiency loss can lead to a very large fluctuation in control costs. In
many cases, then, a detailed discussion of equipment cost estimates, etc.
can become moot.
Since NOX control techniques are not widely used on industrial
boilers, very little is known about long term operation. Thus one area of
concern is how NOX controls affect day-to-day operation. Industrial
boilers are operated with a minimal amount of operator attention and run
under changing loads. Therefore the combustion modifications that are
made for NO control may also require that the boiler control system
A
(e.g., air and fuel flow controls) be modified. The cost of an additional
boiler control system has been estimated- and included in the presented
prices, but without long term tests, a true modification cost can not be
given. Also, since the actual costs depend on site and use of boiler,
only estimated prices for a typical boiler can be given.
The costs of the following control techniques are discussed in this
section: low excess air (LEA), staged combustion air (SCA) — usually
overfire air (OFA) or sidefire air (SFA), flue gas recirculation (F6R),
low NO burners (LNB), reduced air preheat (RAP), and ammonia
A
injection. The following paragraphs describe the required and/or
recommended equipment needed when implementing these combustion
modification techniques. The costs for the required and/or recommended
equipment are included in the prices that will be listed.
4-2
-------
Low excess air operation may require an oxygen trim system
consisting of a flue gas 02 analyzer along with the control equipment
for regulating air flow. This is in addition to the normal air flow
control system. Wind box modifications may also be required for
multi-burner boilers.
Staged combustion requires air ports and possible windbox
modification. Several air ports may be required to allow firing of
different types of fuels. Larger forced draft fan power also may be
needed, and an oxygen trim system should probably be installed.
Flue gas recirculation requires a larger forced draft fan and the
associated duct work to recycle a portion of the flue gas. Windbox and
burners may need to be modified to accommodate the additional gas flow. A
control system to regulate the combustion oxygen and the amount of the
flue gas recirculated would probably also be needed.
Low NO burner operation may require a larger forced draft fan if
/\
the burners have an increased pressure drop. Windbox modifications may
also be required. An oxygen trim system is recommended to allow operation
at the lowest possible excess air.
Ammonia injection requires injector ports, the injection system,
and the ammonia handling and storage system. Ammonia injection may also
require several different injection port locations and a control device to
switch ports as load changes. An air compressor to supply a carrier gas
for the ammonia would also be needed. Controls to regulate the flow of
NHg will also be required. Since the process is patented by Exxon, they
will require a licensing fee. This fee was not included in the present
analysis as that cost is a negotiable item and the information is not
available.
4.1.2 Cost Basis
Table 4-1 summarizes the simplified cost basis used in evaluating
NO controls. Capital costs represent the initial investment for the
J\
control: equipment and installation costs. On an annualized basis, the
initial investment can be levelized into capital recovery charges and
combined with taxes and insurance to comprise annualized capital charges.
Annualized capital charges plus annual operating costs give the total cost
to control per year.
4-3
-------
TABLE 4-1.
COST BASIS FOR EVALUATING NOY CONTROLS
A
Capital Costs (Initial Investment)
Equipment Costs
Installation Costs, Indirect
Engineering
Construction and Field Expense
Construction Fees
Start-up
Performance Test
Installation Costs, Direct
Contingencies
Annualized Costs
Capital Charges (Fixed Costs)
Capital Recovery
Taxes
Insurance
Operating Costs
Utilities
Raw Materials
Operating Labor
Maintenance
Fuel Costs
Since experience with industrial boiler NOX controls is very
limited, a detailed breakdown of the costs into the various capital and
operational cost components as illustrated in Table 4-1 was not always
possible. The analysis relied heavily on estimates from equipment vendors
and published data from utility boiler experience. Where information was
lacking, engineering estimation rules as outlined in Reference 4-2 were
used. Costs were collected from various sources and extrapolated to the
boiler size under consideration. Using engineering judgement, a typical
cost was estimated from these extrapolated values.
Following the guidelines of the EPA memo which described the
suggested cost analysis approach used here (Reference 4-21), the
4-4
-------
reliability of the cost estimates presented here is estimated to be no
better than plus or minus 30 percent except for ammonia injection and low
NO burners. Since these last two techniques represent untried
X
technologies, the reliability of their costs is estimated to be plus
100 percent.
As discussed in Section 2, the limited control performance data
does not allow one to determine the effect of different coal types upon
NO emissions. Hence the control cost estimates presented here are not
A
broken down by coal type.
In calculating the costs of control systems, several assumptions
were made. The annualized capital charges, were taken to be 20 percent of
the total installed cost of the combustion modification, and the
annualized operating labor and maintenance costs were taken to be
5 percent of the total installed cost. Twenty percent was the factor used
for annualized capital charges because it is common industrial practice to
use 20 percent when presenting a first estimate of annualized capital
charges. For example, see the EPA Standard Support and Environmental
Impact Statement for Stationary Gas Turbines (Reference 4-3), the cost
estimates for ammonia injection (References 4-4 and 4-5), and the utility
industry price estimates for NO control given in Reference 4-6. This
A
20 percent includes four percent for G&A, taxes, and insurance and a
capital recovery factor of 16 percent. The utility industry also used
5 percent annualized operating labor and maintenance cost for NO
A
combustion modification techniques for utility boilers (Reference 4-6).
Since there is no long term operating experience with combustion
modifications for industrial boilers, it was decided to use five percent
as a first estimate.
An industrial boiler is assumed to be 82 percent efficient without
an air preheater or economizer and 84 percent efficient with one except
for a pulverized coal-fired boiler which is assumed to be 87 percent
efficient (References 4-7 and 4-8). To generate one kilogram of steam
requires 0.00256 GJ (1100 Btu/lb) of heat. The load factors and fuel
costs given by PEDCo (Reference 4-2) were used in the cost analysis used.
PEDCo used load factors of 45 percent for boilers smaller than 7 x 10 kg
steam/hour (15 x 10 Ib steam/hr) and 60 percent for the larger sizes.
The fuel prices used are $2.84/GJ for No. 2 oil, S2.21/GJ for No. 6 oil,
4-5
-------
$1.85/GJ for natural gas, and $1.10/GJ for low sulfur coal. The price of
No. 6 oil is increased by 20 percent to $2.65/GJ to account for the cost
of heating the fuel when firing and keeping the storage tank warm. The
fuel prices, as well as all other costs to be presented, are 1978 prices.
In the following discussion, costs to modify the boiler are given
as a percentage of the boiler's installed cost, while the steam costs
include the entire steam plant. The total steam plant costs more than
that of the boiler alone because it includes additional equipment such as
the smoke stack and water treatment system. The boiler and steam
production costs used are from a report by PEDCo presented to the
EPA-OAQPS (Reference 4-2). Except for adding an 02 trim system and
ammonia injection, retrofit costs were assumed to be twice that of
installing NOX controls on a new unit as was found by one author for a
small industrial boiler (Reference 4-9). However, this may be optimistic
and retrofit control costs may actually be four times that for new
designs. The factor of two assumed here is just for the purposes of a
first estimate in control costs. It should be reiterated that the control
costs presented in this section, as well as achievable NOX control
levels, are based on very limited data.
The cost estimates presented are only for reaching the moderate,
intermediate, and stringent control levels discussed in Section 3. It is
usually possible to achieve lower NO levels by extending the degree of
A
application of the control technique but the control costs were estimated
assuming that the indicated technique is used just to reach the indicated
level of control. In many cases, using even lower excess air can increase
efficiency, lower the required energy, and reduce the steam cost.
The cost data will be presented in tables in which the capital and
annualized incremental costs and cost effectiveness of NOX controls will
be summarized (the limited available details are given in the Appendix).
The costs are incremented from the costs of the basic uncontrolled
systems. In the tables, the annualized incremental costs were calculated
o
by the following formulas (units of mills/10J kg steam).
Total Annual Cost = Annualized Fixed Costs Plus Operating Cost
Annualized Fixed Costs =
(Total Installed Cost of Control)(0.2)(1000)
o
(Hours/yr) (Load Factor) (Boiler Capacity, 10 kg steam/hr)
4-6
-------
Operating Cost = Fuel + Raw Materials + Utilites + Operating Labor + Maintenance
. p , r . (Thermal Efficiency Change)(GJ/10 kg steam)(mills/GJ)
where i-uei LOST; (Boiler efficiency)
Utilities Costs = (Fan Efficiency Loss)(Boi1er Heat Input)(26 mills/kwh)
(0.65) (Boiler Capacity, 103 kg steam/hr)
and Operating Labor and Maintenance Cost =
(Total Installed Cost of Control)(0.05)(1000)
(Hours/yr)(Load Factor)(Boiler Capacity, 103 kg steam/hr)
Overhead charges have already been incorporated into the labor and
maintenance costs. Thermal efficiency and fan power changes are discussed
in Section 5. The cost effectiveness of a NO control technique is
calculated by the following formula:
rn*t Pffprtix/pnp« - (Total Annualized Cost )(Boiler Capacity, Ip3 kg steam/hr)
cost effectiveness - (Heat Input)(Emission Change)
where Emission Change = Baseline NO Level - NO Control Level
Thus cost effectiveness has units of $/kg NO reduced. The baseline and
/\
controlled NO levels, have been discussed in Section 3. Figures 4-1,
/\
4-2, and 4-3, summarize estimated annualized control costs versus NO
emission levels for coal and residual oil-fired boilers and for firetube
boilers firing natural gas or distillate oil. The following sections will
elaborate on these figures.
4.2 CONTROL COSTS FOR COAL-FIRED BOILERS
The costs for pulverized coal units are engineering estimates based
on published data, manufacturer quotes, and utility boiler experience
(References 4-1 and 4-10 through 4-14).
Stoker unit costs are engineering estimates based on published data
and manufacturer's estimates (References 4-10 through 4-15). Tables 4-2,
4-3, 4-4, and 4-5 list the cost estimates for new and retrofitted units.
And Figure 4-1 shows a graph of estimated annualized cost versus NO
level. Recall that the moderate, intermediate, stringent, and SIP control
levels were defined in Section 3.
4-7
-------
[ J Indicates larger uncertainty
0 59 tW Pulverized Coal
X 44 MW Spreader Stoker
O 22 MW Chain Grate Stoker
O 9 MW Underfeed Stoker
60
e
4-> +J
C 3
O CX
<_> c
40
« 20
.£>
CD
n>
SCA
Baseline
1 1 1
1 1
1 1 1
1 1
r
n
I
I
I
I
[NH, Inj.J
50
100 150 200
NOX ng/J Heat Input
Baseline
,[LNB]
LEA
250
300
Figure 4-1. Estimated annualized control cost versus NOX level for coal-
fired boilers (costs are only first estimates).
-------
i
VO
120
5 90
C *-"
O "I
01
M <->
•r- IO
f- o>
a X
3
C -O
60
30
-30
I I
M\\ X SCA
LNB
Bdseline X Baseline
I 1
j I
SO
100 150
NOX ng/J Heat Input
200
[ ] Indicates large
uncertainty
R\ 4.4 MW Fire tube
X 44 MM Watertube
N
t
Figure 4-2. Estimated annualized control cost versus NOX emission
level for residual oil-fired boilers (costs are only
first estimates).
-------
I
I—1
o
01
O
C_5
O
-!->
c
O -M
O 3
Q.
T3 C
(U M
N
••- +J
r— (O
ro OJ
to
•O i—
0) •—
^-> T-
(O E
100
90
80
70
60
50
40
30
20
10
0
FGR
o
Baseline
Natural Gas
istill ate Oil
Baseline
I I I I I I I I 1 I 1 _l I 1 1 I-
10 20 30 40 50 60
NO ng/J Heat Input
70 SO
[ ] Indicates large uncertainty
0 Distillate oil-fired
Nature 1 grs-fired
(T
rC
Figure 4-3. Estimated annualized control cost versus NO emission levels for distillate
oil and natural gas fired 4.4 MW firetube bo'ler (costs are first estimates
only).
-------
TABLE 4-2. ESTIMATED COSTS OF CANDIDATE NO CONTROL TECHNIQUES FOR
NEW COAL-FIRED BOILERS
System
Standard Boilers
Type
Pulverized Coal
Heat Input
MW (106 Btu/hr)
59 (200)
117 (400)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Str 1 ngent
Control
Effectiveness
Percent
~
10
25
25
25
—
10
25
25
25
Estimated Incremental Costs
Capital
Cost
103 $
--
27
47
[47]b
[237]
--
44
78
[78]
[472]
Annual ized Costs
Fixed Costs
mills
103 kg steam
--
13 (6)a
24 (11)
[24 (11)]
[125]
—
12 (5)«
21 (9)
[21 (9)]
[125]
Operating Costs
mills
103 kg steam
—
-13 (-6)
47 (21)
[47 (21)]
[82]
—
-13 (-6)
46 (21)
[46 (21)]
[82]
Total Costs
mills
103 kg steam
—
0(0)
71 (32)
[71 (32)]
[205]
—
-2(-l)
67 (30)
[67 (30)]
[205]
mills
GJ input
~
0 <0>c
24 <25>
[24 <253
[70 < 74}
—
0.6<0.7> c
22<24>
[22 <24>]
[70 <74>]
aNumbers In parentheses are in units of mills/103 Ib steam.
"Bracket indicates gross estimate.
c<> Indicates units of mills/106 Btu heat input.
Continued
T-1549
-------
TABLE 4-2. Concluded
System
Standard Boilers
Type
Spreader Stoker
Spreader Stoker
Chain Grate
Stoker
Underfeed
Stoker
Heat Input
MW (106 Btu/hr)
44 (150)
25 (85)
22 (75)
9 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
No Controls
SIP
SCA
Moderate
Ammonia Injection
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
No controls
SIP
Intermediate
LEA
Stringent
Contro 1
Effectiveness
Percent
~
1
20
__
20
55
—
10
~
10
Estimated Incremental Costs
Capital
Cost
103 $
—
22
22
.-
17
[102]b
—
17
—
14
Annual i zed Costs
Fixed Costs
mills
103 kg steam
—
16 (7)a
16 (7)
--
22 (10)
[133 (60)]
—
26 (12)
—
54 (24)
Operating Costs Total Costs
mills
lO3 kg steam
--
-5 (-2)
4 (2)
__
5 (2)
[90 (40)]
~
-10 (-4)
—
-6 (-3)
mills
103 kg steam
—
11 (5)
20 (9)
__
27 (12)
[223 (100)]
—
16 (8)
1
48 (21)
mills
GJ input
—
3 <3*
6 <7>
__
8 <8>
[ 71 <75>]
~
5 <5>
--
15 <16>
^Numbers in parentheses are mills/103 Ib steam.
^Bracket indicates gross estimate.
c<> indicates units of mill/10^ Btu heat input.
T-1549
-------
TABLE 4-3. ESTIMATED COST-EFFECTIVENESS AND IMPACTS OF CANDIDATE NO CONTROL TECHNIQUES
FOR NEW COAL-FIRED BOILERS
System
Standard Boilers
Type
Pulverized Coal
Heat Input
MW (106 Btu/hr)
59 (200)
117 (400)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
0
0.3
[0.3]C
[1.0]
—
0
0.3
[0.3]c
[1.0]
Impacts
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
—
0.4
0.8
[0.8]
[4.0]
—
0.4
0.8
[0.8]
[4.0]
SIP-Controlled
Boiler
—
—
0.8
[0.8]
[4.0]
—
—
0.8
[0.8]
[4.0]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
—
0
0.6
L0.6]
[2.0] .
—
0
0.6
[0.6]
[2.0]
SIP-Controlled
Boiler
—
0
0.6
[0.6]
[2.0]
—
0
0.6
[0.6]
[2.0]
-p.
I
aCost of boiler only.
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1562
-------
TABLE 4-3. Concluded
-F*
I
System Impacts
Standard Boilers
Type
Spreader Stoker
Spreader Stoker
Chain Grate
Stoker
Underfeed Stoker
Heat Input
MM (106 Btu/hr)
44 (150)
25 (85)
22 (75)
9 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
No Controls
SIP
SCA
Moderate
Amonia Injection
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
1.6
0.1
__
0.2
[0.5]
—
0.4
—
0.6
Percent Increase In
Capital Costa Over
Uncontrolled
Boiler
—
0.5
0.5
0.7
[5.0]
—
1.2
~
1.5
SIP-Controlled
Boiler
—
0.5
0.5
_.
0.7
[5.0]
• —
1.2
—
1.5
Percent Increase In
Steam Cost0 Over
Uncontrolled
Boiler
—
0.1
0.1
0.2
[2.5]
~
0.2
—
0.2
SIP-Controlled
Boiler
—
0.1
0.1
__
0.2
[2.5]
—
0.2
—
0.2
aCost of boiler only.
"Cost includes entire steam plant.
cBracket indicates gross estimate.
T-1562
-------
TABLE 4-4. ESTIMATED COSTS OF CANDIDATE CONTROL TECHNIQUES
FOR RETROFITTED COAL-FIRED BOILERS
System
Standard Boilers
Type
Pulverized Coal
Heat Input
MW (106 Btu/hr)
59 (200)
117 (400)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
Contro 1
Effectiveness
Percent
--
10
25
25
25
—
10
25
25
25
Estimated Incremental Costs
Capital
Cost
103 $
—
30
70
[70b]
[237]
--
50
118
[118t>]
[237]
Annual ized Costs
Fixed Costs
mills
103 kg steam
~
16 (7)a
37 (17)
[35 (16)]
[125 (57)]
—
13 (6)a
31 (14)
[31 (14)]
[125 (57)]
Operating Costs
mills
103 kg steam
~
-12 (-5)
59 (27)
[60 (27)]
[82 (37)]
~
-13 (-6)
57 (26)
[57 (26)]
[82 (37)]
Total Costs
mills
Ifl3 kg steam
—
4 (2)
96 (44)
[95 (43)]
[205 (93)]
—
0 (0)
88 (40)
[88 (40)]
[205 (93)]
mills
GJ input
—
1 c
33 <35>
[32 <34>]
[70 <73>]
—
0 <0>c
29 <31>
[29 <31>]
[70 <73>]
aNumbers in parentheses are in units of mills/103 lb steam.
"Bracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1550
-------
TABLE 4-4. Concluded
System
Standard Boilers
Type
Spreader Stoker
Spreader Stoker
Chain Grate
Underfeed Stoker
Heat Input
MW (106 Btu/hr)
44 (150)
25 (85)
22 (75)
9 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
No Controls
SIP
SCA
Moderate
Ammonia Injection
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
Control
Effectiveness
Percent
—
1
20
__
20
55
—
10
—
15
Capital
Cost
103 $
—
25
25
__
20
[100] b
—
20
—
14
Estimated Incremental Costs
Annual i zed Costs
Fixed Costs
mills
103 kg steam
—
18 (8)a
18 (8)
w
26 (12)
[131 (59)]
—
30 (14)
—
54 (24)
Operating Costs
mills
103 kg steam
—
-3 (-1)
5 (2)
__
7 (3)
[88 (40)]
—
-10 (-4)
—
-4 (-2)
Total Costs
mills
103 kg steam
—
15 (7)
23 (10)
__
33 (15)
[220 (100)]
—
20 (10)
—
50 (23)
mills
GJ input
—
5<5>c
7<7>
__
11 <11>
[70 <74>]
--
6 -6>
--
16 <17>
^Numbers in parentheses are in units of mills/103 Ib steam.
DBracket indicates gross estimate.
c<> indicates units of mills/10° Btu heat input.
T-1550
-------
TABLE 4-5. ESTIMATED COST-EFFECTIVENESS AND IMPACTS OF CANDIDATE NOV CONTROL
TECHNIQUES FOR RETROFITTED COAL-FIRED BOILERS
System
Standard Boilers
Type
Pulverized Coal
Heat Input
HW (106 Btu/hr)
59 (200)
117 (400)
Type and Level
of Control
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
LEA
Intermediate
SCA
Stringent
LNB
Stringent
Ammonia Injection
Stringent
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
0.1
0.5
[0.4]C
[1.0]
0
0.4
[0.4]C
[1.0]
Percent Increase in
Capital Costa Over
Uncontrolled
Boiler
0.5
1.2
[1.2]
[4.0]
0.5
1.2
[1.2]
[4.0]
SIP-Controlled
Boiler
0.5
1.2
[1.2]
[4.0]
0.5
1.2
[1.2]
[4.0]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
0
0.8
[0.8]
[2.0]
0
0.8
[0.8]
[2.0]
SIP-Controlled
Boiler
0
0.8
[0.8]
[2.0]
0
0.8
[0.8]
[2.0]
aCost of boiler only.
>>Cost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1563
-------
TABLE 4-5. Concluded
System Impacts
Standard Rollers
Type
Spreader Stoker
Spreader Stoker
Chain Grate
Stoker
Underfeed Stoker
Heat Input
MW (106 Btu/hr)
44 (150)
25 (85)
22 (75)
9 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
No Controls
SIP
SCA
Moderate
Amonia Injection
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
2.4
0.2
--
0.2
0.5 c
~
0.5
—
0.7
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
—
0.6
0.6
__
1.0
5.0
—
1.4
—
1.5
SIP-Controlled
Boiler
—
0.6
0.6
__
1.0
5.0
—
1.4
—
1.5
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
—
0.1
0.2
__
0.3
2.5
—
0.2
—
0.2
SIP-Controlled
Boiler
—
0.1
0.2
__
0.3
2.5
—
0.2
—
0.2
co
j*Cost of boiler only.
"Cost includes entire steam plant.
cBracket indicates gross estimate.
T-1563
-------
4.2.1 New Facilities
For pulverized coal-fired boilers, controls are not needed to reach
SIP or moderate levels (301 ng/J). To achieve intermediate levels (258
ng/J), low excess air can sometomes be used which should not raise the
cost of generating steam. Staged combustion through overfire air
operation may allow stringent control levels to be met and could increase
steam cost by about 0.5 percent. Low NO burners or ammonia injection
/\
may be needed to reach stringent control levels. Since both techniques
are only in the development stage, only rough cost estimates can be
given. However, LNB will probably not cost any more than OFA (References
4-1, 4-16). Low NO burners will most likely have a smaller energy
A
penalty than OFA. Furthermore, low NO burner windbox modification and
A
any additional burner cost will probably be no more than installing OFA
ports. Ammonia injection prices were based on a utility boiler report
(References 4-4 and 4-5) and have been extrapolated to industrial boiler
size. Because industrial boiler loads fluctuate more than those of
utility boilers, the cost of an NH~ injection system per kilowatt should
be higher for industrial boilers than utility boilers, which operate at
more constant loads. Specifically, the ammonia injection system will
probably have a higher unit cost since it may require several injection
ports and a control system for switching between the ports. Using the
utility boiler costs, ammonia injection is estimated to raise the price of
steam by over 2 percent.
Large size spreader stokers need controls to reach an intermediate
NO level (258 ng/J) and low excess air operation should be sufficient
A
which would minimally affect the steam price. Overfire air can be used to
achieve the even tighter stringent control levels (215 ng/0) which may
raise the price of steam slightly. Stokers unlike pulverized coal units,
normally have OFA ports as smoke control devices so there is no
incremental charge for these ports and no additional fan power
requirement. This assumes that the OFA ports need not be relocated for
better NO control. Using more LEA than is needed to reach the NOV
A A
control level can reduce the cost of steam. However, this can only be
done where process operation limitations permit. The smaller size
spreader stokers (<29 MW heat input) must meet more rigid control levels.
To meet moderate levels (215 ng/J), OFA can be used which would raise
4-19
-------
Steam costs slightly as was the case for the larger size stokers. Ammonia
.injection should achieve stringent control levels (129 ng/J) but, using
utility boiler price estimates to give a gross estimate, steam cost can
increase by about 2.5 percent which is a very large increase when compared
to the other control techniques. Based on the only two tests reported,
chain grate stokers only need controls to meet stringent control levels
and LEA is recommended. Underfeed stokers only need control to reach
stringent levels and LEA is recommended. Low excess air operation would
raise steam cost slightly, but using even lower excess air than is needed
to reach the control level may lower the steam price, if process operation
limitations will permit.
4.2.2 Modified and Reconstructed Facilities
It is usually cheaper to modify a unit in the design phase than to
retrofit after installation. Also, since retrofit costs are more site
dependent than modifications to new units, retrofit cost estimates have a
larger error than estimates for original equipment. Retrofitted controls
would probably not be as efficient as original equipment. Therefore where
OFA is used in Tables 4-4 and 4-5, the thermal efficiency is assumed to
decrease by 0.25 percent. Ammonia injection costs are assumed to be the
same for retrofitted units as for new ones. In general, N0x control
costs show the same trends for retrofitted as for new units.
4.3 CONTROL COSTS FOR OIL-FIRED BOILERS
The estimated incremental cost of NO controls for new boilers
A
firing residual oil and distillate oil are shown in Tables 4-6, 4-7, 4-8,
and 4-9. Since residual oil-fired units require different control methods
than distillate oil-fired boilers, they are listed separately. Although
boiler costs are about the same for both oils, residual oil firing
requires more fuel handling equipment which raises the cost of the steam
plant. The prices listed in the tables are engineering estimates based on
vendor quotes and published costs (References 4-9, 4-10, 4-11, 4-12, 4-14,
and 4-17 through 4-20). Tables 4-10, 4-11, 4-12, and 4-13 list the
estimated costs for retrofitted boilers. Again, using lower excess air
than is required to meet a control level can minimize the cost impact
where process operation permits. Figures 4-2 and 4-3 show plots of
annualized estimated control costs for new oil-fired boilers.
4-20
-------
TABLE 4-6. ESTIMATED COSTS OF CANDIDATE NOY CONTROL TECHNIQUES FOR
NEW RESIDUAL OIL-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Water tube
Heat Input
MW (106 Btu/hr)
4.4 (15)
8.8 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
LEA
SIP
Moderate
SCA
Intermediate
LNB
Str i ngent
Ammonia Injection
Stringent
Control
Effectiveness
Percent
--
5
25
25
20
35
45
45
Estimated Incremental Costs
Capital
Cost
103 $
—
9
19
[19]b
12
22
[22]
[72]
Annual ized Costs
Fixed Costs
mills
103 kg steam
—
91 (41)a
193 (88)
[195 (88)]
45 (20)
82 (37)
[82 (37)]
[270 (122) ]
Operating Costs
mills
103 kg steam
—
-21 (-10)
117 (53)
[ 120 (54) ]
-68 (-31)
89 (40)
[89 (40)]
[93 (42)]
Total Costs
mills
103 kg steam
—
70 (31)
310 (141)
[310 (141)]
-23 (-11)
171 (78)
[171 (78)]
[363 (165) ]
Mills
GJ input
—
22<24-c
99 <105 >
[99 <105>]
-7 <-8>
55 < 58>
[ 55 < 58 > ]
[117< 123 >]
aNumbers in parentheses are in units of mills/10^ Ib steam.
''Bracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1551
-------
TABLE 4-6. Concluded
System
Standard Boilers
Type
Water-tube
Heat Input
MH (106 Btu/hr)
44 (150)
Type and Level
of Control
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Ammonia Injection
Stringent
Control
Effectiveness
Percent
20
35
45
45
Estimated Incremental Costs
Capital
Cost
103 $
17
32
[32]
[182]
Annual i zed Costs
Fixed Costs
mills
103 kg steam
12 (5)
23 (10)
[ 23 (10)]
[133 (60)]
Operating Costs
mills
103 kg steam
-75 (-34)
80 (36)
[80 (36)] '
[90 (41)]
Total Costs
mills
103 kg steam
-63 (-29)
103 (46)
[102 (46) ]
[223 (101)]
Mills
GJ input
-20 <-28>
33 < 34>
[33 < 34>]
[72 < 75>]
ro
ro
^Numbers in parentheses are in units of mills/103 Ib steam.
"Bracket indicates gross estimate.
c<>indicates units of mills/106 Btu heat input.
T-1551
-------
TABLE 4-7. ESTIMATED COST-EFFECTIVENESS AND IMPACTS OF CANDIDATE NOX CONTROL
TECHNIQUES FOR NEW RESIDUAL OIL-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Uatertube
Heat Input
HU (106 Btu/hr)
4.4 (15)
8.8 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Ammonia Injection
Stringent
Impacts
Cost
Effec-
$/kg NOX
Reduced
~
2.3
3.2
[3.2]c
—
1.1
[0.7]
[1.6]
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
—
8.7
21.0
[21.0]
3.0
5.5
[5.5]
[18.0]
SIP-Controlled
Boiler
~
8.7
21.0
[21.0]
~
2.5
[2.5]
[18.0]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
—
0.2
1.2
[1.2]
-0.1
1.2
[1.2]
[2.5]
SIP-Controlled
Boiler
~
0.2
1.2
[1.2]
—
1.3
[1.3]
[2.6]
I
ro
CJ
aCost of boiler only.
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1564
-------
TABLE 4-7. Concluded
System
Standard Boilers
Type
Water tube
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Ammonia Injection
Stringent
Impacts
Cost
Effec-
$/kg NOX
Reduced
—
0.6
[0.4]
[1.1]
Percent Increase in
Capital Cost" Over
Uncontrolled
Boiler
1.9
3.8
[4.0]
[22.5]
SIP-Controlled
Boiler
—
1.9
[2.0]
[22.0]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
-0.5
0.8
[0.8]
[2.0]
SIP-Controlled
Boiler
—
1.3
[1.3]
[2.5]
aCost of boiler only.
bCost includes entire steam plant.
cBracket indicates gross estimate.
T-1564
-------
TABLE 4-8. ESTIMATED COSTS OF CANDIDATE N0¥ CONTROL TECHNIQUES FOR
NEW DISTILLATE OIL-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Watertube
without an
Air Preheater
Heat Input
HW (10& Btu/hr)
4.4 (15)
29 (100)
Type and Level
of Control
No Control
SIP
Moderate
LEA
Intermediate
FGR
Stringent
LNB
Stringent
No control
SIP
Intermediate
FGR
Stringent
LNB
Stringent
SCA
Stringent
Control
Effectiveness
Percent
—
10
40
'40
—
15
15
15
Estimated Incremental Costs
Capital
Cost
103 $
—
9
19
[19]b
—
26
[26]
26
Annual 1 zed Costs
Fixed Costs
mills
103 kg steam
—
91 (41 )a
192 (87)
[192 (87)]
—
30 (13)
[30 (13)]
30 (13)
Operating Costs
mills
103 kg steam
—
-26 (-12)
175 (80)
[ 100 (45) ]
~
139 (63)
[86 (39)]
86 (39)
Total Costs
mills
103 kg steam
—
65 (29)
367 (167)
[292 (132)]
—
170 (77)
[115 (52)]
116 (52)
mills
GJ input
—
20 <21>c
117< 125>
[93 <99>]
--
54 <57>
[ 37 <27>]
36 <39>
I
r\3
en
aNumbers in parentheses are in units of mills/103 Ib steam.
^Bracket indicates gross estimate.
c<> indicate units of mills/106 Btu heat input.
Continued
T-1552
-------
TABLE 4-8. Continued
System
Standard Boilers
Type
Watertube with
Air Preheater
Heat Input
MM (106 Btu/hr)
29 (100)
Type and Level
of Control
No Controls
SIP
LEA
Moderate
RAP
Intermediate
FOR
Intermediate
LNB
Intermediate
SCA
Intermediate
RAP & FGR
Stringent
RAP & LNB
Stringent
Control
Effectiveness
Percent
5
30
30
30
30
55
55
Estimated Incremental Costs
Capital
Cost
103 $
14
2
26
[26]b
26
26
[26]
Annual ized Costs
Fixed Costs
mills
103 kg steam
__
16 (7)«
2 (1)
29 (13)
[29 (13)3
29 (13)
29 (13)
[29 (13)]
Operating Costs
mills
103 kg steam
-19 (-9)
130 (59)
135 (61)
[90 (41)]
84 (38)
265 (120)
[215 (98) ]
Total Costs
mills
103 kg steam
__
-3 (-2)
132 (60)
164 (74)
[119 (54)]
113 (51)
294 (133)
[244 (111)]
mills
GJ input
-1< -l>c
42 < 44 >
54 < 57 >
[38<40>]
36 < 38 >
94 < 98 >
[ 78<82>]
.£>
ro
aNumbers in parentheses are in units of mil Is/103 Ib steam.
bBracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1552
-------
TABLE 4-8. Concluded
System
Standard Boilers
Type
Water-tube with
Air Preheater
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
No Controls
SIP
LEA
Moderate
RAP
Intermediate
FGR
Intermediate
LNB
Intermediate
SCA-
Intermediate
RAP & FGR
Stringent
RAP & LNB
Stringent
Control
Effectiveness
Percent
__
5
30
30
30
30
55
55
Estimated Incremental Costs
Capital
Cost
103 J
__
17
2
32
[32]b
32
32
[32]
Annual i zed Costs
Fixed Costs
mills
103 kg steam
__
12 (6)«
1 (1)
23 (11)
[23 (11)]
23 (11)
23 (11)
[23 (11)]
Operating Costs
mills
103 kg steam
__
-19 (-9)
128 (58)
133 (60)
[82 (37) ]
82 (37)
260 (118)
[219 (100)]
Total Costs
mills
103 kg steam
__
-7 (-3)
130 (59)
156 (71)
[105 (48) ]
105 (48)
284 (129)
[ 243 (116) ]
mills
GJ input
_ _
-2<-2>c
42 < 44 >
51 < 54 >
[ 34 < 36 >]
34 < 36 >
93 < 98 >
[ 80 < 84 >]
I
ro
aNumbers in parentheses are In units of mills/103 Ib steam.
bBracket Indicates gross estimate.
c<> indicates units of mi 11s/10° Btu heat input.
T-1552
-------
TABLE 4-9. ESTIMATED COST-EFFECTIVENESS AND IMPACTS OF CANDIDATE NOX CONTROL
TECHNIQUES FOR NEW DISTILLATE OIL-FIRED BOILERS
ro
CO
System
Standard Boilers
Type
Flretube
Watertube
without an
Air Preheater
Heat Input
MU (106 Btu/hr)
4.4 (15)
29 (100)
Type and Level
of Control
No Control
SIP
Moderate
LEA
Intermediate
FOR
Stringent
LNB
Stringent
No Control
SIP
Intermediate
F6R
Stringent
LNB
Stringent
SCA
Stringent
Impacts
Cost
Effec-
S/kg NOX
Reduced
--
2.3
4.1
[3.2]C
—
4.4
[3.0]
3.0
Percent Increase in
Capital Costa Qver
Uncontrolled
Boiler
—
9.0
21.0
[21.0]
—
8.0
[8.0]
8.0
SIP-Controlled
Boiler
~
9.0
21.0
[21.0]
—
8.0
[8.0]
8.0
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
~
0.2
1.2
[1.0]
~
1.8
[1.2]
1.2
SIP-Controlled
Boiler
--
0.2
1.2
[1.0]
—
1.8
[1.2]
1.2
aCost of boiler only.
bCost includes entire steam plant.
cBracket Indicates gross estimate.
Continued
T-1565
-------
TABLE 4-9. Continued
System
Standard Boilers
Type
Watertube with
Air Preheater
Heat Input
MH (106 Btu/hr)
29 (100)
Type and Level
of Control
No Controls
SIP
LEA
Moderate
RAP
Intermediate
FOR
Intermediate
LNB
Intermediate
SCA
Intermediate
RAP + FGR
Stringent
RAP ••• LNB
Stringent
Impacts
Cost
Effec-
$/kg NOX
Reduced
__
1.7
2.1
[1.4]C
1.4
2.0
[1.7]
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
—
3.4
0
7.0
[7.0]
7.0
7.0
[7.0]
SIP-Controlled
Boiler
__
3.4
0
7.0
[7.0]
7.0
7.0
[7.0]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
_-
0
1.4
1.7
[1.2]
1.2
3.1
[2.6]
SIP-Controlled
Boiler
0
1.4
1.7
[1.2]
1.2
3.1
[2.6]
-p.
I
ro
aCost of boiler only.
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1565
-------
TABLE 4-9. Concluded
System
Standard Boilers
Type
Water-tube with
Air Preheater
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
No Controls
SIP
LEA
Moderate
RAP
Intermediate
FGR
Intermediate
LNB
Intermediate
SCA
Intermediate
RAP + FGR
Stringent
RAP + LNB
Stringent
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
__
1.6
2.0
[l.3]c
1.3
1.9
[1.6]
Percent Increase in
Capital Costa Over
Uncontrolled
Boiler
_.
3.4
0.1
5.0
[4.0]
4.0
4.0
[4.0]
SIP-Controlled
Boiler
__
3.4
0.1
5.0
[4.0]
4.0
4.0
[4.0]
Percent Increase 1n
Steam Costb Over
Uncontrolled
Boiler
--
0
1.3
1.6
[1.1]
1.1
2.9
[2.4]
SIP-Controlled
Boiler
__
0
1.3
1.6
[1.1]
1.1
2.9
[2.4]
I
CO
o
aCost of boiler only.
bCost includes entire steam plant.
cBracket indicates gross estimate.
T-1565
-------
TABLE 4-10. ESTIMATED COSTS OF CANDIDATE NOX CONTROL TECHNIQUES FOR
RETROFITTED RESIDUAL OIL-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Watertube
Heat Input
MW (106 Btu/hr)
4.4 (15)
8.8 (30)
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Ammonia Injection
Stringent
Control
Effectiveness
Percent
~
5
25
25
20
35
45
45
Estimated Incremental Costs
Capital
Cost
103 $
—
10
30
[30]*
14
34
[34]
[72]
Annuali zed Costs
Fixed Costs Operating Costs Total Costs
mills
103 kg steam
--
102 (46)3
304 (138)
[300 (136)]
52 (24)
127 (58)
[127 (58)]
[270 (122)]
mills
103 kg steam
—
-14 (-6)
170 (77)
[170 (77)]
-66 (-30)
102 (46)
[102 (46)]
[ 93 (42)]
mills
103 kg steam
—
88 (40)
475 (216)
[475 (216)]
-14 (-6)
229 (104)
[229 (-104)]
[363 (165)]
mills
GJ input
—
28 <30>c
152 <161>
[152 <161>]
-4 <-5>
74 <78>
[ 74 <78>]
[117 <123>]
I
co
^Numbers in parentheses are in units of mills/103 Ib steam.
''Bracket indicates gross estimate.
c<> indicates units of mills/10" Btu heat input.
T-1553
-------
TABLE 4-10. Concluded
System
Standard Boilers
Type
Hater tube
Heat Input
HW (10* Btu/hr)
44 (150)
Type and Level
of Control
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Anmonla Injection
Stringent
Control
Effectiveness
Percent
20
35
45
45
Estimated Incremental Costs
Capital
Cost
103 $
20
50
[50]
[180]
Annual ized Costs
Fixed Costs
mills
103 kg steam
15 (7)
37 (17)
[ 37 (17) ]
[ 170 (77) ]
Operating Costs
mills
103 kg steam
-75 (-34)
103 (47)
[103 (47)]
[90 (41)]
Total Costs
mills
ID3 kg steam
-60 (-27)
140 (64)
[ 140 (64) ]
[250 (114)]
mills
GJ input
-19 < -20 >
45 < 48 >
[45<48>]
[80<85>]
GO
ro
lumbers in parentheses are in units of mil Is/103 Ib steam.
bBracket indicates gross estimate.
c<> indicates units of mills/10° Btu heat input.
T-1553
-------
TABLE 4-11. ESTIMATED COST EFFECTIVENESS AND IMPACTS OF CANDIDATE NOX CONTROL
TECHNIQUES FOR RETROFITTED RESIDUAL OIL-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Water-tube
Heat Input
MW (10& Btu/hr)
4.4 (15)
8.8 (30)
•
Type and Level
of Control
No Controls
SIP
Moderate
LEA
Intermediate
SCA
Stringent
LNB
Stringent
LEA
SIP
Moderate
SCA
Intermediate
LNB
Str i ngent
Ammonia Injection
Stringent
Impacts
Cost
Effec-
$/kg NOX
Reduced
~
4.0
5.2
[5.2JC
1.5
[0.9]
[1.6]
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
—
12.5
27.5
[38.0]
3.5
8.5
[8.5]
[18.0]
SIP-Controlled
Boiler
—
12.5
27.5
[38.0]
—
5.0
[5.0]
[18.0]
Percent Increase in
Steam Cost1* Over
Uncontrolled
Boiler
—
0.4
1.9
[2.0]
-0.1
1.6
[1.6]
[2.5]
SIP-Controlled
Boiler
--
0.4
1.9
[2.0]
—
1.7
[1.7]
[2.6]
I
GO
GO
of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1558
-------
TABLE 4-11. Concluded
System
Standard Boilers
Type
Water-tube
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
LEA
SIP
Moderate
SCA
Intermediate
LNB
Stringent
Ammonia Injection
Stringent
Impacts
Cost
Effec-
$/kg MOX
Reduced
0.9
[0.6]
[1.1]
Percent Increase in
Capital Cost* Over
Uncontrolled
Boiler
2.5
6.2
[6.2]
[22.5]
SIP-Controlled
Boiler
~
3.7
[3.7]
[22.5]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
-0.5
1.1
[1.1]
[1.9]
SIP-Controlled
Boiler
—
1.6
[1.6]
[2.5]
I
CO
aCost of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
T-1558
-------
TABLE 4-12. ESTIMATED COSTS OF CANDIDATE NO CONTROL TECHNIQUES FOR
RETROFITTED DISTILLATE OIL-FIRE& BOILERS
System
Standard Boilers
Type
Firetube
Water-tube
without an
Air Preheater
Heat Input
MW (106 Btu/hr)
4.4 (15)
29 (100)
Type and Level
of Control
No Control
SIP
Moderate
LEA
Intermediate
FOR
Stringent
LNB
Stringent
No controls
SIP
Intermediate
FGR
Stringent
LNB
Stringent
OSC
Stringent
Control
Effectiveness
Percent
—
10
40
40
~
15
15
15
Estimated Incremental Costs
Capital
Cost
103 $
~
10
30
[30?
~
40
[40]
40
Annual i zed Costs
Fixed Costs
mills
103 kg steam
~
102 (46) a
304 (138)
[304 (138)]
~
46 (21)
[46 (21)]
46 (21)
Operating Costs
mills
103 kg steam
—
-20 (-9)
208 (94)
[156 (71)]
—
144 (65)
[92 (42)]
92 (42)
Total Costs
mills
103 kg steam
—
82 (37)
512 (230)
[ 460 (209) ]
—
190 (86)
[140 (64)]
138 (64)
mills
GJ input
--
26 <27>c
164 < 171 >
[14<156>]
—
61 < 64 >
[ 45<47>]
44 < 47 >
-pi
tn
aNumbers in parentheses are in units of mills/lO3 lb steam.
bBracket indicates grdss estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1554
-------
TABLE 4-12. Continued
System
Standard Boilers
Type
Watertube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
29 (100)
Type and Level
of Control
No Control
SIP
LEA
Moderate
RAP
Intermediate
FOR
Intermediate
LNB
Intermediate
SCA «
Intermediate
RAP + F6R
Stringent
RAP + LNB
Stringent
Control
Effectiveness
Percent
5
30
30
30
30
55
55
Estimated Incremental Costs
Capital
Cost
103 $
15
2
40
[40 ]b
40
40
[40]
Annual i zed Costs
Fixed Costs
mills
103 kg steam
17 (8)a
2 (1)
45 (20)
[ 45 (20) ]
45 (20)
45 (20)
[45 (20)]
Operating Costs
mills
103 kg steam
-17 (-8)
130 (59)
139 (63)
[90 (41)]
88 (40)
269 (122)
[220 (100)]
Total Costs
mills
103 kg steam
0
132 (60)
185 (84)
[135 (61)]
135 (61)
315 (143)
[265 (120)]
mills
GJ input
0
44 < 47 >
63 < 66 >
[ 46 < 48 >]
46<48>
107 < 113 >
[90<95>]
I
co
aNumbers in parentheses are in units of mills/103 Ib steam.
^Bracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1554
-------
TABLE 4-12. Concluded
System
Standard Boilers
Type
Watertube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
No Control
SIP
LEA
Moderate
RAP
Intermediate
F6R
Intermediate
LNB
Intermediate
SCA-
Intermediate
RAP + FGR
Stringent
RAP + LNB
Stringent
Control
Effectiveness
Percent
5
30
30
30
30
55
55
Estimated Incremental Costs
Capital
Cost
103 $
19
2
62
[62]b
62
62
[62]
Annual ized Costs
Fixed Costs
mills
103 kg steam
14 (6)a
1 (1)
45 (20)
[45 (20)]
45 (20)
45 (20)
[ 45 (20) ]
Operating Costs
mills
103 kg steam
-18 (-8)
130 (59)
139 (63)
[90 (41)]
88 (40)
269 (122)
[220 (100) ]
Total Costs
mills
103 kg steam
-4 (-2)
132 (60)
185 (84)
[135 (61)]
135 (61)
315 (143)
[ 265 (120) ]
mills
GJ input
-1 <-!>
44 < 47 >- -
63 < 66 >
[ 46<48>]
46 < 48 >
107 < 113 >
[ 90<95>]
I
GO
aNumbers in parentheses are in units of mills/103 Ib steam.
^Bracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
T-1554
-------
TABLE 4-13. ESTIMATED COST EFFECTIVENESS AND IMPACTS OF CANDIDATE NOV CONTROL
TECHNIQUES FOR RETROFITTED DISTILLATE OIL-FIRED BOILERS X
CO
00
System
Standard Boilers
Type
Firetube
Watertube
without an
Air Preheater
Heat Input
MU (106 Btu/hr)
4.4 (15)
29 (100)
Type and Level
of Control
No Control
SIP
Moderate
LEA
Intermediate
FGR
Stringent
LNB
Stringent
No Controls
SIP
Intermediate
FGR
Stringent
LNB
Stringent
SCA
Stringent
1
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
4.3
6.0
[5.4?
—
5.0
[3.6]
3.6
Percent Increase in
Capital Cost* Over
Uncontrolled
Boiler
—
12.5
37.5
[37.5]
—
13.0
[13.0]
13.0
SIP-Controlled
Boiler
—
12.5
37.5
[37.5]
—
13.0
[13.0]
13.0
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
~
0.3
1.8
[1.6]
~
2.0
[1.5]
1.5
SlP-Controlled
Boiler
—
0.3
1.8
[1.6]
—
2.0
[1.5]
1.5
aCost of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1559
-------
TABLE 4-13. Continued
4^
00
System
Standard Boilers
Type
Water tube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
29 (100)
Type and Level
of Control
No Control
SIP
LEA
Moderate
RAP
Intermediate
FGR
Intermediate
LNB
Intermediate
SCA
Intermediate
RAP + FGR
Stringent
RAP + LNB
Stringent
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
0
1.7
2.4
[1.7]c
1.7
2.1
[ 1-8]
Percent Increase in Percent Increase in
Capital Cost3 Over Steam Costb Over
Uncontrolled
Boiler
4.0
0
11.0
[11.0]
11.0
11.0
[11.0]
SIP-Controlled
Boiler
4.0
0
11.0
[11.0]
11.0
11.0
[11.0]
Uncontrolled
Boiler
0
1.4
2.0
[1.4]
1.4
3.4
[2.9]
SIP-Controlled
Boiler
0
1.4
2.0
[1.4]
1.4
3.4
[2.9]
aCost of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1559
-------
TABLE 4-13. Concluded
System
Standard Boilers
Type
Watertube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
44 (150)
Type and Level
of Control
No Control
SIP
LEA
Moderate
RAP
Intermediate
FGR
Intermediate
LNB
Intermediate
SCA
Intermediate
RAP + FGR
Stringent
RAP + LNB
Stringent
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
0
1.7
2.4
[1.7F
1.7
2.1
[1.8]
Percent Increase in
Capital Cost9 Over
Uncontrolled
Boiler
4.0
0
11.0
[11.0]
11.0
11.0
[n.o]
SIP-Controlled
Boiler
4.0
0
11.0
[11.0]
11.0
11.0
[n.o]
Percent Increase in
Steam Cost0 Over
Uncontrolled
Boiler
0
1.4
2.0
[1.4]
1.4
3.4
[2.9]
SIP-Controlled
Boiler
0
1.4
2.0
[1.4]
1.4
3.4
[2.9]
-p.
I
aCost of boiler only
bCost includes entire steam plant.
cBracket Indicates gross estimate.
T-1559
-------
4.3.1 New Facilities
For the typical residual oil-fired firetube boiler to achieve
intermediate NO emission levels (108 ng/J) low excess air (LEA) is
A
recommended. This control technique can raise the price of steam by about
0.2 percent. However, even lower excess air over that needed to achieve
the emission level can lower the impact on steam cost. Staged combustion
(SCA) or low NO burners (LNB) are recommended techniques for reaching
J\
stringent control levels (86 ng/J). Staged combustion may raise the price
of steam by over 1 percent and as already noted, LNB should probably have
a smaller effect on steam cost than SCA does. Recall that this is because
LNB are expected to have a smaller incremental capital cost and also have
a smaller energy impact. At present a true estimate of the cost of LNB
can not be made and thus LNB are assumed to be priced the same as SCA
operation.
For the typical watertube boiler firing residual oil, low excess
air is recommended for reaching SIP or moderate control levels (129 ng/J);
LEA has the additional benefit of lowering steam cost. Staged combustion
can be used to meet intermediate control levels (108 ng/J) but it may
raise the price of steam by over 1 percent. Recall that the effect of
staged combustion (overfire air or sidefire air) on thermal efficiency
depends on port location and the fuel being fired; thus the exact cost
impact of the SCA;technique will depend on the air port location and the
fuel being fired. If only one type of fuel is fired, it would be possible
to optimize the location of the air port and possibly decrease the effect
on steam cost. Meeting stringent control levels requires either LNB or
ammonia injection, both of which have already been described. Ammonia
injection costs are based on extrapolated utility prices and low NO
A
burner costs are assumed to be no more than SCA costs. Since both methods
(LNB and NH-j injection) are in the development stage, the costs
estimates may have large errors.
The recommended control methods for a firetube boiler firing
distillate oil are LEA for intermediate levels and flue gas recirculation
(FGR) or LNB for stringent levels. Increased fan power requirements for
FGR makes it a costly technique for a typical distillate oil-fired
firetube boiler. Although LNB are estimated to cost less than FGR, FGR is
4-41
-------
presently available, while low NO burners are still in the development
A
stage.
The larger watertube boilers firing distillate oil are divided
between those with and without an air preheater because the units with air
preheaters emit more NO (see Section 3). Economizers are recommended
A
over air preheaters as a device for increasing thermal efficiency since
they raise efficiency without raising NO emission levels. Watertube
A
boilers without air pretieaters can use FGR, LNB, or SCA to reach stringent
control levels. Staged combustion is estimated to have a smaller effect
on steam cost than FGR but to allow for fuel switching, SCA may require
several air port locations, which may be impractical. Again LNB are
estimated to cost no more than SCA and probably less.
Watertube boilers with air preheaters can use LEA to reach moderate
control leveds without raising steam costs. Achieving intermediate
control levels would require RAP, FGR, LNB, or SCA. Low NO burners
A
should have the least economic impact of these four methods. Reduced air
preheat is the easiest to implement but the thermal efficiency gained by
installing the air preheater is lost. Again SCA should have a smaller
economic impact than FGR if the need for several air port locations to
allow for fuel switching does not make SCA impractical. To reach
stringent control levels, RAP + FGR or RAP + LNB can be used. The high
costs of these methods strongly suggest that economizers be used whenever
possible instead of air preheaters. Low NO burners can have a smaller
A
economic impact than is noted in the table but RAP + LNB would still be a
costly technique due to the loss in thermal efficiency with RAP
operation. The use of LEA and LNB with an economizer instead of an air
preheater may result in lower steam costs and lower NO emissions.
4.3.2 Modified and Reconstructed Facilities
Firetube boilers are relatively more expensive on a percent basis
to retrofit since their initial cost is not very high. For both residual
and distillate oils, achieving stringent control levels can raise the
steam costs by over 2 percent. The control costs are also high for
firetube boilers because of the small base to spread modification costs
over. It also costs more to retrofit watertube boilers than to include
the emission control system in the original design.
4-42
-------
4.4 CONTROL COSTS FOR NATURAL GAS-FIRED BOILERS
The control costs for natural gas-fired boilers discussed in this
section are also engineering estimates based on published costs and
manufacturer estimates (References 4-9 through 4-12, 4-14, and 4-17
through 4-20). Since most of the control methods have already been
discussed, they are only briefly covered here. In all cases, LEA
operation is recommended to lower the cost impact. Tables 4-14, 4-15,
4-16, and 4-17 list cost estimates for new and retrofitted units.
4.4.1 New Facilities
Firetube boilers firing natural gas meet all recommended NO
rt
emission levels without control systems. For watertube boilers again,
economizers are recommended over air preheaters. Watertube boilers
without air preheaters only need LEA operation to meet stringent NO
/\
control levels, possibly reducing steam costs slightly. Watertube boilers
with air preheaters will require additional controls to meet all
recommended emission levels.
Watertube boilers with air preheaters need RAP, FGR, SCA or LNB to
meet SIP or moderate control levels (86 ng/J). Using RAP deletes the
efficiency gained by the air preheaters, but RAP may still be less costly
than FGR. Staged combustion or LNB should have smaller cost impacts than
RAP or FGR but LNB are still being developed and SCA may be impractical
because of fuel switching problems as was discussed earlier. Flue gas
recirculation is not as effective for controlling NO emissions from
A
residual oil-fired boilers and can limit the oils that can be fired when
natural gas is not available. For achieving intermediate control levels,
RAP + OFA/SFA can be used but it can raise steam prices by over
3 percent. The least expensive method for reaching stringent control
levels is RAP + LNB. The system of RAP + FGR can also be used, which may
raise the price of steam by over 4 percent. Alternatively, RAP + NH,
injection can be used, but it is the most costly of these controls and
because of load fluctuations and possible NH, emissions, it may prove
impractical.
4.4.2 Modified and Reconstructed Facilities
Reducing air preheat on an existing boiler equipped with an air
preheater is less cost-effective than using an economizer instead of an
air preheater on a new unit. The other control techniques are expected to
4-43
-------
TABLE 4-14. ESTIMATED COSTS OF CANDIDATE NO CONTROL TECHNIQUES FOR
NEW NATURAL GAS-FIRED BOILERS x
System
Standard Boilers
Type
Firetube
Water-tube
without an
A1r Preheater
Water tube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
4.4 (15)
29 (100)
29 (100)
Type and Level
of Control
No Control
SIP
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
SCA
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Control
Effectiveness
Percent
—
—
5
25
25
25
25
40
Estimated Incremental Costs
Capital
Cost
1QJ $
—
—
14
2
26
26
[26j>
26
Annuali zed Costs
Fixed Costs
mills
103 kg steam
—
—
16 (7)a
2 (1)
29 (13)
29 (13)
[29 (13)]
29 (13)
Operating Costs
mills
103 kg steam
—
—
-25 (-11)
113 (51)
»
120 (54)
69 (31)
[69 (31)]
183 (83)
Total Costs
mills
103 kg steam
—
—
-9 (-4)
115 (52)
150 (67)
98 (44)
[98 (44)]
212 (96)
mills
GJ input
-.
—
-3 <-4>c
38 < 41 >
51 < 53 >
33 < 36 >
[33<35>]
72 < 76 >
aNumbers in parentheses are in units of mills/103 Ib steam.
''Bracket indicates gross estimate.
c<> Indicates units of mills/W6 Btu heat input.
Continued
T-1555
-------
TABLE 4-14. Concluded
System
Standard Boilers
Type
Watertube
with an
Air Preheater
Heat Input
HU (Ifl6 Btu/hr)
29 (100)
44 (150)
44 (150)
Type and Level .
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP +• NH3
Injection
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
LNB
SIP
Moderate
RAP + OSC
Intermediate
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + NH3
Injection
Stringent
Control
Effectiveness
Percent
60
60
60
30
30
30
45
65
65
65
Capital
Cost
103 J
26
[26]b
[118]
2
32
[32]b
32
32
[32]t>
[182]
Estimated Incremental Costs
Annual ized Costs
Fixed Costs
mills
103 kg steam
29 (13)a
[29 (13)]
[132 (60)]
2 (1)
23 (11)
[23 (11)]
23 (11)
23 (11)3
[23 (11)]
[133 (60)]
Operating Costs
mills
103 kg steam
233 (106)
[182 (82)]
[201 (91)]
111 (51)
117 (53)
[66 (30)]
179 (81)
229 (104)
[179 (81)]
(199 (90)]
Total Costs
mills
103 kg steam
262 (119)
[210 (95)]
[333 (151)]
113 (51)
141 (64)
[89 (41)]
203 (92)
252 (114)
[202 (92)]
[332 (150)]
mills
GJ input
89 <94 >
[71 <75>]
[113 <118>]
37 <39>
46 <49>
[29 <31>]
67 <70>
83 <87>
[66 <;o>]
[109 <115>]
aNumbers in parentheses are in units of mills/103 Ib steam.
bBracket indicates gross estimate.
c oindicates units of mills/106 Btu heat input.
T-1555
-------
TABLE 4-15, ESTIMATED COST EFFECTIVENESS AND IMPACTS OF CANDIDATE NOX CONTROL
TECHNIQUES FOR NEW NATURAL GAS-FIRED BOILERS
System
Starldrd Boilers
Type
Firetube
Water-tube
without an
Air Preheater
Water tube
with an
Air Preheater
Heat Input
MW (10& Btu/hr)
4.4 (15)
29 (100)
29 (100)
Type and Level
of Control
No Control
SIP
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
SCA
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
—
1.5
2.0
1.3
[1.3F
1.5
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
~
—
4
7
7
7
[7F
7
SIP-Controlled
Boiler
~
—
4
~
~
~
~
7
Percent Increase in
Steam Cost& Over
Uncontrolled
Boiler
—
—
-0.2
1.8
2.4
1.5
[1.5]
3.4
SIP-Controlled
Boiler
—
—
-0.2
—
~
—
—
1.6
-pa
I
CTl
aCost of boiler only
"Cost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1560
-------
TABLE 4-15. Continued
System
Standard Boilers
Type
Water tube
with an
Air Preheater
Watertube
with an
Air Preheater
Heat Input
MM (106 Btu/hr)
29 (100)
44 (150)
Type and Level
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + NHa
Injection
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
LNB
SIP
Moderate
RAP -i- SCA
Intermediate
Impacts
Effec-
tiveness
$/kg NOX
Reduced
1.3
U.Ojc
[1.6]
1.1
1.4
[0.9JC
1.2
Percent Increase in
Capital Cost3 Over
Uncontrolled
Boiler
7
[7]
[33]
7
7
[7]c
7
SIP-Controlled
Boiler
7
[7]
[33]
—
--
—
7
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
4.2
[3.3]
[5.3]
1.8
2.4
[1-5]
3.4
SIP-Controlled
Boiler
2.4
[1.5]
[3.5]
—
~
—
1.6
aCost of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1560
-------
TABLE 4-15. Concluded
System
Standard Boilers
Type
Watertube
with an
Air Preheater
Heat Input
MM (106 Btu/hr)
44 (150)
Type and Level
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + NH3
Injection
Stringent
Impacts
Cost
Effec-
tiveness
$/kg NOX
Reduced
1.1
[0.9]c
[1.4]
Percent Increase in
Capital Cost9 Over
Uncontrolled
Boiler
7
[7]
[33]
SIP-Controlled
Boiler
7
[7]
[33]
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
4.2
[3.3]
[5.3]
SIP-Controlled
Boiler
2.4
[1.5]
[3.5]
I
*>
CO
aCost of boiler only
bCost includes entire steam.plant.
cBracket indicates gross estimate.
T-1560
-------
TABLE 4-16. ESTIMATED COSTS OF CANDIDATE NO CONTROL TECHNIQUES FOR
RETROFITTED NATURAL GAS BOILERS
System
Standard Boilers
Type
Firetube
Water-tube
without an
Air Preheater
Water-tube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
4.4 (15)
29 (100)
29 (100)
Type and Level
of Control
No Controls
SIP
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
SCA
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Contro 1
Effectiveness
Percent
—
.
5
25
25
25
25
40
Estimated Incremental Costs
Capital
Cost
103 $
—
—
15
2
40
40
[40]
40
Annual ized Costs
Fixed Costs
mills
103 kg steam
—
—
18 (8)a
2 (1)
45 (20)
45 (20)
[ 45 (20) ]
45 (20)
Operating Costs
mills
103 kg steam
—
—
-25 (11)
113 (51)
125 (57)
74 (34)
[74 (34)]
187 (85)
Total Costs
mills
103 kg steam
—
—
-7 (-3)
115 (51)
170 (77)
120 (54)
[ 120 (54)]
230 (104)
mills
GJ input
--
--
-2< -2>c
39 < 40 >
58<61>
41<43>
[ 41 < 43->-} '
78 < 82 >
aNumbers in parentheses are in units of mil Is/103 Ib steam.
"Bracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1556
-------
TABLE 4-16. Continued
System
Standard Boilers
Type
Water-tube
with an
Air Preheater
Heat Input
MU (106 Btu/hr)
29 (100)
44 (150)
Type and Level
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + NHa
Injection
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Control
Effectiveness
Percent
60
60
60
30
30
30
45
Estimated Incremental Costs
Capital
Cost
103 $
40
[40]b
[116]
2
62
[62]
62
Annual i zed Costs
Fixed Costs Operating Costs
mills mills
103 kg steam 103 kg steam
45 (20)a 237 (108)
[ 45 (20) ] [ 185 (84) ]
[130 (59)] [201 (91)]
2 (1) 113 (51)
45 (20) 125 (57)
[45 (20)] [74 (34)]
45 (20) 187 (85)
Total Costs
mills
103 kg steam
280 (128)
[230 (104)]
[ 330 (150) ]
115 (51)
170 (77)
[120 (54)]
230 (104)
mills
GO input
95 < 101>c
[78<82>]
[ 112<118>]
39 < 40 >
58<61>
[41<43>]
78 < 82 >
I
(Jl
o
aNumbers in parentheses are in units of mil Is/103 Ib steam.
bBracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
Continued
T-1556
-------
TABLE 4-16. Concluded
System
Standard Boilers
Type
Water tube
with an
Air Preheater
Heat Input
MU (106 Btu/hr)
44 (150)
Type and Level
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + NH3
Injection
Stringent
Control
Effectiveness
Percent
65
65
65
Estimated Incremental Costs
Capital
Cost
103 $
62
[62]b
[ 182]
Annual ized Costs
Fixed Costs
mills
103 kg steam
45 (20)a
[45 (20)]
[130 (59)]
Operating Costs
mills
103 kg steam
237 (108)
[185 (84) ]
[201 (91)]
Total Costs
mills
103 kg steam
280 (128)
[230 (104) ]
[330 (150)]
mills
GJ input
95 < 101>c
[78<82> ]
[112<118>]
en
aNumbers in parentheses are in units of mills/103 Ib steam.
bBracket indicates gross estimate.
c<> indicates units of mills/106 Btu heat input.
T-1556
-------
TABLE 4-17. ESTIMATED COST EFFECTIVENESS AND IMPACTS OF CANDIDATE NO CONTROL
TECHNIQUES FOR RETROFITTED NATURAL GAS-FIRED BOILERS
System
Standard Boilers
Type
Firetube
Matertube
without an
A1r Preheater
Watertube
with an
Air Preheater
Heat Input
MW (106 Btu/hr)
4.4 (15)
29 (100)
29 (100)
Type and Level
of Control
No Controls
SIP
Stringent
No Controls
SIP
Intermediate
LEA
Stringent
RAP
SIP
Moderate
FOR
SIP
Moderate
SCA
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Cost
Effec-
tiveness
$/kg NOX
Reduced
—
—
—
1.5
2.3
1.6
E...F
1.7
Impacts
Percent Increase 1n
Capital Costa Over
Uncontrolled
Boiler
~
—
5
0
11
11
[11]
11
SIP-Controlled
Boiler
~
—
5
—
—
~
—
11
Percent Increase in
Steam Cost*> Over
Uncontrolled
Boiler
~
—
-0.1
1.8
2.7
1.9
[1.9]
3.7
SIP-Controlled
Boiler
—
~
-0.1
~
—
—
—
1.9
en
ro
aCost of boiler only
"Cost Includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1561
-------
TABLE 4-17. Continued
en
System
Standard Boilers
Type
Water-tube
with an
Air Preheater
Watertube
with an
Air Preheater
Heat Input
HW (ID* Btu/hr)
29 (100)
44 (150)
Type and Level
of Control
RAP 4 FGR
Stringent
RAP + LNB
Stringent
RAP + NH3
Injection
Stringent
RAP
SIP
Moderate
FGR
SIP
Moderate
LNB
SIP
Moderate
RAP + SCA
Intermediate
Cost
Effec-
tiveness
$/kg NOX
Reduced
1.4
[1.1]
[1.6]
1.1
1.7
[1.2]c
1.3
Impacts
Percent Increase in
Capital Cost8 Over
Uncontrolled
Boiler
7
[7]
[33]
0
11
[11]
11
SIP-Controlled
Boiler
7
[7]
[33]
—
—
—
11
Percent Increase in
Steam Costb Over
Uncontrolled
Boiler
4.5
[3.7]
[5.3]
1.8
2.7
[1.9]
3.7
SIP-Controlled
Boiler
2.7
[1.9]
[3.5]
—
--
—
1.9
aCost of boiler only
bCost includes entire steam plant.
cBracket indicates gross estimate.
Continued
T-1561
-------
TABLE 4-17. Concluded
System
Standard Boilers
Type
Water tube
with an
Air Preheater
Heat Input
MH (106 Btu/hr)
44 (150)
Type and Level
of Control
RAP + FGR
Stringent
RAP + LNB
Stringent
RAP + 1*3
Injection
Stringent
Cost
Effec-
tiveness
$/kg NOX
Reduced
1.2
[1.1]
[1.4]
Impacts
Percent Increase in
Capital Costa Over
Uncontrolled
Boiler
7
[7]
[33]
SIP-Controlled
Boiler
7
[7]
[33]
Percent Increase in
Steam Cost0 Over
Uncontrolled
Boiler
4.5
[3.7]
[5.3]
SIP-Controlled
Boiler
2.7
[1.9]
[3.5]
*»
en
aCost of boiler only
bCost includes entire steam plant.
cBracket Indicates gross estimate.
T-1561
-------
give higher steam costs than RAP, as shown in Tables 4-16 and 4-17. The
previous comments on control techniques for new units still apply here for
retrofitted boilers.
4.5 SUMMARY
The primary contributions of combustion modification NO controls
A
to steam cost changes are the equipment modification costs and changes in
thermal efficiency and fan power demand. For firetube boilers annual!zed
equipment costs are usually higher than costs due to efficiency or fan
power demand changes. For watertube boilers, the opposite is usually
true. For both firetube and watertube boilers, all costs are important
and any factors that can lower any of these costs will be beneficial. In
many cases, using the lowest possible excess air will lower the cost
impact. Of course, the boiler should be designed to give the highest
possible thermal efficiency and lowest fan power requirements. Careful
design can result in better fuel efficiency than was assumed in the
calculations for flue gas recirculation and staged combustion.
Of the NOV controls covered, low excess air is the method
A
recommended to be first considered since it can reduce fuel costs. Low
NO burners are a promising technique since they should allow both low
A
NO and LEA operation, and thus save fuel while lowering NOV
A A
emissions. Staged combustion is the next best method, unless fuel
switching problems make it impractical, since the optimal air port
location is fuel dependent. If SCA cannot be used, FGR is the next most
cost-effective technique. Ammonia injection is the least cost effective
technique and load changing may make it very impractical. Also, whenever
possible, an economizer is preferred over an air preheater as a fuel
saving device since it does not raise NO levels.
A
In summary, combustion modification NO controls, once proven and
demonstrated, should be a cost effective means of control for industrial
boilers raising steam costs up to only 1 to 2 percent in most cases.
However, the initial investment required, especially for small boilers,
may be a large fraction of the cost of the boiler itself, up to 25 percent
when controls are installed on a new boiler and up to 50 percent when
retrofitting the controls on an existing boiler. Factory installed
controls on new boilers should prove more cost effective than retrofit
controls.
4-55
-------
REFERENCES FOR SECTION 4
4-1. Lim, K. J., et al., "Environmental Assessment of Utility Boiler
Combustion Modification NOX Controls," Acurex Draft Report
TR-78-105, under EPA Contract No. 68-02-2160, April 1978.
4-2. "Task 7 Summary Report - Technical and Economic Bases for
Evaluation of Emission Reduction Technology," prepared by PEDCo in
support of OAQPS work on NSPS for industrial boilers, June 29,
1978, as revised August 3, 1978. And revisions by Pratapas, J.
Ma., EPA/EAB, letter to J. D. Mobley, EPA/IERL-RTP, September 26,
1978.
4-3. "Standards Support and Environmental Impact Statement Volume 1:
Proposed Standards of Performance for Stationary Gas Turbines,"
EPA-450/2-77-017a, NTIS-PB 272 422/7BE, September 1977.
4-4. Wong-Woo, H, and A. Goodley, "Observation of Flue Gas
Desulfurization and Denitrification in Japan", Report SS-78-004,
California Air Resources Board, March 1978.
4-5. Varga, G. M., Exxon Research and Engineering Co., Linden, New
Jersey, Telecommunication with H. Lips, December 19, 1978.
4-6. Krippene, B. C., "Conventional NOX Reduction Techniques for Oil
and Gas-fired Boilers," presented at the NOX Control Technology
Workshop sponsored by Southern California Edison Company, Electric
Power Research Institute, South Coast (California) Air Quality
Management District, and Ventura County (California) Air Pollution
Control District, Asilomar, California, October 26-28, 1977.
4-7. Coffin, B. D., "Estimate the Cost of Your Next Coal-Fired
Industrial Boiler Plant", Power Magazine. Volume 121, No. 10, pp.
28-29, October 1977.
4-8. Hunter, S. C., and H. J. Buening, "Field Testing: Application of
Combustion Modifications to Control Pollutant Emissions from
Industrial Boilers - Phase I and II (Data Supplement),"
EPA-600/2-77-122, NTIS-PB 270 112/AS, June 1977.
4-9. Heap, M. P., et al., "Reduction of Nitrogen Oxide Emissions from
Field Operating Package Boilers, Phase III," EPA-600/2-77-025,
NTIS-PB 269 277, January 1977.
4-10. Schwieger, "Industrial Boilers - What's Happening Today," Power
Magazine. Volume. 121, No. 2 pp. S.1-S.24, February 1977 and Volume
122\ No. 2 pp. 2.1-S.24, February 1978.
4-11. Gregar, D., Babcock & Wilcox Co., San Francisco, Telecommunication
with H. Lips, Acurex Corp., August 16, 1978.
4-56
-------
4-12. Pater, E., Combustion Engineering, San Francisco, Telecommunication
with H. Lips, Acurex Corp., August 16, 1978.
4-13. Coles, W. F., and J. T. Stewart," Considerations When Converting
Industrial Plants to Coal Firing," ASME 77-IPC-FA-l, 1977.
4-14. Schreiber, R. J. and Evans, R. M., "Survey of Methods of Measuring
NOX from Stationary Sources", Acurex Report TM-78-216 to Energy
and Environmental Analysis, Inc., Arlington, Va., May 1978.
4-15. Giammar, R. D. and R. B. Engdahl, "Technical, Economic and
Environmental Aspects of Industrial Stoker - Fired Boilers," APCA
Paper No. 78-28.2, presented at 71st Annual Meeting of the Air
Pollution Control Association, Houston, Texas, June 25-30, 1978.
4-16. Goodnight, H., John Zink Co., Oklahoma, Telecommunication with R.
Merrill, Acurex Corp., July 10, 1978.
4-17. Lindahl, G., Lindahl Engineering, San Francisco, Telecommunication
with H. Lips, Acurex Corp., August 16, 1978.
4-18. Morton, B., E. Keeler Co., Williamsport, PA, Telecommunication with
H. Lips, Acurex Corp., August 8, 1978.
4-19. Shiu, E., R. F. Mac Donald Co., Foster City, California,
Telecommunication with H. Lips, Acurex Corp., August 16, 1978.
4-20. Cato, G. A., et al., "Reference Guideline for Industrial Boiler
Manufacturers to Control Pollution with Combustion Modification,"
EPA-600/8-77-003b, NTIS-PB 276 715/OBE, November 1977.
4-21 Pratapas, J. M., EPA/SASD, RTP, NC, Letter to J. D. Mobley,
EPA/UIPD, RTP, NC, "Industrial Boiler NSPS ~ Economic Basis for
Technical Assessment (Chapter 3.0)," September 26, 1978.
4-57
-------
SECTION 5
ENERGY IMPACT
This section discusses the energy impact of combustion modification
techniques for controlling NO emissions from industrial boilers. The
A
amount and type of energy required to operate each of the candidate
emission control systems of Section III are identified. Where possible,
these values are compared to the quantities and types of energy required
by a typical facility, without any NO emission control system and one
A
controlled to comply with average state regulations. These State
Implementation Plan (SIP) regulations have been discussed elsewhere
(Reference 5-1) and are summarized in Table 5-1.
TABLE 5-1. AVERAGE STATE IMPLEMENTATION PLAN REQUIREMENTS (REFERENCE 5-1)
Fuel
Level of Control, ng N02/J (lb/106Btu)
Coal
Oil
Gas
301 (0.7)
129 (0.3)
86 (0.2)
5.1 INTRODUCTION
The largest potential energy impact of combustion modification
NO control techniques is their effect upon boiler thermal efficiency.
A
Another significant source of energy impact is the change in fan power
caused by these control techniques. Boiler control systems installed for
low NO operation also increase electricity and instrument air
/\
requirements, but the energy impact is usually minimal.
5-1
-------
The changes in boiler efficiency discussed here are from actual
tests on industrial size boilers as well as engineering estimates. These
estimates were arrived at by extrapolating or interpolating results from
tested boilers. Even for the boiler sizes where there were actual
efficiency measurements, the scatter in the data still required that
engineering judgment be used to estimate a typical value. Because only a
few tests of short duration have been made, any long term effects have not
been determined. Also, industrial boilers operate under fluctuating loads
and small changes in boiler performance are not readily observable.
Because an industrial boiler operates with little attention and loads
fluctuate, fine tuning of the boiler is limited. This restricts operation
efficiency and limits the effectiveness of NO control methods.
/\
The following paragraphs present general comments on the energy
impacts of candidate NO control systems:
/\
0 Low excess air (LEA);
t Staged combustion air (SCA)
-- Overfire air (OFA)
— Sidefire air (SFA);
t Flue gas recirculation (FGR);
• Reduced air preheat (RAP);
t Low NO burners (LNB);
A
• Ammonia injection.
Sections 5.2, 5.3, and 5.4 further discuss the energy impacts on coal-,
oil-, and gas-fired industrial boilers, respectively.
Operating a boiler under low excess air conditions decreases the
total air flow through the boiler, and hence the sensible heat loss out
the stack is minimized, increasing boiler thermal efficiency. When LEA is
used alone, a smaller force draft fan could save additional energy,
although this would only be a small savings. Low excess air operation
would probably require an oxygen trim system, but that would consume only
a minimal amount of energy. Thus, there is a large net gain in energy
with low excess air operation.
Staged combustion via overfire air (OFA) or sidefire air (SFA)
operation can increase the combustion air pressure drop because of
additional duct work. Also, air flow would be increased if the amount of
overfire air is greater than the reduction of air through the flame.
5-2
-------
Therefore additional forced draft fan power is usually required with
staged combustion. From utility boiler experience, energy losses of 0.1
percent of boiler heat input capacity are the maximum expected due to the
larger forced draft fan (Reference 5-2). The effect on thermal efficiency
depends on air port location and the amount of total air used with OFA or
SFA operation. The air port must be located so that proper mixing of the
unburned fuel and air can be achieved, maintaining combustion efficiency.
If the amount of air through the OFA or SFA ports is no more than the
decreased air through the flame, thermal efficiency, in theory, should not
be hurt.
Flue gas recirculation (FGR) also requires more fan power. This
increased fan power requirement is expected to be of the order of 0.25
percent of boiler heat input capacity, based on utility boiler experience
(Reference 5-2). The 0.25 percent factor for industrial boilers is
slightly higher than that for utility boilers, because of the former's
proportionately more constrictive recirculation duct work. Flue gas
recirculation may have a small effect on boiler thermal efficiency because
FGR causes lower furnace temperatures which may decrease the amount of
heat transferred to the water and steam.
Reduced air preheat (RAP) operation will usually lower the boiler's
efficiency. Unless the boiler has an economizer with extra capacity, RAP
operation will raise the flue gas temperature causing a greater loss of
sensible heat from the boiler.
Low NO burners for industrial boilers are still in the
A
development stage. Some low NO burners increase the pressure drop
A
across the burner (References 5-3 through 5-6) and could require more fan
power. In principle, low NO burners should not affect boiler thermal
A
efficiency. A number will be given for energy use by LNB but that number
is a very rough estimate.
Ammonia injection is another control technique under development.
The process requires energy for the injectors and NH., handling
equipment. There is also a slight energy loss due to the carrier gas.
All the comments given here are for typical boilers controlled to
meet representative NO emission levels. The actual energy impact
A
depends on the particular boiler and quantity of control used. Because of
this, the uncertainty in the energy impact listed in the following tables
5-3
-------
is at least +50 percent. Also as already mentioned, the following
discussions are based on very limited data. First, energy impacts for
coal-fired units are discussed, then oil-fired and gas-fired boilers. The
control methods and control levels were described in Section 3.
5.2 ENERGY IMPACT OF CONTROLS FOR COAL-FIRED BOILERS
Most coal-fired industrial boilers are either stoker-fired or
pulverized coal-fired. Only the larger sized industrial boilers are
pulverized coal-fired; the stoker size range covers all industrial
boilers. The discussion that follows on pulverized coal units relies
heavily on utility boiler experience (Reference 5-2). Most of the data on
stokers were collected by KVB, Battelle, and Acurex under EPA sponsored
programs (References 5-7 through 5-13). All comments are based on these
references unless otherwise stated. Whenever possible, LEA should be
combined witti other control methods to reduce any energy increase. Table
5-2 summarizes the energy impact on coal-fired boilers.
5.2.1 New Facilities
The two main methods of firing pulverized coal are tangential and
single wall-fired units. Based on the limited number of tests, these two
firing types give about the same emission levels and are thus treated
together, as discussed in Section 3. Without any controls, the average
pulverized coal-fired units can meet State Implementation Plan (SIP)
levels of 301 ng/J and moderate control levels of 301 ng/J. For a
pulverized coal unit to meet intermediate control levels (258 ng/J), LEA
was recommended since it may decrease coal consumption by 0.5 percent.
Soot could increase slightly, requiring a little more use of soot blowers,
but this would be a minimal effect. To meet stringent control levels,
staged combustion with OFA, may be required. This can result in a small
additional fan power requirement of 0.1 percent and a small drop in
thermal efficiency of 0.25 percent. Low NO burners (LNB) or ammonia
A
injection may also be used to reach stringent control levels. The energy
consumption i. unknown for both methods and with LEA operation, consumption
might even decrease. Some types of low NO burners (References 5-3,
A
5-4, 5-5, and 5-6) could require more fan power which would increase
energy use. For ammonia injection, energy requirements for the injectors
and NH3 handling equipment would be minimal but the air compressor for
5-4
-------
TABLE 5-2. ENERGY CONSUMPTION DUE TO NOX CONTROL TECHNIQUES FOR COAL-FIRED BOILERS
System
Standard Boiler
Type
Pulverized Coal
Pulverized Coal
Heat Input
MW (106 etu/hr)
59 (200)
117 (400)
Type and Level
of Control3
No Control Device
SIP
Moderate
Low Excess Air
Intermediate
Overfire Air
Stringent
Low NOX Burners
Stringent
Ammonia Injection
Stringent
No Control Device
SIP
Moderate
.Low Excess Air
Intermediate
Control
Effectiveness
Percent
—
10
25
25
25
~
10
Energy Types
—
Coal
Electric
or Steam
Coal
Electric
Coal
Electric
—
Coal
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
—
- 0.3 (- 1.0)
0.06 (0.2) )
[ d
0.15 (0.5) )
0.15 (0.5)
0.3 (1.0)
__
0.6
Percent Increase*5
in Energy Use Over
Uncontrolled Boiler
—
- 0.5
0.10 )
} d
0.25 j
0.25
0.5
__
- 0.5
Percent Change0
in Energy Use Over
SIP Controlled Boiler
--
- 0.5
0.10 )
J d
0.25 j
0.25
0.5
--
- 0.5
01
I
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-J- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-f- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
dAdd figures for total energy consumption of control device Continued
eNumber is rough estimate
fLow excess air operation could lower energy impact
T-1439
-------
TABLE 5-2. Continued
System
Standard Boiler
Type
Pulverized Coal
(continued)
Spreader Stoker
Heat Input
MW (106 Btu/hr)
117 (400)
44 (150)
Type and Level
of Control a
Over fire Air
Str i ngent
Low NOX Burners
Str i ngent
Ammonia Injection
Stringent
No Control Device
SIP
Moderate
Low Excess Air
Intermediate
Low Excess Air and
Over fire Air
Stringent
Control
Effectiveness
Percent
25
25
25
—
5
20
Energy Types
Electric
or Steam
Coal
Electric
Coal
Electric
~
Coal
Electric
Coal
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
0.1 (0.4) )
d
0.3 (1.0) )
0.3 (l.O)e.f
0.6 (2.0)e,f
—
- 0.1 (- 0.4)
None expectedf
Percent Increase^
in Energy Use Over
Uncontrolled Boiler
0.10
d
0.25
0.25
0.5
--
- 0.25
—
Percent Changec
in Energy Use Over
SIP Controlled Boiler
0.10
d
0.25
0.25
0.5
;;
- 0.25
--
(Jl
^Control levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-:- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control ^device, MW) -i- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
dAdd figures for total energy consumption of control device
eNumber is rough estimate
fLow excess air operation could lower energy impact Continued
T-1439
-------
TABLE 5-2. Concluded
System
Standard Boiler
Type
Spreader Stoker
Chain Grate
Stoker
Underfeed
Stoker
Heat Input
MW (K)6 Btu/hr)
25 (85)
22 (75)
9 (30)
Type and Level
of Control3
No Control Device
SIP
Low Excess Air and
Over fire Air
Moderate
Ammonia Injection
Intermediate
Stringent
No Control Device
SIP
Intermediate
Low Excess Air
Stringent
No Control Device
SIP
Intermediate
Low Excess Air
Stringent
Control
Effectiveness
Percent
..
20
35
55
—
8
::
15
Energy Types
Electric
Coal
Electric
Coal
—
Coal
—
Coal
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
None expected^
0.1 (0.4)f
—
- 0.11 (-0.4)
::
- 0.04 (- 0.15)
Percent Increase^
in Energy Use Over
Uncontrolled Boiler
__.
—
0.5
--
-0.5
—
- 0.5
Percent Changec
in Energy Use Over
SIP Controlled Boiler
..
--
0.5
--
-0.5
--
- 0.5
en
i
-vl
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
D(Energy consumed by control device, MW)-r- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-f- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
^Add figures for total energy consumption of control device
eNumber is rough estimate
^Low excess air operation could lower energy impact
T-1439
-------
the carrier gas could increase energy use by at least 0.25 percent
(Reference 5-19).
Spreader stokers larger than 29 MW heat input require no controls
to meet SIP or moderate control levels (301 ng/J). Only LEA operation is
needed to meet intermediate levels of 258 ng/J, which could reduce coal
consumption by 0.25 percent. Using even lower excess air than is required
to meet the standard could lower fuel consumption even more. However,
operational limitations may prevent such low excess air levels (see
Section 3). Staged combustion air could be used to meet stringent control
levels (215 ng/J). There is only a small fan power increase since stokers
normally use some OFA as a smoke control method (baseline). Also thermal
efficiency does not change; it could even increase by combining LEA with
OFA. No controls are needed to meet SIP levels for spreader stokers less
than 29 MW. But staged combustion is needed to meet moderate control
levels (215 ng/J). Staged combustion would have the analogous energy
impact on the smaller stokers as on the larger units. Ammonia injection
is recommended to reach either intermediate (172 ng/J) or stringent (129
ng/J) control levels. This process has the same energy impact as for
pulverized coal units.
Only two chain grate stoker tests have been reported, and based on
that limited data, LEA control may be able to achieve the stringent
control level (129 ng/J) with an energy savings of about 0.5 percent. The
underfeed stokers tested needed no controls to meet SIP or intermediate
control levels (172 ng/J). To reach stringent control levels, LEA
operation is recommended, which could give an energy savings of at least
0.5 percent.
5.2.2 Modified and Reconstructed Facilities
Existing units with retrofitted NO controls should have about
J\
the same energy impact as new units. Because of the windbox design,
retrofitted OFA ports might have larger pressure drops and require more
fan power. T, e efficiency for pulverized units using OFA ports, depends
on location. Since it might not be possible to put the air ports in the
optimal spot on a retrofitted boiler, efficiency might be lowered. Also,
a new boiler might be designed to operate under a lower excess air level
than an existing one. Thus the energy impacts on an existing unit may be
greater than those on a new unit. Since the actual energy impact will
5-8
-------
depend on the particular boiler being modified, the expected energy impact
can not be quantified at this time.
5.3 ENERGY IMPACT OF CONTROLS FOR OIL-FIRED BOILERS
This discussion of the energy impact of combustion modifications
for controlling NO emissions from oil-fired boilers is based on tests
A
conducted by KVB and Ultrasystems (References 5-7, 5-8, 5-9, 5-14, 5-15,
5-17). As mentioned previously, these tests were all short term and the
condition of the boiler was not always documented. Also the additional
electricity and instrument air required to operate under low NO
A
conditions are minimal, and these topics are not covered. Residual and
distillate oil-fired boilers are discussed. The energy impacts on
residual oil-fired boilers and distillate oil-fired boilers are summarized
in Tables 5-3 and 5-4. Whenever possible, LEA operation should be used to
increase boiler thermal efficiency and hence reduce energy consumption.
5.3.1 New Units
Firetube boilers firing residual oil need no controls to meet SIP
or moderate control levels (129 ng/J). Low excess air operation can be
used to achieve intermediate control levels, resulting in an oil savings
of about 0.5 percent. Low NO burners or staged combustion is
A
recommended to reach the next control level, stringent (86 ng/J). Low
NO burner might require more fan power but since LNB is still in the
/\
development stage, their effect on fan power requirement is unknown.
Their effect on thermal efficiency is expected to be minimal. The thermal
efficiency in staged combustion depends on both the air port location and
the fuel being fired. Efficiency will not be affected if the air port is
in the proper location for the fuel being fired. Since this will not
always be the case, an efficiency loss of 0.5 percent is assumed. Also
additional fan power equal to about 0.10 percent of boiler heat input,
could be needed.
Low excess air operation is needed to reach SIP or moderate control
levels (129 ng/J) for watertube boilers tiring residual oil. This control
technique could result in a fuel savings of 1 percent. To achieve an
intermediate control level, staged combustion can be used. Efficiency can
increase or decrease depending on type of fuel used and air port
location. Thermal efficiency could be decreased by 0.5 percent, and fan
requirements could be increased. Low NO burners or ammonia injection
A
5-9
-------
TABLE 5-3. ENERGY CONSUMPTION FOR NOX CONTROL TECHNIQUES FOR RESIDUAL OIL-FIRED BOILERS
System
Standard Boiler
Type
Firetube
Water-tube
Heat Input
MW (10* Btu/hr)
4.4 (15)
8.8 (30)
Type and Level
of Control 8
No Control Device
SIP
Moderate
Low Excess Air
Intermediate
Low Excess Air and
Overfire Air
Str i ngent
Low NOX Burners
Str 1 ngeni
Low Excess Air
SIP
Moderate
Low Excess Air and
Overfire or Side-
fire Air
Intermediate
Control
Effectiveness
Percent
—
5
25
25
20
20
35
Energy Types
~
Oil
Oil,
Electric
Oil, Electric
Oil
Oil
Electric
or Steam
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
—
-0.02 (-0.075)
0.02 (0.07) )„
0.004 (0.015H
0.01 (0.04)
-0.1 (-0.3)
0.04 (0.15) ) d
0.01 (0.03) |
Percent Increaseb
in Energy Use Over
Uncontrolled Boiler
—
-0.5
0-5 ld
0.1(
0.25
-1.0
o.s)d
O.l}
Percent Change0
in Energy Use Over
SIP Controlled Boiler
--
!
-0.5
0.5 L
0.1 }
0.25
—
i.sL
0.1 (
en
i
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
^(Energy consumed by control device, MW) -r- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MWj-f- (Standard boiler heat input, MW + energy consumed
by SIJ" control device, MH) X 100
dAdd figures for total energy consumption of control device
^Number is rough estimate
fLow excess air operation could lower energy impact
T-1440
Continued
-------
TABLE 5-3. Concluded
System
Standard Boiler
Type
Watertube
(continued)
Heat Input
MW (106 Btu/hr)
8.8 (30)
Type and Level
of Control3
Low NOX Burners
Stringent
Ammonia Injection
Str i ngent
Wate<"tui)9 44 '153' : Low Excess Air
: SIP
: _ow Lxcr ,i Air and
Ove^f^*'-! ir Side-
Intermediate
Low NOX Burners
Stringent
Ammonia Injection
Stringent
Control
Effectiveness
Percent
45
45
20
20
35
45
45
Energy Types
Oil, Electric
Oil, Electric
Oil
Oil
Electric
or Steam
Oil, Electric
Oil, Electric
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
0.02 (0.08)e, f
0.04 (0.15)f
-0.« (-1.5)
0.04 (0.15) ( d
0.01 (0.03) |
0.1 (0.4)e,f
0.2 (0.8)f
Percent Increase*3
in Energy Use Over
Uncontrolled Boiler
0.25
0.5
-1.0
0.5 |d
0.1 }
0.25
0.5
Percent Change0
in Energy Use Over
SIP Controlled Boiler
1.25
1.5
--
i
M}'
1.25
1.5
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-r- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-r- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
dAdd figures for total energy consumption of control device
eNumber is rough estimate
excess air operation could lower energy impact
T-1440
-------
TABLE 5-4. ENERGY CONSUMPTION DUE TO N0y CONTROL TECHNIQUES FOR DISTILLATE OIL-FIRED BOILERS
System
Standard Boiler
Type
Firetubp
i
Watertube
Without
Air Preheater
Heat Input
MW (106 Btu/hr)
4.4 (15)
29 (100)
Type and Level
of Control8
No Control Device
SIP
Moderate
Low Excess Air
Intermediate
Flue Gas
Recirculation
Stringent
Low NOX Burners
Stringent
No Control Device
SIP
Intermediate
Flue Gas
Recirculation
Stringent
Control
Effectiveness
Percent
10
40
40
._
15
Energy Types
Oil
Oil
Electric
Oil, Electric
__
Oil
Electric or
Steam
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
-0.2 (-0.075)
0.02 (0.075) ) d
0.011 (0.04) |
None expectede.f
~
0.14 (0.5) L
0.07 (0.25) j
Percent Increase*3
in Energy Use Over
Uncontrolled Boiler
-0.5
0.50 I d
0.25J
--
0.5 L
0.25J
Percent Change^
in Energy Use Over
SIP Controlled Boiler
-0.5
0.5 |d
0.25 j
--
0.5 \ d
0.25 J
01
I
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW) -r- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MM - Energy consumed by SIP control device, MW)-r-(Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
dAdd figures for total energy consumption of control device
eNumber is rough estimate
flow excess air operation could lower energy impact Continued
T-1441
-------
TABLE 5-4. Continued
System
Standard Boiler
Type
Watertube
Without
Air Preheater
(continued)
Watertube
With Air
Preheater
Heat Input
MW (K)6 Btu/hr)
29 (100)
29 (100)
Type and Level
of Control3
Low NOX Burners
Stringent
Low Excess Air and
Over fire or Side-
fire Air
Stringent
No Control Device
SIP
Low Excess Air
Moderate
Reduced Air Preheat
Intermediate
Flue Gas
Recirculation
Intermediate
Low NOX Burners
Intermediate
Control
Effectiveness
Percent
15
15
5
30
30
30
Energy Types
Electric, Oil
Oil
Electric or
Steam
Oil
Oil
Oil
Electric
or Steam
Electric, Oil
Energy Consumption
Energy Consumed
by Control Device
MW (100 Btu/hr)
None expectede»f
0.14 (0.5)1 d
0.03 (0.1) {
-0.07 (-0.25)
0.44 (1.5)f
0.14 (0.5)
0.07 (0.25)
0.07 (0.25)e, f
Percent Increaseb
in Energy Use Over
Uncontrolled Boiler
0.5 } d
0.1 j
-0.25
1.5
0.5 ) d
0.25)(
0.25
Percent Changec
in Energy Use Over
SIP Controlled Boiler
0-5 ld
0.1 j
-0.25
1.5
0.5 I d
0.25 j
0.25
en
i
^Control levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-f-(Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-f- (Standard boiler heat input, MW + energy consumed
by SlPcontrol device, MW) X 100
dAdd figures for total energy consumption of control device
eNumber is rough estimate
flow excess air operation could lower energy impact
Continued
T-1441
-------
TABLE 5-4. Continued
System
Standard Boiler
Type
Watertube W^th
Air Preheate^
(continue^
Watertube
With Air
Preheater
Heat Input
MW (106 Btu/hr)
29 (100)
44 (150)
Type and Level
of Controls
Low Excess Air and
Overfire or Side-
fire Air
Intermediate
Reduced Air Pre-
heat and Flue Gas
Recirculation
Stringent
Reduced Air Pre-
heat and Low
NO* Burners
Stringent
No Control Device
SIP
Low Excess Air
Moderate
Reduced Air Preheat
Intermediate
Control
Effectiveness
Percent
30
55
55
5
30
Energy Types
Oil
Electric
or Steam
Oil
Electric
Oil
Steam
or Electric
Oil
Oil
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
0.14 (0.5)1 d
0.03 (0.1) J
0.6 (2.0) \ d
0.07 (0.25))
0.44 (1.5)f
0.07 (0.25)e
-0.1 (-0.4)
0.7 (2.2)f
Percent Increase''
in Energy Use Over
Uncontrolled Boiler
0.5 \ d
O.l}
2.0 \ d
0.25 j
1.5
0.25
-0.25
1.5
Percent Change0
in Energy Use Over
SIP Controlled Boiler
0.5 I d
0.1 j
2.0 j d
0.25J
1.5
0.25
-0.25
1.5
aControl levels modercte, '"te^-ned-'ate, and s^.r'.ngent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW) -=- (Standard boiler heat input, MW) X 100
c(£nergy consumed by control device, MW - Energy consumed by SIP control device, MW) -f- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
<*Add figures for total energy consumption of control device
eNumber is rough estimate
excess air operation could lower energy impact Continued
T-1439
-------
TABLE 5-4. Concluded
System
Standard Boiler
Type
Watertube
Heat Input
MW (100 Btu/hr)
44 fV5G)
with
Type and Level
of Control*
Flue Gas
Secirculation
Air Preheater ', Intermediate
(continued) ;
•
Low NOX Burners
Intermediate
Low Excess Air and
Overfire or Side-
fire Air
Intermediate
Reduced Air Pre-
heat and Flue Gas
Recirculation
Stringent
Reduced Air Pre-
heat and Low
N0y Burners
Strinqent
Control
Effectiveness
Percent
30
30
30
55
55
Energy Types
Oil
Electric
or Steam
Electric, Oil
Oil
Electric
or Steam
Oil
Electric
Oil
Steam
or Electric
Energy Consumption
Energy Consumed
by Control Device
MW (10« Btu/hr)
0.22 (0.75)
0.1 (0.4)
0.1 (0.4)e, f
\
0.22 (0.75) I d
0.04 (0.15) j
\
0.9 (3.0) 1 d
0.1 (0.4) J
0.44 (1.5)f
0.1 (0.4)6
Percent Increase13
in Energy Use Over
Uncontrolled Boiler
\
0-5 { d
0.25)(d
/
0.25
\
0.5 Jd
0.1 /
\
2-0 ( d
0.25 j
1.5
0.25
Percent Change0
in Energy Use Over
SIP Controlled Boiler
\
0.5 { d
0.25(
)
0.25
I
0.5 ) d
0.1 |
j
!
2.0 j d
0.25 )
1.5
0.25
tn
i
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-^ (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW) H- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
^Add figures for total energy consumption of control device
eNumber is rough estimate
^Low excess air operation could lower energy impact
T-1439
-------
could be used to reach stringent control levels. Low NO burners will
A
probably only have a small energy impact. Ammonia injection is also only
in the development stage and will probably have a small energy impact of
about 0.5 percent.
Firetube boilers firing distillate oil need no controls to reach
SIP (129 ng/J) or moderate (86 ng/J) control levels. Low excess air
operation can be used to reach intermediate control levels (65 ng/J), with
a fuel savings of about 0.5 percent. Stringent control levels (43 ng/J)
can be reached by using either flue gas recirculation or low NO
burners. Flue gas recirculation tests showed small thermal efficiency
changes in most cases, but some tests did show losses up to 1 percent. A
0.5 percent loss is assumed and an additional fan power requirement of
0.25 percent of boiler heat input could be required.
Watertube boilers equipped with air preheaters tiring distillate
oil emit more NO than those units without preheaters. Economizers can
/v
be used to reclaim sensible heat from the flue gas without increasing
NO emissions, as discussed in Section 3. Thus economizers should be
A
used instead of air preheaters whenever possible. Watertube boilers
without air preheaters need no controls to reach SIP or intermediate
control levels. Flue gas recirculation, low NO burners, or staged
A
combustion can be used to reach stringent control levels. The energy
impacts of F6R, LNB, and staged combustion discussed above apply here also.
Watertube boilers equipped with air preheaters firing distillate
oil need no controls to meet SIP levels. To meet moderate control levels,
LEA could save about 0.25 percent in energy use. Reduced air preheat,
FGR, LNB, or staged combustion could be used to reach intermediate control
levels. Except for reduced air preheat, the energy impact of these
controls have already been described. Reduced air preheat could lower
efficiency by 1.5 percent, which would offset the efficiency gained by
installing the air preheater. To meet stringent control levels, RAP and
FGR or RAP and LNB could be used. Unless LEA or addition of an economizer
is used with these two methods to lower the energy impact, they will use a
large amount of energy. Reduced air preheat and flue gas recirculation
could decrease boiler efficiency by 2 percent and increase fan power use
by 0.25 percent. Reduced air preheat and low NO burners might increase
A
fuel use 1.5 percent and require more fan power. Again, the efficiency
5-16
-------
gained by using the air preheater is lost, showing the advantage of an
economizer instead of an air preheater.
5.3.2 Retrofitted Facilities
Retrofitted units have about the same energy impact as new units.
Since staged combustion technique efficiency depends on air port location,
it might not be possible when retrofitting to put the OFA or SFA ports in
the optimal location. Since low NO burners change the flame shape, it
/\
might not be possible to retrofit these burners. Also, a new boiler could
be designed to operate under a lower excess air level than an existing
unit, especially, since burners have been developed that allow lower
excess air operation (Reference 5-18).
5.4 ENERGY IMPACT OF CONTROLS FOR GAS-FIRED BOILERS
Data for the energy impact of combustion modifications for
controlling NO emissions from natural gas-fired boilers were collected
^
by KVB and Ultrasystems (References 5-7, 5-8, 5-9, and 5-14 through
5-17). Again, these were short term tests and the condition of the boiler
was not always documented. Table 5-5 summarizes the energy impact on
gas-fired industrial boilers. In all cases, LEA operation is recommended
to minimize energy consumption.
5.4.1 New Facilities
A gas-fired firetube boiler should require no controls to meet SIP
(86 ng/0) or stringent (43 ng/J) control levels. Again as in the oil-fired
case, an economizer is recommended and for the same reasons: an
economizer can save energy without increasing NO emissions. Watertube
/\
boilers without air preheaters need no controls to meet SIP or
intermediate (65 ng/J) control levels. To meet stringent control levels,
LEA could be used which would give about a 0.5 percent fuel savings.
For watertube boilers with air preheaters, controls are needed to
meet SIP or moderate control levels. The recommended methods are RAP,
FGR, staged combustion, and LNB. The energy impact of these controls have
already been described. Fuel losses due to these techniques could be
2.0 percent for RAP, 0.5 percent for FGR, 0.5 percent for staged
combustion, and negligible for LNB if they work as planned. It should be
reiterated that low NO burners are in the development stage. The fuel
/\
loss for FGR and staged combustion would be less if the boiler is designed
for and operated mainly on one type of fuel. As explained earlier, the
5-17
-------
TABLE 5-5. ENERGY CONSUMPTION DUE TO NOX CONTROL TECHNIQUES FOR NATURAL GAS-FIRED BOILERS
System
Standard Boiler
Type
\ Firetube
Watertube
Without
Air Preheater
Watertube
With Air
Preheater
Heat Input;
MW (106 Btu/hr)
4.4 (15N
29 (100)
29 (100)
Type and Level
of Control8
No Control Device
SIP
Stringent
No Control Device
SIP
Intermediate
Low Excess Air
Stringent
Reduced Air Preheat
SIP
Moderate
Flue Gas
Recirculation
SIP
Moderate
Low Excess Air and
Overfire or Side-
fire Air
SIP
Moderate
Control
Effectiveness
Percent
—
— ^
5
25
25
25
25
25
25
Energy Types
—
—
Gas
Gas
Gas
Electric
or Steam
Gas
Electric
or Steam
Energy Consumption
Energy Consumed
by Control Device
MM (106 Btu/hr)
—
—
-0.14 (-0.5)
0.6 (2.0)f
0.14 (0.5) ) d,f
0.07 (0.25) J
0.14 (0.5) ) d
0.03 (0.1) j
Percent Increase0
in Energy Use Over
Uncontrolled Boiler
—
—
-0.5
2.0
0-5 \ d
0.25 j
0.5 \ d
0.1 }
Percent Changec
in Energy Use Over
SIP Controlled Boiler
—
—
-0.5
—
—
--
Ol
I
00
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Taole 5-1.
b(Energy consumed by control device, MW) -e- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-f-(Standard boiler heat input, MW + energy consumed
by SIPcontrol device, MW) X 100
d/ldd figures for total energy consumption of control device
eNumber is a rough estimate
fLw excess air operation could lower energy impact
T-1442
-------
TABLE 5-5. Continued
System
Standard Boiler
Type
Water-tube With
Air Preheater
(continued)
Heat Input
MW (106 Btu/hr)
29 (100)
Type and Level
of Control a
Low NO- Burners
SIP
Moderate
Reduced Air Preheat
and Overfire or
Sidefire Air
Intermediate
Reduced Air Preheat
and Flue Gas
Recirculation
Stringent
Reduced Air Preheat
and Low NOX
Burners
Stringent
Reduced Air Preheat
and Ammonia
Injection
Stringent
Control
Effectiveness
Percent
25
25
40
60
60
60
Energy Types
Gas, Electric
Gas
Electric
or Steam
Gas
Electric
Gas
Electric
or Steam
Gas
Electric
Energy Consumption
Energy Consumed
by Control Device
MW (106 Btu/hr)
0.07 (0.25)e,f
!'
d.f
d,f
0.6 (2.0)f
0.07 (0.25)
0.6 (2.0)f
0.14 (0.5)
Percent Increase15
in Energy Use Over
Uncontrolled Boiler
0.25
d
\
2-5 ( d
0.25 J
2.0
0.25
2.0
0.5
Percent Changec
in Energy Use Over
SIP Controlled Boiler
_.
2.0
..
,
2.0 \ d
0.15 j
1.5
1.5
--
CJl
I
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW) -r- (Standard Doiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device; MW) -r- (Standard boiler heat input, MW + energy consumed
by SIP control device, MW) X 100
dAdd figures for total energy consumption of control device
eNumber is a rough estimate
fLow excess air operation could lower energy impact Continued
T-1442
-------
TABLE 5-5. Continued
System
Standard Boiler
Type
Watertube
With Air
Preheater
Heat Input
MW (10& Btu/hr)
44 (150)
Type and Level
of Control*
Reduced Air Preheat
SIP
Moderate
Flue Gas
Recirculation
SIP
Moderate
Low NOX Burners
SIP
Moderate
Reduced Air Preheat
and Overfire or
Sidefire Air
Intermediate
Reduced Air Preheat
and Flue Gas
Recirculation
Stringent
Control
Effectiveness
Percent
30
30
30
30
30
30
45
65
Energy Types
Gas
Gas
Electric
or Steam
Gas, Electric
Gas
Electric
or Steam
Gas
Electric
Energy Consumption
Energy Consumed
by Control Device
MW (10» Btu/hr)
0.9 (3.0)f
0.2 (0.8) \ d,f
0.1 (0.4) j
0.01 (0.4)e,f
0.1 (3.8) L f
0.04 (0.15)J '
1.1 (3.8) \ d f
0.1 (0.4) / '
Percent Increase^
in Energy Use Over
Uncontrolled Boiler
2.0
0.5 1 d
0.25 f
0.25
2.5 ) d
0.1 j
2.5 1 d
0.25 j
Percent Change0
in Energy Use Over
SIP Controlled Boiler
—
--
—
2.0
2.0 \ d
0.15 f
in
I
ro
O
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-:-(Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW) -3- (Standard boiler heat input, MW + energy consumed
by SlPcontrol device, MW) X 100
dAdc, ."igu.es for total energy consumption of control device
CNuuber is a rough estimate
M.PW excess air operation could lower energy Impact
Continued
T-1442
-------
TABLE 5-5. Concluded
System
Standard Boiler
Type
Watertube With
Air Preheater
(continued)
Heat Input
MU (106 Btu/hr)
44 (150)
Type and Level
of Control3
Reduced Air Preheat
and Low NOX
Burners
Stringent
Reduced Air Preheat
and Ammonia
Injection
Stringent
Control
Effectiveness
Percent
65
65
Energy Types
Gas
Electric
or Steam
Gas
Electric
Energy Consumption
Energy Consumed
by Control Device
MM (1()6 Btu/hr)
0.6 (2.0)f
0.1 (0.4)e, f
0.6 (2.0)f
0.2 (0.8)
Percent Increase0
in Energy Use Over
Uncontrolled Boiler
2.0
0.25
2.0
0.5
Percent Change0
in Energy Use Over
SIP Controlled Boiler
1.5
1.5
en
i
ro
aControl levels moderate, intermediate, and stringent are discussed in Section 3. State Implementation Plan (SIP) control levels
are given in Table 5-1.
b(Energy consumed by control device, MW)-r- (Standard boiler heat input, MW) X 100
c(Energy consumed by control device, MW - Energy consumed by SIP control device, MW)-r- (Standard boiler heat input, MW + energy consumed
by SIP control device, MH) X 100
^Add figures for total energy consumption of control device
eNumber is a rough estimate
fLow excess air operation could lower energy impact
T-1442
-------
optimal air port location is fuel dependent and if only one type of fuel
is burned, it would be easier to optimize the location. Air preheaters
give about a 2 percent gain in efficiency, so the boiler is still more
efficient in some cases, even with FGR or SCA operation, than a boiler
with no air preheater. In other works, FGR or SCA may be more efficient
than RAP on a boiler with an air preheater. Also FGR could require
additional fan power equal to 0.25 percent of boiler heat input and staged
combustion 0.1 percent; LNB may also require more fan power. For
intermediate control, RAP plus OFA/SFA could be used. Using these
techniques might increase fuel use by 2.5 percent and fan use by 0.1
percent of boiler heat input over an uncontrolled boiler. The methods
that reach stringent control levels could also be used to achieve
intermediate control levels.
To achieve stringent control levels, RAP plus FGR, RAP plus LNB, or
RAP plus NH3 injection could be used. As already discussed both LNB and
NH, injection are in the development stage and only predicted energy
impacts rather than tested ones can be given. Reduced air preheat and
flue gas recirculation could increase fuel usage by 2.5 percent and fan
power by 0.25 percent of boiler heat input. Reduced air preheat plus LNB
might increase fuel consumption by 2 percent and slightly affect fan power
usage. Reduced air preheat plus ammonia injection could increase fuel
usage by about 2.5 percent.
5.4.2 Retrofitted Facilities
Energy impacts on retrofitted units would be about the same as new
ones. Since the thermal efficiency of staged combustion depends on port
location, it might not be possible to locate the air ports in the optimal
location on a retrofit. For both staged combustion and FGR, the boiler
might not have the proper windbox design to give the least pressure drop.
A new boiler could be designed to operate at a lower excess air level than
an existing one. Because of flame shape changes, it might not be possible
to retrofit the most efficient low NO burner.
5.5 SUMMARY
Of the control methods just described, LEA is the most fuel
efficient. Low excess air should be used with most control methods to
increase efficiency and reduce NO emissions. Staged combustion air
ports can be located so that thermal efficiency is not decreased if they
5-22
-------
are used with LEA and only one type of fuel is burned. For boilers that
burn several fuels, several air ports would be needed and these ports may
not always be in just the right location. Except for increased fan power
use, it might be possible to design boilers so that FGR would not decrease
thermal efficiency significantly. In some tests this was not always the
case. Low NO burners should not decrease thermal efficiency and might
/\
even allow lower excess air operation which could increase thermal
efficiency. Low NO burners are the most promising new technology.
Ignoring NH3 and carrier gas, ammonia injection appears to have only a
minor energy impact though for raw material consumption, operational, and
environmental reasons it might not be desirable. For new distillate oil-
and gas-fired boilers, economizers are recommended over air preheaters as
energy saving devices.
In summary, combustion modification NO controls for new
A
industrial boilers should only have a minor energy inpact. In fact, with
proper boiler design and control implementation, it might even be possible
in some cases to significantly lower NO emissions and use less energy.
5-23
-------
REFERENCES FOR SECTION 5
5-1 Broz, L, Acurex Corporation, C. Sedman, EPA/OAQPS, and J.D. Mobley,
EPA/IERL, letter to Industrial Boiler Contractors, August 29, 1978.
5-2 Lim, K.J., et ajL., "Environmental Assessment of Utility Boiler
Combustion Modification NOX Controls," Acurex Draft Report
TR-78-105, Under EPA Contract No. 68-02-2160, April 1978.
5-3 Unpublished data supplied by N. Kido, Japan National Research
Institute for Pollution and Resources, August 1978.
5-4 Ando, J., et al., "Nitrogen Oxide Abatement Technology in Japan -
1973," EPA^TJ-284, NTIS-PB 222 335, June 1974.
5-5 Ando, J., et al., "NOX Abatement for Stationary Sources in
Japan," EPA-6W7-77-103b, NTIS-PB 276 948/AS, September 1977.
5-6 Goodnight, H. John Zink Co., Oklahoma, Telcommunication with R.
Merrill, Acurex Corp., July 10, 1978.
5-7 Cato, C.A., et aj^, "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers - Phase I," EPA-600/2-74-078a, NTIS-PB 238 920/AS,
October 1974.
5-8 Cato, C.A., et al., "Field Testing: Application of Combustion
Modification to Control Pollutant Emissions from Industrial Boilers
- Phase 2," EPA-600/2-76-086a, NTIS-PB 253 500/AS, April 1976.
5-9 Hunter, S.C., and H.J. Buening, "Field Testing: Application of
Combustion Modifications to Control Pollutant Emissions from
Industrial Boilers - Phases I and II (Data Supplement),"
EPA-600/2-77-122, NTIS-PB 270 112/AS, June 1977.
5-10 Giammar, R.D. and R.B. Engdahl, "Technical, Economic and
Environmental Aspects of Industrial Stoker-Fuel Boilers," APCA
Paper No. 78-28.2, presented at 71st Annual Meeting of the Air
Pollution Control Association, Houston, Texas, June 25-30, 1978.
5-11 Unpublished data supplied by E. B. Higginbotham, Acurex
Corporation, Mountain View, California, September 1978.
5-12 Gabrielson, J. E., e_t jH._, "Field Tests of Industrial Stoker
Coal-fired Boilers for Emissions Control and Efficiency
Improvement-Site A," EPA-600/7-78-136a, NTIS-PB 295 172/AS,
July 1978.
5-13 Maloney, K. L., et al., "Low-sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers, EPA 600/7-78-153a, NTIS-PB 287
937/AS, July 1978.
5-24
-------
5-14 Carter, W.A., et aj_^, "Emissions Reduction on Two Industrial
Boilers with Major Combustion Modifications," EPA 60077-78-099a,
NTIS-PB 283 109, June 1978.
5-15 Cichanowicz, J.E., eit ^1_._, "Pollution Control Techniques for
Package Boilers. Phase I, Hardware Modifications and Alternate
Fuels," Draft Report, EPA Contract 68-02-1498, November 1976.
5-16 Muzio, L.J., ^t ^L_, "Package Boiler Flame Modification for
Reducing Nitric Oxide Emissions - Phase II of III,"
EPA-R2-73-292-B, NTIS-PB 236 752, June 1974.
5-17 Heap, M.P., et al.. "Reduction of Nitrogen Oxide Emissions from
Field Operating Package Boilers, Phase III," EPA-600/2-77-025,
NTIS-PB 269 277, January 1977.
5-18 Schwieger, R., "Industrial Boilers — What's Happening Today,"
Power, Volume 121, No. 2, pp. S.1-S.24, February 1977.
5-19 Castaldini, C., et al. "Technical Assessment of Exxon's Thermal De
NOX Process," Acurex~Final Report 79-301, EPA Contract 68-02-
2611, April 1979.
5-25
-------
SECTION 6
ENVIRONMENTAL IMPACTS OF CANDIDATES FOR BEST EMISSION CONTROL SYSTEMS
Modification of the combustion process for NO control can alter
the emission rates of other pollutants. These changes, referred to as
incremental emissions, could lead to adverse environmental effects.
Therefore, a key consideration of all NO control development programs
A
must be the effects on emission levels of the criteria pollutants: carbon
monoxide (CO), unburned hydrocarbons (UHC), particulate, and sulfur oxides
(SO ), and the S09/S0^ ratio. Also of concern in recent control
X to
development programs are the noncriteria pollutants, trace metals and
organics.
This section presents the expected effect of combustion
modification NO controls on the criteria and noncriteria pollutants.
A
These postulations are further supported by a review of the possible
formation mechanisms for each pollutant. However, data are insufficient
to completely describe the effect of the NO control and the resulting
incremental emissions. The data that are available are presented as a
function of boiler and fuel type.
6.1 IDENTIFICATION OF THE MAJOR ENVIRONMENTAL CONCERNS
The candidate best NO control system for each fuel category was
A
presented in Tables 3-7, 3-8, 3-10, 3-11, and 3-12. Table 6-1 presents
the expected effect each modification will have on incremental emissions.
A review of Table 6-1 shows that:
• Increased CO and vapor phase hydrocarbon emissions are of major
concern only when excess air levels are lowered
• Sulfate emission levels are expected to decrease or remain
unchanged with all controls except staged combustion and
6-1
-------
TABLE 6-1. POSTULATED EFFECT OF COMBUSTION MODIFICATIONS ON INCREMENTAL EMISSIONS
FROM INDUSTRIAL BOILERS.
Combustion
Modification
Low excess air
Staged combustion
Flue gas
reel rail atlon
Reduced air
preheat
AmMOnla
Injection
LOW mx
burners
Resulting Combustion
Conditions
Reduced local 02 concentra-
tion; decreased gas veloci-
ties; Increased furnace
residence time
Reduced local 0? concentra-
tion; reduced peak flame
temperature; Increased con-
vection zone temperature;
delayed flame zone mixing
Reduced local 02 concentra-
tion; reduced peak flame
temperature; reduced furnace
residence time; Increased
gas velocities; more turbu-
lent flame; Increased con-
vectlve zone temperature
Reduced peak flame tempera-
ture; decreased gas veloci-
ties; Increased furnace
residence times; Increased
local 02 concentration
Increased local NH3
concentration
Delayed fuel-air mixing;
off-stoichlometrlc
combustion
CO
Increased
Possibly Increased
Possibly Increased
No effect
No effect
Possibly Increased
Vapor Phase HC
Increased
Possibly Increased
Possibly Increased
No effect
No effect
Possibly Increased
Sulfate
Decreased overall because of
lowered 02 availability
Possibly decreased because of
decreased convection zone
catalysis (less volatile metal
redistribution)
Possibly decreased
Possibly decreased
Possibly Increased through
near plume solution
catalysis
Possibly decreased because
of less potential for SOg
oxidation
Organic s
Possibly Increased
Possibly Increased
Possibly Increased
Possibly Increased
Decreased with
decreased particle
emissions; no
effect otherwise
Possibly Increased
due to greater
carbonaceous
particle formation
CTi
IV)
Continued
-------
TABLE 6-1. (Concluded)
Combustion
Modification
Low excess air
Staged
combustion
Flue gas
reclrculation
Reduced air
preheat
Reduced load
Ammonia
Injection
Low NOX
burners
Participate
Size Distribution
Possible trend to larger
sizes
Possible trend to larger
sizes
Probably no effect
Probably no effect
Probably no effect
Trend to smaller particles
(NH4HS04 aerosol )
Trend to larger particles
Mass Emissions
Possibly decreased because of
increased bottom and ash
fallout and Internal deposi-
tion
Unknown effect: possible
Increase due to soot forma-
tion; possible decrease due
to larger particles and con-
vection zone depositor! and
slagging
Possibly increased due to
Increased velocities and
possibility of soot formation
Possibly increased due to
less bottom slagging
Probably no net effect
Possibly decreased with ESPs
because of conditioning;
Increased otherwise
Possibly increased because
of greater soot formation
Trace Netals
Segregating
Unknown effect: possible in-
crease due to Increased
volatility but possible de-
crease with Internal deposi-
tion
Possibly decreased because of
decreased repartitlonlng to
small particles
Possibly decreased 'f^cause of
decreased repartltioning to
small particles
Possibly reduced because of
less concentration In snail
particles
Possibly reduced because of
less concentration In small
particles
Possibly Increased because
larger fraction of small
particles
Possibly decreased because
of overall trend to larger
particles more easily
controlled
Nonsegregatlng
Possibly reduced because of
reduced mineral particle
emissions and internal
particle deposition
Possibly reduced due to
larger particles (more car-
bon) and convection zone
slagging
Possibly increased with
Increased particle emissions
Possibly increased with
increased particle emissions
Probably no effect
Qecreased with decreased
particle emissions; no
effect otherwise
Possibly decreased because
larger particles more
easily controlled
CTi
I
CO
-------
ammonia injection (which alters the form of SO, to
NH3HS04)
• Changes in emitted particle size distribution are expected only
when operating with low excess air, staged combustion or low
NO burners. In these instances the production of larger
particles is expected.
• Increased particulate mass emissions are of potential concern
when flue gas recirculation, staged combustion, or low NO
A
burners are used
• Condensible organic emissions are likely to increase with all
combustion NO controls except ammonia injection
/\
• Decreased segregating trace metal emissions are possible when
using staged combustion, flue gas recirculation, or ammonia
injection. Segregating species are those that are partitioned
to various particle sizes.
t Nonsegregating trace metal emissions are only of potential
concern when implementing flue gas recirculation and reduced
air preheat
The following subsection discusses the formation mechanism for each
pollutant as a function of the combustion conditions.
Obviously care must be taken when quantifying impacts of NO
controls. A careful balance between reduced NO and increased
A
incremental emissions must be maintained to minimize the total impact on
ambient environmental goals.
6.2 FORMATION MECHANISMS OF MAJOR POLLUTANTS
Since incremental emissions are sensitive to the same combustion
conditions as NO , an understanding of the formation mechanisms of these
A
incremental pollutants will permit a better appreciation of how NO
control conditions affect these combustion generated pollutants. Such
knowledge can aid in the interpretation of the limited field test data
available and provide informed speculation on how NO controls act.
A
Subsection (.2.1 reviews the formation mechanism of the criteria
pollutants: carbon monoxide, unburned hydrocarbons, particulate, and
sulfur oxides. (Nitrogen oxides formation has already been discussed in
Section 2.) Subsection 6.2.2 discusses the formation mechanisms of the
noncriteria pollutants: trace metals and organics.
6-4
-------
6.2.1 Criteria Pollutants -- Fetation /iecn in isms
Carbon Monoxides
The presence of CO in the exhaust gases of combustion systems
results principally from incomplete fuel combustion. Several conditions
can result in incomplete combustion. These include:
• Insufficient oxygen availability
• Poor fuel/air mixing
• Cold wall flame quenching
• Reduced combustion temperature
• Decreased combustion gas residence time
• Load reduction (reduced efficiency)
Since various combustion modifications for NO reduction can produce one
^
or more of the above conditions, the possibility of increased CO emissions
is a concern for environmental, energy and operational reasons. Flue gas
CO emission concentrations in excess of 2000 ppm can severely damage
equipment from explosions in flue gas exit passage.s (Reference 6-1).
Unburned Hydrocarbons
Unburned hydrocarbon emissions can include essentially all vapor
phase organic compounds emitted from a combustion source. These are
primarily emissions of aliphatic, oxygenated, and low molecular weight
aromatic compounds which exist in the vapor phase at flue gas
temperatures. These emissions include all alkanes, alkenes, aldehydes,
carboxylic acids, and substituted benzenes (e.g., benzene, toluene,
xylene, ethyl benzene, etc.) (References 6-2 and 6-3). Condensed phase
organic compounds are presently noncriteria pollutants and are discussed
in Section 6.3. .
Like CO, UHC occur due to incomplete combustion. Therefore, any
combustion modification which reduces the combustion efficiency will most
likely increase the concentrations of vapor phase hydrocarbons. These
pollutants are of environmental concern because of their role in the
atmospheric reactions which lead to photochemical smog (Reference 6-1).
Total Particulate
Gas-fired combustion equipment produces negligible amounts of
particulate matter. The quantity of emissions increases when distillate
oil and residual oil are used and the greatest quantity is emitted when
coal is the primary fuel (Reference 6-4).
6-5
-------
Participate emissions from oil-fired units can be composed of soot
(condensed organic matter) and ash (incombustible mineral matter). Coal
particulate emissions are largely ash, and occasionally contain some
unburned carbonaceous residue (Reference 6-1). The composition of the
particulate generated in the combustor can affect mass emissions. This is
due primarily to the relationship between composition and particle size,
and the particulate control device employed for particle removal. In
addition, some trace element emissions depend on the particle size
distribution. Finally, polycyclic organic matter (POM) emissions from
combustion sources occur largely as solid phase carbonaceous residue.
High particulate emissions, especially from coal-fired boilers, may
increase the possibility of high POM emissions (Reference 6-1). (The
formation mechanisms and emissions of trace elements and POM are discussed
in later sections.)
The formation of particulates in a combustion source is closely
related to combustion aerodynamics, the mechanisms of fuel/air mixing, and
the effects of these factors on combustion gas temperature-time history.
The optimum conditions for reducing particulate formation (intense, high
temperature flames as produced in high turbulence and rapid fuel/air
mixing) are not the conditions for suppressing NO formation.
/\
Therefore, most attempts to design low-NO combustors have been
compromised by the need to limit the formation of particulates
(Reference 6-1).
Particulate emissions are subdivided into expected particle size
distribution and particulate mass emissions. When NO controls are
/\
applied to reduce combustion efficiency, condensible organic matter (soot)
increases. If the combustion modification results in a reducing
atmosphere rather than an oxidizing atmosphere, ash emissions may decrease
due to increased slag formation and internal deposition of ash ("bottom
ash").
Particle size distribution can affect the emissions of trace
metals. Some trace metals segregate to the smaller particle sizes. If
combustion modifications reduce particle sizes, segregating trace metals
emissions will increase. Since small particulate remains suspended for
larger periods of time, it can penetrate the body's respiratory system
more easily, and remain in the lungs for longer periods of time.
6-6
-------
Therefore, greater adverse health effects are possible. The more complete
the combustion, the smaller the particle size distribution. Therefore,
loss of combustion efficiency can result in increased mass emissions from
the boiler and increased particle size (Reference 6-1). Larger particles
are more easily removed by pollution control devices. Boilers equipped
with these devices may reduce mass emissions from the stack when
combustion efficiency is reduced.
Sulfates
Ambient sulfate levels are of increasing concern in regions with
large numbers of combustion sources firing sulfur-bearing coal and oil.
Although the direct health effects of high ambient sulfate levels are
currently unclear (Reference 6-5), high sulfate aerosol concentrations
decrease visibility and aggravate acid precipitation.
Ambient sulfates are generally comprised of directly emitted
sulfates (primary sulfates) and those derived from the atmospheric
oxidation of sulfur dioxide, SOp, (secondary sulfates). Sulfur dioxide
is emitted when sulfur is contained in the fuel. Up to 98 percent of all
sulfur entering the boiler may be discharged as S(L. The primary
concern for incremental emissions, then, is to control the ratio of
primary sulfate to S02 (S04/S02). The sulfate present may exist as
either sulfuric acid (H^SO^) or as metal or ammonium sulfates.
The precise mechanisms for the formation of sulfates are not
completely understood. However, two processes contribute to final flue
gas sulfate levels. The first is homogeneous SCL oxidation in the flame
through the reaction:
S02 + 0 + M = S03 + M (6-1)
where M is a third body molecule. Although S02 is the thermodynamically
favored product at high temperatures, it is currently thought that some
S03 is formed through Equation (6-1). Subsequent rapid gas quenching
then freezes the system into a nonequilibrium state. Any SCL formed
through this reaction will, at reduced temperatures, combine with
available water vapor to form sulfuric acid. This sulfuric acid will then
adsorb onto available particulate matter or, in the absence of sufficient
particulate matter, condense as an acid mist.
6-7
-------
The second important sulfate formation mechanism is catalyzed
heterogeneous SCL oxidation in postcombustion regions by flue gas
particulate and internal boiler deposits. Several potential oxidation
catalysts exist in suspended and deposited flue gas particulate, including
vanadium, nickel, iron, manganese oxides, and carbon (soot).
Based on the above, it is possible to speculate how NO controls
rt
might affect primary sulfate production. Reduced oxygen availability
should definitely decrease primary sulfate emissions. Thus, NO
controls which decrease local oxygen availability should lower sulfate
emission levels. It is difficult to identify the effects of combustor
temperature time history on sulfate production. This is because not much
is known about in situ catalytic mechanisms and their relative importance
to homogeneous SOp oxidation. Since trace metals present in the gas
stream catalytically oxidize S02 to S03> combustion conditions which
facilitate volatilization-condensation and partitioning of these metals,
such as high peak flame temperatures, should promote SOp conversion.
Conversely, combustion controls which lower peak flame temperature should
decrease sulfate production.
6.2.2 Noncriteria Pollutants -- Formation Mechanisms
Organics
Organics are those species not included in the criteria pollutant
class of unburned vapor phase hydrocarbons. The remaining organic
emissions are composed largely of compounds emitted from combustion
sources in a condensed phase. These compounds can almost exclusively be
classed into a group known variously as polycyclic organic matter (POM) or
polynuclear aromatic hydrocarbons (PNA or PAH). The following discussion
treats POM emissions from stationary combustion sources and the effects of
NO controls on these emissions.
^
Although polycyclic organic matter can conceivably be formed in the
combustion of any hydrocarbon fuel, it 1s considered more of a problem
when associated with soot (carbonaceous particulate) emissions from coal-
and oil-fired combustion equipment. Polycyclic organic matter are
especially prevalent in the emissions from coal burning, because a large
fraction of the volatile matter in coal (coal tar) preexists as POM.
Although the formation of POM in flames is complex and variable, it
is possible to form a relatively clear picture of the overall reaction.
6-8
-------
In a reducing atmosphere at temperatures around 2,OOOK (conditions common
in the center of flames), radical species of the form, HC=CH and RCH=CH,
can rapidly combine and form large polynuclear aromatic molecules through
radical chain propagation (References 6-3, 6-6). As combustion gas cools
and chain propagation is quenched, a variety of POM species can remain
when combustion is incomplete. Upon further cooling, these species
condense and are emitted largely as soot or high carbon content
particulate.
POM emissions have significant environmental impact because several
species are highly carcinogenic (Reference 6-3). The fact that they
generally exist as fine particulate makes them an even more serious health
hazard.
It is important to again note that although POM formation is
possible during methane combustion, the formation of these large aromatic
molecules is facilitated by the presence of higher molecular weight
radicals. Thus, POM production is of only minor concern in gas-fired
systems, of some concern in oil-fired systems, and of greatest concern in
coal-fired equipment. Whatever the combustion source, POM emissions
should increase under conditions of poor combustion efficiency. Since
NO combustion controls can lead to inefficient combustion and soot
A
formation if not carefully applied (especially low excess air and staged
combustion), implementation of these controls can lead to increased POM
formation.
A few comments are in order here concerning an extremely toxic
subclass of polynuclear aromatic hydrocarbons, the polychlorinated and
polybrominated biphenyls (PCBs and PBBs). A theoretical assessment of PCB
formation in combustion sources (Reference 6-7) concluded that, although
PCB formation is thermodynamically possible during coal and residual oil
(fuels which contain some chlorine) combustion, it is unlikely due to
short reaction residence times and low chlorine concentrations. If PCBs
are formed, they would be expected to occur under conditions which promote
POM emissions. However, PCBs have never been verified in conventional
combustion source emissions.
Trace Elements
Emissions of trace metals are a concern for combustion sources
firing coal and residual oil. They are a lesser problem in sources firing
6-9
-------
distillate fuels since trace metal concentrations in distillate oils are
generally much lower than those in residual oils. Trace metals from
stationary sources are emitted to the atmosphere with the flue gas either
as a vapor or condensed on particulate. The quantity of any given metal
emitted, in general, depends on:
• Its concentration in the fuel
t The combustion conditions in the boiler
• The type of particulate control device used, and its collection
efficiency as a function of particle size
• The physical and chemical properties of the element itself
It has become widely recognized that some trace metals concentrate
in certain waste particle streams from a boiler (bottom ash, collector
ash, flue gas particulate), while others do not (References 6-8 through
6-14). The most logical explanation for this segregation involves a
volatilization-condensation mechanism (Reference 6-8). Certain metals
have boiling points sufficiently high that they are not volatilized in the
combustion zone. Instead, they form a melt of relatively uniform
concentration, which becomes both bottom ash or slag, and flyash. Thus,
these elements, termed Class I, remain in a condensed phase throughout the
boiler and show little partitioning with particle size. By contrast,
other metals have boiling points below peak combustion temperatures, so
they are volatilized in the combustion zone and do not become incorporated
in the slag. As combustion gases cool by traveling through the boiler,
these elements, termed Class II, either form condensation nuclei or
condense onto other available solid surfaces (predominantly preexisting
Class I ash particles). Since the available surface area to mass ratio
increases as particle size decreases, these elements concentrate in small
particles. Finally, metals such as Mercury (Hg) and to some extent
Selenium (Se), remain vaporized through the stack and are emitted as flue
gas vapor components. These are referred to as Class III metals.
By understanding trace metal partitioning and concentration in fine
particulate, it is possible to postulate the effects of NO combustion
^
controls on incremental trace metal emissions. Several NO controls for
X
boilers reduce peak flame temperatures (staged combustion, flue gas
recirculation, reduced air preheat, load reduction, and water injection).
The volatilization-condensation theory predicts that if the combustion
6-10
-------
temperature is reduced, less Class II metals will initially volatilize,
hence less will be available for subsequent condensation. Under these
conditions (lowered flame temperature), it is expected that less Class II
metal (the segregating trace metals) will be redistributed to small
particulate. Therefore, in boilers with particulate controls, lowered
volatile metal emissions should result due to improved particulate
removal. Flue gas emissions of class I metals (the nonsegregating trace
metals) should remain relatively unchanged.
Lowered local CL concentrations are also expected to affect
segregating metal emissions from boilers with particle controls. Lowered
0« availability decreases the possibility of volatile metal oxidation to
less volatile oxides. Under these conditions Class II metals should
remain in the vapor phase into the cooler sections of the boiler. More
redistribution to small particles should occur and emissions should
increase. Again, class I metals should be unaffected. This behavior is
expected when low excess air is implemented. Other combustion NO
A
controls which decrease local 02 concentrations (Staged Combustion and
flue gas recirculation) also reduce peak flame temperature. For these,
the effect of lowered combustion temperature is expected to predominate.
The effect of NO combustion controls on segregating metal
/\
emissions from combustion sources without particle collection devices
should be marginal at best. Particle redistribution will not affect mass
emissions because all particulate produced is emitted from these sources.
However, since trace metal condensation on internal boiler surfaces
undoubtedly occurs, conditions which decrease the extent of Class II metal
volatilization (lowered peak flame temperature) should cause a slight
decrease in segregating metal emissions. Conversely, conditions which
increase metal volatility (low local 02 concentrations) should cause
slight increases in volatile metal emissions (Reference 6-1).
6.3 ENVIRONMENTAL IMPACTS OF N0¥ CONTROLS FOR COAL-FIRED BOILERS
A
Coal-fired industrial boilers have been grouped into four equipment
categories as follows:
• Field erected, pulverized coal.
• Field erected, stoker, spreader stoker
• Field erected, stoker, chain grate stoker
• Packaged, stoker, underfeed stoker
6-11
-------
The recommended NO control levels for the various fuels for industrial
boilers were presented in Table 3-6. These recommendations, coupled with
the NO control techniques discussed in Section II, provided the data
y\
for Tables 3-7 and 3-8, which showed the best control method to reach a
given standard. However, the incremental impact of each suggested control
must be known before the control is implemented on a widespread basis.
Table 6-2 presents incremental emission data from recently
completed field test programs (References 6-15 and 6-19 through 6-21).
Included in this test series were stoker type industrial boilers, as
presented in Table 6-3. The information from these tables is presented
graphically in Figures 6-1 and 6-2.
All tests used low excess air for NO control except test series
«
H, which included one overfire air test and test N which included one high
excess air test. In nearly all cases, CO emissions increased slightly, as
predicted. Unburned vapor phase hydrocarbon emissions fluctuated between
increases and decreases.
All comparative participate tests show a decrease in particulate
emissions following a particulate control device. Reduced excess air was
expected to increase particle size. This would make the particles easier
to collect in particulate control devices. Since all boilers in the
comparative tests were equipped with dust control devices, it appears that
the predicted effect is correct. Reduced excess air was expected to
increase mass emissions of particulates.
The particle size distribution of the ash emitted from a boiler
will also increase with low excess and overfire air NO control. This
is due to a slight decrease 1n combustion efficiency. Table 6-4 presents
test data collected downstream of a dust collection device during a recent
field test program (Reference 6-16). Though other tests were conducted,
these data were the only comparative test data identified. A clear shift
to larger particle size is noted. These data, coupled with the results
from Figures 6-1 and 6-2, further suggest improved dust removal device
efficiency and reduced particulate mass emissions from the stack.
Data collected during a coal-fired boiler test program (Reference
6-16) are in accordance with the trace metal partitioning theory discussed
in Section 6-3. Figure 6-3 illustrates the partitioning of low-volatility
iron, moderately volatile cobalt, and highly volatile copper.
6-12
-------
TABLE 6-2. INCREMENTAL EMISSIONS FROM PULVERIZED COAL-FIRED INDUSTRIAL BOILERS
(References 6-15 and 6-20)
CO
Boiler
Test
Series
A
B
C
System
Actual/Design
Heat Input Boiler
Nrf (10* Btu/hr) Type
116/145 Watertube
(400)7(500) Single
Wall
133/145 Watertube
(390)/(500) Single
Wall
38/75 Watertube
(129)/(260) Single
Wall
38/75 Watertube
(130)/(260) Single
Wall
53/65 Watertube
(180)/(220) Tangential
53/65 Watertube
(180)/(220) Tangential
NOX Control
(Excess 03, %)
Baseline
(8.6)
Low Excess
Air
(8.1)
Baseline
(7.4)
Low Excess
Air
(6.6)
Baseline
(5.3)
Low Excess
Air
(4.5)
N0x Emissions
ng/J
216
212
563
529
234
222
Incremental
Change,
ng/J
—
-4
—
-34
—
-12
Criteria Emissions3
Incremental
Pollutant ng'/J Change,
ng/J
CO 29
UHC
S03
PART 1140
CO 47 +18
UHC
S03
PART
CO 0
UHC
S03 6
PART 2288
CO 0 0
UHC
S03
PART
CO 0
UHC 4
S03 5
PART 511
CO
UHC 1 -3
S03
PART
aNo data available on noncriteria emissions
Continued
T-1447
-------
TABLE 6-2. Concluded
Boiler
Test
Series
0
E
F
System
Actual /Design
Heat Input Boiler
MM (IQfi Btu/hr) Type
76/93 Watertube
(260)7(320) Tangential
76/93 Watertube
(261)/(320) Tangential
38/67.2 Water-tube
(130)/(230) Single Wall
38/67.2 Watertube
(l30)/(230) Single Wall
32.8/46.7 Watertube
(112)/(160) Single Wall
33.1/46.7 Watertube
(113)/(160) Single Wall
NOX Control
(Excess 02, X)
Baseline
(5.8)
Low Excess
Air
(4.8)
Baseline
(4.5)
Low Excess
Air
(3.4)
Baseline
(5.1)
Low Excess
Air
(3.4)
NO Emissions
ng/J
296
303
201
152
174
136
Incremental
Change.
ng/J
+7
-49
-38
Criteria Emissions9
Incremental
Pollutant ng/J Change,
ng/J
CO 0
UHC 2
S03 9
PART 834
CO 00
UHC 1 -1
S03
PART
CO 11
UHC 90
S03 4.7
PART
CO 12 +1
UHC 5.4 -3.6
S03 2.2 -2.5
PART 2895
CO 23.2
UHC 10
S03 21.7
PART 1194
CO 4.2 +19
UHC 14 +4
S03 0 -21.7
PART 995 -199
aNo data available on noncriteria emissions
T-1447
-------
TABLE 6-3. INCREMENTAL EMISSIONS FROM STOKER COAL-FIRED INDUSTRIAL BOILERS
(References 6-15 and 6-20)
Boiler
Test
Series
G
H
System
Actual/Design
Heat Input Boiler NOX Control
NU (106 Btu/hr) Type (Excess 02. X)
30/62 Water tube Baseline
(103)/(210) Chain (9.5)
Grate
30/62 Watertube Low Excess
(100)/(210) Chain Air
Grate (9.0)
30/62 Watertube Low Excess
(105)/(20) Chain Air
Grate (8.7)
24/36 Watertube Baseline
(81)/(125) Spreader (6.2)
Stoker
24/36 Uatertube Overfire
(81)/(125) Spreader Air
Stoker (6.1)
24/36 Watertube Low Excess
(82)/(120) Spreader Air
Stoker (4.7)
N0x Emissions
ng/J
100
75
77
196
145
142
Incremental
Change,
ng/J
—
-25
-23
—
-51
-54
Criteria Emissions3
Incremental
Pollutant ng/J Change,
ng/J
CO 9
UHC 5
SO.
PART 176
CO 22 +13
UHC 11 +6
S03
PART 161 -15
CO 20 +11
UHC 4 -2
S03
PART
CO 0
UHC
S03 20
PART 1320
CO 18 +18
UHC
S03
PART
CO 8 +8
UHC
S03
PART 847 -473
*No data available on noncriteria emissions
Continued
T-1446
-------
TABLE 6-3. Continued
0>
Boiler
Test
Series
1
J
K
System
Actual /Design
Heat Input Boiler
MM (106 Btu/hr) Type
14/17 Water tube
(48)/(60) Underfeed
Stoker
13/1? Watertube
(44)/(60) Underfeed
Stoker
13/17 Watertube
(45)/{60) Underfeed
Stoker
13/17 Watertube
(45)/(60) Underfeed
Stoker
32/39 Watertube
(109)/(135) Spreader
Stoker
33/39 Watertube
(112)/(135) Spreader
Stoker
12/15 Watertube
(40)/(50) Spreader
Stoker
12/15 Watertube
(40)/{50) Spreader
Stoker
NOX Control
(Excess 02, X)
Baseline
(6.6)
Low Excess
A1r
(4.9)
Baseline
(9.8)
Low Excess
Air
(7.0)
Baseline
(7.0)
Low Excess
Air
(4.9)
Baseline
(8.0)
Low Excess
Air
(5.8)
___—_— __j
NOX Emissions
ng/J
163
115
137
123
226
205
284
202
Incremental
Change,
ng/J
--
-48
"
-14
—
-21
—
-82
Criteria Emissions9
Incremental
Pollutant ng/J Change,
ng/J
CO 0
UHC
SOi 23
PART
CO 0 0
UHC
so3
PART
CO 0
UHC
S03
PART 1647
CO 119 +119
UHC
SO,
PART
CO 10
UHC 5
SOi 15
PART 1587
CO 47 +37
UHC 2 -3
SOi
PART
CO 9
UHC 2
S03 15
PART
CO 7 -2
UHC 4 +2
S03
PART 279 -219
*No data available on noncriteria emissions
Continued
M446
-------
TABLE 6-3. Continued
Boiler
Test
Series
L
M
N
System
Actual/Design
Heat Input Boiler
MM (106 Btu/hr) Type
18/22 Hatertube
(60)/(75) Spreader
Stoker
18/22 Uatertube
(62)/(75) Spreader
Stoker
35/44 Uatertube
(119)/(150) Spreader
Stoker
36/44 Matertube
(120)/(150) Spreader
47/67 Water tube
(160)/(120) Spreader
Stoker
44/67 Watertube
(150)/(230) Spreader
Stoker
42/67 Watertube
(143)7(230) Spreader
Stoker
NOX Control
(Excess O^. X)
Baseline
(7.8)
Low Excess
Air
(5.9)
Baseline
(10.2)
Low Excess
Air
(8.9)
Baseline
(10.8)
Low Excess
Air
(8.9)
High Excess
Air (HEA)
(12.6)
NOX Emissions
ng/J
284
237
338
228
334
220
241
Incremental
Change,
ng/J
--
-47
—
-50
—
-114
-93
Criteria Emissions^
Incremental
Pollutant ng/J Change,
ng/J
CO 34
UHC 2
S03 28
PART 140
CO 22 -12
UHC 4 *2
S03
PART 123 +17
CO 0
UHC
S03 36
PART 1649
CO 0 0
UHC
S03
PART
CO 0
UHC
S03 4
PART 361
CO 0 0
UHC
S03
PART
CO 0 0
UHC
S03 13 +9
PART 317 -44
*No data available on noncriteria emissions
Continued
T-1446
-------
TABLE 6-3. Continued
en
i
oo
Boiler
Test
Series
P
Q
System
Actual/Design
Heat Input Boiler
MM (10* Btu/hr) Type
17.6/29.3 Uatertube
(60)/(100) Spreader
Stoker
17.6/29.3 Uatertube
(60)/(100) Spreader
Stoker
17.6/29.3 Water-tube
(60)/(100) Spreader
Stoker
17.6/29.3 Hater-tube
(60)/(100) Spreader
Stoker
43.2/46.9 Hatertube
(83)/(160) Spreader
Stoker
23.1/46.9 Uatertube
(79)/(160) Spreader
Stoker
31.5/46.9 Uatertube
(107)/(160) Spreader
Stoker
32.2/46.9 Uatertube
(110)7(160) Spreader
^. Stoker
NOX Control
(Excess Op, X)
Baseline
Montana Coal
(10.9)
Low Excess A1r
Montana Coal
(6.5)
Baseline
Illinois Coal
(10.0)
Low Excess
Air
Illinois Coal
(7.8)
Baseline
Montana Coal
(8.6)
Low Excess
Air
Montana Coal
(7.7)
Baseline
Illinois Coal
(8.6)
Low Excess
Air
Illinois Coal
(6.6)
NOX Emissions
ng/J
312
206
289
258
326
183
287
241
Incremental
Change,
ng/J
—
-106
-31
"
-53
-46
Criteria Emissions*
Incremental
Pollutant ng/J Change,
ng/J
CO 205
UHC
SOi 10
PART 447
CO 17 -188
UHC
S03
PART 388
CO 18
UHC
SOj 9
PART 674
CO 0 -18
UHC
S03
PART 455 -219
CO 53
UHC
SOi 14
PART
CO 48 -5
UHC
so3
PART 5803
CO 17
UHC
S03
PART
CO 33 -84
UHC
S03
PART 234
'Cyclone outlet only
Continued
M446
-------
TABLE 6-3. Concluded
vo
Boiler
Test
Series
R
S
System
Actual /Design
Heat Input Boiler
MM (10* Btu/hr) Type
13.4/23.4 Watertube
(45.7/(80) Spreader
Stoker
13.4/23.4 Uatertube
(45.9/(80) Spreader
Stoker
5.0/13.2 Uatertube
(17.0/(45) Vibrating
Grate
Stoker
5.0/13.2 Watertube
(17.0/(45) Vibrating
Grate
Stoker
NOX Control
(Excess 02. X)
Baseline
2/3 Illinois,
1/3 Montana Coal
(9.4)
Low Excess
2/3 Illinois.
1/3 Montana Coal
(8.0)
Baseline
Western Coal
(9.8)
Low Excess
Western Coal
(7.3)
NO Emissions
ng/J
207
239
199
152
Incremental
Change,
ng/J
—
+32
-47
Criteria Emissions*
Incremental
Pollutant ng/J Change,
ng/J
CO 61
UHC
S03 133
PART 1209
CO 33 . -28
UHC
S03 44 -89
PART 987 -222
CO 18
UHC
S03
PART
CO 8 -10
UHC
S03
PART
aNo data available on noncriteria emissions
T-1446
-------
CT>
O
c
IO
«
O Meets no HOX control level
29 MW (100 x IO6 Btu/hr).
6-20
-------
C
o
10
4-1
c
OJ
L.
U
(Note: alphabetic characters
identify boiler test series
in tables 6-2 and 6-3)
O Meets no NOX control level
0 Meets moderate NOX control level
£ Meets inter. NOX control level
0 Meets stringent NOX control level
O CO emissions
& UHC emissions
Q $03 emissions
Q Particulate emissions
-100
-60
-60
-40
-20
+120
- • +100
-• +80
..+60
. . +40
• ' +20
- • -20
- - -40
•• -60
• - -80
+20 +40
OR
OR -89ng
O" -222
J
ig/J
Change in NOX emission rate (ng/J)-
Figure 6-2. Change in incremental emissions from coal-fired
industrial boilers <29 MW (100 x 106 Btu/hr).
6-21
-------
TABLE 6-4. EFFECT OF OVERFIRE AIR NOX CONTROL ON PARTICLE SIZE DISTRIBUTION*
FOR A COAL-FIRED CHAIN GRATE STOKER (Reference 6-16)
Fuel
T>oe
Coal
Coal
turner
Typt
Grate
Grate
Test
Load
GJhr-1
112
103
&
85.5
Impact
^:-.
24.6
23.6
Cyci
15.6
1S.1
Actual 050 of Stage No.b
1
!!•
3.5
3.5
2
!••
2.1
2.1
3
tail
1.4
1.4
4
!*•
0.70
0.71
5
ImB
0.35
0.35
Cyclom
•M
10.39
10.82
Cyclone. Stage and Filter Catch
Stage No.
1
M
1.056
0.200
2
mm
0.780
0.276
3
•d
0.660
0.472
4
mm
0.340
2.10
5
•fl
0.600
3.26
Filter
BM
0.572
1.29
Total
Catch
•M
14.60
18.42
Comaents
Baseline no toot
LOM HOX no somt
ro
ro
•Particle slie distribution determined by use of • irlnk Model *B' cascade lapactor
•050 Identifies the site fraction In microns. ^articulates with an aerodynamic diameter
greater than the O$Q cut point will be captured. Increasing stage number corresponds to
decreasing particle size.
T-1451
-------
I
en
O>
O
(O
*J
c
cu
o
c
o
o
ID
X)
o
100,000
50,000
0
Coal
10
5
0
Furnace
Upstream of
rnllprtnr
In
collPrtnr
Downstream
of colJPrtnr
tt)
o.
200
100
v///.
'777.
Figure 6-3. Partitioning of elements based on effluent location for a
coal-fired industrial boiler (Reference 6-16).
6-23
-------
Test data collected during the same test program (Reference 6-16)
support the trace metal segregation theory as discussed in Section 6.3. As
shown in Figure 6-4, the concentration of the volatile element antimony
increased as the particle size decreased. The concentration of less volatile
manganese remains relatively evenly distributed between particulate fractions.
The data presented above, indicate that NO control techniques which
A
alter the overall boiler temperature profile, or change the particulate mass
emissions or particle size distribution can affect the concentration of trace
metals emitted from the collector.
Tests for polycyclic organic matter (POM) have been conducted (Reference
6-16). The data from a stoker coal-fired boiler (chain grate) is presented In
Table 6-5. The data are incomplete due to the lack of sufficient gas stream
samples for analyses. Though organic species are present, their general trend
as a function of NO control is not known.
A
EPA-sponsored tests of two industrial spreader stokers indicate only a
possible slight increase in organic emissions under low-NO firing conditions
A
(LEA, OFA) as compared to those under baseline conditions (References 6-22 and
6-23).
The above emission data was presented for combustion modifications
only. Low NO burners and ammonia injection, considered to be advanced
A
control methods, are still in the development stages. Actual incremental
emission data are not available.
6.4 ENVIRONMENTAL IMPACTS OF NOY CONTROLS FOR RESIDUAL OIL-FIRED BOILERS
A
Oil-fired industrial boilers fall into two major equipment categories.
These are packaged watertube and firetube boilers. The recommended NO
control levels for industrial boilers firing residual oil fuel are presented in
Table 3-6. The recommended NOX control techniques from Section III are low
excess air, staged combustion, low NO burners and ammonia injection.
A
Table 6-6 presents incremental emission data collected during two recent
test programs (References 6-15 and 6-17). This information is presented
graphically in Figures 6-5 through 6-8.
Figure 6-5 presents all changes in low excess air incremental emission
data as a function of changes in NO emission levels. All low NO control
^* X
conditions that meet any of the recommended control levels results in an
increase in CO emissions. Generally, the more the N0x emissions are reduced,
the higher the CO emission rate. As with coal fired boilers, hydrocarbon
levels remain relatively unchanged.
6-24
-------
o>
•M
Q>
U
O
2000
1000
0.2 0.5 1.0 2.0 5.0
Particulate aerodynamic diameter, um
10
20
— — — — measured at dust collector inlet
at dust collector outlet
Figure 6-4. Trace element concentration in fine particulate
(Reference 6-16).
6-25
-------
TABLE 6-5. EMISSION RATES OF POLYCYCLIC ORGANIC MATTER (POM) FROM A COAL-FIRED CHAIN-GRATE
STOKER BOILER (Reference 6-16)
r>o
Run
No. PON
9 7,12 Dteethylbenz(a) anthracene
10
11
9 Benzo(a)pyrene
10
11
9 3 Methyl chol anthrene
10
11
9 Dibenz(a.n) anthracene
10
11
i
In Coal
9 X
None
dectected
None
detected
None
detected
109 100
245 100
18.8 100
None
detected
None
detected
None
detected
610 100
822 100
673 100
In Hopper
Ash
9 X
None
detected
2.26 --
1.39 --
37 34
92.6 38
651 3462
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
In Stack Gases
Part icul ate
9 X
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Insufficient
sample
Vapor
9 X
None
detected
Trace
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
None
detected
-------
TABLE 6-6. INCREMENTAL EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS
(REFERENCE 6-15)
Boiler
Test
Series
A
B
C
System
Actual/Design
Heat Input
MU (106 Btu/hr)
35/44
(120)/(150)
35/44
(120)/(150)
8.4/20
(27}/(68)
8.1/20
(27)/(68)
18/23
(61)/{79)
19/23
(64)/(79)
Boiler
Type
Uatertube
Watertube
Watertube
Watertube
Uatertube
Watertube
NOX Control
(Excess 0?, X)
Baseline
(5.0)
Low Excess
A1r
(3.1)
Baseline
(5.3)
Low Excess
A1r
(4.9)
Baseline
(3.3)
Low Excess
A1r
(2.7)
NOX Emissions
ng/J
165
138
115
101
148
143
Incremental
Change,
ng/J
..
-27
..
-14
-5
Criteria Emissions"
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
503
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
ng/J
0
7
~
—
0
5
—
—
0
— '
—
140
10
—
—
--
0
2
—
780
70
2
—
— -
Incremental
Change,
ng/J
— „
—
«
—
0
-2
—
--
..
—
-- .
—
+10
—
—
.•
—
+70
0
—
•*
CTv
I
ro
data available on noncriteHa emissions
Continued
T-144g
-------
TABLE 6-6. Continued
Boiler
Test
Series
0
E
Systea
Actual /Design
Heat Input
MM (1()6 Btu/hr)
9.3/12
(32)/(40)
9.3/12
(32)/(40)
10/13
(36)/(45)
11/13
(37)/(45)
10/13
(36)/(45)
10/13
(36)/(45)
Boiler
Type
Matertube
Watertube
Hatertube
Watertube
Watertube
Watertube
NOX Control
(Excess 02. X)
Baseline
(4.3)
Low Excess
Air
(4.0)
Baseline
(3.0)
Low Excess
Air
(1.6)
Overfire
Air
(2.9)
Overfire
Air
(3.0)
NOX Emissions
ng/J
109
98
183
136
97
90
Incremental
Change,
ng/J
— —
-11
„
-47
-86
-93
Criteria Emissions9
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
so3
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
ng/J
0
3
12
62
9
0
—
41
0
0
2
46
41
5
—
—
19
4
—
59
31
0
__
--
Incremental
Change,
ng/J
__
—
—
—
+9
-3
—
-21
..
—
~
+41
+5
—
—
+19
4
—
+13
+31
0
__
~~
I
ro
CD
*No data available on noncriterla emissions
Continued
T-1449
-------
TABLE 6-6. Continued
Boiler
Test
Series
F
System
Actual /Design
Heat Input
MW (106 Btu/hr)
4.1/5.1
(14)/(17)
4.1/5.1
(14)/(17)
4.1/5.1
(14)/(17)
3.9/5.1
(14)/(17)
4.1/5.1
(14)/(17)
4.1/5.1
(14)/(17)
4 1/5 1
(l4)/(i7)
Boiler
Type
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
NOX Control
(Excess 02. *)
Baseline
(3.1)
Low Excess
Air
(0.9)
Over fire
Air
(2.4)
Overfire
Air
(3.25)
Overf i re
Air
(3.1)
Baseline
(2.9)
Low Excess
Air
(2.25)
NOX Emissions
ng/J
95
70
61
102
75
91
77
Incremental
Change,
ng/J
„
-25
-34
+7
-20
__
-14
Criteria Emissions*
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
so3
Part.
CO
UHC
so3
Part.
CO
UHC
S03
Part.
ng/J
0
0
—
13
34
—
—
—
53
1
—
--
0
0
—
—
0
3
—
12
0
0
2
13
48
0
—
— —
Incremental
Change,
ng/J
—
«
--
+34
--
—
—
+53
+1
—
--
0
0
—
—
0
3
—
-2
^^
__
—
—
+48
0
..
--
I
ro
vo
*No data available on noncriteria emissions
Continued
T-1449
-------
TABLE 6-6. Continued
Boiler
Test
Series
F
(Cont.)
G
H
System
Actual/Design
Heat Input
MU (106 Btu/hr)
4.1/5.1
(14)/(17)
4.1/5.1
(14)/(17)
4.0/5.1
(14)/(17)
4.1/5.1
(14)/(17)
4.0/5.1
(14)/(17)
11/13
' (38)/(45)
11/13
(39)/(45)
Boiler
Type
Uatertube
Hatertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
NOX Control
(Excess 02, <}
Overflre
Air
(3.0)
Overflre
Air
(2.9)
Baseline
(3.0)
Low Excess
Air
(1.0)
Overflre
A1r
(3.1)
Baseline
(2.9)
Low Excess
Air
(1.6)
NOX Emissions
ng/J
84
73
122
84
85
146
107
Incremental
Change,
ng/J
-7
-18
„
-38
-37
-39
Criteria Emissions3
Pollutant
CO
UHC
so3
Part.
CO
UHC
S03
Part.
CO
UHC
so3
Part.
CO
UHC
S03
Part.
CO
UHC
so3
Part.
CO
UHC
so3
Part.
CO
UHC
so3
Part.
ng/J
27
13
—
~
10
0
—
--
1
2
4
36
62
4
3
26
8
1
3
32
8
.
22
66
21
10
44
Incremental
Change,
ng/J
+27
+13
—
—
+10
0
—
--
„
..
—
—
+61
+2
-1
-10
+7
-1
-1
-4
__
—
—
+13
-12
-22
I
U>
O
data available on noncrlterla emissions
Continued
T-1449
-------
TABLE 6-6. Concluded
Boiler
Test
Series
H
(Cont.)
I
System
Actual /Design
Heat Input
MW (106 Btu/hr)
11/13
(37)/(45)
5.4/7.3
(18)/(30)
5.4/7.3
(8)/(30)
5.4/7.3
(18)/(30)
5.5/7.3
(19)/(30)
5.5/7.3
(19)/(30)
5.5/7.3
(19)/(30)
5.4/7.3
(19)/(30)
Boiler
Type
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
NOX Control
(Excess 0?, *)
Over fire
Air
(3.0)
Baseline
(9.3)
Low Excess
Air
(7.6)
Low Excess
Air
(5.5)
Low Excess
A1r
(4.5)
Low Excess
Air
(4.3)
Low Excess
Air
(4.2)
Low Excess
Air
(3.6)
NOX Emissions
ng/J
86
184
174
156
127
140
94
113
Incremental
Change,
ng/J
-60
— —
-10
-28
-57
-44
-90
-71
Criteria Emissions*
Pollutant
CO
UHC
so3
Part.
CO
UHC
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
ng/J
10
—
—
—
<10
—
—
<10
—
—
"
aNo data available on noncriteria emissions
T-1449
-------
>575.7 ng/J
"3
O)
to
O
•^
CO
CO
(O
4->
C
i-
u
c
OE
-60
&E
M^HV
-4
°
-20
+100
• +80
-- +60
• • +40
- . +20
+20
+40
+60
-- -20
QCO emissions^
A UHC emissions
Q SOX emissions
O Total -60
particulate emissions
O Meets no NOX control level
0 Meets moderate NOX control level
O Meets intermediate NOX control level
• Meets stringent NOX control level
Change in NO., emissions (nq/J)'
Figure 6-5. Change in incremental emissions with low excess air NOX
control for residual oil-fired watertube industrial boilers
(References 6-15 and 6-17).
6-32
-------
180 -
160 -
140 -
g1 120 -
100
60
40
20
6J 1232.1 ng/J CO
Noderjte control level _».
Intermediate control level
Stringent control level
© NO
180
160
140
120
100 .f
80
60
40
20
4 6 8 10
Excess oxygen (%}
12
Figure 6-6. Changes in CO and NOX emissions with reduced excess
oxygen for a residual oil-fired watertube
industrial boiler (Reference 6-17).
6-33
-------
O
a1
B>
O
-I
O)
I
CO
O
3
10
-^
c_
.
• F
•
fjE •" ^
OE
»E r, ^ FA
AE. . 5vF ^ ft
^ FT ™
-80 -60 -40W _ h -20
d
-20 .
-40 '
(Note: alphabetic characters
Identify boiler test series
in table 6-6)
• +60
+40
- +20
+20
O CO emissions
& UHC emissions
D SOX emissions
O Total participate
emissions
O Meets no NOX control level
(D Meets moderate NOX control level
d Meets intermediate NOX control level
• Meets stringent NO
x control level
Change 1n NOX emissions (ng/J)
Figure 6-7. Change in incremental emissions with overfire air NOX
control for residual oil-fired watertube industrial
boilers (References 6-15 and 6-17).
-------
Q 891.1 ng/J CO
Recomnended control level
Moderate —
Intermediate —
Stringent _»
Break point undefined
it
<
i 220
200
180
160 _
-^
er.
c
140 a
ie
t-
c
120 -2
I/)
1
100 cx
80
60
40
20
6 8 10
Percent excess air
12
Figure 6-8. Change in CO and NOX emissions with decreasing excess
oxygen for a residual oil-fired firetube industrial
boiler (Reference 6-17).
6-35
-------
A trend for sulfate emissions similar to that of coal-fired boilers
is not apparent for residual oil-fired boilers. However, a test from
Series H was conducted with an excess oxygen content of 1.6 percent, and
tests from Series 6 with 1.55 percent and 1.0 percent excess 0? levels.
Though marginally conclusive, the higher 02 level test does have the
highest SO., oxidation level.
Finally, as was true with the coal-fired boilers, Figure 6-5 shows
that particulate emissions for boilers with dust control devices are
•
reduced with low excess air firing. This is most likely due to increased
particle size resulting from reduced combustion completeness, making the
particles easier to catch.
Test data collected on a watertube boiler (Reference 6-17) over a
range of excess oxygen levels is presented in Figure 6-6. This figure
shows the reductions in NO with decreasing excess oxygen levels.
A
Complete combustion occurs until the oxygen level is reduced to
approximately 4.25 percent. The emission rate of CO then climbs sharply.
The data presented in Figure 6-5 show a significantly more scattered
relationship between CO and NO emissions than Figure 6-6 suggests.
/\
However, it is reasonable to conclude that each boiler has simi-lar
emission characteristics, but fuel/air mixing, fuel nitrogen
concentrations, flame temperatures, and many other variables, are
responsible for the data scatter.
The effect of overfire air on NO control is shown in
/\
Figure 6-7. The emission rate of CO is generally increased with
increasing reductions in NO emission rates. The emission rates of UHC
A
remain the same or are increased only slightly.
Overfire air (staged combustion) reduces the excess oxygen
available for reaction in the primary combustion zone of the boiler.
Since less oxygen is available for reaction under these conditions, a
reduction in sulfate emissions in the primary zone could be expected.
Addition of secondary combustion air may quench the reaction, resulting in
reduced overall SO-. Figure 6-7 shows decreases in sulfate emissions on
both tests conducted. (The potential for trace metal catalytic oxidation
will be discussed later in this section.)
Finally, the trend established in Figures 6-1 and 6-5 of reduced
particulate emissions, has one exception, test condition E. The boiler
6-36
-------
located at this test site does not have a dust control device. Since
reduced combustion efficiency results in increased particulate size and
emission rate, this facility would be expected to have increased
particulate emissions without dust control devices. Again, sufficient
data is not available to establish overall particulate removal
efficiencies.
A second series of tests conducted at various excess oxygen
contents was reported in Reference 6-17. These data were collected on a
firetube boiler and illustrate the relationship between NO and CO
A
emission rates as a function of excess oxygen concentrations. As in
Figure 6-6, a distinct increase in CO emissions is noted as excess oxygen
reaches the lower practical operating limit. Unfortunately, this lower
limit is not clearly defined. It is seen that CO emissions drastically
increase before the NO emission rate reaches even the moderate control
XX
level.
A set of size distribution tests were conducted during the field
test series reported in Reference 6-16. It was found that the combustion
of oil fuel produced a larger proportion of particulates having an
aerodynamic diameter less than 3 micrometers than did coal fuel. A
comparison of Table 6-4 for coal and Table 6-7 for residual oil shows this
trend.
Other data collected during various low NO control conditions
/\
were reported in References 6-15 and 6-18. The data are presented in
Figures 6-9 through 6-11. Though test number 132 does not follow the
trend, generally an increase in particle size as excess air levels are
decreased can be seen. The remaining combustion modifications and
combinations of modifications also indicate an increased particle size but
the degree of change is mixed.
A recently completed field test program on an oil-fired industrial
boiler (Reference 6-18) is the only source of organic emission data
identified. The organic species proved very difficult to identify, with
most sample quantities insufficient to allow for analysis.
No polychlorinated biphenyls (PCB) were identified during the oil
tests. The concentration of polycyclic organic matter (POM) contained in
the various sample train fractions is shown in Table 6-8. The most
complete analysis was obtained from the organic absorbent (XAD-2) resin.
6-37
-------
TABLE 6-7. EFFECT OF OVERFIRE AIR NOX CONTROL ON PARTICLE SIZE
DISTRIBUTION* FOR A RESIDUAL OIL-FIRED WATERTUBE BOILER
(Reference 6-16)
Fuel
Type
lo. 6
lo. 6
Burner
Type
Steam
Steam
Test
Load
GJ hr-1
34
34
*>*
ng/J
111
97.6
Impact
ll""!
cm3 s'1
22.6
22.7
Cycl.
i*i
__
--
Actual Djo of Stage No>
1
!•
3.62
3.61
2
V*
2.17
2.17
3
i*
1.45
1.44
4
IOT
0.72
0.72
5
I*"
0.36
0.36
Cyclone
"9
None
None
Cyclone, Stage and Filter Catch
Stage No.
1
"9
2.812
3.112
2
•9
1.616
1.372
3
mq
0.668
0.596
4
•9
0.4S6
0.332
5
•9
0.312
0.196
Filter
•9
2.700
2.344
Total
Catch
mq
8.564
7.952
Comments
Baseline
Low NO,
co
CO
aParticle size distribution determined by use of a Brink model *B' cascade Inpactor
b05Q Identifies the size fraction in micrometers. Pirticulates *1th an aerodynamic diameter
greater than the OJQ cut point Mill be captured. Increasing stage number corresponds to
decreasing particle size.
T-1452
-------
<-*
Ol
n>
o.
Ql -I
3 O
rt) T3
r»- O
O> -J
olOO
c
3
c
— •
o»
as
T3
1
O
T3
-J
O
r-l-
30
I
co
ID
O
&« 3
cr — •
«< O)
w
3
o»
10
0»
3
3
-a
- O>
r>
r»-
^
3.0
Baseline
Low excess
air
_L
o.i
0.3
1.0 3.0 10
Aerodynamic diameter, ym
30
100
Figure 6-9. Effect of low excess air NOX control on particle size distribution
for a residual oil-fired watertube industrial boiler. (Reference 6-15)
-------
30.01
S'o.o
O
u
Ol
4-»
1 5.0
3.0
•
01
13
Q.
i 1.0
0.5
0.3
0.1
Test No.
• 143 (*6, OFA)
O 170 (#6, FGR + OFA)
O 132 (*6, low 02)
^ 159 (#6, FGR)
<3 99 (#6, Baseline)
i i i
I L
I I I I I I I
Location
I I
19
I
O OOOOOOQ O
<— esj m «t ui i«3 r«. 00 3R
co
-------
Q Test no. 200-24 baseline
Q Test no. 201-13 low 02
Test no. 203-27 OFA
O Test no. 203-28 OFA
Test no. 202-5 RAP
Location 38
Load * 89°; of rated
Fuel: #6 fuel oil
30 40 50 60 70 80 90 95 98 99 99.8
Cumulative proportion of impactor catch, % by mass
Figure 6-11. Effect of NOX controls on particle size distribution
for a residual oil-fired watertube industrial boiler.
(Reference 6-18)
6-41
-------
TABLE 6-8. EFFECT OF COMBINED LOW EXCESS AIR, STAGED COMBUSTION, AND FLUE
GAS RECIRCULATION ON POLYCYCLIC ORGANIC MATTER (POM) EMISSIONS
FROM A RESIDUAL OIL-FIRED INDUSTRIAL BOILER (Reference 6-18)
Sample
Train
Fraction
10 W
solids
3 ym
solids
1 ym
solids
Filters
Solids sec-
tion wash
XAD-2 resin
Organic
module rinse
Condensate
Impinger 1-3
Polycyclic Organic Matter (POM)
Test Number*
2-Baseline 3-Low NOX 4-Low NOX
yg/g
IS*
IS
IS
IS
NRO
0.005
IS
<0.001
--
yg/m3
—
—
~
~
—
0.04
—
<0.24
--
yg/g
i
IS
IS
IS
NR
0.0008
1.45
0.002
--
yg/m3
0.1
—
—
—
—
0.006
50
0.5
--
yg/g
IS
IS
IS
IS
NR
<0.1
IS
NR
--
yg/m3
—
—
—
—
~
<0.8
—
—
—
*Test 1 results were obtained using a fuel with a different analysis.
+Insufficient sample.
°Not recorded.
6-42
-------
The results of these tests are presented in Table 6-9. The results show a
significant reduction in POM in the XAD-2 resin for the low NO test
A
compared to that for baseline conditions. The test results are definitely
not in line with the expected trends. However, without complete analysis
of all fractions, a conclusion concerning the total gas stream cannot be
made.
Trace element emission data are also limited. The same study which
provided the POM data, above, provided the trace element data reported
below (Reference 6-18). A combination of reduced excess air staged
combustion and flue gas recirculation resulted in an increase in
particulate emissions of from 30 to 60 percent over baseline conditions.
Tables 6-10 through 6-12 present the results of the element partitioning
study as a result of the increased particulate loading. Comparison of
test 3 (low NO ) with test 2 (baseline) indicates that calcium,
y\
chromium, iron, manganese, titanium and zinc were increased by 10 to 90
percent in the solid particulate less than 3 micrometers. These same
elements, plus barium, cobalt, and copper were increased by over 20% in
the total amount of solid particulate collected.
Comparison of the concentration of arsenic, cobalt, copper, iron,
manganese, nickel, vanadium, zinc, chloride and sulfates at each size
fraction shows a clear shift in concentration towards the smaller particle
sizes during low NO operation. The remaining species were not present
in sufficient quantities to allow an assessment.
It appears that, for this particular boiler, an increase in trace
metal emissions, in proportion to increased particulate, occurs with
increased NO control. A shift towards increased trace metal
/\
concentration in smaller particulate can also be seen.
The NO control data, unfortunately, is still very limited,
A
presenting information only on a combination of control technologies, and
only for one boiler. More data must be collected before firm conclusions
can be presented.
The above emission data were presented for combustion modifications
only. Low NOX burners and ammonia injection, considered to be advanced
control method, are still in the development stages. Actual incremental
emission data are not available.
6-43
-------
TABLE 6-9. EFFECT OF NOX CONTROL ON POLYCYCLIC ORGANIC MATTER (POM)
EMISSIONS FROM A RESIDUAL OIL-FIRED BOILER: XAD-2 RESIN
TEST ONLY* (Reference 6-18)
POM Component^
Anthracene
Phenanthrene
Methyl Anthracenes
Fluoranthene
Pyrene
Benzo(c)phenanthrene
Chrysene
Benzo Fluoranthenes
Benz(a)pyrene
Benz(e)pyrene
Total POM
Baseline
ng POM
g Part icu late
3.2
—
0.2 r
1.2
0.05
0.002
0.03
0.007
0.004
0.004
4.74
ng POM
m^ Flue gas
24
—
1.6
9.0
0.4
0.02
0.19
0.05
0.032
0.032
35.5
Low NOX
ng POM
g Participate
0.45
0.02
0.12
0.13
0.05
—
0.004
0.007
—
—
0.78
ng POM
m-3 Flue gas
3.4
0.1
0.9
0.9
0.4
—
0.03
0.05
—
—
5.8
aLow NOX condition: combined low excess air, staged combustion,
and flue gas recirculation.
sis by gas chromatograph — mass spectrometry.
6-44
-------
TABLE 6-10. EFFECT OF COMBINED LOW EXCESS AIR, STAGED COMBUSTION
AND FLUE GAS RECIRCULATION ON TRACE SPECIES EMISSIONS
FROM A RESIDUAL OIL-FIRED INDUSTRIAL BOILER
(Reference 6-18)
total Enlislon Conccntr
Atomic ASiorptlon,
Te«t
Condition
Antiaony
Areenic
B»riu»
•erylliuii
Cadnluw
Calciua
Chxoaiua
Cobalt
Copper
Iron
Lead
ttenganea*
Mercury
Nickel
Selcniun
Tellurium
Tin
TitanivM
VanadiuB
Zinc
Chloride
Fluorid*
Nitrate*
Sulfatea
2
B«*eline
< 380
6.5 < 15
95 < 210
< 6
13
650
750
65 < 130
32
4300
45 < 70
70
< 1.9
1300 <1«00
< 12
< 300
< 750
70 < 1600
3200 < 3400
370
12000
170 < 180
130
18000
3»
lot, HO,
< 540
59 < 64
640 < 740
< a. 9
4.8 < 12
2000
740
79 < 150
39 < 44
4700
9.9 < 21
99
0.06 < 21
1600
9.9 < 290
< 450
< 1000
120 < 2500
3400 < 3600
810
3500
64 < 79
110 < 120
18000
itione by
uq/n}
4"
Low 140,
< 350
55
800 < (50
< 6
1.1 < 6
440 < 460
530
18 < 85
95
3100
< 15
65
2
2200
< 11
< 290
< 700
20 < 100
2400
3300
6000
24 < 33
85
21000
Total Cwiiiiei Concen-
trations by Spark Source
2
Baseline
11
6.5
MC
0.015 •' 3
7.5 < 13
2000 < MC
960
8 < MC
49
13PO
-------
TABLE 6-11.
TRACE SPECIES EMISSIONS FROM A RESIDUAL OIL-FIRED INDUSTRIAL BOILER
UNDER BASELINE CONDITIONS (TEST 2) (REFERENCE 6-18)
Sanule Typ*
Suplr Njnber
Sanple K*iohr./Vol.
Units
Antinony
Arsenic
B*riu»
Eerylliun
C*.!niun
CalciuM
ChroBiun
Cobalt
Copper
Iron
I**4
Kanq£ne*e
Hercury
Nickel
Sclcniun
felluxlua
Tin
Titanium
Vcnadiu*
tine
Chloride
fluoride
Nltratef
Sulfatei
Mottle, Probe.
10 w» Cyclor.e
Solids
S6C
1.6620 q
uq/q
< 38
< 1.5
38
< 0.8
0.8
1900
72
120
46
MOO
150
SI
< 0.03
1900
< 1.5
< 38
< 76
< 460
6300
400
279
205
113
14200
U9/«3
< 3.2
< 0.13
3.2
< 0.065
0.065
160
6
10
3.8
450
13
4.3
< 0.0025
160
< 0.13
< 3.2
< 6.3
< 38
520
33
23
17
9.4
1200
3 U» Cyclone
Solids
716
0.4443 <|
W9/9
< 210
33
460
< 4.2
< 4.2
1900
140
310
50
7200
< 20
75
< 0.17
2200
< 8
< 210
< 420
<1200
10000
40O
NES
134
NCS /
NES /
ui/*-1
< 4.7
0.73
30
< 0.093
< 0.093
42
3.1
6.7
1.1
160
< 0.44
1.7
< 0.0038
49
0.19
< 4.7
< 9.3
< 27
220
8.9
NF.S
3
NES
NES
1 LI* Cyclone
Solids
720
0.7196 q
Wo/q
< 250
< 10
600O
< 5
< 5
1500
310
940
100
32000
< 15
210
< Q.l
900"
< 10
< 250
< 500
2500
43000
1300
NES
909
NES
NTS
uq/»3
< 2.7
< 0.11
66
< 0.055
< 0,055
38
3.4
10
1.1
350
< 0.27
2.3
< 0.0022
99
< 0.11
< 2.7
< 5.5
27
470
14
NES
10
NES
NTS
Filters
538
0.4157 q
Uq/q
< 500
200
80O
< 10
< 10
4BOO
240
1600
460
?iooo
1OOO
250
< 0:4
30000
< 20
< 500
<1000
<1OOO
)9000
4900
116PO
< 2
39.5
t 57000
ug/m3
< 10
4.2
17
< 0.2
< C.2
100
5
33
9.6
440
21
5.2
< 0.008
620
•: 0.42
< 10
< ;i
< 62
1800
100
240
< 0.04
0.82
9500
Solid
Sect ion
Wash
19- 2 A
160'. ml
pq/*l
< 0-5
0.019
< 0.1
< 0.005
O.P05
0.49
0.09
< 0.2
0.06
2.6
0.14
0.17
< 0.005
0.77
< 0.01
< 0.3
< 1
< 1
2.5
1.7
2.1
< 0.1
0.24
7.0
uq/n3
< 40
1.4
< 8
< 0.4
0.4
39
7.2
< 16
4.1
21P
11
14
< 0.4
62
0.8
< 24
< 80
< 80
200
140
170
< 8
19
560
-------
TABLE 6-12.
TRACE SPECIES EMISSIONS FROM A RESIDUAL OIL-FIRED INDUSTRIAL BOILER
UNDER LOW NOX CONDITIONS (TEST 3)a (REFERENCE 6-18)
Sample Type
Sample Njnbcr
Sample Heiqht/Vol.
ynits
Antinony
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Nickel
Selenium
Tellurium
Tin
Titanium
Vanadium
Zinc
Chloride
Fluoride
Nitrate*
Sulfatei
Norzle. Probe,
1O gin Cyclone
Solids
722
2.416) q
P9/q
< 50
4
480
< 1
< 1
1900
69
104
43
5200
NES
49
O.S
970
< 2
< 50
< 100
600
5400
281
< 30
54
43
8910
uq/m3
< 6
0.5
57
< 0.12
< 0.12
230
8
12
5
620
—
6
0.06
120
0.24
6
12
72
650
34
< 4
6.S
5.1
1100
3 |im Cyclone
Solids
723
1.0724 g
uq/q
< 2500
< 100
< 1000
< 50
< 50
3500
950
450
< 50
4400
NES
20O
< 2
1700
< 5000
< 2500
< 5000
<15000
7000
250
< 97
NES
67
14000
ug/m3
< UP
< 5
< 53
< 3
< 3
190
50
24
< 3
230
—
11
< 0.1
90
< 270
< 130
< 270
< 800
370
13
< 5
—
3.6
740
1 Ui» Cyclone
Solids
726
0.2120 q
ug/q
< 830
< 33
< 330
< 17
< 17
3000
300
300
< 150
6500
NES
117
< 0.67
3000
< 33
< 830
<1700
5000
14000
350
NES
NFS
NES
NES
Uij/n
< 9
< 0.4
< 4
< 0.2
< 0.2
31
3.1
3.1
< 2
68
--
1.2
< 0.007
31
< 0.4
< 9
< 18
52
ISO
3.7
—
~
—
—
Filters
539
0.9974 q
Uq/q
< 170
33
730
< 3.3
< 3.3
MOO
ieo
807
200
20000
NES
160
< 0.13
13000
< 6.7
< 170
< 330
<1000
43000
3000
1700
< 1
46
170000
Uq/»3
< 8
1.6
36
< 0.2
< 0.2
150
8.9
40
9.9
1000
—
7.9
< 0.006
640
< 0.3
< 8
< 16
< 49
2100
150
84
< 0.05
2.3
8400
Solid
Section
H.is!^
19- 3A
1D39 ml
•iq/ml
< 0.5
0.01
< 0.1
< C.OOS
< 0.005
15
0
< 0.2
0.11
1.8
0.11
0.16
< 0.005
0.5
0.04
< 0.3
< 1
< 1
1.4
0.49
< 0.5
< 0.1
0.26
12
ug/m3
< 46
o.r--
< 9
< 0.5
< 0.5
1430
0
< 18
10
160
10
15
< O.S
46 '
3.6
< 27
< 91
< 91
130
45
< 46
< 9
24
1100
cn
i
aLow NOX condition: combined low excess air, staged combustion, and flue gas
recirculation.
-------
Due to the comparative high cost of this technique, the ammonia
injection process will probably not be feasible on small size boilers such
as firetubes and package watertubes unless stringent emission levels are
required. In addition, since these industrial units are generally not
base loaded, that is they do not operate at a steady continuous load, the
variable heat input will cause significant flue gas temperature
fluctuations which will reduce the performance of the control technique.
6.5 ENVIRONMENTAL IMPACTS OF NOX CONTROLS FOR DISTILLATE OIL AND
NATURAL GAS-FIRED BOILERS.
Distillate oil and natural gas-fired industrial boilers are
generally packaged firetube boilers. The recommended NO control
/\
techniques are presented in Table 3-10 for distillate oil and Table 3-11
for natural gas. The recommended emission levels for both fuels are
presented in Table 3-6.
Table 6-13 presents the incremental emission data available for
distillate oil-fired boilers. Table 6-14 presents the incremental
emission data available for natural gas-fired boilers.
Figure 6-12 presents the data for CO emissions with the various
types of NO control techniques for distillate oil fuels. Carbon
/\
monoxide emissions increase in all cases where NO reductions occurred.
/\
Flue gas recirculation resulted in the largest decrease in NO emission
n
rate and met the stringent control level in both cases. All other control
types met the intermediate control level, with CO emissions varying from
no change to substantial increase. Low excess air resulted in the largest
increases.
Figure 6-13 presents the incremental emission data for unburned
vapor phase hydrocarbons from distillate oil-fired boilers. Generally
there appears to be no change with NO emission reduction.
/\
Data on the emissions for natural gas-fired boilers are presented
in Figure 6-14. Low excess air NO control results in the largest
A
incremental increases in CO emissions. However, the NO emissions are
/\
generally reducod to only moderate or intermediate levels. The best
control technique for reaching the required NOX levels without severe
incremental emission impact is flue gas recirculation. All other control
techniques are mixed in their ability to control NOX and their effects
on other emissions. Figure 6-15 presents additional CO emission data as a
6-48
-------
TABLE 6-13. INCREMENTAL EMISSIONS FROM DISTILLATE OIL-FIRED INDUSTRIAL BOILERS
Boiler
Test
Series
A
B
C
D
System
Actual/Design
Heat Input
Ml (106 Btu/hr)
6.9/9.3
(23)/(33)
7.0/9.3
(24/(33)
26/32
(89)/(UO)
26/32
(89)/(110)
2.0/2.9
C)/(10)
1.5/2.9
(5)/(10)
4.1/5.1
(14)/(18)
Boiler
Typ«
Uatertube
Uatertube
Uatertube
Uatertube
Flretube
Flretube
Uatertube
NOX Control
(Excess 0;. <)
Baseline
(5.9)
Low Excess
Air
(2.8)
Baseline
(5.7)
LOM Excess
Air
(3.8)
Baseline
(7.2)
Low Excess
Air
(3.6)
Baseline
(3.6)
HO, Emissions
ng/J
66
57
115
__
121
85
37
Incremental
Change,
ng/J
-9
„
• —
_
-36
Criteria Emissions*
Pollutant
CO
UHC
SOj
PART
CO
UHC
$03
PART
CO
UHC
SOi
PART
CO
UHC
so3
PART
CO
UHC
PAR*T
CO
UHC
SO 3
PART
CO
UHC
S03
PART
ng/J
0
--
7
20
6
-.
--
0
„
8
10
0
„
—
0
24
1
23
0
5
--
17
6
17
Incremental
Change,
ng/J
—
—
+6
— .
—
..
"™
0
—
—
—
-*
0
-19
—
-
*No data available on noncrtteria enissions
Continued
T-1448
-------
TABLE 6-13. Continued
I
-------
TABLE 6-13. Continued
I
en
Boiler
Test
Series
F
G
System
Actual /Design
Heat Input
HU (106 Btu/hr)
4.2/5.1
(14)/(18)
4.2/5/1
(14)/(18)
4.2/5/1
(14)/(18)
4.3/5.1
(15)/(18)
4.2/5.1
(14)/(18)
4.3/5.1
(15)/(18)
5.0/8.4
(17)/(28)
6.0/8.4
(20)/(2B)
Boiler
Type
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
NO, Control
(Excess 02, X)
Baseline
(31)
Low Excess
Air
(1.2)
Flue Gas
Recirculation
(0.85)
(28.4 X FGR)
Flue Gas
Recirculation
(0.7)
(27.9 * FGR)
Overf ire
Air
(3.1)
Overfire
Air
(3.2)
Baseline
(5.3)
Low Excess
Air
(4.7)
NOX Emissions
ng/J
66
55
17
19
54
55
51
47
Incremental
Change,
ng/J
-11
-49
-47
-12
-11
__
-4
Criteria Emissions'
Pollutant
CO
UHC
S03
PART
CO
UHC
S03
PART
CO
UHC
S03
PART
CO
UHC
S03
PART
CO
UHC
S03
PART
CO
UHC
S03
PART
CO
UHC
SOl
PART
CO
UHC
SO 3
PART
ng/J
3
1
1
25
62
1
3
15
7
1
5
5
24
1
—
12
1
1
12
8
0
..
--
31
-.
12
13
51
—
—
Incremental
Change.
ng/J
__
—
—
--
+59
0
+2
-10
+4
+0
+4
-20
+21
0
--
+9
0
0
-13
5
-1
—
—
„
.-
--
+20
--
—
aNo data available on noncriteria emissions
Continued
T-1448
-------
TABLE 6-13. Concluded
en
r\j
Boiler
Test
Series
H
Systen
Actual/Design
Heat Input
NU (10* Btu/hr)
20/58
(68)/(200)
Boiler
Type
Uatertube
Uatertube
NOX Control
{Excess 02 , ()
Baseline
(4.4)
0»erf1re
Air
(5.4)
NOX Emissions
ng/J
56
55
Incremental
Change,
ng/J
„
-3
Criteria Emissions*
Pollutant
CO
UHC
SOj
PART
CO
UHC
S03
PART
ng/J
0
0
12
0
0
—
—
Incremental
Change,
ng/J
„
—
~~
0
0
—
—
*No data available on noncrtteria missions
T-1448
-------
TABLE 6-14. INCREMENTAL EMISSIONS FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS
Boiler
Test
Series
A
V
B
C
System
Actual /Design
Heat Input
MM (10* Btu/hr)
4.9/8.4
(17)/(27)
7.3/8.4
(24)/21)
32/46
(10/(157)
35/46
(120)/(157)
35/46
(120)/(157)
8.4/20
(27)/(70)
8.4/20
(27)/(70)
8.4/20
(27)/(70)
Boiler
Type
Matertube
Matertube
Matertube
Matertube
Matertube
Matertube
Matertube
Matertube
NOX Control
(Excess 02. X)
Baseline
(2.2)
Low Excess
Air
(0.9)
Baseline
(5.3)
Low Excess
A1r
(3.2)
Reduced Air
Preheat
(5.2)
Baseline
(5.7)
Low Excess
Air
(3.7)
Reduced Air
Preheat
(5.6)
NOX Emissions
ng/J
40
38
79
82
81
108
85
100
Incremental
Change,
ng/J
__
-2
__
+3
+2
— .
-23
-8
Criteria Emissions'
Pollutant
CO
UHC
Part.
CO
UHC
S03
Part.
CO
UHC
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
ng/J
21.
—
--
152
—
—
—-
0
22
—
3
12
—
--
0
12
--
— -
0
0
—
—
4
0
—
—
0
--
--
--
Incremental
Change,
ng/J
—
—
+131
--
--
--
..
—
—
+3
-13
--
--
0
-10
--
--
_—
—
•
—
+4
0
--
—
0
—
--
— —
tn
co
data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Continued
System
Boiler
Test
Series
D
/
E
Actual /Design
Heat Input
MW (106 Btu/hr)
22/38
(76)/(130)
22/38
(76)/(130)
24/35
(82)/(120)
24/35
(82)/(120)
57/73
(193)/(250)
58/73
(200)/(250)
•
58/73
(200)/(250)
Boiler
Type
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
NOX Control
(Excess 02. X)
Baseline
(7.1)
Reduced Air
Preheat
(7.1)
Baseline
(4.4)
Low Excess
Air
(2.2)
Baseline
(2.6)
Reduced Air
Preheat
(2.6)
Reduced Air
Preheat
(2.5)
NOX Emissions
ng/J
82
83
117
111
96
71
95
Incremental
Change,
ng/J
— —
+1
__
-1
...
-25
-1
Criteria Emissions*
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
Part.
CO
UHC
S03
Part.
CO
UHC
S03
. Part.
CO
UHC
so3
Part.
CO
UHC
S03
Part.
ng/J
62
—
—
—
70
—
—
—
0
—
—
0
—
—
--
100
7
—
—
112
—
—
—
99
—
—
~~
Incremental
Change,
ng/J
_ ^
--
—
—
+12
—
—
—
__
—
—
0
•
—
— *
_ _
—
—
--
+12
—
«
—
-1
--
—
~^
01
I
aNo data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Continued
Boiler
Test
Series
F
6
System
Actual/Design
Heat Input
MM (106 Btu/hr)
12/13
(40)/(45)
12/13
(40)/(45)
12/13
(40)/(45)
10/13
(35)/(45)
11/13
(35)/(45)
11/13
(14)/(18)
4.1/5.1
(14)/(18)
Boiler
Type
Watertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
NOX Control
(Excess 02, X)
Baseline
(1.9)
Low Excess
Air
(1.35)
Reduced Air
Preheat
Reduced Air
Preheat
Overfire
Air
(3.4)
Overfire
Air
Baseline
(3.2)
NOX Emissions
ng/J
112
93
120
63
82
52
30
Incremental
Change,
ng/J
__
-19
+8
-49
-30
-60
„
Criteria Emissions'
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
Part.
CO
UHC
Part.
CO
UHC
S03
Part.
CO
UHC
503
Part.
CO
UHC
S03
Part.
ng/J
0
2
—
~
279
0
—
--
9
2
«
9
0
--
6
0
—
—
11
..
—
—
3
1
—
~™
Incremental
Change.
ng/J
— ^
—
—
—
-279
-2
—
—
+9
0
—
+9
-2
—
+6
.-
—
—
+11
..
~
— -
„
—
—
"™
en
i
en
01
*No data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Continued
Boiler
Test
Series
G
(Cont.)
N
System
Actual /Design
Heat Input
MU (106 Btu/hr)
4.1/5.1
(14)/(18)
4.1/5.1
(U)/(18)
3.9/5.1
(13)/(18)
4.2/5.1
(14)/(18)
4.0/5.1
(14)/(18)
12/13
(40)/(45)
11/13
(40}/{45)
Boiler
Type
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
Watertube
NOX Control
(Excess 03, X)
ion Excess
Air
(2.0)
Flue Gas
Reclrculatlon
(2.9)
Flue Gas
Reclrculation
(2.75)
Overflre
Air
(2.8)
Overflre
Air
(2.4)
Baseline
(1.6)
Low Excess
Air
(1.25)
NOX Emissions
ng/J
29
19
8
39
27
82
71
Incremental
Change,
ng/J
-1
-11
-22
*9
-3
„
-11
Criteria Emissions*
Pollutant
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
CO
UHC
503
Part.
CO
UHC
so3
Part.
CO
UHC
S03
Part.
CO
UHC
so3
Part.
ng/J
25
—
—
—
0
0
—
—
37
13
—
—
0
0
—
—
3
0
—
— —
43
—
«
—
619
--
—
— —
Incremental
Change,
ng/J
+22
—
—
~
-3
-1
—
—
+34
+12
—
—
-3
-1
—
—
0
-1
—
— •*
..
—
—
—
576
—
—
™*
01
01
data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Continued
Boiler
Test
Series
H
(Cont.)
I
System
Actual/Design
Heat Input
HU (10* Btu/hr)
11/13
(40)/(45)
12/13
(40)/(4S)
12/13
(40)/(45)
4.2/5.1
(14)/(18)
4.1/5.1
(14)/(18)
4.4/5.1
(14)/(18)
4.0/5.1
Boiler
Type
Uatertube
Uatertube
(2.2)
Uatertube
Uatertube
Uatertube
Uatertube
Uatertube
NOX Control
(Excess 02, X)
Ovterfire
Air
(2.25)
Reduced Air
Preheat
Overfire
Air
(2.25)
Baseline
(3.0)
Flue Gas
Recirculation
(3.2)
(20.3* FGR)
Flue Gas
Recirculation
(2.5)
(19.9* FGR)
Baseline
(3.2)
NOX Emissions
ng/J
57
62
53
49
12
11
46
Incremental
Change,
ng/J
-25
-20
-29
—
-37
-38
«
Criteria Emissions*
Pollutant
CO
UHC
S03
Part.
CO
UHC
Part.
CO
UHC
s°3
Part.
CO
UHC
Part.
CO
UHC
Part.
CO
UHC
Part.
CO
UHC
Part.
ng/J
38
3
85
1
1
—
6
1
5
0
6
1
--
Incremental
Change,
ng/J
-5
-40
-42
—
—
+5
0
+4
-1
--
—
en
i
en
*No data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Continued
Boiler
Test
Series
1
(Cont. )
J
K
Systeii
Actual /Design
Heat Input
MM (106 Btu/hr)
4.0/5.1
(14)7(18)
4.2/5.1
(14)/(18)
4.0/5.1
(14)/(18)
2.5/3.5
(8.5J/12)
2.2/3.5
(7.5)/(12)
2.3/3.5
(2.5)/(12)
•
5.8/7.3
(20)/(25)
Boiler
Type
Water-tube
Hatertube
Watertube
Firetube
Flretube
Firetube
Watertube
NOX Control
(Excess 02, X)
Lew Excess
Air
(1.1)
Overflre
Air
(2.8)
Flue Gas
Recirculation
(3.3)
Baseline
(7.1)
Low Excess
Air
(6.6)
High Excess
Air
(7.8)
Baseline
(10.3)
NOX Emissions
ng/J
44
25
13
87
90
90
64
Incremental
Change,
ng/J
-2
_—
-33
— —
+3
+3
„
Criteria Emissions*
Pollutant
CO
UHC
*>3
Part.
CO
UHC
so3
Part.
CO
UHC
s°3
Part.
CO
UHC
S03
Part.
UHC
UHC
S°3
Part.
CO
UHC
S03
Part.
CO
UHC
S03
Part.
ng/J
208
0
—
—
91
0
—
—
5
0
2
3
19
—
—
50
—
—
— •
55
—
—
~~
25
—
—
~~
Incremental
Change,
ng/J
+302
-1
—
~
+85
0
—
—
-1
0
—
-1
^_
—
—
— •
+31
—
—
—
+36
—
..
••
— —
—
—
~-
CTl
I
tn
Co
data available on noncriteria emissions
Continued
T-1450
-------
TABLE 6-14. Concluded
Boiler
Test
Series
K
(Cont.)
System
Actual /Design
Heat Input
m (10* Btu/hr)
5.8/7.3
(20)/(25)
5.7/7.3
(20)/(25)
5.7/7.3
(20)/(25)
5.6/7.3
(20)/{25)
Boiler
Type
Watertube
Watertube
Watertube
Watertube
NOX Control
(Excess Op, X)
Low Excess
Air
Low Excess
Air
Low Excess
Air
(6.1)
Low Excess
Air
(5.0)
NOX Emissions
ng/J
67
68
65
59
Incremental
Change,
ng/J
+3
+4
+1
-5
Criteria Emissions9
Pollutant
CO
UHC
Part.
CO
UHC
Part.
CO
UHC
Part.
CO
UHC
S03
Part.
ng/J
27
—
31
~
36
883
Incremental
Change,
ng/J
+2
—
+6
—
+11
+858
CM
I
cn
to
*No data available on noncrlterta emissions
T-1450
-------
-3
?
""^
41
2
§
i
s
e
8.
c
0
0: (141 ng/J CoT
«
(Note: alphabetic characters
identify boiler test series
in table 6-13)
•
.
^•LH •
F
<
P _ 27. 9% FGR
F« •
f
F_28.4t FGR F^A Q
I 1 m I/T> I yfcl
-80 -60 ' -40 C -20 H
Q Meets no NOX control level
0 Meets moderate NO. control level
-20 •
O Meets Intermediate HOX control level
«) Meets stringent NOX control level
-40 -
O Low excess air
QFlue gas rcclrculation
AOverfire air
• +120
. +100
.+80
• +60
• +40
. +20
D-HEA
+20
i
S
i
Change In NO emission rate (ng/J)
Figure 6-12. Change in CO emission rate with NOX control for distillate
oil-fired industrial boilers (References 6-15 and 6-17).
6-60
-------
I/I
I/)
ro
(Note: alphabetic characters Identify
boiler test series in table 6-13)
QMeets no NOX control level
(pMeets moderate rate NOX control level
(^Meets intermediate NOX control level
• Meets strinaent NCL control level
* A
QLow excess dir
QFlue gas recirculation
£0verfire air
-40
-30
-20
LEA-F
0
c
-+50
- +40
- +30
-+20
- +10
--10
- -20
Change in NOX emission rate (ng/J)-
Figure 6-13.
Change in UHC emission rate with NO., control
for distillate oil-fired industrial boilers
(Reference 6-15 and 6-17).
6-61
-------
f>
(0
cr.
c
to
O
1/1
i/i
O
o
o
c
QJ
U
C
-60
•-+200
--+150
'
••+100
(NOTE: Alphabetic
characters identify
boiler test series
in Table 6-14)
H .- -50
O Meets no control level
(D Meets moderate control level
O Meets Intermediate control level
• Meets stringent control level
Q Reduced air preheat
{}Flue qas recirculation
& Over fire air
O Low excess air
-250
Incremental change in NO emissions (ng/J)*
Figure 6-14. Change in CO emissions with NO. control for
a gas-fired industrial boiler (Reference 6-17).
6-62
-------
100
90
80
^ 70
c
S 60
I 50
i
S 40
30
20
10
883.1 ng/J CO
NO
co
Recommended control level
Moderate-
Inter- .
mediate
Stringent -*
I
100
90
80
70 I
60
50
c
o
E
a.
30
20
10
7 8 9
Percent excess oxygen
10
11
12
Figure 6-15.
Changes in CO and NOX emissions with reduced excess
oxygen for a gas-fired watertube industrial boiler
(Reference 6-17).
6-63
-------
function of low excess air levels. As with coal and residual oil, a point
is reached where CO emissions begin to increase rapidly. It is readily
apparent that, with this technique, a small incremental decrease in NO
A
results in a large change in CO emissions at the lower excess oxygen
levels.
Figure 6-16 presents the emission rates of unburned hydrocarbons.
The quantity of data is very limited. Generally, however, very slight
changes are noted with the various NO control techniques.
/\
Particulate emissions from natural gas-fired boilers were reported
as typically 1.72 to 3.01 ng/J (0.004 to 0.007 lb/106 Btu) in Reference
6-19. The reporting of particulate emissions during later test work with
various NO techniques were omitted due to the low emission rates.
Distillate oil-fired boilers emitted 8.6 to 17.2 ng/J (0.02 to 0.04
Ibs/MBtu) in the same test series. Particulate emissions data (Table
6-13) are plotted in Figure 6-17. Once again, as noted with coal- and
residual oil-firing, particulate emissions decrease with NO control.
A
Since each of the boilers tested is equipped with a dust control device,
this could indicate an increase in particle size under low NO
conditions and improved dust control device efficiency. Table 6-15
confirms the shift to larger particles with 82.0 percent greater than 1.3
micrometers under baseline conditions and 94.5 percent greater than 1.3
micrometers under low NO conditions.
A
Emissions of sulfates, trace elements, and organics have generally
not been measured during NO testing programs on units firing distillate
A
oil or natural gas. This is due to the low concentrations of these
components in the fuel. Therefore, no incremental emission data is
available for presentation.
As with coal and residual oil fuels, low NO burners and ammonia
A
injection are still in the development stages for natural gas
application. Actual incremental emission data are not available.
6.6 OTHER POLLUTION SOURCES
The above discussions have centered around the impact of NO
controls on the products of combustion. Generally, the pollutants are
emitted from the stack as air pollutants. The decreased particulate
emissions from the stack under low NO conditions are assumed to result
A
from particulate collection by dust control devices. This increases the
6-64
-------
1
1
-0
cr
c
a;
s_
c
0
v>
X
o
3E
C
JT
1
(Note: alphabetic characters
identi'fy boiler test series
in table 6-14)
•M
«•
• G .
1 I C
LmA^ CTd M .
-80 -60 c -401 F ^20F G I
m
UJ
B
Q Meets no NOX control level -
(D Meets moderate NOX control level
d Meets inter. NOX control level
0 Meets stringent NOX cont. level ™
O Low excess air
Q Reduced air preheat
£ Over- fire air
*\ Flue gas recirculation
- +40
- +20
F
n 1
^Ac 1
+20 +40
OB
- -20
- -40
^ Change in NOX emission rate (ng/J) — *
h-
K*
to
N
•3.
Figure 6-16.
Change in unburned hydrocarbon emissions with NOX
control for gas-fired industrial boilers
(References 6-15 and 6-17).
6-65
-------
"3
"^
CT
c
o
*•»
I/)
in
s
•I
I.
1C
Q.
o.
c-
c
1C
(Note: alphabetic characters
identify boiler test series in
-table 6-13)
-40
-30
-20
-10
Overf1 re
air
F d
F- Low
9 excess
air
flue gas recirculation
--10
-20
Meets no NOX control level
Meets moderate NOX control level
Meets Inter. NOX control level
Meets stringent NOX control
level
-30
-40
Change in NOX emission rate
(ng/J)
Figure 6-17.
Change in particulate emissions with
NOX control for a distillate oil-fired
watertube industrial boiler (Reference 6-15)
6-66
-------
TABLE 6-15. EFFECT OF OVERFIRE AIR NO CONTROL ON PARTICLE SIZE DISTRIBUTION FOR
A DISTILLATE OIL-FIRED WAfERTUBE INDUSTRIAL BOILER (Reference 6-16)
Fuel
Type
«o. 2
lo. 2
(o. 2
Burner
Type
Steam
Steam
Steam
Test
Load
GJ hr-1
58
65
65
NOX
ng/J
49.4
~
-
Impact
Flow
cm3 s-1
28.3
28.3
28.3
cSct
UB
—
"
—
Actual DSO of Stage No.D
1
pm
3.2
3.2
3.2
2
"•
1.9
1.9
1.9
3
M"
1.3
1.3
1.3
4
M"
0.64
0.64
0.64
5
Ml
0.32
0.32
0.32
Cyclone
ng
None
None
None
Cyclone. Stage and Filter Catch
Stage No.
1
•9
96.9
5.60
10.6
2
•9
7.55
0.148
3.57
3
•9
0.408
0.064
0.788
4
"9
0.756
1.032
0.62
5
•9
0.008
0.024
0.034
Filter
•9
0.368
0.192
0.20
Total
Catch
•9
105.6
7.06
15.842
Comments
Lower Load
Low NO,
Baseline
I
cr>
aParticle size distribution determined by use of a Brink model *B' cascade impactor
bD^o identifies the size fraction in micrometers. Fartlculates with an aerodynamic diameter
greater than the DJQ cut point will be captured. Increasing stage number corresponds to
decreasing particle size.
T-1455
-------
quantity of solid waste to be discharged from the system. The incremental
increase in solid pollutants is expected to be small when compared to the
total dust emissions from the system. No continuous sources of water are
involved with the NO control techniques. Increased deposits within the
^
boiler not removed as slag may require increased washing of internal
surfaces. In addition, dust or slag removal devices which utilize
sluicing as the transport mechanism for ash disposal may be increased
slightly. However, information is not available to determine if the
overall pollutant burden (leachate concentration, chemical oxygen demand,
suspended solids content, etc.) would be impacted.
Pollution increases due to thermal and electrical discharge are not
expected to increase. Noise pollution would be affected by any increase
in operating equipment (such as fans for flue gas recirculation).
However, it is not expected that the incremental increase will be
measurable when compared to the overall plant noise level.
6.7 SUMMARY
Tables 6-16 through 6-19 compare the recommended NO control
A
techniques, the levels of control achievable, and the resulting
incremental changes in other pollutant emissions. Where actual data are
not available, a postulated effect is presented.
Carbon monoxide levels generally increase with NO control, although
this can be minimized if not eliminated with judicious application of the
control. Actual test data shows unburned hydrocarbon emissions to be
decreased more often than increased, though the data are variable. Sulfate
emissions decrease with decreasing oxygen content; particulate emissions
decrease due to an (assumed) increase in particulate control device collection
efficiency. The best NO control device for industrial boilers firing coal
appear to be low excess air and staged combustion (overfire air), but
information is too limited to be conclusive.
Low excess air and staged combustion (overfire air) appears to have
little effect on incremental emissions from residual oil-fired boilers. For
distillate oil- and natural gas-fired boilers, flue gas recirculation, staged
combustion, and reduced air preheat appear to be the best methods available.
Incremental emissions are potentially increased by NO controls.
/\
More data are needed to quantify the incremental emissions for each control
technique and to determine if any significant environmental impact may result.-
6-68
-------
TABLE 6-16. POSTULATED EFFECT OF CANDIDATE NO^ CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM COAL-FtRED INDUSTRIAL BOILERS
Boiler
Coal-Fired Boiler ±29 MU
Coal-Fired Boilers < 29 MU
NOX Control
Technique
Low Excess Air
Overflre Air
Low NOX Burners
Ammonia Injection1
Low Excess Air
Level of
Control
Moderate
Intermediate
Stringent
Intermediate
Stringent
Stringent
5 Stringent
Intermediate
Stringent
Change In Incremental Emissions
CO
*
*
*
(*)
(NE)
V
UHC
V
(*)
(*)
(NE)
c*>
S03
(-)
(-)
(-)
<*>
n
Partlculate
(")a
(-)*
(-)a
(NE)
Ha
( ) No data available
Some decrease
+ Some Increase
v Variable results
NE No effect
^Assuming dust control devices are utilized, otherwise (+)
DAnmon1a Injection may cause ammonia and byproduct emlsslo
T-1453
-------
TABLE 6-17. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM RESIDUAL OIL-FIRED
INDUSTRIAL BOILERS
NOX Control
Technique
Low Excess Air
Overfire Air
*
Low NOX
Burners
Ammonia
Injection
Level of
Control
Moderate
Intermediate
Stringent
Moderate
I ntermedi ate
Stringent
Intermediate
Stringent
Stringent
Change in Incremental Emissions
CO
+
+
•H-
( + )
+
+
(+)
( + )
(NE)
UHC
(+)
V
V
(+)
+
+
(+)
(+)
(NE)
S03
(-)
-
-
(-)
(-)
-
(-)
(-)
(+)
Parti cul ate
-
-
-
(_)a
-
-
(-)a
(-)a
(NE)
( ) No data available
Some decrease
+ Some increase
•H- Significant increase
a Assuming dust control devices are utilized. Otherwise (+)
v Variable results
NE No Effect
6-70
-------
TABLE 6-18. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM DISTILLATE OIL-FIRED
INDUSTRIAL BOILERS
NOv Control
Technique
Low Excess Air
Flue Gas
Recirculation
Overfire Air
Reduced Air
Preheat
Low NOX
Burners
Level of
Control
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Intermediate
Stringent
Stringent
Change in Incremental Emissions
CO
(+)
++
(*+)
(+)
(+)
+
(+)
+
+
(NE)
(NE)
(+)
UHC
(+)
(+)
(+)
(+)
+
(+)
» '
+
+
(NE)
(NE)
(+)
S03
(-)
(-)
(-)
(-)
(-)
(-)
(-)
(-)
(-)
(-)
(-)
Particulate
(-)
(.)«
(•)«
(.)«
(.)a
(-)a
(.)a
(+)
(+)
(-)•
( ) No data available
Some decrease
+ Some increase
++ Significant increase
a Assuming dust control devices are utilized. Otherwise (+)
NE No Effect
6-71
-------
TABLE 6-19. POSTULATED EFFECT OF CANDIDATE NOX CONTROL SYSTEMS ON
INCREMENTAL EMISSIONS FROM GAS-FIRED INDUSTRIAL BOILERS
NOX Control
Technique
Low Excess Air
Flue Gas
Recirculation
Over fire
Air
Reduced Air
Preheat
Low NOX
Burners
Level of
Control
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Moderate
Intermediate
Stringent
Stringent
Change in Incremental Emissions3
CO
+
+
+
M
-
+
-
+
+
( + )
UHC
( + )
-
M
M
(*)
;;;
-
(+) -
(*)
( ) No data available
Some decrease
+ Some increase
++ Significant increase
a S03 and particulate not present in natural gas
combustion products
6-72
-------
REFERENCES FOR SECTION 6
6-1. Mason, H. B. et al., "Preliminary Environmental Assessment of
Combustion Modification Techniques, Volume II, Technical Results,"
EPA-600/7-77-119b, NTIS-PB 276 681/AS, October 1977.
6-2. Vapor Phase Organic Pollutants -- Volatile Hydrocarbons and
Oxidation Products, National Academy of Sciences, Washington, 1976.
6-3. Particulate Polycyclic Organic Matter, National Academy of
Sciences, Washington, 1972.
6-4. Surprenent, N., et al., "Preliminary Emissions Assessment of
Conventional Stationary Combustion Systems," EPA-600/7-76-046a,
NTIS-PB 251 612/8BA, January 1976.
6-5. Richards, J., and R. Gerstle, "Stationary Source Control Aspects of
Ambient Sulfates: A Data Base Assessment," PEDCo Final Report, EPA
Contract No. 68-02-1321, Task 34, PEDCo Environmental, Cincinnati, OH,
February 1976.
6-6. Bittner, J. D., et al., "The Formation of Soot and Polycyclic
Aromatic Hydrocarbons in Combustion Systems," in Proceedings of the
Stationary Source Combustion Symposium. Vol. 1, EPA-600/2-76-152a,
NTIS-PB 256 320/AS, June 1976.
6-7. Knierien, H., Jr., "A Theoretical Study of PCB Emissions from
Stationary Sources," EPA-600/7-76-028, NTIS-PB 262 850/AS,
September 1976.
6-8. Klein, D. H., et al., "Pathways of Thirty-Seven Trace Elements
through Coal-Fired Powerplant," Environmental Science and
Technology, Vol. 9, No. 10, pp 973-979, October 1975.
6-9. Davison, R. L., et al., "Trace Elements in Flyash," Environmental
Science and Technology, Vol. 8, No. 13, pp. 1107-1113, December 1974.
6-10. Kaakinen, J. W., et al., "Trace Element Behavior in Coal-Fired
Powerplant," Environmental Science and Technology, Vol. 9, No. 9
pp. 862-869, September 1975.
6-11. Cato, G. A., and R. A. Venezia, "Trace Metal and Organic Emissions
of Industrial Boilers," Paper 76-27.8, 69th Annual APCA Meeting,
June 1976.
6-12. "Coal-Fired Powerplant Trace Element Study, Vol. I, A Three Station
Comparison," Radian Corp. report for EPA Region VIII, NTIS-PB 257
293/1BE, September 1975.
6-73
-------
6-13. Gladney, E. S., et al., "Composition and Size Distributions of
Atmospheric Participate Matter in Boston Area," Environmental
Science and Technology, Vol. 8, No. 6, p. 551, June 1974.
6-14. Ensor, D. S., et al.. "Elemental Analysis of Flyash from Combustion
of a Low Sulfur Coal," Paper 75-33.7, 68th Annual APCA Meeting,
June 1975.
6-15. "Cato, G. A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers -- Phase II," EPA-600/2-76-086a, NTIS-PB 253 500/AS,
April 1976.
6-16. Cato, G. A., "Field Testing: Trace Element and Organic Emissions
from Industrial Boilers," EPA-600/2-76-086b, NTIS-PB 261 263/AS,
October 1976.
6-17. Heap, M. P., et al.. "Reduction of Nitrogen Oxide Emissions from
Package Boilers," EPA-600/2-77-025, NTIS-PB 269 277, January 1977.
6-18. Carter, W. A., et al., "Emission Reduction on Two Industrial
Boilers with Major Combustion Modifications," EPA-600/7-78-099a,
NTIS-PB 263 109, June 1978.
6-19. Cato, G. A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers -- Phase I," EPA-650/2-74-078a, NTIS-PB 238 920/AS,
October 1974.
6-20. Maloney, K. L., et al.. "Low Sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers," EPA-600/7-78-153a,
NTIS-PB 287 937/AS, July 1978.
6-21. Gabriel son, J. E., et al., "Field Tests of Industrial Stoker
Coal-fired Boilers for Emissions Control and Efficiency Improvement
- Site A," EPA-600/7-78-136a, NTIS-PB 285 972/AS, July 1978/
6-22. Goldberg, P.M., and E. B. Higginbotham, "Field Testing of an
Industrial Stoker Coal-Fired Boiler — Effects of Combustion
Modification NOX Control on Emissions — Site A," Acurex Report
TR-79-25/EE, EPA Contract No. 68-02-2160, Acurex Corp., Mountain
View, CA, August 1979.
6-23. Lips, H. I., and E. B. Higginbotham, "Field Testing of an
Industrial Stoker Coal-Fired Boiler — Effects of Combustion
Modification NOX Control on Emissions -- Site B," Acurex Report
TR-79-18/EE, EPA Contract No. 68-02-2160, Acurex Corp., Mountain
View, CA August 1979.
6-74
-------
SECTION 7
EMISSION SOURCE TEST DATA
This section contains the experimental data recorded on tests of
various NO emission controls conducted on industrial boilers. Data
A
selection and test methods are summarized. These data (References 7-1
through 7-9) were used to generate the baseline and controlled NO
/\
emission levels presented in the preceding sections of this report.
7.1 CRITERIA FOR SELECTION
A brief description of the data selection procedure follows in
Section 7.1.1. Section 7.1.2 summarizes the test methods used.
7.1.1 Data Selection
Where possible, the data selected from published tests had to meet
certain prescribed criteria to be included in the NO control technology
/\
assessment. These criteria included:
t Well planned and controlled experimental conditions in which
only the parameter under investigation was allowed to vary.
All other important parameters were held as constant as
practically possible.
• Characterization and documentation of all major parameters and
conditions during the test, such as fuel analysis, and boiler
and burner design and operating variables.
• Representative boilers with representative baseline emissions.
In some cases, however, very limited data did not permit a
determination of representativeness. These cases have been
noted in the text of this report.
t Reasonableness of the data. In some cases extreme values are
given, as these were the only data available. These values are
generally noted and this section contains, in addition to the
7-1
-------
parameters associated with these data, other data which support
more moderate values, if available.
• Reliability and reproducibility of the data. In many cases,
because of the very limited number of tests run, reproducibility
could not be confirmed.
In the following data tables in this Section, a few selected test
points may involve unacceptable operating conditions, as defined by:
• CO emissions >400 ppm @ 3 percent 02
• Bacharach smoke spot no.> 4
• Opacity >20 percent
Those controlled test points with high CO and/or smoke emissions are
-indicated with an asterisk (*) in the data tables. However, it should be
pointed out that in most cases, these "special" test points already had
baseline NO emission levels meeting or exceeding the suggested moderate
A
control level (and in some cases even the stringent control level), all
under acceptable operating conditions. And therefore it is not unexpected
that further application of combustion modifications may lead to
unacceptable operating conditions. Thus these data points are included
here, in order for the data base to be complete and to project ranges of
extreme control, as observed by field investigators.
7.1.2 Test Methods
The two major investigative groups, KVB and Ultrasystems, used both
wet chemical and instrumental methods. For instance, one group (KVB) used
EPA Method 5 for particulate matter and EPA Method 9 for opacity. For
sulfur oxides they used the Shell-Emeryville wet chemical procedure and
for the remaining gases they used instruments obtained from a variety of
manufacturers. The other group, Ultrasystems, principally used
instrumentation to measure concentration. Selection of the methods used
by both companies were primarily based on:
• Portability. All boilers investigated were in the field;
t Cost. Despite their high initial cost, most instruments if
properly calibrated and maintained are more cost-effective than
the wet analytical methods they replace;
• Reliability. Properly calibrated and maintained instruments are
generally far more reliable than the wet methods they replace.
7-2
-------
Table 7-1 lists the types of monitors employed by the two principal
groups of investigators and their operating principles. A brief synopsis
of the errors associated with the measurement of each of the pollutants
follows. Only those for NO/NO are presented. The reader is referred
A
to Reference 7-4 for a complete discussion of the methods employed.
Nitrogen oxides concentrations were measured by a Thermo Electron
model 10A analyzer. The functional basis of the instrument is the
chemiluminescent reaction of NO and 0., to form NOp in an excited state.
When excited N02 molecules revert to their ground state, light emission
results. The resulting chemiluminescence is monitored through an optical
filter by a high sensitivity photomultiplier tube. The output of the
photomultiplier is electronically processed so it is linearly proportional
to the NO concentration.
Because the analyzer is sensitive only to NO, total NO is
A
determined by reducing any NO,, in the sample to NO. Reduction is
thermal, the gas being passed through a thermally insulated
resistance-heated stainless steel coil. N02 can be obtained by taking
the difference in readings with and without the converter in operation,
and assuming that NO + N0? = NO .
Cm A
The specifications of the instrument are presented below:
Accuracy 1% of full scale
Span stability + 1% of full scale in 24 hours
Zero stability + 1 ppm in 24 hours
Power requirements 115 + 10V, 60 Hz, 1000 watts
Response 90% of full scale in 1 second (NO
A
mode), 0.7 sec (NO mode)
Output 4 - 20 ma
Sensitivity 0.5 ppm
Linearity + 1% of full scale
Vacuum detector operation
Range 2.5, 10, 25, 100, 250, 1000, 2500,
10,000 ppm full scale
Other criteria pollutants are listed in Table 7-1 along with the
instrument or test method used. The reader is referred to Section 6 for a
listing of the criteria pollutant emission data associated with NO
rt
7-3
-------
TABLE 7-1. EMISSION MEASUREMENT INSTRUMENTATION
Emission
Nitric oxide
Oxides of nitrogen
Carbon monoxide
Carbon dioxide
Oxygen
Hydrocarbons
Sulfur dioxide
and trl oxide
Total part leu late
natter
Part leu late size
Smoke spot
Opacity
Symbol
NO
MOX
CO
CO?
02
HC
S02
S03
PM
--
K
—
KVB (References 7-4 and 7-5)
Measurement Method
Cheml luminescent
Cheml luminescent
Spectrometer
Spectrometer
Polarographlc
Flame 1on1zat1on
Absorption/
tltratlon
EPA Method 5
Visual counting
Cascade Inpactor
Reflectance
Photometric
EPA Method 9
Equipment Manufacturer
and Model Number
Thermo Electron 10 A
Thermo Electron 10A
Beckman 865
Beckman 864
Teledyne 325A
Beckman 402
KVB Equipment Company
Joy Manufacturing Company
Mllllpore Corporation* XX50
Monsanto-Br1nkD
Research Appllcance Company
62R-100
—
Ultrasystems (Reference 7-2)
Measurement Method
Cheml luminescent
Cheml luminescent
Spectrometer
--
PolarograpMc
~
Electrochemlcaie
—
~
Vlsual
—
Equipment Manufacturer
and Model Number
Thermo-Electronc
Thermo-Electronc
MSA LIRA-303
~
Theta Sensor^
—
Theta Sensor
—
~
Bacharach
—
I
-t.
* Reference 7-4.
b References 7-3, 7-5.
c Backup measurements made with Theta Sensor US-6000 analyzer.
« Backup measurements made with Teledyne 320AX.
* S02 only.
T-1611
-------
controls, and to References 7-2 and 7-4 for a discussion of the instruments
and/or techniques employed.
7.2 EMISSION SOURCE TEST DATA FOR COAL-FIRED BOILERS
Coal-fired industrial boilers have been tested during several EPA
sponsored field investigations (References 7-4, 7-5 and 7-7 through 7-9).
These include six pulverized coal-fired units, one cyclone, twelve spreader
stokers, two underfeed stokers, two chain grate stokers and a vibrating
grate stoker. Tables 7-2 through 7-4 present the results of NOX emission
controls as applied to pulverized coal and cyclone boilers; Tables 7-5
through 7-8 present the results for various stokers.
The measurement of nitrogen oxides and the errors associated with
these measurements have been described in Section 7.1. The direct
experimental readings were in parts per million. These were corrected to
the nominal 3 percent oxygen level and further corrected for water. The
results were then converted into an input specific value, ng/J or
lb/106 Btu by:
a. Knowing the higher heating value (HHV) of the fuel and the amount
of fuel consumed in a given period of time, or
b. Knowing the size of the boiler (the number of pounds of steam
produced in a given period of time and the exact relationship
between this with the HHV of the fuel, i.e., boiler efficiency).
As fuel consumption was not well documented, the unit conversion
constants used by the investigators (References 7-4 and 7-5) were based on
(b) from which they obtained a constant for each type of fuel for the
conversion.
7.3 EMISSION SOURCE TEST DATA FOR OIL-FIRED INDUSTRIAL BOILERS
Tables 7-9 through 7-15 summarize the results of various NO
A
emission controls as applied to a series of boilers burning residual oil.
The data were obtained from a large number of tests run on industrial
boilers under various EPA programs (References 7-1 through 7-6). The
criteria used for selecting these data are listed in Section 7.1.
Residual oils employed in these tests consisted of No. 5 and No. 6
fuel oil and two others, NSF oil and PS 300 oil, which both qualify on the
basis of viscosity as No. 5 oils. In addition to the effects of low excess
a1r on boilers burning residual oil, Table 7-9 shows the effects of two
differing No. 6 oils on the NO emissions of a watertube industrial
7-5
-------
TABLE 7-2. N0¥ EMISSION TEST DATA FROM PULVERIZED COAL-FIRED INDUSTRIAL BOILERS WITH LOW EXCESS AIR (LEA)
ActMl/DesIp
Nut Inawt
M (10* lu/tr)
53.5/15.9
UI2)/(22$)
7t.2/9i.«
(2*0)/(MO)
J8.1/76.J
(IM)/(2M)
117/147
(400)/(SOO)
38. 0/47. 2
(IM)/(?»)
38.0/47.?
(!»)/(?»)
12. 8/4*. 7
(II2|/(I60)
n. a/in
(320)/(40D)
Control
Net MM
IE*«
4.1-4.5
IE*
s.a-4.i
IE*
7.4-t.t
IE*
!.*-•. 1
LEA
4.5-3.4
IE*
4.1-4.0
IE*
5.1-1.4
l£«
3.4-1.1
Fuel Cherwterlltlct
Heat
Value
».S7'
(11.430)
2S.94
(11.1*0)
?7. S8
(It.BH)
28.59
(12.300)
31.70
<*.33t)
25.04
(10.77*)
24.9
(10,741)
30. M
(13.190)
«
•
1.40
1.34
O.S3
l.SO
0.73
l.M
0.93
l.SS
I
S
4.20
7.74
1.IS
l.M
0.11
l.U
0.12
2.92
f
tak
t.Jt
11. U
10. S
14.4*
10.04
14.4*
t.M
7.78
•Mkcr af
Tests*
1
1
1
1
1
1
1
1
Ittellw «, t»l55lo.s*
•4 «0?/J ( Ib «0?/10* Ity)
214
(O.S44)
2W
(0.688)
563
(1. 3D
21*
(O.M2)
201 <
(0.4*7)
244*
(0.5*7)
174'
(0.401)
494
(1.15)
Controlled W, EalsslORsk
•9 M>;/J (Ib «0;/IO> lt»)
Loo
--
--
—
--
--
--
--
"
HI*
--
--
--
~
--
--
--
"
Utrin
222
(O.S17)
103
(0.704)
$?»•
(J.2J)
212
(0.493)
1U'
(0.3S3)
197'
(0.458)
IM<
(0.314)
470
(1.09)
rcrcmt
IcouctloiiC
S
-2
t
2
2S
19
22
S
Control
level
Stwporteo*
lntemtdUt*
--
--
StrlnftM
Strlnont
StrlHojnt
Strlnofnt
toller
Itfentlflcttlo*
w1-"-- "•
i 12-20, T. vr
• 31-7. ». MT
» 11-2. ». HT
AhH (1.
SK. NT
AtH 11.
». HT
rramt N
», MT
120-42. Cy. WT
••MrilS
-
-
-•
Hulttfy*!
FuTMce
--
-
-
deference
7-1
7-1
7-1
7-1
7-7
7-7
7-7
7-1
I
en
nil retorte* te dlfOMCd In Section 3.
(>ce« oijroen, 1. first »«lue is til* excess ilr (bosellne) condition, second ««lue Is Iw etctss llr condition.
Mj/k, {Itu/idl .» received.
I. tinventljl: SM, single Mill Cy, cyclone
HI. oitrrtube.
' Cstloiite only, «0, xlyes «ssune H0? Is 51 of ton I (ml, w MS •eJiured).
• Vdy involve unacceptable operating conditions leading to high C(J and/or swilce emissions.
T-1575
-------
TABLE 7-3.
NOX EMISSION TEST.DATA FROM PULVERIZED COAL-FIRED INDUSTRIAL BOILERS WITH
BURNERS-OUT-OF-SERVICE (BOOS)
Actual /Design
Heat I"P"»
m (10* Itu/hr)
11. >/>«.?
(M1/U60)
jB.i/67.2
(130)/(?M)
Control
Method
MOS,*
MOS.I
Futl Characteristic*
NMt
Value
11. 58'
(11.H3)
S.04
(10.77*)
f
N
0.83
I.Ot
i
s
1.15
l.M
1
Ask
10.5
14.4»
•untfr of
Tests*
1
1
tasellne W. E»>
nq NO?/J (Ih »7/IO« Btu)
Ln>
--
„
Hloh
--
..
Avfr«9»
378*
(0.88)
144
(O.JT5)
Percent
W,
*eductlonc
34
tl
Control
IfWFl
Supportelf'
--
Stringent
Boiler
Identlf kjllon
1 31-7. SW,9
WT"
AIM »3
SU. Ut
Renurks
Only 3?I NO,
reduction
when collared
to baseline
•t SOS load
4t eicess 0?
Reference
7-1
7-7
All reported teitt nrre short-tero K3 Hr).
W, enltsliMt deternlMd by ck««« ((tu/lb) at received.
SH. tingle Mil.
" W. MUrtube.
• lurner pattern ? I 2, top rlahl flrln| air only.
1 Etthute only. M), values assuox «0? Is SS of total (only M) MS ocasured).
* Hay Involve unacceptable operating conditions leading to high CO and/or ante Missions.
1-1576
T-1576
-------
TABLE 7-4.
NOX :MISSION TEST DATA FROM PULVERIZED COAL-FIRED INDUSTRIAL BOILERS WITH LOAD REDUCTION (LR)
VtMl/Brilp
Heat Input
m (10* tt./fcr)
--/4J.»
--/(3JO)
--/147
--/(MO)
~/n.i
--/(?«)
../n»
--/(400)
--/»«
•/
«« W7/J (Ik Wj/IO* Itu)
20*
(0.4H)
?33
(0.541)
14?
(I.N)
4*4
(1.14)
M«'
(0.571)
M3*
(O.(54|
M4<
(0.613)
155*
(O.WO)
Controlled *», EnltlloHi11
«« «?/J ( Ik Wj/W* «t»)
lav
--
--
—
-
--
-
--
—
Hl«h
--
--
--
—
--
--
--
--
»»tr«ft
144
(o-jni
If/*
10. «H)
611
(l.«4»
4S4
(l.W)
1*7<
(0.4cet> Oj
5.41 eiceit 02
4.21 CICCM 02
Deference
7-1
7-1
7-1
7-1
7-7
7-7
7-7
7-7
00
• Oil reported teitt «re tngrt-Une «3 Or).
o M! ewUslont drtemlned by cnrntltfilnetcence In eM os<*s.
c l«frce«t rttetf lixil. flrtl >ilue It Meji (Md (kiwllne); wcond >ilue U In loed.
' HJ/tf (itu/lb) i\ received. .
4 SN. tlnglt Mil.
k M>. Mtertube.
1 dilute only, M), »
-------
TABLE 7-5. NOX EMISSION TEST DATA FROM COAL-FIRED INDUSTRIAL STOKERS WITH LOW EXCESS AIR (LEA)
Actual /Design
Heat Input
m (lo* itu/kr)
32.2/39.6
(110)/
•9 «02/J ( Ib NOj/10* Btu)
235
(0.547)
263
(0.612)
336
(0.7«1)
330
(0.767)
284
(0.660)
283
(0.6SS)
196
(0.456)
239*
(0.556)
293h
(0.681)
209 *
(0.036)
312"
(0.726)
Controlled •>„ lnHsJoni1'
ng «0?/J (Ik NO;/ 10* 6tu)
IM
--
--
"
—
--
--
—
--
-
--
-•
Nl^h
--
--
-•
--
-•
--
—
--
--
--
Aoertge
216
(0.502)
219
(0.510)
287
(0.66«)
219
(0.509)
202
(0.469)
219
(0.509)
142*
(0.330)
180"
(0.419)
215h.
(0.500)
Uf1
(0.305)
206k
(0.479)
P*rr*nt
1C,
leductlont
8
17
15
34
29
22
28
n
27
37
34
Control
Lrvrl
Supported
Intermediate
InterwdUte
MDderite
litlmnHttt
Moderite
--
Strlnoent
Strlciaent
Strlnotnt
Stringent
Strtn9ent
Boiler
Ideittlficltlon
» 11-1. SS9
' 11-1. SS
1 14-1, SS
• 14-4, SS
1 ?l-2. SS
• 21-3. SS
1 30-8. SS
Site A, SS
Site A. SS
Site 8. SS
IM-M«!l«m
1 ?. SS
Rmrks
Ln» Low)
Reference
7-1
7-1
7-l'
7-1
7-1
7-1
7-1
7-8
7-8
7-9
7.7
' All reported If Ml wre short-ten K3 hr).
* W, OTlstlons tfctemintd by chmlluilnesceiKe In alue It hltk eicess air (baseline) condition, second value Is Ion eicess air condition.
' MJ/ko. («tu/lb) as recetttd.
9 SS. spreader stoker; UTS. underfeed stoker; CGS. chain grate stoker; KS. vibrating grate stoker.
" CstlMte only. Ml, tallies tssuM M>? Is 5< of total (onl/ "0 MS Matured).
* May Involve unacceptable operating conditions leading to high CO and/or smke Missions.
Continued
T-1578
-------
TABLE 7-5. Concluded
AttMl/VeStfn
HMt Inpyt
m no* it./»r)
17.4/».l
(IO)/(!flO)
».;/«.*
(81)/(l«0)
3l.*74t.«
(10B)/(UO)
11.5/J3.4
(4t)/(M)
u.?/i7.»
(4S1/I60)
I1.S/I7.*
<4«)/(«0|
31.4/63.0
UO/I/UIM
S.0/13.?
Il7)/(4i)
Control
•till*
UAi
10.0-7.1
LEA
i.6-7.7
IU
!.*-«.*
LEA
1.4-1.0
IE*
i.6-4.<
IE*
9.8-8.0
LEA
».S-8.2
LEA
9.8-7.3
Fuel Characteristics
Meet
Value
?;.»'
(12.006)
M.S'
(8,408)
a.t
(1J.448)
».?
(10.B4Z)
».«
(11.610)
H.99
(11.610)
77 .(0
(11,873)
?«.!
(10.378)
S
l.M
O.M
1.J7
O.M
1.40
1.40
0.44
0.51
S
S
3.07
i.ts
?.a
l.M
O.H
O.M
3. OS
0.«J
«
Atk
*.w
t.u
7.M
7.M
».51
t.Sl
13.7
3.*?
MKr of
t«t»t
I
1
1
1
'
1
1
1
Incline »„ E>ltsloml>
fto W;/J | Ib M?/10* ft.)
2M*
(0.6H)
?*••
(O.S4»(
»;•«
(0.4*7)
»7K
(0.411)
1(3
(O.I7»|
m
(0.117)
100
(0.?3J)
123»
(O.Z90)
Conlrollrt •)„ (•Ittlomll
H, Wj/J (Ib W7/IO« (t«)
In
--
--
--
--
--
"
--
"
Htqh
--
--
--
--
--
--
--
--
A»tri)t
»•»
(O.MH)
It)*
(0.4»)
Ml*
(o.wai
?)»»
(0.1««)
117
(0.?7?)
lit
(O.J7SJ
96.5*
I0.77S)
US"
(O.K7)
fWCCTt
»•
«M)«CllOllc
11
a
16
-13
»
-18
4
6
Control
tewl
SatPportKKl
Interval l«tc
Strlnomt
IntcrwdUU
--
$trlnor»tt Oir9«i, I. first Mine Is High cicesl «lr (kaielfne) condition, tecond « eicetl , »«luei «SUK M); ll 5« of tot»I (only M> MS •etsured).
• Nay Involve unacceptable operating conditions leading to high CO and/or woke missions.
-------
TABLE 7-6. NO* EMISSION TEST DATA FROM COAL-FIRED INDUSTRIAL STOKERS WITH OVERFIRE AIR (OFA)
Actual/Design
Hut Input
Ml (10* Btu/hr)
M/36.6
(•2)/(lH)
24/36.6
(i2)/(l»>
30.5/63.0
(104)/(2IS)
28/63.0
(9S)/ttlS)
44.0/H.6
(isoi/ino)
(6.7/87.9
(?»)/( JOOI
30.6/46.9
) as received.
SS, spreader stoker, UfS. underfeed stoker; CSS. chain grate stoker; V6S. vibrating grate stoker.
estimate only, «0, values assume •>? Is 5( of total (only m MS measured).
May Involve unacceptable operating conditions leading to high CO md/or smoke (missions.
T-1579
-------
TABLE 7-7. NOX EMISSION TEST DATA FROM COAL-FIRED INDUSTRIAL STOKERS WITH LOAD REDUCTION (LR)
AciiMl/Onifn
HMt l«*nt
Ml (ID* lu/ftrl
•-/44.0
--/(ISO)
--/«.«
--/(ZOO)
--/».«
--/(K»J
--/».!
--/(IH)
--/».!
--/(100I
--/».J
--/(100)
--/•'.«
--Mm)
--/46.»
••/(I60)
--/46.»
--/(I60)
--/?3.4
--/(Ml
--/?3.4
--/(Ml
-/4.0
-/(H.5)
Control
Net ho*
««
100-80
11
lao-n
i«
76-SO
t*
6S.6-38.4
11
«0-M
U
«-60
LI
77 -if
I*
70-47.1
LI
67-49
LI
73.S-61
LI
76-S7.S
11
64.4-4?. 3
Furl Ch*r*ct«rltttct
NM(
••In*
30.47*
(13.110)
30.%
(13.320)
30 96
(13.320)
30.01
(U.M3)
».?
(8.704)
27.*
(12.0W)
24.5
(10.547)
28. »
(U.448)
1».S
(8.408)
28.8
(12.441
M.?
(10.84?
?4.S
(10.514
f
•
1.33
l.M
l.M
1.4*
0.78
1.30
1.01
1.37
0.68
1.35
0.48
O.S1
I
S
1.58
O.H
O.M
l.li
0.73
1.07
l.M
i.n
1.15
?.51
l.M
O.H
f
Atll
7.W
10.36
10. M
t.n
».»
*.(0
6.M
7.7*
».U
8.?4
7.M
S.14
••Sir y
t*ttl<
1
1
1
I
1
1
1
1
1
1
1
1
Incline m. dlttlm**
•f «2/J ( it Wj/IO* *U|
34*
(0.806)
36S
(0.840)
3*6
(O.W7)
m
(0.455)
774"
(O.*3f)
MS*
(0.756)
213k
(0.741)
J31"
<0.7M(
Z34*
(0.443)
MI"
(0.468)
2?7"
(O.S7«)
111"
(0.431)
Control IK) •>„ f.lnloKi'
14 «?/J (Ib H0f/\(f 8tu)
l«>
"
"
"
--
--
-
--
--
--
--
--
--
Hiy.
--
--
--
--
--
--
-
-•
--
--
--
--
Average
331
(0.786)
311
(0.770)
?*?
(0.*5S)
11*
(0.277)
?!»»
(0.50»)
7W»
(0.*7J)
tn»
(6.533)
?l»"
(0.501)
U3h
(0.4»)
171"
(0.3»7)
?39»
(0.556)
i?a"
(0.?»9)
^n-coit
»,
Infect lone
}
«
Z7
3f
W
11
n
34
?2
15
-5
?9
Control
lr»*l
SlOCwrtKf*
--
--
NoMrltf
Strlnint
Iitt*nitdl2
5.1-S.2X
eicett O^
8.41 eicest 0;
7.K eicets 0;
8.11 eicets Oj
8.0S etcess 0;
15. 21 eicess 0;
Reference
7-1
7-1
7-1
7-1
7-7
7-7
7-8
7-7
7-7
7-7
7-7
7-7
i
«j
KJ
• All reported tests «ere thort-leru «3 hr).
• HO. eaitslont determined by che»l Iminesrence In ill cites.
c Bised on iveriqe of III tests.
" Hodrrite. Interimliite or stringent levels discussed In Section 3.
* rrrcrnt loit). l.rM V If high loJrt (bisellne), second »llue Is Ion >Md.
' KJ/tt (8tu/lb) n rei»i«rd.
9 SS. spreiiler stnkrr. llfS, undrrfeed stt(*fr. CCS. chlln grlte sinker; VCS, vlbrltlng grite stoker.
" 1st mite only, HI, nihiri »:<,a* Ml; is 5S of tntll (only NO MS leisured).
Continued
T-1580
-------
TABLE 7-7. Concluded
1
— >
(jO
A. 1 1141 fto^iqn
Hrj| Iniml
•* 11(1* Bl.|.tir|
• ,'4.0
/I! S
/I7 6
-M*OI
--/I7 i
--/(Ml
/61.0
/(?I5)
•/*) 0
--.'(715)
--/I7.6
••/(to)
--/I7 6
-~/(nO)
••/I'.?
-/(«5)
-/I1.7
-•/(«•.!
timlrol
Melhnd
!•'
»?.4).S
III
100-711
III
70-53
I*
S6-44
III
49-3?
I*
SS J5
III
4S-?S
in
67-Tt
1*
•7-44
roel thararterUHcs
Heat
Value
» s'
|13,l?3)
?6.99
(li,6lO|
X 99
(li.6101
77.60
(li,R73)
V 60
(li.8'31
t\. S
(9,?76)
71. >
(1?, 1R7)
73 6
(10,14?)
Td.O
d?.o;3)
1
H
0.9S
1.40
1.40
0.94
0.94
1.10
l-?4
0.91
1.78
I
S
O.SD
o.w
0.86
3.05
3. OS
0.7?
?.79
0.03
?-8l
I
*rt
S ?9
9. SI
9. SI
13.7
13.7
S.I
11.03
3.9?
7.75
Number of
lesU*
1
|
1
1
1
?
7
|
1
dxellne NO. r«U^lnnsh
nq M)7/J IM< WI^/UP Hill)
TnS11
(n.MJ)
I9S
(0.4531
191
(0.471)
94 7
(O.??0|
14 1
(0.719)
IH711
(n.435|
)n4tl
(0.47fl)
tnjh*
(0. ?3S|
170"
(0.7791
(nn(riill,
flrftiif I •on*'
?6
7
37
16
-n
49
75
-?S
0
r>inlrr 37-10. IIT^
1 15-17 13. UTS
• f, 6. tr,s
I » «, res
UM-fau n.lre
t 1 , f r.s
IM f»i fUlre
I I. rr.s
iW-Stoot 1 7
vni
IM Slmil 1 7
»r.',
Denurlrs
IS S« e.
7.B-7.91 e«ces* 0?
II. 71 e
Refer e«re
7-7
7-1
7-1
7-1
7-1
7-7
7-7
7-7
7-7
• II reported leMi were short tern «3 hr). T-1581
' NO, e«t^»
-------
TABLE 7-8. NOX EMISSION TEST DATA FROM COAL-FIRED INDUSTRIAL STOKERS WITH REDUCED AIR PREHEAT (RAP)
*CtMl/»«lf»
HMJ Input
M (10* »t./*r)
24/31.1
(U)/(18)
24.2/M.f
(H.S)/U»)
Central
NKht4
vr*
Mt.SOM.l
w»
M1.4-1H.4
F«l CMrockn-Uttct
Nut
VtlM
».»'
(U.JW)
J0.0»
(12.213)
(
i
1.4*
I.W
1
S
t.ll
1.1*
1
Ml
t.n
J.71
le*t»«
1
1
•nellM m. blttlimk
•I »}/J (Ik n?/10> tt.)
1»
(0.4H)
132
(O.W)
CmtnIM W, teltttan*
•f «I/J (Ik M?/10* IU)
IM
--
„
m«i
-
— ^
ftrarm
162*
«O.W»)
U4«
(0.111)
NrctM
•i
I^MtlOTl
17
-Z
COTtrtl
U«l
s*»«-t^*
StrtafMt
StrlHfMt
klltr
l«t«tiric«ti«ii
1 304, SSf
i 30-a. ss
taMrilt
IS ocnt Oj
H MOM 0}
I
4*
• All r*portt4 Ittti «rt ikwl-ttn K3 Ir).
* •), Mlttlon *t(rBl«tf ky ckwriliMlmtcmct ta ill c«wt.
c i«s«f oi wtri«t of
-------
TABLE 7-9. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH LOW EXCESS AIR (LEA)
Actual/Design
Hut Input
m (10* ttu/hr)
2.0/2.1
(6.?)/(7)
3.2/1.1
(10.9)/(10.5)
5.1/5.3
(I7.4)/(18)
3.5/3.2
(ll.»)/(Il)
1.6/3.5
(5.5)/(12)
2.3/3.5
(7.9)/(12)
4.2/5.1
(14.2)/(17.S)
4.1/5.1
(14.1)/(17.S)
15/21
(5l)/<80)
10.S/13.2
(3»)/(45)
5.7//.S
(19.5)/<2S)
3.1/5.6
<12.4)/<19.2)
Control
Method
LEA*
5.4-3.)
LCA
3.J-l.f
L£A
7.Z-3.7
LEA
4.1-3.7
l£A
i. 1-2.0
LEA
S.9-3.2
UA
4.0-2.2
LCA
3.14.9
LEA
5.7-4.0
UA
3.0-1.*
UA
5.S-l.t
1C**
7.6-7J
Fuel Ouncttrlttlcs
Meat
«ark«
No. 6 oil
No. 5 oil
No. 5 oil
No. 5 oil
•0. « Oil
No 5 oil
Higher load
No. 1 oil
Different
Do. 6 oil
No. 6 oil
No. « oil
No. 5 oil
NSF oil
(Ho. S oil)
•eference
7-1
7-1
7-1
7-1
7-2
7-2
7-1
7-1
7-1
7-1
7-2
7-1
All reported tests were short-teni ( 3 hr). . T-isai
NO, eaissloni determined by cheat IwlMscence In ill cases. Continued
ff4&ed on average of III tetts.
Moderate, Intermediate or stringent loclt discussed In Section 1.
FlrM value, temperature (K) of baseline combustion air; second value, temperature (K) of RAP combustion «lr.
MJ/kJ (JU/lb).
FT, firatubei XT. MttrtiOt.
* Ha, involve unacceptitl* opcritfnq conditions Ifadtn? to hloh CO and /or saoke calislons.
-------
TABLE 7-9. Concluded
Actual/Design
H.4J InOVt
M (10* OU/kr)
n.i/».t
(100)/(12S)
24.J/29.3
(U)/(100)
15. 2/19.0
(52)/(*S)
21. 1/24.4
(72)/(90)
23.4/30.0
(80)/[10S)
34.9/41.9
(11*)/(1M»
I.S/20.S
(29)/(70)
35.5/44.0
(121)/(1M)
9.4/11.7
(32)/(40)
M.4/25
(S»)/l*S)
I3.8/17.1
(47)/(S9.2)
IS. 2/19.0
(S2)/(*S)
Control
Method
LEA
*.4-4.»
LEA
9.3-S.9
UA
4.7-3.0
UA
7.4-7.0
LEA
t.3-S.l
LEA
7.2-«.0
LEA
S.3-4.J
LEA
5.0-J.l
LEA
4.3-3.*
LEA
7.4-5.4
LEA
S.0-2.3
LEA
5.7-3.4
f«tl Ckoroctortsttci
MMt
«•)<•
-
42.*2
(11.331)
44.0
(10.930)
42.02
(10.420)
43.W
(U.910)
43. M
(10.910)
—
42.34
(10.213)
43. M
(10.773)
-
-
—
f
1
O.U
0.77
0.29
•.a
0.2t
O.M
—
0.31
0.30
0.32
0.31
0.31
1
S
I.1S
1.29
1.03
I.M
i.n
1.03
-
1.74
l.fl
0.31
O.U
O.U
S
A>k
O.QH
O.U
0.0*3
0.031
0.032
0.032
—
0.03
0.07
0.010
0.014
0.014
Tnti<
1
1
1
• 1
1
1
1
1
1
1
1
1
OwtliM •. ErtMlfn*
^ Hl/J (It •}/!•* Ot«)
!•
(1.4401
ta
(O.M)
m
(0.247)
13*
(0.321)
142
(0.330)
133
(0.300
Hi
(O.IW)
«.*
(0.1H)
in
(0.2M)
IN
(0.4M)
362
(0.043)
210
(O.OS1)
C«rtnll«l •, EBtujmk
«« «i/J (M Mt/N* *U)
UK
-
--
—
—
--
—
—
"
"
—
—
—
It*-
--
--
«•
—
—
—
--
~
--
-•
—
—
**r«t.
170
(0.414)
»
(O.S23)
!?244)
121
(O.JK)
11*
(0.2W)
131
(0.304)
101*
(0.23S)
M.4
(0.159)
100
(0.234)
14S
(0.337)
301
(O.H9)
2W
(0.5*1)
PorcoM
MuctlBK
1
12
1
12
M
2
12
-2
*
23
17
11
Control
<*•' ^
SWIOrto*
-
-
lotoraoltato
•Morolo
IMoroto
—
Iitomdltu
Strlngoiit
lntomodltU
—
—
-•
Oollor
l«»H1flMt1o»
1 2-*. Iff
* 27-1. Iff
1 lt-2. NT
f 10-2. Iff
f 10-3. Iff
f 11-4, KT
f 20-1. Iff
1 2f-S. NT
1 37-2. NT
f 7-3, Iff
1 2-2. NT
t 2-4. NT
—
n 300 *n
(M. $ •)))
K 300 til
(••. S .11)
•*. ( oil
•>. ( oil
to. * oil
«•. ( oil
No. ( oil
No. i oil
No. i oil
No. S 011
PS 300 oil
(No. S oil)
PS 300 oil
(No. 5 oil)
Nororooct
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
• All reported tests «tr« start-ten ( 3 kr).
* NO, Millions dtter.ined by dMalluilMscoiKt 1* oil ctses.
c ««s«d on «er«9e of ill tests.
« Nooer«te. Intermediate or strlnoent levels discussed In Section 3.
« Eicrss oiyaen. t, first v«lut Is high Meets •<« Is Ion eicess «lr condition.
' HJ/ka («tu/lb).
9 FT. firetube; XT. Mtertube.
• H*r Involve MuccepUble ooeritlng conditions leidtng to high CO ond/or eoote eeilsslons.
T-1583
-------
TABLE 7-10. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH STAGED COMBUSTION
AIR (SCA)
Actual/Design
Meat Input
HI (10* Itu/hr)
1.8/3.5
(*)/(!?)
1.8/3.5
(6>/<12)
4.0/5.1
4.J/S.1
11.1/13.2
Control
Method
SCA*
a)- 0.76
SCA*
a>- 0.6S
SCA'
SCAf
SCA'
Fuel Characteristic*
Heat
Value
44.679
(19.219)
44.67
(19.219)
43.82
(18.780)
43.82
(18,780)
42.92
(18.466)
f
*
0.26
0.26
0.23
0.23
0.31
t
S
0.32
0.32
0.60
0.60
1.88
I
Ash
0.01
0.01
0.034
0.034
O.OS
ImmAer of
Tests*
1
I
1
1
1
Baseline HO, emission!*
ng M;/J ( Ib W2/10* 8tu)
96.2
(0.224)
96.2
(0.224)
120
(0.200)
120
(0.280)
168'
(0.390)
Controlled NOX emissions0
ng NO^/J ( Th NO^/10^ ttu)
Ion
..
SI 9
(o!wi»
__
„
..
....
„
51.9
(0.121)
...
._
Average
49.0
(0.114)
SI. 9
(0.121)
84.9
(0. 197)
70
(0.162)
97.41
(0.227)
Percent
•eduction'
49
„
29
42
42
Control
Level
Supported4
Stringent
Stringent
Stringent
Stringent
Intermediate
toller
Identification
1 KCC, FT*
1 KCC. FT
• 19-1. Iff
1 19-1. NT
f 38-?, Iff
•emarks
to. S oil
21 eftcets 0?
Lance depth 2.S
to. S oil
4.4( eiceti
-------
TABLE 7-11. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH BURNERS OUT OF SERVICE
(BOOS) (Reference 7-1)
Actual/Design
Heat Input
m (10° Itu/hr)
13.8/17.3
(47)/(59.2)
14.9/19.0
(50/165.0)
14.4/24.9
(49)/(84)
M. 9/46. 9
(119)/(ltO)
22.3/30.8
(76)/(10S)
17.6/26.4
(60)/(90)9
8.5/20.5
(29)/(70)
21/44
(701/1150)
Control
Method
•DOS
HOS
BOOS
MOS
BOOS
WOS
BOOS
BOOS
Fuel Characteristics
Heat
Value
..!*
„
_.
43.96
(18,910)
41.96
(18.910)
42.82
(18.420)
..
42.34C
(18.213)
I
1
0.31
0.18
0.32
0.26
0.2*
0.2«
..
0.31
1
S
o.u
0.63
0.35
1.03
1.03
1.04
„
2.74
*
Ash
0.014
0.014
0.010
0.032
0.032
0.031
._
0.03
Mater of
Tests'
2
1
2
1
7
1
3
1
Baseline NOK Ctrissionsb
no. N02/J ( Ib M>2/10> Btu)
363
(O.M5)
275
(0.640)
192
(0.446)
133
(0.309)
134
(0.311)
138
(0.321)
128
(0.299)
145
(0.337)
Controlled NO. E«lssions°
ng NOZ/J (III «2/l<>* Btu)
LOH
294
(0.684)
_.
139
(0.322)
„
122
(0.283)
125
(0.291)
High
346
(0.807)
153
(0.356)
..
128
(0.321)
__
137
(0.244)
Average
320
(0.744)
248
(0.577)
146
(0.340)
94.2
(0.219)
127
(0.296)
98.2
(0.228)
130
(0.303)
104
(0.243)
Percent
"0.
•eduction":
12
10
24
29
S
29
-2
28
Control
Level
Support***
„
..
Interned* it*
Note-it*
Interacdtit*
Noderit*
Interned lite
toller
Identtrtcitlon
1 2-2. MTf
1 2-4. MT
1 7-3, WT
I 18-4, HT
t 18-3, Ifff
i 18-2, m
1 28-1, WT
< 29-5, Wf
HcMrki
TMO rowt of 3
burners, sUojered,
•Iddle top burner
on tlr only: PS 300
(NO. S oil)
TDO ron of 3
burners, staggered.
• Iddle bottoB burner
on ilr only. PS 300
(No. S oil)
Single row of 4
burners, • diddle
burner on «lr only.
(No. S oil)
TV ron of 2
burners one top
burner on air only
(No. i oil)
Tw rows of 2
burners, one ton
on air only. No. 6
oil. Excess 0? 6X.
One row of 3 burners.
center burner on air
only. No. 6 oil
One rw of 3 burners.
center burner on air
only. No. 6 oil.
Excess 03 61
TMO burners top
burners on air only.
No. 6 oil. Excess
0? 5.51
I
t-*
CO
* All reported tests were short-ter« ( 3 hr).
t> NO, Missions determined by cheatluannescence In all cases.
c Based on average of all tests.
d Moderate. Intermediate or itrtnj« 10* Itg/hr, 7.4S excess 02. IMS at 60 « 10* Itu/hr, 8.21 excess 0;.
T-1589
-------
TABLE 7-12. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH FLUE GAS RECIRCULATION
(F6R)
ActiMl/Deslgn
He«t Input
Ml (10* Itu/hr)
1.2/3.5
<4)/(12)
1.2/1.5
(4)/(12)
1.2/3.5
(4)/(12)
1.1/3.5
(O/(12)
1.1/3.5
<()/(12)
1.1/1.5
(10.5)/(12)
2.1/7.1
<10)/{»)
1.1/1.3
((.5)/(H)
4.4/7.3
(»)/(»)
«.«/;.!
(15)/(25)
4.2/5. 1
(14.4)/(17. i)
4.2/5.1
<14.4)/(17.S)
Control
Nethotf
F«, 2»e
F«, 401
f«. SIS
F«. 2H
FBI. 4M
m, ax
r«, ns
FCR. ITS
F«. U
Ftt. 24*
F(i. 201
Ft*. 1M
Fuel CMrKterlstlcs
Mett
«•
Reduction^
0
11
13
24
24
21
11
20
-2
1
15
S
Control
Le«el
htporteil'
InteratdUU
Interaedltte
Strlntnt
Stringent
Stringent
Stringent
Stringent
Stringent
Stringent
Stringent
Stringent
Stringent
•oiler
Identification
1 ECCC, FT?
1 CCCC, FT
1 ECCC. FT
» ECCC. FT
» ECCC. FT
• ECCC. FT
f fCCC. HT
f CCCC, WT
1 ECCC. HT
1 ECCC. MT
1 M-l. Iff
1 19-). WT
•e«rks
No. 5 Oil
do. 5 Oil
Mo. 5 oil
Do. 5 oil
No. 5 oil
Ho. 5 011
No. 5 oil
No. 5 oil
No. 5 oil
No. 5 oil
Stew
itonlMtlm
No. 6 oil
Mr
•tomlzttlon
No. ( oil
Reference
• 7-2
7-2
7-2
7-2
7-2
7-2
7-2
7-2
7-2
7-2
7-2
7-1
All repartee- tettt «ere snort-tor* ( 1 nr).
to, Missions tttemlnetf ojr ckeeilIwlnesceiK* In ill
*
-------
TABLE 7-13. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH COMBINED FLUE GAS
RECIRCULATION AND STAGED COMBUSTION AIR (FGR/SCA) (REFERENCE 7-3)
Actual/Design
Meal Input
m (10* Itu/hr)
4.J/5.I
(14.6)/(1?.S)
4.3/S.l
(l4.6)/(i;.S)
4.3/5.1
(14.6)/(I7.S)
Control
Method
FGIt. 23. l«
SCA.
*| • 1.01'
FGR, 231
SCA,
«*• 1.1
FGII. 19.61
5CA.
*, - 1.21
fg»l Characteristics
Hut
Vlluc
43.849
(18.850)
43. M
(18.790)
43. U
(18,780)
t
"
0.22
0.21
0.23
I
S
0.40
0.60
0.60
*
Ash
0.0»
0.034
0.0)4
•urtwr of
T«tl<
1
1
1
easellne «0, (•1sslgns°
•1 »2/J ( Ib M>2/10* Itu)
120
(0.210)
130
(0.303)
130
(0.303)
Controlled "0. £«Hslonjb
n, Wj/J (Ib Mj/lflC Itu)
Lw
..
„
„
High
..
..
._
A«*ra9«
90. 5
(0.210)
69*
(0.16)
65*
(0.151)
Peretnt
HI
RtductlonC
2S
S3
50
Control
le»l
StMorttd*
Int«rattfl4tt
Strlnoent
Strlnfent
toller
Mntlflcitlon
1 U-l. HI*
1 1»-1. HT
1 H-l. NT
ICNTtl
Ro. ( ell
4.21 e>c«> Of
IMC* . ( oil
1.91 cicnt Oj
Lwc* depth 2.1 •
*>. ( oil
1.51 t»ct«s Oj
Ltnct depth 1.2 •
I
ro
O
All rfported tctts Mre ihort-tfr« «) hr).
MJM e*U*tofls dcterained by cheallunlnetcence In •!! cases.
8«^ed on «ver«9e of ill le&ts.
Hodertte. Interaedute or stringent levels discussed In Section 3.
M«ss percent flue g«s rec1rcul«tlon.
g • Ciiulxlence ratio, defined n ritlo of stolchlonctrlc
-------
TABLE 7-14. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH REDUCED AIR
PREHEAT (RAP) (REFERENCE 7-1)
Actutl/Dcilo*
Httt Input
m (10* Itu/kr)
•.1/13.2
*.4/11.7
Control
Nrthod
M**
430-350
KAf
3I1.S-31S.4
Fwl CMroctcrlttlct
Heat
Vilut
44.oV
(19.H7)
45.07
(U.3M)
t
"
0.4t
0.30
1
S
0.11
l.fl
s
to*
0.01
0.07
Mxr of
Tntt*
1
1
Oascllnc NO. Emissions^
•f M)2/J (IbkDj/lO* Ita)
U3
(0.425)
109
(0.2541
Controlled W, e>lsil«nb
nj W?/J (Ib «0?/IO* llu)
LM
..
..
Nlok
„
*""•"
153
(0.1SS)
104
(0.241)
•crcent
«.
li
S
Control
Lml
_
NoocriU
•oiler
Identiricotlon
»-2. KTl
37-2. HT
•Hurts
No. f oil
Euesl 0; JS
No. i oil
hcn> oj n
I
ro
All reoorteC tettf Mr( iaort-ttn K3 hr).
tO, CBliSloul detemlned by dmllMttoitcooco li «I1 CMM.
lisetf on •>«•••> of «ll tcitt.
Noderitc. IntcraodUto or ttrlnornt Icnh tfltcuiM* l« Swtlon 3.
first >iluc. toiMritort («) of bisollnt OMtaistlail «lr; MCOT4 >ol«
T-1SK
NJ/k) (Itu/lb).
HT, Mtortvkt bollor
toawrtUr* («) of M» contwttlon ilr.
-------
TABLE 7-15. NOX EMISSION TEST DATA FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS WITH LOAD REDUCTION (LR)
(REFERENCE 7-1)
Actwl/DMlfR
Hut Input
M (I0< Itu/lr)
-/S.O
•/(17)
-/3.1
-/M.S)
-rt.3
-/o*)
-«.}
-/(!•)
-/i.i
-/(ID
-/«.»
-/(«)
-/».4
-/(W)
-/30.B
-/(IDS)
-/«.»
-/(ISO)
Control
Netted
IM
i2*-7i
w
IM-tt
M
*-«
U
*-»
u
77-JO
U
6»-4«
It
80-4f
M
7*-44
L«
75-45
Ft»l Characteristics
NMt
Viluc
43.77'
(IS.S30)
43.*l
(IS.7JO)
42.31
(11.200)
42.31
(i8.2»)
42.31
(IB, 200)
••
42.82
(1S.420)
44.00
(18,930)
44.00
118.930)
1
0.21
0.20
0.10
0.10
O.K
0.32
O.M
o.n
0.29
1
s
1.72
1.30
1.4.
1.4*
1.4«
0.3S
1.04
1.03
1.03
I
Alh
O.MS
0.21
0.007
0.007
0.007
0.010
0.031
0.043
0.043
•••her of
T«t|4
1
1
1
1
1
1
1
1
1
latellne an, Emissions*
•f N02/J (IbWj/lO* |tu)
120
(0.27«)
104
(0.243)
N.«
(0.232)
90.9
(0.211)
n.t
(0.232)
115
(0.42«)
160
(0.372)
176
(0.410)
144
(0.335)
CoMrollCtf "0, (•lHl«l
M| *>1/1 (It M^/IO* lt«)
IM
--
—
*~
*•
—
"
—
—
"
HI*
"
—
*•
-•
"
"
-
--
"
fcrerlft
104
(0.241)
»7.«
(0.?27)
H.4
(0.201)
§7.0
(0.2WI
M.«
(0.211)
141
(9.17*1
101
(0.2SO)
123
(0.287)
180
(0.41»)
Ffrceot
Itatoc'tloiic
13
«
14
4
10
24
13
X
-25
Control
level
Supported*
Intemedlite
IntinH. 1 all
Emu 0; 2.51
Nt. S all. air
•toalMtlo*
Cum 0; 7.31
*> S Oil. It««
•tOHltttlon.
F.HCMI O^ 71
No. 5 all
ficm Of 7.51
do. 5 ell
Cicvt* Oj 7.71
frdwitcd ilr
Ho. (all. F.u«s 0?
8.51. rre*w
r\j
• 111 reoorted tetts "ere short-tera K3 hr).
D MOK cMfsslons detemtned by chetllu»lnescence In all oses.
c lated on averaoe of all tests.
« Hoderitc, Intermediate or stringent levels discussed In Section 3.
' Percent rated load, first value is high load, second value Is Ion toad.
' MJ/kg (Itu/lb).
9 n. flretube; MT. Mtertube.
Continued
T-1593
-------
TABLE 7-15. Concluded
Acliul/oesit*
Kelt Input
M (ID* Itu/kr)
-744
-/(ISO)
-/I7.1
-/(*»)
-/H.O
-/(«)
-/*.«
-/(!»)
-/S.I
-/(!».*)
•/Z3.4
-/(»)
-/».!
-/(IW)
-/l.S
-/(«»
-/7.1
-/(»(
Control
Netto*
U«
79-47
I*
100 -»1
ut
77-H
11
W-30
L«
n-ss
Ul
75-41
l«
•s-ss
Ul
92-4*
U
?4-»
Fu»l Cktrictcrlitlci
Hut
VllM
47.13'
(11.211
—
~
-
4?. 49
(11.210)
41.14
(11.5*0)
47.62
(ll.JJJ)
44. M
(W.07S)
44.40
dt.099)
I
K
0.11
-
-
0.5?
0.44
O.J7
0.77
0.04
0.15
«
S
2.74
O.H
O.M
1.15
2.10
1.51
l.Zt
0.*7
0.7$
I
Alh
0.01
0.014
0.014
0.02f
0.044
0.012
0.10
0.04
0.02
Mwr of
T«lU«
1
1
1
1
1
1
1
1
1
Itsclln* W, btlislmsl>
»t M;/J (lkMi./10» Itu)
Ii5
(O.M4)
241
(0.5*0)
1M
(0.614)
215
(0.500)
21*
(0.510)
l«4
(0.42t)
2S7
(O.SM)
170
(O.iW)
71.?
(0.1M)
Control !»(! W, t»l»
119 M>2/J (It H0;/I0* Itu)
IM
"
--
--
"
"
"
"
--
Ht«h
--
—
—
--
—
--
~
-
"
A>CT>««
145
(0.3171
??5
(O.S21)
110
(0.62S)
197
(0.4-4)
710
(0.4M)
155
IO.X1)
746
(O.S71)
110
(0.7 H
No. 6 oil.
Euess Q; M
PS 300 (No. 5) oil
Cicets 0; 91
No. 5 oil. ficen 0}
4f (Mtrtuct 7-2).
No. 5 oil Eicess
-------
boiler. The fuel characteristics columns exemplify the differences in fuels
that, due to viscosity, are both labeled as No. 6 oils.
Data on NO emission controls as applied to boilers burning
A
distillate oil are contained in Tables 7-16 through 7-20. The tests were
selected because they best fitted the criteria for selection listed in
Section 7.1. All of the data resulted from two EPA sponsored field
investigations and one subsequent study of a boiler with major modifications
(References 7-1, 7-3 through 7-5).
All distillate oils used were classified as No. 2. All had
comparable higher heating values and sulfur, nitrogen, and ash contents.
7.4 EMISSION SOURCE TEST DATA FOR GAS-FIRED BOILERS
Emission source test data for NO controls on industrial boilers
A
burning natural gas are presented in Tables 7-21 through 7-27. A large
number of tests were conducted using this fuel under various EPA sponsored
programs (References 7-1 through 7-5). The criteria whereby these tests
were chosen as representative were presented in Section 7-1.
7.5 DEVELOPING EMISSION SOURCE TEST DATA
EPA is currently sponsoring several field test programs demonstrating
combustion modification NO controls for industrial boilers. These
A
programs include identification of optimal combustion conditions for 11
stoker coal-fired boilers, sponsored jointly with the Department of Energy
(References 7-8 and 7-10), and field demonstrations of the TRW low NO
burner for both oil- and gas-firing (References 7-11 and 7-12). The
imminent results from these studies should help fill some of the data gaps
identified in this study. In addition, several other field tests of these
and other combustion controls are being planned, including 30-day continuous
monitoring programs (Reference 7-12). The results of these and other test
programs should be monitored and incorporated in future updates of the
assessment of combustion modification NO controls.
A
7-24
-------
TABLE 7-16. NO EMISSION TEST DATA FROM DISTILLATE (NO. 2) OIL-FIRED INDUSTRIAL BOILERS
WlfH LOW EXCESS AIR (LEA) (REFERENCE 7-1)
Actual /Design
Heat Input
m (106 etu/hr)
1.6/2.9
(5.5)/<10.0)
2.7/5.9
(9.3)/{20.0)
3.3/3.2
(11.3)/(11)
4.7/5.3
(1S.9)/(18)
4.6/5.3
(15.W(18)
2.0/2.1
(6.7)/<7)
3.2/3.8
(11)/(13)
5.4/8.5
(18.S)/|».0)
7.0/8.5
(24.0)/{29.0)
4.2/8.S
<14.5)/(29.0)
6.9/8.8
(23.5)/(X)
4.1/5.1
(14)/(17.5)
4.1/5.1
(14)/(17.5)
3.4/5.1
(ll.«)/(J7.5)
25.8/32.2
(88}/(110)
Control
Method
LEA*
5.6-3.6
LEA
5.2-2.7
Baseline
«-7
Baseline
8.0
Baseline
a.o
Baseline
6.8
Baseline
3.1
LEA
5.9-4.5
LEA
3.8-2.7
LEA
1.2-5.1
LEA
5.9-2.8
LEA
3.4-2.6
LU
3.0- l.S
LEA
4.3-3.7
LEA
5.7-3.8
Fuel Characteristics
Meat
Value
_.f
-
45.12
(19,410
45.12
(19,410
45.12
(19.410
45.12
(19.410
45.12
(19.410)
45.19
(19.440)
45.19
(19.440)
45.1»
(19.440)
-
45 .26
(19.470)
45 .2f
(19.470)
4S.26
(19.470)
44.45
119,340)
I
--
-
0.02
0.02
0.02
0.015
0.015
0.04S
0.045
0.045
0.031
0.006
0.006
0.006
0.01
t
s
0.23
0.30
P.48
0.48
0.48
0.36
0.19
0.40
0.40
0.40
0.22
0.06
0.06
.06
.18
t
Ash
-
-
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.001
0.001
0.001
0.001
0.004
Nutfwr of
Tests*
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baseline NO, Emissions"
ng Wj/J (IS NOj/lO* Btu)
96.5
(0.224)
107
(0.248)
70.5
(0.164)
63.8
(0.149)
65.0
(0.151)
70 .0
(0.163)
46.4
(0.108)
54.4
(0.127)
48.2
(0.112)
59.5
(0.138)
69.0
(0.1M)
37.0
(0.086)
51.0
(0.119)
46.0
(0.107)
102
(0.236)
Controlled NO. Emissions"
ng HO,/J (It. H>?/106 Btu!
LOW
"
-
-
-
-
-
~
--
-
-
-
-
-
—
High
-
-
-
-
-
-
-
-
-
-
-
"
-
-
—
Averftge
85.8
(0.200)
81,3
(0.189)
-
-
--
--
-
SI. 6
(0.120)
47.7*
(0.111)
51.6
(0.120)
58.3
(0.136)
35.9*
(0.083)
50.5
(0.117)
46.0
(0.107)
93.7
(0.218)
Percent
NO,
Reduction0
11
24
-
-
-
"
~
5
1
11
16
3
1
0
8
Control
Level
Supported*1
Moderite
Moderate
Moderite
Interned lite
Interned utt
Modertu
Intermediate
IntenMdUtt
InterwdUU
Intermediate
InterwdUte
Stringent
Intemedtat*
IntemodUu
--
Boiler
Identification
«-2. FT9
*4-4. FT
26-2. FT
26-1. FT
Z6-1, FT
23-1. FT
24-TV, FT
fl-1. NT
«-l, «T
ll-i, HT
«-3, NT
t 19-1. HT9
f 19-1. UT
1 19-1. VT
1 17-T-8, UT
Reaurks
No lir preheat.
No air preneat.
Air atomltation
Air atoflrization
Air atoorizatlon
Atr ttoMizatlon
A1r ato»4>ation
Me air preheat.
Higher load.
Ho air prehut.
do air preheat.
Steam atoaifzation.
Ho air preheat.
Air atqariiition.
No air preheat.
Mechaniied atmlzation.
•o air preheat.
I
ro
tn
' Alt reported tests Mere short-ten ( 3 hr).
° NO, eaUsions determined by cMmlluminetcence in all cases.
' Based on average of all tests.
d Noderate. Intermediate or stringent levels discussed In Section 3.
' Eicess oiygen. 1. first value Is high excess air (baseline) condition; second value Is lev encess air condition.
' MJ/kj (Itu/lb).
9 FT. ftretube; UT, wtertube.
•May Involve unacceptable operating conditions leading to high CO and/or smoke Missions.
-------
TABLE 7-17. NOX EMISSION TEST DATA FROM DISTILLATE (NO. 2) OIL-FIRED INDUSTRIAL BOILERS WITH FLUE GAS
RECIRCULATION (FGR) (REFERENCE 7-3)
Acted/Onion
Nut Input
Ml (10* ItK/kr)
4.3/S.l
4.3/S.l
(!4.e)/(17.S)
Control
NttNod
FBI. IBS*
fw, us
Fuel CiMrKterlitlci
MMt
•nine
45. H'
(It.oM)
4$. 78
(M.MO)
t
II
0.008
All report^ Uttt «rc itart-tera K3 N-).
•0, nluloits *trr*lM« by ctw»iluiilmtaKi In ill C4i*t.
8
-------
TABLE 7-18.
NOX EMISSION TEST DATA FROM DISTILLATE (NO. 2) OIL-FIRED INDUSTRIAL BOILERS WITH STAGED
COMBUSTION AIR (SCA) (REFERENCE 7-3)
Actual/Design
Neat Input
m (10* ItWkr)
4.3/S.l
(14.5)/(I7.S)
4.3/S.l
(14.S)/(17.$)
4.3/5.1
|14.S)/(1?.S)
Control
•kthod
SW. f>| •
I.04*1
SCA.
«•• • 1.10
SCA.
«>i • J.w
r«el CharacUrlstlcs
Hrat
•altt
45. «l'
(l».«10
n.n
(H.MO
45.78
II*.MO;
(
0.008
cess (b 3.1*
Lncc oapth. l.( •.
Eicest 0? Ml
Lance depth ?.l •.
Ctcess 0; 3f .
loice depth. ?.I •.
ha air preheat.
•vj
ro
• All report** ttitf «*Te short-tern «3 br).
IB, emissions determined by cheat luminescence 1* all c
-------
TABLE 7-19. NOX TEST DATA FROM DISTILLATE (NO. 2) OIL-FIRED INDUSTRIAL BOILERS WITH COMBINED FLUE GAS
RECIRCULATION AND STAGED COMBUSTION AIR (FGR/SCA) (REFERENCE 7-3)
W ($ iwir)
4.1/S.l
(I4.»)/(17.I)
4.1/i.l
CMtrol
Ntthtt
ran. K.it*
*io^*"
soT
*• 1.1
r«t OUTMtirUtki
*•»
«•!«
..
(lt.«10)
1
i
• »
0.001
f
s
•••
0.14
f
Mil
^^
0.001
"SS."
1
1
l«Mll«* M. [•ltt(|Hlk
•1 «t/J (Ik W,/IO» tU)
(7.4
(0.1S7)
•7.4
(0.1S7)
CwtralM •), tal«»t«m*
•I «Oz/J (Ik Wj/10* lu)
LOB
^^
-
Hl|k
„
-
«nr*«i
II •
(0.041)
K
(•.OX)
».
n
77
C«*tr«t
StrlRftot
StrlnfMI
Itfntlflutl**
U»-l, «*
t!9-la tff
Htwrtt
EKCIS Ov }.n.
IMC* «*»tk. 1.2 •.
bent 0; Z.SS.
l«Kt *ptll. Z.I •.
to *1r yrctiHt.
ro
00
> All r**grtt4 M«l< Mr* tkart-tcrat KJ kr).
* NO, million «Ur«l»< by dwdi Iwlitumc* I* »I1 cnm.
c ttttt » tfatft of ill tciti.
' NodrrtU. lilcratdlttc or tlrlHfnt l«wl« *\\a»M*t In Itcttt* 1.
• H«i ptrcc«t flu* t" rtctrcnlitH.
' CqulMloiM r«tl«. 4triM4 « r«l» «T (Mlditaartrte
-------
TABLE 7-20. NOX EMISSION TEST DATA FROM DISTILLATE (NO. 2) OIL-FIRED INDUSTRIAL BOILERS WITH LOAD
REDUCTION (LR) (REFERENCE 7-1)
Actuil/Deslfn
Nett Input
m (10* Ittt/hr)
-/2.»
-/(10.0)
•n.1
•/(»)
-/».$
-/(»)
-/a. 5
-/(W)
-/sa.«
-/(ZOO)
•rtt.l
-/(lU)
•/M.2
-/(HO)
Control
Method
70-30<
K.5-44.5
M-M
H-50
45-11
W-71
W-X
fuel OurKUrlstlct
Hut
Vilue
..f ,
—
45.1*
(H.440)
45. l»
(U.440)
45.07
(H.JW)
--
44. W
(19,3«)
I
*
--
—
0.045
0.045
0.011
0.01S
0.01
I
s
0.21
O.JO
0.40
0.40
0.11
0.21
0.11
«
«ik
--
—
0.001
0.001
0.001
0.005
0.004
ta*«r of
T«tl<
1
1
I
t
1
1
'
liwllnt "0, [•Uslomk
n« «Oj/J ( Ib «0?/10» Itu)
«5.«
(o.?ni
I0f
(O.M7)
44.1
(0.103)
4s.a
(0.111)
51. J
(0.1X)
151
(0.3S1)
114
(0.2*5)
Controlled IDg emissions*
nq W?/J (Ib IB?/IO« Itu)
lce» 0; 1.41
•o 4lr preheit.
(iceii 0? 41.
•o «lr preknt.
C>ce» 0> 51.
No 0> M.
^J
ro
4 AM reported tests Mre skort-teni K3 hr).
l> •), Missions detervlned by ckralIwlnescence In •)! CIMS.
c lisrd on »er<4e of «ll tests.
* HoOfttt. Intenwdlite or strlnoent levels discussed In Section 3.
• Fercent rtted lotd. first xlue Is hlaH lo lo«d.
' NJ/fcg (Itu/lb).
I FT, rtrttube: HT, Mtertube
T-15M
-------
TABLE 7-21. NOX EMISSION TEST DATA FROM GAS-FIRED INDUSTRIAL BOILERS WITH LOW EXCESS AIR (LEA)
ActMl/Oeslgi
Meet Input
m (10* tte/kr)
1. «*/?.!
(S.OW10.0)
4.1/S.t
(14.0)/(20)
Z.t/i.t
(t.0)/(20)
2.1/2.I
<».0)/(10.0)
l.»/2.1
(t.«)/(8.0)
l.i/1.1
(12.4)/(N.S)
5.0/S.l
<17.2)/(U)
l.OS/1.2
(M.4)/(ll)
1.I/3.S
(l.B)/(U)
Z.0/3.5
<«.»>/( 12)
Control
Natkod
UM
1.0-1.*
in
*.»-0.7
UA
*.o-».»
u*
S.l-l.t
LEA
11.0-1.2
LEA
4.1-1.1
LEA
7.2-2.7
IE*
3.«-2.»
LEA
ii.s-a.o
IEA
*.0-«.S
fwl Characteristics
NMt
lalM
*.«S»
(UOS)
x.os
(INI)
M.fS
(ll«)
3t.«5
3».H
(IMi)
11. W
(«M)
U.«
(M4)
11 .n
(«M)
_
„
I
•
"
_
«
..
_.
_
„
„
_
..
I
s
»
w
..
^
—
..
M
..
„
..
«
Art
-
__
_
..
..
..
..
._
„
•M*tr of
TttU*
1
1
1
1
1
1
1
1
1
1
laMllw Ml. iBlulank
«H«t/J (IkHz/lO* »U)
S1.0
(0.11»)
H.I
(O.IM)
SZ.5
(o.iwi
M.(
(O.OM)
ll.«
(O.OM)
31 .«
(0.074)
».(
(O.OM)
4/.«
(0.111)
53. t
(0.114)
S2.0
(O.U1)
CoMrolM «O, EBl»l«i>k
«»H)j/J (Ib Wj/IO* nil)
Lw
-
..
„
„
..
._
„
..
_.
..
mik
-
M
..
M
..
..
..
..
„
..
ftnurm
11.7
(0.07S)
40.1
(O.OM)
41.1
(0.101)
!0.4*
(0.«4»)
M.O
(O.W4)
».(
(0.070)
X.l
(O.WO)
48 .4*
(0.111)
44.4
(0.10*)
45. »
(0.107)
hrcMt
•>•
M
-------
TABLE 7-21. Continued
Actual/Design
Neit Input
M (10* Itu/kr)
4.9/8.S
(23.i)/(«)
5.0/1.5
(17.0)/(M)
3.Z/7.3
(11.0l/(«)
K/H
(W)/(110)
4.1/5.1
(14)/(17.S)
47/59
(1M)/(200)
2.9-4.1/7.3
(10-I4)/(25|
7.0/«.l
(?4)/(30)
40/47
(1)S)/(1M)
23/M
(77)/(130)
44/73
UW)/(250)
12/13
(40)/(4S)
Control
Netnod
UA
4.5-1. «•
LEA
t.4-2.2
LEA
1.9-5.0
LEA
f.1-2.0
LEA
3.2-2.0
LEA
J.7-1.3
LEA
..3-2.4
LEA
5.7-2.7
LEA
3.1-2.C
LEA
i.l-t.l
LEA
t.5-3.7
LEA
1.9-1.4
Fuel Ckvicterlstlct
Nut
11 lue
36.45'
I HOO
X.K
(1101)
3t.t5
(not)
17.35
(112«)
33. M
(1023)
27.50
(S31)
•-
3t.«5
HIM)
37.35
(112*)
34.73
(1050)
34.63
(1047)
33.il
(toil)
(
1
~
—
--
-
-
-
"
-
--
—
~
I
s
-
—
—
—
—
"
"
-
"
"
"
s
As*
-
-
-
—
—
—
~
•-
—
--
—
Nurtcr of
le»t»«
1
1
1
1
I
t
2
1
1
1
1
1
iMeltne W, Emissions*
•1 Wz/J ( Ik «02/IO* IU)
36.7
(0.085)
37.7
(O.OM)
41.8
(0.097)
47.1
(0.111)
30.1
(0.070)
»7. »
(0.22()
34.7
(0.011)
49.0
(0.113)
191
(0.40?)
IOS
(o.ni)
M.4
(0.2M)
11?
(0.7«l)
Controlled »« (•itsion(l>
no. Wj/J (Ib «;/10> «tu)
Lou
--
—
--
-
--
W.6
(o!o71)
•-
—
--
--
••
HI oil
:
—
-
-
-•
ID
(0.07?)
"
--
--
••
Average
33.1
(0.077)
».«
(0.013)
7.14
(0.01M)
a;.i
(0.1*1)
n.o
(O.OM)
97.4
(0.??7)
30.9
(0.072)
39.3
(0.091)
173
(0.40?)
100
(0.?MI
17.2
(O.»3l
9M«
(O.?l«)
Percent
W.
leductlonc
10
-t
S3
-71
7
1
11
20
9
4
10
17
Control
level
Swporte*"
Strlnjent
Stringent
Stringent
IMertU
Stringent
-
Strlogent
Stringent
. -
-
Nodertte
••
loller
IdentKlcjtlon
• 1-1. MT«
» 1-2. KT
1 S-7U-3. NT
t 10-5. MT
t 19-1. «
» 39-tlOi. V
t ECCC. WTI
« 1-3. Iff
f 9-ic-t. vr
1 32-4. HT
1 34-2. NT
f »-?. «T
Remarks
•o ilr preheit
•0 «tr preheit
Ho ttr preneit
Do Ilr preneit
•o »lr preKeit
Ho ilr preheit
Do lir preheit
Reference
7-1
7-1
7-1
7-1 '
7-1
7-1
|
7-2
7-1
7-1
7-1
7-1
7-1
i
oo
•All reported In Is »rre snort-ten «J hr).
•*>, Missions determined l>» che«i luminescence In til cites.
c»«ed *lu* t» lo» eicett ilr CMS) HI on.
Continued
9FI. flretutei Ml, Mtertuoe
• lUy Involve MiiccepUble op«r»ttng condition turfing u hi 9)1 CO ml/or smote wltslons.
-------
TABLE 7-21. Concluded
VtMl/Orilr
neat int.i
m (io* itu/hr)
WYM.O
(53)/(«.0)
I4.i/M
(4f.4)/(00)
35/41.3
(120)/(1SO)
13.5/10
(W)/(W)
».f/tS.«
(»4)/(22S)
t.im
<»)/(»)
35/44
(!»)/( t»)
M/3S
(0.102)
M.I
(0.1^»
127
(o.m>
80. !•
(o.im
70. »•
(O.IK)
04.7
(0.1*7)
01.0
(0.1*0)
111
(0.2M)
HKOTt
<*>!
*t*Kt<«|C
0
-4
24
35
30
22
-4
S
C«»tr»l
lc*tt
Sw*ort«4<
Strlufnt
lnMrw««l*
—
IMiritt
NBdirvte
Nodiritc
IMlrtU
—
Oel1«r
t4Mt1f1c(t1«l
*2-4. Mf
t W-4. «T
1 4-J, ¥T
f »-ot-i. «r
f 12-24. NT
f 20-1. Kt
i 2*-s. m
f 32-1, NT
Mnrki
•o «tr prtdcit
No «*r pr*k«tt
wrprwcft
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
—I
I
00
ro
Mil iwtM tMll wr« ilMrt-t(f* ((3 kr).
N), nlitlont fettnrinH by clmliMlmwnct In ill cam.
C(K*4 g> »«r»j« of ill t«tf.
**xlfr»t«, Inttrxtfltl* or ttrtufnt Imlf 41tcmM4 1* StctlOT 3.
*Etce<* ••r*n. *. 'lr«' ••'•' I* klfh «>cttt itr (b«»lliw) condttlM, second »•!•» It Ion cicni «1r condition.
'nj/J. (itu/rt)).
*rr, flrctubr, KT, Mttrt«b«.
* Nay Involve unacceptable operating conditions leading to nigh CO and/or swk« Mission*.
T-1C13
-------
TABLE 7-22. NOX EMISSION TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH STAGED COMBUSTION
AIR (SCA) (REFERENCE 7-3)
Actual/Design
Heat Input
Ml (I0> llu/hr)
2.S/3.5
1.2/3.5
4.3/5.1
11.3/13.2
(3I.7)/(45|
Control
Netted
SCA*
•>• at
SCA*
•>• 12W
SCA'
«£• • O.fTaf
SCA'
Fuel Characteristics
Meat
(alue
-
..
38.69
(1035)
37.7
(1011)
1
i
-
_.
„
^_
t
S
-
„
»
„
t
Ash
--
..
..
„
Hunter of
Tests*
1
1
1
1
•asellne NOK Cnjlssfons0
nt M>2/J I In •Bj/io' Itu)
35.3
(O.OM)
21.0
(O.OoS)
45.*
(0.107)
«?.!
(0.191)
Controlled «0, Emlsslontb
nf M);/J (Ib Wj/IO* Itu)
LO*
-
_^
M
„
Hl«h
"
„
„
„
Avnraaje
34.5
(o.oaoi
23.6*
(O.OM)
2S 0
(oiosf)
St. 6
(0.132)
•crcent
NOX
Reducttonc
S
It
4f
31
Control
level
Supported"
Str Inocnt
Str Intent
Stringent
Intemcdlate
toiler
Identification
t CCCC. FT"
1 ECCC. FT
f 19-1, HT
f 31-2, HT
•enarks
Overall «cess 0»:
2.91 (SCA). I.H
(baseline) (ftef. 7-2)
no air preheat
Overall OMCCSS Oy:
7.61 (SCA). «.0»
(baseline) (kef. 7-2)
•o air preheat
Lance at 2.1 •
Overall eicess 0;
2.M no air preheat
Overall eicess 0>
2.251
CO
CO
'All reported Uttl Mere start-tern (O nr).
N), Millions determined by chenilli»lnttcence In all caws.
'»«sed on averao« of all tests.
•Mudrrate. Intemedlate or ttrlnajent levels discussed In Section 3.
*>*• turner sloichlonctry.
'*k * Eoulvalence ratio, defined as ratio of stolenlanttrlc air-fuel ratio to actual air-fuel ratio at Ike burner.
WJ/.3 (Itu/ft'l.
"fl. firetube, M, Mtertube.
•Nay Involve unacceptable operating conditions leading to high CO and/or swke emissions.
T-U14
-------
TABLE 7-23.
NOX EMISSION TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH FLUE GAS RECIRCULATION
(FGR)
Neat Input
M (10* Ote/kr)
1.75/1.5
((1/112)
1.75/1.5
1.75/1.5
(*)/(«)
1.75/11.$
2.1/1.5
2.0/7.1
(7)/(25)
2.0/7.1
(7)/(2S)
2.0/7.1
(9.5)/(25)
4.2/5.1
(14.5)/(17.5)
4.2/5.1
Control
•MUM)
FM10P
mm
F« n
FSR50*
FOR5M
FBI. 121
rex. 25*
FSR. 221
F0». 01
FBI. 20S
Fuel Characteristics
NMt
taint
BJ
—
..
_
„
«
«
__
14.24*
(10%)
34.24
(10K)
I
i
mm
—
„
_
_
„
..
„
._
X
s
— ^
—
„
„
M
._
_
..
„
s
«s»
__
—
„
..
._
..
~.
^.
._
Nmker of
Tests*
1
1
1
J
1
1
1
2
2
2
One lint NO, EaHss tons'
n, NOj/J (IkNOj/lofoti.)
41
(0.0*5)
41
(0.095)
11
(0.077)
33
(0.077)
M
(0.004)
27
(0.0(2)
27
(0.0(2)
22
(O.OSO)
52
(0.121)
45. e
(0.107)
Controlled "0, Cnlss Ions'
n* W?/J (Ik ND;/M» Ot>)
Ion
10
(0.021)
1.2
(O.Olt)
..
3.1
(0.0071)
5.2
(0.012)
12
(0.020)
(.6
(O.OK)
7.0
(O.OK)
21
(0.04*)
11.2
(0.02*)
m*k
14
(0.012)
(6.021)
..
6.6
(6.015)
7.0
(O.Olt)
It
(O.OW)
10
(0.021)
*.2
(0.021)
2*
(O.OS7)
12.2
(0.020)
*~~
13
10.010)
0.*
(0.021)
9.2*
(0.071)
4.4
(0.010)
(.0*
(0.014)
14
(0.011)
0.2
(0.019)
(.1
(0.01*)
25
(O.OSO)
11.7
(0.027)
Percent
•eauctlonc
to
7*
72
06
M
41
70
(1
52
75
Control
level
Supported*
Strlnvmt
Strlnoent
Strtnftnt
Str Intent
Str ln«ent
Stringent
Stringent
Stringent
5tr Intent
Stringent
Oolltr
Identification
1 ECCC. r'
1 ECCC. FT
i ECCC. n
1 ECCC. FT
f ECCC. n
* ECCC. NT
1 ECCC. kT
1 ECCC. HT
1 19-1. NT
* 19-1. NT
Rowks
Excess 0; 4X
No air preheat
Excess 0; 41
No air preheat
Excess Oj 1.2*
No air preheat
Excess 0; 3.5*
No air preheat
Comparatively high
load. Excess 0;
21. No air preheat
Excess 0;
1-3*
No air preheat
E«»ss 0?
1-1*
No air preheat
Excess 0?
1.2-2.61
No air preheat
Excess 0;
1.5-1. IS
No air preheat
Excess 0}
2.5-3.2*
No air preheat
Keference
7-2
7-2
7-2
7-2
7-2
7-2
7-Z
7-2
7-3
7-3
^J
oo
•Ml reported tests nere skort-tem Kl hr).
"HO, cotillons determined kjr cheat iMtnesceKI In all cases.
cl
-------
TABLE 7-24 NOX TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH COMBINED FLUE GAS RECIRCULATION
AND STAGED COMBUSTION (FGR/SCA) (REFERENCE 7-3)
Actiul/DetlfO
Neil Input
4.0/S.l
(U.M/d'.S)
Control
Nitkoo-
F«. 17.M*
fT-OMt
Fuel Ouroctorlfttci
Neot
(line
M.HI
(UK)
1
"
-
t
S
-
„
Ask
-
Ikjftcr of
Tetti*
1
fesellM M, Eilidntk
•1 Mj/J ( Ik M^/IO* Itu)
4S.«
(0.1W)
Controlled M, Eoiliilomk
ne «2/J (Ik Wj/IO* It.)
lo»
--
HI*
--
«»«r«et
11.2
(O.OM)
rorcent
»•
It
Control
Level
Strlneot
toiler
IdMtlflcotlo*
1 U-l, HI"
knorkt
Onrill e>c«f Oj
•> «lr prekMt
CO
en
•All reoorte* tttts Mr* slwrt-ten
oalstloM tttaiut* lo Section 1.
«f forcmt "frffiJ^J^ M'r*tl» •* tUlckttMtrtc tlr-fMl ritl* U ocUil «lr-f«*l r»tl» M Me kunwr.
. Mtorti*e.
-------
TABLE 7-25. NOX EMISSION TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH LOAD REDUCTION (LR)
fctMt/BMlf*
Hnl l«p«t
m (10* »t*
1
1
1
1
1
1
1
1
1
1
1
1
ItMltat m. Mn«mk
i^Wl/J (IS Wj/10* It.)
«.«
(8.101)
U.f
(0.1»)
n.t
(O.OM)
M.2
(O.Ml)
31 .«
(0.07J)
«.»
(o.ie?)
4J.1
(0.10?)
n.t
(O.OH)
41. t
(0.0*7)
N.I
(0.0*1)
M.l
io.mil
18.8
(O.OM)
CwlrvIM «, bliftaMk
«4 «;/J ( Ib «?/IO« tta)
IM
-
—
-
--
—
—
—
--
--
--
—
—
m^
--
-
—
—
—
—
-
—
—
-
—
-•
«i«mi
Sl.O
(0.1W)
U.I
(0.11?)
».l
(0.070)
».o
(0.0(5)
J«.»
(0.081)
3».J
(0.087)
•3.4
(0.101)
17.*
(O.OM)
4?. 8
(0.100)
U.O
(0.1711
M.8
(l).0»3)
7.1
(0.017)
^^CWlt
ta*K*l«|C
-10
0
-I
n
.10
»
i
7
-z
-3J
-1
»
C«tr«l
Imcl
SWVOrtM'
Iir prttwtt
No «1r pr*tt«it
No «1r prtheit
No air preheat
IMC*U Oj 3S
No air preheat
hctn Oj 81
•o air preheat
No air preheat
No afr preheat
tefennee
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
7-1
I
CO
•Ml retwrtnl tests wre »hort-ter« K3 hr).
•W, «l«loi« Otenaliwd b/ chenl luntnesceiKe In all cases.
glased on aorrave of all tests.
'•'iM'fate. Interwdlate or strlne^nt lewis d(sc«sse4 In Section 3.
fertenl \ouS. first >alue Is hldi load (baseline), second »«)ue It leu
'MJ/«J (8tv/ft)|.
Continued
toad.
T-1S17
*r, flretube; KI. Mtertube.
-------
TABLE 7-25. Concluded
•ctMl/teslon
Neat Input
HI (10* Itu/hr)
-m.t
--/(HO)
-rt.l
-/(1»-S)
-/».!
»/<100)
-/i;.f
--/(M)
«/7.J
-/(»)
-/3.S
-nut
-/4».J
--/(ISi)
-/4».»
-/(1«0)
-/!•
--/(«0)
-/«5.»
-/(2?S|
Control
•Mhod
U
H-?7«
U
•1-70
U
7$-»
U
10142
U
Tt-41
U
73-11
U
•5-Jf
11
t4-7*
U
•-57
LR
100-M
Fuel Characteristics
Hut
Val«
4?.1»
(MM)
30.1
(1W1)
31.4
t»H)
42.1
(112*1
—
-
M.fS
(KM)
42.1
(11«)
42.1
III*)
37.1
(1016)
«
i
--
—
—
--
—
—
-
-
—
—
I
S
-
—
—
—
—
—
--
-
-
—
s
«sk
--
—
—
—
--
—
—
~
-
—
NM*er of
Testsa
'
1
'
1
1
1
1
1
'
1
latellne NO, Emissions*
no. Wj/J ( Ib M>2/10* III)
43.?
(0.147)
21.6
(O.OM)
57. «
(0.134)
M.7
(0.13*)
33.2
(0.077)
4S.»
(0.107)
171
(0.41S)
20>
(0.47»)
12!
(0.2*0)
104
(0.241)
Controlled NOR Enlsslons^
09 HO^/J (In «0j/l()6 Bttl)
low
--
-
—
-
"
-
-
-
--
"
NI4h
--
-
—
—
--
-
-
--
-
-•
werafle
S4.(
(0.127)
».«
(0.071)
51.5
(0.120)
SJ.l
(0.121)
M.4
(0.082)
*S.O
(0.105)
$3.0
(0.123)
111
(0.421)
70.4*
(0.1*4)
H.I
(0.20*)
PCI Cf til
RedKtlonC
14
-7
11
(
.7
Z
70
1?
44
14
Control
lerel
Vmrartedd
Intenvdlitt
StHntmt
IfitenxlllU
Intcrvdlatt
Strlnjcnt
Strlnftiit
Intencdltte
--
(Mertte
Noder.te
toiler
Ideal lflc«t Ion
f 10-5. HTt
f 1»-1. KT
* tr-i. HT
1 10-4. Iff
1 tCCC. «T
1 tCCC. FT
f *-J. HT
f *-K-(, HT
1 *-K-l, HT
1 »-M. HT
Reurks
E>cess 0; 71
Ho «lr preheit
E>cess 0; 31
No >1r preheat
Eiceji Oj 6.81
Do air preheat
Cucess 0; 3.81
Mo air preheat
No air preheat
No air preheat
Eicess 0; 12. SI
Encess 0; «I
Emss 0; ft
Excels 02 S.St
Reference
7-1
7-1
7-1
7-1
7-2
7-2
7-1
7-1
7-1
7-1
-4
I
CO
•All report* tests wre short-ten K3 hr).
•NO, Missions determined by cnw! liwlnewence In at) casts.
ciased m a»«raoe of all tests.
^Moderate. Intermediate or itrlnent levels dlscvsted In Section }.
Percent load; first nine Is ht«h load (baseline), second value Is Iw load.
'tU/*f (Rtu/ftl).
-------
TABLE 7-26.
NOX EMISSION TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH REDUCED AIR PREHEAT (RAP)
(REFERENCE 7-1)
ActMl/Oestjn
Heat Input
MM (10* Itu/hr)
M.o/73.2
(?00)/(ttO)
44/73.?
(1SO)/(?50)
11/13
(39)/('M
Control
Method
»«•*
3(3-303
tlr
391-301
PJU>
550-480
Fuel Characteristics
Heat
Valoe
j, of
(1047)
M.O
(1047)
37.7
(1011)
«
II
„_
..
„
t
5
_„
„
I
Ash
„
„
Hunker of
1
1
1
Incline "0, hrisslons*
119 M>2/J ( Ib MDj/loA 8t«)
M.t
(O.??l)
108
(o.?so)
11?
(0.?S1)
Controlled NO. Cwlsslonsb
n« MV/J (Ib N0?/I0« llu)
In.
„
-.
HI*
„
A.«-aqe
70. »
(0.1M)
S8.7
(0.1«)
(3.7
(0.147)
*>.
75
43
44
Control
Support etf<<
Naderate
Intenvdlate
Intervdlate
lol'er
Identl1 '.Ion
» 34-?. MM
• 34-?, MT
< 38-?, MT
P«^,
f»cessOj ?.7*
hcess 0; 4.7*
Eicess 0; 1.7*
I
OJ
00
•All reported tests Here short-tern «) M-
^NOX e»1ss(ons tf«teni1iwd by chaifliMitnescence In alt cases.
'Rased on atertve of ill tests.
/ft3).
MI, natertube.
T-1618
-------
TABLE 7-27. NOX EMISSION TEST DATA FROM NATURAL GAS-FIRED INDUSTRIAL BOILERS WITH BURNERS OUT OF SERVICE
(BOOS) (REFERENCE 7-1)
•CtMl/VtttO*
HMI Input
m (10* ite/kr)
I3.s/i7.«
(«)/(»)
1.S/20.S
(»)/(»)
I7.1/3S.2
(fl)/(120)
Control
NttM
MOS
nos
MS
Fuel Ourocterlstlcf
NMt
*•!**
42.1*
(ll»)
37.J
(1000)
M.I
(IOSO)
s
*
_
-—
<
S
_
„
mm
t
tak
_
..
^_
•••er of
t«tf*
J
1
2
fax DM M), Cousins*
no «2/J (Ik MZ/IO* Me)
123
(0.217)
10S
<0.«I)
Id*
(0.241)
Controlle* W, ealsslons*
*« Wj/J (Ib Wj/IO* Itn)
lw
«.f
(0.22S)
«
(0.113)
74
(0.17Z)
Nl^l
107.1
(0.24»»
70
(0.«»)
M
(0.116)
Aocrtft
10?. 5
(0.238)
M.I
(0.1*0)
77
(0.179)
Ptrccut
itdnctfo^
17
44
27
Control
Lml
V*portr<<
Intorwtflit*
Modtrlt*
toller
lonitirtc
i <-K-I. KT'
» 21-1. vr
1 32-1. MT
ItMrts
TM ran of tmf
bwrMTt. one apftr
•OOS burner on «lr
only. Cictlf 0; 31
One ran of tkrtt
kvrMrl. Center bltrnrr
on «lr only, bctfl
Oj S.SS.
Tn rout or t«o
onrnrrt. both upocr
burnrrs on «lr on) jr.
ClCtSf 0; 4.4|
-vj
I
CO
Mil rcoortcd Uits «rf tkort-toni (O kr).
•M), oojlttlont *t«ralnt4 kjr ck*o)ll«ilM>c«ic« In ill u*n.
cliM« on wer*|o of oil tetti.
•Nodrriu. Internco'lott or itrlnont tewlf
-------
REFERENCES FOR SECTION 7
7-1 Hunter, S. C. and H. J. Buening, , "Field Testing: Application of
Combustion Modifications to Control Pollutant Emissions from
Industrial Boilers -- Phases I and II (Data Supplement),"
EPA-600/2-77-122, NTIS-PB 270 112/6AS, June 1977.
7-2 Cichanowicz, J. E., et al.. "Pollutant Control Techniques for Package
Boilers. Phase I Hardware Modifications and Alternate Fuels," Draft
Report, under EPA Contract No. 68-02-1498, November 1976.
7-3 Carter, W. A., et a!., "Emissions Reduction on Two Industrial Boilers
with Major Combustion Modifications," EPA 600-7-78-099a, NTIS-PB 283
109, June 1978.
7-4 Cato, G. A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial Boilers
-- Phase I," EPA-650/2-74-078a, NTIS-PB 238 920/AS, October 1974.
7-5 Cato, G. A., et al.. "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial Boilers
- Phase II,", EPA-600/2-76-086a, NTIS PB-253 500/AS, April 1976.
7-6 Heap, M. P., et al.. "Reduction of Nitrogen Oxide Emissions from
Field Operating Package Boilers, Phase III," EPA-600/2-77-025,
NTIS-PB 269 277, January 1977.
7-7 Maloney, K. L., et al.. "Low-sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers," EPA-600/7-78-153a,
NTIS PB-287-937/AS, July 1978.
7-8 Gabrielson, J. E., et al., "Field Tests of Industrial Stoker
Coal-fired Boilers for Emissions Control and Efficiency Improvement -
Site A," EPA-600/7-78-136a, NTIS PB-285-9727AS, July 1978.
7-9 Lips, H. I., and E. B. Higginbotham, "Field Testing of an Industrial
Stoker Coal-Fired Boiler ~ Effects of Combustion Modification NOX
Control on Emissions — Site B," Acurex Report TR-79-18/EE, EPA
Contract No. 68-02-2160, Acurex Corporation, Mountain View, CA,
August 1978.
7-10 Langsjoen, P. L., et al_._, "Test Results of Modern Coal Fired Stoker
Boilers for Emissions and Efficiency," presented at the American
Power Conference, Chicago, Illinois, April 23-25, 1979. .
7-11 Matthews, B. J., TRW, Inc., Redondo Beach, California, Letter to
W. Peters, EPA IERL-RTP, NC, March 23, 1979.
7-12 Hall, R. E., IERL-RTP, NC, Telecommunication with K. J. Lim, Acurex
Corporation, May 18, 1979.
7-40
-------
APPENDIX A
COST DETAILS
Following are listed tables of estimated capital costs and
annualized costs for combustion modification NO control techniques.
rt
Tables are presented for each combination of typical boiler type/candidate
control system. All assumptions (capital recovery factor, load factors,
engineering estimate factors, etc.) are all discussed in Sections 4 and
5. The format followed is that requested by EPArEAB. These tables
supplement the summary cost tables presented in Section 4.
A-l
-------
TABLE A-l. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 59 MW PULVERIZED COAL-FIRED BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $16.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 5.000
Total Direct Costs (equipment + installation) $ 21.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 27.000
Land
Working capital (25% of total direct operating costs) p
GRAND TOTAL (turnkey + land + working capital) $27.000
aCosts are engineering estimates based on References 4-1 and 4-10 through 4-13
t»From Annual Cost Table (see following table).
A-2
-------
TABLE A-2. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILER*
Direct cost
Direct labor 0
Supervision 0
«^««_
Maintenance labor
Maintenance materials > $ 1,250
Replacement parts
,
Electricity Negligible
Steam 0
Cooling water 0
Process water Q
Fuel $(6.178)
Waste disposal 0
Chemicals 0
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 1.080
Capital recovery factor
(16% of total turnkey costs . $ 4.320
Total capital charges
TOTAL ANNUALIZED COSTS $ 472
$(4.928)
Included above
$ 5.400
aEnergy usage is described in Section 5.
A-3
-------
TABLE A-3. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $26.000
Installation costs, direct
Foundations and supports
Ductwork .
Stack
Piping
Insulation
Painting
Electrical
Total Installation cost $12.000
Total Direct Costs (equipment + installation) $ 38.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 7.000
Total Turnkey Costs (direct + indirect + contingencies $ 47.000
Land --
Working capital (25% of total direct operating costs)b $ 4T450
GRAND TOTAL (turnkey + land + working capital) $ 51,450
aCosts are engineering estimates based on References 4-1 and 4-10 through 4-13
bFrom Annual Cost Table (see following table).
A-4
-------
TABLE A-4. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILER*
Direct cost
Direct labor 0
Supervision 0
-------
TABLE A-5. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS (LNB)
FOR A NEW 59 MW PULVERIZED COAL-FIRED BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 38.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 7.QQQ
Total Turnkey Costs (direct + indirect + contingencies $ 47.000
Land
Working capital (25% of total direct operating costs) $ p
GRAND TOTAL (turnkey + land + working capital)
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5
bFrom Annual Cost Table (see following Table).
A-6
-------
TABLE A-6. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 17.800
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits . 4 ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.880
Capital recovery factor
(16% of total turnkey costs $ 7.520
Total capital charges $ 9.400
TOTAL ANNUAL I ZED COSTS $ 27.200
operation is assumed to cost no more than staged combustion
(see Sections 4 and 5).
A-7
-------
TABLE A-7. ESTIMATED INCREMENTAL CAPITAL COSTS FOR AMMONIA INJECTION
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork •
Stack
Piping .
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $235,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $237,000
Land --__
Working capital (25% of total direct operating costs) $ 8,OOP
GRAND TOTAL (turnkey + land + working capital) $245.000
aAmmonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
bFrom Annual Cost Table (see following table).
A-8
-------
TABLE A-8. ESTIMATED INCREMENTAL ANNUAL COSTS FOR AMMONIA INJECTION
ON A NEW 59 MW PULVERIZED COAL-FIRED BOILER3
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 31.084
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ] )_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 9.400
Capital recovery factor
(16% of total turnkey costs $38.000
Total capital charges $ 47.400
TOTAL ANNUALIZED COSTS $ 78.484
aAmmonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
A-9
-------
TABLE A-9. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 44 MW COAL-FIRED SPREADER STOKER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 4.000
Total Direct Costs (equipment + installation) $ 17.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 3,000
Total Turnkey Costs (direct + indirect + contingencies $ 22.000
Land -
Working capital (25% of total direct operating costs) p
GRAND TOTAL (turnkey + land + working capital) $ 22.000
acosts are engineering estimates based on References 4-10 through 4-15,
bprom Annual Cost Table (see following table).
A-10
-------
TABLE A-10. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 44 MW COAL-FIRED SPREADER STOKER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials \ $ 1,000
Replacement parts
Electricity Negligible
Steam 0
Cooling water 0
Process water Q
Fuel $(2,332)
Waste disposal Q
Chemicals Q
Total direct cost $ (1,532)
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.) Included above
Total overhead cost $ (1,332)
By-product credits. j )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 880
Capital recovery factor
(16% of total turnkey costs $ 3.520
Total capital charges $ 4.4QQ
TOTAL ANNUALI ZED COSTS $ 3>068
aEnergy usage is described in Section 5.
A-ll
-------
TABLE A-ll. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW COAL-FIRED SPREADER STOKER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork _____
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 4.000
Total Direct Costs (equipment + installation) $ 17.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(1056 of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 22.000
Land —
Working capital ^25% of total direct operating costs) $ 200
GRAND TOTAL (turnkey + land + working capital) $ 22.000
aCosts are engineering estimates based on References 4-10 through 4-15,
bFrom Annual Cost Table (see following table).
A-12
-------
TABLE A-12. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW COAL-FIRED SPREADER STOKER3
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
'Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges
TOTAL ANNUAL I ZED COSTS
0
$ 1.000
Negligible
0
0
$ 1.000
0
Included above
$ 880
$ 3.520
$ 4.400
$ 5.400
^Energy usage is described in Section 5.
A-13
-------
TABLE A-13. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 25 MW COAL-FIRED SPREADER STOKER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $10.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 3.000
Total Direct Costs (equipment + installation) $ 13.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 17.000
Land --
Working capital (25% of total direct operating costs) $ 150
GRAND TOTAL (turnkey + land + working capital) $17,150
aCosts are engineering estimates based on References 4-10 through 4-15,
bFrom Annual Cost Table (see following table).
A-14
-------
TABLE A-14. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 25 MW COAL-FIRED SPREADER STOKER*
Direct cost
Direct labor 0
Supervision 0
^
Maintenance labor
Maintenance materials > $ 750
Replacement parts
/
Electricity Negligible
Steam 0
Cooling water 0
Process water 0
Fuel 0
Waste disposal 0
Chemicals 0
Total direct cost $ 750
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits : j )_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 680
Capital recovery factor
(16% of total turnkey costs $ 2.720
Total capital charges $ 3.400
TOTAL ANNUAL IZED COSTS $ 4.150
aEnergy usage is described in Section 5.
A-15
-------
TABLE A-15. ESTIMATED INCREMENTAL CAPITAL COSTS FOR AMMONIA INJECTION
ON A NEW 25 MW COAL-FIRED SPREADER STOKER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork .
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $100,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $102.000
Land
Working capital (25% of total direct operating costs)b $ 3.400
GRAND TOTAL (turnkey + land + working capital) $ 10.540
aAmmonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
&From Annual Cost Table (see following table).
A-16
-------
TABLE A-16. ESTIMATED INCREMENTAL ANNUAL COSTS FOR AMMONIA INJECTION
ON A NEW 25 MW COAL-FIRED SPREADER STOKERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 13.625
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 4.080
Capital recovery factor
(16% of total turnkey costs $16.320
Total capital charges $ 20.400
TOTAL ANNUAL IZED COSTS $ 34.025
^Ammonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
A-17
-------
TABLE A-17. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 22 MW COAL-FIRED CHAIN GRATE STOKERS
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $10.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 3.000
Total Direct Costs (equipment + installation) $ 13.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 17.000
Land
Working capital (25% of total direct operating costs)b $ 0
GRAND TOTAL (turnkey + land + working capital) $17,000
aCosts are engineering estimates based on References 4-10 through 4-15.
bFrom Annual Cost Table (see following table).
A-18
-------
TABLE A-18. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 22 MW COAL-FIRED CHAIN GRATE STOKERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
$ 1.000
Electricity small
Steam 0
Cooling water 0
Process water 0
Fuel $(2.286)
Waste disposal 0
Chemicals 0
Total direct cost $(1,286)
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits . { ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 680
Capital recovery factor
(16% of total turnkey costs $ 2.720
Total capital charges $ 3.400
TOTAL ANNUAL IZED COSTS $ 2.114
Energy usage is discussed in Section 5.
A-19
-------
TABLE A-19. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 9 MW COAL-FIRED UNDERFEED STOKER*
Equipment cost
Basic equipaent (includes freight)
Required auxiliaries
Total equipment cost $ 8,000
Installation costs, direct
Foundations and supports
Ductwork •
Stack
Piping
Insulation .
Painting
Electrical
Total installation cost $ 2.000
Total Direct Costs (equipment + installation) $ 10.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 14.000
Land --
Working capital (25% of total direct operating costs)b $ Q
GRAND TOTAL (turnkey + land + working capital) $ 14.000
j^Costs are engineering estimates based on References 4-10 through 4-15,
bFrom Annual Cost Table (see following table).
A-20
-------
TABLE A-20. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 9 MW COAL-FIRED UNDERFEED STOKER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
600
Process water 0
- Fuel $ (927)
Waste disposal
Chemicals
Total direct cost $ (327)
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits { )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 560
Capital recovery factor
(16% of total turnkey costs $ 2.240
Total capital charges $ 2.800
TOTAL ANNUALIZED COSTS $ 2.473
aEnergy usage is discussed in Section 5.
A-21
-------
TABLE A-21. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 5,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 1.000
Total Direct Costs (equipment + installation) $ 6.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.OOP
Contingencies
(20% of direct and indirect costs) $ 1.000
Total Turnkey Costs (direct + indirect + contingencies $ 9.OOP
Land
Working capital (25% of total direct operating costs)*3 $ 0
GRAND TOTAL (turnkey + land + working capital) $ 9,ppp
aCosts are engineering estimates based on References 4-9 through 4-12, and
4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-22
-------
TABLE A-22. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
350
Maintenance materials
Replacement parts
Electricity small
Steam 0
Cooling water 0
Process water 0
Fuel $ (770)
Waste disposal 0
Chemicals 0
Total direct cost $ (420)
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 360
Capital recovery factor
(16% of total turnkey costs $ 1.440
Total capital charges $ 1,800
TOTAL ANNUAL I ZED COSTS $ 1,330
a£nergy usage is discussed in Section 5.
A-23
-------
TABLE A-23. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 7,000
Installation costs, direct
Foundations and supports
Ductwork •
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 14.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 19.000
Land --
Working capital (25% of total direct operating costs) $ 1..435
GRAND TOTAL (turnkey + land + working capital) $ 20.435
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
Annual Cost Table (see following table).
A-24
-------
TABLE A-24. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER*
Direct cost
Direct labor 0
Supervision 0
\
Maintenance labor
Maintenance materials > $ 850
Replacement parts
Electricity $ 631
Steam 0
Cooling water 0
Process water 0
' Fuel $ 857
Waste disposal 0
Chemicals 0
Total direct cost $ 2.338
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits ] ^
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 760
Capital recovery factor
(16% of total turnkey costs $ 3.040
Total capital charges $ 3.800
TOTAL ANNUAL I ZED COSTS $ 6.138
aEnergy usage is discussed in Section 5.
A-25
-------
TABLE A-25. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack .
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 14.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.OOP
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 19.000
Land
Working capital (25% of total direct operating costs)
GRAND TOTAL (turnkey + land + working capital) $19,000
aLNB is assumed to cost no more than staged combustion and most likely will
cost less (see Sections 4 and 5).
^From Annual Cost Table (see following table).
A-26
-------
TABLE A-26. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 4.4 MW RESIDUAL OIL-FIRED FIRETUBE BOILER3
850
Probably small
Direct cost
Direct labor 0_
Supervision 0_
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 720
Capital recovery factor
(16% of total turnkey costs $ 3.080
Total capital charges
TOTAL ANNUALI ZED COSTS
Depends if pressure drop changes
0
0
$ 2.338 (using same value
as used for
staged combustion)
$ 3.800
$ 6.138
3LNB operation is assumbed to cost no more than staged combustion and will
probably cost less (see Sections 4 and 5).
A-27
-------
TABLE A-27. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $10,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 3.000
Total Direct Costs (equipment + installation) $ 13,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included, above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 17.000
Land
Working capital (25% of total direct operating costs) 0.
GRAND TOTAL (turnkey + land + working capital) $ 17.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
Annual Cost Table (see following table).
A-28
-------
TABLE A-28. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILER9
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges
TOTAL ANNUAL IZED COSTS
$
750
Negligible
0
0
0
$(20,734)
0
0
$(19.984)
Included above
$ 680
$ 2.720
$ 3.400
$(16.584)
Energy usage is described in Section 5.
A-29
-------
TABLE A-29. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32.000
Land
Working capital (25% of total direct operating costs)b $ 5.329
GRAND TOTAL (turnkey + land + working capital) $ 37.329
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-30
-------
TABLE A-30. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILER3
Direct cost
Direct labor 0
Supervision 0
\
Maintenance labor
Maintenance materials $ 1,500
Replacement parts
Electricity $ 9.250
Steam 0
Cooling water 0
Process water 0
Fuel $10.566
Waste disposal 0
Chemicals 0
Total direct cost $ 21.317
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits . ] }_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 1.280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUAL IZED COSTS $ 31.317
aEnergy usage is described in Section 5.
A-31
-------
TABLE A-31. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork .
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 25,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32.000
Land
Working capital (25% of total direct operating costs)
GRAND TOTAL (turnkey + land + working capital) $ 32.000
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-32
-------
TABLE A-32. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials $ 1.500
Replacement parts
/
Electricity ?
Steam 0
Cooling water 0
Process water 0_
Fuel ?
Waste disposal 0_
Chemicals 0
Total direct cost $ 21,000
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits ^ J_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 27.400
is assumed to cost no more than staged combustion (see Sections 4 and 5),
A-33
-------
TABLE A-33. ESTIMATED INCREMENTAL CAPITAL COSTS FOR AMMONIA INJECTION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $180.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $182.000
Land
Working capital (25% of total direct operating costs)b $ 6.000
GRAND TOTAL (turnkey + land + working capital) $188.000
aAmmonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5).
bFrom Annual Cost Table (see following table).
A-34
-------
TABLE A-34. ESTIMATED INCREMENTAL ANNUAL COSTS FOR AMMONIA INJECTION
ON A NEW 44 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 24.000
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 7.200
Capital recovery factor
(16% of total turnkey costs $28.800
Total capital charges $ 36.000
TOTAL ANNUALIZED COSTS $ 60.000
aAmmonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5).
A-35
-------
TABLE A-35. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 5,000
Installation costs, direct
Foundations and supports
Ductwork .
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 1.000
Total Direct Costs (equipment + installation) $ 6.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ l,QQQ
Total Turnkey Costs (direct + indirect + contingencies $ 9.000
Land --
Working capita' (25% of total direct operating costs) .0
GRAND TOTAL (tu -nkey + land + working capital) $ 9.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table [see following table).
A-36
-------
TABLE A-36. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
•ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges
TOTAL ANNUAL IZED COSTS
350
Negligible
0
$ (870)
$ (520)
Included above
$ 360
$ 1.440
$ 1,800
$ 1.280
aEnergy usage is described in Section 5.
A-37
-------
TABLE A-37. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight) _
Required auxiliaries _
Total equipment cost $ 9,000
Installation costs, direct
Foundations and supports _
Ductwork _
Stack _
Piping _
Insulation _
Painting _
Electrical _
Total installation cost $ 5.000
Total Direct Costs (equipment + installation) $ 14.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2 . OOP
Contingencies
(20% of direct and indirect costs) $ 3,000
Total Turnkey Costs (direct + indirect + contingencies $ 19.000
Land --
Working capital (25% of total direct operating costs) $
GRAND TOTAL (turnkey + land + working capital) $19,875
aCosts are engineering estimates based on References 4-9 through 4-12 4-14
and 4-17 through 4-20.
Annual Cost Table (see following table).
A-38
-------
TABLE A-38. ESTIMATED INCREMENTAL ANNUAL COSTS DUE TO FLUE GAS RECIRCULATION
ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
850
Maintenance materials
Replacement parts
Electricity - Fan $ 1.733
Steam 0
Cooling water 0
Process water 0
Fuel $ 914
Waste disposal 0
Chemicals 0
Total direct cost $ 3,497
Overhead
Payroll (30% of direct labor) --
Plant (26% of labor, parts & maint.) Included above
Total overhead cost —
By-product credits . ] ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 760
Capital recovery factor
(16% of total turnkey costs $ 3.040
Total capital charges $ 3.800
TOTAL ANNUAL IZED COSTS $ 7.297
aEnergy usage is described in Section 5.
A-39
-------
TABLE A-39. ESTIMATED INCREMENTAL CAPITAL COSTS OF LOW NOX BURNERS (LNB)
ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork •
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 14,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 19.000
Land
Working capital (25% of total direct operating costs) $ 500
GRAND TOTAL (tun key + land + working capital) $ 19.500
<|LNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
DFrom Annual Cost Table (see following table)
A-40
-------
TABLE A-40. ESTIMATED INCREMENTAL ANNUAL COSTS OF LOW NO* BURNERS (LNB)
ON A NEW 4.4 MW DISTILLATE OIL-FIRED FIRETUBE BOILER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
' Fuel
Waste disposal
Chemicals
Total direct cost $ 1,9QJ:
Overhead
Payroll (30* of direct labor]*
Plant (26% of labor, parts & nremt.))
Total overhead cost
By-product credits ^ ))
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs,)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 3.400
TOTAL ANNUAL IZED COSTS $5,300
aiNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
A-41
-------
TABLE A-41. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 29 MW DISTILLATE OIL-FIRED FIRETU8E BOILER WITHOUT
AN AIR PREHEATER3
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs) $ 6.000
GRAND TOTAL (turnkey + land + working capital) $ 32.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-42
-------
TABLE A-42. ESTIMATED INCREMENTAL ANNUAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 29 MW DISTILLATE OIL-FIRED FIRETUBE BOILER WITHOUT
AN AIR PREHEATERa
Direct cost
Direct labor 0__
Supervision 0
Maintenance labor
Maintenance materials \ $ 1.200
Replacement parts
Electricity - Fan ' $14.718
Steam 0
Cooling water 0
Process water 0
Fuel $ 8.494
Waste disposal 0
Chemicals 0
Total direct cost $ 24.412
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ] )_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.040
Capital recovery factor
(16% of total turnkey costs $ 4,160
Total capital charges $ 5,200
TOTAL ANNUAL I ZED COSTS $ 29.612
aEnergy usage is described in Section 5.
A-43
-------
TABLE A-43. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITHOUT
AN AIR PREHEATER3
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10* of direct costs) Included above
Construction and field expense
(10* of direct costs) Included above
Construction fees
(10* of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26,000
Land
Working capitil (25* of total direct operating costs) $ 3r750
GRAND TOTAL (turnkey + land + working capital) $29,750
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5),
bFrom Annual Cost Table (see following table).
A-44
-------
TABLE A-44. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITHOUT
AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 15,000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits j ]_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 4.800
TOTAL ANNUALI ZED COSTS $ 19.800
is assumed to cost no more than staged combustion (see Sections 4 and 5)
A-45
-------
TABLE A-45. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITHOUT AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs)b $ 3.775
GRAND TOTAL (turnkey + land + working capital) $ 29.775
aCosts are engineering estimates based on References 4-9 through 4-12 4-14
and 4-17 through 4-20.
"From Annual Cost Table (see following table).
A-46
-------
TABLE A-46. ESTIMATED INCREMENTAL ANNUAL COSTS OF STAGED COMBUSTION
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITHOUT AN AIR PREHEATERa
Direct cost
Direct labor
Supervision 0
•»
Maintenance labor
Maintenance materials \ $ 1.200
Replacement parts
Electricity - Fan $ 6.307
Steam 0
Cooling water 0
Process water 0
Fuel $ 7,597
Waste disposal 0
Chemicals 0
Total direct cost $ 15.103
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits : ] ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.080
Capital recovery factor
(16% of total turnkey costs $ 4.120
Total capital charges $ 5,200
TOTAL ANNUALIZED COSTS $ 20.303
aEnergy usage is described in Section 5.
A-47
-------
TABLE A-47. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER3
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 8.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 2.000
Total Direct Costs (equipment + installation) $ 10.000
Installation costs, indirect
Engineering
(10/6 of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 14.000
Land --
Working capita1 (25% of total direct operating costs) Q
GRAND TOTAL (turnkey + land + working capital) $ 14.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-48
-------
0
$ 600
Negligible
0
0
TABLE A-48. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE
BOILER WITH AN AIR PREHEATER3
Direct cost
Direct labor 0
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges
TOTAL ANNUAL IZED COSTS $ [618)
$(4.018)
0
0
$ (3.418)
Included above
$ 560
$ 2.240
$ 2.800
^Energy usage is described in Section 5.
A-49
-------
TABLE A-49. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost 0
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost 0
Total Direct Costs (equipment + installation)
Installation costs, indirect
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Start-up (2% of direct costs)
. Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs)
Total Turnkey Costs (direct + indirect + contingencies $ 2.000
Land
Working capital (25% of total direct operating costs)3 $ 5.QQQ
GRAND TOTAL (turnkey + land + working capital) $7 QOO
aFrom Annual Cost Table (see following table).
A-50
-------
TABLE A-50. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
ON A NEU 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor 0
Maintenance materials 0_
Replacement parts p_
Electricity 0_
Steam 0_
Cooling water 0_
Process water 0
Fuel $23.388
Waste disposal 0
Chemicals 0
Total direct cost $ 23.388
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.) —
Total overhead cost
By-product credits j J_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 80
Capital recovery factor
(16% of total turnkey costs $ 320
Total capital charges $ 400
TOTAL ANNUALIZED COSTS $ 23.788
aEnergy usage is described in Section 5.
A-51
-------
TABLE A-51. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (Includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs* direct
Foundations and supports
Ductwork "
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10* of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20* of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capita1 (25% of total direct operating costs)4 $ 6.000
GRAND TOTAL (turnkey + land + working capital) $ 32.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-52
-------
TABLE A-52. ESTIMATED INCREMENTAL ANNUAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials
Replacement parts
$ 1.200
Electricity $14.718
Steam 0
Cooling water 0
. Process water 0
Fuel $ 8.494
Waste disposal 0
Chemicals 0
Total direct cost $ 24.412
Overhead
Payroll (30% of direct labor) __I^_
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits ] ]_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 1.040
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 29.612
^Energy usage is described in Section 5.
A-53
-------
TABLE A-53. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs)3 $ 3.750
GRAND TOTAL (turnkey + land + working capital) $ 29.750
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5)
bFrom Annual Cost Table (see following table).
A-54
-------
TABLE A-54. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel ' _____
Waste disposal
Chemicals •
Total direct cost $ 15.QQQ
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits j )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs _._
Total capital charges $ 5 200
TOTAL ANNUALIZED COSTS $ 20,200
*LNB is assumed to cost no more than staged combustion (see Sections 4 and 5),
A-55
-------
TABLE A-55. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 29 MM DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATER3
Equipment cost
Basic equipment (includes freight) _____
Required auxiliaries
Total equipment cost $13,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect :
Engineering
(10* of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital '25% of total direct operating costs)3 $ 3.778
GRAND TOTAL (turnkey + land + working capital) $ 29.778
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-56
-------
TABLE A-56. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 29 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATER3
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials $ 1.200
Replacement parts
Electricity - Fan $ 6.307
Steam 0
Cooling water 0
•Process water 0
Fuel $ 7.605
Waste disposal 0
Chemicals 0
Total direct cost $ 15.112
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits { ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.040
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 20.312
^Energy usage is described in Section 5.
A-57
-------
TABLE A-57. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT AND
FLUE GAS RECIRCULATION ON A NEW 29 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs)4 $ 12.000
GRAND TOTAL (turnkey + land + working capital) $ 38.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table)
A-58
-------
TABLE A-58. ESTIMATED INCREMENTAL ANNUAL COSTS OF REDUCED AIR PREHEAT AND
FLUE GAS RECIRCULATION ON A NEW 29 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials \ $ 1.200
Replacement parts
Electricity - Fan $14.718
Steam 0
Cooling water 0
Process water 0
Fuel $31.757
Waste disposal 0
Chemicals 0
Total direct cost $ 47.675
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,040
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5.200
TOTAL ANNUAL IZED COSTS $52.875
aEnergy usage is described in Section 5.
A-59
-------
TABLE A-59. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT AND
LOW NOX BURNERS ON A NEW 29 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect :
Engineering
(10* of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital '25% of total direct operating costs)3 $ 4.000
GRAND TOTAL (turnkey + land + working capital) $ 30.000
aLNB operation is assumed to cost no more than staged combustion
(see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-60
-------
TABLE A-60. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT AND
LOW NOX BURNERS ON A NEW 29 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity - Fan
Steam
Cooling water
• Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 38.000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits { }.
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 43.200
&LNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
A-61
-------
TABLE A-61. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE
BOILER WITHOUT AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 8,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 2.000
Total Direct Costs (equipment + installation) $ 10.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 14.000
Land
Working capital (25% of total direct operating costs)3 0
GRAND TOTAL (turnxey + land + working capital) $14.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
Annual Cost Table (see following table).
A-62
-------
TABLE A-62. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER WITHOUT
AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
V
Maintenance labor
Maintenance materials
Replacement parts
600
Electricity Negligible
Steam p
Cooling water p
Process water P
Fuel $(4.990)
Waste disposal P
Chemicals 0
Total direct cost $ (4.390)
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ^ ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 560
Capital recovery factor
(16% of total turnkey costs $ 2.240
Total capital charges $ 2.800
TOTAL ANNUAL IZED COSTS $ (1,590)
aEnergy usage is described in Section 5.
A-63
-------
TABLE A-63. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
OPERATION ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE
BOILER WITH AN AIR PREHEATER
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost 0
Installation costs, direct
Foundations and supports ______
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost 0
Total Direct Costs (equipment + installation) 0
Installation costs, indirect
Engineering
(10X of direct costs)
Construction and field expense
(lOt of direct costs)
Construction fees
(lOt of direct costs)
Start-up (2t of direct costs)
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20t of direct and indirect costs)
Total Turnkey Costs (direct + indirect + contingencies $ 2.000
Land
Working capita: (25t of total direct operating costs)3 $ 5.000
GRAND TOTAL (turnkey + land + working capital) $ 7.000
aFrom Annual Cost Table (see following table).
A-64
-------
TABLE A-64. ESTIMATED INCREMENTAL ANNUAL COSTS DUE TO REDUCED AIR PREHEAT
OPERATION FOR A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials 0
Replacement parts
Electricity Possible small savings
Steam 0
Cooling water 0
• Process water 0
Fuel $20.330
Waste disposal 0
Chemicals 0
Total direct cost $ 20.330
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) -
Total overhead cost —
By-product credits j }_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 80
Capital recovery factor
(16% of total turnkey costs $ 320
Total capital charges $ 400
TOTAL ANNUAL I ZED COSTS $__2J^730
^Energy used by RAP is described in Section 5.
A-65
-------
TABLE A-65. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS
RECIRCULATION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2X of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs) $ stnnn
GRAND TOTAL (turnkey + land + working capital) $ 31,000^
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-66
-------
TABLE A-66. ESTIMATED INCREMENTAL ANNUAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials \ $ 1.200
Replacement parts
Electricity - Fan ' $14.717
Steam 0
Cooling water Q
Process water 0
Fuel $ 5,672
Waste disposal 0
Chemicals 0
Total direct cost $ 21,589
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ] [
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,040
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5,200
TOTAL ANNUALIZED COSTS $ 26,784
aEnergy usage is described in Section 5.
A-67
-------
TABLE A-67. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED
COMBUSTION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs) $ 3.000
GRAND TOTAL (turnkey + land + working capital) $ 29.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-68
-------
TABLE A-68. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER3
Direct cost
Direct labor 0
Supervision 0
•v
Maintenance labor
Maintenance materials \ $ 1,200
Replacement parts
Electricity - Fan $ 6.307
Steam 0
Cooling water 0
. Process water 0
Fuel $ 4.907
Waste disposal 0
Chemicals 0
Total direct cost $ 12.414
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits { [
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 1.040
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 17.614
^Energy usage is described in Section 5.
A-69
-------
TABLE A-69. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NO* BURNERS
(LNB) ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 20,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(1056 of direct costs) Included above
Construction fees
(IQ% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20* of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25X of total direct operating costs) $ 3.000
GRAND TOTAL (turr.key + land + working capital) $ 29.000
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-70
-------
TABLE A-70. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 29 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam -
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 12,000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits j 1
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 17.200
3LNB operation is assumed to cost no more than staged combustion (see
Sections 4 and 5).
A-71
-------
TABLE A-71. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND STAGED COMBUSTION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost 113,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10X of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital '25% of total direct operating costs) $ 8.000
GRAND TOTAL (turnkey + land + working capital) $ 34.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
DFrom Annual Cost Table (see following table).
A-72
-------
TABLE A-72. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
AND STAGED COMBUSTION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials \ $ 1.200
Replacement parts
Electricity - Fan ' $ 6.307
Steam 0
Cooling water 0
• Process water 0
Fuel $25.416
Waste disposal 0
Chemicals 0
Total direct cost $ 32.923
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.080
Capital recovery factor
(16% of total turnkey costs $ 4.160
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 38.123
^Energy use is discussed in Section 5).
A-73
-------
TABLE A-73. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND FLUE GAS RECIRCULATION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $13.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7.000
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs) $ 10.000
GRAND TOTAL (turnkey + land + working capital) $ 36.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
°From Annual Cost Table (see following table).
A-74
-------
TABLE A-74. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
AND FLUE GAS RECIRCULATION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER3
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials\ $ 1.200
Replacement parts
Electricity - Fan ' $14.717
Steam 0
Cooling water Q
Process water 0
Fuel $26.001
Waste disposal 0
Chemicals 0
Total direct cost $ 41,918
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ] ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.080
Capital recovery factor
(16% of total turnkey costs $ 4.120
Total capital charges $ 5.200
TOTAL ANNUALIZED COSTS $ 47.118
aEnergy use is discussed in Section 5).
A-75
-------
TABLE A-75. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND LOW NOX BURNERS ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 20.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 4.000
Total Turnkey Costs (direct + indirect + contingencies $ 26.000
Land
Working capital (25% of total direct operating costs)
GRAND TOTAL (turnkey + land + working capital)
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-76
-------
TABLE A-76. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT (RAP)
AND LOW NOX BURNERS (LNB) ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity - Fan
Steam
Cooling water
•Process water
Fuel $20,330 RAP
Waste disposal
Chemicals
Total direct cost $ 32.330
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ]_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 960
Capital recovery factor
(16% of total turnkey costs $ 3.840
Total capital charges $ 4.800
TOTAL ANNUALIZED COSTS $ 37.130
3LNB is assumed to cost no more than staged combustion and RAP energy use is
described in Section 5.
A-77
-------
TABLE A-77. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND NH3 INJECTION FOR A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $116.000
Installation costs, indirect
Engineering
(10X of direct costs) Included above
Construction and field expense
(10X of direct costs) Included above
Construction fees
(10X of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $118,000
Land
Working capital (21% of total direct operating costs) $ 9.000
GRAND TOTAL (turnkey + land + working capital) $127.000
injection costs are extrapolated from utility boiler data (References 4-4
and 4-5).
bFrom Annual Cost Table (see following table).
A-78
-------
TABLE A-78. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT (RAP)
AND NH3 INJECTION ON A NEW 29 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials $15.831 NH- injection
Replacement parts
Electricity - Fan
Steam
Cooling water
Process water
Fuel $20.330 RAP
Waste disposal
Chemicals
Total direct cost $ 36,161
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ] ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 4.720
Capital recovery factor
(16% of total turnkey costs $18,880
Total capital charges $ 23.600
TOTAL ANNUALIZED COSTS $ 59.361
^Ammonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5) and RAP energy use is from Section 5.
A-79
-------
TABLE A-79. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 117 MW PULVERIZED COAL-FIRED BOILER9
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $25.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 35.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 7.0QO
Total Turnkey Cosu.s (direct + indirect + contingencies $ 44,000
Land
Working capital (25% of total direct operating costs)b 0
GRAND TOTAL (turnkey + land + working capital) $44.000
aCosts are engineering estimates based on References 4-1 and 4-10 through 4-13.
bFrom Annual Cost Table (see next table).
A-80
-------
TABLE A-80.
ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials $ 2,100
Replacement parts
Electricity Negligible
Steam 0
Cooling water 0
Process water 0
' Fuel ($12.356)
Waste disposal 0
Chemicals 0
Total direct cost
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,760
Capital recovery factor
(16* of total turnkey costs $ 7,040
Total capital charges
TOTAL ANNUALIZED COSTS
$(10,256)
Included above
$ 8,800
$ 1.456
aEnergy usage is described in Section 5,
A-81
-------
TABLE A-81. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $39.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $24.000
Total Direct Costs (equipment + installation) $ 63,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 13.000
Total Turnkey Costs (direct + indirect + contingencies $ 78.000
Land --
Working capital (?5% of total direct operating costs) $ 9,000
GRAND TOTAL (turnkey + land + working capital) $ 87.QQQ
aCosts are engineering estimates based on References 4-1 and 4-10 through 4-13
bFrom Annual Cost Table (see following table).
A-82
-------
TABLE A-82. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILER*
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials $ 3.900
Replacement parts
7 -^—^^-^^^^—^™
Electricity -- fan $25.224
Steam 0
Cooling water 0
Process water 0
Fuel $ 5.906
Waste disposal 0
Chemicals 0
Total direct cost $ 35.i30
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credit? ^ ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 3.120
Capital recovery factor
(16% of total turnkey costs $12.480
Total capital charges $ 15.600
TOTAL ANNUALIZED COSTS $ 50.630
aEnergy usage is described in Section 5.
A-83
-------
TABLE A-83. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS (LNB)
FOR A NEW 117 MW PULVERIZED COAL-FIRED BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports ______
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 63.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 13.000
Total Turnkey Costs (direct + indirect + contingencies $ 78,000
Land .
Working capital (25% of total direct operating costs) $ 0
GRAND TOTAL (turnkey + land + working capital) $ 78.000
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5
^From Annual Cost Table (see following Table).
A-84
-------
TABLE A-84. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
'Fuel
Waste disposal
Chemicals
Total direct cost $ 35.000
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j J_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 3,120
Capital recovery factor
(16% of total turnkey costs $12,480
Total capital charges $ 15,600
TOTAL ANNUALIZED COSTS $ 50.630
*LNB operation is assumed to cost no more than staged combustion
(see Sections 4 and 5).
A-85
-------
TABLE A-85. ESTIMATED INCREMENTAL CAPITAL COSTS FOR AMMONIA INJECTION
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $470.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10* of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $472.000
Land --
Working capital (25% of total direct operating costs) $ 16.000
GRAND TOTAL (turnkey + land + working capital) $433 QOO
aAmmonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
bFrom Annual Cost Table (see following table).
A-86
-------
TABLE A-86. ESTIMATED INCREMENTAL ANNUAL COSTS FOR AMMONIA INJECTION
ON A NEW 117 MW PULVERIZED COAL-FIRED BOILERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 62.168
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits . ( )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $18.800
Capital recovery factor
(16% of total turnkey costs $76.000
Total capital charges $ 94.800
TOTAL ANNUALIZED COSTS $155.968
aAmmonia injection costs are extrapolations from utility boiler data
(References 4-4 and 4-5).
A-87
-------
TABLE A-87. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $ 7,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 2,000
Total Direct Costs (equipment + installation) $ 9,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 1,000
Total Turnkey Costs (direct + indirect + contingencies $ 12,000
Land .
Working capita' (25% of total direct operating costs) 0
GRAND TOTAL (turnkey + land + working capital) $ 12.000
are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-88
-------
TABLE A-88. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR OPERATION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges
TOTAL ANNUALIZED COSTS
0
$ 500
Negligible
0
0
0
$ (4,147)
0
$ (3,6471
Included above
$ 480
$ 1,920
$ 2.400
$ d.247)
Energy usage is described in Section 5.
A-89
-------
TABLE A-89. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $10.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 7,000
Total Direct Costs (equipment + installation) $ 17.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.OOP
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 22,000
Land
Working capital (25% of total direct operating costs) $ 2.000
GRAND TOTAL (turnkey + land + working capital) $ 24.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-90
-------
TABLE A-90. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Direct cost
Direct labor 0
Supervision 0
, — - ..
Maintenance labor
Maintenance materials $ 1,000
Replacement parts
Electricity $ 1,650
Steam 0
Cooling water Q
Process water 0
Fuel $ 2.113
Waste disposal Q
Chemicals 0
Total direct cost $ 4.763
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits j )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 880
Capital recovery factor
(16% of total turnkey costs $ 3,520
Total capital charges $ 4.400
TOTAL ANNUAL I ZED COSTS $ gj63
aEnergy usage is described in Section 5.
A-91
-------
TABLE A-91. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERS
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 17,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10* of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 3.000
Total Turnkey Costs (direct + indirect + contingencies $ 22.000
Land .
Working capital (25% of total direct operating costs)
GRAND TOTAL (turnkey + land + working capital) $ 22,000
3LNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-92
-------
TABLE A-92. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Direct cost
Direct labor 0
Supervision Q
Maintenance labor
Maintenance materials $ 1,000
Replacement parts
Electricity ?_
Steam 0_
Cooling water 0_
Process water p_
Fuel l_
Waste disposal 0
Chemicals 0
Total direct cost $ 4.5QQ
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost --
By-product credits j )
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 880
Capital recovery factor
(16% of total turnkey costs $ 3,520
Total capital charges $ 4.400
TOTAL ANNUALIZED COSTS $ 8.900
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
A-93
-------
TABLE A-93. ESTIMATED INCREMENTAL CAPITAL COSTS FOR AMMONIA INJECTION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 70,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $ 72,000
Land
Working capital (25% of total direct operating costs) $ 1,QQQ
GRAND TOTAL (turnkey + land + working capital) $ 73 QOO
aAmmonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5).
bFrom Annual Cost Table (see following table).
A-94
-------
TABLE A-94. ESTIMATED INCREMENTAL ANNUAL COSTS FOR AMMONIA INJECTION
ON A NEW 8.8 MW RESIDUAL OIL-FIRED WATERTUBE BOILER3
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 5,000
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ^
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 2880
Capital recovery factor
(16% of total turnkey costs $11,520
Total capital charges $ 14,400
TOTAL ANNUAL I ZED COSTS $ 19,400
^Ammonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5).
A-95
-------
TABLE A-95. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW EXCESS AIR
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $10.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $ 3,000
Total Direct Costs (equipment + installation) $ 13,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 2.000
Total Turnkey Costs (direct + indirect + contingencies $ 17,000
Land --
Working capital (25% of total direct operating costs) 0
GRAND TOTAL (turnkey + land + working capital) $ 17.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
&From Annual Cost Table (see following table).
A-96
-------
TABLE A-96. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW EXCESS AIR
OPERATION ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE
BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials / $ 750
Replacement parts
Electricity Negligible
Steam 0
Cooling water 0
-Process water 0
Fuel $(6.027)
Waste disposal 0
Chemicals 0
Total direct cost $ (5,277)
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 680
Capital recovery factor
(16% of total turnkey costs $ 2,720
Total capital charges $ 3.400
TOTAL ANNUALIZED COSTS $ (1877)
aEnergy usage is described in Section 5.
A-97
-------
TABLE A-97. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost 0
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost 0
Total Direct Costs (equipment + installation)
Installation costs, indirect
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Start-up (2% of direct costs)
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs)
Total Turnkey Costs (direct + indirect + contingencies $ 2.000
Land
Working capital (25% of total direct operating costs)3 $ 8.770
GRAND TOTAL (turnkey + land + working capital)
Annual Cost Table (see following table).
A-98
-------
TABLE A-98. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor
Supervision 0_
Maintenance labor p_
Maintenance-materials 0
Replacement parts 0_
Electricity 0_
Steam 0
Cooling water 0_
Process water 0
Fuel $35,082
Waste disposal 0
Chemicals 0
Total direct cost $ 35,082
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.) --
Total overhead cost
By-product credits j ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 80
Capital recovery factor
(16% of total turnkey costs $ 320
Total capital charges $ 400
TOTAL ANNUALIZED COSTS $ 35.482
aEnergy usage is described in Section 5.
A-99
-------
TABLE A-99. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 25,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs)3 $ 9,080
GRAND TOTAL (turnkey + land + working capital) $ 41.080
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-100
-------
TABLE A-100. ESTIMATED INCREMENTAL ANNUAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor Q
Supervision 0
V •—•• • II • H
Maintenance labor
Maintenance materials > $ 1.500
Replacement parts
Electricity $22.077
Steam 0
Cooling water Q
- Process water 0
Fuel $12.741
Waste disposal 0
Chemicals Q
Total direct cost $ 36.318
Overhead
Payroll (30% of direct labor) —
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1.280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 42.718
aEnergy usage is described iii Section 5.
A-101
-------
TABLE A-101. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 25,000
Installation costs, indirect
Engineering
(IQ% of direct costs) Included above
Construction and field expense
(10X of direct costs) Included above
Construction fees
(10* of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs)3 $ 5.500
GRAND TOTAL (turnkey + land + working capital) $ 37.500
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-102
-------
TABLE A-102. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS (LNB)
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 22,000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits ^ ^
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 28.400
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5),
A-103
-------
TABLE A-103. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10,000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs)9 $ 5.592
GRAND TOTAL (turnkey + land + working capital) $37,592
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-104
-------
TABLE A-104. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW DISTILLATE OIL-FIRED WATERTUBE BOILER WITH
AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials? $ 1,500
Replacement parts
Electricity - Fan $ 9,460
Steam 0
Cooling water 0
Process water 0
Fuel $11.407
Waste disposal 0
Chemicals 0
Total direct cost $ 22.367
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j J_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 1.280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 28.767
aEnergy usage is described in Section 5.
A-105
-------
TABLE A-105. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT AND
FLUE GAS RECIRCULATION ON A NEW 44 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32.000
Land
Working capital (25% of total direct operating costs)3 $ 17,000
GRAND TOTAL (turnkey + land + working capital) $ 49,000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table)
A-106
-------
TABLE A-106. ESTIMATED INCREMENTAL ANNUAL COSTS OF REDUCED AIR PREHEAT AND
FLUE GAS RECIRCULATION ON A NEW 44 MM DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials
Replacement parts
$ 1.500
Electricity - Fan $22.077
Steam 0
Cooling water 0
Process water 0
Fuel $47,636
Waste disposal 0
Chemicals 0
Total direct cost $ 71.213
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 77,613
aEnergy usage is described in Section 5.
A-107
-------
TABLE A-107. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT AND
LOW NOX BURNERS ON A NEW 44 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32?OOP
Land
Working capital (25% of total direct operating costs)3 $ 6,000
GRAND TOTAL (turnkey + land + working capital) $ 38.000
aLNB operation is assumed to cost no more than staged combustion
(see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-108
-------
TABLE A-108. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT AND
LOW NOX BURNERS ON A NEW 44 MW DISTILLATE OIL-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity - Fan
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 60.000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits j[ ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 6400
TOTAL ANNUALIZED COSTS $ 66.400
is assumed to cost no more than staged combustion (see Sections 4 and 5).
A-109
-------
TABLE A-109. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
OPERATION ON A NEW 44 MW NATURAL GAS-FIRED WATERTUBE
BOILER WITH AN AIR PREHEATER
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost 0
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost 0
Total Direct Costs (equipment + installation) 0
Installation costs, indirect
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Start-up (2% of direct costs)
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs)
Total Turnkey Costs (direct + indirect + contingencies $ 2.000
Land
Working capital (25% of total direct operating costs)3 $ 7.000
GRAND TOTAL (turnkey + land + working capital) $9 QOO
aFrom Annual Cost Table (see following table).
A-110
-------
TABLE A-110. ESTIMATED INCREMENTAL ANNUAL COSTS DUE TO REDUCED AIR PREHEAT
OPERATION FOR A NEW 44 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0_
Maintenance labor
Maintenance materials 0_
Replacement parts
Electricity Possible small savings
Steam 0
Cooling water 0
Process water 0
Fuel $30.495
Waste disposal 0
Chemicals 0
Total direct cost $ 30,495
Overhead
Payroll (30* of direct labor) -
Plant (26% of labor, parts & maint.) -
Total overhead cost _
By-product credits j _ ^
Capital charges
G & A, taxes and insurance
of total turnkey costs) $ _ 80
Capital recovery factor
(16% of total turnkey costs $ 320
Total capital charges $^ 400
TOTAL ANNUALIZED COSTS $ 30,895
aEnergy used by RAP is described in Section 5.
A-lll
-------
TABLE A-lll. ESTIMATED INCREMENTAL CAPITAL COSTS FOR FLUE GAS
RECIRCULATION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATER*
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs) $ 8.000
GRAND TOTAL (turnkey + land + working capital) $ 40.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-112
-------
TABLE A-112. ESTIMATED INCREMENTAL ANNUAL COSTS FOR FLUE GAS RECIRCULATION
ON A NEW 44 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0
Maintenance labor
Maintenance materials $ 1,500
Replacement parts
Electricity - Fan $22.076
Steam 0
Cooling water 0
Process water 0
Fuel $ 8,508
Waste disposal 0
Chemicals 0
Total direct cost $ 32,084
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j[ ^
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,280
Capital recovery factor
(16% of total turnkey costs $ 5,120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 38,484
aEnergy usage is described in Section 5.
A-113
-------
TABLE A-113. ESTIMATED INCREMENTAL CAPITAL COSTS FOR STAGED
COMBUSTION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight) ^
Required auxiliaries
Total equipment cost $15.000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10,000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (J5% of total direct operating costs)b $ 4.500
GRAND TOTAL (turnkey + land + working capital) $ 36.500
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-114
-------
TABLE A-114. ESTIMATED INCREMENTAL ANNUAL COSTS FOR STAGED COMBUSTION
ON A NEW 44 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision 0
- ——^—^—«•—
Maintenance labor
Maintenance materials > $ 1,500
Replacement parts
/ ~
Electricity - Fan $ 9.460
Steam 0
Cooling water 0
Process water 0
Fuel $ 7,360
Waste disposal 0
Chemicals 0
Total direct cost $ 18,320
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits J[ ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,280
Capital recovery factor
(16% of total turnkey costs $ 5,120
Total capital charges $ 6,400
TOTAL ANNUALIZED COSTS $ 24,720
aEnergy usage is described in Section 5.
A-115
-------
TABLE A-115. ESTIMATED INCREMENTAL CAPITAL COSTS FOR LOW NO* BURNERS
(LNB) ON A NEW 44 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATER3
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 25,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5,000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs) $ 4,000
GRAND TOTAL (turnkey + land + working capital) $ 36,000
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5),
bFrom Annual Cost Table (see following table).
A-116
-------
TABLE A-116. ESTIMATED INCREMENTAL ANNUAL COSTS FOR LOW NOX BURNERS
(LNB) ON A NEW 44 MW NATURAL GAS-FIRED WATERTUBE BOILER
WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total direct cost $ 18.000
Overhead
Payroll (30% of direct labor)
Plant (26% of labor, parts & maint.)
Total overhead cost
By-product credits { ]_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs)
Capital recovery factor
(16% of total turnkey costs
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 24.400
aLNB operation is assumed to cost no more than staged combustion (see
Sections 4 and 5).
A-117
-------
TABLE A-117. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND STAGED COMBUSTION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10.000
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32.000
Land
Working capital (25% of total direct operating costs) $ 12,000
GRAND TOTAL (turnkey + land + working capital) $44,000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
Annual Cost Table (see following table).
A-118
-------
TABLE A-118. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
AND STAGED COMBUSTION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0_
Maintenance labor
Maintenance-materials } $ 1,500
i
Replacement parts
Electricity - Fan $ 9.460
Steam 0
Cooling water 0
Process water 0
Fuel $38.124
Waste disposal Q
Chemicals 0
Total direct cost $ 49.084
Overhead
Payroll (30% of direct labor) -
Plant (2655 of labor, parts & maint.) Included above
Total overhead cost
By-product credits ^ ^
Capital charges
G & A, taxes and insurance
(4* of total turnkey costs) $ 1.280
Capital recovery factor
(16% of total turnkey costs $ 5.120
Total capital charges $ 6.400
TOTAL ANNUALIZED COSTS $ 55.484
aEnergy use is discussed in Section 5.
A-119
-------
TABLE A-119. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND FLUE GAS RECIRCULATION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost $15,000
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost $10,OOP
Total Direct Costs (equipment + installation) $ 25,000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20% of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32.000
Land
Working capital (25% of total direct operating costs) $ 15.000
GRAND TOTAL (turnkey + land + working capital) $ 47.000
aCosts are engineering estimates based on References 4-9 through 4-12, 4-14,
and 4-17 through 4-20.
bFrom Annual Cost Table (see following table).
A-120
-------
TABLE A-120. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT
AND FLUE GAS RECIRCULATION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor 0
Supervision 0_
Maintenance labor
Maintenance materials $ 1,500
Replacement parts
Electricity - Fan $22.076
Steam 0
Cooling water 0
Process water 0
Fuel $39.002
Waste disposal 0
Chemicals 0
Total direct cost $ 62.578
Overhead
Payroll (30% of direct labor) -
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits ^ ]_
Capital charges
G & A, taxes and insurance
(4% of total turnkey costs) $ 1,280
Capital recovery factor
(16% of total turnkey costs $ 5,120
Total capital charges $ 6,400
TOTAL ANNUALIZED COSTS $ 68.978
aEnergy use is discussed in Section 5.
A-121
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TABLE A-121. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND LOW NOX BURNERS ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $ 25.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2.000
Total Indirect Costs $ 2.000
Contingencies
(20* of direct and indirect costs) $ 5.000
Total Turnkey Costs (direct + indirect + contingencies $ 32,000
Land
Working capital (25% of total direct operating costs)b 12.000
GRAND TOTAL (turnkey + land + working capital) 44.000
aLNB is assumed to cost no more than staged combustion (see Sections 4 and 5).
bFrom Annual Cost Table (see following table).
A-122
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TABLE A-122. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT (RAP)
AND LOW NOX BURNERS (LNB) ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity - Fan
Steam
Cooling water
Process water
Fuel $30,495 RAP
Waste disposal
Chemicals
Total direct cost $ 49.000
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j ^
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $
Capital recovery factor
(16% of total turnkey costs $
Total capital charges $ 6,400
TOTAL ANNUALIZED COSTS $ 55.400
aLNB is assumed to cost no more than staged combustion and RAP energy use is
described in Section 5.
A-123
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TABLE A-123. ESTIMATED INCREMENTAL CAPITAL COSTS FOR REDUCED AIR PREHEAT
AND NHa INJECTION FOR A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Equipment cost
Basic equipment (includes freight)
Required auxiliaries
Total equipment cost
Installation costs, direct
Foundations and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
Total installation cost
Total Direct Costs (equipment + installation) $180.000
Installation costs, indirect
Engineering
(10% of direct costs) Included above
Construction and field expense
(10% of direct costs) Included above
Construction fees
(10% of direct costs) Included above
Start-up (2% of direct costs) Included above
Performance tests (minimum $2000) $ 2,000
Total Indirect Costs $ 2,000
Contingencies
(20% of direct and indirect costs) Included above
Total Turnkey Costs (direct + indirect + contingencies $182,000
Land _
Working capital (25% of total direct operating costs) $^ 13,000
GRAND TOTAL (turnkey + land + working capital) $195,000
injection costs are extrapolated from utility boiler data (References 4-4
and 4-5).
bFrom Annual Cost Table (see following table).
A-124
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TABLE A-124. ESTIMATED INCREMENTAL ANNUAL COSTS FOR REDUCED AIR PREHEAT (RAP)
AND NH3 INJECTION ON A NEW 44 MW NATURAL GAS-FIRED
WATERTUBE BOILER WITH AN AIR PREHEATERa
Direct cost
Direct labor
Supervision
Maintenance labor
Maintenance materials $24,000 NH. injection (all direct costs)
Replacement parts
Electricity - Fan
Steam
Cooling water
Process water
Fuel $30.495 RAP
Waste disposal
Chemi ca1s
Total direct cost $ 54.495
Overhead
Payroll (30% of direct labor) Included above
Plant (26% of labor, parts & maint.) Included above
Total overhead cost
By-product credits j )_
Capital charges
6 & A, taxes and insurance
(4% of total turnkey costs) $ 7,280
Capital recovery factor
(16% of total turnkey costs $29.120
Total capital charges $ 36.400
TOTAL ANNUALIZED COSTS $ 90.895
aAmmonia injection costs are extrapolated from utility boiler data
(References 4-4 and 4-5) and RAP energy use is from Section 5.
A-125
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APPENDIX B
LIST OF COMMON ABREVIATIONS
BOOS Burners out of service
CO Carbon monoxide
EPA Environmental Protection Agency
FGR Flue gas recirculation
HC Hydrocarbon
LEA Low excess air
LNB Low NO burner
A
LR Load reduction
N2 Nitrogen
NH3 Ammonia
NO Nitrogen oxides
Oo Oxygen
OFA Overfire air
PAH (PNA) Polynuclear aromatic hydrocarbon
POM Polycyclic organic matter
RAP Reduced air preheat
SCA Staged combustion air
SFA Sidefire air
SIP State implementation plan
S02 Sulfur dioxide
S03 Sulfur trioxide
UHC Unburned hydrocarbon
B-l
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-178f
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Technology Assessment Report for Industrial Boiler
Applications: NOx Combustion Modification
6. REPORT DATE
December 1979
6. PERFORMING ORGANIZATION CODE
7. AUTMOR(S)
K.J.Lim, R.J. Milligan, H. I. Lips , C.Castaldini,
R.S.Merrill, and H. B. Mason
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Acurex Corporation
485 Clyde Avenue
Mountain View, California 94042
10. PROGRAM ELEMENT NO.
INE624
11. CONTRACT/GRANT NO.
68-02.-3101, TaskB
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 6/78-6/79
14. SPONSORING AGENCY CODE
EPA/600/13
is.SUPPLEMENTARY NOTES JERL-RTP project officer is Robert E. Hall, Mail Drop 65, 919/
i«. AB RACT rp^g report gjves results of an assessment of current and developing
combustion modification NOx control technology for coal-, oil-, and natural-gas-
fired industrial boilers. Control effectiveness and applicability, reliability and
availability, process impacts, capital and operating costs, energy impacts, and
environmental impacts are evaluated. Currently available techniques are capable of
moderate (10-25%) NOx reductions for coal- and residual-oil-fired boilers and major
(40-70%) reductions for distillate-oil- and gas-fired units with minimal adverse
operating impacts. Combustion modifications are estimated to increase the cost of
steam by only 1-2%, but could increase the initial capital cost of a boiler by 1-20%.
Analysis of measured or postulated incremental emissions, other than NOx, indi-
cates that these emissions are generally unaffected when preferred NOx controls are
implemented, although further testing is warranted.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Assessments
Combustion Control
Nitrogen Oxides
Boilers
Capitalized Costs
Operating Costs
Fossil Fuels
Dust
Aerosols
Trace Elements
Air Pollution Control'
Stationary Sources
Particulate
Combustion Modification
Industrial Boilers
Emission Factors
13B
14B
21B
07B
13A
14A,05A
21D
11G
07D
06A
8. DISTRIBUTION STATEMEN1
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
20. SECURITY CLASS (Thispage)
Unclassified
21. NO. OF PAGES
497
22. PRICE
EPA Form 2220-1 (9-73)
B-2
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