FIELD SURVEILLANCE
AND ENFORCEMENT GUIDE:
COMBUSTION
AND INCINERATION SOURCES
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air an 3 Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, N- C. 27711
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APTD-1449
FIELD SURVEILLANCE
AND ENFORCEMENT GUIDE:
COMBUSTION
AND INCINERATION SOURCES
by
Timothy W. Devitt, Richard W. Gerstle, and Norman J. Kulujian
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-0606
EPA Project Officer: Thomas Donaldson
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
June 1973
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The APTD (Air Pollution Technical Data) series of reports is issued by
the Office of Air Programs, Environmental Protection Agency, to report
technical data of interest to a limited number of readers. Copies of
APTD reports are available free of charge to Federal employees, current
contractors and grantees, and non-profit organizations - as supplies
permit - from the Air Pollution Technical Information Center, Environ-
mental Protection Agency, Research Triangle Park, North Carolina 27711,
or may be obtained, for a nominal cost, from the National Technical
Information Service, 5285 Port Royal Road, Springfield, Virginia 22151.
This report was furnished to the Environmental Protection Agency by
PEDCo-Environmental Specialists, Inc., Cincinnati, Ohio, in fulfillment
of Contract No. 68-02-0606. The contents of this report are reproduced
herein as received from the contractor. The opinions, findings, and
conclusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency.
Publication No. APTD-1449
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Acknowledgment
This report was prepared under the direction of Mr.
Timothy W. Devitt. Principal authors were Mr. Norman J.
Kulujian, Mr. Richard W. Gerstle, and Mr. Devitt. Mr.
Arnold Stein of Pacific Environmental Services assisted in
preparing the section describing inspection procedures for
fuel-fired indirect heat exchangers.
Project consultants were Professor Charles Gruber of
the University of Cincinnati, and Dr. David Fine of
Massachusetts Institute of Technology's Fuel Research
Laboratory.
Project Officer for the Environmental Protection Agency
was Mr. Thomas M. Donaldson. The authors appreciate the many
contributions made to this study by both Mr. Donaldson and
Dr. Harold G. Richter of EPA.
Several state and local agencies were visited to obtain
information used in preparing this report. The authors
particularly appreciate the assistance given by the Division
of Air Pollution Control of the City of St. Louis, the Wayne
County Air Pollution Control Division, and the New Jersey
State Bureau of Air Pollution Control.
Mrs. Anne Cassel was responsible for editorial review
and Mr. Chuck Fleming prepared the graphics.
111
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TABLE OF CONTENTS
ACKNOWLEDGMENT
LIST OF FIGURES xi
LIST OF TABLES xv
1.0 INTRODUCTION 1-1
2.0 FUEL-FIRED INDIRECT HEAT EXCHANGERS 2-1
2.1 Theory of Combustion 2-1
2.1.1 Combustion Chemistry 2-1
2.1.2 Fuel Combustion Characteristics 2-5
2.2 Overall Combustion Process 2-6
2.3 Coal-Fired Indirect Heat Exchangers 2-11
2.3.1 Coal Handling 2-13
2.3.2 Coal Classification 2-15
2.3.3 Coal-Firing Techniques 2-17
2.3.4 Process Instrumentation and Control 2-32
2.3.5 Sources and Characteristics of
Emissions 2-34
2.4 Oil-Fired Indirect Heat Exchangers 2-39
2.4.1 Fuel Oil Process 2-39
2.4.2 Fuel Oil Classification 2-41
2.4.3 Oil Burners 2-41
2.4.4 Process Instrumentation and Control 2-45
2.4.5 Sources and Characteristics of
Emissions 2-47
2.5 Gas-Fired Indirect Heat Exchangers 2-48
2.5.1 Gas Flow Processes 2-48
2.5.2 Natural Gas Classification 2-48
2.5.3 Gas Burner Configurations 2-50
2.5.4 Process and Control Instrumentation 2-53
2.5.5 Sources and Characteristics of
Emissions 2-53
v
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TABLE OF CONTENTS
2.6 Combination-Fuel-Fired Indirect Heat
Exchangers 2-54
3.0 INCINERATORS 3-1
3.1 Principles of Incineration 3-1
3.1.1 Refuse Properties 3-2
3.1.2 Grate Processes 3-2
3.1.3 Ignition Process 3-4
3.1.4 Combustion Air 3-4
3.1.5 Mixing and Gas Residence Times 3-5
3.2 Overall Incineration Process 3-6
3.2.1 Single Chamber Incinerators 3-6
3.2.2 Starved Air Incinerators 3-6
3.2.3 Multiple Chamber Incinerators 3-7
3.2.4 Incinerator Charging Methods 3-8
3.2.5 Hearth and Grate Systems 3-11
3.2.6 Furnace Wall Enclosures 3-14
3.3 Municipal Incinerators 3-14
3.3.1 Delivery and Weighing 3-14
3.3.2 Tipping Area and Storage Pits 3-14
3.3.3 Shredders 3-16
3.3.4 Charging Methods 3-17
3.3.5 Furnace Characteristics 3-17
3.3.6 Sources and Characteristics of
Emissions 3-21
3.4 Municipal Sewage Sludge Incinerators 3-25
3.4.1 Multiple Hearth 3-26
3.4.2 Other Sludge Incineration Techniques 3-26
3.4.3 Sources and Characteristics of
Emissions 3-28
3.5 Residential/Commercial/Industrial
Incinerators 3-29
3.5.1 Residential and Small Commercial
Incinerators 3-29
3.5.2 Wood Waste Incinerators 3-29
3.5.3 Pathological Waste Incinerators 3-32
vi
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TABLE OF CONTENTS
Page
3.5.4 Brake Shoe Debonding and Electrical
Winding Reclamation Incinerators 3-33
3.5.5 Drum Reclamation Furnaces 3-34
3.5.6 Wire Reclamation Incinerators 3-36
3.5.7 Sources and Characteristics of
Emissions 3-36
4.0 ATMOSPHERIC EMISSION CONTROL METHODS 4-1
4.1 Mechanical Collectors 4-1
4.2 Wet Scrubbers 4-5
4.3 Fabric Filters 4-10
4.4 Electrostatic Precipitators 4-10
4.5 Afterburners 4-11
4.6 Sulfur Oxides and Nitrogen Oxides Emission
Control 4-16
5.0 PROCESS CONTROL AND EMISSION MONITORING
INSTRUMENTATION 5-1
5.1 Process Control Instrumentation 5-1
5.1.1 Steam Pressure 5-1
5.1.2 Flow 5-3
5.1.3 Temperature 5-3
5.1.4 Draft 5-6
5.1.5 Flue Gas Analysis 5-6
5.2 Emission Monitoring Instrumentation 5-7
5.2.1 Automated Instrumentation 5-8
5.2.2 Manual (Intermittent) Sampling 5-19
6.0 INTRODUCTION TO INSPECTION PRACTICES 6-1
6.1 Observing the Plant Environment 6-1
6«2 Interviewing Plant Personnel 6-2
6.3 Inspecting Inside the Plant 6-3
vn
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TABLE OF CONTENTS
Page
7.0 FIELD INSPECTION EQUIPMENT AND RECORDS 7-1
7.1 Basic Equipment 7-1
7.2 Emission Monitoring Instrumentation 7-2
7.3 Field File 7-2
8.0 INSPECTION PROCEDURES: FUEL-FIRED
INDIRECT HEAT EXCHANGERS 8-1
8.1 Inspection of the Combustion Process 8-3
8.2 Inspection of Air Pollution Control Systems 8-9
8.2.1 Particulate Emissions Control Systems 8-9
8.2.2 Sulfur Dioxide Emission Control
Systems 8-11
8.2.3 Nitrogen Oxide Emission Control
Systems 8-11
8.3 Inspection Form 8-12
8.4 Recordkeeping Requirements 8-12
8.5 Procedures for Estimating Emissions 8-12
8.5.1 Flue Gas Volume 8-19
8.5.2 Particulate Emissions 8-21
8.5.3 Sulfur Dioxide Emissions 8-25
8.5.4 Nitrogen Oxides Emissions 8-27
8.6 Example Inspection 8-33
9.0 INSPECTION PROCEDURES: MUNICIPAL
INCINERATORS 9-1
9.1 Inspection of the Incineration Process 9-2
9.2 Inspection of the Air Pollution Control
Systems 9-7
9.3 Inspection Form 9-8
9.4 Recordkeeping Requirements 9-8
9.5 Procedures for Estimating Emissions 9-8
9.6 Example Inspection 9-15
VI11
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TABLE OF CONTENTS
Paqe
10.0 INSPECTION PROCEDURES: COMMERCIAL/
INDUSTRIAL INCINERATORS 10-1
10.1 Design and Operating Factors 10-1
10.2 General Equipment and Facility
Observations 10-2
10.2.1 Residential/Apartment House
Incinerators 10-3
10.2.2 Pathological Incinerators 10-4
10.2.3 Industrial/Commercial Incinerators 10-5
10.2.4 Sewage Sludge Incinerators 10-6
10.2.5 Reclamation Incinerators 10-7
10.2.6 Wood Waste Incinerators 10-7
10.3 Inspection Forms 10-8
10.4 Procedures for Estimating Emissions 10-8
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LIST OF FIGURES
Figure Page
2.1 Effect of Excess Air on Combustion Efficiency.... 2-4
2.2 Simplified Diagram of a Large Fuel-Fired
Indirect Heat Exchange System 2-7
2.3 Rotary Regenerative Air Heater with Gas and Air
Counterflow 2-10
2.4 Process Flow for a Coal-Fired Boiler 2-12
2.5 Coal-Handling Equipment for Truck or Rail
Delivery 2-14
2.6 Fuel-Air Systems for Coal-Firing Operations 2-19
2.7 Single Retort, Horizontal Underfeed Stoker with
Side Ash Discharge 2-21
2.8 Double Retort, Horizontal Underfeed Stoker with
Side Ash Discharge 2-22
2.9 Multiple Retort, Gravity Feed Underfeed Stoker
with Rear Ash Discharge 2-23
2.10 Chain-Grate Stoker with Rear Ash Discharge 2-24
2.11 Vibrating-Grate Stoker 2-26
2.12 Traveling-Grate Spreader Stoker with Front Ash
Discharge 2-27
2.13 Spreader Stoker with Gravity Fly Ash Return 2-28
2.14 Direct-Fired Pulverized Coal Furnace 2-30
2.15 \7arious Methods of Firing Pulverized Coal 2-31
2.16 Circular Burners for Firing Pulverized Coal 2-31
2.17 Cyclone Furnace Operation 2-33
2.18 Boiler Control Systems 2-35
2.19 Emission Sources in a Coal-Fired Process 2-37
2.20 Process Flow for an Oil-Fired Boiler 2-40
2.21 Low Pressure, Air-Atomizing Burner 2-44
2.22 Detail of Low Pressure, Air-Atomizing Burner
Nozzle 2-44
2.23 Mechanical Atomizing Oil Burner 2-46
XI
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LIST OF FIGURES (Continued)
Figure ]
2.24
2.25
2.26
2.27
2.28
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16
3.17
4.1
4.2
4.3
4.4
Rotary Cup Oil Burner
Process Flow For a Gas-Fired Boiler
Non-Primary Air Aerated Burners
Starved Air Incinerator
Multiple Chamber Incinerator Flow Diagram
Cutaway of a Retort Multiple-Chamber Incinerator .
Cutaway of an In-Line Multiple-Chamber
Reciprocating Grates
Rocking Grates
Drum Grates
Traveling Grates
Municipal Incineration Operation
Plan of Tipping Area and Storage Pits with
Crane
Sources of Atmospheric Emissions from a
Municipal Incinerator
Sludge Treatment System
Typical Section of a Multiple-Hearth Sludge
Incinerator
Sources of Emission from Sewage Sludge
Incineration
Unmodified Flue-Fed Incinerator
Conical Burner for Wood Waste Incineration
Continuous-Type Drum Reclamation Furnace with
an Afterburner
Dust Settling Chamber
Conventional Reverse Flow Cyclone
Cyclones Arranged in Parallel
Spray Tower
Page
2-46
2-49
2-51
2-52
2-53
3-7
3-8
3-10
3-10
3-12
3-13
3-13
3-13
3-15
3-16
3-22
3-26
3-27
3-28
3-30
3-31
3-35
4-2
4-3
4-3
4-7
Xll
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LIST OF FIGURES (Continued)
Figure Page
4.5 Venturi Scrubber 4-7
4.6 Fluid Bed Scrubber 4-9
4.7 Electrostatic Precipitator 4-12
4.8 Relationship Between Collection Efficiency and
Specific Collection Area for Various Coal
Sulfur Contents 4-12
4.9 Relationship Between Collection Efficiency and
Corona Power for Fly Ash Precipitators 4-13
4.10 Relationship Between Collection Efficiency and
Specific Collection Area for Municipal
Incinerators 4-13
4.11 Relationship Between Collection Efficiency and
Delivered Corona Power for Municipal Incinerators 4-14
4.12 Typical Direct-Fired Afterburner 4-15
4.13 Lime/Limestone Scrubbing Systems for Sulfur
Oxides Emission Control 4-18
5.1 Steam Pressure Measuring Elements 5-1
5.2 Heavy-Duty Precision Bourdon Gage 5-2
5.3 Section Through Steam-Flow Mechanism of Boiler
Meter 5-4
5.4 Typical Chart Record Made by Boiler Meter 5-4
5.5 Temperature Measuring System 5-5
5.6 Draft Measuring Vertical Scale Indicator 5-7
5.7 Gaseous Pollutant Monitor with Sampling and
Conditioning Systems 5-9
5.8 Light Transmission System 5-10
5.9 Nondispersive Infrared System « 5-11
5.10 Ultraviolet Photometry System 5-12
5.11 Electrochemical System 5-13
5.12 Chemiluminescent System 5-14
5.13 Flame Photometric Sulfur Monitor 5-15
5.14 Correlation Spectrometer System 5-17
5.15 Flame lonization Monitor 5-18
Xlll
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LISl1 OF FIGURES (Continued)
Figure Page
8.1 Relationship Between Percent Excess Air, 02, CO-,
for Various Fuels 7.... 7 . 8-20
8.2 Volume of Flue Gas Emitted 8-20
8.3 Percent of Ash in Coal Emitted as Fly Ash in
Stoker-Fired Boilers 8-22
8.4 Percent of Ash in Coal Emitted as Fly Ash in
Pulverized-Coal-Fired boilers 8-22
8.5 Electrostatic Precipitator Collection Efficiency
vs. Delivered Power 8-24
8.6 Relationship Between Collection Efficiency and
Collecting Surface Area to Gas Flow Ratio for
Various Coal Sulfur Contents 8-24
8.7 Nomograph for Calculating S02 Emissions 8-26
8.8 NO Emissions from Utility Boilers (Coal- Oil-
ana Gas-Fired Units) 8-28
xiv
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LIST OF TABLES
Table Page
2.1 Characteristics of Coal-Fired Equipment 2-13
2.2 Typical Chemical Composition and Heating Value
for Various Types of Coal 2-16
2.3 Capacity Range of Coal-Burning Equipment 2-16
2.4 Ultimate and Proximate Analyses for a Typical
Coal Sample 2-17
2.5 Properties for Fuel Oils 2-42
3.1 Classification of Wastes to be Incinerated 3-3
3.2 Types of Municipal Incinerator Systems in Use
and Projected for Use 3-18
4.1 Effects of Cyclone-Design Parameters on
Efficiency 4-4
4.2 Range of Collection Efficiencies for Mechanical
Collectors Applied to Combustion Sources 4-5
4.3 Range of Collection Efficiencies for Wet
Scrubbers Applied to Combustion Sources 4-9
7.1 Source Inspection Equipment 7-1
7.2 Source Inspection Field File 7-2
8.1 Design Parameters Affecting Particulate Emission
Rate 8-4
8.2 Plume Characteristics and Operating Parameters .. 8-6
8.3 Recommended Recordkeeping Requirements 8-18
8.4 Particulate Collecting Efficiency for Mechanical
Collectors on Coal-Fired Operations 8-21
8.5 Percentage Decrease in NO Emissions from Utility
Boilers by Combustion Modifications 8-27
8.6 Emission Factors for Industrial and Commercial
Size Boilers 8-29
9.1 Design Parameters for Municipal Incinerators .... 9-3
9.2 Relationship Between Plume Characteristics and
Operating Parameters 9-3
xv
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LIST OF TABLES (Continued)
Table
9.3 Recommended Recordkeeping Requirements for
Municipal Incinerators 9-8
9.4 Municipal Incinerator Emission Factor Summary ... 9-13
9.5 Average Control Efficiency of Air Pollution
Control System 9-14
9.6 Conversion Factors for Particulate Incinerator
Emissions 9-15
10.1 Incinerator Design Parameters 10-2
10.2 Relationships Between Plume Characteristics and
Incinerator Operating Parameters . . » 10-2
10.3 Emission Factor Summary for Commercial/Industrial
Incinerators 10-9
xvi
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FIELD SURVEILLANCE AND ENFORCEMENT GUIDE:
COMBUSTION AND INCINERATION SOURCES
1.0 INTRODUCTION
The Field Enforcement Officer (FEO), often referred to
as the air pollution inspector, performs a vital role in
state and local air pollution control programs. He has
direct responsibility for surveillance of air pollution
emission sources and enforcement of applicable regulations.
He is often the only contact between the agency and industry.
As the agency's representative he must explain its programs,
including such elements as emission regulations, procedures
during air pollution emergency episodes, and requirements for
permits to operate and registration of sources.
Historically, the Field Enforcement Officer has been
primarily concerned with enforcing regulations applying to
visible and particulate emissions, particularly from
fuel-fired indirect heat exchangers (eg. process and power
plant boilers), and incinerators. Since Federal air quality
standards have been established for several gaseous pollutants,
(sulfur dioxide, nitrogen oxides, hydrocarbons, and carbon
monoxide), local governments in many areas have set emission
regulations for these pollutants as well as particulates.
It is now the responsibility of the FEO to enforce these
regulations. This document presents guidelines to assist
the FEO in performing these duties as applied to fuel-fired
indirect heat exchangers and incinerators.
The early sections describe combustion processes, both
fuel fired and incineration. Principles of combustion and
incineration, the overall plant processes (eg. from receipt
of coal to disposal of ash), process and emission monitoring
instrumentation, and sources and characteristics of emissions
are also described. These descriptions are presented at some
1-1
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length because of the variability in experience of the FEO's
who will use this document. For many, this material will
serve merely as a review. For others, especially those
officers recently assigned, the descriptions will provide
the background needed to understand the source inspection
procedures presented in later sections.
Ideally these inspection procedures would culminate
with methods for determining emissions, either by checking
continuous emission monitoring equipment or by applying
relationships between emissions and process operating and
design parameters. Very few facilities, however, are equipped
with continuous monitoring equipment. And there" are no
reliable procedures, except for sulfur oxides, for determin-
ing pollutant emissions by use of process design and
operating data. But calculations based on process operating
and design data can yield gross estimates of emissions, and
methods for making such estimates are presented in this
document. Although they are not sufficiently precise to
determine borderline violations, they can help the FEO to
identify gross violations of emission regulations.
For evaluation of emissions at times other than during
an inspection, the facilities must maintain certain records
of operating conditions to be reviewed by the FEO at the
time of inspection. In addition, copies of certain records
may be periodically sent to the agency. The recommended
recordkeeping requirements, which will facilitate this
review are outlined.
1-2
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2.0 FUEL-FIRED INDIRECT HEAT EXCHANGERS
2.1 Theory of Combustion
Combustible matter in fuels is composed mainly of
three elements: carbon, hydrogen, and sulfur. Combustion,
or burning, is the rapid combination of oxygen with these
fuel elements resulting in release of heat. The oxygen is
supplied by air, which is approximately 21 percent oxygen
and 79 percent nitrogen by volume. For most fuels, only
carbon and hydrogen are important since the percent of
sulfur is so low as to be negligible in producing heat.
Every combustion process requires (1) sufficient
time to complete the chemical reactions, (2) sufficient
temperature to heat the fuel through its various decom-
position stages and to ignite the carbon and hydrogen, and
(3) sufficient turbulence to mix the oxygen and fuel elements
to insure complete combustion plus efficient utilization
of the heat generated by the combustion reactions. Com-
bustion is complete when all the combustible fuel elements
have been fully oxidized (burned).
2.1.1 Combustion Chemistry
2.1.1.1 Chemical Reaction of Fuels with Air. During
burning, oxygen combines with combustible elements and
compounds in fixed proportions by weight to yield heat.
The basic combustion reactions are:
Carbon to carbon dioxide C + 0,, -»• CO0 + heat
^ £*
Carbon to carbon monoxide 2C + 0_ + 2CO + heat
Carbon monoxide to
carbon dioxide 2CO + °2 "*" 2CO2 + heat
Hydrogen to water vapor 2H~ + 0~ •* 2H20 + heat
Sulfur to sulfur dioxide S + 02 -»• S02 + heat
2-1
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Liquid and gaseous fuels are composed of many hydro-
carbon compounds. The molar combustion reactions of the most
common of these hydrocarbons are listed below:
Methane CH4 + 202 -*• CO + 2H20 + heat
Acetylene 2C2H4 + 502 ""4C02 + 2H2° + heat
Ethylene C^E^ + 302 -> 2C02 + 2H20 + heat
Ethane 2C0H,- + 70~ -»• 4C00 + 6H00 + heat
z b 2. 2. 2.
These equations define the "theoretical" or "stoichio-
metric" oxygen required for perfect combustion — that
based on the perfect mixing of fuel and air, with neither
substance left over after the completion of the process.
The theoretical amount of air required is five times the
amount of oxygen.
2.1.1.2 Heat of Combustion. The heat of combustion
is measured as the quantity of heat evolved by burning a
standard unit of fuel (BTU/lb for coal, BTU/gallon for
oil, and BTU/ft for gases). Heat contents of fuels from
different geographical areas differ because of variations
in percentages of carbon and hydrogen. Tables illustrating
heating values for the various types and grades of fuels are
presented in sections describing specific combustion
processes.
2.1.1.3 Ignition Temperature. Ignition temperature is
the temperature that must be attained or exceeded in the
presence of oxygen to cause combustion under given conditions.
When the ignition temperature is exceeded, more heat is
generated by the reaction than is lost to the surroundings
and combustion becomes self-sustaining. Ignition temperatures
are lowest for coal, intermediate for liquid fuels, and
highest for gaseous fuels.
2-2
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2.1.1.4 Air Requirements. The amount of air used
in a combustion system depends on the chemically required
(stoichiometric) amount of oxygen for complete combustion
and the degree of mixing (i.e., the amount of contact of
the oxygen with the combustible fuel elements). With ideal
mixing, the theoretical air-to-fuel ratio provides complete
combustion, with no need for excess air. But since in
practice mixing is never ideal, excess air is needed to
completely burn the combustible matter.
The combustion system operator adjusts the excess air
rate to yield the highest thermal efficiency, the condition
at which the most steam is raised per unit of fuel input.
As shown in Figure 2.1, starting from the low side,
increasing the excess air will decrease the amount of
unburned combustible matter and increase the combustion
efficiency, at the same time diluting and cooling the
combustion gases. At a given point, the system would lose
more heat in the stack gases by further increase in excess
air than would be gained by releasing the remaining heat of
combustion. This point is the point of maximum overall
thermal efficiency.
Excess air requirements vary with types of fuel and
firing equipment. Since gas is easily mixed with air, it
provides complete combustion most easily among the fuels.
Some commercial gas burners can achieve complete combustion
with 0 to 10 percent excess air. Liquid fuels, less easily
mixed with air, require 3 to 20 percent excess air. Coal
requires 10 to 50 percent excess air for economical
combustion and still leaves some unburned carbon in the ash
residue.
2-3
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If
o <
UJ UJ
II
INCREASING EXCESS AIR •
oS
MAXIMUM OVERALL
EFFICIENCY
TOO MUCH
HEAT LOSS
INCREASING EXCESS AIR •
Figure 2.1. Effect of excess air on combustion efficiency.
Combustion processes differ slightly, depending
upon whether fuel and oxygen are mixed as part of fuel
preparation (premix) or immediately before combustion
(burner mix). In general heat applications, burner mix
is most common; in applications requiring precise or stoichio-
metric conditions premix burning is used. Premix burning,
called hydroxylation, is characterized by a small blue flame
with little or no luminescence. Burner mix combustion
thermally cracks the fuel and produces a yellow luminous
flame. Some burning techniques employ a premix or primary
air, followed by a mixture of secondary air. A high primary
air rate produces a short, blue flame, whereas a low primary air
rate results in a long, luminous flame.
2-4
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2.1.2 Fuel Combustion Characteristics
Combustion characteristics differ with various states
of fuels: solid, liquid, and gaseous.
2.1.2.1 Solid Fuels. Combustion of solid fuels takes
place in three zones: distillation, incandescence, and
flame. In the distillation zone, volatiles are distilled
from the solid material. In the incandescent zone, the
non-volatile carbon burns in the incandescent coal. In the
flame zone, the volatile matter is ignited by the incan-
descent matter and is burned. Solid fuels are burned in a
fue*. bed, in suspension, or £>y combination of these methods.
2.1.2.2 Liquid Fuels. Liquid fuels are reduced to
small droplets to increase the surface area available for
combining with oxygen. These small droplets are easily
vaporized when exposed to furnace heat, and are in gaseous
form during combustion.
Liquid dispersion or atomization, which is accomplished
by several means, produces fuel in various forms ranging
from a sheet of oil to a very fine mist. The degree of
atomization controls the amount of excess air required to
assure complete combustion.
Two major classes of liquid fuel burners are (1) burners
that vaporize the liquid within the burner and (2) burners
that atomize the liquid so vaporization will occur in the
combustion space. These are discussed in Section 2.4.3.
2.1.2.3 Gaseous Fuels. Gaseous fuels, very easily
dispersed in air, require no fuel preparation. Combustion
of gas takes place in two ways, depending upon when the gas
and air are mixed. When gas and air are mixed prior to
2-5
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ignition, burning proceeds by blue flame hydroxylation.
Cracking, or yellow flame burning, occurs when oxygen is
added to the fuel after both have been heated. Soot and
carbon black can be formed in yellow flame burning if
insufficient oxygen is present or if the combustion process
is stopped before completion.
2.2 Overall Combustion Processes
In indirect-fired heat exchangers, the flame and products
of combustion are separated from the heat transfer medium
(e.g. water or steam). This is in contrast to direct-fired-
heat exchangers where the combustion products do contact
the materials in the process. Examples of the latter include
kilns and incinerators.
More than 30 million fuel-fired indirect heat
o
exchangers are currently in operation in the United States.
They range in size from residential and commercial heating
units to large industrial power plants and electric utility
power generating plants with boilers rated at over 1000
megawatts. Although coal-, oil-, and gas-fired boilers
differ in design and operation, the basic process is the
same. Chemical energy in the fuel is converted into heat,
mechanical energy, or electrical energy.
Figure 2.2 illustrates the overall combustion process
for large units capable of generating either process steam
or electricity. The basic components of the combustion
process are the fuel burning equipment, the furnace, and
the boiler surface. The heat released by combustion is used
to produce hot water or steam in various heat exchanger
sections. Additional heat may be recovered, as required,
2-6
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from the flue gas stream by addition of a superheater surface
to produce superheated steam, a steam reheating surface,
a feed water heating surface (economizer), and an air preheater
to heat the incoming primary air. Components of the combustion
process are discussed in the remainder of this section.
Furnace - The furnace or firebox is usually of
refractory cement, water tube, or firebrick construction.
Types of furnaces and the associated burners are discussed
in greater detail in the sections describing specific
fuel burning operations. Furnaces are rated irt terms of
million BTU/hour of capacity, or when combined with a boiler,
in pounds of steam generated/hour or boiler horsepower. Since
the furnace and boiler are built as an integrated unit, no
sharp distinction is usually made.
Boilers - Boiler heating surfaces are defined as those
parts of shells, drums, or tubes which contact hot gases
on one side and water on the other. Heat is transferred from
the hot gases through the boiler walls to the water on the
opposite side. The transmitted heat raises the water temperature
to the boiling point and produces steam. Boilers are classified
as shell, fire tube, and water tube boilers, with the following
size ranges:
Type of boiler Size range
Ib steam/hour
Shell 650 - 8,.000
Firetube 420 - 25,000
Watertube 10,000 and larger
The shell type boiler is a closed vessel containing
water, with a portion of the shell exposed to a source of
heat, such as fire below it.
2-8
-------
The fire tube boiler incorporates tubes within the shell.
Hot gases from the fire pass through the tubes. Because
heat is absorbed by the tubes as well as by the shell, the
fire tube boiler is much more efficient than the simple
shell boiler.
The water tube is similar, but in this case water
and steam flow through the tubes and the hot gases are
in contact with the outside surface of the tubes. Most
boilers are of the water tube design because it allows
high heat transfer rates.
Fans - Fans move air or gas by imparting sufficient
energy to produce a pressure differential in the air flow
system. The fan usually consists of a bladed rotor or
impeller and a housing, which collects and directs the
gas discharged by the impeller.
Draft is a measure of static pressure in a furnace,
gas passage, flue, or stack; draft is characterized as
forced or induced. Forced draft occurs when air or the
products of combustion are caused to flow through a unit
by maintaining them at a pressure above atmospheric. Induced
draft is caused when air or the products of combustion are
forced to flow through a unit by maintaining them at a
pressure less than atmospheric. Forced draft fans "push"
air and induced draft fans "pull" air.
Economizers - In a steam-generating unit, the
economizer absorbs heat from the flue gas to heat the feed-
water before the water enters the boiler. This removal of
additional heat from the flue gases, yielding more efficient
use of fuels, warrants the term "economizer". The economizer
usually consists of two water drums (or headers) with tubes
of 2- or 3-inch outside diameter connecting the inlet and
outlet drum.
2-9
-------
Air Heaters - The air heater reclaims some heat, which
would otherwise be lost, from the flue gas to heat the air
required for fuel combustion. Practically all pulverized-
coal-fired units require hot air for drying the fuel. Pre-
heated air is not essential for the smaller stoker-fired
units.
The two basic types of air heaters are recuperative
and regenerative. Recuperative heaters transfer heat
directly from <-he hot gases or steam on one side of the
surface to the other side. Regenerative heaters transfer heat
directly from the hot gases to the air through an intermediate
device which is first heated and then cooled.
The rotary regenerative air heater is illustrated in
Figure 2.3. Rotating plates pass through the gas stream,
WARM FLUE CAS OUT COLD AIR IN
PLATE
GROUPS i
./ \ I
PLATE
GROUPS
x
HOT FLUE GAS IN
WARM AIR OUT
Figure 2.3. Rotary regenerative air heater with gas
and air counterflow.3
2-10
-------
become heated, and then pass through the air stream. The
plates give up heat to the air before again entering the gas
stream, thus maintaining the regenerative cycle.
Reheaters and Superheaters - Steam is heated to higher
temperatures in superheaters and reheaters to effect higher
thermodynamic gain and, more importantly, to improve turbine
efficiency. These units are essentially banks of tubes
exposed to the hot gas stream.
Soot Blowers - Soot blowers are lances which release
jets of high pressure steam or air to remove soot deposited
on heat exchanger surfaces. These lances are usually of a
retractable type in large coal and oil burning boiler
installations. Frequency of soot blowing varies from
about one to three times a day for most industrial boilers.
Large power generating stations often soot blow continuously
to minimize emission puffs.
Stacks - Boilers not requiring a high draft can
operate with the natural draft provided by stacks. Large
boilers equipped with superheaters, economizer, and air
heaters, however, undergo such a high total draft loss
that sufficient induced draft cannot be obtained without
the aid of fans.
2.3 Coal-Fired Indirect Heat Exchangers
The selection of the type of coal-fired unit for a
specific application depends on the load demand. A
reference chart relating the various kinds of coal-firing
equipment to several size range scales and facility classi-
fications is listed in Table 2.1.
Figure 2.4 illustrates the overall process from coal
receiving to ash disposal for a coal-fired facility. Use
2-11
-------
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2-12
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of the various processing steps depends upon the type of
furnace at the facility and the quantity of fuel consumed,
2.3.1 Coal Handling
Coal is transported by rail, truck, boat, barge,
conveyor belt, or a combination of these. Unloading is
simple when the coal is dry, because it flows freely. If
the coal is moist or frozen, force may be required to
start it flowing. In hot, dry weather the coal may be so
dry that the fine particles ('fines') will be blown away,
creating a potentially serious dust problem.^
Table 2.1. CHARACTERISTICS OF COAL-FIRED EQUIPMENT
I
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( GNOUP VI - LARGE 1 NOUS TRIAL » 1 TH PROCESS STEAM ',
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A variety of equipment covering the range of plant
requirements is available for unloading coal and
transporting it to outside storage or to inside bunkers
and hoppers. Plants using more than 10 tons of coal per
day usually require complete mechanical coal-handling
equipment.
Figure 2.5 illustrates an arrangement for a medium-
size plant where coal is delivered by rail or truck. The
truck dumps the coal through the grate into the hopper,
from which it is lifted by a bucket elevator to the coal
bunker. The coal is then fed to the stoker hopper.
OPERATING
PLATFORM
LADDER AND
SAFETY CAGE
ELEVATOR
UNLOADING
POINT
Figure 2.5. Coal-handling equipment for
truck or rail delivery.3
2-14
-------
Continuous plant operation often requires outside
storage of coal at or near the site. Part of the
incoming coal goes to outside storage, and the remainder
goes immediately to the furnace. The stockpiled coal is
rotated to minimize such changes as loss in heating value,
reduction of coking power, increase in ignition temperature,
and most important, losses from self ignition. At large
plants, the coal is moved by bulldozers into pits, from
whi'ih it is conveyed to the coal bunkers by belt conveyors.
Sizing operations are confined to crushing and
pulverizing coal for use in either pulverized-coal-fired or
cyclone-fired furnaces; stoker-fired units receive coal
which is properly sized for firing. Screening is not
required except for removal of large foreign objects. For
pulverized firing the coal is crushed if necessary, passed
through a magnetic separator, and ground very fine in
pulverizers, which are generally integrated with the firing
equipment. Crushers are used to produce the larger-size
coal required for cyclone furnaces.
Some plants operate coal crushers so they can burn
coal, which is not screened or sized. In plants with
both pulverized coal and stoker firing, all of the incoming
coal may be sized to suit the stokers, the portion going to
the pulverizers being crushed if necessary.
2.3.2 Coal Classification
The three broad coal classifications are anthracite (hard
coal), bituminous (soft coal), and lignite (brown coal) .
Bituminous coal is by far the most commonly used fuel.
2-15
-------
The American Society for Testing and Materials has
further classified coals in classes and groups based on
the fixed carbon and heating values calculated on a mineral-
free basis. Table 2.2 illustrates typical ranges of chemical
composition for various classes of coals.
Table 2.2.
TYPICAL CHEMICAL COMPOSITION AND HEATING VALUE
FOR VARIOUS TYPES OF COAL
Type
Anthracite
Bituminous
Subbituminous
Lignite
Carbon?
%
75-90
50-80
45-65
35-50
Ash,
%
10-20
5-25
5-25
5-12
Sulfur,
%
0.6-0.8
0.7-4.5
0.7-4.5
1.0
MBTU/lb
11.8-13.0
10.5-14.4
8.5-10.2
6.3
a Total Carbon-Ultimate Analysis
Table 2.3 lists the types of coal-firing units and
furnace sizes used for the various classes of coal.
Table 2.3. CAPACITY RANGE OF COAL-BURNING EQUIPMENT'
Fuel
Anthracite coal
Bituminous coal
Lignite
Equipment
Retort
Traveling grate
Pulverizer
Retort
Traveling grate
Spreader stoker
Pulverizer
Traveling grate
Spreader stoker
Pulverizer
Capacity
range,
,lb fuel/hr
Up to 1000
100-3000
5000 up
300-15000
1500-20000
700-30000
3500 up
1750-30000
1750-30000
4500-60000
Burning rate
furnace
BTU/cuft
15000
30000 to 50000
30000
30000 to 35000
10000 to 25000
30000 to 35000
30000 to 35000
35000
Mesh size
diameter less
than -inches
5/16
3/32 to 5/16
.003
2
1
3/8
.003
3/32 to 5/1 6
3/32
.003
2-16
-------
Two types of analyses are commonly used to describe
coal composition. Ultimate analysis is a determination
of each of the major chemical elements. Proximate analysis
entails determination of four arbitrarily defined groups
of constituents: moisture/ volatile matter, fixed carbon,
and ash. The sum of the fixed carbon and volatile matter
of a coal is termed the combustible portion. Examples of
ultimate and proximate analyses of a typical coal sample
follow in Table 2.4.
Table 2.4.
ULTIMATE AND PROXIMATE ANALYSES FOR A
TYPICAL COAL SAMPLE
Ultimate
Moisture
Ash (corrected)
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
%
9.61
9.19
66.60
3.25
0.49
1.42
9.44
100.00
Proximate
Moisture
Ash
Volatile matter
Fixed carbon
%
9.61
9.37
30.68
50.34
100.00
2.3.3 Coal-Firing Techniques
Coal is either burned in a bed supported by a grate,
as on some types of stoker systems, or it is injected by
some transport medium, mixed with combustion air, and
burned in suspension.
Stokers of various types are all designed to feed
coal uniformly onto a grate within the furnace and to
2-17
-------
remove the ash residue from the furnace zone. Stokers
allow high rates of combustion, and the continuous process of
stoker firing permits refined control and high efficiency.
Pulverized coal and cyclone furnace firing are strong
competitors of the mechanical stoker in J arge systems,
because of the large amount of floor area required for the
stoker grates. Pulverized coal and cyclone furnace firing
are suitable for the largest central-station boiler units,
with outputs of over 10 million pounds of steam per hour.
Mechanical stokers are generally used for smaller loads,
such as space heating and in production of steam with small -
and moderate-size boilers.
Coal-firing units can be classified in three main
groups and subgroups:
(1) Underfeed
(2) Overfeed (moving grate, spreader, vibrating grate)
(3) Suspension fired (cyclone, spreader, pulverized)
The underfeed operation introduces the primary air and
the fuel from below the grate, and the fuel burns from the
top to the bottom of the bed. The overfeed operation
introduces coal to the grate from the top and the primary
air under the grate, and the fuel burns from the bottom
to the top of the fuel bed. Figure 2.6 illustrates
idealized overfeed and underfeed burning processes.
Combustion of coal in suspension is similar in
principle to combustion in an overfeed fuel bed. The
volatile matter is first distilled off and burned.
Secondary air and turbulence in the firing zone then
permit oxygen to come into contact with the particle to
complete combustion. For some suspension-fired units,
2-18
-------
such as the spreader stoker, final oxidation takes place
on grates, whereas in pulverized-coal-fired and cyclone
units, combustion is completed while the fuel is still
suspended.
Types of coal combustion units and normal operating
practices are described in the following sections.
COMHJSTION FUEL
GASES
RAW
FUEL
IGNITION
PLANE
GRATE —
IGNITION.
PLANE
GRATE
i FUEL
*
• f, *
IGNITED FOE!
ASH):
AIR
IDEALIZED UNDERFEED FUEL KD
PRIMARY
AIR
IDEALIZED OVERFEED FUEL BED
Figure 2.6 P . nFuel-air systems for coal-firing operations.'
2.3.3.1 Underfeed Retort Stokers. Underfeed stokers
can be classified by the method of coal feed, horizontal
or gravity; the location of the ash pit, side or end
discharge; and the number of retorts, single or multiple.
The type of unit is generally a function of capacity.
Single or double retort, horizontal underfeed, side
discharge stokers are designed to service boiler units
generating up to 30,000 pounds of steam per hour,
continuously, with slightly higher peak values. Fuel
rates should not exceed 35 pounds of coal per square foot
2-19
-------
of grate surface per hour for water wall furnaces, and 25
pounds of coal per square foot per hour for refractory
wall furnaces. Multiple retort gravity-feed stokers can
be designed with capacities suitable for boiler units
generating from 20,000 to 400,000 pounds of steam per
hour. Fuel rates in multiple retort furnaces range up to
60 pounds of coal per square foot of grate per hour.
In the side discharge, horizontal underfeed stoker,
shown in Figure 2.7, coal is intermittently force-fed to
the fuel bed by a ram or, in very small units, is contin-
uously fed by a screw. The coal moves in a longitudinal
channel, called a retort, usually assisted by an auxiliary
push rod with small pusher blocks at the bottom of the
retort. After the retort is full, the fuel is forced up-
ward by the ram and spills over the top on each side to
form, and to feed, the fuel bed. Air is supplied through
tuyeres at each side of the retort and through air openings
in the side grates. Combustion air is force-fed from a
plenum chamber or windbox through the tuyere openings and
perforated grates. Manually operated dampers admit air
from the central plenum to the ash pits for final burnout
before the ash is dumped.
Some designs of side-dump underfeed stokers rely on
pressure from the incoming raw fuel to achieve distribution
over the side grates. For those wider than 8 feet, however,
distribution is obtained from reciprocating tuyere-block
action between the retort sections, as shown in Figure
2.8. Other designs, with a single center retort, depend
upon agitating grates for fuel distribution.
2-20
-------
COAL
HOPPER
Figure 2.7. Single retort, horizontal underfeed
stoker with side ash discharge.
2-21
4
-------
Figure 2.8. Double retort, horizontal underfeed
stoker with side ash discharge.5
The rear ash-discharge, gravity feed type of under-
feed stoker is usually longer than the side ash-discharge,
horizontal feed type and is always fitted with multiple
retorts. The multiple retort stoker, Figure 2.9, consists
of a series of inclined single retorts placed side by side
with tuyeres, and sloped from front to rear for constant
ash discharge. Each retort is equipped with a primary
ram, which feeds the coal into the ram box at the head of
the retort. From this point, the fuel bed is moved slowly
toward the rear and at the same time is forced upward over
the bank of tuyeres by secondary pushers or by the moving
bottom of the retort. Most of the combustion air enters
through the boxes supporting the tuyeres, which are located
between the retorts. An overfeed or cleanup section is
provided at the rear end of the bank of tuyeres to complete
combustion before the ash is discharged to the pit for
disposal.
Overfire air is commonly used with underfeed stokers
to provide some combustion air and turbulence in the flame
2-22
-------
zone directly above the active fuel bed. This air is
provided by a separate overfire-air fan and is injected
through small nozzles in the furnace walls. Overfire air
is effective in preventing smoke, especially at low loads
with a "lazy" fire, and when sudden increases in coal feed
occur.
COAL HOPPER
ASH
DISCHARGE PLATE
Figure 2.9. Multiple retort, gravity feed underfeed
stoker with rear ash discharge.3
Underfeed stokers are started by placing kindling or
oiled waste over the coal on each side of the retort.
Light air pressure is applied to hasten burning after
ingition is well established.
2.3.3.2 Moving-Grate Stokers. Moving-grate stokers
are classified as overfeed stokers. They are equipped
with chain or traveling grates and with refractory arches
2-23
-------
or overfire~air jets to improve combustion. This type of
stoker is usually designed for forced draft; natural draft
designs are gradually becoming obsolete.
Chain- and traveling-grate stokers can produce up to
300,000 pounds of steam per hour. A continuous fuel burning
rate of 500,000 BTU per square foot of grate per hour can
be achieved.
In chain- and traveling-grate stokers, assembled links
or grates are joined in endless belt arrangements that pass
over sprockets or return bends located at the front and rear
of furnaces. As shown in Figure 2.10, coal is fed from the
hopper onto the moving assembly and enters the furnace
after passing under an adjustable gate that regulates the
thickness of the fuel bed. At the far end of the travel, .
combustion is completed and ash is discharged over the
end of the grate into the ashpit.
COAL HOPPER
COAL GATE
ra BTB BTtfl felTB rata qiTa MTfa HTH puratfarra aira BrfiTSfa HI
-RETURN
REND
STOKER DRI'VE
CHAIN SPROCKET
HYDRAULIC
DRIVE
Figure 2.10. Chain-grate stoker witb rear ash discharge.'
2-24
-------
Most stoker-fired furnaces are provided with water
cooling. Completely water-cooled furnaces require less
maintenance and form less slag than refractory or air-cooled
constructions.
The furnace is ignited by placing kindling over the
coal and lighting it. Sufficient air is admitted to the
compartments to cause the kindling to burn briskly. After
the kindling has ignited the coal, the stoker is started
(1and maintained at a speed adequate to light the entire bed.
2.3.3.3 Vibrating-Grate Stokers. The vibrating-
grate stoker consists of a grate structure supported on.
plates that are free to move back and forth. These units
are either manufactured separately or sold as a "packaged"
unit, consisting of a complete steam or hot water generating
system.
Sizes of vibrating-grate furnaces range from 5,000
to 100,000 pounds of steam per hour. Grate heat release
may range from 350,000 to 500,000 BTU per square foot per
hour. "Packaged" units range from 3 to 30 million BTU
per hour input, and have a maximum boiler capacity of
20,000 pounds of steam per hour.
Figure 2.11 is a sectonal view of a typical vibrating-
grate stoker. Coal is hopper fed, and an adjustable gate
regulates the thickness of the fuel bed. A vibration
generator is located at the front of the stoker. Coal is
fed to the stoker as the entire fuel bed is conveyed down
the inclined grate, and the ash is discharged into the
ash hopper by the vibrations of the grate.
2-25
-------
COAL HOPPER -
COAL GATE .
OVERFIRE-AIR NOZZLES
GRATE TUYERE
BLOC If 5
FLEXING
PLATES
UNDERFIRE AIR PORTS
VIBRATION GENERATOR-
Figure 2.11. Vibrating-grate stoker.
Forced air to the stoker is distributed through com-
partments beneath the stoker, formed by the individual
flexing-grate support plates. A short front arch, supple-
mented by overfire-air jets, is sufficient for proper
combustion. Although both refractory and water walls are
in use, new furnaces use only water-cooled surfaces.
Combustion controls are completely automatic so that
coal feed to the hopper from the bin and ash discharge is
coordinated with load conditions. Forced and induced draft
fans provide the necessary air.
Vibrating-grate stoker furnaces can be fired with
multiple fuels, singly or in combination. If the unit
is to be fired with oil, a thin layer of ash on the grate
will prevent residues from baking onto the surfaces.
2-26
-------
2.3.3.4 Spreader Stokers. The spreader stoker combines
suspension burning and a thin, fast-burning fuel bed on a
grate. A rotating paddle system "throws" coal onto the
grate. Spreader stokers may be stationary, with intermittent
traveling, reciprocating, or vibrating. Spreader stokers
can also burn combinations of coal and wood chips.
Spreader stokers range in size from 5,000 to 400,000
pounds of steam per hour. Burning rates range from 450,000
BTU/per square foot per hour (36 pounds coal per square
foot per hour) on stationary or dumping grates to as much
as 750,000 BTU (60 pounds coal)t on traveling grates.
The modern spreader stoker, as shown in Figure 2.12,
consists of feeder units arranged to distribute fuel over
the grate area, a grate, forced draft systems for both
undergrate and overgrate air, and combustion c<_uicrols to
coordinate air and fuel supply.
COAL
HOPPER
TRAVEL DIRECTION
SIDE-WALL HEADER
Figure 2.12. Traveling-grate spreader stoker
with front ash discharge.5
2-27
-------
An integral part of many spreader-stoker firing systems
is the provision for the return and burning part of the fly-
ash that is removed from the flue gas stream. A gravity
flow fly-ash return is shown in Figure 2.13. Pneumatic
conveying systems are used to reinject material into the
furnace in the high temperature zone above the grate for
burning.
Figure 2.13. Spreader stoker with gravity flow
fly-ash return.^
Traveling-grate spreader stokers are generally installed
with one large plenum or air chamber under the entire grate
surface. Overfire-air systems are useful in promoting good
combustion and reducing smoke formation, especially at
low load.
2-28
-------
Before light-off, the spreader distributes coal evenly
over the grate to a depth of approximately one inch.
Kindling is then placed over a large portion of the coal
surface and ignited. As the fuel ignites, the fan speeds
or dampers are adjusted to supply sufficient combustion air.
2.3.3.5 Pulverized Coal Firing. Since suspension
firing of coal is more complex than stoker firing, many
variations of pulverized-coal-fired equipment are in
operation. These can be classified by processing systems,
types of pulverizers, burner configurations, firing methods,
and ash collection techniques.
Furnaces are further classified depending on the type
of ash removal. If the ash is not molten, the furnace is
called a dry-bottom or dry-ash removal furnace. In a wet-
bottom or slag-tap furnace, the ash is maintained above the
fusion temperature and leaves the furnace bottom in molten
form.
Approximately 80 percent of the ash originally in the
coal in a dry-bottom furnace may be entrained in the flue
gas from the furnace, the remainder going to the ash catch
hopper. In slag-tap furnaces approximately 50 percent of
the ash is entrained in the flue gas.
The bin system and the direct-firing system are used
to process, distribute, and burn pulverized coal. In the
now outdated bin system, the coal is processed at a location
apart from the furnace. It is dried, pulverized, classified
within the pulverizer, and then stored. From storage, the
pulverized coal is conveyed pneumatically to utilization bins.
This system was used extensively before reliable pulverizers
were developed. However, the direct-firing system, as shown
2-29
-------
in Figure 2.14, is now used predominantly. In the direct-
firing system, raw coal is dried and pulverized within the
pulverizer, and the finished product moves to the burners in
a continuous, uninterrupted pattern. Coal and primary air are
mixed before entering the burner.
The several common firing methods, schematically repre-
sented in Figure 2.15, are vertical, tangential, and
horizontal. These methods of firing also apply to furnaces
fueled with oil and gas or combinations of all three fuels.
The three types of burners are the circular burner,
rujltiple-tip burner, and cross-tube burner. Pulverized coal
is fed into these burners, using air as a transport medium,
where it is ignited and mixed with the main combustion air.
The circular type, shown in Figure 2.16, is used
most frequently. Either gas or oil can be burned
effectively as alternate fuels. Capacity of these
individual burners is approximately 165 million BTU per
hour. Most dry-ash removal furnaces have circular burners,
but they are occasionally used in slag-tap furnaces with
the burner wall formed entirely of furnace-cooling tubes.
IY.FASS
rUlVEMZEOCOAL
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(MfMOCTYK)
MUMAftY-
AMFAN
STEAM COH.
AIR HEATER
Figure 2.14. Direct-fired pulverized coal furnace.
2-30
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PRIMARY AIR . -TERTIARY
AND COAL I | AIR
_ PRIMARY AIR
AND COAL
PRIMARY AIR_
AND COAL
.SECONDARY
\
SECONDARY
AIR
MULTIPLE INTERTUBE PLAN VIEW OF FURNACE
PRIMARY AIR PRIMARY AIR
AND COAL AND COAL "1
MULTIPLE INTERTUBE
J
SECONDARY AIR SECONDARY AIRJ
CIRCULAR
SECONDARY AIR
CYCLONE
SECONDARY AIR
PRIMARY AIR
AND COAL
Figure 2.15. Various methods of firing pulverized coal.'
PULVERIZED COAL
AND PRIMARY AIR
PRIMARY AIR
VANES
Figure 2.16. Circular burners for firing pulverized coal.'
2-31
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Pulverized coal burners are stable when ignited and
thus no auxiliary startup fuel is required.
2.3.3.6 Cyclone Firing. Although cyclone firing may
be defined as a method of suspension coal firing, a separate
category is warranted by several basic differences:
(1) cyclone-fired furnaces burn larger size coal; (2) ash
removal is always slag tap; (3) ash recovery is greater than
in other pulverized-coal-fired furnaces (i.e. less ash is
entrained in the flue gas).
Cyclone furnaces can be classified by turnace design,
coal preparation system, feed type, and ash removal system.
Cyclone furnaces are best suited for steam rates of 200,000 Ib.
per hour or higher. Principal use is for steam and electric
generation in public utilities.
Figure 2.17 illustrates operation of the cyclone
furnace. Incoming coal, after being crushed, is thrown to
the walls of the cyclone barrel, held in a slag layer formed
on the walls of the cyclone, and contacted by high tangential
velocity air. The gaseous products of combustion are dis-
charged through the center portion of the barrel into the
boiler. Molten slag in excess of the thin layer retained
on the walls continually drains toward the rear and dis-
charges through the tap hole to a slag tank.
2.3.4 Process Instrumentation and Control
Properly equipped control systems for coal-fired steam
boilers monitor the following variables:
0 steam pressure, temperature, and flow
0 feedwater pressure, temperature, and flow
0 water level
0 furnace and duct draft
0 combustion air flow
0 fuel rate
0 flue gas composition, temperature, and smoke
density (optional).
2-32
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CRUSHED
COAL
HIGH-SPEED
SECONDARY AIR
Figure 2.17. Cyclone furnace operation.
The major variables in boiler operation are flow of
steam, air, and fuel. The basic functions of the boiler
instrumentation, and in larger units the associated automatic
controls, are to adjust fuel supply to maintain constant
steam flow or pressure under varying loads, and to maintain
the proper ratio of combustion air to fuel supply.
Control system instrumentation for a specific boiler
depends largely on the boiler size and the desired degree of
control of steam production. The three major categories of
control systems all respond to variations in steam pressure:
0 On-Off controls are limited in practice to firetube,
shell, and small watertube boilers. A steam pressure "band"
is defined such that a drop in pressure beyond the lower
2-33
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limit actuates a switch to start the stoker or burner and open
the air damper. When the pressure reaches the upper limit of
the tolerance band, fuel flow stops. With these controls
combustion efficiency is low and steam header pressure can
vary appreciably.
0 Positioning controls are used on medium-sized units,
including most packaged boiler systems. A master pressure
controller, responding to changes in steam header pressure,
changes the settings on the forced draft damper, which
controls air flow and stoker speed. Although pressure can
be maintained within closer limits than with the on-off
control system, air/fuel ratios still vary.
0 Metering controls function by measuring fuel and
air flows and modifying fuel rates and damper positions to
maintain correct air/fuel ratios.
Schematics of these control systems, and variation
between actual and ideal air/fuel ratios under varying load
conditions, are shown in Figure 2.18.
A change in steam demand initiates a signal from the
steam pressure controller that causes a change in fuel and
air quantities. The steam flow/air flow instrument compares
the index of the rate of fuel being burned (proportional to
steam flow) to a calibrated air flow index and initiates
any readjustment of the air damper required to maintain the
desired firing conditions.
Furnace draft is regulated separately by use of a
furnace draft controller.
2.3.5 Sources and Characteristics of Emissions
Coal-fired steam or power generating facilities can emit
particulates, sulfur oxides, nitrogen oxides, and to a lesser
2-34
-------
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extent, hydrocarbons, and carbon monoxide. In addition, trace
quantities of various elements (e.g. chlorine, lead, beryllium)
can be emitted. The points of emission from coal-fired heat
exchangers are shown on Figure 2.19. Although several types
of pollutants are emitted, particulates, sulfur dioxide and
nitrogen oxides are of primary concern to the field enforcement
officer since the other pollutants are emitted in much lesser
quantities.
2.3.5.1 Coal Preparation, Conveying, and Storage Areas.
Unburned coal fines can become airborne at any point before
entering the coal feeder. Oil and calcium chloride, used for
dustproofing the coal, is usually applied at the mine. But
it is sometimes necessary to reapply it at the boiler site to
reduce fugitive dust emissions if the small coal sizes and
high winds present significant dust potential.
2.3.5.2 Furnace Emissions.
0 Particulate Emissions - The amount of fly ash emitted
depends on several factors, the more significant ones being
composition of the coal, boiler design, and boiler steam rate.
Other conditions remaining fixed, fly ash emission will be
approximately proportional to the ash content of the coal.
Boiler design and operation determine the percentages of ash
retained in the furnace and emitted in the flue gas. The
amount of ash emitted usually ranges between 20 percent, for
cyclone-fired units, to 80 percent, for pulverized-coal-fired
units. This corresponds to a range of approximately 20 to
200 pounds of particulates emitted (prior to the control device)
per ton of coal burned.
0 Sulfur Dioxide 'Emissions - The SO2 content of the
flue gas is a function of the sulfur content of the coal.
2-36
-------
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About 90 percent of the sulfur in the coal is oxidized to SO-
and less than 5 percent forms SO-,. The rest remains in the
particulate matter, slag and ash residue. For a 2 percent
sulfur content coal, approximately 80 pounds of S02 would be
emitted per ton of coal burned.
0 Nitrogen Oxides Emissions - Nitric oxide (NO) is formed
in the furnace at temperatures in excess of about 2800°F from
the reaction between atmospheric nitrogen and oxygen. It can
also be formed at much lower furnace temperatures by the reaction
of oxygen with the organically bound nitrogen contained in the
fuel. The NO, once formed, is slowly oxidized to NO^ at
temperatures below 1100°F. The NO- contribution to the total
NO (NO + NO-) emitted is usually about 3 to*5 percent. The
X £.
remaining 95 percent of the NO is slowly oxidized to NO- in
the ambient air.
The main factors affecting the amount of NO formed are:
ji
the nitrogen content of the fuel, the flame and furnace
temperature, the length of time the combustion gases are
maintained at the flame temperature, the rate of cooling of
the gases and the amount of excess air present in the flame.
Because of the large number of parameters involved in NO
X
formation, emissions vary widely even between similar types
of units. Emissions can range between 3 and 60 pounds of
NO- per ton of coal burned.
0 Carbon Monoxide and Hydrocarbon Emissions - Carbon
monoxide and hydrocarbon emissions are very low for all but the
smallest units; in these smaller units proper control over
combustion is more difficult to maintain. If the furnace is
operated at low excess air (below about 5 percent) or if
staged firing is used, the CO emissions may increase sharply.
Indeed, when the furnace is "tuned" to minimize NO emissions,
X
it is the increase in the CO emissions above 200 ppm which
2-38!
-------
usually sets the limit (i.e. the excess air requirement is
reduced until the CO level reaches 200 ppm). In a well
"tuned" furnace utilizing low excess air firing or staged
combustion, CO emissions are expected to be about
200 ppm.
2.3.5.3 Ash Discharge. Ash from control device hoppers
and cleanout systems must be properly handled to eliminate
the possibility of fugitive dust emissions. The ash is usually
conveyed by water to a silo or settling pond. The waste dumped
from the silo into trucks must remain moist before transporting
to a landfill site, settling pond, or other destination.
2.4 Oil-Fired Indirect Heat Exchangers
2.4.1 Fuel Oil Process
Typical flow in a fuel oil-fired combustion system
from initial receiving of the oil to generation of steam
is shown in Figure 2.20.
A filter eliminates particles that could clog oil
lines and nozzles. A pressure ratio regulator ensures that
proper amounts of fuel and air (or steam) enter the burner
to allow effective atomization. After the fuel is ignited
in the furnace, the process is identical to coal or gas
burning.
Optimum oil burner operation depends on careful control
of fuel viscosity. A burner functions properly only if oil
viscosity at the burner orifice is held between fairly
narrow limits. If viscosity is too high, effective atomization
does not take place. If viscosity is too low, excessive oil
will flow through the burner orifice, upsetting the balance
of combustion air and fuel.
2-39
-------
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The oil preheaters required for burning residual fuel oils
are located at the supply tank, since the oil must be heated
before it can be pumped to the burners. Preheat temperatures
depend on the type of oil.
Oil preheaters are operated with either electricity or
steam. Electrical heaters are more flexible, since they
can be used when the combustion equipment is cold and no
steam is available. If an oil burner is ignited from a
cold start, and the oil is not preheated to its normal
temperature, burner ignition is often difficult or impossible.
2.4.2 Fuel Oil Classification
The term fuel oil applies to a wide range of liquid
petroleum products including crude oil, distillates, and
residuals. In Table 2.5, pertinent properties of the
various grades of fuel oil are listed. Numbers 1 and 2 are
distillate oils; Numbers 5 and 6 are residuals or "bottoms"
from refinery processes. Number 4 oil is likely to be a blend
containing appreciable distillate stock even though it is
classified as a residual fuel. Distillate oils contain less
sulfur and ash than do the more viscous residuals.
Residual fuels are less expensive than distillate oils
but require more elaborate process equipment at the combustion
facility. Thus the selection of fuel is based on consideration
of the trade-offs between capital equipment cost and annual
operating cost, which includes the fuel cost. The sizes of
combustion units typically using the various types of fuels
are shown in Table 2.5.
2.4.3 Oil Burners
Oil is burned by reduction to small droplets that can
be easily vaporized and ignited when exposed to furnace heat.
2-41
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Table 2.5. PROPERTIES OF FUEL OILS
Grade
1
1
4
5
6
Description
A distillate
oil intended
for vaporizing
pot-type burn-
ers and other
burners re-
quiring this
grade of fuel .
A distillate
oil for gener-
al-purpose do-
mestic heating.
for use in
burners not
requiring No .
1 Fuel oil .
An oil for
burner instal-
lations not
equipped with
preheating fa-
cilities.
A residual -
type oil for
burner instal-
lations equip-
ped with pre-
heating facil-
ities.
An oil for use
in burners
equipped with
preheaters per-
mitting use of
high viscosity
fuel.
Flash pt.
min . F
100
100
130
130
150
Water and
sediment, %
by volume
trace
0.10
0.50
1.00
7.00
Max.
ash,
%wt
-
-
0.10
0.10
-
Sugg 'sfd
preheat
temp.fF
-
-
-
170-220
220-260
Avg. heat
conrtnf,
BTU/gal
136,000
142,000
145,000
148,000
151,000
Sulfur
content
range
0.10 to
0.50
0.10 to
1 .00
0 .20 to
2.00
0 .50 to
3.00
0.70 to
4.00
Size
installation
using fuel
domestic
units
200 hp
200 to
1000 hp
1000 hp
Liquid dispersion or atomization produces burnable oil in
various forms ranging from a sheet to an extremely fine mist.
The degree of atomization controls the amount of excess air
required to assure complete combustion.
Liquid fuel is burned by two general methods. The first
is to vaporize the liquid within the burner. Vaporizing
burners are fired only with the most volatile distillates and
are used only in the smallest space heaters. Because of the
2-42
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high fuel costs, vaporizina burners are seldom used in
larger installations.
The second method of breaking up the liquid fuel is
to atomize it by mechanical means in the burner so that
vaporization occurs in the combustion space. This is
accomplished by forcing oil under pressure through a
nozzle, by applying centrifugal force or by use of an
auxiliary fluid to inject the oil into the combustion
chamber.
With low-pressure, air-atomizing burners, as shown in
Figure 2.21 and the nozzle portion detailed in Figure 2.22,
a major portion of the required combustion air is supplied
near the oil orifice at 1 to 5 psig to atomize the oil
stream. Secondary combustion air is admitted around the
periphery of the mixture. In comparison with other types of
oil burners, these units introduce a higher percentage of air
in close proximity to the atomized oil. High-pressure steam
or air-atomizing burners use either steam or air to atomize
the fuel oil stream at the burner tip. The auxiliary fluid,
moving at high velocity atomizes the slower-moving oil stream
as the mixture passes into the burner tip. Pressure
of the atomizing fluid ranges from 30 to 175 psig. High-pressure
burners atomize with considerably less air than low-pressure,
air-atomizing burners. Compressed air consumption ranges
from 30 to 200 cubic feet of air per gallon of oil, about
2 to 15 percent of the theoretical combustion requirement.
Oil pressure atomizing burners depend upon high fuel
pressure (75 to 150 psig) to cause the oil to break up into
small droplets upon passing through an orifice. The fixed
orifices of these units are considerably smaller than those
2-43
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Air inlet
Micro-metering
oil valve
Quick-disconnect
oil valve lever
Oil inlet
Secondary
atomizing
air
\ Primary
~^~ atomizing
Figure 2.21. Low-pressure, air-atomizing burner.'
OIL-
Figure 2.22. Detail of low-pressure,
air-atomizing burner nozzle.^
2-44
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used with other types of oil burners. These burners atomize
properly over a fairly narrow pressure range. No air is
mixed with the fuel oil.
Mechanical atomizing burners are the most common oil
burners at large power plant steam generators. The fuel oil
is given a strong whirling action by diffuser vanes before
it is released through the tip, as shown in Figure 2.23.
Proper atomization depends on high centrifugal velocities,
Which in turn require high oil pressure.
Rotary cup burners, such as that shown in Figure 2.24,
provide atomization by throwing the fuel centrifugally from
a rotating cup or disc. No air is mixed with the oil before
atomization. Combustion air is admitted through an annular
port around the rotary cup. These burners are usually
constructed with integral forced-draft blowers. A common
motor drives the oil pump, atomization cup, and blower.
2.4.4 Process Instrumentation and Control
The descriptions of boiler instrumentation and combustion
control systems presented in Section 2.3.4 for coal-fired
boilers apply generally to all indirect heat exchangers.
The differences between oil- and coal-fired boilers are
discussed in this section.
Fuel flow/air flow combustion controls are popular on
gas- and oil-fired units in which severe load fluctuations can
occur. Steam flow/air flow devices used for coal-fired
boilers are momentarily in error during major load changes
because the fuel consumption is normally higher or lower
than is indicated by the steam flow load index.
Steam header pressure is the control parameter. The
output from the steam pressure controller is relayed to an
2-45
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BLADED CONE AIR-DOOR HANDLE
IMPELLER ,
OBSERVATION AND
LIGHTING DOOR
QUICK-DETACHABLE
COUPLING
! DOORS
STEAM SUPPLY
Figure 2.23. Mechanical atomizing oil burner.
8
MOUNTING HINGE
MOTOR
OIL
Figure 2.24. Rotary cup oil burner.
2-46
-------
actuator regulating air flow from a forced-draft fan.
A change in air flow causes a pressure drop in the furnace;
this drop is sensed by fuel flow instrumentation, which
changes the fuel rate. A ratio relay station is interposed
in the system to enable the operator to maintain the optimum
air/fuel ratio.
A flame-failure sensing device is usually an integral
part of the combustion control system. In the event of
flame failure, fuel flow immediately stops. Oil-fired
boilers use visible light photocells or temperature sensors
to detect flame failure.
2.4.5 Sources and Characteristics of Emissions
Combustion gases from the furnace represent the only
potentially significant emissions source. Particulates,
sulfur oxides, nitrogen oxides, hydrocarbons and carbon
monoxide, as well as trace amounts of volatile materials
contained in the oil (e.g. vanadium), can be emitted.
Particulate emissions will vary depending upon the
type of fuel oil. The usual range is between 0.07 pound per
million BTU for distillate oil burned in domestic units,
to 0.15 pound per million BTU for boilers burning residual
oils.
Sulfur dioxide emissions are a function of the sulfur
content of the fuel oil. The typical range is between 0.5 and
3.5 pounds per million BTU burned in power plant, industrial-
and commercial-size boilers.
Nitrogen oxides emissions are highly variable, as discussed
for coal-fired boiler emissions in Section 2.3.5. NO emissions
X
typically range between 0.25 pound per million BTU fov
commercial-size boilers to greater than 0.8 pound per million
BTU for large power plant boilers.
2-47
-------
Carbon monoxide and hydrocarbon emissions are usually
low except in units which are improperly operated and have
low combustion efficiencies. Carbon monoxide is usually between
0.04 and 0.2 pound per thousand gallons and hydrocarbons between
2 and 3 pounds per thousand gallons of fuel burned.
2.5 Gas-Fired Indirect Heat Exchangers
2.5.1 Gas Flow Processes
Natural gas is generally piped directly to the consumer,
with no need for storage at the consumer's plant. Natural
gas as delivered is substantially free of sulfur and ash,
burns without smoke, and mixes easily and'intimately with
air to give complete combustion with low excess air.
Because the hydrogen content of natural gas is higher
than that of oil or coal, more water vapor is formed in
combustion and efficiency of the steam generating equipment
is slightly lower than that of a large well operated coal-
fired unit. Although the many types of gas burners differ
in the manner in which air is combined with gas, processes
downstream of the burners are similar to those of burning
coal and liquid fuel.
Figure 2.25 represents a gas process from storage
facility to burner.
2.5.2 Natural Gas Classification
Natural gas fuel is a mixture of hydrocarbons, of
which methane and ethane predominate. Some natural gase's
also contain sulfur compounds, but these are extracted
from the gas before delivery to the consumer. Because
natural gas supplies contain varying percentages of different
hydrocarbons, gross heating values range from 900 to 1200 BTU
per standard cubic foot in different localities.
2-48
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2-49
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In addition to natural gas, other gaseous compounds
are mixed and used for combustion. One popular mixture
is liquified petroleum gas (LPG), which consists of one
or more of the followincr: propane, propylene, butane, and
butylene. The advantages of LPG are the high gross heating
value (about 3000 BTU per standard cubic foot) and the ease
of handling.
For a given fuel, the combustion efficiency and the
stability, shape, and luminosity of the flame depend on the
primary and ^v=condary air rates and the degree of turbulence.
A high primary air rate produces a short, blue flame, whereas
a low primary air rate produces a long, luminous flame.
Excessive pri™=iry air results in a smoky flame with yellow
tips.
2.5.3 Gas Burner Configurations
Gas burners are considerably simpler than those used
with either solid or liquid fuels. Little excess air is
required to complete the combustion since the gases mix
easily with the combustion air and no preheating is needed.
Only a portion of the total air requirement, the
primary combustion air, is mixed with the fuel before
ignition in partially aerated burners. Two other burner
types in fairlv wide> use are the totally aerated burner and the
non-primary aerated burner. In totally aerated burners
all combustion air is mixed with fuel before ignition.
In non-primary burners, no combustion, air is mixed with
fuel ahead of the burner port and all combustion air is
actually secondary air.
Figure 2.26 illustrates operation of the partially
aerated gas burner. Gaseous fuel is introduced through the
control valve into the burner head and allowed to flow through
the fixed orifice into the throat. The jetted gas stream
2-50
-------
induces combustion air to flow through the primary air port
and creates enough tui-bnlence to mix fuel and air between
the orifice and the burner tip. The quantity of induced
primary air is regulated by air port setting, gas pressure,
and specific gravity. Ignition starts at the burner tip,
where additional (or secondary) air contacts the mixture.
Combustion IP completed after the burner tip where additional
secondary air reacts with the burning mixture.
PRIMARY AIR
INS PIRATED
SECONDARY AIR •
INSPIRATED
Figure 2.26. Partially aerated gas burner.
Figure 2.27 illustrates a common natural-draft industrial
type burner with air aspirated at the nozzle (spud) and
burner throat. Although the air is supplied at two different
points, the fuel and air are mixed prior to ignition. Another
type of totally aerated burner applies high pressure to
aspirate the gas. The governor diaphragm controls the amount of
gas admitted to the aspirator to produce the correct fuel-
to-air ratio.
2-51
-------
-- GAS LINE
.SHUTTER
„ ,. _. /.SPUD HOLDER
GAS VALVE t /BURNffi tODY
WALL CASTING / / • wr>T7Ii:
SPUD
BURNER THROAT--
PRESSURE GAGE
Figure 2.27. Totally aerated gas burner.
Non-primary aerated, or nozzle mix burners mix air and
gas at the burner tile, as shown in Figure 2.28. The
burner may be a standard forced-draft register with the gas
emitted from holes at the supply pipe tip (Figure 2.28.a).
In Figures b and c, rings drilled with small holes disperse
gas more effectively but can plug more easily. In Figure
2.28.d a spider is located in the burner inlet. Gas is
released sideways, causing the spider to rotate. The spider is
attached to a fan, so that forced draft is provided by the
movement of the spider.
Gas burners are controlled by regulating only the
flow of gas in aspiratory burners or by regulating both
gas and air where these are controlled separately.
For all gas burners just described, firing arrangements
can be identical to those for pulverized coal and oil
furnaces shown previously in Figure 2.15.
2-52
-------
AIR
REGISTER
CAS
SUPPLY'-
IGNITION
TUBE
GAS-
OUTLET
HOLES
IGNITION
TUBE
GAS
SUPPLY
AIR
REGISTER,
GAS RING
GAS-
OUTLET
HOLES
(A) BLUNT PIPE
(B) SMALL RING
GAS
SUPPLY
AIR
REGISTER
GAS-
OUTLET
HOLES
IGNITION
TUBE
(C) LARGE RING
GAS
SUPPLY
INTEGRAL
FAN
GAS-
OUTLET
HOLES
SPIDER
(D) TURBINE
Figure 2.28. Non-primary air aerated burners.
4
2.5.4 Process Instrumentation and Control
As mentioned earlier, the descriptions of boiler
instrumentation and combustion control systems presented
in Section 2.3.4 for coal-fired systems apply generally to
all indirect heat exchangers. The differences between
gas-fired boilers and the previously mentioned systems are
discussed in this section.
The presence of a flame is sensed by a conducting flame-
rod or by an ultraviolet or infrared light detector. In the
event of a flame failure during operation, the fuel supply
immediately stops. The furnace and gas passages are purged
with air before the burners are relighted.
2-53
-------
Steam header pressure regulates the supply of primary
fuel by actuating the fuel supply system. Since air/fuel
ratios are diffe^nt tor each fuel, output signals from each
fuel meter form the basis of air flow regulation.
2.5.6 Sources and Characteristics of Emissions
The combustion gas from the furnace is the only
significant emission source. The major pollutant is
nitrogen oxides, although hydrocarbons and carbon monoxide
emissions can be significant if there is insufficient combustion
air.
As with coal- and oil-fired units, NO emissions
X
from gas-fired units are highly dependent upon the unit's
combustion characteristics. NO emissions typically range
it
between 0.05 pound per million BTU for small commercial
units to 0.4 pound per million BTU for large .power plant
boilers.
Hydrocarbon emissions range from 0.008 pound, per million,.
BTU for the small commercial boilers to 0.04 pound per
BTU for power plant boilers. Carbon monoxide emissions vary
between 0.02 pound per million BTU for small commercial boilers
to only trace amounts for the large industrial and power plant
boilers. Sulfur oxides and particulates are approximately
0.0006 and 0.018 pound per million BTU, respectively.
2.6 Combination-Fuel-Fired Indirect Heat Exchangers
Many industrial units burn combinations of coal, oil,
or gas because of fuel availability, price fluctuations,
and the requirements for temporary fuel switching necessitated
by air pollution emergency episodes.
2-54
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Stoker-equipped furnaces are sometimes arranged for
auxiliary firing with oil and gas. The oil and gas
burners must be so arranged that the flame does not impinge
on furnace walls or grate surfaces. If change-over from
coal to the auxiliary fuels is frequent, a small amount of
air is usually admitted through the idle gas or oil burners
to prevent clogging by the coal ash. If auxiliary fuels are
rarely used, throat plugs are installed in the idle burners.
Some applications warrant not only a change-ov^r from
one fuel system to another, but also the capability to burn
more than one type of fuel simultaneously. For example,
cyclone firing is an excellent method for burning oil and
gas as well as coal. Streams of oil may be injected either
into the secondary air stream or through the front coal
burner, where the oil is picked up and atomized by the high-
velocity air. Gas is fired through flat ports located in
the secondary-air entrances to the cyclone. Gas and oil
burners located in the roof may be left in place when coal
is fired; thus fuel switching can be done by remote control
without removing the cyclone furnace from service. Pulverized-
coal-fired units are also usually amenable to switching fuel.
In this type of unit, the coal nozzle is withdrawn from the
furnace and the oil or gas nozzle is inserted.
Multiple burners represent a design compromise. As a
result, many facilities using combination burners generate
more particulate emissions than those burning a single fuel.
2-55
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References - Chapter 2
1. Smith, W, S. and Gruber, C. W. Atmospheric Emissions
from Coal Combustion - An Inventory Guide. Springfield,
Va. NTIS No. PB 170-851. 1966
2. Background Information for Proposed New-Source Performance
Standards; Steam Generators, Incinerators, Portland Cement
Plants, Nitric Acid Plants, and Sulfuric Acid Plants.
Springfield, Va. NTIS No. PB 202-459
3. Steam, Its Generation and Use. Babcock & Wilcox Company.
37 edition. New York, N. Y. 1963
4. Perry, R. H. et. al. Perry's Chemical Engineers Handbook.
Fourth edition. McGraw Hill, New York, N. Y.
5. Adapted from: Steam, Its Generation and Use. Babcock &
Wilcox Company. 37th edition, New York, N. Y. 1963
6. Babcock & Wilcox Bulletin BR-71. New York, N. Y.
7. Danielson, J. A. Air Pollution Engineering Manual. DHEW
Springfield, Va. NTIS No. PB 190-243, 1967
8. Babcock & Wilcox Bulletin 6-53. New York, N. Y.
Additional Information Sources
1. Fryling, G. R. Combustion Engineering, A Reference Book
on Fuel Burning and Steam Generation. Combustion Engineering
Inc. New York, N. Y. 1967
2. North American Combustion Handbook. First edition. North
American Manufacturing Company, Cleveland, Ohio. 1965
3. Oglesby, S. and Nichols, G. A. Manual of Electrostatic
Precipitator Technology. Southern Research Institute,
Springfield, Va. NTIS No. PB 196-381
4. Vandegrift, A. E. et. al. Handbook of Emissions & Control
Practices for Stationary Particulate Pollution Sources
Midwest Research Institute, Springfield, Va. NTIS No.
PB 203-522
2-56
-------
3.0 INCINERATORS
Incineration is defined as the disposal of waste
materials by burning in an enclosed structure. The
process of incineration reduces the weight, volume and
volatile contents of the refuse.
Incinerators are constructed with one or more combustion
chambers. With single chamber incinerators, control of
smoke, volatilized gases, and soot is difficult because of
the lack of control over combustion air and temperature.
Single chamber incinerators are operated in residential
dwellings and small commercial establishments/ such as
markets, restaurants, and grocery stores.
Multiple chamber incinerators are used in larger
operations (e.g., capacities greater than 100 pounds per
hour) and in those that require better control of the
combustion process. They are used for disposal of municipal
refuse, pathological wastes, and a multitude of commercial
and industrial wastes.
The principles of incineration are reviewed in Section
3.1. Then follows a description of specific furnace and
grate systems used with the various types of incinerators.
The incineration systems used for municipal and various types
of industrial and commercial wastes are then described.
3.1 Principles of Incineration
Incinerators are combustion systems that burn refuse.
Thus, the same fundamental combustion considerations appli-
cable to indirect-fired heat exchangers also apply to
incinerators. Refuse, however, differs markedly from fossil
3-1
-------
fuel and its characteristics vary over a wider range.
Thus the systems that incinerate refuse differ from those
that burn fossil fuels.
3.1.1 Refuse Properties
Table 3.1 presents seven waste classifications defined
by the Incinerator Institute of America (IIA). In comparing
refuse and fossil fuels these points are important:
0 The quantity and characteristics of the residue
from burning refuse necessitate more extensive
ash handling equipment.
0 Grate-loading rates for solid wastes are much
lower than those for solid fuels.
0 Theoretical air requirements for refuse are lower
than for other fuels, but the methods of combustion
require higher excess air rates.
3.1.2 Grate Processes
Refuse is incinerated on a grate surface similar to
those used for coal combustion. While on the grate, the
refuse goes through the following stages: drying, ignition,
residue burn-out, and residue cooling.
The high moisture content of refuse causes it to burn
slowly. Increasing the underfire air rate increases the rate
of refuse drying by evaporation, intensifies the fire, and
thus increases the burning rate. If the air rate becomes
too high, however, appreciable quantities of ash and metallic
salts and oxides can be entrained in the flue gas.
When the undergrate air flow is too low, substantial
amounts of carbon monoxide are formed by the incomplete
oxidation of carbon. Carbon monoxide may also be formed by
moisture from the refuse flowing to the surface of the bed
and reacting with the residue carbon.
3-2
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3.1.3 Ignition Process
The ignition front is the surface in the fuel bed at
which combustion starts. Energy is released by the
combustion reactions occurring at the front; below the
front, the refuse is being dried.
Ignition is achieved by the use of overfire combustion
air and by charging in such a manner that the refuse will
be dried with a minimum of underfire air. Thus, the
charging door is usually located as far as possible from
the flame port, so that the volatiles from the fresh charge
pass through the flames of the stabilized and heated portion
of the burning fuel bed.
3.1.4 Combustion Air
Combustion air consists of underfire, overfire, and
secondary air. Underfire air is supplied below the grate
to dry the refuse, cool the grates, and supply oxygen for
the combustion reactions. Overfire air is admitted above
the burning bed of refuse to assure ignition and complete
burning of the volatile elements. It is usually admitted
through openings in the charging door or incinerator walls.
Secondary air is added through high-velocity jets in the
side walls and roof of the furnace enclosure to allow
temperature control.
High-velocity combustion air (mainly used on larger
units) is supplied by centrifugal fans. Low-velocity air
is admitted through louvers, doors, or other openings, as a
result of the negative pressure or draft within the furnace
chamber.
In suspension burning, the amount of air that conveys
the shredded refuse into the chamber may be between 50 and
3-4
-------
100 percent of the theoretical air required for combustion.
Excess air is added at points in the furnace chamber to
induce mixing. If the suspension burning system has a
grate at the bottom of the furnace chamber to complete
residue burnout, a small amount of underfire air is also
passed through the grate.
3.1.5 Mixing and Gas Residence Times
In every combustion process, enough time must be
allowed to complete the chemical reactions and enough
turbulence provided to mix the oxygen and volatilized
components. These features can be assured by designing the
combustion system (1) so that furnace volume is adequate
for the needed retention times, and (2) so that changes in
velocity and direction of flow provide the needed turbulence.
Single chamber furnaces cannot provide enough time and
turbulence; hence ineffective mixing usually leads to in-
complete burning of soot, carbon monoxide, and hydrocarbons.
The turbulent mixing of multiple chamber incinerators
is achieved by use of restricted flow areas and abrupt changes
in flow direction. After primary combustion takes place,
the gases are passed into a mixing chamber before additional
combustion takes place in a secondary chamber.
The variety of incinerator systems in use today results
from different combinations of the following incinerator
subsystems or components:
0 Refuse feeding mechanism - batch or continuous;
0 Furnace construction - single or multiple combustion
chamber, refractory or water walls;
0 Refuse support - various grate systems, hearths,
or suspension burning.
3-5
-------
3.2 Overall Incineration Process
Furnaces may have one or more combustion chambers,
and refuse may be fed either in batches or continuously. Most
large incinerators/ especially the large municipal incinerators,
are continuously fed, and all but the most rudimentary are
equipped either with multiple combustion chambers or with a
single combustion chamber and an afterburner.
3.2.1 Single Chamber Incinerators
In single chamber incinerators one chamber serves for
ignition, combustion, and ash removal. Controlling the
smoke, volatilized gases, and fly ash emissions is difficult.
Combustion efficiency is improved and emissions reduced by
use of auxiliary fuel injection, design modifications, and
emission control devices.
3.2.2 Starved Air Incinerators
The "starved air" or "controlled air" incineration systems
meter air into a closed combustion chamber to control burning
in a process that produces combustible carbon monoxide rather
than carbon dioxide. As shown in Figure 3.1, waste is fed
into the primary combustion chamber, olaced on a. hearth, and
ignited. Gases from the primary chamber pass to the secondary
combustion chamber where they are mixed with preheated air
and ignited by a gas jet. The mixture burns at temperatures
of 2000°F to 2400°F.
A blower introduces air to the bottom of the combustion
chamber through headers. The air supply is proportional to the
amount needed in the combustion chamber; as the fire becomes
hotter, the concentration of oxygen decreases, automatically
reducing the rate of burning.
3-6
-------
Oxygen starved incinerators burn Types 0 through 4 wastes
in capacities of 100 to over 1000 Ibs. per hour. Volume
reductions range from 10:1 to greater than 100:1, depending
on waste composition.
STACK
SECONDARY
COMBUSTION
CHAMBER
PRIMARY
COMBUSTION
CHAMBER
PREHEATED AIR
BLOWER
Figure 3.1. Starved air incinerator.
3.2.3 Multiple Chamber Incinerators
In multiple chamber incinerators, the combustion
process proceeds in two stages: primary or solid fuel
combustion in the ignition chamber, followed by secondary
or gaseous-phase combustion in a separate chamber. This
process is schematically illustrated in Figure 3.2.
3-7
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The incineration process begins in the ignition
chamber, where drying, ignition, and combustion of the waste
takes place. A flame port connects the ignition chamber
with the mixing chamber. Moisture and volatile components
are vaporized and partially oxidized in passing through
the flame port. Additional air, augmented by secondary
burners as necessary, assists in initiating the second stage
of combustion. The gaseous-phase reaction is aided by
turbulent mixing, caused by abrupt changes in flow direction
and restricted flow areas. After the gases leave the mixing
chamber, they pass through the curtain wall port to the
secondary combustion chamber, where final oxidation of
combustible components take place. Fly ash and other
particulate matter are collected in the combustion chamber
by impingement on the chamber wall or by settling. The gases
are then discharged through a stack, usually passing through
some type of air pollution control device before entering
the atmosphere.
There are two basic types of multiple chamber incinerators,
retort and in-line. In the retort type, as shown in Figure
3.3, the horizontal, vertical, and lateral gas flow directions
change before the gas is discharged through the stack. In
the in-line type, component chambers are arranged one after
the other in a line, as shown in Figure 3.4. Both designs
include ignition, mixing, and secondary combustion chambers.
3.2.4 Incinerator Charging Methods
Most large incinerators are operated by continuous
charging because it enables better combustion control. Batch
feeding often admits significant quantities of cold air to the
furnace during charging and thereby disrupts the combustion
process.
3-9
-------
SECONDARY
COMBUSTION
CHAMBER
MIXING
CHAMBER
FLAME PORT
CURTAIN
WALL PORT
CLEANOUT
DOOR
CLEANOUT DOOR
WITH UNDERGRATE
AIR PORT
IGNITION
CHAMBER
CHARGING DOOR
WITH OVERFIRE
AIR PORT
GRATES
ASH PIT
- FLAME PORT
SECONDARY
AIR PORT
MIXING CHAMBER
BURNER PORT
MIXING CHAMBER
CURTAIN WALL PORT
Figure 3.3. Cutaway of a retort
multiple-chamber incinerator.
_/ IGNITION
CHARGING'DOOR, , CHAMJER
WITH OVERFIRE ""
AIR PORT
SECONDARY
AIR PORT
FLAME ,-CURTAIN WALL
GRATES
CLEANOLT DOORS WITH '
UNDERGRATE AIR PORTS LUCATION OF
SECONDARY
BURNER MIXING CHAMBER
SECONDARY
COMBUSTION
CHAMBER
CURTAIN
WALL PORT:
CLEANOUT
T DOORS
Figure 3.4. Cutaway of an in-line
multiple-chamber incinerator.l
3-10
-------
Small municipal incinerators and most commercial/
industrial incinerators are batch fed.
3.2.5 Hearth and Grate Systems
Nearly all incinerators incorporate either a refractory
hearth to support the burning refuse or one of a variety
of grate structures, which stoke or mix the refuse during
the combustion process. Grates are distinguished from
hearths by the openings through which ash and underfire air
can pass. Hearths are essentially solid and have no under-
fire capability. Suspension burning may also require a
hearth or grate if combustion is not completed while the
refuse is in suspension.
3.2.5.1 Stationary Hearth. Stationary hearth furnaces
are used in small commercial and industrial incinerators.
The stationary hearth is usually the refractory floor of the
furnace. Either overfire or side air ports are used. A
blade mechanism may load the hearth with refuse and remove
the ash residue. The number of rotary hearth systems tha-f-
exist are so few that no discussion is warranted.
3.2.5.2 Rotary Kiln. Rotary kilns, preceded by a
drying and ignition grate, are used as incinerators by some
industries. The kiln is a slowly revolving cylinder inclined
toward the discharge end. Drying and partial burning of the
refuse take place on grates before the material is fed into
the kiln, where the cascading action exposes it to complete
combustion.
3.2.5.3 Stationary Furnace Grate. Stationary grates
are used in a variety of incinerator furnaces, ranging from
small flue fed units to large municipal incinerators. The
grates are of simple cast or fabricated metal design. Manual
stoking of the burning refuse bed is required to obtain
reasonably complete residue burnout.
3-11
-------
3.2.5.4 Mechanical Grates. Mechanically operated
grates include reciprocating, rocking, drum, and traveling
grates. These are mainly used on large municipal incinerators,
The grates are usually installed in a slightly inclined
position, with the lower end at the ash discharge point.
As the refuse burns, the grates are manually controlled to
move the burning bed toward the discharge hoppers. Some
batch-feeding processes occasionally require the operator to
manually spread the burning refuse over the grate or to
•
remove larger pieces of metal or clinkers.
Figure 3.5 illustrates the reciprocating grate arrange-
ment, in which alternate grates are moved to cause the refuse
to cascade toward the discharge end.
MOVING
GRATES
FIXED
GRATES
Figure 3.5. Reciprocating grates.
Figure 3.6 illustrates the rocking grate. Alternate
rows of grate sections rotate about a pinned end toward the
discharge area. The burning mass is dislodged as the grate
rotates and is thrust toward the residue hopper.
3-12
-------
RAISED POSITION
NORMAL POSITION
Figure 3.6. Rocking grates.
The drum grate, or roller grate, is shown in Figure
3.7. Rotation of the drums creates a strong mixing action
of refuse between successive drums.
Figure 3.7. Drum grates.
The traveling grate, Figure 3.8, is widely used in
continuously fed incinerator furnaces. The two principal
types of traveling-grate stokers are the chain grate and
the bar grate.
(f° U ]D DIG DID DID DI°).
2
Figure 3.8. Traveling grates.
3-13
-------
3.2.6 Furnace Wall Enclosures
The design of incinerator walls depends upon the
maximum operating temperature expected within the furnace.
Typical materials of construction include refractories,
metals, and combinations of these such as firebrick-covered
metal. The walls may be cooled with water or air.
3.3 Municipal Incinerators
Municipal incinerators are designed to dispose of
combustible wastes from residential, commercial, and industrial
sources. Capacity of small municipal incinerators ranges
from 50 to 100 tons per day; some of the larger incinerators
burn more than 1000 tons per day. Most existing units are
lined with refractory brick and operate at excess combustion
air rates of at least 150 percent.
A typical municipal incineration process is illustrated
in Figure 3.9. Individual operations include solid waste
delivery, storage, preparation, charging, burning, and ash
discharge.
3.3.1 Delivery and Weighing
Incoming and outgoing trucks are weighed on scales, which
vary from simple beam scales to electronic relay scales.
Incinerators with capacities of 100 or more tons per day
generally require two or more scales, one to weigh loaded
vehicles and the otner t<~< weigh empty trucks.
3.3.2 Tipping Area and Storage Pits
After being weighed, the trucks move to the tipping area
which, as shown in Figure 3.10- is usually adjacent to the
storage pits or charging hoppers. At large installations
the trucks unload into a storage pit, whereas in smaller
3-14
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3-15
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incinerators the waste may be dumped directly into the
furnace-charging hopper or onto the tipping floor. An
overhead crane redistributes the waste and charges the
incinerator hoppers.
CRANE
OVERRIDE
AREA
111 f*
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CHARGING
. FLOOR
Figure 3.10. Plan of tipping area and
storage pits with crane.
3.3.3 Shredders
Shredders are used only in the more recently developed
suspension burning incinerators. The waste is shredded by
a shearing or guillotine action, which reduces the refuse
to particles about 1 to 2 inches in length. The waste is
then blown into the furnace for incineration. Combustion
occurs largely in suspension, although some residual burning
may be done on a grate or other type of hearth. Large
foreign objects must be removed from the refuse.
3-16
-------
3.3.4 Charging Methods
Cranes are used at large municipal incinerators to
transfer the waste to the charging hoppers from the storage
pit. At smaller incinerators, where the storage area and
charging hoppers are on the same level, front end loaders,
vibrating hoppers, or conveyors are used for charging.
Although the feeding of the refuse may be either batch
or continuous, most recently constructed incinerators use
continuous firing to improve combustion control. Batch
feeding of refuse directly into the furnace is usually done
with a clam-shell bucket or grapple attached to a traveling
crane.
The most frequently used continuous feeding system is
the hopper and gravity chute. Refuse is fed to the hopper
by a crane and bucket. A chute leads from the hopper to the
furnace grate or other feeder conveyor. The hopper is always
filled to some degree with refuse to provide an air seal at
the feed opening to the furnace.
3.3.5 Furnace Characteristics
As mentioned earlier, a multiplicity of furnace designs
stems from the variety of incinerator subsystems available.
Table 3.2 lists percentages of the various types of furnace
designs in use in 1968 and the projected usage of the various
types through 1985. The more common units are described in
the following sections.
3.3.5.1 Batch Feed Incineration System. Most con-
temporary municipal batch feed incineration systems consist
of vertical cylindrical chambers or rectangular cell units,
with capacities as low as a few tons per day to as high-.as-
300 tons per day.
3-17
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Refuse accumulated in the feed hopper is periodically
charged by opening a sliding gate between the hopper and the
primary chamber. When the charging gate is opened, the
furnace draft draws large quantities of air into the furnace,
disrupting the combustion process. Dual gate air-lock
systems or ram feeders are sometimes used to prevent this.
The charging doors on vertical cylindrical batch feed
incinerators are directly above the grates. The refuse on
the grates is stoked either manually or mechanically by a
rotating cone with extended air-cooled arms. The residue or
ash is pushed to the outside of the furnace, where manual or
hydraulically operated dumping grates are periodically lowered
to discharge the accumulated ash. Any glowing char in the
ash hopper is quenched by water sprays.
On rectangular batch feed furnaces, the charging doors
are in the middle or near the rear of the roof of each
furnace cell. The refuse travels from the rear to the front
of the furnace, the resulting ash falling from the front of
the grates to the ash discharge system below. A few plants
discharge partially burned refuse to the ash pits, where
complete burnout takes place.
The typical batch incinerator is equipped with fans to
force underfire air through the grates. Overfire air is
introduced through furnace wall ports in the primary combustion
chamber. Flue gases from the primary combustion chambers
pass into the secondary chamber, where the combustion of
volatile gases and particulates is completed. Downstream of
the secondary chamber, wetted baffle systems, cyclone dust
collectors, or more commonly, settling chambers are used to
remove some of the particulate matter entrained in the flue
gas.
3-19
-------
Batch-feed incinerators provide relatively little control
of the combustion process. The high burning rate often
overwhelms the constant air supply, causing particulate and
gaseous emissions from the primary and secondary chambers.
In addition, the fresh charge of refuse may mix with the ash
and be discharged before it is satisfactorily incinerated.
3.3.5.2 Continuous Feed, Rectangular Furnace System.
Refuse from a storage pit is transferred to the charging
hopper, from which it moves by gravity down the feed chute
and into the primary combustion chamber. The refuse in the
feed chute serves as a seal that prevents the gases in the
primary combustion chamber from exiting through the chute.
Refuse entering the primary chamber is ignited by the burning
refuse and by radiation from the hot refractory.
Underfire air passes through the grates and up through
the refuse bed. Overfire air is forced through jet nozzles
in the primary chamber walls. Combustion of the volatile
gases and particulates is completed as the gases pass through
the secondary chamber.
The residue leaving the primary chamber may fall directly
into a dry-ash pit or into a water-filled quench tank for
subsequent disposal.
3.3.5.3 Continuous Feed, Ignition Grate Plus Burnout
Kiln Furnace. The ignition grate plus burnout
kiln utilizes grates to dry and ignite the refuse and a rotary
kiln to complete the combustion. Underfire air is preheated
by using it to cool sections of the refractory walls in the
ignition chamber and is forced through the ignition grates.
As refuse drops from the drying grate to the ignition grate,
the larger pieces are broken up. The partially burned refuse
is discharged from the ignition grate section into a revolving
inclined rotary kiln. The refuse/residue mixture slowly
3-20
-------
tumbles through the kiln; unburned refuse is exposed to
the high-temperature gases to complete the incineration.
3.3.5.4 Continuous Feed, Waterwall Furnace. The
continuous feed waterwall incinerator is similar to the
refractory wall incinerator. Refuse feed, grate design,
residue removal, and ash handling subsystems are identical.
Unlike the incinerators previously described, however,
watercooled furnaces are equipped with boiler tubes to
recover heat, followed by an economizer and possibly an
air heater.
Such units operate at excess air levels in the 50 to
100 percent range, since the walls can absorb higher heating
loads. Soot blowers are required to keep tube surfaces clean.
3.3.5.5 Advanced Municipal Incinerator Designs. Many
new incineration techniques such as horizontal cylindrical
furnaces, and semi-continuous package systems have been
proposed. None of these units, however, is yet in wide-
spread commercial use.
3.3.6 Sources and Characteristics of Emissions
Municipal incinerators can emit combustible and mineral
particulates, combustible gases (carbon monoxide, hydrocarbons,
and odors) and noncombustible gases (nitrogen oxides, sulfur
oxides, and hydrogen chloride). The points of emission from
the incineration operation are shown in Figure 3.11. Although
several types of pollutants are emitted, particulates and odors
are of primary concern to the field enforcement officer, since
the other pollutants are usually emitted in lesser quantities.
3.3.6.1 Receiving and Storage Areas. Since these areas
can be a source of odors, litter, and dust, they require
close attention to proper handling and housekeeping procedures.
3-21
-------
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3.3.6.2 Furnace. The furnace is the major source of
emissions. Particulates, nitrogen oxides, carbon monoxide,
and hydrocarbons can be emitted in significant quantities.
Particulate emissions from the furnace consist of smoke,
soot, fly ash, grit, and a multitude of carbonaceous compounds.
Uncontrolled particulate emissions may vary from 5 to 100
4
pounds per ton of solid waste burned. Excessive amounts of
underfire air cause higher emission rates due to carry-off
of material from the burning bed. Insufficient combustion
air or low temperatures in the secondary or combustion chamber,
lead to excessive amounts of smoke (combustible or volatile
particulate).
Nitrogen oxide emissions from municipal incinerators are
low in comparison to the quantity emitted by other sources
(e.g. about one-tenth the amount from boilers). Because of
the low temperature at which incinerators generally operate,
most of the NO is formed by direct conversion of chemically
bound nitrogen in the refuse (in contrast with boilers, where
the nitrogen in the combustion air reacts at the higher furnace
temperatures to form NO). Refuse rich in food wastes, textiles,
and yard wastes contain the most nitrogen, and would be expected
to give the highest NO emissions. Decreasing the amount of
excess air in the furnace has the effect of raising the temper-
ature and should lead to greater NO emissions. About 1 to 3
percent of the NO leaving the furnace is in the form of N0~.
X ^
Hydrocarbon emissions are due to pyrolysis and cracking
of volatile refuse components on the refuse bed. Since hydro-
carbons are destroyed by combustion within the bed and in the
overfire air region, most of the hydrocarbons are emitted from
the first third of the grate (or the first few minutes after
3-23
-------
charging in batch-fed units), when the ignition and initial
drying/burning processes are occurring. Under these conditions,
the rapid release of combustibles make great demands upon the
available air supply and unburned hydrocarbon material passes
from the bed into the overfire region, where mixing limitations
often prevent complete combustion before these materials pass
to the stack.
The combustion of hydrocarbons occurs in two stages:
rapid oxidation to carbon monoxide, followed by the relatively
(Jslow oxidation of the CO to CO-. As a result, hydrocarbon
emissions are always associated with CO emissions. Because
the hydrocarbon reaction to CO is faster than the CO reaction
to C02/ CO emissions are always very much greater than hydro-
carbon emissions.
On a weight basis, carbon monoxide is the most significant
pollutant emitted from municipal incinerators. Furthermore,
existing air pollution control devices do not significantly
reduce CO emissions. Carbon monoxide emissions are due to
poor mixing and to quenching by misplaced overfire-air jets.
Sulfur content of the refuse averages only about 0.1
percent. Resulting S0_ emissions are between 1 and 2 pounds
per ton of refuse fired. Hydrogen chloride emissions are
due to the burning of the polyvinyl chloride found in increasing
amounts in municipal solid waste.
3.3.6.3 Residue Disposal. The ash residue removed from
ignition chambers must be water-quenched before transport
to a landfill site. Particulates from control device hoppers
should also be water-treated to reduce fugitive dust. A
shroud should be used between, the hopper discharge and receiving
truck or car to reduce dust emissions.
3-24
-------
3.4 Municipal Sewage Sludge Incinerators
Sludge incinerators are used to reduce the volume of
sludge generated by municipal waste water treatment plants
by burning the combustible content. An inert, odor-free
residue is produced, suitable for landfill.
The sludge incineration process involves three steps:
preliminary dewatering, drying, and combustion. Mechanical
dewatering techniques are needed because the moisture content
of sludge is high, greater than 90 percent. Drying and
combustion may be done separately or successively in the
same unit. Sludge drying and combustion equipment include
multiple hearth furnaces, flash drying units, fluidized bed
units, atomized spray units, and wet oxidation units. Self-
sustained combustion is often possible with dewatered raw
sludge once the burning of auxiliary fuel raises temperatures
to the ignition point.
Figure 3.12 is a generalized schematic of a sludge treat-
ment system. Raw sludge feeds either into a gravity settling
tank or directly into a dewatering device. The waste, either
raw or digested, enters the dewaterer, where moisture is
removed. The sludge is left as a cake-like substance, which
may be stored, depending on the maximum capacity of the
incinerator. Mineral ash and stack gases are the end products
after the sludge is dried and incinerated. Ash is cooled,
discharged, and transported hydraulicaliy, mechanically, or
pneumatically to lagoons; it may also be stored dry and hauled
periodically to landfill areas.
3-25
-------
NATURAL
GAS
STACK
GASES
DIR
WA
i
TREAT
PLA
TY
TER
MENT
NT
I
CLEAN FLO
WATER
RAW THICKENING
LUDGE OR
TANK
(OPTIONAL)
CCULENT '
AIDS
DIGESTING
TANK
(OPTIONAL)
DEWATERING
DEVICE
bLUUVjt
CAKE
|
AIR POLLUTION
CONTROL
DEVICE
•I INCINERATOR
ASH RESIDUE «-
Figure 3.12. Sludge treatment system.
3.4.1 Multiple Hearth
A typical multiple hearth furnace, the most popular sewage
sludge incinerator in use, is shown in Figure 3.13. Partially
dewatered sludge is continuously fed to the upper hearths,
which form a drying and cooling zone. Intermediate hearths
form a high-temperature combustion zone, where all volatile
gases and solids are burned. Combustion of most of the total
fixed carbon is completed on the lower hearths.
3.4.2 Other Sludge Incineration Techniques
Flash drying, fluidized bed, atomized spraying, and wet
oxidation are methods which are occasionally used to incinerate
sewage sludge. In a flash drying system, moisture is reduced,
by heating, to about 10 percent before being blown into the
furnace. Fluidized bed operations suspend sand and sludge by
upward moving air; oxidation occurs as the sludge is held in
3-26
-------
COOLING AIR DISCHARGE
FLOATING DAMPER
SLUDGE INLET
FLUE GASES OUT
RABBLE ARM
AT EACH HEARTH
DRYING ZONE
COMBUSTION J
ZONE
COOLING ZONE
ASH
DISCHARGE —
COMBUSTION
AIR RETURN
- RABBLE ARM
DRIVE
COOLING AIR FAN
Figure 3.13. Typical section of a
multiple hearth sludge incinerator.
3-27
-------
suspension. Atomized sludge incinerators reduce particle size
by grinders, then spray the sludge particles through a reactor,
The waste is dried and burned in suspension. Wet oxidation
refers to sludge incineration in an aqueous medium by heating
and pressurizing the waste before burning takes place in a
reactor.
3.4.3 Sources and Characteristics of Emissions
Odor emission is the major air contaminant from an
incinerator burning sewage sludge. At a typical sewage
treatment plant, odors may emanate from many sources as shown
in Figure 3.14, including accumulation of grit, screenings
and skimmings, raw sludge thickening, storage in tanks,
vacuum filtration of raw sludge, incineration and heat drying
of sludge.
NATURAL
GAS
PARTICUIATE
STACK CO.
GASES SOx
ODORS
ODORS
DIRTY
WATER
^
TREATMENT
PLANT
1
RAW
SLUDGE
,
>
THICKENING
OR
SETTLING
TANK
(OPTIONAL)
DIGESTING
TANK
(OPTIONAL)
I \'*~'i ' IwMN^U/ '*•" •" ' - ' • '
-j "——
CLEAN
WATER
FLOCCULENT
AIDS
ASH RESIDUE «-
I
Figure 3.14. Sources of emission from sewage
sludge incineration.
3-28
-------
The ash discharged from sewage sludge incinerators is
essentially free of all organic compounds and hence odors.
However, removal of ash residue can be a source of fugitive
dust emissions if proper handling and ash containment procedures
are not followed.
The primary end products of combustion are carbon monoxide,
carbon dioxide, sulfur dioxide, odors, and inert ash.
3.5 Residential/Commercial/Industrial Incinerators
Residential, commercial, dad industrial operations entail
a multitude of different types of incinerators depending upon
specific incineration requirements. Most of these units are
batch-fed, and many are of single chamber design. The most
widely used units are described in the following sections.
3.5.1 Residential and Small Commercial Incinerators
Many multiple-dwelling units that incinerate refuse use
flue-fed incinerators. A flue-fed incinerator, as shown in
Figure 3.15, is one in which the stack also serves as a chute
for refuse charging. The single chamber, flue-fed incinerator
has a rectangular combustion chamber separated by dump grates
from an ash pit below. Garbage and other wet materials are
dried by use of gas burners located below the grates. A
charging door above the grates is used for igniting and stoking
the refuse. Ashes fall to the ash pit and are removed through
a cleanout door. Underfire and overfire air openings are
nsually incorporated in both doors.
3.5.2 Wood Waste Incinerators
Some lumber and woodworking plants use cylindrical silo
incinerators or conical burners to burn wood waste. A number
of industries, such as cotton ginning, with similar wastes also
use these types of incinerators.
3-29
-------
CHARGING DOOR
OVERFIRE AIR PORT
BASEMENT FLOOR
CLEANOUT DOOR
UNDERFIRE AIR PORT
Figure 3.15. Unmodified flue-fed incinerator.'
3-30
-------
The conical burner consists of a sheet metal shell
supported by structural steel members in the shape of a tepee
with a mesh screen on top. The metal shell is cooled by
peripheral air, which flows around the metal. Generally these
systems provide little control over combustion air. Some units
incorporate an underfire air system using blowers to supply
air around the base of the burning refuse pile. In many units,
however, air enters the unit only through small openings at
the base of the unit, with little possibility of control.
Figure 3.16 shows a typical conical burner used for wood waste
combustion.
SCREEN .
TANGENTIAL AIR INLETS
Figure 3.16. Conical burner for wood waste incineration.
3-31
-------
A silo incinerator consists of a vertical steel cylindrical
chamber sometimes lined with refractory brick and covered with a
screen. Combustion air is admitted through louvers located
near -hhe base of the structure. Because high temperatures
can be maintained in the refractory-lined chamber, combustion
efficiencies are higher than in conical units. However, good
combustion control is difficult.
Multiple chamber incinerators for burning wood waste use
both in-line and retort designs similar to those described in
Section 3.2.3.
Primary air ports on continuously fed incinerators are
sized for introduction of approximately double the theoretically
required air. Underfire air ports admit about 10 percent of
the total air, the remaining 90 percent being added above the
grates. Cleanout doors are provided for removal of ash residue
from the primary and secondary combustion chambers. Most
multiple chamber wood-burning incinerators are not equipped
with air pollution control equipment.
Wood waste can also be effectively burned in spreader
stoker coal-fired units as described in Section 2.3.
3.5.3 Pathological Waste Incinerators
Pathological waste includes all organic wastes of human
and animal origin. It is composed principally of carbon,
hydrogen, oxygen, and small amounts of nitrogen and contains
approximately 85 percent water. Particulate emissions from
pathological units are usually small, but potential for odor
emissions is so great that multiple chamber incinerators are
always used.
Waste is charged onto a solid hearth rather than a grate
system because fluids are released in such quantities that
they do not immediately evaporate. Primary air ports are not
3-32
-------
used, since the waste does not require passage of air through
the burning material. Leakage of air into the primary chamber
provides sufficient primary combustion air. Gases move through
the mixing chamber into the secondary combustion 2one at low
velocities to ensure complete combustion. An auxiliary burner
in the secondary combustion chamber maintains a high gas
temperature. Large pathological units usually incorporate high
stacks to dilute potential odors.
3.5.4 Brake Shoe Debonding and Electrical Winding
Reclamation Incinerators
Brake shoes and electrical equipment are reclaimed by
both single- and multiple-chamber incineration. Emissions from
single chamber incinerators are reduced by installation of an
afterburner. Two basic equipment configurations are used. One
is a single structure housing the primary and secondary
combustion chambers; the other consists of two separate pieces
of equipment, a primary chamber and an afterburner or secondary
chamber. Many variations of these two configurations include
the following:
0 A continuous process device using an endless chain
conveyor that transports material into a tunnel-like
chamber. Products of combustion, smoke, and volatile
components are collected near the center of the tunnel
and vented to an afterburner. Continuous process
equipment of this type usually has a higher heat
requirement than corresponding batch-fed equipment
because of the introduction of excessive air at the
openings to the primary chamber.
0 A semi-continuous operation consisting of two
refractory-lined compartments connected back to back.
While material is being processed in one of the
compartments, the other is being unloaded and loaded.
Smoke and gaseous effluents are vented to a vertical
afterburner and stack.
3-33
-------
In the brake debonding process, brake shoes are charged
to an oven, called a debonder, where heat is applied carefully
to avoid damage to the shoes. The organic adhesive portions
of the lining start to melt, and as the temperature is
increased volatilization proceeds until all the combustibles
have been consumed. Brake shoe adhesives usually have sufficient
heating value to maintain burning without external heat. In
the electrical reclamation incinerator, combustible organic
compounds used for insulation begin to volatilize upon applica-
tion of heat. Since the combustible content of electrical
windings is insufficient to sustain burning, auxiliary heat
is supplied by primary burners.
3.5.5 Drum Reclamation Furnaces
Steel drums used in transporting and storing chemicals
and other materials are cleaned, repaired, and repainted for
reuse. Most drum reclamation is done in single chamber
furnaces. Both batch- and continuous-fed furnaces are used.
Both types are refractory lined to conserve heat within the
furnace.
In a batch type process, gas burners are arranged around
the chamber to cover the exterior drum surface completely
with flame. Air is supplied through air ports in the side of
the chamber. The drums are placed in the chamber open end
down so the residual materials will melt and flow out of the
drum as well as burn. The flame applied to the exterior surface
burns off the grease, paint, and other coatings. Ignition of
molten material on the interior burns off the interior surface
coatings.
Continuous-type furnaces, illustrated in Figure 3.17,
are constructed in the form of a tunnel through which the
drums pass on a drag conveyor. After entering the tunnel
3-34
-------
upside down, the drums pass through the preheat zone, where
they are heated by radiation from the ignition zone. They
then pass through the ignition zone, where the combustibles
in direct contact with burner flames ignite and burn. They
further pass through the cooling zone, where a small amount
of burning continues until combustion is complete and the
drums are cooled by induced air. The gases are combined
with secondary air in the ignition zone and led to an after-
burner. Secondary air ports provide about 100 percent of the
theoretical combustion air.
• STACK
DRUM OUTLET OPENING
SECONDARY
AIRPORT
SECONDARY
BURNER
PRIMARY
BURNER
AFTERBURNER
(SECONDARY
COMBUSTION
CHAMBER)
•I BAFFLE
Figure 3.17. Continuous-type drum reclamation
furnace with an afterburner.!
3-35
-------
3.5.6 Wire Reclamation Incinerators
Copper scrap is recovered from insulated wire in both
single and multiple chamber incinerators. Batch units are
usually constructed in one of two configurations: a dual
structure consisting of a primary chamber venting through an
afterburner, or a single structure containing a primary chamber
and one or two secondary combustion chambers arranged as in a
multiple-chamber incinerator.
In a single chamber furnace, wire is ignited with a hand
torch or a gas burner mounted through the side of the chamber.
The burning process is self-sustaining after ignition. After
burnout, the wire is cooled and the char adhering to the upper
surface is removed by rapping or by high velocity air jets.
In a typical multiple chamber retort furnace, the wire is
charged onto a hearth in the primary chamber. It is ignited
by natural gas hand torches or small gas burners. Excess air
is introduced through primary air ports and by leakage around
the edges of the charging door. Primary chamber emissions are
ducted to the secondary chamber or afterburner, where secondary
burners maintain high temperatures *nd complete combustion.
Wire is removed from the chamber and quenched with water to
curtail smoking and remove ash.
3.5.7 Sources and Characteristics of Emissions
Each type of incinerator has different rates and
characteristics of emission due to the unique composition of
waste being burned. The sources of emissions, however, are
similar for most incinerators and include:
0 receiving and charging area where odors and litter
are potential problems unless proper handling and
housekeeping is practiced.
3-36
-------
0 fly ash collection from cleanout chambers and control
device hoppers unless the ash is properly moistened
and transported.
0 incinerator stack major emissions can be particulates,
odors, carbon monoxide and hydrocarbons.
3-37
-------
References - Chapter 3
1. Danielson, J. A. Air Pollution Engineering Manual. DHEW.
Springfield, Va. NTIS No. PB 190-243. 1967
2. De Marco, J. et. al. Incinerator Guidelines - 1969.
USDHEW Bureau of Solid Waste Management, Washington, D. C.
PHS Publication No. 2012. 1969, 98 pages.
3. Neissen, W. et. al. Systems Study of Air Pollution from
Municipal Incinerators. A. D. Little, Springfield, Va.
NTIS No. APTD 1283, 1284, 1285
4. Compilation of Air Pollutant Emission Factors (Revised).
Environmental Protection Agency, Springfield, Va.
NTIS Publication No. AP-42
5. Burd, R. S. A Study of Sludge Handling & Disposal.
Springfield, Va. NTIS No. PB 179-514
6. Balakrishman, S. et. al. State of the Art Review of Sludge
Incineration. Resource Engineering Associates. U. S.
Government Printing Office, Washington, D. C.
7. Stein, A, Air Pollution Field Operations Manual. Volume II,
Pacific Environmental Services, Springfield, Va.
NTIS No. APTD 1102
3-38
-------
4.0 ATMOSPHERIC EMISSION CONTROL METHODS
The basic types of emission control devices are mechanical
collectors, wet scrubbers, electrostatic precipitators,
fabric filters, and afterburners. All of these have been
used to some extent to control emissions from incinerators
and fuel-fired combustion processes. Mechanical collectors
and electrostatic precipitators (for the larger units) are
the most common control devices for fuel-fired heat exchangers.
Mechanical collectors and various types of scrubbers are
the most commonly used devices for incinerators. Afterburners
are used on some commercial/industrial incinerators. Fabric
filters have found only very limited application for controlling
emissions from combustion sources.
This section describes briefly the methods to control
emissions from combustion sources. EPA control techniques
12 3
documents for particulate, ' sulfur oxides and nitrogen
4
oxides provide more complete descriptions.
4.1 Mechanical Collectors
Mechanical collectors rely upon particle inertia to
separate the particle from the carrier gas stream. Thus they
can remove only particulate pollutants, and only those that
are relatively large (generally greater than 20 micrometers
diameter).
The most common types of mechanical collectors are settling
chambers and cyclones. A settling chamber is shown schematically
in Figure 4.1. Settling chambers may be part of the furnace
or an enlargement in the stack breeching. In the settling
chamber, the flue gas velocities are decreased so that the
larger particles settle out of the gas stream. Settling
chambers are not effective for removal of particles smaller
than about 50 micrometers in diameter.
4-1
-------
INLET AIR DUCT v ^
-------
ZONE OF INLET
INTERFERENCE
TOP VIEW
INNER VORTEX
GAS INLET
SIDE VIEW
OUTER VORTEX
INNER VORTEX
OUTER VORTEX
INNER CYLINDER
(TUBULAR GUARD)
CORE
| \—.' DUST OUTLET
Figure 4.2. Conventional reverse flow cyclone.
Figure 4.3. Cyclones arranged in parallel.
4-3
-------
Table 4.1. EFFECTS OF CYCLONE DESIGN
PARAMETERS ON EFFICIENCY
Increase in parameter
Particle size
Particle density
Inlet velocity
Cyclone body length
Number of gas revolutions in cyclone
Ratio of body diameter in exit duct diameter
Gas viscosity
Cyclone diameter
Gas density
Effect on efficiency
Increase
Increase
Increase
Increase
Increase
Increase
Decrease
Decrease
Decrease
Cyclones are classified as either "high efficiency" or
"high throughput". High efficiency cyclones are characterized
by a narrow inlet opening to attain a high inlet velocity,
long body length relative to body diameter, and a small outlet
diameter relative to the body diameter. Higher collection
efficiencies result from the increased energy expended due to
the high inlet velocities. High throughput cyclones have
larger inlet openings and larger gas exits. High efficiency
cyclones therefore are long and thin, whereas high throughput
and lower efficiency cyclones are squat. Pressure drop through
low efficiency units is typically in the range of 0.5 to 2
inches of water, whereas high efficiency units operate with
2 to 6 inches pressure drop.
The range of collection efficiencies for these devices
applied to combustion sources is shown in Table 4.2. Cyclones
are sometimes applied to oil fired units although their efficiency
is generally lower than the values shown for coal fired units
because of the smaller particle size distribution.
4-4
-------
Table 4.2. RANGE OF COLLECTION EFFICIENCIES FOR
MECHANICAL COLLECTORS APPLIED TO COMBUSTION SOURCES1
Source
Fuel fired heat exchangers
Cyclone furnace
Pulverized furnace
Spreader stoker
Other stokers
Municipal incinerator
Pressure drop range
(inches of water)
Range of collection efficiencies, %
High efficiency
cyclone
30-40
65-75
85-90
90-95
80-90
2.0 to
6.0
Lower efficiency
cyclone
20-30
40-60
70-80
75-85
70-80
0.5 to
2.0
Settling
chamber
20-30
25-50
40-60
(with
water
sprays)
0.1 to
0.5
4.2 Wet Scrubbers
Wet scrubbers can control both particulate and gaseous
pollutants. The multitude of wet scrubber designs ranges from
simple wetted baffles to high-energy venturi scrubbers.
Although various types of wet scrubbers have been used to a
significant extent on incinerators, they have only recently
been applied to control of emissions from fossil-fuel-fired
heat exchangers and only then because of their potential for
controlling sulfur dioxide as well as particulate emissions.
One exceedingly important design consideration for
scrubbers applied to both municipal incinerators and boilers
is the materials of construction for the scrubber. Acid gases
in the flue gas are absorbed by the scrubbing liquor causing it
4-5
-------
to become extremely corrosive. Special materials of
construction and linings are therefore required.
Scrubbers can usually be classified in the following
categories:
0 Spray chambers (usually with baffles)
0 Venturi
0 Packed tower (includes fixed, fluidized-bed, and
turbulent bed).
Spray chambers can range from simple water sprays fitted
into an existing stack, baffle, or settling chamber to specially
daaigned units, such as the cyclonic spray tower. Pressure
drops are in the range of 2 to 5 inches of water with the usual
scrubbing liquor consumption of about 4 to 8 gallons per 1000
CFM of flue gas. This type of device is rarely used solely for
gaseous pollutant control because of its relatively low
collection efficiency for gaseous pollutants. Occasionally they
are used for simultaneous gaseous and particulate removal.
Figure 4.4 is a schematic of a simple spray tower. The
wetted baffle and spray chambers are the most common control
devices on incinerators, aside from simple settling chambers.
Figure 4.5 illustrates a venturi scrubber. A high
velocity gas stream in the throat of a venturi scrubber
disintegrates the liquid and exposes it to contact with the
gas stream. Venturi scrubbers have high collection efficiency
for particulates, although relatively high power inputs are
required. Pressure drops of 15 to 50 inches of water are not
uncommon with this unit. Liquid requirements range up to 10
gallons per minute per 1000 cubic feet of gas. Venturi
scrubbers have been used to control incinerator and boiler
emissions.
4-6
-------
GAS IN
STRAINER
PIPE
MIST ELIMINATOR
•»- GAS DISTRIBUTION PLATE
Figure 4.4. Spray tower,
Figure 4.5. Venturi scrubber.
4-7
-------
Packed scrubbers are used to provide enough contact
between the scrubbing liquor and effluent gas stream to
remove gaseous pollutants. There are three basic types of
packed towers: fixed, fluidized, and turbulent. Because
of the high plugging potential, fixed bed scrubbers are
normally used only for gaseous pollutant removal where
particulate loading is very light. The fluid bed scrubbers,
which use high-density spheres for packing material, also
have found limited use for the sa'me reasons. Turbulent bed
scrubbers, shown in Figure 4.6, use low-density spheres and
are not as susceptible to plugging because of the intense
motion of the packing medium. Packed scrubbers have not been
used extensively on combustion sources, although the turbulent
bed scrubber is gaining in popularity.
Pressure drops are usually between 1 to 4 inches of water
per foot of packing. Liquid rates range between 1 and 15
gallons per minute per 1000 ACFM.
Because of the multiple mechanisms involved in particulate
collection, it is difficult to establish a single relationship
to express efficiency as a function of operating and design
parameters. A relationship sometimes used to estimate
particulate collection efficiency is the contacting power theory.
Simply stated, the greater the power input, the higher the
particulate collection efficiency. Contacting power is the
power per unit of volumetric flow rate consumed in gas-liquid
contacting. This power includes the kinetic energy or pressure
head loss across the scrubber, the kinetic energy or pressure
head loss of the scrubbing liquor, plus any other types of
energy dissipated in the gas stream such as energy supplied by
a mechanical rotor.
4-8
-------
AAIST ELIMINATOR
FROM
RECIRCULATION
PUMP
SCRUBBING LIQUOR
RETAINING GRID
FLOATING BED OF, .
LOW DENSITY SPHERES
RETAINING GRID
MAKEUP LIQUOR-*-!==
TO RECIRCULATION
PUMP
FEED GAS
TO DRAIN OR
RECOVERY
Figure 4.6. Fluid bed scrubber.
The range of collection efficiencies for various types
of scrubbers is shown in Table 4.3.
Table 4.3. RANGE OF COLLECTION EFFICIENCIES FOR WET
SCRUBBERS APPLIED TO COMBUSTION SOURCES 1'5
Scrubber type
Wetted, close spaced baffle
Settling chamber and water spray
Venturi
Turbulent bed
Range of particulars
collection efficiency, %
Incinerators
50-60
30-50
90-99
90-97
Fuel fired heat
exchangers
90-99
90-97
4-9
-------
4.3 Fabric Filters
Fabric filters can be classified in two ways: by the
shape of the filtering surface, either tubular or envelope,
and by type of bag cleaning mechanism, either mechanical or
reverse air flow. The few installations on fuel combustion
and incineration sources have used tubular bags and reverse
air flow for bag cleaning.
Fabric filters are not commonly applied to combustion
sources because of the difficulty in removing the collected
ash from the fabric and the danger of fires due to the high
temperatures and carryover of combustible material.
Typical pressure drops across a fabric filter are between
4 and 6 inches of water. Particulate collection efficiency
is in excess of 99 percent.
4.4 Electrostatic Precipitators
Electrostatic precipitators are used to a considerable
extent on coal-fired boilers and have recently been applied
to controlling emissions from residual oil-fired boilers and
municipal incinerators. In the precipitator, the particles
receive an electrical charge and are driven towards the
collecting surface by the electrostatic field. The collecting
surface (plates) are rapped periodically and the collected
ash falls into the hopper. Figure 4.7 illustrates an
electrostatic precipitator.
Particulate collection efficiency can be related to
design parameters by the Deutsch-Anderson equation, as follows:
n = 1 - exp (^r w)
where n = collection efficiency, %
.2
A = plate area, ft'
V = gas volume, ft /min
w = precipitator rate constant, ft/min.
4-10
-------
The precipitation rate constant is selected by the
designer, usually on the basis of past experience. Selection
of the rate constant then fixes the plate area for a desired
collection efficiency and given gas volume.
The precipitation rate parameter is highly dependent upon
particle resistivity. Resistivity, in turn, is dependent upon
sulfur content of the fuel and the operating temperature of the
precipitator. These relationships are shown for precipitators
on coal-fired boilers in Figure 4.8. As this figure shows,
the lower the sulfur content, the greater the collecting
plate area per unit gas volume required for a given collection
efficiency. For example, a precipitator installed on a boiler
burning a 2 percent sulfur coal should have at least 0.25 square
feet of plate area per CFM to be a high efficiency collector.
The resistivity of the ash limits the maximum power input to
the precipitator, thereby limiting collection efficiency. For
example, as shown in Figure 4.9, if a precipitator is operating
with a corona power (secondary voltage x secondary current) of
only 40 watts per 1000 CFM, the unit cannot be obtaining high
collection efficiencies.
Figures 4.10 and 4.11 show these same relationships for
precipitators applied to municipal incinerator effluent. In
summary, particulate collection efficiency for electrostatic
precipitators ranges between 80 and 99 percent and is highly
dependent upon precipitator design and process operating
conditions.
4.5 Afterburners
Afterburners are used on several types of commercial
and industrial incinerators to control odors and combustible
4-11
-------
STEEL SUPPORT LEVEL
FAN
ASH CONVEYOR
ROOF LEVEL
Figure 4.7. Electrostatic precipitator /
99.9
100 200 300
AREA/1000 cfm
Figure 4.8. Relationship between collection
efficiency and specific collection area
for various coal sulfur contents.6
4-12
-------
99
98
97
96
95
90
U
t
LU
s
a
g 80
70
50
I
I
25 50 75 100 125
CARONA POWER, wotti/1000 efm
150
Figure 4.9. Relationship between collection
efficiency and corona power for fly ash
precipitators.
CTION EFFICIENCY, %
3 4
V
2 90
O
u
y
/
/
/ .
/ *r
t^^
0 0
w
T
/
/
f
^1
/ 1
j^
s^
r
= 10 cm/sec /
/
f
/
* if
^
^
1
^
^T
—
'
,s£
>^
•
Lx
* 4 cm/sec
0 DESIGN
• TEST '
1 0.2 0.3 0.4 0.5 0.
. . .. ... . ,.2
SPECIFIC COLLECTION SURFACE AKEA, *.
v
Figure 4.10. Relationship between collection
efficiency and specific collection area for
municipal incinerators.
4-13
-------
99.9
5"
o
o
u
50
100 150
POWER, wottv'IOOO cfm
Figure 4.11. Relationship between collection
efficiency and delivered corona power for
municipal incinerators.
particulate emissions. In addition, many commercial and
industrial incinerators have secondary burners, in lieu of
afterburners/ in the mixing or secondary chambers. These
secondary burners are not true afterburners, since an after-
burner is an add-on device. However/ they serve the same
function: to complete combustion.
There are two basic types of afterburners, thermal and
catalytic. Thermal afterburners use direct flame incineration
and operate at higher temperatures than do the catalytic units.
Thus, they require more fuel. The catalytic units are susceptible
4-14
-------
to catalyst poisoning and fouling, and they are not used
on incineration sources.
Figure 4.12 illustrates a direct-fired afterburner.
The minimum temperatures and residence times required
to effectively oxidize the pollutants are normally specified
for thermal afterburners. They are usually in the range of
1200 to 1800°F and 0.3 to 0.6 second, depending upon the
material being burned.
RERACTORY LINE
STEEL SHELL
GAS BURNER PIPING
INLET FOR
CONTAMINATED
AIRSTREAM
Figure 4.12. Typical direct-fired afterburner.
4-15
-------
4 .6 Sulfur Oxides~^.nd Nitrogen Oxides 'Emiasion-angontrol
Sulfur and nitrogen oxide emissions are of concern
from fuel-fired indirecfi heat exchangers. Emissions from
incinerators are negligible.
Sulfur oxide emissions from fuel-fired indirect heat
exchangers are due to the sulfur content of the fuel, whereas
NO emissions are a function of fuel nitrogen content, and
H
furnace operating and design conditions. Methods for controlling
usually require furnace modifications and substantial changes
in operating conditions . Control techniques used include low
excess air combustion, flue gas recirculation, flame temperature
reduction, staged combustion, and burner modification. Wet
scrubbing of flue gases for NO control is being tried on an
X
experimental basis.
Low excess air firing decreases NO emission primarily
X
because it reduces the amount of oxygen available for reaction.
Recirculating cool flue gases reduces NO emissions by reducing
A.
the temperature of the flame zone and by decreasing the amount
of oxygen available for NO production.
^S.
Flame temperature can be reduced by lowering the air pre-
heat temperature or by injection of steam or water through the
burner atomizer. The use of these techniques, however, can
decrease boiler efficiency and result in higher corrosion rates.
In two-stage combustion, approximately 80 to 90 percent of
the total air supply is introduced through the burners with the
fuel. The remainder of the necessary combustion air is admitted
through auxiliary air ports in the walls of the firebox. Thus
the amount of oxygen available for NO production in the high
H
temperature flame zone is substantially reduced.
4-16
-------
The specific design and configuration of a burner has an
important bearing on the amount of NO formed. The spud type
A.
gas burner appears to give a higher emission rate than the
radial spud type, which in turn, produces more NO than the
n
ring type. There is also a tendency toward higher NO emissions
H
with "tight" burner spacing, which causes high local flame
temperatures.
Nitrogen oxide control methods are discussed in greater
4 7
detail in other sources. '
Sulfur oxide emissions can be reduced by burning lower
sulfur content fuel and by use of various flue gas desulfu-
rization processes. The SO- emission control processes
commercially available include lime/limestone solution scrubbing,
sodium solution scrubbing, magnesium oxide slurry scrubbing and
catalytic oxidation of the S00 to sulfuric acid.
£
In lime/limestone scrubbing systems, the S0~ reacts with
the scrubbing solution to form calcium sulfate and sulfite.
The several versions of the process are illustrated in Figure
4.13. In Method 1, Scrubber Addition of Limestone, the flue
gas contacts a slurry containing finely ground limestone. The
limestone is added directly to the scrubber effluent recycle
stream. Part of the scrubber discharge is settled to remove
a solid product and the settler overflow is either recycled as
shown or discharged. The second method, Scrubber Addition of
Lime, is similar to Method 1 except that the limestone is first
calcined to lime externally before addition to the scrubber
circuit. In the finalr.method, Boiler Injection, the lime-
stone is calcined in the boiler and carried to the scrubber
in the flue gas.
4-17
-------
GAS TO STACK
STACK
GAS
SCRUBBER
-T
CoCCVj
f
PUMP
TANK
*•
SETTLER
~l
METHOD I. SCRUBBER ADDITION TO LIMESTONE
+ CoSO4
TO WASTE
STACK
GAS
CaCO,
CALCINER
-»-GAS TO STACK
SCRUBBER
Ca(OHL
PUMP
TANK
SETTLER
CaO
METHOD 2. SCRUBBER ADDITION TO LIME
CaS03 + CaSO4
TO WASTE
GAS TO STACK
;aco3
BOILER
O
o
u
5
O
SCRUBBER
-r-
PUMP
TANK
•*-
-HP""
SETTLER
J
i
METHOD 3. BOILER INJECTION
CaSO3 -t-
TO WASTE
Figure 4.13. Lime/limestone scrubbing systems
for sulfur oxides emission control.
4-18
-------
In sodium solution scrubbing, S02 in the flue gas is
absorbed into a solution of sodium sulfite, bisulfite, and
sulfate, converting some of the sulfite to bisulfite. The
scrubbing solution is regenerated by evaporating water and SO?
while crystalizing sodium sulfite in an evaporative crystalizer.
The vapor product is cooled to condense out all of the water.
The pure gaseous S02 can be further processed to liquid S02,
sulfur, or sulfuric acid. Condensed water is used to re-
dissolve the sulfite solids for recycle to the scrubber.
The magnesium oxide scrubbing process is similar to lime
scrubbing. The principal difference is that the spent magnesium
sulfite and sulfate salts are regenerated producing a concen-
trated stream of 10-15% S02 and regenerated MgO for reuse in
the scrubbing system. Since the reactant is recycled, it must
be protected from contamination by fly ash. Thus the process
is limited to oil-fired boilers or must be preceeded by high
efficiency particulate collection devices if applied to a coal
fired unit.
In the catalytic oxidation process, the flue gas is passed
through a fixed catalyst bed where SO- in the presence of 0,
& £
is converted to S03. The SO- is then absorbed in recirculated
H2S04 in an absorption tower. Sulfuric acid is produced as
the byproduct.
Additional information on these processes is readily
available in the sulfur oxides control techniques document.
4-19
-------
References - Chapter 4
1. Control Techniques for Particulate Air Pollutants.
Environmental Protection Agency, Springfield, Va.
NTIS No. PB 190-253. 1969
2. Danielson, J. A. Air Pollution Engineering Manual.
DHEW. Springfield, Va. NTIS No. PB 190-243. 1967
3. Control Techniques for Sulfur Oxide Air Pollutants.
Environmental Protection Agency, Springfield, Va.
NTIS No. PB 190-254. 1969
4. Control Techniques for Nitrogen Oxide Emissions from
Stationary Sources. Environmental Protection Agency,
Springfield, Va. NTIS No. PB 190-265. 1970
5. Vandegrift, A. E. et. al. Handbook of Emissions and-Control
Practices for Stationary Particulate Pollution Sources.
Midwest Research Institute, Springfield, Va. NTIS No.
PB 203-522
6. Oglesby, S. and Nichols, G. A. Manual of Electrostatic
Precipitator Technology. Southern Research Institute,
Springfield, Va. NTIS No. PB 196-381
7. Bartok, W. et. al. Systematic Field Study of NO Emission
Control Methods for Utility Boilers. ESSO Research and
Engineering Company, Springfield, Va. NTIS No. PB 210-739
4-20
-------
5.0 PROCESS CONTROL AND EMISSION MONITORING INSTRUMENTATION
5.1 Process Control Instrumentation
Combustion control systems for boilers and incinerators
vary with such factors as type of unit, rated load capacity,
and fuel. However, the instruments that measure the
combustion parameters and convert these measurements into
input signals are limited to a few different principles
of operation
5.1.1 Steam Pressure
Steam pressure is usually the principal variable
measured in a combustion control system. The three types
of elements used to measure steam pressure are the diaphragm,
the bellows, and the bourdon tube. These devices are shown
in Figure 5.1.
PRESSURE INLET
SCALE
BOURDON
TUBE
PRESSURE
INLET
Diaphragm
Bellows
Bourdon Tube
Figure 5.1. Steam pressure measuring elements.'
5-1
-------
In diaphragm measuring devices the differential
pressure between the two sides of the diaphragm deflects
the diaphragm, causing a pointer to rotate to the correct
pressure reading. The bellows unit operates on a similar
principle. Applied pressure causes the bellows to expand
proportionally, and a pointer indicates the steam pressure,
The bourdon tube is a C-shaped element; the fixed end is
open to the pressure source and the free end is displaced
as the pressure changes. As pressure increases, the tube
straightens and the pointer moves on a graduated scale.
Diameters of dials for pressure gages range from 4 to 12
inches. Figure 5.2 shows details of a pressure gage
housing a bourdon tube.
I. BOURDON TUBE 5. GEARED SECTOR
2. TUBE SOCKET 6. POINTER SHAFT
3. TIP 7. HAIR SPRING
4. ADJUSTABLE LINKAGE 8. SUPPORT FOR MECHANISM
Figure 5.2. Heavy-duty precision bourdon gage.
5-2
-------
5.1.2 Flow
Steam flow/air flow or fuel flow/air flow recorders
are essential in proper boiler operation. The fuel flow/
air flow recorder is commonly used on oil-and gas-fired
units, especially when severe load swings are likely.
The steam flow/air flow recorder is commonly used on coal-
fired units.
Flow measurement relies on the relationship between
fluid velocity and differential pressure. A pressure drop
can be induced by inserting an orifice or nozzle in the
pipe through which the fluid is flowing. The magnitude of
the pressure drop is related to the flow rate. The
orifice or nozzle is the primary sensing element.
Several types of secondary elements convert the
pressure differential into a flow rate measurement: liquid-
filled manometers, flow meters, Ledoux Bell meters, force
or balance meters, and bellows or diaphragms.
Flow parameters are read in pounds per hour and
recorded on a control panel instrument similar to the one
shown in Figure 5.3. Pen position indicates instantaneous
flow rate and the pen tracing provides a history of steam
flow rates at any given time of day. Figure 5.4 shows a
circular chart record for a coal-fired boiler. An integrator
records the total flow in pounds.
5.1.3 Temperature
Two basic arrangements are used to sense temperature
and actuate a remotely mounted indicator or recorder. When
temperatures do not exceed 1000°F, a filled system thermom-
eter may be used, Figure 5.5. The sensing element, a bulb,
is connected with a length of capillary tubing to a spiral
measuring element, which actuates the instrument pointer or
5-3
-------
PRESSURE TIGHT -
•EARING
1 GUIDE LINK
Figure 5.3. Section through steam-flow mechanism
of boiler meter.
Figure 5.4. Typical chart record made
by boiler meter.
5-4
-------
pen. If the system is filled with mercury, the liquid
contracts with decreasing temperature and expands with
increasing temperature. As a consequence the measuring
element coils and uncoils. The end connected to the
capillary is fixed, and the motion of the free end acts
through linkage to position the pen or pointer. If the
system is filled with gas (nitrogen is frequently used),
the pressure in the measuring element changes with temper-
ature. Since volume of the system is fixed, the pressure
in the system increases as temperature rises and decreases
as temperature falls. The measuring element reacts in the
same manner as in the liquid filled system.
TEMPERATURE
ELEMENT
CHART )
PLATED ^szssaosa^s?
Figure 5.5. Temperature measuring system.
5-5
-------
The second basic temperature sensor is a thermocouple,
which is a welded junction of two dissimilar metals. The
junction is located in the region where the temperature is
to be measured, and the other ends of the metal elements
are connected electrically to the measuring instrument.
The heated junction develops an electromotive force which
is proportional to temperature change. A galvanometer type
instrument converts the electrical signal into a temperature
measurement.
5.1.4 Draft
Draft is the pressure differential that causes gases
to flow from a region of higher pressure to one of lower
pressure. The flow of air and combustion gases through
ducts, boiler, flues, and stack is initiated and maintained
by developing a draft.
Draft measuring instruments may use diaphragm, bellows,
or bourdon tube elements similar to those used for measuring
steam pressure. Because the absolute pressures under which
the elements work are much lower than those in steam
pressure sensing applications, spiral or helical bourdon
tubes replace the less flexible C-shaped devices. Draft
is generally indicated in inches of water on a vertical
scale meter, as shown in Figure 5.6; the meter is located
on the boiler room control board.
5.1.5 Flue Gas Analysis
Flue gas analyzers that indicate levels of carbon
dioxide, oxygen, and (to a limited extent) combustible gases,
are used to achieve and maintain maximum combustion efficiency,
Most boiler operations use either CO- or 0? measurements.
The percentage of excess combustion air can be determined and
hence controlled.
5-6
-------
Figure 5.6. Draft measuring vertical scale indicator.
Carbon dioxide detectors operate either by chemical
absorption or thermal conductivity. Oxygen and combustible
gas analyzers rely upon paramagnetic phenomenon or
catalytic combustion.
5.2 Emission Monitoring Instrumentation
Emission monitoring instruments are classified in two
basic categories: automated continuous monitoring equipment,
which is usually located in semi-permanent monitoring
installations, and intermittent sampling equipment, which
is usually portable.
5-7
-------
5.2.1 Automated Instrumentation
This section describes some of the monitoring systems
that are commercially available for current stack monitor-
ing applications. The initial instrument costs are relatively
high ($4000 to $6000), and further requirements, such as
sample conditioners and recording instruments, can add two
to three thousand dollars, depending on the specific
application. Since most of these instruments are not
portable, they do not lend themselves to use by the field
enforcement officer. They' may be found in industrial
installations, however, and therefore t>asic knowledge of
their operation is necessary.
Most of the automated instruments used to monitor
stack emissions from stationary combustion sources have
been adapted from ambient air monitoring systems. The
problems associated with stack monitoring are usually due
to the sampling system rather than the detection system.
Stack samples often must be diluted, dried, filtered, or
otherwise conditioned to prevent interferences or damage
to the detection systems. Figure 5.7 illustrates a typical
monitoring system requiring sample conditioning.
5.2.1.1 Particulate Monitors. Monitors that measure
mass concentration of particulate in stacks are not yet
commercially available. The technique used most commonly
for monitoring particulate emissions is measurement of
opacity or percent of light transmission.
5-8
-------
REMOTE CONTROL
UNIT
Figure 5.7. Gaseous pollutant monitor with sampling
and conditioning systems.
Light transmission devices pass light through the sample
gas, which attentuates the light intensity by scattering
and absorption; the resulting intensity is measured by a
photocell. No sample conditioning system is required, but
the optical lens must be cleaned often. Optical density is
measured in terms of smoke density units or percent trans-
mi ttance .
Figure 5.8 illustrates the operating principles.
Unfortunately, optical density does not correlate directly
with mass emission rates. However, such instruments can be
used to monitor stack gas opacity.
5-9
-------
CLEAN PURGE GAS -N
\
k
LIGHT S
COLLIM-*
LENS sr
CLEANP
OURCE ||
^o
UION; II
5TEM ' l|l
URGE GAS'''
i 1
fi' T\
-------
range as NO can cause major interferences. Optical filters
used to eliminate the interferences are not always completely
effective. Because filters are used, the nondispersive
infrared systems can be made specific for NO or NO2.
(Nitrogen dioxide [N02] accounts for approximately 5 percent
of total NO in large combustion sources such as power plants.)
A.
Response time (exclusive of the sampling systems) is short,
about 0.5 second for 90 percent of full scale. Accuracy is
only as good as the calibration gas, probably within + 5
percent. Zero drift is usually stated as + 2 percent full
scale for a 24-hour period. Calibration is accomplished with
known gas concentrations available commercially. Instruments
should be calibrated daily.
INFRARED SOURCE
REFERENCE
CELL
RECORDER
SAMPLE OUT
ABSORBS I.R. ENERGY
IN REGION OF INTEREST
o OTHER MOLECULES
CONTROL UN IT
Figure 5.9. Nondispersive infrared system.
5-11
-------
Ultraviolet (UV) systems measure the energy absorption
at one or more wavelengths in the ultraviolet region of the
spectrum. A reference cell and a sample cell lie in the
path of an ultraviolet source. The energy loss due to UV
absorption in the sample cell is detected by a phototube,
and resulting current output is related to the concentration
of the desired constituents. Figure 5.10 illustrates the
operating principle of an ultraviolet system. Performance
specifications of commercially available UV instruments are
similar to those of infrared instruments, differing
primarily in sensitivity to interferences. UV instruments
display less than + 2 percent zero drift in a 24-hour
period and respond in less than a second. Calibration
requirements and techniques are similar to those used for
infrared systems.
TUNGSTEN LAMP
400 mu
REFERENCE CELL
• COMPONENT OF INTEREST
O NON-ABSORBING MOLECULES
\'
MIRROR
ALTERNATING
13 CHOPPER
SAMPLE IN
SAMPLE CELL
• ft SAMPLE OUT
MIRROR
PHOTOTUBE
Figure 5.10. Ultraviolet photometry system.
5-12
-------
Electrochemical instruments entail a combination of
semi-permeable membranes, electrodes (eg. specific ion),
and electrolyte solutions. A typical cell configuration
is shown in Figure 5.11. Estimated lifetime of most
electrochemical sensors is 3 to 9 months, depending upon
the humidity of the sample gas, which affects the rate of
electrolyte evaporation. Accuracy and precision are
similar to those of UV and IR instruments. Electrochemical
instruments are not subject to interference by N», 0~,
ri£ £1
CO, C09, hydrocarbons, or water vapor. The systems can be
calibrated with known gas mixtures. Although maintenance
is relatively simple, it can be expensive since it usually
requires replacement of the electrochemical sensor module
at a cost of approximately $200.
MEMBRANE
___,__.
k
6 -\
THIN FILM ELECTROLYTE
i t
W///////////////////M
^PKKlWr; Fl FrTROnF ///
TO AMt-
ELECTROCHEMICAL TRANSDUCER
Figure 5.11. Electrochemical system.
5-13
-------
Chemiluminescent detectors depend on the oxidation
of NO to NOp in presence of atomic oxygen or ozone. These
represent the latest addition to the NO monitor market.
X
During the gas-phase reaction, an activated state of N02 is
formed. When it returns to the stable state, light is
emitted (chemiluminescence) in a given spectral range. Figure
5.12 depicts a typical chemiluminescent system. Chemiluminescent
detectors are extremely sensitive (1 ppm minimum); they operate
through wide ranges of concentration and exhibit the same
stability as other NO detectors.
AMBIENT AIR
FLOWMETER
OXYGEN
SOLENOID VALVE
CALIBRATION \
GAS
^
HIGH VOLTAGE
POWER SUPPLY
Figure 5.12. Chemiluminescent system.
5-14
-------
5.2.1.3
Monitors. Several ambient air monitoring
techniques have been adapted for use in monitoring stack
emissions of SO2. These include flame photometry, electro-
chemical detectors, nondispersive infrared, ultraviolet,
and correlation spectrometry. The reactivity of S0? and
interferences from particles and moisture necessitate sample
conditioners for monitoring systems which extract a sample
from the stack; monitors using instack optical methods do
not require sample conditioning.
Flame photometry is gaining popularity for instack
monitoring of SO-- The gas sample is burned in a hydrogen
flame, yielding a sulfur emission spectrum. The intensity
of a specific wavelength in the emission spectrum is measured
by a photomultiplier tube. The flame photometer requires a
sample conditioning system to remove particles. Temperature
and flow rate of the sample are variables that must be
controlled. Figure 5.13 shows a flame photometric sulfur
detection system.
D .C . POWER
SUPPLY
Figure 5.13. Flame photometric sulfur monitor.
5-15
-------
Electrochemical transducers for detection of SO- are
commercially available; their operational characteristics
are similar to those described in Section 5.2.1.2 for
detection of nitrogen dioxide.
Nondispersive infrared systems for S02 monitoring
employ the same principle and specifications as discussed
for NO monitoring in Section 5.2.1.2. The infrared system
X*
is readily calibrated with known gas standards available
commercially. Although a calibration schedule is left to
the user, the sample conditioning systems usually require
frequent maintenance.
The traditional ultraviolet absorption systems, as
described for NO monitoring are also used for determination
J\.
of SO?. Similar operational principles are involved.
The correlation spectrometer eliminates the need for
a sample conditioner. This is a true instack system, since
the detector is housed in a slotted probe that extends into
the stack as shown in Figure 5.14. An ultraviolet beam
shines through the slot in the probe. Any light not
absorbed by the sample is reflected back to the spectro-
meter. The unabsorbed spectrum is compared with the
characteristic SO- absorption spectrum at the chosen wave-
length, and the difference is taken as a measure of the SO,,
£
content. The manufacturer specifies accuracy within Hh 2 percent
zero drift in 24 hours, and 5-second response time. Inter-
ferences are minimized by the spectrum comparison technique.
Calibration is easily accomplished with an internal standard.
5-16
-------
Figure 5.14.
Correlation spectrometer
system.
Other monitoring systems available for SO2 usually
entail wet chemistry; the instruments are subject to heavy
maintenance requirements in the form of periodic addition
or changing of reagents and are therefore not desirable for
instack monitoring.
5.2.1.4 Hydrocarbon Monitors. Hydrocarbon emissions
from combustion sources are low (in the parts per million
range). They are usually measured by a flame ionization
detector. Two techniques in common use employ this detector.
In one system total hydrocarbons are measured and in the
other, specific hydrocarbon compounds are separated by
chromatographic techniques prior to detection.
The flame ionization detector measures an increase in
ion intensity resulting from combustion of hydrocarbon
compounds in a hydrogen/air flame. Flame ionization detectors
cover a wide range of concentrations and are highly
sensitive. Most flame ionization detectors used for in-
5-17
-------
stack monitoring are identical to those used for ambient
monitoring of hydrocarbons. Figure 5.15 is a diagram of
a flame ionization detector system for total hydrocarbons.
An effective sampling and interface system is essential
for conditioning the sample to eliminate interferences.
Output is usually calibrated to read parts per million by
volume as methane.
AIR SUPPLY
REGULATOR
FLAME DETECTOR
ELECTROMETER
SAMPLE
Figure 5.15. Flame ionization monitor.
Specific types of hydrocarbons can be separated and
analyzed with the gas chromatograph. Separation is
accomplished with various chromatographic absorption
columns. A flame ionization detector determines concen-
trations of the various individual hydrocarbons. Standard
5-18
-------
gases are generally used for calibration. The gas
chromatograph is not usually portable and requires
careful calibration; it does not lend itself to source
monitoring without a sampling interface system to remove
particulates.
5.2.1.5 Carbon Monoxide Monitors. Carbon monoxide
in stacks is usually measured with nondispersive infrared
instruments. CO is well suited to this technique because
of its absorption characteristics. The infrared systems
used to measure CO are subject to interference by CO-,
water vapor, and hydrocarbons. A narrow-pass optical
filter can be included to minimize C0~ and water inter-
ference. Performance specifications for nondispersive
infrared analyzers were discussed in Section 5.2.1.2 (NO
X
measurement).
5.2.2 Manual (Intermittent) Sampling
Because of practicality, cost, and ease of operations,
the field enforcement officer will use intermittent sampling
equipment to a greater degree than automated continuous
monitoring devices. He can use these rapid, inexpensive
test procedures and devices to assist in his enforcement
judgements and to check on the operation of continuous
monitoring equipment.
At present, particulate emissions cannot be determined
because of the lack of suitable equipment. Examples of
techniques for intermittant sampling of gaseous pollutants
are listed below:
0 Detector tubes - A measured volume of sample gas is
drawn through a detector tube containing a substrate
impregnated with a specific reagent, which changes color
upon exposure to a specific pollutant. The intensity, or
5-19
-------
length of stain, is proportional to the concentration of
the pollutant. Detector tubes and pump devices are
commercially available and inexpensive. Gaseous pollutants
such as CO, CO.,, NO , SO-, HC, and many other trace pollutants
£ X ^
found in flue gases can be detected with this technique. The
accuracy of this type of measurement depends on the specific
pollutant and its concentration; generally the device is
considered semiquantitative, and therefore accuracy is
estimated to be within + 25 percent.
0 Portable combustion meters - Inexpensive meters are
available for detection of combustible gases. Pollutants
such as carbon monoxide and hydrocarbons respond to this
device. This device, too, provides only semiquantitative
measurements, but can be used to estimate emissions.
0 Gas absorption devices - The Orsat and Fyrite devices
can be used to measure carbon dioxide and oxygen content of
combustion gases. These constituents are absorbed in
appropriate reagents, and the change in volume is measured
by means of a gas burette. These devices are inexpensive
and are accurate within approximately + 0.2 percent (2000 ppm)
by volume.
0 Grab sampling - Techniques involving evacuated flasks
and nonreactive plastic bags made of materials such as
Mylar and Tedlar can be used to secure a sample rapidly for
subsequent laboratory analyses.
5-20
-------
References - Chapter 5
1. Evans, R.K., Combustion Control, Power. December 1967.
2. Crosby Gauge Bulletin.
3. Steam, Its Generation and Use. Babcock and Wilcox Company.
37th Edition. New York, N.Y. 1963.
4. Bailey Meter Company Bulletin
5-21
-------
-------
6.0 INTRODUCTION TO INSPECTION PRACTICES
The preceding sections have set forth fundamentals of
combustion processes and equipment of concern to the field
enforcement officer. Having become familiar with this
material, the FEO may find it valuable as a reference
resource, a useful compendium of technical information
relating specifically to the work he performs.
The sections that follow are designed as a step-by-
step guide to proficient inspection practices. Although
each inspection is, of course, a unique event, certain basics
may be cited that apply generally to all such inspections.
This section describes some of these fundamentals, with an
emphasis on safety precautions that must be observed at all
times, in all facilities. Section 7 describes the equipment
with which a field enforcement officer performs his daily
work, and the kinds of records he may be expected to maintain.
Sections 8, 9, and 10 present detailed procedures for inspection
of indirect-fired heat exchangers, municipal incinerators and
commercial/industrial incinerators, respectively.
6.1 Observing the Plant Environment
Before entering the plant premises, the FEO should evaluate
the general plant environment. He should note any visible
emissions, odors, or dustfall in the surrounding area; look for
possible damage to vegetation and for effects of pollutants on
materials and paint; observe the areas in which fuel and/or
refuse are unloaded and stored; and check for evidence of ash
disposal, debris handling, and related practices that can affect
local air quality. He should document all significant observations,
noting the date, time of day, and weather conditions (especially
6-1
-------
wind speed and direction). In reading visible emissions
from stacks, it is imperative that he follow the recommended
procedures regarding location of observer in relation to
plume and sun.
6.2 Interviewing Plant Personnel
Direct communication with plant personnel can range
from formal, scheduler? interviews to the informal conversations
that usually occur during conduct of an inspection. All such
communications can be valuable: they enhance the enforcement
officer's understanding of plant scheduling, operations,
problems, and management attitudes. Likewise, they give plant
personnel some insight into the mission of the field enforcement
officer and the reasons for the inspection. Whether the
inspection is a routine periodic check or is performed in
response to complaints, the officer is called upon for objec-
tivity and tact in his dealings with plant personnel.
When inspections are planned, the FEO will usually have
arranged an appointment with the plant manager. Sometimes,
however, especially on unscheduled visits, discussions with
another staff member may be appropriate. In any case, it is
important that the FEO state immediately his name, agency
affiliation, and purpose of the visit. If a violation has
occurred or is suspected, the FEO should notify the responsible
persons promptly upon entering the plant.
Whenever possible, it is helpful to meet and talk with
members of the plant staff who usually work with the boiler
or incinerator; these persons can provide detailed information
about process operation, startup conditions, procedure during
equipment breakdowns, and related items.
6-2
-------
The initial visit to a plant will entail an extensive
review of the process equipment, plant layout, and operating
schedules. Subsequent visits require less time, since their
primary purpose is to ascertain whether conditions have
changed, and if changes have occurred to check their effects
on pollutant emissions.
6 . 3 Inspecting Inside the Plant
Since detailed instructions for in-plant inspections are
given in Sections 8, 9, and 10, this section emphasizes safety
precautions, which must be observed in all types and sizes of
facilities. As an enforcement officer and a representative
of the agency, the FEO is obligated to observe all safety
precautions, whether or not they are cited in the regulations
of the plant being visited. Ordinarily the FEO should not
sign accident waivers when entering a plant. He should, however,
arrive equipped with personal safety equipment such as a hard
hat, protection for eyes and ears, safety shoes, and other
items, detailed in Section 7.
On the first visit to a plant, the FEO should review all
safety rules with plant personnel. He should never tour the
plant without an escort. He must not open furnace doors,
manipulate valves or controls, or in any way try to change the
operating characteristics of the plant equipment. When observing
the interior of a combustion chamber, he should allow the
operator to open the viewing ports; he should always use the
appropriate eye and face shields. Since the FEO will work
daily with fans, belt and chain drives, and electrical motors,
he should keep constantly in mind the hazards associated with
this type of equipment.
6-3
-------
The central rule underlying all of the specific
instructions just cited is that the FEO should take no
action that could in the slightest way constitute a safety
hazard to himself or to plant personnel.
6-4
-------
7.0 FIELD INSPECTION EQUIPMENT
The enforcement officer should carry certain basic
equipment and pertinent facility records to properly perform
field inspections.
7.1 Basic Equipment
Table 7.1 lists the basic equipment each field enforcement
officer should have to perform his inspections both properly
and safely. Optional equipment is marked with an asterisk(*).
Table 7.1. SOURCE INSPECTION EQUIPMENT
Plume evaluation equipment
Polaroid camera
Compass
Wind speed indicator
Flashlight
Thermometer (50-800°F)
Stop Watch
Tape measure
6 foot rule
Hard hat
Safety glasses
Safety shoes
Asbestos gloves
*Manometer or pressure/vacuum gage (0-30 in. Hg and 0-10 in
*Gas detection equipment
*Fuel sample containers
thermocouple
*Portable millivolt meter (temperature compensated)
In addition, the agency should make available to the
officer an official vehicle equipped with a two way radio to
provide transportation and to facilitate communications.
7-1
-------
It is good practice to wear safety shoes, a hard hat,
and safety glasses during an inspection. Many plants require
such protection of their employees and visitors. Always wear
safety glasses or a. face shield when examining the interior of
the incinerator chambers. Asbestos gloves can provide protection
during work at or near the furnace. Coveralls or shop coats
also come in handy when inspecting the dirty areas of a site.
7.2 Emission Monitoring Instrumentation
The field enforcement officer's equipment may also
include monitoring equipment for gases as described in
Section 5.2. In most cases this will be limited to simple
detection tubes for CO and C02, since more sophisticated
techniques are expensive and require more time than is available
to the officer on an inspection.
7.3 Field File
The basic forms and records which the field enforcement
officer should carry with him on an inspection are listed in
Table 7.2.
Table 7.2. SOURCE INSPECTION FIELD FILE
Form
Copy of Previous Field Inspection
Form
Copy of Code
Emergency Episode Procedures
Preinspection Sheet or Permit
Observation Recording Form
Field Inspection Form
Notice of Violation
Completion
Before inspection
During inspection
During inspection
After inspection (if necessary)
7-2
-------
Bring a copy of the permit or a preinspection data sheet
to verify that current operating practices are in conformance
with those stated on the permit. Example preinspection forms
for fuel-fired heat exchangers and for incinerators are
presented in the following pages. Most of the information will
come from the permit application, although the inspector may
have to obtain certain information, such as furnace dimensions,
and capacities, in the field.
Carry a copy of the local air pollution regulations and
emergency episode procedures for review with the operator to
insure that he understands their requirements.
7-3
-------
PREINSPECTION DATA SHEET FOR FUEL-FIRED HEAT EXCHANGERS
TYPE OF HEAT EXCHANGER
RATED INPUT CAPACITY
MAXIMUM OPERATING RATE
RATED STEAM OUTPUT
MAXIMUM STEAM OUTPUT
FURNACE VOLUME width
OPERATING SCHEDULE
COAL FIRING
TYPE OF FIRING D
Coal Fired
Oil Fired
Gas Fired
If Multiple Fired, Check
BTU/hr
BTU/hr
lb/hr@
Ib/hr @
ft x depth ft
Hr/Day
Grate Typ
PRIMARY STANDBY
a D
a a
a a
Appropriate Boxes
BTU/lb steam
BTU/lb steam
x height ft = ft3
Days/Wk Wk/Yr
e
E Spreader Stoker
D Pulverized Coal
D Cyclone
FLY ASH REINJECTION
SOOT BLOWING
(H Continuous
D Intermittent
TIME INTERVAL BETWEEN BLOWING
DURATION minutes
D Dry Bottom O Wet Bottom
D YES O NO
minutes
7-4
-------
OUTSIDE COAL STORAGE D YES O NO
MAXIMUM AMOUNT STORED OUTSIDE tons
IS OUTSIDE STORAGE SPRAYED D YES a NO
COAL COMPOSITION Range Average
Ash % to % %
Sulfur % to % %
BTU/lb as fired to
ARE FUEL CONSUMPTION RECORDS KEPT DYES a NO
FOR STOKER SYSTEM,
Coal Size
FOR PULVERIZED COAL AND CYCLONE SYSTEM,
FIRING METHOD D Front Wall
O Front Wall - Rear Wall
D All Wall
O Tangential
D Other Type
OIL FIRING
FIRING METHOD D Front Wall
D Front Wall - Rear 'Wai I
D All Wall
O Tangential
D Cyclone
a Other Type
TYPE OF FUEL D No. 1
D No. 2
a No. 4
D No. 5
0 No. 6
D Other Type
7-5
-------
TYPE OF ATOMIZATION
D Oil Pressure
O Steam Pressure
D Air Pressure
O Rotary Cup
O Other
psi
psi
Type
OIL PREHEAT
OIL COMPOSITION
Ash
Sulfur
BTU/Gal as fired
O YES
D NO
PREHEAT TEMPERATURE
°F
Range
% to
% to
Average
to
ARE FUEL CONSUMPTION RECORDS KEPT
NUMBER OF BURNERS
FIRING CAPACITY PER BURNER
WAS UNIT A CONVERSION UNIT
IF OIL STANDBY, STATUS OF BURNER
Rated
Normal
Maximum
Q YES O NO
_BTU/hr
BTU/hr
~BTU/hr
O YES D NO
D Left In Firebox
D Pulled Out and Stored
O Multiple Fuel Burner
GAS FIRING
FIRING METHOD
D Front Wall
a Front Wall -Rear Wall
O All Wall
D Tangential
Q Cyclone
O Other
Type
GROSS HEATING VALUE
BTU/Cu ft @ 60°F
Range
Average
to
ARE FUEL CONSUMPTION RECORDS KEPT
NUMBER OF BURNERS
D YES
D NO
7-6
-------
FIRING CAPACITY PER BURNER
WAS UNIT A CONVERSION UNIT
IF GAS STANDBY, STATUS OF BURNER
CONTROL EQUIPMENT
Type of Cleaning Equipment
Pressure Drop Across Collector
Design Efficiency (If Known)
Airflow to Control Device Inlet
Stack Diameter
Stack Height
Stack Temperature
MONITORING EQUIPMENT
Opacity Meter
Others
Rated
Normal
Maximum
BTU/hr
BTU/hr
BTU/hr
D YES
D NO
a
a
a
Left in Firebox
Pulled Out and Stored
Multiple Fuel Burner
O2 Meter
CO2 Meter
Combustion Gas Analyzer
Smoke Alarm
MAINTENANCE AND OPERATING RECORDS KEPT
Amount of Steam Generated
Amount of Fuel Used
Type of Fuel Used
Grate or Burner Equipment
Instrumentation Calibration
Fans, Ductwork, Control Equipment
Soot Blowing Intervals and Duration
ACFM @
YES
D
D
D
D
D
D
D
D
*DS KEPT YES
D
D
D
D
D
lent Q
fion Q
in.
%
°F
ft
ft
°F
NO
D
a
a
a
D
a
a
D
NO
D
a
D
D
D
D
D
7-7
-------
PREINSPECTION DATA SHEET FOR INCINERATORS *
FACILITY IDENTIFICATION
TYPE OF INCINERATOR D Municipal Refuse
D Municipal Sludge
O Commercial/Industrial
O Apartment
O Other
Type
WASTE STORAGE
D Open Area
O Paved Floor
O Receiving Pit
O Other
WASTE CLASSIFICATION OR HEATING VALUE
Type
RATED CAPACITY (Per Furnace)
Ib/hr
Circle Type 01 23456
or BTU/lb
NUMBER OF FURNACES
NUMBER OF FURNACES AT THE INCINERATOR SITE LEADING TO A COMMON STACK
COMBUSTION CHAMBERS D Primary
D Mixing
O Secondary
TYPE OF COMBUSTION AIR
N
D Primary Underfire
F I
D D
O D O Primary Overfire
ODD Secondary or Mixing
TYPE OF CHARGING
CHARGING METHOD
D Batch
D Continuous
D Chute Fed
O Flue Fed
D Direct Fed
D Other
OPERATING SCHEDULE
Hr/Day
Type
Days/Wk
Wk/Yr
9 F Forced Draft
I Induced Draft
N Natural Draft
* If an incineration site has two or more furnaces and the furnaces are not identical, separate
forms are required for each furnace.
7-8
-------
Width Depth Height Total
PRIMARY CHAMBER DIMENSIONS ft x ft x ft = ft3
SECONDARY CHAMBER DIMENSIONS ft x ft x ft - ft3
MIXING CHAMBER LENGTH ft
GRATE OR HEARTH TYPE
GRATE AREA ft2
ANGLE OF INCINERATION Degrees
AUXILIARY FUEL D Natural Gas
D Oil
D LPG
D Other Type
D CONTINUOUS D INTERMITTENT O STARTUP
MAXIMUM AUXILIARY FUEL HEATING RATE (IF USED) BTU/hr
AUXILIARY FUEL INTRODUCTION IN D Primary Chamber
D Mixing
D Secondary
AUXILIARY FUEL TEMPERATURE CONTROL D Yes If Yes, Lower Limit °F
a NO
COMBUSTION MAKEUP AIR PROVISION SOURCE
INSTRUMENTATION YES NO
Secondary Chamber Temperature D D
Underfire Air Draft D D
Overfire Air Draft D D
Combustion Gas Analyzer or Orsat D D
7-9
-------
CONTROL EQUIPMENT
Type of Cleaning Equipment-
Pressure Drop Across Collector In. HoO
Design Water Rate gpm
Design Efficiency (If Known) %
Airflow to Control Device Inlet ACFM @ °F
Stack Diameter ft
Stack Height ft
Stack Temperature °F
MONITORING EQUIPMENT YES NO
Opacity Meter p p
Others a a
a n
a a
Flue Gas Analyzers p p
MAINTENANCE AND OPERATING RECORDS KEPT YES NO
Amount of Refuse Burned p p
Furnace Walls Q p
Grate System rj p
Auxiliary Fuel Burners (If Used) p p
Instrumentation Calibratioa p p
Fans, Ductwork, Control Equipment p p
7-10
-------
8.0 INSPECTION PROCEDURES: FUEL-FIRED INDIRECT HEAT EXCHANGERS
The purpose of an inspection by the FEO is to determine
whether a source is operating in compliance with applicable
emission regulations. The initial decision regarding compliance
usually is made either (1) by considering process design and
operating characteristics at the time of permit issuance, or
(2) by conducting emission stack tests under various furnace
operating conditions considered representative of the range of
normal operation. Thus when these initial evaluations have
been made, the major responsibility of the FEO is to check that
the source is still operating either (1) as specified in the
permit application, or (2) under the same conditions as when
the source satisfactorily passed the emission source tests.
The initial permit review is usually performed by an
experienced engineer. This review is crucial, since it is the
foundation for future enforcement actions. The permit must
contain certain specific operating and design information to
allow meaningful evaluation. Preinspection data sheets,
presented in Section 7, list the minimum technical information
required for such an evaluation. If this information is not
given on existing permit forms, the FEO should complete a pre-
inspection data sheet during his first inspection.
In addition, when checking on permit-related information,
the FEO must determine whether the plant is following good
operating and maintenance practices, since improper furnace
operation or maintenance can lead to excessive emissions. He
must also check the operation of the air pollution control
equipment to determine whether it attains the specified
collection efficiencies. He should also spot-check selected
records to determine whether good operating practices have
been followed in the interval between inspections.
8-1
-------
Thus a source inspection should cover the following
elements:
(1) Determine whether the source meets equivalent
opacity regulations;
(2) Determine whether the source is operating in
accordance with permit conditions;
(3) Determine whether operating and maintenance
procedures conform with good practice;
(4) Spot-check selected records of operation since
last inspection to determine whether good
operating and maintenance procedures are used
regularly;
(5) Determine whether the air pollution control
equipment is operating properly.
Section 8.1, Inspection of the Combustion Process,
describes general facility observations, which are not amenable
to quantitative comparisons with accepted standards. General
guidelines, however, are noted. The design and operating
factors that can be quantitatively compared with "good practice"
values are also described.
Section 8.2, Inspection of Air Pollution Control Systems,
describes the procedures for inspecting air pollution control
equipment. Section 8.3 presents an example inspection check-
list for recording field observations. Section 8.4 lists the
types of records the facility should maintain.
Section 8.5, Procedures for Estimating Atmospheric
Emissions, describes methods of estimating emissions from
various types of sources. Since most of these procedures rely
upon design rather than operating data, these estimates would
normally be made during the permit review stage. If the
detailed review has not been performed, however, the permit
review engineer or the FEO should make this evaluation using
the data contained on the preinspection data sheets or obtained
during the first inspection.
8-2
-------
Section 8.6 presents an example inspection. If this
inspection indicates that a source apparently is not operating
in compliance with applicable regulations, the FEO should
follow established agency procedures regarding notice of
violation, request for source test, and related matters. If
the FEO is so equipped, he can use a portable test device, as
described in Section 5.0, to determine emission rates for NO ,
a
SO , and CO. Although the legal standing of such tests is
X
undetermined because the test method does not follow established
procedures, it does provide an accurate determination of
emissions while requiring only two to three hours of the FEO's
time. Unfortunately, no similar methods are yet availaole for
a quick determination of particulate emission rate.
8.1 Inspection of the Combustion Process
Operational practices are major factors in the generation
and emission of air contaminants from fuel-fired indirect heat
exchangers. These practices are indicated by the condition of
the equipment, maintenance procedures, and general housekeeping.
Although they cannot be quantitatively related to pollutant
emissions, certain operating conditions must be checked, since
deviation from accepted procedures can lead to increased
emissions.
Certain design factors that can be at least semiquanti-
tatively related either to emissions or to "good practice" are
also discussed in this section. Table 8.1 lists the design
parameters affecting particulate emissions and common design
values for each parameter. Design values should have been
checked at the time the permit was issued to determine whether
the unit would operate within these commonly accepted values.
8-3
-------
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8-4
-------
Units that deviate from these general norms, however, may still
yield acceptable emission levels, since many different furnace
and boiler designs are effective in obtaining good combustion
and minimal emissions.
Described below are detailed procedures for inspection of
facilities operating a fuel-fired indirect heat exchanger.
Observe the plume before entering the plant.
Determine plume's equivalent opacity. (Don't mistake
water vapor condensation for particulate emission.
For example, on a cold day burning high-moisture-
content fuel may cause a water vapor plume.) Also
note the plume color and check Table 8.2 for possible
operating factors that may be causing the visible
emission. If visible emissions are exceeding applicable
standards, use the standard form and follow established
procedures for recording the violation.
Inspect the fuel preparation system.
0 COAL-FIRED BOILERS
Check the outside coal pile for evidence of windblown
dust. If chemical additives are used to suppress wind-
blown dust, check the frequency of their application.
Check the conveyor system as a source of windblown
dust emission. If the system is not hooded or
covered, check to see if a cover can be installed,
if required.
Check the coal size and compare with values given
in Table 8.1 for the various types of firing systems.
0 OIL-FIRED BOILERS
Determine the frequency of cleaning fuel oil storage
tanks (should be cleaned about once a year). Sludge
deposits can occur in the tank, especially if the
tank is not used continuously. Sludge can cause
burners to plug and decrease atomization efficiency,
thereby increasing emissions. Periodic cleaning will
minimize the "process upsets" that lead to high
emission levels.
Numbers refer to corresponding section of example checklist.
8-5
-------
Table 8.2. PLUME CHARACTERISTICS AND OPERATING PARAMETERS
Stock
plume
White
Gray
Black
Reddish-
brown
Bluish-
white
Yellow or
brown
Associated
pollutant
Particulate
Particulate
Particulate
Nitrogen
dioxide
Sulfur
trioxide
Organics
Occurrence
Coal
1
1
1
2
2
2
Oil
2
2
2
2
1-2
2
Gas
2
2
2
2
3
2
Possible operating
factors to investigate
Excessive combustion air;
loss of burner flame in
oil fired furnace
Inadequate air supply
or distribution
Lack of oxygen; clogged or
dirty burners or in-
sufficient atomizing
pressure; improper oil pre-
heat in oil fired furnace;
improper coal size or type
in coal fired furnace
Excessive furnace temper-
ature, burner configura-
tion, too much excess air
High sulfur content
in fuel
Insufficient excess air
1 = common; 2 = rare; 3 = never encountered
Check the oil preheat temperature and atomization
pressure gauges for each no2!zle. Correct preheat
temperatures are listed in Table 8.1, and recommended
pressures for the nozzles are given in manufacturer's
literature.
0 COMBINATION-FIRED UNITS
Check the procedures for maintaining burners used
for standby fuels. If burners are not cleaned and
properly stored or protected (eg. stored in kerosene),
excessive emissions will result when the burners are
put back in use.
Inspect the furnace interior
(Caution: When inspecting the furnace interior, use
specially designed filters for eye protection. In
addition, the officer must never open furnace doors,
manipulate controls, change valve settings, or in
any way interfere with boiler operation).
8-6
-------
©
0 GRATE SYSTEMS
Check eveness of the coal distribution on the bed.
For spreaders stokers, bed thickness should be
between 2 and 4 inches. For traveling grate, chain
grate, and vibrating units, it should be between 5
and 7 inches.
Determine the maximum grate loading and compare
with values in Table 8.1 (this is done only at the
permit review stage).
0 BURNER SYSTEM
Determine maximum burner load at permit review
stage and compare with values in Table 8.1, or
manufacturer's suggested burning rate.
0 FLAME CHARACTERISTICS
Grate Systems
Look into furnace and note pattern of flame from the
coal bed.
* Totally yellow flame indicates too little air, similar
to weak, lazy flame.
* Dark smoke means soot and particulate emissions high.
Burner Systems
* Mixture of yellow and blue flame attached to ports
indicates correct proportions of air and fuel.
* Totally blue flame lifting off ports indicates too
much air. Dazzling or bright white flame indicates
that the flame temperatures may be sufficiently high
to create excessive NOX emissions.
* Presence of black spots indicates poor atomization.
Compare steam flow rate for the individual boilers with
maximum design rate.
Read the steam flow rate (on the control panel) for
the boiler and compare with maximum design value
listed on the permit. Rates above maximum design
values will lead to excessive emission. Low loads
may cause smoking if the correct amount of combustion
air is not carefully maintained. Ask the operator
when the steam flow meter was last calibrated. Also
inquire if the pens read "true" values of Ib/hr or
if the pen trace has been modified. Modified
instrumentation may include a scale factor. If an
inordinate amount of time (e.g. 12 months) has passed
or if there is doubt about the accuracy of the reading,
request that it be calibrated.
8-7
-------
Check the air/fuel ratios.
For steam flow/air flow recorders, compare chart
values (located on the boiler control panel) with the
following guides:
Air flow (Ib/hr) should read between 10 and 25 per-
cent higher than steam flow (Ib/hr) for coal-fired
operations.
Air flow and steam flow should read approximately
the same value for oil and gas operations.
For fuel flow/air flow recorders:
Approximate ratio for oil-fired units is 70 pounds
of fuel oil per 1000 pounds of air, or 10 gallons
fuel oil per 1000 pounds of air.
Approximate ratio for gas-fired units is 55 pounds of
natural gas per 1000 pounds of air, or 1250 cubic
feet per 1000 pounds of air.
Inspect control panel instrumentation.
Inspect steam flow/air flow or fuel flow/air flow,
combustion gas (C02, 0« or unburned combustible)
and emission monitors on the control panel for
proper functioning. Check last calibration date
for all recorders.
Inspect ash disposal system.
Check both furnace bottom ash and control equipment
ash hoppers for correct ash handling procedures.
Ash from hoppers should not drop significant
distances when being transferred. Ash should be
moistened before transport to minimize fugitive
dust emissions. If system is not enclosed or hooded,
determine by visual observation if hooding is
required to minimize fugitive dust emissions.
Check fans and ductwork.
Inspect the breechings and air ducts through air
heaters, economizers, and superheaters for cracks
and holes.
8-8
-------
Review operating records.
Check fuel analysis records to determine sulfur
content and compare with sulfur level specified
for that facility. For coal-fired boilers, also
note the ash content to determine whether it is
still within the general values reported on the
permit. Obtain fuel heating value to express
emission concentrations in Ib/MM BTU.
Check firing rates and fuel consumption values.
These can be compared to permit information to
see if source is running above design conditions.
Check charts of the light transmittance device
(if one is installed) to identify periods of
violation. Check frequency of cleaning the photo-
cell lens (should be done at least daily).
Check frequency and duration of soot blowing.
This operation should conform to local codes or
permit information.
8.2 Inspection of Air Pollution Control Systems
8.2.1 Particulate Emissions Control Systems
Mechanical collectors and electrostatic precipitators
are the devices most commonly used for particulate emission
control. The most indicative guide to their performance is
the condition of the plume. If the plume opacity is greater
than it was under similar boiler load conditions at an earlier
time, either the collection efficiency of the controls has
decreased, or the fuel quality has decreased.
Other than plume condition, the following items should
be checked to insure that mechanical collectors- are operating
at maximum collection efficiency.
Determine the interval between cleanouts of the
ash collecting hopper. Buildup of dust causes
re-entrainment of dust back into the exhaust gas
stream.
8-9
-------
Check the pressure drop across the collector
(available from reading the difference between
draft gauges for the stack draft and draft at
the closest point to the inlet of the collector).
These devices commonly operate with pressure
drops of 2 to 6 inches of water. Greater pressure
drops indicate plugged cones or hoppers; lesser
pressure drops may be due to erosion of internal
components which could substantially reduce the
collection efficiency.
Examine exterior of cyclones for cracks and holes.
Air leaks caused by holes will change the air flow
pattern in the cyclone and decrease its efficiency.
The single-stage high voltage precipitator is the most
commonly used particulate control device on larger boiler
plants. The FEO should evaluate the effectiveness of the
control device as follows:
Check the frequency and method of ash removal from
the hoppers. Backed-up ash deposits in the hoppers
will reduce precipitator efficiency by entrainment
of particulates in the flue gas and can cause the
entire unit to short out.
Check the spark rate meter for each section. The
meter should read approximately 100 sparks/minute
for the most efficient operation. This value,
however, varies significantly from one installation
to another, depending upon coal properties.
Check the maintenance records regarding wire
breakage. If an excessive number of wires have
been cut without being replaced, the unit's
efficiency will have decreased.
Read and note the secondary current and voltage
for each section.
The above notations can be used, as described in later
sections, to determine precipitator collection efficiency.
Wet scrubbers are being used to a limited extent, primarily
for controlling S0«. Inspection procedures are discussed in
the following section.
8-10
-------
Fabric filters are not discussed here because
they are-het used to any significant extent f©r--Gon.troi-
ling particulatfe emissions from -fossil fuel-fired
combustion sources.
8.2.2 Sulfur Dioxide Emissions Control Systems
Control of SO has been approached in two ways: (1)
*£
burning of fuels with low sulfur content, and (2) desul-
furization of flue gas.
When control is by sulfur content, review records
of fuel composition; if there are no records or
if their accuracy is in question, obtain samples
of the fuel for future analysis.
Flue gas desulfurization processes used to control SO
X
emissions will have been source tested to establish their
effectiveness. The FEO must verify that the collection
system is operating under the same conditions as when it
passed the acceptance test. For example, for lime/limestone
scrubbing:
Record liquid-to-gas ratio, pH of scrubbing
liquor, lime or limestone addition quantities, and
pressure drop and compare to acceptance test values.
Records of such key parameters should also be reviewed
to determine the effectiveness of control processes in the
intervals between inspections.
8.2.3 Nitrogen Oxide Emission Control Systems
Control of NO is being approached by modification of
JC
basic furnace design, by changes in combustion chamber
geometry, and by reduction of maximum temperatures. The
control method used should be specified as an addendum to the
permit application. The FEO must check that the control
process is being operated as specified on the permit addendum
8-11
-------
(e.g., low levels of excess air are being maintained, boiler
load is not exceeding specified value, CO meter is operating
properly - used to warn of excessive CO levels due to staged
firing or low excess air levels). The FEO should check
appropriate records (e.g., boiler load, CO, and O2 meter
records) to determine whether the system operates properly
during intervals between inspection.
8.3 Inspection Form
Data obtained during an inspection can be summarized on
an inspection form similar to that shown on the following
pages. This form also serves as a record of the inspection.
8.4 Recordkeeping Requirements
Table 8.3 lists recommended recordkeeping requirements.
The FEO should spot-check such records during his inspection
to verify that the source is adhering to proper operating
procedures during the interval between inspections.
8.5 Procedures for Estimating Emissions
Emissions are usually calculated for the maximum operat-
ing rate of the unit, since emissions are the highest at this
operating condition except for visible smoke. (Units operat-
ing above their maximum design capacity usually produce
excessive emissions, and the source should be cited for not
operating in accordance with permit specifications). Further-
more, the procedures for estimating emissions are largely
based upon the unit's design parameters and are not suffi-
ciently precise to reflect quantitatively the changes due to
readily measurable variations in operating parameters. Thus
the emission estimating procedures are normally used as part
of the permit evaluation process to judge the adequacy of
the system for complying with the emission regulations.
8-12
-------
INSPECTION CHECKLIST FOR FUEL-FIRED INDIRECT
HEAT EXCHANGERS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact
Source Code Number
PREINSPECTION DATA SHEET
D Adequate Information
D Inadequate Information (Obtain needed data during first inspection)
(7) PRE ENTRY DATA
Stack Plume Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation D In Compliance D Not In Compliance
Smoke D White D Grey D Black or Brown
D Reddish Brown D Bluish White D Yellowish Brown
(2) FUEL PREPARATION SYSTEM
A. Coal-Fired Units Last
Maintenance
Satisfactory Unsatisfactory Date
Coal pile fugitive dust D Q
Dust additive application D D
Coal conveyor system Q D
Coal size D Q
B. Oil-Fired Units
Fuel oil storage tank cleaning Q D
frequency o D D
Oil preheat temperature F Q p
Atomization pressure psi Q p
Burner maintenance frequency p, p
C. Gas-Fired Units
Burner maintenance frequency
Keyed to reference number in Chapter 8 of text.
8-13
-------
FURNACE INTERIOR
Furnace Pressure
D positive
D negative
Ao Furnace Walls
Have operator open furnace door. Use extreme caution
when looking into furnace. Wear either a face shield or
safety glasses. Use proper filters to protect eyes against
brightness of flame.
Satisfactory Unsatisfactory
Last
Maintenance
Date
Cracks and/or Leaks
access doors
breechings
air ducts
B. Grate System
Grate condition
Grate travel rate
Bed height
Bed evenness
C. Flame Characteristics
Impingement on walls and arches
Flame pattern
a
a
a
a
a
n
a
a
a
Characteristics related to air quantities (Circle)
Stokers -
Burners -
Excess
White"
Totally Blue
D
D
D
D
a
a
a
D
a
Normal
Yellowish Orange
Blue and Yellow Mix
Lack
Grey
Totally Yellow
Do *Grate Loading (Stoker-Fired Units Only)
Complete for each individual furnace leading to common stack.
Grate Area = Width ft x depth ft =
* Inspection only performed during permit review stage.
8-14
-------
Loading Rate
a) Feed Rate Control (From Operator) Ib coal/hr •
b) From Steam Flow Indicator
Coal Rare = Ib steam/hr x 0 .09 = Ib coal/hr
Coal Burning Rate .
Grate Loading = Grate Area = = Ib/hr - ft
E. Burner Loading (per burner)
*
Coal Ib/hr x 13,000 BTU/lb = BTU/hr
Oil gal/hr x 145,000 BTU/gal = BTU/hr
Gas ft3/hr x 1,000 BTU/ft3 = BTU/hr
Check manufacturer's specification for acceptable limits.
FLOW RATES
Current steam flow rate from control panel Ib/hr
Maximum design steam flow rate (from preinspection sheet) Ib/hr
FLOW RATIOS
Steam flow/air flow recorder
Maximum values Minimum values
Steam flow Ib/hr Ib/hr
Air flow Ib/hr Ib/hr
Fuel flow/air flow recorder
Fuel flow Ib/hr Ib/hr
Air flow Ib/hr Ib/hr
Ratio D acceptable D unacceptable
CONTROL PANEL INSTRUMENTATION Last
Maintenance
Satisfactory Unsatisfactory Date
Air flow/steam (or fuel) flow g Q
Furnace pressure & draft gages ^ Q
Speed & amperage indicators for ._. p.
control equipment
*These are typical values. Actual heat content values should
be used when known.
8-15
-------
Stack viewer
Opacity monitor
Flue gas analyzer
Smoke meter
Flame detector
ASH DISPOSAL SYSTEM
A. Furnace Ash Hopper
Cleanout & transport procedure
General housekeeping
Bo Control Equipment Ash Hopper
Cleanout & transport procedure
General housekeeping
FANS AND DUCTWORK
Fan Condition
Duct Condition
AIR POLLUTION CONTROL EQUIPMENT
Type_
Mechanical
Interval Between Hopper Cleanouts
Satisfactory
D
D
D
D
D
D
D
D
D
D
D
Unsatisfactory
D
a
a
a
a
Type
hours
D
D
D
a
D
a
Last
Maintenance
Date
Exterior Condition
Hopper Level Indicator
D Satisfactory
D Satisfactory
D Unsatisfactory
D Unsatisfactory
Pressure before Collector
Pressure after Collector
Scrubber
Scrubbing liquor flow
Pressure before scrubber
Pressure after scrubber
jn . H2O
n .
Type
GPM
Jn . H2O
in . H2O
8-16
-------
Electrostatic Precipitator
Interval Between Hopper Cleanouts _hours
Exterior Condition Q Satisfactory D Unsatisfactory
Spark Rate: _sparks/minute
Operating Voltage (KV) Operating Current (MA)
Field 1
Field 2
Field 3
Field 4
Field 5
Field 6
8-17
-------
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8-18
-------
In the following subsections, procedures are given for
estimating emissions of particulates, SO,,, and NO from
£t X
coal-, oil-, and gas-fired units using design operating data,
Emissions of hydrocarbons and CO are very low in all but
the most poorly operated combustion units.
The emission estimates resulting from these procedures
should be considered for what they are, estimates only.
Actual emissions from a unit may differ significantly from
calculated emissions, especially for nitrogen oxides.
Nevertheless these estimates may prove useful in identifying
those units that, because of design or operating procedures,
have the potential for emitting excessive emissions.
8.5.1 Flue Gas Volume*
Obtain percent C02, 02, or excess air from
instrumentation or operator.
Use Figure 8.1 to determine percent excess
air if unavailable from facility.
Obtain exit flue gas temperature from
instrumentation panel.
Read maximum steam flow (Ib/hour) from
instrument panel.
Determine heat input according to following
formula:
Heat input (lllion BTU/hr, .,£*% ^ciS^T'x 1000)
(Typical boiler efficiency is 85 percent or .85).
Determine CFM/million BTU/hr heat input from
Figure 8.2 using the percent excess air obtained
from Figure 8.1 and the flue gas temperature.
(Accuracy +10%).
Determine flue gas volume (acfm) by multiplying
the value obtained in the previous step by the
heat input value, in million BTU/hr.
* See page 8-30 for example calculation,
8-19
-------
100 -s
90-
80-
70r
60-:
3
g
£
S
1 f
60.
f 15.
35-
_, S 25-
! s '5.
S S 10-
LL. O>
S 5-
u 2-
"UHIGH VOLATILE!
BITUMINOUS 4
LOW VOLATI LE_f
J BITUMINOUS 1
° SEMIAHTHRACITtf
f
ANTHRACITE-^
• L
COKE-[
- METHANE
- AVERAGE NATURAL GAS
-ETHANE
- PROPANE
- BUTANE
-PENTANE
• GASOLINE
- KEROSENE
• No. 2 FUEL OIL
- No. t FUEL OIL
- Ho . 5 FU EL 0 1 L
- No . 6 FUEL OIL
]
> BUNKER "C" OIL
r> MEDIUM VOLATILE
•^ BITUMINOUS
>SUBBITUMINOUS
J AND LIGNITE
S
t/J
S
e
o
i
Figure 8.1. Relationship between percent
excess air, 0_, C02 for various fuels.
TOO -
s
400
300
200
100
200
300 400 500
CFM/MiHion BTU/hr input
Figure 8.2. Volume of flue gas emitted.
(Accuracy +10%)
8-20
-------
8.5.2 Particulate Emissions
Uncontrolled emissions.
For stoker-fired unitsa, determine grate loading
in MM BTU/ft2-hr and obtain percent of ash
emitted as fly ash from Figure 8.3.
For pulverized-coal-fired units, determine
percent of load and obtain percent of ash
emitted as fly ash from Figure 8.4.
Obtain ash content of the coal from plant
records or operator.
Calculate potential emissions as follows:
U.E. = (A)(R)(C)(2000)
where:
U.E. = uncontrolled emissions (Ib/hour)
A = percent ash in coal
R = rate at which coal is burned (tons/hour)
C = percent of ash emitted from Figures 8.3 or 8.4
Control device efficiency.
Mechanical Collector - Use design or preferably, test
efficiency after ascertaining that operating conditions are
consistent with design or test conditions (e.g., pressure
drop, mechanical condition). If such data are not available
determine pressure drop across the collector and use Table
8.4 to find collection efficiency.
Table 8.4. PARTICULATE COLLECTION EFFICIENCY FOR
MECHANICAL COLLECTORS ON COAL-FIRED OPERATIONS
Furnace
Spreader stoker
Other stokers
Pulverized
Cyclone
Pressure drop
(inches of water)
0.1 to 0.5
0 .5 to 2 .0
2 .0 to 6 .0
0.1 to 0.5
0 .5 to 2 .0
2 .0 to 6 .0
0 .5 to 2 .0
2.0 to 6.0
0 .5 to 2 .0
2.0 to 6.0
Efficiency
35
70
90
25
75
90
50
70
20
30
Excludes spreader stokers. For spreader stokers, use
(AC)=13 for units without fly-ash reinjection; (AC)=20
for units with fly-ash reinjection.
8-21
-------
150
120
°. 100
<
u_
o
80
60
20
I _J I I I
"0 0.2 0.4 0.6 0.8 1.0
GRATE LOADING (mm BTU/hr-ft2)
Figure 8.3. Percent of ash in coal emitted as fly
ash in stoker-fired boilers.1
80
u
a 40
Z
I
20
25
50
NACE
EMITTED DURING
SOOT BLOWING
I
I I
75 100
PERCENT LOAD
125
Figure 8.4. Percent of ash in coal emitted as fly
ash in pulverized-coal-fired boilers. 1
8-22
-------
Electrostatic Precipitator - Use design or preferably
test efficiency after ascertaining that present operating
conditions are consistent, with design or test conditions
(e.g., boiler load, ash and sulfur contents of coal,
precipitator operating temperature). If such data are not
available, use the following procedures.
Read secondary currents and voltages for each
field of the precipitator.
Calculate delivered- corona power for each
section according to the following formula:
Delivered power = (secondary voltage) x (secondary
current)
If there are no meters for secondary voltage and
current, calculate delivered power for each
precipitator field as follows:
Delivered power = (Input power) x (power supply
efficiency)
Input power = (primary current) x (primary voltage)
Typical power supply efficiency is 90 percent.
Determine total corona power input by summing the
delivered power for each section.
Calculate corona power input per thousand CFM of
flue gas (i.e. watts per 1000 CFM)
Obtain precipitator collection efficiency value
from Figure 8.5.
If power data are not available from meters on. the
precipitator power supply panel, use the following procedure,
Determine total square feet of precipitator
collecting area (plate area) from manufacturer's
specifications.
8-23
-------
99
98
94
UJ
U 92
u.
fc 90
o
1
O 80
60
40
20
I
I
25 50 75 100
CORONA POWER, watH/1000 cfm
125
ISO
Figure 8.5. Electrostatic precipitatc-r collection
efficiency vs delivered power.
99.9
PERCENT 3 2.5 2 U 1 OJ
400
AHA/MB •*»
Figure 8.6. Relationship between collection efficiency
and collecting surface area to gas flow
ratio for various coal sulfur contents.
8-24
-------
Obtain sulfur content of coal being burned from
operator.
Determine expected collection efficiency from
Figure 8.6 using values of sulfur content and
collecting area per 1000 ACFM obtained above.
Actual emissions. Actual emissions are computed
according to the following formula.
AE = (UE)(100-E)
where:
AE = actual emissions (Ib/hr)
UE = uncontrolled emissions (Ib/hr)
E = control device efficiency, percent
8.5.3 Sulfur Dioxide Emissions
Coal-fired units.
Obtain sulfur content of coal from plant records. •
Calculate S02 emissions using the nomograph in
Figure 8.7.
Oil-fired units.
Obtain sulfur and BTU content of oil from plant
records. BTU content can be obtained from
Table 2.5.
Obtain maximum fuel burning rate in gallons/hour.
Calculate S02 emissions from the following formula:
Ecn = 15 x | x 106
oU- n
where:
Ec_. = actual SO0 emissions (Ib/million BTU input)
£>L)« At
S = fraction by weight of sulfur in the oil
(dimensionless)
H = heating value of oil (BTU/gallon oil)
To determine SO2 emissions in Ib/hr, multiply by
the heat input (million BTU/hr).
8-25
-------
% SULFUR
IN COAL
10.0 -
9.0 -
8.0
7.0 -
6.0 ~
5.0 ~
4.0 -
3.0 -
2.0 -'
1.5
1 .0 -
0.9 -
0.8 -
0.7 -
0.6 -
0.5 -
HEATING VALUE,
Btu/lb
SOX *i S02,
ppm at
50% EXCESS AIR lb/106 Btu
(Bituminous coal )
400'
500-
600--1 .5
700 _
800 - - '
900- •
1 ,000-
e-20,000
7 15 ,0.00 -"
-10,000
1-5.000
- 3
1 ,500-
- 4
2,000 -r 5
'- 6
I- 7
3 , 000 - I-
r 9
4., 000-=- 10
5.000 - \
6,000 - - 1 5
7,000- 1
Figure 8.7. Nomograph for calculating SOj emissions
8-26
-------
8.5.4 Nitrogen Oxides Emissions
Utility-size boilers (50 to 1000 MW).
Uncontrolled emissions.
Count the number of furnaces in the boiler. A
single furnace with a division is considered as
two furnaces.
Determine the number of equivalent firing walls
per furnace, using the following table.
Tangential
Front wall
Vertical
Horizontally opposed
Cyclone
4 firing walls per furnace
1 firing wall per furnace
1 firing wall per furnace
2 firing walls per furnace
3 firing walls per furnace
Divide the boiler gross load by the number of
furnace firing walls.
For the particular furnace type, read off the
uncontrolled NO emissions (corrected to 3% 0~/
dry basis) using Figure 8.8.
Controlled emissions.
Obtain percent reduction in NO emissions from
Table 8.5. X
Apply percent reduction values to uncontrolled
emissions obtained from Figure 8.8.
Table 8.5. PERCENTAGE DECREASE IN NOV EMISSIONS FROM
UTILITY BOILERS BY COMBUSTION MODIFICATIONS
fe
Type of Unit
Coal fired boiler
Tangential
Front wall
Horizontally opposed
Cyclone
Oil fired boiler
Tangential
Front wall
Horizontally opposed
Cyclone
Gas fired boiler
Tangential
Front wall
Horizontally opposed
Cyclone
Staged
firing
23
14
20
20
25
25
13
13
50
37
45
54
Low excess
air
39
40
33
33
23
17
38
38
33
13
15
17
LEA and
staging
46
55
50
50
31
45
40
40
70
43
50
59
Flue gas
recirculation
33
33
33
33
38
12
33
33
60
33
33
20
Water
injection
10
10
10
10
10
10
10
10
10
10
10
10
8-27
-------
M
-H
01
CM
O
n
8
CO
8
EH
I
U
IS
O
O
1000 -
I I I I I I I I I I I I I I
'40 80 120 160 200 240 280 300
GROSS FURNACE LOAD PER FURNACE FIRING WALL (MW/FFW)
Figure 8.8. NOX emissions from utility
boilers (coal-, oil- and gas-fired units).
8-28
-------
Industrial and commercial size boilers.
Obtain NO emission factors from Table 8.6.
These factors represent averages and are not
representative of emissions from any one
boiler.
Table 8.6. EMISSION FACTORS FOR INDUSTRIAL
AND COMMERCIAL SIZE BOILERS6'7'8'9
Type of unit
Coal fired units
Overfire
Underfire
Spreader stoker
Pulverized
Cyclone
Oil fired units
> TOO ,000 pph
< 100,000 pph
Gas fired units
< 100, 000 pph
> 100,000 pph
Nitrogen oxide emission factors
lb/106 BTU
0.57
0.38
0.38
0.76
2.3
0.50
0.25
0.12
0.24
Ib/ton
15
10
10
20
60
Ib/gal
75
38,
lb/10" cu ft
120
240
Calculated as NC>2
8-29
-------
EMISSION ESTIMATING EXAMPLE
Facility Information
Fuel type
Unit size*
Steam output*
Fuel rate*
Fuel ultimate analysis
element as received
Unit characteristics
pulverized coal
150MW
1,260,000 Ib/hr
121,000 Ib/hr
dry basis
carbon
hydrogen
nitrogen
oxygen
sulfur
ash
BTU/lb HV
61.88
4.70
1.76
8.26
1.38
18.17
12,020
65.10
4.95
1.85
8.70
1.46
19.29
12,680
balanced draft
water tube boiler
front wall (horizontal) fired boilers
dry bottom ash removal
electrostatic precipitator efficiency (tested)
97% (by weight)
Flue Gas Volume
Previous Orsat at similar conditions
O2 = 7.1%
CO2= 13.5%
CO-0.1%
FEO notes O2 meter on instrumentation panel. O2 = 6.5%. After finding out from plant
that lead is in exit duct, he used this to determine excess air.
from figure 8.1, for O2 reading of 6.5%,
CO,
13.1%
Excess air 43 %
110% load (max. conditions)
8-30
-------
FEO can only read economizer exit temperature of 710°F from instrumentation panel.
Plant engineer informs him that exit flue gas temperature is approximately 430°F at desired
conditions.
T exit gas = 430°F
FEO determines heat input from formula after boiler operator says boiler efficiency is 83%
Heat input = 1,260,000 Ib steam/hr x 1QOO BTU/|b steam
0.83
Heat input = 1518 MM BTU/hr
Since the FEO has obtained fuel rate and fuel analysis, he checks heating value
Heat input = 121000 Ib/hr x 12020 BTU/lb = 1454 MM BTU/hr
He makes the decision this value is more accurate due to more reliable input and uses it.
Heat input = 1454 MM BTU/hr
* CFM/MM BTU/hr is determined from figure 8.2.
ACFM/MM BTU/hr input = 410
Gas Volume = 410 ACFM/MM BTU/hr x 1454 MM BTU/hr = 596100 ACFM
Gas Volume = 596100 ACFM
Particulate Emissions
* From figure 8.4, % ash emitted is 63 (at 1 10% lead)
* Potential emissions
U.E. = (A)(R)(C)(2000)=^17) () () (2000)
U.E.= 13870 Ib/hr
8-31
-------
Actual emissions
A.E.= (U.E
. ~
A.E. = 416.1 Ib/hr
= 03870)
100-97
100
416.1 Ib/hr =
1454 MM BTU/hr
Sulfur Dioxide Emissions
From coal analysis (dry basis)
from figure 8 .7,
.286 Ib part/MM BTU ^—Check this value with local control regulations
S = 1 .46%
HV = 12680 BTU/lb
S = 2 .2 Ib/MM BTU 4—Check this value with local control regulations
or
= 910 ppm @ 43% EA
870 ppm @ 50% EA.
870 ppm @ 50% EA would approximately be 870 x
Nitrogen Oxide Emissions
Front wall horizontal firing is 1 firing wall/furnace
from graph, Figure 8.8, furnace has 825 ppm NOx @ 3% O2 . From combustion gas
analysis, Q~ = 6.5,
21.0-6.5)
825 ppm x
- n
z. I «u "" o »u j
= 664 PPm @ 6 -5% °2 (Furnace conditions)
~"
664 parts NC>2
10° parts air + NO2
596100 a ft"
(460 + 70 )s 46 Ib NO2/lb mole 60 mi
mn
mm
( 460 + 430 )a X 387 s ft3/lb mole X 1 hr
= 1680 I b NO2/hr
1680 Ib
1454 MM
1 .15 Ib NO2/MM BTU
•Check this value with local control
regulations
8-32
-------
8.6 Example Inspection
The completed form on the following pages illustrates
the use of the preinspection data-sheet and inspection^
checklist.
8-33
-------
PREINSPECTION DATA SHEET FOR FUEL-FIRED HEAT EXCHANGERS
TYPE OF HEAT EXCHANGER
RATED INPUT CAPACITY
MAXIMUM OPERATING RATE
RATED STEAM OUTPUT
MAXIMUM STEAM OUTPUT
PRIMARY
Coal Fired pi
Oil Fired D
Gas Fired a
If Multiple Fired, Check Appropriate Boxes
dO 0 MM BTU/hr
STANDBY
D
MM BTU/hr
000 lb/hr@ 1200
BTU/lb steam
BTU/lb steam
FURNACE VOLUME
OPERATING SCHEDULE
COAL FIRING
TYPE OF FIRING
width 30 ft x depth 1o ft x height ?/l ft = lA-ZSoo fr
Hr/Day
fl Grate
O Spreader Stoker
O Pulverized Coal
D Cyclone
FLY ASH REINJECT1ON
SOOT BLOWING
D Continuous
E3 Intermittent
TIME INTERVAL BETWEEN BLOWING
DURATION 3 -roS minutes
1 ^Days/Wk 50 Wk/Yr
Type
D Dry Bottom D Wet Bottom
D YES Kf NO
8-34
-------
OUTSIDE COAL STORAGE S YES D NO
MAXIMUM AMOUNT STORED OUTSIDE \.QOOQ *° tons
IS OUTSIDE STORAGE SPRAYED Q YES a NO
COAL COMPOSITION
Ash
Sulfur
BTU/lb as fired
Range
8 % to | B %
l.5> % to 2.7 %
11,4-00 to 15,100
Average
11 %
?. .0 %
\"Zloo
ARE FUEL CONSUMPTION RECORDS KEPT
YES a NO
FOR STOKER SYSTEM,
Coal Size
lOO%
FOR PULVERIZED COAL AND CYCLONE SYSTEM,
FIRING METHOD D Front Wall
D Front Wall - Rear Wall
D All Wall
O Tangential
O Other
OIL FIRING
FIRING METHOD
TYPE OF FUEL
Type
G Front Wai I
D Front Wall -Rear Wall
D All Wall
D Tangential
O Cyclone
D Other Type
D No. 1
D No. 2
O No. 4
0 No. 5
O No. 6
D Other Type
8-35
-------
TYPE OF ATOMIZATION
D Oil Pressure
D Steam Pressure
D Air Pressure
D Rotary Cup
a Other
psi
psi
psi
Type
OIL PREHEAT
OIL COMPOSITION
Ash
Sulfur
BTU/Gal as fired
O YES
D NO
PREHEAT TEMPERATURE
°F
Range
% to
% to
Average
to
ARE FUEL CONSUMPTION RECORDS KEPT
NUMBER OF BURNERS
FIRING CAPACITY PER BURNER
WAS UNIT A CONVERSION UNIT
IF OIL STANDBY, STATUS OF BURNER
Rated
Normal
Maximum
0 YES D NO
BTU/hr
"BTU/hr
"BTU/hr
D YES D NO
D Lett in Firebox
D Pulled Out and Stored
D Multiple Fuel Burner
GAS FIRING
FIRING METHOD
D Front Wall
O Front Wall -Rear Wall
O All Wall
O Tangential
O Cyclone
D Other
Type
GROSS HEATING VALUE
BTU/Cu ft @ 60°F
Range
Average
to
ARE FUEL CONSUMPTION RECORDS KEPT
NUMBER OF BURNERS
YES
NO
8-36
-------
FIRING CAPACITY PER BURNER Rated _ BTU/hr
Normal _ BTU/hr
Maximum BTU/hr
WAS UNIT A CONVERSION UNIT YES NO
IF GAS STANDBY, STATUS OF BURNER D Left in Firebox
D Pulled Out and Stored
D Multiple Fuel Burner
CONTROL EQUIPMENT
Type of Cleaning Equipment £nu.Tg.o&TATti
Pressure Drop Across Collector Q.C, in.HoO
Design Efficiency (If Known) 35 %
Airflow to Control Device Inlet |4o,ooo ACFM @
Stack Diameter b-10
Stack Height f^c, ~ft
Stack Temperature "5A-0 °F
MONITORING EQUIPMENT YES NO
Opacity Meter w rj
_ a a
_ a a
°2 Meter ^ n
CO2 Meter rj ^
Combustion Gas Analyzer p ^
Smoke Alarm g] rj
MAINTENANCE AND OPERATING RECORDS KEPT YES NO
Amount of Steam Generated 53 D
Amount of Fuel Used roj |-j
Type of Fuel Used rg p
Grate or Burner Equipment p, N^
Instrumentation Calibration ]2 rj
Fans, Ductwork, Control Equipment Q ^
Soot Blowing Intervals and Duration rj
$-37
-------
INSPECTION CHECKLIST FOR FUEL-FIRED INDIRECT
HEAT EXCHANGERS
FACILITY IDENTIFICATION
Facility Name / ';• J JTILi y v 6-1.
Facility Address
Inspection Date 11 11?>\1 Z
Person to Contact ^ . Jo. it -._ ,7 PL ^..-T t -> '
Source Code Number QEV"£-.
PREINSPECTION DATA SHEET
0 Adequate Information
D Inadequate Information (Obtain needed data during first inspection)
1 PRE ENTRY DATA
,
Stack Plume Equivalent Opacity (Circle One) 0 (20) 40 60 80 100
Opacity Regulation JS In Compliance D Not In Compliance
Smoke White vGrey) Black or Brown
Reddish Brown Bluish White Yellowish Brown
FUEL PREPARATION SYSTEM
A. Coal-Fired Units Last
Maintenance
Satisfactory Unsatisfactory Date
Coal pile fugitive dust Q jg.
Dust additive application D 03. e"c~ OTt~
Coal conveyor system (3 D M/IX
Coal size 13 Q
B. Oil-Fired Units
Fuel oil storage tank cleaning Q D
frequency 0 D D
Oil preheat temperature F rj rj
Atomization pressure psi r-, r-.
Burner maintenance frequency p p
C. Gas-Fired Units
Burner maintenance frequency Q p
Keyed to reference number in Chapter 8 of text.
Zo MIKJO-TE.S. EXCEEDED 2.0% Op^crry Poe.
10 % Of TiAe "TTnc E>ui STILL WA.S IM
8-38
-------
FURNACE INTERIOR
Have operator open furnace door. Use extreme caution
Furnace Pressure when looking into furnace. Wear either a face shield or
safety glasses. Use proper filters to protect eyes against
D positive brightness of flame .
£3 negative
Last
A0 Furnace Walls Maintenance
Satisfactory Unsatisfactory Date
Cracks and/or Leaks
access doors (2 D
breechings ^ O
air ducts jg D
B. Grate System
Grate condition $ D (?
Grate travel rate D El c.
f^t-
Bed height G$ Q
Bed evenness Q "'jg
C. Flame Characteristics
Impingement on walls and arches 0. D
Flame pattern gj D
Characteristics related to air quantities (Circle)
Excess Normaj^ Lack
Stokers - White Q^ellowish OrgrtO^ Grey
Burners - Totally Blue Blue and Yellow Mix Totally Yellow
Do *Grate Loading (Stoker-Fired Units Only)
Complete for each individual furnace leading to common stack.
Grate Area = Width ft x depth ft = ft2
Inspection only performed during permit review stage.
-1/s.iNj >i_/xcwi.
CO Lip fe-Y
8-39
-------
Loading Rate
a) Feed Rate Control (From Operator)
b) From Steam Flow Indicator
Coal Rate = Ib steam/hr x 0 .09 =
Coal Burning Rate
Grate Loading = Grate Area =
Ib coal/hr
Ib coal/hr
Ib/hr -
E . 'Sorwei: Loading "fp^l burri*t)
1,940,
(L,
\\,mvi(
Coal 25,000 Ib/hr x J^yflOTj BTU/1b = 2 97.5 MM BT U/hr
Oil gal/hr x 145,000 BTU/gal = BTU/hr
Gas fr3/hr x 1,000 BTU/ft3 = BTU/hr
Check manufacturer's specification for acceptable limits.
FLOW RATES
Current steam flow rate from control panel sbew^SoooooJb/hr
Maximum design steam flow rate (from preinspection sheet)
FLOW RATIOS
Steam flow/air flow recorder
Maximum values
Steam flow
Minimum values
Air flow 3>15ooolb/hr
Fuel flow/air flow recorder
Fuel flow _ Ib/hr
Air flow Ib/hr
Ib/hr
Ib/hr
Ratio D acceptable
CONTROL PANEL INSTRUMENTATION
Air flow/steam (or fuel) flow
Furnace pressure & draft gages
Speed & amperage indicators for
control equipment
D unacceptable ' iwiv\. a\r -fWo
Satisfactory Unsatisfactory
H Q
H a
a EI
Last
Maintenance
Date
In
*These are typical values
be used when known.
Actual heat content values should
8-40
-------
Stack viewer
Opacity monitor
Flue gas analyzer
Smoke meter
Flame detector (f.wt)
ASH DISPOSAL SYSTEM
A. Furnace Ash Hopper
Cleanout & transport procedure
General housekeeping
B. Control Equipment Ash Hopper
Cleanout & transport procedure
General housekeeping
@ FANS AND DUCTWORK
Fan Condition
Duct Condition
® AIR POLLUTION CONTROL EQUIPMENT
Type
Mechanical
Satisfactory Unsatisfactory
Interval Between Hopper Cleanouts
a
a
m
m
a
Type
hours
a
a
a
D
a
a
a
a
Exterior Condition
Hopper Level Indicator
D Satisfactory D Unsatisfactory
D Satisfactory D Unsatisfactory
Last
Maintenance
Date
10/Z/TL
*?.
Pressure before Collector
Pressure after Collector
Scrubber
Scrubbing liquor flow
Pressure before scrubber
Pressure after scrubber
in. H2O
in. H2O
Type
_GPM
in. H2O
in. H2O
8-41
-------
Electrostatic Precipifator
Interval Between Hopper Cleanouts IQ hours
Exterior Condition E8 Satisfactory D Unsatisfactory
Spark Rate: sparks/minute
Operating Voltage (KV) Operating Current (MA)
39 no Apufee Field 1
32 •• D Field 2
Field 3
37 " Field 4
zzzzzz! mzzuzzi Fie|d5
Field 6
6>v
^1-l-OXTIOrJ
8-42
-------
Q)
«<_<* o
*. VJ
«u_
E-L.«.»-KV«.
8-43
-------
Frequency
-£2
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Fuel specificatior
Ash content
cr
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| Monthly or
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BTU content
X
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^
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8-44
-------
References - Chapter 8
1. Smith, W.S. and Gruber, C.W. Atmospheric Emissions from
Coal Combustion - An Inventory Guide. Springfield, Va.
NTIS No. PB-170-851, 1966.
2. Steam, Its Generation and Use. Babcock and Wilcox Company.
37th Edition. New York, N.Y. 1963.
3. Perry, R.H. et al. Perry's Chemical Engineer's Handbook.
Fourth Edition. McGraw Hill. New York, N.Y.
4. Control Techniques for Particulate Air Pollutants.
Environmental Protection Agency. Springfield, Va. NTIS
No. PB-190-253, 1969.
5. Oglesby, S. and Nichols, G. A Manual of Electrostatic
Precipitator Technology. Southern Research Institute.
Springfield, Va. NTIS No. PB-196-381.
6. Adapted from: Bartok, W. et al. Systematic Field Study
of NO Emission Control Methods for Utility Boilers.
ESSO Research and Engineering Company. Springfield, Va.
NTIS No. PB-210-739.
7. "Background Information for Establishment of National
Standards of Performance for New Sources, Industrial Size
Boilers," Walden Research Corp., Waltham, Mass. Contract
CPA 70-165, Task Order No. 5. Prepared for Office of Air
Programs, Environmental Protection Agency, Research
Triangle Park, North Carolina. 1971.
8. LaMontia, C.L., and Field, E.L.: "Tackling the Problem
of Nitrogen Oxides," Power, P. 63. April 1969.
9. Woolrich, P.F., "Methods for Estimating Oxides of Nitrogen
Emissions from Combustion Processes." Amer. Ind. Hyg.
Assoc. J. 22, 481. 1961.
8-45
-------
-------
9.0 INSPECTION PROCEDURES: MUNICIPAL INCINERATORS
Inspection procedures for municipal incinerators are
similar in many respects to those for fuel-fired indirect
heat exchangers; the procedures include general inspection
of the incineration process, inspection of the air pollution
control system, and spot-check of selected records.
The FEO should review the operating permit application
prior to an inspection, since the primary purpose of a routine
field inspection is to determine whether a unit is conforming
With permit conditions. In addition to checking on permit-
related items, the FEO should determine whether the plant is
following good operating practices, since improper operation can
lead to excessive emissions. During non-routine inspections
prompted by complaints or visible emission violation, the
enforcement officer should establish the cause for violation
and discuss corrective procedures with the operator.
Section 9.1, Inspection of the Incineration Process,
describes general facility observations and the design and
operating factors that can be quantitatively compared with
"good practice" values.
Section 9.2, Inspection of Air Pollution Control Systems,
describes the procedures for inspecting air pollution control
equipment. Section 9.3 presents an example inspection check-
list for recording field observations. Section 9.4 lists the
types of records the facility should maintain.
Section 9.5, Emission Estimating Procedures, describes
methods of estimating emissions from municipal incinerators.
Since most of these procedures rely upon design rather than
operating data, these estimates would normally be made at
9-1
-------
the permit review stage. If the detailed review has not
been performed, however, the permit review engineer or the
FEO should make this evaluation using the data contained on
the preinspection data sheets or obtained during the first
inspection. Section 9.6 presents an example inspection.
If an inspection indicates that a source is not operating
in compliance with applicable regulations, the FEO should
follow established agency procedures regarding notice of
violation, request for source test, and related matters.
9.1 Inspection of the Incineration Process
The field enforcement officer must observe, in a quali-
tative manner, the items associated with atmospheric emissions.
Equipment condition, charging procedures, and general house-
keeping all influence the emission rate. Incinerator design
is also a major factor that should be reviewed at the time the
construction permit or operating permit applications are
evaluated. Table 9.1 lists the design parameters important
from a potential emissions standpoint, and the accepted values
for each parameter. Units that deviate from these values
may be operating properly, however, since many different
incinerator designs are effective.
Observe the plume before entering the plant.
Check plume opacity. (Don't mistake water vapor
condensation for particulate emission. The conden-
sation plume eventually dissipates, exposing any
particulate emissions.) Also note the plume color
and check Table 9.2 for possible operating factors
that may be causing the emission.
* Numbers refer to corresponding sections of example checklist,
9-2
-------
Table 9.1. DESIGN PARAMETERS FOR MUNICIPAL INCINERATORS
Parameter
Grate loading
Underfire/overfire air
ratio
Underfire air rate
Secondary chamber temperature
Retention time or chamber
velocity
Mixing chamber
Secondary chamber
Recommended value
o
40 lb/ft--hr. recommended
50 Ib/fr -hr . maximum
1 :2 recommended for regular refuse
1 :1 recommended for wet refuse or regular
garbage
2
100 scfm/ft grate area maximum
1600 F recommended average
1400°F minimum average
0 .5 second minimum or 25 ft/sec maximum
1 .0 second minimum or 10 ft/sec maximum
Table 9.2. RELATIONSHIPS OF PLUME CHARACTERISTICS
AND OPERATING PARAMETERS
Possible operating factors to
investigate and corrective action
Stack
plume
White
Black
Fly
ash
Grate
loading
Decrease
Decrease
Overfire
air rate
Increase
Secondary
temperature
Increase
Underfire
air rate
Decrease
Decrease
9-3
-------
Check for odor before entering the plant.
Note whether odors are detectable downwind of the plant.
If odors are present, the FEO should determine the
source.
Inspect the receiving area.
Check for odors and general housekeeping. Note back-
log quantity of refuse. Inspect truck dumping and
crane charging procedures. If trucks are weighed
upon entering and leaving site, obtain weight records
for subsequent calculations to determine whether
incinerator capacity is being exceeded.
Examine the charge hopper.
The hopper should either be fully charged or have a
door to seal the ignition chamber. Check for any other
air leaks.
The FEO can also estimate the charging rate to determine
whether the grate loading or the incinerator capacity is being
exceeded. Checking incoming refuse weight records and comparing
these with furnace operating hours will indicate average
or long-term (e.g., one-week or month) conditions. To estimate
the charging rate during an inspection, the FEO should: Estimate
the volume (cubic feet) of the crane bucket by multiplying the
approximate length, width, and height together. Note how many
times the crane drops in a certain time interval and estimate
how many loadings would occur in an hour. Multiply the cubic
feet of shovel volume by the number of drops per hour and refuse
density (assume 10 Ib/ft as fired)a to determine the total
weight of refuse burned in Ib/hr. The total weight charged per
hour can be compared with operating permit values to determine
whether the incinerator is exceeding maximum operating capacity
or can be divided by the grate area to determine whether the
recommended grate loading values (Table 9.1) are being exceeded.
Compacted refuse may be 20 Ib/ft or higher,
9-4
-------
Examine the furnace.
Inspect the walls for air leaks or cracks by placing
hand close to the wall. Have the incinerator operator
open the furnace ports and check the firebox interior
for the following items:
0 proper grate travel (may only be possible when furnace
is empty)
0 adequate stoking (may only be possible when furnace
is empty)
0 absence of blowholes
0 missing grate sections (may only be possible when
furnace is empty)
0 amount of unburned refuse passing through grate
0 broken or missing firebricks in arches and
interior refractory.
Exercise extreme caution and wear eye protection when
looking into the furnace because of the possibility of
exploding glass bottles or reversal of furnace pressures.
A filter should be used to shield the eyes against the bright-
ness of the burning refuse.
The amount of waste charged (grate loading) influences
the temperature gradient and amount of air passing through the
refuse bed. The FEO will often encounter grate loadings higher
than those recommended because of increases in the population
served by the incinerator and in per-capita refuse generation
rates. High grate loadings decrease combustion efficiency,
causing emissions of unburned particulate matter and odors.
To determine grate area, multiply the primary chamber
length (feet) by the width (feet) for each furnace. Divide
the previously determined refuse quantity (Ib/hr) by the grate
2
area (ft ) and compare with the allowable refuse values in
Table 9.1. As a quick check, note the height of the refuse
bed. Bed heights greater than 3 feet usually indicate grate
loadings in excess of recommended values.
The amounts of underfire and overfire air can significantly
affect emissions. Excessive underfire air, although it
increases the burning rate, causes particles to be lifted off
9-5
-------
the burning refuse bed and emitted from the stack. With
wet refuse, underfire air can be increased to promote burning
without increasing the emission rate, but this practice should
be limited to burning of refuse having high moisture content
and should not become routine. Overfire air is required to
complete the burnout of volatilized combustible material. To
attain higher burning rates, many units routinely operate with
underfire/overfire air ratios higher than those recommended in
Table 9.1. Since this practice leads to excessive particulate
•missions, it should be discouraged. (A second or third shift of
operation at the incinerator may be required.)
It is impossible for the FEO to determine the amount of
air entering the incinerator, but if the flame pattern is too
active, or large particles are emitted from the stack, air
quantities may be exceeding acceptable levels.
Check the control panel.
Read the secondary chamber temperature from instrument
panel. Considering thermocouple position, determine
whether temperature is acceptable (e.g., thermo-
couple located in transition between the chamber and
ductwork leading to stack will read lower than thermo-
couple at the chamber midpoint). Recommended minimum
average chamber temperature is about 1400°F.
Inspect ash disposal system.
Check both furnace bottom ash and control equipment
ash hoppers for correct ash handling procedures. Ash
from hoppers should not drop significant distances
when being transferred unless an enclosure is used to
prevent dust emissions. Ash should be moistened before
transport to minimize dust emissions during transit to
the ash'disposal site.
Inspect ductwork.
Check ductwork for missing sections, holes, and leaks.
9-6
-------
Review operating records.
Spot check records of refuse quantities incinerated
and operating hours to determine whether unit is
operating above capacity. Check maintenance records
to determine whether preventative maintenance program
is being followed.
9.2 Inspection of Air Pollution Control Systems
Various types of scrubbers and inertial collectors
(including wetted wall baffles incorporated into the design
of the incinerator) are the most commonly used control devices,
Recently electrostatic precipitators have been installed on
several incinerators.
Because of the variety of control device designs in use,
it is impractical to establish specific inspection procedures
for each control device type. In general, check to see
whether the unit is operated in accordance with manufacturer's
specifications. If it is, however, this does not necessarily
mean that the unit is attaining the specified collection
efficiency, since many units are underdesigned. The most
effective enforcement and surveillance method is to test
emissions when the incinerator is operating under adverse
conditions (e.g., high load, wet refuse) to determine whether
the control device is meeting required collection efficiencies,
Record the values for key control device parameters (e.g.,
pressure drop, scrubbing liquor to gas flow ratio) so that
on subsequent inspections the FEO can determine whether
the control device is operating in accordance with values
that emissions tests have determined to be effective.
Electrostatic precipitators should be inspected in the
same general manner as described for precipitators applied to
coal-fired boilers.
9-1
-------
9.3 Inspection Form
Data obtained during an inspection can be summarized on
an inspection form similar to that shown on the following
pages. This form also serves as a record of the inspection.
9.4 Recordkeeping Requirements
Table 9.3 lists the recommended recordkeeping require-
ments for municipal incinerator facilities. The FED should
spot-check such records during his inspections to verify that
proper operating practices are followed in the intervals
between inspections.
Table 9.3. RECOMMENDED RECORDKEEPING REQUIREMENTS FOR
MUNICIPAL INCINERATORS
Item
Refuse burned
Operating hours/furnace
Temperature of
secondary chamber
Air pollution control
device parameters
Units
tons/day
hours
°F
-
Frequency
Daily
Daily
Continuous recording
Daily
Records maintained for minimum of three months
9.5 Procedures for Estimating Emissions
Particulates are the emissions of primary concern from
municipal incinerators. To a lesser extent, odors, carbon
monoxide, hydrocarbons, and nitrogen oxides may also be of
concern. As the earlier discussions indicated, emission rates
vary considerably among incinerators of various types and also
vary from day to day at the same incinerator. Because of the
9-8
-------
INSPECTION CHECKLIST FOR MUNICIPAL INCINERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact
Source Code Number
PRE INSPECTION DATA SHEET
D Adequate information
D Inadequate information (Obtain needed data during first inspection)
PRE ENTRY DATA
Stack Plume
Stack Plume
Odors
RECEIVING AREA
Percent Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation D In Compliance QNot In Compliance
Ringelmann No. (Circle One) 0 1
Smoke D White D Grey
D None D Faint
2345
D Black or Brown
D Strong
Odors
General Housekeeping
Weigh Scale
Refuse Burning Rate (from plant records)
No. of operating hours per day
Satisfactory
_
D
a
Unsatisfactory
a
a
a
Last
Maintenance
Date
Tons of refuse collected per day (for one week period)
Tons/day x
2000
number of operating hours/day =
Total
Average
Average
Tons/week
Tons/day
Ib/hr
Keyed to reference number in Chapter 9 of text.
9-9
-------
CHARGE HOPPER Last
Maintenance
Satisfactory Unsatisfactory Date
Hopper Condition Q Q
Absence of air leaks to furnace n Q
Refuse burning rate (calculate only if unobtainable from plant record information)
Calculate bucket volume
+ Volume = ft. x ft. x ft. = ft3
Number of drops in minutes.
* Charge Rate = Bucket Vol. (ft3) x No. of drops x 600 = Ib/hr
Minutes which drops occurred
FURNACE CHAMBERS
Have operator open furnace door. Use extreme caution when
Furnace pressure looking into furnace because of possibility of exploding glass
positive bottles and the like. Wear either a face shield or safety glasses.
negative Use proper filters to protect eyes against brightness of flame.
A. Firebox Condition Last
Maintenance
Satisfactory Unsatisfactory Date
Cracks and/or leaks in walls Q Q
Grate condition Q D
Grate travel and stoking O Q
Absence of blowholes D D
Grate dropthrough Q D
Interior refractory D D
+ Must be calculated for each chamber. If all chambers are similar, volume can be averaged,
*3 o
* Assume refuse density of 10 Ib/ft . Compacted refuse may be 20 Ib/ft or higher.
a Some items can only be checked when furnace is not operating.
9-10
-------
B. Grate Area (Of Operating Chambers)
Width, Depth, No. of Similar Active Chamber* Area/
Chamber _ft ft Chambers Time Percentage ft2
1 x x x =
2 x x x =
3 x x x =
4 xx x -
5 x x x =
Total Grate Area, ft2
Active chamber time percentage = No. of operating hours in one week - hours of down time
No. of operating hours in one week period
C . Grate Loading
refuse rate(lb /hr ) 2
Grate Loading = grate area (ft 2) = = Ib/hr - ft
Approximate bed height ft
D. Thermocouple Location
CONTROL PANEL INSTRUMENTATION Last
Maintenance
Satisfactory Unsatisfactory Date
Secondary chamber temperature F Q D ______
Gages reading properly D D
Graph recording time trace Q Q
ASH DISPOSAL SYSTEM
A. Furnace Ash Hopper
Cleanout & transport procedure Q D
General housekeeping D D
Ash characteristics D D
B. Control Equipment Ash Hopper
Cleanout & transport procedure Q Q
General housekeeping Q Q
FANS AND DUCTWORK
Fan condition D ^
Duct condition D d
9-11
-------
) AIR POLLUTION CONTROL EQUIPMENT
Type
Mechanical
Type
Interval Between Hopper CIeanouts
hours
Exterior Condition
Hopper Level Indicators
Pressure before Collector
Pressure after Collector
Scrubber
Scrubbing liquor flow
Pressure before scrubber
Pressure after scrubber
D Satisfactory D Unsatisfactory
Q Satisfactory Q Unsatisfactory
in . H2O
in . H2O
_GPM
in . H2O
in . H2 O
Electrostatic Precipitator
Interval Between Hopper Cleanouts
Exterior Condition
Spark Rate:
hours
Operating Voltage (KV)
D Satisfactory D Unsatisfactory
sparks/minute
Operating Current (MA)
Field 1
Field 2
Field 3
Field 4
RECORDKEEPING REQUIREMENTS
Item
Refuse burned
Secondary temperature
APC Device Design Parameter
(Specify pressure drop,
corona power, water flow
rate, etc.)
Number
Tons/day
daily record; maintain records for
3 months
maintain recording charts for 3 months
once per shift.
9-12
-------
many design and operating variables affecting emission rates,
it is not possible to establish procedures for estimating
emissions from individual jncinerators.
Table 9.4 presents emission factors for various types
of incinerators. These factors are, at best, suitable for
comparing emissions from one type of incinerator with those
from another. Procedures for using these factors are presented
below:
Table 4. MUNICIPAL, INCINERATOR EMISSION FACTOR SUMMARY2
Pollutant
Mineral participate
(Ib/ton of refuse)
Combustible participate
(Ib/ton of refuse)
Carbon monoxide
(Ib/ton of refuse)
Nitrogen oxides(as NC>2)
(Ib/ton of refuse)
Hydrocarbons
(Ib/ton of refuse)
Sulfur oxides (as SO2)
(Ib/ton of refuse)
Hydrogen chloride
(Ib/ton of refuse)
(Ib/ton of PVC resin)
Continuous, refractory wall
Rock-
ing
grate
14
4
30
3
2
4
1
1180
Recip.
grate
29
4
30
3
2
4
1
1180
Trav.
grate
13
4
30
3
2
4
1
1180
Grate -
kiln
34
3
21
3
2
4
1
1180
Batch, refractory wall
Circ.
10
5
35
3
3
4
1
1180
Rectang .
20
5
41
3
3
4
1
(180
Hearth
8
5
41
3
3
4
1
1180
Continuous, water wall
Rock-
ing
grate
14
3
21
3
2
4
1
llfao
Recip .
grate
28
3
21
3
2
4
1
1180
Trav.
grate
13
3
30
3
2
4
1
1180
Suspen -
sion
burning
49
2
15
3
1
4
1
1180
9.5.1 Uncontrolied Emissions
Determine the following incinerator characteristics
0 wall type: refractory or water wall
0 charging characteristics: batch or continuous
0 grate type
9-13
-------
Obtain uncontrolled emission values from Table 9.4 for
the specific incinerator.
Control device efficiency.
Collection efficiencies vary widely. Table 9.5 lists
collection efficiencies for units operating satisfactorily.
Actual emissions.
Actual emissions are computed according to the following
formula:
AE = (UE) (1-E)
where:
AE = actual emissions
UE = uncontrolled emissions
E = control device efficiency
Although air pollution emissions from incinerators
should be defined in terms of pounds of pollutant per weight
of refuse charged, they are often expressed in other units.
Table 9.6 lists conversion factors for various units for a
common municipal incinerator refuse (having a heating value
of 4450 BTU/lb).
Table 9.5.
AVERAGE CONTROL EFFICIENCIES OF AIR
POLLUTION CONTROL SYSTEM2
APC system removal efficiency (weight percent)
APC Type
None (flue settling only)
Dry expansion chamber
Wet bottom expansion chamber
Spray chamber
Wetted wall chamber
Wetted, close-spaced baffles
Mechanical cyclone (dry)
Medium -energy wet scrubber
Electrostatic precipitaror
Fabric niter
Mineral
particular*
20
20
33
40
35
50
70
90
99
99.9
Combustible
participate °
2
2
4
5
7
10
30
80
90
99
Carbon
monoxide
0
0
0
0
0
0
0
0
0
0
Nitrogen
oxides
0
0
7
25
25
30
0
65
0
0
Hydro-
carbons
0
0
0
0
r o
0
0
0
0
0
Sulfur
oxides
0
0
0
0.1
0.1
0.5
0
1.5
0
0
Hydrogen
chloride
0
0
10
40
40
50
0
95
0
0
Polynuclear ,
hydrocarbons 1
10
10
22
40
40
85
35
95
60
67
Volatile
metals
5
0
4
5
7
10
0
80
90
99
.Assumed primarily < 5 microns.
Assumed two-thirds condensed on particulate, one-third as vapor.
Attuned primarily a fume < 5 microns.
9-14
-------
Table 9.6. CONVERSION FACTORS FOR PARTICULATE
INCINERATOR EMISSIONS3'2
Lb0on
refuse
(as received)
Lbs/1000 Ibs
flue gas at 50%
excess air
Lbs/1000 Ibs
flue gas at
12%CO2
Grains/SCF
at 50% excess
air
Grains/SCF
at 12%CO2
Groms/Nm3
at NTP, 7% CO2
Lbs/ton
refuse
(as received)
1
11.27
10.0
21.31
18.85
15.0
Lbs/1000 Ibs
flue gas at 50%
excess air
0.089
1
0.89
1.93
1.71
1.36
Lbs/1000 Ibs
flue gas at
12%CC>2
0.10
1.12
1
2.16
1.92
1.53
Grains/SCF
at 50%
excess air
0.047
0.52
0.46
1
0.89
0.704
Grains/SCF
at 12%
C02
0.053
0.585
0.52
1.12
1
0.79
Grams/Nm
at NTP,
7%CO2
0.067
0.74
0.66
1.42
1.26
1
* Based on refuse of 4,450 BTU/lb or higher heating value
For example, to convert from Lbs/ton refuse to
Lbs/1000 Ibs flue gas at 50% excess air, multiply the
Lbs/ton refuse value by the factor 0.089.
9.6 Example Inspection Report
The following pages illustrate the use of the pre-
inspection data sheet and inspection checklist as they
might be filled out by an FEO in the field.
9-15
-------
PREINSPECTION DATA SHEET FOR INCINERATORS *
FACILITY IDENTIFICATION (JM,
TYPE OF INCINERATOR lEi Municipal Refuse
O Municipal Sludge
CD Commercial/Industrial
D Apartment
D Other
Type
WASTE STORAGE
Type
Circle Type 0 1 (2) 3 4 5 6
or _______ BTU/lb
NUMBER OF FURNACES 2
D Open Area
O Paved Floor
{3 Receiving Pit
O Other
WASTE CLASSIFICATION OR HEATING VALUE
RATED CAPACITY (Per Furnace) \%o Tpp
(24 Ho»e
NUMBER OF FURNACES AT THE INCINERATOR SITE LEADING TO A COMMON STACK
COMBUSTION CHAMBERS 8 Primary
C3 Mixing
0 Secondary
® F I N
TYPE OF COMBUSTION AIR O D El
SI D O
JS O D
Primary Underfire
Primary Overfire
Secondary or Mixing
TYPE OF CHARGING
CHARGING METHOD
OPERATING SCHEDULE
D Batch
63 Continuous
IS Chute Fed
D Flue Fed
D Direct Fed
a Other
1^ Hr/Day
B
Type
Days/Wk
51
Wk/Yr
® F Forced Draft
I Induced Draft
N Natural Draft
If an incineration site has two or more furnaces and the furnaces are not identical, separate
forms are required for each furnace.
a.
<_-
- Au_
9-16
OF
-------
k Width Depth Height Total
PRIMARY CHAMBER DIMENSIONS 3o ft x 6 ft x \2. ft = 2&&Q ft3
SECONDARY CHAMBER DIMENSIONS 5o ft x 13 ft x \o ft -
MIXING CHAMBER LENGTH 25 ft
GRATE OR HEARTH TYPE
GRATE AREA (.1^,?) 2-4o ft2
ANGLE OF INCINERATION jp Degrees
AUXILIARY FUEL Kloue. D Natural Gas
D Oil
0 LPG
D Other Type
D CONTINUOUS D INTERMITTENT a STARTUP
MAXIMUM AUXILIARY FUEL HEATING RATE (IF USED) _ BTU/hr
AUXILIARY FUEL INTRODUCTION IN O Primary Chamber
O Mixing
D Secondary
AUXILIARY FUEL TEMPERATURE CONTROL O Yes If Yes, Lower Limit _ °F
v a NO
COMBUSTION MAKEUP AIR PROVISION SOURCE
INSTRUMENTATION YES NO
Secondary Chamber Temperature S D
Underfire Air Draft @l D
Overfire Air Draft H D
Combustion Gas Analyzer or Orsat D [2
9-17
-------
CONTROL EQUIPMENT
Type of Cleaning Equipment
Pressure Drop Across Collector
Design Water Rate
Design Efficiency (If Known)
Airflow to Control Device Inlet
Stack Diameter
Stack Height
Stack Temperature
MONITORING EQUIPMENT
Opacity Meter
Others
Flue Gas Analyzers
MAINTENANCE AND OPERATING RECORDS KEPT
Amount of Refuse Burned
Furnace Walls
Grate System
Auxiliary Fuel Burners (If Used)
Instrumentation Calibration
Fans, Ductwork, Control Equipment
ACFM @
YES
a
a
D
D
a
YES
m
D
a
a
El
n
I.Q - 2.0 'n' H2O
10-is. gpm
^ bo %
oF
fco
ft
NO
a
n
a
m
NO
a
D
a
8'
To A
LEAD To ^
9-18
-------
INSPECTION CHECKLIST FOR MUNICIPAL INCINERATORS
WtU-A
FACILITY IDENTIFICATION
Facility Name (_)K
Facility Address
Inspection Date
Person to Contact
Source Code Number QE.PA 2.Oo\- &\1
PRE INSPECTION DATA SHEET
63 Adequate information
D Inadequate information (Obtain needed data during first inspection)
^
PRE ENTRY DATA
Stack Plume
Stack Plur-ft
Odors
RECEIVING AREA
Odors
General Housekeeping
Weigh Scale
a.
Percent Equivalent Opacity (Circle One) 0(20)40 60 80 100
Opacity Regulation D In Compliance 0 Not In Compliance
Ringelmann No. (Circle One) 012345
Smoke White 5^£L B\ack or Brown
None (joint^ Strong
•See Last
Maintenance
TIME. IM Etcess. Of- '2.o%,~n»e,«Poe£.
Satisfactory
I
D
Refuse Burning Rate (from plant records)
No. of operating hours per day \lp
Tons of refuse collected per day (for one week period)
Tons/day x
2000
number of operating hours/day -
Unsatisfactory
D
D
Dka.
4/8
4/9 .
Total
Average
Average
Date
in
2*1
2-5 le>
lib
2/73
U&tTons/
111 Tons,
2%oo 'I
Ib/hr
Keyed to reference number in Chapter 9 of text.
9-19
-------
CHARGE HOPPER Last
Maintenance
Satisfactory Unsatisfactory Date
Hopper Condition fj $ lr-
Absence of air leaks to furnace 0 Q
Refuse burning rate (calculate only if unobtainable from plant record information)
Calculate bucket volume D\G>*jn- 6f._^^-r,-.r ~ Uto>T \s
TPP
+ Volume = ft.x ft.x ft.=
Number of drops in minutes.
* Charge Rate = Bucket Vol. (ft3) x No. of drops x 600 = Ib/hr
Minutes which drops occurred
0 FURNACE CHAMBERS
Have operator open furnace door. Use extreme caution when
Furnace pressure looking into furnace because of possibility of exploding glass
D positive bottles and the like. Wear either a face shield or safety glasses.
El negative Use proper filters to protect eyes against brightness of flame.
A. Firebox Condition Last
Maintenance
Satisfactory Unsatisfactory Date
Cracks and/or leaks in walls g3 fj
Grate condition H D
Grate travel and stoking gl D I2./id/11
Absence of blowholes 63 D —
Grate dropthrough g| D —
Interior refractory D E3
+ Must be calculated for each chamber. If all chambers are similar, volume can be averaged
*5
* Assume refuse density of 10 Ib/ft .
a Some items can only be checked when furnace is not operating.
^ -Sex. Klort 3.
9-20
-------
B. Grate Area (Of Operating Chambers)
Width, Depth,
amber ft ft
1 61
20 *i
D /
*3 o^>
4*g>4
5 Al H
*
/e chamber
•7.9 x 5 x
1.5> x 6 x
•7.S x & x
^C- v Q v
• t> X O x
1."3 X ft X
3pcc.**rvo«J
time percentage =
No. of Similar Active Chamber* Area,
Chambers Time Percentage ft
I x \00
\ x \oo
| x UO
1 x 0
4 x 100
Total Grate Area,
No. of operating hours in one week
60
bo
60
0
240
ft2 4-10
- hours of down time
No. of operating hours in one week period
Grate Loading
refuse rate(lb /hr )
Grate Loading = grate area (ft )
Ib/hr - ft
D,
Approximate bed height 4- TO S
Thermocouple Location (
ft
OF-
.oioo-Ci^V
CONTROL PANEL INSTRUMENTATION
Secondary chamber temperature
Gages reading properly
Graph recording time trace
ASH DISPOSAL SYSTEM
A. Furnace Ash Hopper
Cleanout & transport procedure
General housekeeping
Ash characteristics
B. Control Equipment Ash Hopper
Cleanout & transport procedure
General housekeeping
FANS AND DUCTWORK
Fan condition
Duct condition
Satisfactory
Unsatisfactory
a
a
a
Last
Maintenance
Date
a
a
a
is
s
a
a
a
a
a
\ih\
*2/5,AMt>4
9-21
-------
Type
Mechanical
Type
Interval Between Hopper Cleanouts
hours
Exterior Condition
Hopper Level Indicators
Pressure before Collector
Pressure after Collector
Scrubber
Scrubbing liquor flow 4o -5
Pressure before scrubber
D Satisfactory D Unsatisfactory
rj Satisfactory D Unsatisfactory
in . H2O
in . H2O
GPM
U(,
'n •
Pressure after scrubber — p.4 in . H2 O
Electrostatic Precipitator
hours
Interval Between Hopper Cleanouts
Exterior Condition O Satisfactory D Unsatisfactory
Spark Rate: sparks/minute
Operating Voltage (KV)
Operating Current (MA)
Field 1
Field 2
Field 3
Field 4
RECORDKEEPING REQUIREMENTS
Item
Refuse burned
Number
IfcS
Tons/day
Secondary temperature 12.00-1^00
APC Device Design Parameter ^
(Specify pressure drop,
corona power, water flow
rate, etc .)
>F If
daily record; maintain records for
3 months
maintain recording charts for 3 mo
once per shift.
9-22
-------
V-
oe.
W
BO
JLE-Fi/se.
r-o
4 t~
IKI OP&-J
1*4 \\0p*e*-» '
JM
"To \Ajiut>. W^ewco
/A
te.
Win*
9-23
-------
References - Chapter 9
1. DeMarco, J. et al. Incinerator Guidelines - 1969. USDHEW,
Bureau of Solid Waste Management. Washington, D.C. PHS
Publication No. 2012. 1969, 98 pages.
2. Neissen, W. et al. Systems Study of Air Pollution from
Municipal Incinerators. A.D. Little. Springfield, Va.
NTIS No. APTD 1283, 1284, 1285.
9-24
-------
10.0 INSPECTION PROCEDURES: COMMERCIAL/INDUSTRIAL INCINERATORS
The inspection of commercial/industrial incinerators is
similar to the inspection of fuel-fired indirect heat
exchangers and municipal incinerators; procedures include
inspection of the incinerator and air pollution control
equipment, and a spot-check of selected records. The FEO
will encounter many variations of incinerators ranging from
primitive to relatively advanced, including homemade or
converted units that are not specifically designed for the
waste being burned.
Section 10.1 describes the design and operating factors
that should be considered during the permit evaluation.
Section 10.2 describes general facility observations for the
following types of units: residential/apartment house, patho-
logical, industrial, reclamation, sewage sludge, and wood
waste incinerators. Procedures for inspecting control devices
are similar to those described for fuel-fired heat exchangers
and municipal incinerators and are not repeated here. Section
10.3 presents example inspection checklists for recording field
observations. The checklists include the types of records that
should be maintained by incinerator facilities. Section 10.4
describes methods for estimating emissions.
10.1 Design and Operating Factors
Table 10.1 lists the incinerator design parameters
important from an air pollution standpoint and the "good
practice" design values. The influence of these parameters on
emission rate is discussed in Section 9.1 as they apply to
municipal incinerators. Values for these parameters should be
checked at the permit review stage to determine the adequacy
of the incinerator design.
10-1
-------
Table 10.1. INCINERATOR DESIGN PARAMETERS"
Parameter
Grate or
hearth loading
recommended
Ib/fT-hr
Final chamber
temperature
minimum °F
Final chamber
retention time or
chamber velocity
Auxiliary . _ei
requirement)
BTU/lb - Ib waste
Residential
50
....
2000
Pathological
10
1600
5 ft/sec
maximum
8000
Industrial/commercial
70 (Type 1)
55 (Type 2)
40 (Typ* 3)
1400
20 ft/sec max uype 1)
15 ft/sec max (Type 2)
10 ft/sec max (Type 3)
0 (Type 1)
1500 (Type 2)
3000 (Type 3)
Sludge
(after drier)
50
(per stage)
1600
(at maximum
hearth)
_.»_
variable
Reclamation
Dependent upon
reclaimed material
1400
0 .5 seconds
minimum
variable
Wood waste
75 (Dry)
1800 (Dry)
20 ft/sec
maximum
0 (Dry)
2000 (Wet)
10.2 General Equipment and Facility Observations
The FEO should observe the incinerator, its stack, and
surroundings before entering the plant. Table 10.2 lists the
general operating parameters that affect color and density
of the plume.
Table 10.2. RELATIONSHIPS BETWEEN PLUME CHARACTERISTICS
AND INCINERATOR OPERATING PARAMETERS
Stack
plume
White
Black
Fly ash
Possible operating factors to
investigate and corrective action
Grate
loading
Decrease
Decrease
Overfire
air rate
Increase
Secondary
temperature
Increase
Underfire
air rate
Decrease
Decrease
10-2
-------
Though smaller sources incinerate less waste than a
municipal incinerator, they are frequently overcharged on a
short-term basis. Excessive emissions frequently are due
to starting a "cold" furnace several times a day. The
startup procedure should be carefully reviewed with the
operator and periodically observed.
10.2.1 Residential/Apartment House Incinerators
Although the use of residential single chamber incinerators
is rapidly declining, FEOs in some metropolitan areas must
inspect these incinerators. Design guidelines presented in
Table 10.1 for residential incinerators are limited because of
the enormous number of possible designs. The field enforcement
officer's objective is to assure that the incinerator is
properly operated and maintained. He should check the following
items:
0 Observe the plume before inspecting the incinerator.
Determine if plume opacity exceeds applicable standards.
Check Table 10.2 for,possible corrective actions.
0 Upon entering the incinerator area, calculate or
estimate grate loadings, as described in Section 9.1.
Also calculate amount of auxiliary fuel used. Compare
to values in Table 10.1 and to specified values on
permit applications.
0 Examine charging and ash pit doors, underfire spinners,
and air dampers for adequate air supply throughout
the ignition and burning period. Examine the charging
and ash pit doors for proper sealing.
0 Check the draft dampers for proper functioning.
0 Determine whether ash is removed regularly from ash
chambers and note ash disposal method.
0 Check to see that chutes and grates are not blocked.
*Numbers refer to corresponding sections of example checklists
for use in inspecting commercial/industrial incinerators.
10-3
-------
0 Review stoking procedures; gentle stoking minimizes
fly ash emissions.
0 Many residential units are equipped with an afterburner
or other control device. If one is used, check the
condition of the equipment.
Improving the burning process may be the best method of
reducing emissions. Suggestions for improvement include:
0 Installation of dampers in the breeching to limit
draft and to achieve desired combustion temperatures.
This is particularly necessary in tall buildings where
the high draft can cause excessive particulate entrain-
ment in the flue gases.
0 Installation of dual flues in a flue-bed unit; use of
separate flues for charging and exhaust will eliminate
disruption of the fire bed.
0 Redesign of chute charging doors so that they cannot
be opened during a burning cycle and so that they
shut automatically after waste is deposited.
0 Provision of auxiliary undergrate gas burners to
further decrease moisture content of refuse.
0 Installation of afterburners or scrubbers to reduce
emissions.
10.2.2 Pathological Incinerators
Odors are the only potentially significant emissions from
pathological incinerators. Inspection procedures for a patho-
logical incinerator are described below.
1) ° Note whether odors are detectable around the incinerator
site.
0 Calculate or estimate hearth loadings, as in the
procedure described in Section 9.1/ and compare with
allowable values in Table 10.1.
0 Determine secondary chamber temperature (if possible).
Adequate auxiliary fuel is needed to raise chamber
temperature to at least 1600°F to eliminate odors.
10-4
-------
° Check the amount of auxiliary fuel used; adequate fuel
is needed to dehydrate pathological wastes since deep
lying tissue is insulated from the ignition chamber heat.
0 Ask the operator if the hearth is preheated before
a charge is introduced -in the incinerator. The burner
must be placed in the immediate vicinity of the
charged material for complete burnout. If possible,
examine the general condition of the incinerator interior,
0
Most pathological incinerators are designed with multiple
chambers. Single chamber units must be equipped with
an afterburner. Check the afterburner to assure proper
burning sequence takes place.
10.2.3 Industrial/Commercial Incinerators
These incinerators are designed to handle wide ranges
of fuel composition (Types 0,1,2,3 and 4 wastes). Auxiliary
fuel is required in the primary chamber for all but type 0
and type 1 waste . Inspection procedures :
° Observe the plume before inspecting the incinerator.
°
Check charging procedures. Since refuse charging
and ignition may take place many times throughout
the day, adherence to correct charging procedures is
very important. A small initial charge should be
ignited, half burned, and pushed to the rear of the
ignition chamber. As new refuse is added to the front
section of the grate, the fire propagates to the newly
charged material. Ply ash is minimized, since the
refuse pile need not be unduly disturbed.
° Examine waste and determine refuse type.
° Determine or approximate grate loading and compare with
the allowable values in Table 10.1 and to specified
loading on permit application.
° Determine secondary chamber temperature (if possible) .
Compare with values in Table 10.1 and to specified
loading on permit application.
10-5
-------
0 Check to see that adequate auxiliary fuel is being
used.
0 Inspect burners, grates, chamber interior, air ports,
and dampers; note any defective equipment.
0 If the unit is equipped with an air pollution control
device, examine the system for leaks, unemptied hoppers,
10.2.4 Sewage Sludge Incinerators
Multiple hearth incinerators are the most common type
used for burning sewage sludge. The treatment plant and the
settling and digesting tanks are potential odor sources. In
addition to the required combustion zone temperature of 1600°F
(Table 10.1), temperatures should be about 1000°F at the top
hearths and near 600°F at the bottom hearths. The combustion
waste gases should be raised to 1300°F or higher to minimize
odors. Inspection procedures:
0 Observe the plume before inspecting the incinerator.
Note any odors near the treatment plant, the settling
and digesting tanks, and downstream of the site.
0 Estimate the hearth loading rate and compare with
allowable values listed in Table 10.1 and to specified
loading on permit application.
0 Determine the maximum temperature or the temperature
gradient across the hearths and compare with values
in Table 10.1 and to specified loading on permit
application.
0 Ask plant personnel how much auxiliary fuel is used tc
supplement the waste. Calculate the heating value
added per pound of waste and compare with values in
Table 10.1.
0 Inspect auxiliary burners, hearths, air ports, and
the air moving system; note any defective equipment.
0 Examine the air pollution control system for clogged
passages and holes or openings which reduce pressure
drop.
10-6
-------
10.2.5 Reclamation Incinerators
Of the many types of reclamation incinerators, all
may be classified as either enclosed or not enclosed. Enclosed
incinerators have single or multiple chambers; inspection
procedures are similar to those for commercial/industrial units,
Some unenclosed units, such as those for drum reclamation,
utilize an open-ended tunnel. Inspection procedures for such
units are listed below:
0 Observe the plume before entering the incinerator.
0 Calculate or estimate design parameters and compare
with values in Table 10.1 or in permit application.
0 Examine hoods and induced-draft fans. These must-be
large enough to prevent combustion products from
escaping ends of tunnel.
0 Note the clearance between refractory walls and the
reclaimed material. Clearance should be minimal (no
more than 4 inches) to reduce air passage.
0 Suggest installation of air curtains (if needed) to
help prevent the escape of smoke caused by air currents
or wind across the face of the tunnel.
10.2.6 Wood Waste Incinerators
When multiple chamber incinerators are properly used to
burn wood wastes, emissions are minimal. The only difficulty
is the daily startup procedure. Dry clean paper and dry scrap
wood should be charged together. Any warmth retained by the
furnace from the previous day's fire helps to accelerate the
burning rate. As burning proceeds, necessary air adjustments
can be made by observing stack emissions. Grey or white smoke
can be minimized by closing all air ports. When black smoke
appears, the primary air ports and then the secondary air
ports should be opened.
10-7
-------
No auxiliary fuel is needed, since the heating value of
dry wood is high. The heating value of landscape and agri-
cultural field wastes is lower than that of wood wastes,
although they are burned in a "wood waste" incinerator.
They require additional fuel for proper incineration.
10.3 Inspection Forms
Data obtained during an inspection can be summarized
on forms similar to those shown on the following pages.
These forms also serve as a record of inspection.
10.4 Procedures for Estimating Emissions
Table 10.3 lists emission factors for various types
of commercial/industrial incinerators. As indicated by the
range of factors, shown in parentheses, emissions from any
one unit will vary considerably with design and operating
conditions. Thus these factors should be considered as averages
that do not reflect emissions from any one unit.
Collection efficiencies of the various types of control
devices are similar to the values presented in Table 9.
for municipal incinerators. With values for the uncontrolled
emission factor and control efficiency, emissions can be
calculated for the various types of units by the procedure
described in Section 9.5.
10-8
-------
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10-9
-------
INSPECTION CHECKLIST FOR
RESIDENTIAL/APARTMENT HOUSE INCINERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact
Type Incinerator
D Single chamber
D Multiple chamber
Source Code Number
PERMIT FORM STATUS
D Adequate information
D Inadequate information (obtain needed data during first inspection)
(ft PRE ENTRY DATA
Stack Plume
Percent Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation D In Compliance D Not in Compliance
Smoke
D White
D None
D Grey
0 Faint
Odors
GRATE LOADING AND AUXILIARY FUEL REQUIREMENTS
ft =
A. Grate Loading
Grate Area ft x
Number of Apartments Feeding Incinerator
Pounds of Refuse/Day = 10 x No. of Apartments
Loading- Pounds of Refuse/Day
Burning Period(hours/day) x Grate Area
Bo Auxiliary Fuel Requirements
Fuel Rate =
Amount of Refuse Charged
Auxiliary Fuel Requirement =
fr/hr x 1000 =
Fuel Rate
Refuse Charge
D Black or Brown
D Strong
ft
Ib/day
jb/hr-ft"'
_BTU/hr
Tb/hr
BTD/lb waste
Keyed to reference number in Chapter 10.2 .1 .
10-10
-------
GENERAL EQUIPMENT INSPECTION Last
Maintenance
Satisfactory Unsatisfactory Date
Auxiliary Burners Q pj
Grates ^ rj
Combustion Chamber rj Q
Underfire Air Port g p
Overfire Air Port rj Q
Cleanout Door r-j Q
Charging Door Q Q
Chute Doors Q Q
Dampers ^ p
Charging Procedure Q
AIR POLLUTION CONTROL EQUIPMENT
Type
Afterburner
Scrubber
Other - Specify
10-11
-------
INSPECTION CHECKLIST FOR PATHOLOGICAL INCINERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact
Type Incinerator
D Single Chamber
D Multiple Chamber
Source Code Number
PERMIT FORM STATUS
D Adequate Information
d Inadequate Information (Obtain needed data during first inspection)
(P) PRE ENTRY DATA
Stack Plume Percent Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation D In Compliance D Not In Compliance
Stack Plume Ringelmann No. (Circle One) 0 12345
Smoke D White D Grey D Black or Brown
Odors D None D Faint D Strong
HEARTH LOADING
Hearth Area ft x ft = ft2
Estimated Maximum Charge Per Hour Ib/hr
Charge in Ib/hr . 2
= Hearth Area = lb/hr ' *
FINAL CHAMBER TEMPERATURE
Temperature Reading (Indicate Units)
Location of Thermocouple
Keyed to reference number in Chapter 10.2.2.
10-12
-------
T) AUXILIARY FUEL REQUIREMENTS
3. lftnn_ BTU/hr
Fuel Rate = ft A' x 100° ~ ~~~~lb/hr
Amount of Refuse Charged
Fuel Rate ^ BTU/lb waste
Auxiliary Fuel Requirement = Refuse Charge = •
GENERAL EQUIPMENT - FACILITY OBSERVATIONS -MAINTENANCE DATA
Last
Maintenance
Date
•
Item
Preheated Hearth YES
Flame Burner Position
(Directly on charge)
Auxiliary Burners
Hearth
Combustion Chamber
A.r Ports
Dampers
Changing Procedure
AIR POLLUTION CONTROL EQUIPMENT
Type
Afterburner
Other
Specify
•
NO
Satisfactory
a
a
n
a
D
a
D
_
Unsatisfactory
D
D
a
a
D
D
D
10-13
-------
INSPECTION CHECKLIST FOR INDUSTRIAL/COMMERCIAL INCINERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact ~^
Type Incinerator
D Single Chamber
D Multiple Chamber
Source Code Number
PERMIT FORM STATUS
D Adequate information
D Inadequate information (Obtain needed data during first inspection)
(P) PRE ENTRY DATA
Stack Plume Percent Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation D In Compliance D Not In Compliance
Smoke D White D Grey D Black or Brown
Odors O None D Faint D Strong
@ CHARGING PROCEDURE
D Satisfactory D Unsatisfactory
@ REFUSE CLASS (Circle One) 012345
0 GRATE LOADING
2
Grate Area = _ ft x _ ft = _ ft
Estimated Maximum Charge Per Hour = _ Ib/hr
FINAL CHAMBER TEMPERATURE
Temperature Reading _ (Indicate Units)
Location of Thermocouple
Keyed to reference number in Chapter 10,2.3.
10-14
-------
AUXILIARY FUEL REQUIREMENTS (Type 0 and 1 Wastes Excluded)
Fuel Rate = fT/h
Amount of Refuse Charged
Auxiliary Fuel Requirement =
GENERAL EQUIPMENT
Item
Auxiliary Burners
Grates
Combustion Chamber
Air Ports
Dampers
AIR POLLUTION CONTROL
r x 1000 =
Fuel Rate
Refuse Charge
Satisfactory
a
a
a
a
a
EQUIPMENT
Unsatisfactory
D
a
a
D
D
BTU/hr
Ib/hr
BTU/lb waste
Last
Maintenance
Date
Afterburner
Scrubber
Mechanical
Other Specify
10-15
-------
INSPECTION CHECKLIST FOR SEWAGE SLUDGE INCINERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Inspection Date
Person to Contact
Source Code Number
Type of Incinerator
Q Multiple Hearth
D Other
No. of Hearths
Specify
Diam.
ft
PRE ENTRY DATA
Stack Plume
Odors(Specify Area)
Percent Equivalent Opacity (Circle One) 0 20 40 60 80 100
Opacity Regulation
Smoke White
None
None
None
D In Compliance
Grey
Faint
Faint
Faint
HEARTH LOADING
Hearth Area 0.785 x (
Estimated Maximum Charge Per Hour
Loading = Charge in Ib /hr =
) Diam.
Hearth Area
MAXIMUM HEARTH TEMPERATURE
Maximum Temperature Reading
Hearth Stage
AUXILIARY FUEL REQUIREMENTS
Fuel Rate =
Amount of Sludge Charged
Auxiliary Fuel Requirement = Ftjel Rafe
ft /hr x 1000 =
Fuel R
Refuse Charge
D Not In Compliance
Black or Brown
Strong
Strong
Strong
ft
"Ib/hr
Ib/hr - fr
(Indicate Units)
BTU/hr
"lb/hr
BTU/lb waste
Keyed to reference number in Chapter 10.2.4= of text.
10-16
-------
GENERAL EQUIPMENT Last
Maintenance
Item Satisfactory Unsatisfactory Date
Auxiliary Burners r-j Q
Hearths rj Q
Combustion Chamber .-, r-,
AIR POLLUTION CONTROL EQUIPMENT
Type
Afterburner
Scrubber
Mechanical
Other Specify
10-17
-------
References - Chapter 10
1. DeMarco, J. et al. Incinerator Guidelines - 1969. USDHEW,
Bureau of Solid Waste Management. Washington, B.C. PHS
Publication No. 2012. 1969, 98 pages.
2. Compilation of Air Pollutant Emission Factors (Revised).
Environmental Protection Agency. Springfield, Va. NTIS
Publication No. AP-42.
10-18
-------
BIBLIOGRAPHIC DATA
SHEET
1. Report No.
APTD-1449
i. Title and Subtitle
Field Surveillance and Enforcement Guide:
Combustion and Incineration Sources
3- Recipient's Accession No.
5- Report Date
Issue: June 1973
6.
7. Authoi(s)
T.W. Devitt, R.W. Gerstle. N.J. Kulunian
8> Performing Organization Kept.
No.
9. Performing Organization Name and Address
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10. Project/Task/Work Unit No.
11. Contract/Grant No.
68-02-0606
12. Sponsoring Organization Name and Address
Environmental Protection Agency
Office of Air and Water Programs
Research Triangle, Park, North Carolina 27711
13- Type of Report & Period
Covered
Final
14.
15. Supplementary Notes
16. Abstracts
This document presents guidelines for use by state and local air
pollution control agencies in their field surveillance and enforce-
ment activities concerning combustion and incineration emission
sources. The combustion and incineration processes, atmospheric
emissions from these processes, and emission control methods are
described in the initial sections of the report. General guidelines
with respect to emission source inspection are then presented followed
by detailed procedures for inspection of steam-electric plants,
municipal incinerators, and common types of commercial/industrial
incinerators. The types of records that should be kept to facilitate
such inspections are also identified.
17. Key Words and Document Analysis. 17a. Descriptors
Abatement
Enforcement Procedures
Boilers
Incineration
17b. Identifiers/Open-Ended Terms
Air Pollution Control
17c. COSATI Field/Group
18. Availability Statement
Release Unlimited
19, Security Class (This
Report)
. UNCLASSIFIED
20. Security Class (This
Page
1JNCLASS1FIED
21. No. of Pages
22. Price
FORM NTIS-3S (REV. 3-72)
USCOMM-DC H852-P72
-------
INSTRUCTIONS FOR COMPLETING FORM NTIS-35 (10-70) (Bibliographic Data Sheet based on COSATI
Guidelines to Format Standards for Scientific and Technical Reports Prepared by or for the Federal Government,
PB-180 600).
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2. Leave blank.
3. Recipient's Accession Number. Reserved for use by each report recipient.
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FORM NT(S-33 (REV. 3-72) USCOMM-DC 140B2-P72
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