COMBUSTION EVALUATION
IN AIR POLLUTION CONTROL
by
J. Taylor Beard
F. Antonio lachetta
Lenibit U. Lilleleht
ASSOCIATED ENVIRONMENTAL CONSULTANTS
P. O. Box 3863
Charlotfcesville, VA 229O3
Prepared for U.S. Environmental Protection Agency
Under Contract 68-02-2893
EPA PROJECT OFFICER: James 0. Dealy
AIR POLLUTION TRAINING INSTITUTE
U.S. ENVIRONMENTAL PROTECTION AGENCY
MANPOWER AND TECHNICAL INFORMATION BRANCH
)FFICE OF AIR QUALITY PLANNING AND STANDARDS
RFSFARCH TRIANGLE PARK, N.C. 27711
OCTOBER, 1978
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COMBUSTION EVALUATION
IN AIR POLLUTION CONTROL
By
J. Taylor Beard
F. Antonio lachetta
Leuibit U. Lilleleht
ASSOCIATED ENVIRONMENTAL CONSULTANTS
P. 0. Box 3863
Charlottesville, VA 22903
October 1978
Prepared for
PROJECT OFFICER: James 0. Dealy
U. S. ENVIRONMENTAL PROTECTION AGENCY
MANPOWER AND TECHNICAL INFORMATION BRANCH
OFFICE OF AIR QUALITY PLANNING AND STANDARDS
RESEARCH TRIANGLE PARK, N. C. 27711
Contract No. 68-02-2893
TASK III
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TABLE OF CONTENTS
CHAPTER TITLE PAGE
1 Introduction to Combustion Evaluation in
Air Pollution Control 1-1
Appendix 1-1, Instructional Objectives 1-5
2 Fundamentals of Combustion 2-1
3 Fuel Properties 3-1
4 Combustion System Design 4-1
5 Pollution Emission Calculations 5-1
Appendix 5-1, "Compilation of Air Pollution
Control Factors" 5-26
6 Combustion Control and Instrumentation 6-1
7 Gaseous Fuel Burning 7-1
8 Fuel Oil Burning 8-1
9 Coal Burning 9-1
Appendix 9-1, "Corrosion Deposits from
Combustion Gases" by William T. Reid 9-21
10 Solid Waste and Wood Burning 10-1
11 On-Site Incineration of Commercial
and Industrial Waste 11-1
12 Municipal Sewage Sludge 12-1
13 Direct Flame and Catalytic Incineration 13-1
Appendix 13-1, Control of Volatile Organic
Emissions from Existing Stationary
Sources, EPA-450/2-76-028 13-13
iii
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CHAPTER TITLE PAGE
14 Waste Gas Flares 14-1
Appendix 14-1, "Flare Combustion" by
Leonard C. Mandell, P.E. , 14-27
15 Combustion of Hazardous Wastes 15-1
16 NOX Control 16-1
17 Improved Combustion Through
Design Modification 17-1
IV
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CHAPTER 1
INTRODUCTION TO COMBUSTION EVALUATION
IN AIR POLLUTION CONTROL
Air pollution is caused by both natural and mechanical sources. In
urban areas, where ambient air pollution levels are highest, the majority
of the emissions are from stationary and mobile combustion sources. Emis-
sions include particulates and gaseous chemicals which damage both the
public health and the general welfare.
Combustion Evaluation in Air Pollution Control presents the fundamen-
tal and applied aspects of state-of-the-art combustion technology, which
influence the control of air pollutant emissions. Emphasis will be placed
on controlling combustion in order to minimize emissions, rather than on
the well-known combustion gas cleaning techniques (which are adequately
presented elsewhere).
To summarize, the goals of Combustion Evaluation in Air Pollution
Control are to provide engineers, technical and regulatory officials, and
others with knowledge of the fundamental and applied aspects of combus-
tion, as well as an overview of the state-of-the-art of combustion tech-
nology as it relates to air pollution control work.
In order to achieve these goals, emphasis will be on calculations,
as well as design and operational considerations for those combustion
sources and control devices which are frequently encountered, including:
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a. Combustion sources burning fossil fuel for the generation
of steam or direct heat;
b. Combustion sources burning liquid and solid waste; and
c. Pollution control devices which utilize combustion for the
control of gaseous and aerosol pollutants.
Students will become familiar with combustion principles as well as
the more important design and operational parameters influencing air
pollution emissions from typical combustion sources. Further, they will
be able to perform selected fundamental calculations related to the quan-
tities of emissions and the requirements for complete combustion. Parti-
cipants will understand some of the more important mechanisms by which
trace species are formed in and emitted by stationary combustion processes.
The students will understand the ways in which certain design and operation
variables may be set to minimize emissions.
An individual assimilating the knowledge described above will have
the ability to perform work with combustion-related pollution problems:
evaluate actual and potential emissions from combustion sources; perform
engineering inspections; and develop recommendations to improve the per-
formance of malfunctioning combustion equipment.
The detailed instructional objectives, which are presented in Appen-
dix 1-1, are discussed below.
The basic factors affecting the completeness of fuel combustion
(oxygen, time, temperature, and turbulence) are important concepts which
must be understood in any evaluation of combustion. The consequences of
poor combustion include the emission of smoke, particulates, carbon mon-
oxide, and other unoxidized or partially oxidized hydrocarbon gases.
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Fundamental concepts must be considered in the analysis of combus-
tion-related air pollution problems. For example: the temperature of
a fuel oil establishes its viscosity, viscosity (and other design vari-
ables) determines the atomized-droplet size in an oil burner; droplet
size influences evaporation rate, which in turn sets the time require-
ments for complete combustion. Another important consideration is the
formation of NOX, which may be reduced by limiting the excess air in the
combustion zone.
Combustion calculations will be derived from fundamental concepts
of chemistry and thermodynamics. Many computational examples will be
presented, using algebraic equations with tabulated property and standard
factor values. Particular emphasis will be on practical calculations
which are typically required for the review of combustion installations and
to determine compliance with emission standards.
Other important factors used to reduce pollutant emissions are
equipment design and operational characteristics. A physical understand-
ing of these characteristics will be used to determine the corrective
action needed for malfunctioning combustion equipment. Common stationary
combustion sources will be described. These include (a) fuel combustion
equipment for natural gas, fuel oil, coal, and wood; (b) waste gas com-
bustion equipment, including flares, catalytic incinerators, and direct-
flame incinerators; and (c) solid waste combustion equipment designed to
burn garbage, industrial waste gas, municipal sewage sludge, and various
potentially hazardous chemical waste materials.
When these instructional objectives have been successfully accom-
plished, individuals will be (a) familiar with combustion principles,
1-3
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(b) able to perform calculations, (c) able to describe formation of air
pollution from combustion sources, and (d) able to make recommendations
for improving emissions from combustion sources.
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APPENDIX 1-1
INSTRUCTIONAL OBJECTIVES
FOR COMBUSTION EVALUATION IN AIR POLLUTION CONTROL
1. Subject: Introduction to Combustion Evaluation in Air Pollution
Control
Objective: The student will be able to:
a. identify three major goals of Combustion Evaluation in Air
Pollution Control;
b. list four of the subject areas which will be emphasized in the
course (fundamentals of combustion, fuel properties, combus-
tion system design, emission calculations, various combustion
equipment topics, NO^ control);
c. present two reasons for applying the fundamental concepts of
combustion when solving combustion evaluation problems in
air pollution control;
d. list three of the important air pollutant emissions which may
be limited by combustion control.
2. Subject: Fundamentals of Combustion
Objective: The student will be able to:
a. use the basic chemical equations for combustion reactions,
with or without excess air, to calculate air requirements
and amount of combustion products;
b. apply the ideal gas law to determine volumetric relation-
ships for typical combustion situations;
c. distinguish between different types of combustion as char-
acterized by carbonic theory (yellow flame) and hydroxyla-
tion theory (blue flame);
d. define heat of combustion, gross and net heating values,
available heat, hypothetical available heat, sensible heat,
latent heat, and heat content;
e. determine the available heat obtained from burning fuels at
different flue gas exit temperatures and with various amounts
of excess air, using generalized correlations;
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f. list the chemical elements which combine with oxygen when
fuels burn;
g. list the four items necessary for efficient combustion;
h. describe qualitatively the interrelationships between time,
temperature, turbulence, and oxygen required for proper com-
bustion of a given fuel;
i. recite the conditions for equilibrium;
j. describe how an excess quantity of one reactant will affect
other concentrations at equilibrium;
k. cite the expression for the rate of reaction;
1. identify the Arrhenius equation as a model for the influence
of temperature on combustion rate;
m. define the activation energy;
n. describe the mechanism of catalytic activity; and
o. list the reasons for the deterioration of catalytic activity.
3. Subject: Fuel Properties
Objectives: The student will be able to:
a. state the important chemical properties which influence air
pollutant emissions;
b. use the tables in the student manual to find representative
values for given fuel properties;
c. describe the difference in physical features which limit the
rate of combustion for gaseous, liquid, and solid fuels;
d. explain the importance of fuel properties such as flash point
and upper and lower flammability limits which relate to safe
operation of combustion installations;
e. use either specific or API gravity to determine the total
heat of combustion of a fuel oil;
f. describe the influence of variations in fuel oil viscosity
on droplet formation and on completeness of combustion and
emissions;
g. list the important components in the proximate and ultimate
analyses;
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h. define "as fired," "as received," "moisture free," and "dry
basis" as they apply to the chemical analysis of solid fuels;
and
i. explain the significance of ash fusion temperature and caking
index in the burning of coal.
4. Subject: Combustion System Design
Objective: The student should be able to:
a. describe the relationship between energy utilization, furnace
heat transfer, and excess air as means of furnace temperature
control;
b. understand the limits which may be imposed by thermodynamic
laws and how these limits dictate choice of energy-recovery
devices following the furnace; and
c. calculate the energy required from fuel to meet an output
energy requirement.
5. Subject: Pollution Emission Calculations
Objective: The student should be able to:
a. describe the nature and origin of most of the published emis-
sion factors and state what is necessary for more precise
estimates of emissions from a specific installation with
specified design features;
b. apply the proper method for using emission factors to deter-
mine estimates of emissions from typical combustion sources;
c. define and distinguish between concentration standards (Cvs
and C^), pollutant mass rate standards (PMRS) , and process
standards (Es);
d. use average emission factors to estimate the emissions from
typical combustion installations;
e. calculate the degree of control required for a given source
to be brought into compliance with a given emission standard;
f. perform calculations using the relationships between anti-
cipated SO2 emissions and the sulfur content of liquid and
solid fuels;
g. identify the proper equation for computing excess air from
an Orsat analysis of the flue gas of a combustion installa-
tion;
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h. state the reasons for expressing concentrations at standard
conditions of temperature pressure, moisture content, and
excess air;
i. identify and use the proper factors for correcting field
measurements to a standard basis, such as 50% excess air,
12% CO2, and 6% 02; and
j. use F-factors to estimate emissions from a combustion source.
6. Subject: Combustion Control and Instumentation
Objective: The student will be able to:
a. list the important variables (steam pressure, steam flow
rate, gas temperature) which may serve as the controlled
variables used to actuate fuel/air controls for combustion
systems;
b. describe the primary purpose of a control system which is
to maintain combustion efficiency and thermal states;
c. understand the interrelationships between varying load
(energy output) requirements and both fuel/air flow and
excess air;
d. identify instrument readings indicating improper combustion
or energy transfer; and
e. describe the influence of excess air (indicated by 02 in
stack gases) on the boiler efficiency, fuel rate, and eco-
nomics of a particular boiler installation.
7- Subject: Gaseous Fuel Burning
Objective: The student will be able to:
a. describe the functions of the gas burner;
b. define pre-mix and its influence on the type of flame;
c. list burner design features and how these affect the limits
of stable flame operating region;
d. name four different types of gas burners and their special
design features;
e. cite typical gas furnace, breeching and stack operating
temperatures, pressures, and gas flow velocities;
f. describe the relationship between flue gas analyses and the
air-to-fuel ratio;
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g. list the causes and describe the signs of malfunctioning
gas-burning devices; and
h. describe techniques used to correct a malfunctioning gas-
burning device.
8. Subject: Fuel Oil Burning
Objective: The student will be able to:
a. describe the important design and emission characteristics
of oil burners using air, steam, mechanical (pressure), and
rotary-cup atomization;
b. describe the influence of temperature on oil viscosity and
atomization;
c. describe how vanadium and sulfur content in fuel oil influ-
ence furnace corrosion and air pollution emissions;
d. describe burner nozzle maintenance and its influence on air
pollutant emissions from oil combustion installations; and
e. locate and use tabulated values of oil fuel properties and
pollutant factors to compute uncontrolled emissions from
oil-burning sources
9. Subject: Direct-Flame and Catalytic Incineration
Objective: The student will be able to:
a. cite examples of air pollution sources where direct-flame
and catalytic afterburners are used to control gaseous
emissions;
b. describe the influence of temperature on the residence time
required for proper operation of afterburners;
c. apply fundamental combustion calculations to determine the
auxiliary fuel required for direct-flame and catalytic
incineration with and without energy recovery;
d. perform the necessary calculations to determine the proper
physical dimensions of an afterburner for a specific appli-
cation;
e* list three reasons for loss of catalytic activity and ways
Of preventing such loss; and
f. site methods available for reducing afterburner operating
costs.
1-9
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10. Subject: Coal Burning
Objective: The student will be able to:
a. describe the design characteristicj and operating practice
of coal burning equipment, including overfeed, underfeed,
and spreader stokers, as well as pulverized and cyclone fur-
naces;
b. discuss the parameters that influence the design of overfire
and underfire air (in systems which burn coal on grates)
and for primary and secondary air (in systems which burn
coal in suspension);
c. describe the influence of the amount of volatile matter and
fixed carbon in the coal on its proper firing in a given
furnace design; and
d. describe how changing the ash content and the heating value
of coal can influence the combustion as well as the capacity
of a specified steam generator.
11. Subject: Solid Waste and Wood Burning
Objective: The student will be able to:
a. list the important similarities and differences in both the
physical and chemical properties of solid waste, wood waste,
and coal;
b. describe the mechanical configurations required to complete
combustion of solid waste and wood waste and compare with
those for burning coal; and
c. describe the unique combustion characteristics and emissions
from burning unprepared solid waste and refuse-derived fuel.
12. Subject: Controlled-Air Incineration
Objective: The student will be able to:
a. describe the combustion principles and pollution emission
characteristics of controlled-air incinerators contrasted
with those of single and multiple-chamber designs;
b. identify operating features which may cause smoke emission
from controlled-air incinerators; and
c. relate the temperature of gases leaving the afterburner to
the amount of auxiliary fuel needed by the afterburner.
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13. Subject: Combustion of Hazardous Wastes
Objective: The student will be able to:
a. cite special requirements associated with the combustion of
hazardous liquid and solid wastes;
b. recite the special requirements for treating the combustion
products to control pollutant emissions from incineration
operations ;
c. list examples of substances and/or elements which cannot be
controlled by incineration;
d. describe the fuel requirements necessary to dispose hazard-
ous waste materials; and
e. list a number of hazardous waste materials (including poly-
chlorinated biphenyls — PCB ' s — pesticides , and some other
halogenated organics) which may be disposed of successfully
through proper liquid incineration devices; give the required
temperatures and residence times to achieve adequate destruc-
tion.
14. Subject: NOx Control
Objective: The student will be able to:
a. identify three of the major stationary sources of NOX emis-
sions;
b. locate and use emission factors to estimate the amount of
NOX emitted by a potential combustion source;
c. describe the difference between mechanisms for forming
"Thermal NOx" and "Fuel NOX";
d. describe various techniques for NOX control: flue-gas
recirculation, two-stage combustion, excess air control,
catalytic dissociation, wet-scrubbing, water injection, and
reduced fuel burning rate; and
e. state the amount of NOx control available from particular
examples of combustion modification.
15. Subject: Improved Combustion through Design Modification
Objective: The student will be able to:
a. state the benefits of proper maintenance and adjustment of
residential oil-combustion units;
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b. list three important features to check during the main-
tenance of commercial oil-fired burners?
c. discuss the difference between "minimum 02" and "lowest
practical 02" and why these are important in industrial
boilers;
d. list two reasons why a burner may have a higher "minimum
02" level than the typical value; describe what remedies
may be available;
e. indicate the effect of the combustion modification techniques
on thermal efficiency: lowering excess air, staged-air com-
bustion; reduced combustion-air preheat, and flue-gas recir-
culation; and
f. discuss why NOX control from coal-fired utility boilers is
more difficult to achieve than from similar oil or gas units.
16. Subject: Waste Gas Flares (Optional)
Objective: The student will be able to:
a. calculate the carbon-to-hydrogen ratio of a waste-gas stream
and determine when and how much steam will be required for
smokeless-flare operation;
b. understand the difference between elevated and ground-level
flares and the design considerations which underlie the
choice of one or the other; and
c. describe provisions for leveling waste-gas flow rates from
intermittent sources.
17. Subject: Municipal Sewage Sludge Incineration (Optional)
Objective: The student will be able to:
a. list and discuss the air pollutants emitted in incineration
of sewage sludge;
b. describe special design features required to burn wet sew-
age sludge fuel;
c. describe the combustion-related activity occurring in each
of the four zones of the multiple-hearth sewage sludge
incinerators;
d. discuss the options of combustion air preheating, flue gas
reheating, and energy recovery; and
e. list two important operational problems which can adversely
influence air pollution emissions.
1-12
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CHAPTER 2
FUNDAMENTALS OF COMBUSTION
Introduction
Combustion is a chemical reaction. It is the rapid oxidation of com-
bustible substances accompanied by the release of energy (heat and light)
while the -constituent elements are converted to their respective oxides.
The products of complete combustion of hydrocarbon fuels are innocu-
ous carbon dioxide and water vapor. Incomplete combustion, however, can
lead to serious air pollution problems with the emissions of smoke, car-
bon monoxide, and/or other partially oxidized products, and should there-
fore be avoided. Further, should the fuel contain elements such as sulfur
and nitrogen, then the flue gases will contain their respective oxides as
pollutants, even with complete combustion. Chapter 16 describes thermal
NOX and fuel NOX-
To achieve efficient combustion with a minimum of air pollutant emis-
sions, it is essential that the proper amount of air be available to the
combustion chamber and that adequate provision be made for the disposal
of the flue gases. Other factors influencing the completeness of combus-
tion are temperature, time, and turbulence. These are sometimes referred
to as the "three T's of combustion," and need to be given careful considera-
tion when evaluating existing or proposed combustion processes, as well as
designs for new installations.
Each combustible substance has a characteristic minimum ignition tem-
perature which must be attained or exceeded, in the presence of oxygen,
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for the oxidation reaction to proceed at a rate which would qualify it
as combustion. Above the ignition temperature heat is generated at a
higher rate than its losses to the surroundings which makes it possible
to maintain the elevated temperatures necessary for sustained combustion.
Time is a fundamental factor in the design, which influences the
performance of combustion equipment. The residence time of a fuel par-
ticle in the high-temperature region should exceed the time required for
the combustion of that particle to take place. This will therefore set
constraints on the size and shape of the furnace for a desired fuel firing
rate. Since the reaction rate increases with increasing temperature, the
time required for combustion will be less at higher temperatures, thus rais-
ing an economic question for the designer: the smaller the unit, the higher
the temperature must be to oxidize the material in the residence time available.
Turbulence and the resultant mixing of fuel and oxygen are also essen-
tial for efficient combustion processes. Inadequate mixing of combustible
gases and air in the furnace can lead to emissions of incomplete combus-
tion products, even from an otherwise properly sized unit with sufficient
oxygen. Turbulence will speed up the evaporation of liquid fuels for com-
bustion in the vapor phase. In case of solid fuels, turbulence will help
to break up the boundary layer of combustion products formed around the
burning particle which would otherwise cause the slowing down of the combus-
tion rate by decreasing availability of oxygen to the surface reaction.
Proper control of these four factors— oxygen, temperature, time, and
turbulence — are necessary in order to achieve efficient combustion with
a minimum of air pollutant emissions. This chapter will concentrate on
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the combustion fundamentals associated with theoretical air and thermo-
chemical calculations. Gas laws will be applied in determining the
volumetric flow rates of various streams in combustion
processes. The effect of temperature on the reaction rates and equili-
bria will also be discussed in general terms. Subsequent chapters will
discuss the applications of these principles to the burning or oxidation
of specific combustible substances in selected combustion equipment.
Stoichiometric Combustion Air
Oxygen is necessary for combustion. The amount of oxygen required for
complete combustion is known as the Stoichiometric or theoretical oxygen
and is determined by the nature and, of course, the quantity of the com-
bustible material to be burned. With the exception of some exotic fuels,
combustion oxygen is usually obtained from atmospheric air.
Consider a generalized fuel with a chemical formula Cx Hy Sz Ow
where the indices x, y, z, and w represent the relative number of atoms
of carbon, hydrogen, sulfur, and oxygen respectively. Balancing the
chemical reaction for the complete oxidation (combustion) of this fuel
with oxygen from air gives:
Hy Sz O* + (x + J. + z - |) Q2 + gig. (X + J. + z . |) ^ ^
(2.1)
-»• x C02 + | H20 + z S02 + g^|- (x + Z. + z . J.) N2 + Q
where Q represents the heat of combustion.
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The above reaction assumes that:
• air consists of 21% by volume of oxygen with the remaining 79%
made up of nitrogen and other inerts;
• combined oxygen in fuel is available for combustion, thus reduc-
ing air requirements;
• fuel contains no combined nitrogen, so no "fuel NOX" is produced;
• "thermal NOX via the nitrogen fixation is small, so that it is
neglected in stoichiometric air calculations;
• sulfur in fuel is oxidized to SC>2 with negligible SOg formation.
Equation (2.1) relates the reactants on a molar basis. One gram-mole
of a substance is the mass of that substance equal to its molecular weight
in grams. A gram-mole of any substance contains Avogadro's number of
molecules of that substance, i.e. there are 6.02 x 1023 molecules/g-mole.
Pound-moles (Ib-mole) are also in common use. Since one pound-mole is
equivalent to the molecular weight of the substance in pounds, it contains
454 times as many molecules as a gram-mole.
The generalized combustion equation, Equation (2.1) can be converted to a
mass basis simply by multiplying the number of moles of each substance by
its respective molecular weight.
Avogadro's law states:
Equal volumes of different gases at the same pressure and
temperature contain equal numbers of molecules.
Thus it follows that the volumes of gaseous reactants in Equation (2.1) are in
the same ratios as their respective numbers of moles.
The following is an example of the procedure for determining the amount
of stoichiometric (or "theoretical" or "100% total") air for complete
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combustion of methane, CH4, using Eq.(2.1).
Referring to Eq.(2.1), for CH4: x = 1; y - 4; z = w = 0.
Thus balancing the combustion equation gives:
.79 f .
CH4 + 202 + 2 -J^T N2 "*" C02 + 2H2° + 7-53 1
moles or
relative volumes: 1 + ^2 + 7.53 t •*• ^1 + 2 + 7.53
total air flue products
mass: 16 + 64 + 211 -»• 44 + 36 + 211
mass/
combustibles: 1 + 4 + 13.28 -*• 2.75 + 2.25 + 13.28
The above expression gives not only the theoretical air requirements in
terms of moles or volume, Eq.(2.2a), and mass (2.2b, c), but it also per-
mits the determination of the resulting combustion products which the
flue needs to handle.
Attachment 2-1 gives similar results for a number of combustible
compounds in addition to methane. This table also contains other useful
data for combustion calculations, including molecular weights, densities,
specific gravities and volumes, and heats of combustion.
In the case of a pure compound, such as methane in the previous exam-
ple and all substances listed in Attachment 2-1, the x, y, z, and w indices
have integer or zero values in the generalized combustion equation, Eq.(2.1)
More often, however, one is interested in burning fuels which are mixtures
of combustible substances, such as fuel oils and coal for example. In
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these cases the x, y, etc. indices may take on fractional values and
the general chemical formula is indicative only of the relative abun-
dance of the atomic species rather than of any exact molecular architec-
ture. However, Eq. (2.1) could still be used —even with non-integer
coefficients. 15ie indices in the chemical formula for a mixture can be
obtained from its ultimate chemical analy&is by dividing the percent (by
weight) of composition of each of the constituent elements by their respec-
tive atomip weights. After having thus established the formula for the
fuel, one could then apply Eq.(2.1) to make the desired combustion cal-
culations .
It is often easier, however, to incorporate the conversion from the
ultimate analysis to the chemical formula of the fuel into a general ex-
pression which gives the amount of air required. One such expression
frequently used with solid and liquid fuels is:
Ma t = 11.53 C + 34.34 (H2 - i O2) + 4.29 S (2.3)
where MA t is the mass of stoichiometric air per unit mass of fuel, and C,
H2, C>2, and S now represent the weight fractions, i.e. percent/100, of
carbon, hydrogen, oxygen, and sulfur in the fuel, respectively. Note that
the numerical coefficients in Eq.(2.3) are the same as the mass (pounds)
of air per mass (pounds) of combustibles for the corresponding elements
in Attachment 2-1.
For mixtures of gaseous fuels it is easier to compute the amount of
air required for each of the constituent compounds, e.g. methane, ethane
ethylene, etc. directly, using the constants from Attachment 2-1, and then
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adding them to get the total. Further, as the analyses of gaseous fuels
are usually available on a volumetric basis, the volume rather than mass
of stoichiometric air is of the most interest. Thus, for a unit volume of
gaseous fuel, say 1 scf (standard cubic foot), the volume of theoretical
air, VA t, also in standard CU. ft., is:
vA,t = 2-38 (co + H2> + 9-53 CH4 + 16-68 C2H6 + 14-29 C2H4
(2.4)
+ 11.91 C2H2 + + 7.15 H2S - 4.76 O2
where the molecular symbols now represent the volume fractions of the indi-
cated components, and the numerical coefficients are again found in Attach-
ment 2^1, but this time from the "mole per mole of combustibles or cu. ft.
per cu. ft. combustibles" column. Should the gas mixture contain other
combustible substances not already included in Eq.(2.4), these can be added
similarly. Absence of a substance means that its volume fraction
*
is zero and that term will drop out of Eq.(2.4).
The products of complete combustion are C02, H20, SO2, and N2 from
combustion air. The quantities of these can also be determined with the
help of Attachment 2-1. For example, the mass of flue products produced
per unit mass of any fuel burned is:
M-y» = 3.66 C
2
MH o = 8.94 H2 + H20*
(2.5)
Mcr. = 2.00 S
S02
M., = 8.86 C + 26.41 (H9 O-) + 3.29 S + N **
N2 4 Q 2 2
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where the atomic and molecular symbols once again represent the weight frac-
tion of the respective constituents in the fuel, and:
H20* is the weight fraction of water in the fuel as
moisture, and
N2** is the weight fraction of N in the fuel as nitrogen.
Note also that any moisture in the combustion air needs to be added to the
theoretical combustion products from Eq.(2.5) to obtain the total flue gas
stream for complete combustion with theoretical air.
Volumetric Relations for Gases and Vapors
It is often necessary to find the volume of a gas or a gas mixture
at different conditions of temperature and pressure. The volume of an
ideal or perfect gas has been found to be directly proportional to its
absolute temperature, T, and inversely proportional to the absolute pres-
sure, p.
V T
v* - n " R F (2'6)
where v* is the molar volume,and V the total volume of n moles of the gas.
The coefficient of proportionality, R, is the universal gas constant, and
is identical for all ideal gases. The numerical value of R does, however,
vary depending on the units used for other quantities in the ideal gas
law, Eq.(2.6). Values of R for some more frequently used sets of units
are listed in Attachment 2-2.
2-8
-------
According to Eq. (2.6), one mole of any ideal gas occupies the same
volume at the same pressure and temperature. Thus a comparison of
volumes at identical, often standardized, conditions is useful as an indi-
cator of the relative numbers of molecules or moles involved. Molar
volumes of ideal gases at several such "standard" conditions are given in
Attachment 2-3. The ideal gas law, Eq. (2.6), is quite adequate for the
gas phase pressure-volume-temperature relations in most combustion pro-
cesses. Significant deviations from such ideal behavior begin to appear
only at pressures much higher than are encountered in most combustion
installations.
Since most combustion processes take place at essentially constant
pressure, normally close to one atmosphere, the volume of gases at some
other temperatures can be calculated using Charles' law:
Vl ' V0
T0
Note that one needs to use absolute temperatures, either degrees Rankine
(°F + 460) or Kelvin (°C + 273.15) in Eq.(2.7). Charles' law is merely
a special application of the ideal gas law by taking the ratio of Eq.(2.6)
written at conditions 0 and 1 for a fixed amount of gas (nQ = n,)
at constant pressure (pg = p,).
Boyle's law, Eq.(2.8), relates the volume to pressure at constant
temperature (TQ = T^) and amount of gas (HQ = n,), and can also be
obtained from Eq.(2.6).
P0
Vn
o PI
2-9
-------
Charles' and Boyle's laws are more convenient to use than the ideal gas
law if there is only one variable affecting a change in volume, i.e.
temperature or pressure, respectively.
Partial pressure of the i-th component, p^, of a mixture is the
pressure exerted by that component if it were to occupy alone the same
volume as the mixture at the same temperature. Dal ton's law states that
the total pressure, p, exerted by a mixture is the sum of the partial
pressures of each of its components:
P = I Pi = PA + PB + PC + .....
where Pi = j_ n
Flammability Characteristics of Gases and Vapors
A homogeneous mixture of a combustible gas and air is said to be flam-
mable if it can propagate a flame. Flammability is limited to a
finite range of compositions, even when the mixture is subjected to an
ignition source or to elevated temperatures. This limit at the more dilute
mixture of combustibles is known as the lower flammability or explosive
limit (LEL) , while the limit at the more concentrated (combustible-rich
limit) end of the flammable range is the upper flammability or explosive
limit (UEL).
At concentrations below LEL the localized heat release rate of the
oxidation reaction at the ignition source is lower than the rate at which
heat is dissipated to the surroundings, and therefore it is not possible
to maintain high enough temperature which is required for flame propagation
2-10
-------
or sustained combustion. Above the upper flanoiability limit, there is
less than the necessary amount of oxygen,with the result that the flame
does not propagate due to the local depletion of oxygen, thus causing the tem-
perature, and hence the oxidation rate, to drop below the levels required
for sustained combustion.
The rate of flame propagation in combustible mixtures covers a wide
range as it depends on a number of factors including the nature of the
combustible substance, mixture composition, temperature, and pressure.
For a given substance the flame propagation rate is maximum at or near
the stoichiometric mixture composition, and drops off to zero at the upper
and lower explosive limits.
Attachment 2-4 is typical of the effect of temperature on the limits
of flammability. Here TL is defined as the lowest temperature at which
a liquid combustible has vapor pressure high enough to produce a vapor-
air mixture within the flammability range (at LEL). The autoignition
temperature (AIT) on the other hand, is the lowest temperature at which
a uniformly heated mixture will ignite spontaneously. These quantities
are summarized for selected combustible substances in Attachment 2-5.
Good sources of such data for a large number of different gases and vapors
are Bureau of Mines Bulletins 503 and 627 (2, 3).
Thermochemical Relations
Combustion reaction, with its release of heat and light, is referred to
as an exothermic reaction. Energy,which is released as the result of re-
arranging chemical bonds, can be utilized for power generation, space
heating, drying, or for air pollution abatement, just to mention a few
2-11
-------
applications. Thermochemical calculations, which are the subjects of the
next several sections of this chapter, are concerned with the heat effects
associated with combustion. These calculations permit determination of the
energy released by burning a specific fuel. Only a part of this heat will
be available for useful work, however.
Each combustion installation has heat losses, some of which can be
controlled to a certain extent, and others over which there is little or no
control. The avoidable heat losses are those which can be minimized by
good design and careful operation. They will be discussed in subsequent chap-
ters. The efficiency of a combustion installation reflects how well the
designer succeeded in this respect. The percent efficiency is defined as
100 minus the sum of all losses,expressed as percent of the energy input
from the fuel.
In order to make efficiency as well as other thennochemical cal-
culations, one needs to be able to determine the fuel heating values, heat
contents of entering and leaving streams, and any other heat losses. Since
rather specialized terminology is involved, a definition of terms
is in order to avoid confusion and ambiguities later.
Heat of Combustion — Heat energy evolved from the union of a combus-
tible substance with oxygen to form CO2, H2O (and SO2> as the
end products, with both the reactants starting, and the products
ending at the same conditions, usually 25°C and 1 atm.
Gross or Higher Heating Value — HVG or HHV — The quantity of heat
evolved as determined by a calorimeter where the combustion
products are cooled to 60°F and all water vapor condensed to
liquid. Usually expressed in terms of Btu/lb or Btu/scf.
2-12
-------
Net or Lower Heating Value — HVN or LHV— Similar to the higher heat-
ing value except that the water produced by the combustion is not
condensed but retained as vapor at 60°F. Expressed in the same units
as the gross heating value.
Enthalpy or Heat Content — Total heat content, expressed in Btu/lb,
above a standard reference condition.
Sensible Heat — Heat, the addition or removal of which results in
a change of temperature.
Latent Heat — Heat effect associated with a change of phase, e.g.
from liquid to vapor (vaporization), or from liquid to solid
(fusion), etc., without a change in temperature. Expressed usually
as Btu/lb.
Available Heat — The quantity of heat available for intended (useful)
purposes. The difference between the gross heat input to a com-
bustion chamber and all the losses.
According to a heat balance, energy outflow from a system and accumu-
lation within the system equals the energy input to the system. For steady-
state operations the accumulation term is zero. Therefore:
Heat In (sensible + HHV) = Heat Out (sensible + latent + available) (2.10)
Attachment 2-6 illustrates the various quantities in the heat balance
and their interrelations. The length of each bar (Parts 2-6.b, d) repre-
sent the heat content of the respective stream or streams. Part 2-6.c of
Attachment 2-6 gives the same information as Parts 2-6.b and 2-6.d, but
recognizes in addition that the heat contents (enthalpies) are functions
2-13
-------
of temperature. The sensible heat content of fuel and air, above the 60°F
enthalpy reference level, needs to be added to the gross heating value on
the input side. The amount added will depend, of course, on the tempera-
tures of these streams and could in fact be negative, if any of them enter
at temperatures below 60°F.
Flue losses are made up of sensible and latent heat contributions
and are also dependent on the temperature. The higher the flue gas tem-
perature, the higher these losses are, and the less heat remains for useful
work. Conversely, the extraction of heat from the system, presumably for
some useful purpose, decreases the stack gas heat content and improves
the heat utilization efficiency of the operation. Stack gas temperature
should not be allowed, however, to drop below the level where condensation
will appear (to avoid corrosion problems).
An estimate of the adiabatic flame temperature is obtained from
Attachment 2-6.c by extending the combustion products temperature vs.
enthalpy curve until no heat is extracted (Available Heat = 0). The
actual adiabatic temperature will not be as high, though, since (a) com-
bustion is not instantaneous and some heat losses to the surroundings are
likely to occur, and (b) at temperatures above about 3,000°F some CO2
and H_0 will begin to dissociate absorbing some heat. Note that pre-
heating fuel and combustion air permits the generation of higher tem-
peratures in the combustion chamber or higher amounts of heat available
for useful purposes at the same exit gas temperature levels.
Further, some of the hottest flames available are obtained by the
use of oxygen instead of air. The oxy-acetylene torch can reach 5,600°F,
oxy-hydrogen torch 6,800°F, and oxy-atomic hydrogen torch about 10,000°F,
2-14
-------
all because of the absence of flue gas nitrogen heat losses.
The Attachment 2-6 is rather idealized and should be used only in a
qualitative sense. For example, no radiation or conduction (through fur-
nace walls) is considered. The boundary between the sensible and latent •
heat contributions cannot be segregated as sharply as indicated — conden-
sation will occur over a range of temperatures. Thus, in a real system
the dashed curve may be more representative of the true situation. Also,
the increasing heat contents are not always linear with temperature as
shown. The reciprocal of the slope of these lines is proportional to the
specific heats which are known to be functions of temperature.
Let us now compute the flue gas losses by determining the heat con-
tent of exiting combustion products. Consider a general case where the
stack gases are made up of n components, the quantities of each, m^,
having been determined earlier in this chapter.
The total mass flow rate of the stack gases mtot (Ib/hr) is:
• • • • . 5 .
mtot = m^ + m2 + . . . + m^ + . . . + mn = £ mi (2.11)
Assuming no latent heat effects (no phase changes), the enthalpy of each
component h. (Btu/lb) at temperature T2 is:
hi = Cp, i (T2 " V
where C_ j = specific heat of i-th component, Btu/lb°F and
p» j-
TQ = reference temperature for enthalpy (h = 0 at T = T ), °F
2-15
-------
Enthalpies at various temperatures can be calculated by Equation (2.12)
if the specific heat data are available, or they could be obtained
from Attachment 2-7, which gives the enthalpies for a number of gases of
interest in combustion calculations. Heat contents at intermediate tem-
peratures can be obtained by linear interpolation.
Enthalpy of a mixture, 1%^ (Btu/lb) , at T2 is then:
n n
"mix - .1 xi hi - .1 *i cp, i (2'141
The sensible heat input by air and fuel can be calculated by an equation
analogous to Eq.(2.14) and is:
, air
= I "j cp, j (2.15)
where T^ is the fuel and air inlet temperature, and the subscript j
represents input components.
2-16
-------
With the higher (gross) heating value of the fuel, £>„ (Btu/lb fuel),
£1
the available heat, QA (Btu/hr), from this installation will be:
2 A = "fuel QH + *fuel, air " <*flue losses (2'16)
Note again that the above has not included any radiation or conduction
losses. Should these occur, they need to be substracted from the right
side of Equation (2.16).
These calculations have already been performed for different types
of fuels, and the results presented in tabular or graphical .form to
facilitate the design or the evaluation of a combustion process. Curves
in Attachment 2-8 show the available heat (if the hydrogen to carbon ratio
in the fuel is known) for a complete combustion of various fuels with
stoichiometric air and fuel input at 60°F. These curves serve as a
generalized comparison for all hydrocarbon fuels.
Curves in Attachment 2-9 would be preferred should data for specific
fuels be available. Attachment 2-10 is still another generalization for
hydrocarbon fuels giving the available heat as a percent of the gross
heating value and various amounts of excess combustion air. Note that
this chart is only approximate since it is based on the assumption that
the combustion air required per gross Btu heating value is the same for
all fuels.
Attachment 2-11 relates the various combustion losses to the air-to-
fuel ratio. With perfect mixing, one would expect a minimum in total
losses at the stoichiometrically correct air/fuel ratio. As a result of
a less than perfect mixing, however, the minimum total loss occurs
2-17
-------
at higher air/fuel ratios (excess air). The exact location of this mini-
mum depends not only on the degree of mixing of the fuel and combustion
air, but also on the characteristic burning rate of the particular fuel.
Recommended excess air quantities for an optimal combustion efficiency
from the heat utilization point of view will be discussed under the
respective fuels burning chapters.
Reaction Equilibrium and Kinetics
The following is a qualitative discussion of the chemical reaction
equilibrium and kinetics in an attempt to clarify the roles which con-
centrations and temperature play in combustion processes. Much has been
written on the subject with most of the more recent work by chemists at a
level too sophisticated for the purpose here. There are, however, quite
readable discussions available, among them a book by J. B. Edwards (5).
Chemical reactions are seldom as simple and complete as was implied
by the general combustion reaction Eq.(2.1). All reactions are considered
to be reversible to some extent. How far a reaction proceeds depends on
the relative rates of the forward and reverse reactions. Consider a reac-
tion where reactants A and B form products C and D:
A + B + C + D (2.17)
From the law of mass action, the rates of reactions are proportional to
the concentrations of reactants. Hence the forward rate, rf, is:
rf = kf [A] [B] (2.18)
2-18
-------
and the reverse rate;
rr = kr [C] [D] (2.19)
where the k's represent the reaction velocity constants, and the square
brackets the concentration of the respective species.
At equilibrium the forward and reverse rate are necessarily equal. Thus:
kf [A] [B] = kr [c] [D] (2.20)
It is now convenient to define an equilibrium constant K:
v _ kf _ Cc] CD]
r .,- - -
[A] [B]
(2.21)
The equilibrium constant, K, is a function of temperature through the tem-
perature effect on the reaction velocity constants kf and kr. Note that
if it were desired to reduce the concentration of one of the reactants, say
reactant A for example, this could be accomplished by increasing the con-
centration of B. This is exactly the rationale for using excess air to
assure complete combustion of the fuel.
It is common knowledge that some reactions proceed faster than others.
The reaction rates depend on the chemical bonding in the materials. Enough
energy must be supplied to break the chemical bonds in the fuel and in
the molecular oxygen before new bonds can be formed. It is convenient to
think of this energy as elevating the reactants to a new higher energy
state, called the transition state, where an activated but unstable complex
2-19
-------
is formed from the reactants. This complex can break up into new products
or go back to the initial reactants. Such a model of a chemical reaction
is illustrated in Attachment 2-12. The energy necessary to raise the
reactant molecules to the transition state is called the activation ener-
gy, AE.
Molecules in any substance are distributed over a spectrum of energies
as indicated on the left side of Attachment 2-12. There are relatively few
molecules at very high and very low energies with the bulk of them at some
intermediate energy state. The area under the distribution curve repre-
sents the total number of molecules in the system. The energy spectrum is
a function of temperature, and shifts to a higher energy level as tempera-
ture increases (e.g., dashed curve at T2). Only these molecules which are
in energy states equal to or higher than the transition state will be able
i
to form the activated complex and eventually the products. The fraction
of molecules which possesses this requisite activation energy is higher
at elevated temperatures, as is apparent by the larger shaded area under
the energy distribution curve at T2 in comparison with that at T^. There-
fore, at higher temperatures one can expect a higher reaction rate. This
temperature effect on the reaction rate can be represented by an Arrhenius-
type relation, as shown in Attachment 2-13. The temperature effect is
exponential and gives a straight line on a semilog plot of k vs. the
reciprocal of the absolute temperature.
The presence of a catalyst increases the reaction rate, but not the
total amount of products obtained, nor the equilibrium concentrations.
Many surface-type catalysts introduce adsorption/desorption steps into
the overall reaction sequence, as shown in Attachment 2-14. The net effect
2-20
-------
of these steps is an apparent lowering of the effective activation energy.
This makes it possible for a larger fraction of reactant molecules to
reach the transition state with the result that the reaction rate will in-
crease. The bottom half of Attachment 2-14 illustrates how a catalyst
increases the reaction rate through an increased k-value at constant tern-
j
perature, or that the same rate could be obtained with catalyst at a
higher 1/T (or lower absolute temperature, T).
Practical applications of the above are found in the catalytic inci-
neration of combustible gases and vapors discussed in Chapter 13. Tem-
peratures and residence times required for catalytic oxidation are much
lower (see page 13-29) than those required by thermal afterburners (see
page 13-17).
Summation
Insufficient air will result in incomplete combustion with emissions
of pollutants such as carbon monoxide, solid carbon particulates in the
form of smoke or soot, and unburned and/or partially oxidized hydrocarbons.
Burning carbon with insufficient oxygen can produce CO:
C + j 02 •*• CO (2.22)
With additional oxygen the carbon monoxide can be converted to CO :
CO + J °2 •"*" C02 (2.23)
Even gaseous fuels, such as methane, could produce pollutants when
burned with too little oxygen:
2-21
-------
CH4 + °2 - C (solid) + 2 H20 (2'24)
The solid carbon particles can agglomerate resulting in smoke and soot.
Somewhat more oxygen, but still less than theoretical, could lead to car-
bon monoxide formation by the following reaction:
CH4 + 02 •*• CO + 2 H20 (2.25)
Reactions similar to those represented by Equations (2.22) and (2.25) can
occur in the presence of adequate air if: (a) the oxygen is not readily
available for the burning process, as a result of inadequate mixing or turbu-
lence, (b) the flame is chilled too rapidly, and/or (c) the residence time
is too short. These "3 T's of Combustion" are all interrelated and need
to be considered carefully in order to achieve efficient combustion with a
minimum of pollutant emissions.
References
1. Steam, Its Generation and Use, 38th Edition, Babcock and Wilcox,
New York (1972).
2. Bureau of Mines Tech. Paper 450 and Bulletin 503.
3. Zabetakis, M. G., "Flammability Characteristics of Combustible
Gases and Vapors," Bureau of Mines, Bulletin 627 (1965).
4. North American Combustion Handbook, North American Manufacturing
Company, Clevelend, Ohio, 1st Edition (1952), 2nd Edition (1978).
5. Edwards, J. B. , Combustion; The Formation and Emission of Trace
Species, Ann Arbor Science Publishers, Ann Arbor, Michigan (1974).
2-22
-------
No. Substance
1 Carbon'
2 Hydrogen
3 Oxygen
4 Nitrogen (atm)
5 Carbon monoxide
6 Carbon dioxide
Paraffin series
7 Methane
8 Ethane
9 Propane
10 n-Butane
11 Isobutane
12 n-Pentane
13 Isopentane
14 Neopentane
15 n-Hexane
Olefin series
16 Ethylene
17 Propylene
18 n-Butene
19 Isobutene
20 n-Pentene
Aromatic series
21 Benzene
22 Toluene
23 Xylene
Miscellaneous gases
24 Acetylene
25 Naphthalene
26 Methyl alcohol
27 Ethyl alcohol
28 Ammonia
29 Sulfur*
30 Hydrogen sulfide
31 Sulfur dioxide
32 Water vapor
33 Air
Molecu- Sp Gr
lar Lb per Cu Ft Air =
Formula Weight Cu Ft per Lb 1.0000
C 12.01 -
H, 2.016 0.0053 187.723 0.0696
0, 32.00 0.0846 11.819 1.1053
Nj 28.01 0.0744 13.443 0.9718
CO 28.01 0.0740 13.506 0.9672
CO, 44.01 0.1170 8.548 1.5282
CH, 16.04 0.0425 23.552 0.5543
C,H, 30.07 0.0803 12.455 1.0488
C,H. 44.09 0.1196 8.365 1.5617
C,H,0 58.12 0.1582 6.321 2.0665
C,H,0 58.12 0.1582 6.321 2.0665
C,H,, 72.15 0.1904 5.252 2.4872
C,H,, 72.15 0.1904 5.252 2.4872
CjH,, 72.15 0.1904 5.252 2.4872
C.H,, 86.17 0.2274 4.398 2.9704
C,H. 28.05 0.0742 13.475 0.9740
C,H. 42.08 0.1110 9.007 1.4504
C.H. *• 56.10 0.1480 6.756 1.9336
C.H. 56.10 0.1480 6.756 1.9336
C5H,o 70.13 0.1852 5.400 2.4190
C.H. 78.11 0.2060 4.852 2.6920
C,H. 92.13 0.2431 4.113 3.1760
C.H.o 106.16 0.2803 3.567 3.6618
C,H, 26.04 0.0697 14.344 0.9107
C10H. 128.16 0.3384 2.955 4.4208
CH,OH 32.04 0.0846 11.820 1.1052
C,H,OH 46.07 0.1216 8.221 1.5890
NH, 17.03 0.0456 21.914 0.5961
S 32.06 -
H,S 34.08 0.0911 10.979 1.1898
SO, 64.06 0.1733 5.770 2.2640
H,0 18.02 0.0476 21.017 0.6215
0.0766 13.063 1.0000
Heat of Combustion
Btu per Cu Ft Btu per Lb
Gross Net Gross Net
(High) (Low) (High) (Low)
- - 14,093 14,093
325 275 61.095 51,623
_ _ _ _
_ _ _ _
321 321 4.347 4,347
— — — —
1012 911 23,875 21.495
1773 1622 22,323 20,418
2524 2322 21,669 19.937
3271 3018 21.321 19.678
3261 3009 21.271 19.628
4020 3717 21.095 19,507
4011 3708 21.047 19,459
3994 3692 20.978 19,390
4768 4415 20.966 19,415
1604 1503 21,636 20.275
2340 2188 21.048 19.687
3084 2885 20.854 19.493
3069 2868 20.737 19.376
3837 3585 20,720 19,359
3752 3601 18,184 17,451
4486 4285 18,501 17,672
5230 4980 18.650 17.760
1477 1426 21.502 20,769
5854 5654 17,303 16,708
868 767 10,258 9,066
1600 1449 13,161 11,917
441 364 9,667 7,985
- - 3,980 3.980
646 595 7.097 6,537
— — — —
— — — —
— — — —
For 100% Total Air
Moles per mole of Combustible or
Cu Ft per Cu Ft of Combustible
Required
for Combustion Flue Products
O, N, Air CO, H,0 N,
1.0 3.76 4.76 1.0 - 3.76
0.5 1.88 2.38 - 1.0 1.88
_ _ _ _ _ _
_ _ _ _ _ _
0.5 1.88 2.38 1.0 - 1.88
_ _ _ _ _ _
2.0 7.53 9.53 1.0 2.0 7.53
3.5 13.18 16.68 2.0 3.0 13.18
5.0 18.82 23.82 3.0 4.0 18.82
6.5 24.47 30.97 4.0 5.0 24.47
6.5 24.47 30.97 4.0 5.0 24.47
8.0 30.11 38.11 5.0 6.0 30.11
8.0 30.11 38.11 5.0 6.0 30.11
8.0 30.11 38.11 5.0 6.0 30.11
9.5 35.76 45.26 6.0 7.0 35.76
3.0 11.29' 14.29 2.0 2.0 11.29
4.5 16.94 21.44 3.0 3.0 16.94
6.0 22.59 28.59 4.0 4.0 22.59
6.0 22.59 28.59 4.0 4.0 22.59
7.5 28.23 35.73 5.0 5.0 28.23
7.5 28.23 35.73 6.0 3.0 28.23
9.0 33.88 42.88 7.0 4.0 33.88
10.5 39.52 50.02 8.0 5.0 39.52
2.5 9.41 11.91 2.0 1.0 9.41
12.0 45.17 57.17 10.0 4.0 45.17
1.5 5.65 7.15 1.0 2.0 5.65
3.0 11.29 14.29 2.0 3.0 11.29
0.75 2.82 3.57 - 1.5 3.32
SO,
1.0 3.76 4.76 1.0 - 3.76
1.5 5.65 7.15 1.0 1.0 5.65
— — _ _ _ _
— — — — _ _
— — — — — —
For 100% Total Air
Lb per Lb of Combustible
Required
for Combustion Flue Products
0, N, Air CO, H,0 N,
2.66 8.86 11.53 3.66 - 8.86
7.94 26.41 34.34 - 8.94 26.41
— — — — — —
_ _ _ _ _ —
0.57 1.90 2.47 1.57 - 1.90
— — — — — —
3.99 13.28 17.27 2.74 2.25 13.28
3.73 12.39 16.12 2.93 1.80 12.39
3.63 12.07 15.70 2.99 1.63 12.07
3.58 11.91 15.49 3.03 1.55 11.91
3.58 11.91 15.49 3.03 1.55 11.91
3.55 11.81 15.35 3.05 1.50 11.81
3.55 11.81 15.35 3.05 1.50 11.81
3.55 11.81 15.35 3.05 1.50 11.81
3.53 11.74 15.27 3.06 1.46 11.74
3.42 11.39 14.81 3.14 1.29 11.39
3.42 11.39 14.81 3.14 1.29 11.39
3.42 11.39 14.81 3.14 1.29 11.39
3.42 11.39 14.81 3.14 1.29 11.39
3.42 11.39 14.81 3.14 1.29 11.39
3.07 10.22 13.30 3.38 0.69 10.22
3.13 10.40 13.53 3.34 0.78 10.40
3.17 10.53 13.70 3.32 0.85 10.53
3.07 10.22 13.30 3.38 0.69 10.22
3.00 9.97 12.96 3.43 0.56 9.97
1.50 4.98 6.48 1.37 1.13 4.98
2.08 6.93 9.02 1.92 1.17 6.93
1.41 4.69 6.10 - 1.59 5.51
SO,
1.00 329 4.29 2.00 - 3.29
1.41 4.69 6.10 1.88 0.53 4.69
— — — —
— — — — _ _
— — — — _ _
•Carbon and sulfur are considered as gases for molal calculations only.
Note: This table is included by courtesy of the American Gas Association and the Industrial Press. The format and data are
taken principally from "Fuel Flue Gases," 1941 Edition, American Gas Association, with modifications, especially in the
four columns labeled "Heat of Combustion," using data from "Gas Engineers Handbook, The Industrial Press, 1965."
All gas volumes corrected to 60 F and 30 in. Hg dry.
-------
Attachment 2-2, Ideal (Perfect) Gas Law
?v
T
where
P
v*
T
R
absolute pressure
molal volume
absolute temperature
universal gas constant
Selected values of R:
R
1545.33
10.73
0.7302
1.987
82.06
8.315
ft - Ibf
Ib - mole UR
psia - ft3
Ib - mole °R
atm - ft3
Ib - mole °R
cal
g - mole °K
atm - cm3
g - mole °K
Pa - m3
kg - mole °K
2-24
-------
Attachment 2-3, Molar Volumes of Ideal Gases
at Standard Conditions
Standards
Universal
Scientific
Natural Gas
Industry
Temperature
0°C -»• 273.15 K
60°F (520 R)
Pressure
1 atm -»• 1.013 x 10° Pa
30 in. Hg
Molar Volume
22.4 litre/g - mole
2.24 x 10~2 m3/ kg - mole
359 ft3/lb - mole
379 ft3/ Ib - mole
2-25
-------
Attachment 2-4, Temperature Effect on
Limits of Flammability in Air3
Saturated vapor
air mixtures
Mist
Upper
limit
Auto-
ignition
Lower
limit
AIT
TEMPERATURE-
Notes: 1. The flammable region to the left
of the saturated vapor-air mixture
curve contains droplets of the liquid
combustible (mist) suspended in a
vapor-air mixture.
2. A non-flammable mixture (at Point A)
may become flammable if its tempera-
ture is elevated sufficiently (to
Point B) by a localized energy source.
2-26
-------
Attachment 2-5, Limits of Flairanability, Lower Temperature Limits (TL)
and Autoignition Temperatures (AIT) for
Selected Substances
Combustible Formula
Acetylene c?Ho
n-Butane C4H10
Carbon, Fixed C
Charcoal
Bituminous Coal
Semibituminous Coal
Anthracite
Carbon Monoxide CO
Ethane C2H6
Ethyl Alcohol C2H5OH
Ethyl ene C2H4
Gasoline
Hydrogen H2
Hydrogen Sulfide H2S
Jet Fuel (JP-4)
Methane CH4
Methyl Alcohol CH^OH
Propane ^Hg
Sulfur S
(vol
2
1
12
3
3
2
1
4
4
1
5
6
2
2
%) (vol %) (°C)
.5 100
.8 8.4 -72
.5 74
.0 12.4 -130
.3 19
.7 36
.2 7.1
.0 75
.0 44
.3 8
.0 15.0 -187
.7 36
fit
.1 9.5 -102
-0 247
4- •! 1-. 1 A « •£ « « « » _ J_ _ j J .3
AIT
305
405
340
400
465
450 - 600
515
365
490
270 - 440
400
240
540
385
450
and temperature.
2-27
-------
Attachment 2-6, Furnace Heat Balance Relations
Part 2-6.a
IN: Air
Fuel
Furnace
V.
System Boundary
OUT:
Flue Products
Available Heat
Part 2-6.b
Part 2-6.c
Part 2-6.d
OUTPUT
Flue Gas Losses
Latent I Sensible
Available
Heat
1-
Adiabatic Flame Temperature
w
60°F Ref.
r ^ ___ , ^, **rr-m
Flue Gas Temperature
0
I
I
ENTHALPY
INPUT
GROSS HEATING VALUE
Air
&
Fuel
2-28
-------
Attachment 2-7, Heat Contents of Various Gases and Water Vapor4
Temp
°F
60
100
200
500
400
500
600
700
800
900
1000
1200
1400
1600
"1SOO
200ff
2200
2400
2600
2600
3000
3200
3400
3600
Relative heat concent (h) in Btu per pound (at atmospheric pressure)
Oz
0
8.8
30.9
53.3
76.2
99.4
123-1
147.2
171.7
196.6
221.7
272.5
324.3
377.3
430.7
484.0
539.3
594.4
649.0
702.8
N2
0
9-9
34.8
59.9
85.0
110.3
136.1
161.7
187.7
213.9
240.7
294.7
350.8
407.3
465.0
523.8
583.2
642^
702.8
763.1
758.6 824.1
816.4 885.8
873-4 947.6
931.0
1010.3
Air
0
9.6
33.6
57.7
81.8
106.0
130.2
154.5
178.9
203.4
235.0
288.5
343.0
398.0
455.0
513.0
570.7
628.5
687.3
746.6
806.3
866.0
925.9
986.1
CO
0
10.0
34.9
59-9
85.0
110.6
136.3
162.4
188.7
215.6
242.7
297.8
354.3
407.5
465.3
523.8
583.3
643.0
703.2
771.3
832.6
894.0
956.0
1018.3
CO2
0
8.0
29.3
52.0
75.3
99-8
125.1
149.6
177.8
205.6
233.6
290.9
349-7
416.3
470.9
532.8
596.1
659-2
723.2
787.4
852.0
916.7
981.6
1047.3
S02
0
5.9
21.4
37.5
54.4
71.8
89.8
108.2
127.0
146.1
165.5
205.1
245.4
286.4
327.8
369.1
411.1
452.7
495.2
537.5
580.0
622.5
665.0
707.5
H,
0
137
484
832
1182
1532
1882
2233
2584
2935
3291
4007
4729
5460
6198
6952
7717
8490
9272
10060
10870
11680
12510
13330
CH4
0
21.0
76.1
136.4
202.1
272.6
347.8
427.4
511.2
599.2
691.1
886.2
1094.1
1313.0
1542.6
H2O
0
1165
1212
1259
1307
1355
1404
1454
1505
1609
1717
1829
, . .
2-29
-------
Attachment 2-8, Comparison of Pure Hydrocarbon Fuels
in Perfect Combustion4
0.75 0.80. 0.85 0.90 0.95 1.00
POUNDS CARBON / POUND COMBUSTIBLE
O.Vs 0^20 O.'lS o!lO 0.05 0.00
POUNDS HYDROGEN / POUND COMBUSTIBLE
4 5 6 7 8910
CARBON/ HYDROGEN RATIO
oo
2-30
-------
Attachment 2-9, Available Heats for Some Typical Fuels
I I i i I I i I i i I
AVAILABLE HEATS FOR-
SOME TYPICAL FUELS -
300 600 900 1200 1500 1800 2100 2400 2700 3000
FLUE GAS EXIT TEMPERATURE *F
NOTE: Fuels listed above are identified by their gross heating values.
The sum of the moisture loss and" the dry flue gas loss at any parti-
cular exit gas temperature may be evaluated by subtracting the
available heat from the gross heating value. Note that all avail-
able heat figures are based upon perfect combustion and a fuel input
temperature of 60°F- The scales on the left side of this chart are
for the solid curves. The scales on the right are for the dashed
curves.
2-31
-------
Attachment 2-10, Generalized Available Heat Chart for all Fuels
at Various Flue Gas Temperatures and Various
Excess Combustion Air4 (Refer to 60°F)
E"
O> l*
O)
O-
400
x WOO 1400 1800 2200 2600 3000
800 1200 1600 2000 2400 2800 3200
Flue gas temperature *F
This chart is only applicable
to cases in which there is no
unburned fuel in the products
of combustion.
The average temperature of the
hot mixture just beyond the end
of the flame may be read at the
point where the appropriate %
excess air curve intersects the
zero available heat line.
2-32
-------
Attachment 2-11, Variation in Furnace Losses
with Air-to-Fuel Ratio4
Poor Mixing
RADIATION and WALL LOSSES
air deficiency ^ excess ar
chemically correct
AIR-FUEL RATIO
2-33
-------
Attachment 2-12, Rate of Chemical Reac-
REACTANTS -^?
ACTIVATED
COMPLEX
•^T^ PRODUCTS
NO, OF
MOLECULES
C + D
REACTION
COORDINATES
NO, OF
MOLECULES
RATE : R = k
REACT,
VEL, CONST,
k = FUNCTION OF
,,,
2-34
-------
Attachment 2-13, Temperature Effect on Reaction Rate
ARRHENIUS EQUATION:
k - a e
A!
RT
.WHERE; k = REACTION VELOCITY CONSTANT
Q « FREQUENCY FACTOR
AE - ACTIVATION ENERGY
R - GAS CONSTANT
T - ABSOLUTE TEMPERATURE
SLOPE
2,303 R
2-35
-------
Attachment 2-14, Effect of Catalyst on Reaction Rate
ADS
-We + D) ~
ADS * /ADS*"
WITH CATALYST
LOG
2-36
-------
CHAPTER 3
FUEL PROPERTIES
Introduction
This chapter presents the various physical and chemical properties
of fuels used in stationary combustion equipment. The three dominant
fuels are coal, fuel oil, and natural gas; however, there are a number
of other fuels which are important in particular industries and regions.
Fuels typically are classified as solid, liquid, and gaseous fuel.
Gaseous fuels have an advantage, in that their rate of combustion is rapid,
being fundamentally limited by the diffusion or mixing of air (oxygen)
with the gas.
Liquid fuels burn in a gaseous form, therefore the rate of combustion
of liquid fuels is limited by their rate of evaporation (or distillation).
Some liquid fuels are very volatile (vaporize easily) and others, such as
No. 6 fuel oil, require special conditioning.
Solid fuels burning is limited by two phenomena. The volatile matter
fraction of a solid fuel is distilled off and burns as a gas. The remain-
ing fixed-carbon fraction burns as a solid, with the rate of combustion
limited by the diffusion of oxygen to the surface.
Fuel properties are important variables influencing both combustion
design and various operational considerations. Complete combustion, with the
lowest practical amount of excess air (maximum fuel economy) and the lowest
emission of air pollutants, requires control of fuel properties, as well as
other parameters.
3-1
-------
The heating value of fuels may be determined experimentally in de-
vices which operate at either constant volume (bomb calorimeter) or con-
stant pressure (continuous flow gas calorimeter). Because of the possible
loss of energy due to expanding gases, the constant volume values may be
higher than constant pressure values.
The higher heating value (also called the gross heat of combustion,
and the total heat of combustion) is the measured energy release (Btu/lb or
Btu/gal) when products of combustion are cooled to standard temperature and
the water vapor is condensed.
The lower heating value is energy released when products of combus-
tion are cooled to standard temperature, and all water is vapor. This
value is computed from the experimentally determined higher heating value.
The lower flammability (or explosive) limit is the minimum concentra-
tion (% volume) of gases or vapors in air below which flame propagation
will not occur. There is also a maximum limit on concentration of gases
or vapors in air above which flame propagation will not occur. A mixture
between the lower and upper flammability limits will support a flame or
explode! Typical safe practice is to maintain waste gas or vapor concen-
trations at less than 25% of the lower flammability limit. It is important
to provide oxygen-free storage with delivery of the material to a combus-
tion system where oxygen is added and the combustion controlled. The lack
of homogeneity within a mixture can result in localized explosive conditions,
although the average concentration would appear to be safe.
Gaseous Fuels
Gaseous fuels are composed of mixtures of gaseous components as illus-
trated in Attachment 3-1. Natural gas is the typical gaseous fuel burned.
3-2
-------
It has a higher heating value (around 1,000 Btu/scf) which depends on the
chemical composition (or the source). Methane is the primary constituent
of natural gas.
Natural gas is thought of as a sulfur-free fuel. However, as it
comes from the well, natural gas may contain sulfur (mercaptans and hydro-
gen sulfide) and will be "sour." Through a refining process/ the sulfur
products are removed, and the gas is then called "sweet."
Liquefied petroleum gas (LPG) is a group of hydrocarbon materials
which are gaseous under normal atmospheric conditions. However, they nay
be liquefied under moderate pressure (80 to 200 psig). This is a consider-
able advantage in shipping considerations, because the chemical energy stor-
age on a volume basis is considerably increased. LPG is composed of blends
of paraffinic (saturated) hydrocarbons such as propane, isobutane, and nor-
mal butane. These are gases which are derived from natural gas or from
petroleum refinery operations.
Refinery gas is a byproduct blend of gases typically produced in a
petroleum refinery and used for process heating. The heating value and
composition may vary widely, depending on the particular refining process.
Coke oven gas, illustrated in Attachment 3-2, is one of the gaseous
fuels derived from coal. Coke oven gas is given off from bituminous coal
in the coke carbonization process (at high temperatures in the absence of
air). The properties of coke oven gas vary with the coal, temperature,
time, and the other conditions of the operation. Typically coke oven gas
t» '
has heating values which range from 450 to 650 Btu/scf.
Producer gas is derived from the partial oxidation of coal or coke.
Typical heating values range from 140 to 180 Btu/scf.
3-3
-------
Other synthetic gases used in petroleum and metallurgical operations
include carburetted water gas, regenerator waste gas, and blast furnace
gas.
Liquid Fuels
Naturally occurring crude oil, although combustible, is refined into
various petro-chemical products for economic and combustion safety reasons.
In addition to fuel oils, various gasolines, solvents, and chemicals are
produced from distillation, cracking, and reforming processes.
The standard grades of fuel oils for stationary combustion equip-
ment are described in Attachment 3-3. Note that No. 2 fuel oil is the dis-
tillate oil commonly used for domestic heating purposes, and that No. 6
fuel oil (Bunker C) is used primarily in industrial heating and power
generating. Example properties for each grade are in Attachment 3-4.
An important property of fuel oils is specific gravity, the ratio of
the weight of a volume of oil at 60°F to the weight of an equal volume of
water. Specific gravity is important because it provides an indication of
the chemical composition and heating value of the oil. As the hydrogen
content increases, the specific gravity decreases, the combustion energy
released per pound increases, but the energy released per gallon decreases.
For example, refer to Attachment 3-5 and consider a No. 6 fuel oil
having a specific gravity of 0.9861. The total heat of combustion is
18,640 Btu/lb. A No. 2 fuel oil having a specific gravity of 0.8654 would
have 19,490 Btu/lb. The denser fuel oil has a lower hydrogen content
and a smaller heating value on a mass basis. However, on a volume basis
(Btu/gal at 60°F) the No. 6 has a higher value.
3-4
-------
Instead of specific gravity, the API degree scale is commonly used
in oil specifications. It is inversely related to the specific gravity
at 60°F:
Degrees API = - - — - 131.5
sp. gr. @ 60°F
The flash point is an important safety related property. It is the
lowest temperature at which an oil gives off sufficient vapor to cause
a flash or explosion when a flame is brought near the oil surface. The
concern about flash point is illustrated by the fact that No. 6 fuel oil
typically is heated (for pumping or atomizing reasons) to a temperature
(up to 210°F) which is higher than the flash point of a No. 2 fuel oil
(100°F). If a No. 2 oil were placed in the tank for No. 6 oil, and if the
heaters accidentally were not disabled, a serious explosion could occur.
Explosions of this type were recorded when units formerly burning No. 6
were converted, because of air pollution concerns, to burn No. 2.
Viscosity is the measure of a fluid's internal friction or resistance
to flow. As illustrated in Attachment 3-6, viscosity is reduced as the
temperature is increased. Various standard experimental measurement:, tech-
niques have been adopted for viscosity. The Saybolt Universal Scale (SUS)
and Saybolt Furol Scale (SFS) indicate the length of time required for a
given quantity of oil to pass through a particular sized orifice. A sam-
ple of oil at a given temperature will have a lower SFS value than SUS,
because the orifice size of the Furol test is much larger. Note that the
vertical scale of Attachment 3-6 has been made non-linear. This assists
one in approximating the viscosity/ temperature change of a given oil (by
locating a given viscosity /temperature point and projecting a line through
the point, parallel to the sloping lines shown).
3-5
-------
If a No. 5 or No. 6 fuel oil has too high a viscosity when it reaches
the atomizer, the droplets formed will be too large.. Incomplete combustion
can occur, because larger drops may not have enough time to burn
because of an inadequate rate of evaporation. The evaporation rate
depends on the total area available, and big drops have much less total
area than would many small drops of an equivalent total mass.
Sulfur in fuel oil is a primary air pollution concern, in that most
of the fuel sulfur becomes S02 which is emitted with the flue gas. Some of
the sulfur, however, may produce acidic emissions which cause dew-point prob-
lems and corrosion of the metal furnace surfaces (economizers, air heaters,
ducts, etc.). Sulfur can be removed from fuel oil by refining operations.
Other trace elements which may be contained in fuel oils are vanadium and
sodium. The influences of these materials on air pollution emissions will
be discussed in Chapter 8.
Diesel fuels classified as ID, 2D, and 4D are very similar to No. 1,
2, and 4 fuel oils respectively, as can be surmised from Attachment 3-7.
In many situations they may be used interchangeably. The main difference
arises from the necessity for greater uniformity in diesel fuels, which is
obtained by specifying cetane rating, sulfur, and ash restrictions for die-
sel operation.
The cetane number is one measure of the auto-ignition quality of fuels
for diesel (compression ignition) engines. Most high-speed diesels require
fuels with cetane values from 50 to 60. Cetane ratings below 40 may cause
exhaust smoke, increased fuel consumption, and loss of power (3).
Smoke and exhaust odor are directly affected by fuel volatility.
The more volatile diesel fuels vaporize rapidly and mix better in the
combustion zone. The distillation temperatures for different fractions
3-6
-------
of the fuel provide an indication of fuel volatility. A low 50% distilla-
tion temperature will prevent smoke, and a low 90% distillation temperature
(e.g. 575°F) will ensure low carbon residuals (3). End point distillation
temperatures less than 700°F are desirable.
Stationary gas turbines are designed for constant speed and opera-
tion and may be designed to burn gas or a distillate fuel oil such as No. 2
or 2D. Larger units are designed to burn heavy residual oils. The major
requirements are for the fuel and products of combustion to be npndepositing
and noncorrosive.
For variable-speed and variable-load gas turbines special fuel speci-
fications are required. Kerosene is the general fuel commonly used for
such applications. It has an endpoint temperature of 572°F (max), a flash
point of 121 (min), and a very low aromatic content. It is similar to the
Jet A and JP-1 fuels, as indicated in Attachment 3-8. Aircraft turbojets
operate at high altitudes with low air temperatures; therefore, fuel freez-
ing, volatility, and boiling temperatures are important requirements (A).
Solid Fuels
Coal is the most abundant energy resource of the USA. Unfortunately,
coal is a fuel which may have high nitrogen, sulfur, and ash content, rela-
tive to other fuels. Control of air pollution emissions from coal may in-
clude the techniques of fuel modification, combustion modification, and
flue gas cleaning.
t»
As illustrated in Attachment 3-9 and 3-10, coal is generally classi-
fied as anthracite, bituminous, subbituminous, or lignite. Anthracite coal
has the highest fixed carbon, and lignite coals have the lowest calorific
value, as shown by example in Attachment 3-11.
3-7
-------
Because the composition and properties of coal are variable, depend-
ing on the source, standard sampling and laboratory procedures have been
established by ASTM.
As illustrated in Attachment 3-12, the ultimate analysis provides the
percentage by weight of elemental carbon, hydrogen, nitrogen, oxygen,
sulfur, and total ash in the coal. The proximate analysis provides the
fractions of a coal sample that are moisture, volatile matter, fixed car-
bon, and ash. In addition, the heating value is typically included.
The above-mentioned coal analysis may be given on an "as received"
basis. However, a "moisture free" or "dry" basis removes the influence of
moisture from the tabulated numbers, thereby removing a variable which
changes with handling and exposure conditions.
Surface moisture is the moisture (percent by weight) of coal which
is removed by drying in air at 18 to 27°F (10 to 15°C) above room tempera-
ture. The "total moisture" includes the surface moisture and the moisture
removed by oven drying at 216 to 230°F (104 to 110°C) for one hour. However,
the "total moisture" does not include water of decomposition (combined water)
and water of hydration, which are part of the volatile matter in the proxi-
mate analysis and part of the hydrogen and oxygen content in the ultimate
analysis.
Volatile matter is the gaseous material driven off when coal is
heated to a standard temperature. It is composed of hydrocarbons and other
gases from distillation and decomposition.
Fixed carbon is the combustible fraction remaining after the vola-
tiles are removed. The ash is the noncombustible residue remaining after
complete combustion of the coal. This is not to be confused with fly ash,
3-8
-------
which is airborn particulate composed of both ash and some combustible
material (carbon).
Sulfur in coal is in both organic and inorganic forms. Inorganic
forms include metal sulfides (pyrite and marcasite) and metal sulfates
(gypsum and barite). About half of the sulfur in coal is in pyritic form
and half is organic. Pyrite is a dense, small crystal which may be re-
moved mechanically by gravimetric techniques. Organic sulfur is more
difficult (expensive) to remove.
Ash-softening temperature is used to identify coal likely to form
clinkers on the fuel bed and slag on boiler tubes and superheaters. A low
ash-fusion temperature is desirable for removal of ash from slagging (wet
bottom) furnaces.
Caking coals have a high agglomerating index and burn poorly on a
grate because they become plastic and fuse together. On the other hand,
free burning coals burn as separate pieces of fuel without agglomerating.
Grindability index measures the ease of pulverizing coal. The free-
swelling index is a measure of the behavior of rapidly heated coal which
provides an indication of the tendency of coal to coke.
Coke is a porous fuel formed by distructive heating of coal in the
absence of air. Attachment 3-13 illustrates the fact that the properties
of coke depend on the coking operational conditions.
Petroleum coke, coal tar (liquid), and coal tar pitch are other by-
product fuels which may be burned in industrial boilers.
Wood is composed mainly of cellulose and water. Wet wood, wood chips,
saw dust, bark, and hogged fuel have a wide range of moisture contents from
4 to 75%, as illustrated in Attachments 3-14 and 3-15. Special drying or
blending may be required for proper combustion of wood wastes.
3-9
-------
Bagasse is fibrous sugar cane stalk (after sugar juices are removed).
Bagasse has high moisture (40 to 60%) and relatively high ash due to silt
picked up in harvesting (see Attachment 3-16).
Municipal solid waste is a fuel often used for production of steam.
Except for the presence of glass and metals, solid waste is very similar to
hogged wood fuel. The composition of municipal wastes vary considerably
(the moisture varies particularly with exposure). Average values of com-
position and analysis are presented in Attachment 3-17.
References
1. Fryling, G. R., Combustion Engineering, revised edition, published
by Combustion Engineering, Inc., 277 Park Avenue, New York 10017 (1966).
2. Steam, Its Generation and Use, 38th Edition, published by Babcock
and Wilcox, 161 East 42nd Street, New York 10017 (1972).
3. Obert, E. F., Internal Combustion Engines and Air Pollution,
Intext Publishers, New York (1973).
4. Taylor, C. F., and Taylor, E. S., The Internal Combustion Engine,
International Textbook Co., Scranton, PA (1966).
5. "Bunkie's Guide to Fuel Oil Specifications," Tech Bulletin No.
68-101, National Oil Fuel Institute, Washington, D.C.
6. Corey, R.C., Principles and Practice of Incineration, Wiley
Interscience, New York (1969).
7. Johnson, A. J., Auth, G. H., Fuels and Combustion Handbook, McGraw
Hill Book Co. (1951).
8. Obert, E. F., Internal Combustion Engines and Air Pollution, 3rd
Edition, Intext Educational Publishers, New York (1973).
3-10
-------
Attachment 3-1, Analyses of Samples of Natural Gas'
Sample No.
Source of Gas
1
Pa.
2
So. Cal.
3
Ohio
4
La.
5
Okla.
Analyses
Constituents, % by vol
Hg Hydrogen
CH4
C2H4
CO
CO2
— — 1.82 — —
Methane 83.40 84.00 93.33 90.00 84.10
Ethylene — — 0.25 — —
Ethane 15.80 14.80 — 5.00 6.70
Carbon monoxide — — 0.45 — —
Carbon dioxide — 0.70 0.22 — 0.80
Nitrogen 0.80 0.50 3.40 5.00 8.40
Oxygen — — 0.35 — —
Hydrogen sulfide — — 0.18 — —
Ultimate, % by wt
S Sulfur — — 0.34 — —
H2 Hydrogen 23.53 23.30 23.20 22.68 20.85
C Carbon 75.25 74.72 69.12 69.26 64.84
N2 Nitrogen 1.22 0.76 5.76 8.06 12.90
O2 Oxygen — 1.22 1.58 — 1.41
Specific gravity (rel to air) 0.636 0.638 0.567 0.600 0.630
Higher heat value
Btu/cu ft @ 60F & 30 in. Hg 1,129 1,116 964 1,002 974
Btu/lb of fuel 23,170 22,904 22,077 21,824 20,160
Reprinted with permission of
Babcock & Wilcox
3-11
-------
Attachment 3-2, Selected Analysis of Gaseous Fuels Derived from Coal2
Analyses, % by vol
H2 Hydrogen
CH4 Methane
C2H4 Ethylene
CO Carbon monoxide
w
C02
Nitrogen
M C02 Carbon dioxide
Coke-oven
gas
47.9%
33.9
5.2
6.1
2.6
3.7
0.6
-
-
0.413
Blast-furnace
gas
2.4%
0.1
-
23.3
14.4
56.4
-
-
3.4
1.015
Carbureted
water gas
34.0%
15.5
4.7
32.0
4.3
6.5
0.7
2.3
-
0.666
Producer
gas
14.0%
3.0
-
27.0
4.5
50.9
0.6
-
-
0.857
O Oxygen
C,Uf Benzene
o b
H20 Water
Specific gravity (relative to air)
Higher heat value — Btu/cu ft
@ 60F & 30 in. Hg 590 - 534 163
@ 80F & 30 in. Hg - 83.8
Reprinted with permission
of Babcock & Wllcox
-------
Attachment 3-3, Detailed Requirements for Fuel Oils1
Grade el Fuel Oil*
f A disliltote oil intended lor vapor- I
.. . 1 iling pol-lype burncri and olher I
I burmn requiring thli grade of 1
I fuel 1
1 A diilillale ail for general purpose 1
No. 2 dameilic healing for uie in burners .•
I nor requiring No. 1 fuel ail 1
f An oil for burner installations noil
No. 4 equipped wilh preheating focil- /
llliei J
(A reiidual-lype oil for burner in-j
No. 5 ilatlalions equipped wilh preheat- .
ting facililiei J
I An oil for uie in burners equipped |
No. * with prehealers permllling a high- ,
(viscosity fuel ' 1
Flash
Point.
F
Min
100 or
legal
100 or
legal
130 or
legal
130 or
legal
ISO
Pour
Point,
F •
Mat
0
20*
20
...
Water
ond
Sediment,
per cent
by
volume
Max
trace
0.10
0.50
1.00
2.00>
Carbon
•eildue
on 10
per cent
oorUmi.
per cent
Man
0.15
0.35
A.h.
per cent
by
weight
Max
0.10
0.1P
Distillation
Temperature!,
f
10 per
cent
Point
Mai
420
i
90 per cent
Point
Mo«
550
640'
Min
540'
f eybell Vttce.lly, >ec
Universal at
(OOF
Man
37.93
125
Furol at
122F
Min ' Max
32.4
45
150
40
300
Min
...
45
Kinematic Vltcollly,
cenllstehet
At 100 F
Max
2.2
(3.6)'
(26.4)
Mm
1.4
(2.0)'
(5.8)
132.1)
At 122 F
Mo«
181)
1638)
Mh
...
t»2)
Grav-
IIV.
deg
API
Min
35
30«
...
Coppei
Strip
Corro-
sion
Ma>
No. I
...
a Recognizing the necessity for low sulfur fuel oils used in connection with heal treatment, nonferrous metal, glosi. ond ceramic furnaces and other special uses, a sulfur requirement may be tpoci-
tled in accordance wilh the following table:
Grade of Fuel Oil
No. 1
No. 2
No. 4
No. 5
No. 6 -..
Sulfur, max. per cent
OJ
1.0
no limit
no limit
no limit
Other sulfur limits may be specified only by mutual agreement between the purchaser ond the seller.
1 It is the Intent of these classifications thai failure to meet any requirement of a given grade does not automatically place on oil In the next lower grade unless in fact it meets all requirements
of the lower grade. . '
* lower or higher pour points may be specified whenever required by conditions of storage or use. However, these specifications shall not require a pour point lower than 0 F under any conditions.
'The 10 per cent distillation temperature point may be specified at 440 F maximum for use in other than atomizing burners.
• When pour point less than 0 F is specified, the minimum viscosity shall be 1.8 cs (32.0 sec, Soyboll Universal) ond the minimum 90 per cent point shall be waived.
1 The amount of water by distillation plus the sediment by extraction shall not exceed 2.00 per cent. The amount of sediment by extraction shaH not exceed 0.50 per cent. A deduction in quantity
shall be made for all water and sediment in excess of 1 .0 per cent.
• In Ike stales of Alaska, Arizona, California, Hawaii, Idaho, Nevada, Oregon, Utah and Washington, a minimum gravity of 28 deg API h permissible
Reprinted with permission
of Combustion Engineering
-------
Attachment 3-4, Typical Analyses and Properties of Fuel Oils1
ft__J»
WfOQV
.
Type
Color
API gravity, 60 f
Specific gravity, 60 '60 f
Ib ptr U.S. gallon, 60 f
Vitcoi., Centistokei, 100 f
Viscos.. Soybolt Univ., 100 F
Viicai., Soyboll Furol, 122 F
Pour point, F
Temp, for pumping, F
Temp, for atomizing, F
Carbon residue, per cent
Sulfur, ptr cent
Oxygen and nitrogen, per cent
Hydrogen, per cent
Carbon, per cent
Sediment and water, per cent
Aih, per cent
Btu per gallon
N. 1
Fuel OH
Oiitillalo
(Kerosene)
Light
40
0.8251
6.870
1.4
31
—
Below zero
Atmospheric
Atmospheric
Trace
0.1
0.2
13.2
86.5
trace
Trace
137,000
No. 2
Fuel Oil
Distillate
Amber
32
0.8654
7.206
2.68
35
—
Below zero
Atmospheric
Atmospheric
Trace
0.4-0.7
0.2
12.7
86.4
Trace
Trace
141,000
No. 4
Fuel Oil
Very Light
Na. 5
Fuel Oil
No. 6
Fuel Oil
light 1
Residual 1 Residual
Black
21
0.9279
7.727
15.0
77
—
10
15 min.
25 min.
2.5
0.4-1.5
0.48
11.9
86.10
0.5 max.
0.02
146,000
Block
17
0.9529
7.935
50.0 ;
232
—
30
35 min.
130
5.0
2.0 max.
0.70
11.7
85.55
1.0 max.
0.05
148,000
Residual
Black
12
0.9861
8.212
360.0
—
170
65
100
200
12:0
2.8 max.
0.92
10.5
85.70
2:0 max.
O.OB
150,000
* Technical information from Humble Oil & Refining Company.
Reprinted with permission
of Combustion Engineering
3-14
-------
Attachment 3-5, Gravities, Densities, and Heats of Combustion of Fuel Oils6
I— • ' : ' '
VALUES FOR 10 TO 49 DEC API, INCLUSIVE. REPRINTED PROM BUREAU OF STANDARDS
MISCELLANEOUS PUBLICATION NO. 97, "THERMAL PROPERTIES OF PETROLEUM PRODUCTS."
GRAVITY AT
60/60 F
DEC
API
5
6
7
8
9
10
11
12
13
14
15
In
17
18
19
20
21
22
23
24
25
20
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
*Wfc
43
44
^*#
45
tw
Aft
*fV
47
~ 1
48
49
SPECIFIC
GRAVITY
1.0366
1.0291
1.0217
1.0143
1.0071
1.0000
0.9930
0.9861
0.9792
0.9725
0.9659
0.9593
0.9529
0.9465
0.9402
0.9340
0.9279
0.9218
0.9159
0.9100
0.9042
0.8984
0.8927
0.8871
0.8816
0.8762
0.8708
0.8654
0.8602
0.855C
0.8498
0.8448
0.8398
0.8348
0.8299
0.8251
0.8203
0 8155
V • U4 *J *J
0.8109
0.8063
o'.8017
o!?972
o'.7927
0.7883
0.7839
DENSITY
AT 60 F
LB PER
GAL
8.643
8.580
8.518
8.457
8.397
8.337
8.279
8.221
8.164
8.108
8.053
7.998
7.944
7.891
7.839
7.787
7.736
7.686
7.636
7.587
7.538
7.490
7.443
7.396
7.350
7.305
7.260
7.215
7.171
7.128
7.085
7.043
7.001
6.960
6.920
6.879
6.839
6.799
6.760
6.722
6.684
6.646
6.609
6.572
6.536
TOTAL HEAT OP COMBUSTION
(At Constant Volume)
BTU
PER LB
18, 250
18,330
18,390
18,440
18,490
18,540
18,590
18,640
18,690
18,740
18,790
18,840
18,890
18,930
18.980
19,020
19,060
19,110
19,150
19,190
19,230
19,270
19,310
19,350
19,380
19,420
19,450
19,490
19,520
19,560
19,590
19,620
19,650
19,680
19,720
19,750
19,780
19,810
19,830
19,860
19,890
19,920
19,940
19,970
20,000
BTU PER
GAL
AT 60 F
157,700
157,300
156, 600
155,900
155,300
154,600
153,900
153,300
152,600
152,000
151,300
150,700
150,000
149,400
148,800
148,100
147,500
146,800
146,200
145,600
145,000
144,300
143,700
143,100
142,500
141,800
141,200
140,600
140,000
139,400
138,800
138,200
137,600
137,000
136,400
135,300
135,200
134,700
134,100
133,500
132,900
132,400
131,900
131,200
130,700
CAL PER G
10, 140
10,180
10,210
10,240
10,270
10,300
10,330
10,360
10,390
10,410
10,440
10,470
10,490
10,520
10,540
10,570
10, 590
10,620
10, 640
10,660
10,680
10,710
10,730
10,750
10,770
10,790
10,810
10,830
10,850
10,860
10,880
10,900
10,920
10,940
10,950
10,970
10,990
11,000
11,020
11,030
11,050
11,070
11,080
11,100
11 110
NET HEAT OF COMBUSTION
(At Constant Pressure)
BTU PER LB
17,290
17,340
17,390
17,440
17,490
17 , 540
17,580
17,620
17,670
17,710
17,750
17,790
17,820
17,860
17,900
17,930
17,960
18,000
18,030
18,070
18, 100
18,130
18,160
18,190
18,220
18,250
18,280
18,310
18,330
18,360
18,390
18,410
18,430
18,460
18,480
18,510
18,530
18,560
18,580
18,600
18,620
18,640
18,660
18.680
18.700
BTU PER
GAL
AT 60 F
149,400
148,800
148,100
147,500
1-16,900
146,200
145,600
144,900
144,200
143,600
142,900
142,300
141,600
140,900
140,300
139,600
139,000
138,300
137,700
137,100
136,400
• 135,800
135,200
134,600
133.900
133.300
132.700
132,100
131,500
130,900
13X),300
129,700
129,100
128,500
127,900
127,300
126,700
126,200
125,600
125,000
124,400
123,900
123,300
122,800
122,200
CAL PER G
9,610
9,650
9,670
9.700
9,720
9,740
9,770
9,790
9,810
9,840
9,860
9,880
9,900
9,920
9,940
9,9oO
9,9UO
10,000
10,020
10,040
10,050
10,070
10. 090
10,110
10,120
10,140
10,150
10,170
10,180
10,200
10,210
10,230
10,240
10,260
10,270
10,280
10,300
10,310
10,320
10,330
10,340
10,360
10,370
10,380
10,390
3-15
-------
Attachment 3-6, Approximate Viscosity of Fuel Oil5
W
o
o
CO
3
CO
60000
30000
18000
12000
7000
4400
3000
2000
1400
1000
750
550
440
340
280
220
(85
145
120
103
90
80
68
60
55
51
48
46
44
sS
S
s
\
\
\
\
\\
s
\
\
>
V,
\
\
\
'
V
\
\
s
x
,
V
\
s
\
Vs
S
\
\
\
s
S
s
\
\
)
7s
\
s.
\
s, i
^
\
s
\
s
S
v
V
\
o
y
\
s.
V
1
\
X
,
\
k
s
f
\
\
\
\
X
\
y
\
\
V
\
\
\
^y
s
\
\
A
\
ss
s
s
\
V
*
v
\
x
\
^>
\
v
s
s
\
\
^^
S
^
S
\
\
'*i
'
\
\
\
\
L
\
\
<\
X;
\
s
\
3
S
S
\
\
\
\
\
\
^
\
\
V
/•
r
O
\
\
\
\
\
^
1
\
\
N
s
f
\
\
s
\
k V
V
\
S
*c
\|
\
*\
\
X
\
^\
\
\
N
?
^
^
V
\
\
I
\
N
s
^
9
\
\
\
\|
\
\
^
o
0
\
N
?.
1
s
\
\
\
\
\
k V
^ ^
\*
Vs
\
\
,
X
\
\
s
X
]*
/.
L '
s
\
\
s
V
N
*0
A
\
\\
^
^
\
X
N
\
<
(
V
SX
\
X
N
•
\
V
X
/•
^
X
X
1
x
>
\
•^
\
\
Jy
^
\
V
N
V
s
— ^
10000
5800
2750
I 700
1080
700
400
300
203
135 CO
102 CO
73 <
57 5
45 o
35 £
30 H
25 <
22
0 20 40 60 80 100 120 140 160 180 200 220 240
TEMPERATURE DEG. F.
3-16
-------
Attachment 3-7, Diesel Fuel Oil Specifications7
Cetane rating min
Hash point, min. "F ,
Hour point, max, "F
Visrnsitv. mm-max. SL sec HM)T
API. mm
ASTM Di-itill.inon. *F. 10 percent, max
C on 10 percent bottoms, percent, mass. . .
Ash, percent, mass
VV ater. sediment, percent vol
Sulfur, percent mass
Diinll.iic Furl Oil,
1
KM)
0
30-34
35
420
550
0.15
Trace
11)
40
KM)
30-34
550
0.15
0.01
Trace
0.50
1
100
21)
33-3H
30
540-640
0.35
0.10
211
40
125
33-45
540-675
0.35
0.02
0.10
1.0
4
130
20
45-1.25
0.10
0.50
41)
30
130
45-125
0.10
0.50
2.0
Rnidiul Furl Oili
5
130
350-750
0.10
l.(K)
6
150
9(X)r9.000
2.00
Attachment 3-8, Aviation Turbine Oils
Kpiluirr-mrn
AS I'M l>li."
Flaih point. "K (min-max)
Frer/mt; point. "K (max)
(Jravitv. API imm-mux}
Vapor pressure. Reid psin (min-max)
Disiillation. *K
IO percent max
20 percent max
.50 pen-nil max
911 percent max
F.P max
Heatini> value, lower. (Blu/lb,,) min. .
Sulfur, (percent by mass) (max)
Smoke point.+ mm (min)
Aromaiics, vol. percent, (max)
Potential qum. m*/IOO ml (max)
Jet A
110-150
-40t
39-51
400
450
550
18.400
0.3
23
20
14
JetB
-60
45-57
0-3
290
370
470
I8.4IX)
0.3
20
14
III) (min)
-76
3.5 (max)
410
490
372
IK..VH)
0.2
20
8
JP-'
-76
50-60
5-7
240
350
470
IH.400
0.4
25
14
Jf-4
-76
45-57
2-3
290
370
47(1
IH.400
0.4
25
14
140 (min).
— 55
36-48
41 HI
550
IK.3(H
0.4
20
25
14
JP-6
-6.5"
37-50
1K.400
0.4
25
14
ClTE-ll
-67
3
200
325
550
0.4
25
14
3-17
-------
Attachment 3-9, United States Coal Reserves by States, 19702
(million tons)
State
Alabama
Alaska
Arkansas
Colorado
Georgia
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Michigan
Missouri
Montana
New Mexico
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wyoming
Other States
Total
Bituminous
13,518
19,415
1,640
62,389
18
139,756
34,779
6,519
18,686
65,958
1,172
205
23,359
2,299
10,760
110
0
41,862
3,299
48
57,533
0
2,652
6,048
32,100
9,712
1,867
102,034
12,699
618
671,055
Sub-
bituminous
0
110,674
0
18,248
0
0
0
0
0
0
0
0
0
131,877
50,715
0
0
0
0
284
0
0
0
0
150
0
4,194
0
103,011
4,057
428,210
Lignite
20
0
350
0
0
0
0
0
0
0
0
0
0
87,525
0
0
350,680
0
0
0
0
2,031
0
6,878
6
0
117
0
0
46
447,647
Anthracite
0
0
430
78
0
0
0
0
0
0
0
0
0
0
4
0
0
0
0
0
12,117
0
0
0
0
335
5
0
0
0
12,969
total
13,538
130^89
2,420
80,715
18
139,756
34,779
6,519
18,686
65,958
1,172
205
23,359
221,701
61,479
110
350,680
41,862
3,299
332
69,650
2,031
2,652
12,926
32,250
10,047
6,183
102,034
120,7l!0
4,721
1,559,881
Source, Bureau of Mines.
Reprinted with permission
of Babcock & Wilcox
3-18
-------
Attachment 3-10,. ASTM Classification of Coals by Rank2
Class
I. Anthracitic
II. Bituminous
III. Subbituminous
IV. Lignitic
Group
1. Mela-anthracite
2. Anthracite
3. Semianthracite«
Fixed Carbon
Limits, %
(Dry, Mineral-
Matter-Free
Basis)
Equal or
Greater
Than
98
92
86
I. Low volatile bituminous coal 78
2. Medium volatile bituminous coal 69
3. High volatile A bituminous coal —
4. High volatile B bituminous coal - —
5. High volatile C bituminous coal —
1. Subbituminous A coal
2. Subbituminous B coal
3. Subbituminous C coal
1. Lignite A
2. Lignite B
—
—
Less
Than
98
92
86
78
69
—
—
Volatile Matter
Limits, %
(Dry, Mineral-
Matter-Free
Basis)
Greater
Than
2
8
14
22
31
—
—
Equal
or Less
Than
2
8
14
22
31
™~ ¥J
—
Calorific Value
* Limits, Btu/lb
(Moist,t>
Mineral-Matter- Agglomerating
Free Basis) Character
Equal or
Greater
Than
—
14,000d
r13,000d
jll.500
\10,500«
10,500
9,500
8,300
6,300
Less
Than
— j-Nonagglomerating
} Commonly
agglomerating*
11,500 Agglomerating
11,500-,
10,500
9,500 J>Nonaggk>merating
8,300
6,300 )
•This classification does not include a few coals, principally non-
banded varieties, which have unusual physical and chemical prop-
erties and which come within the limits of fixed carbon or calorific
value of the high-volatile bituminous and Subbituminous ranks. All
of these coals either contain less than 48% dry, mineral-matter-
free fixed carbon or have more than 15,500 moist, mineral-matter-
free British thermal units per pound.
b Moist refers to coal containing its natural inherent moisture but
not including visible water on the surface of the coal.
"If agglomerating, classify in low-volatile group of the bituminous
class.
d Coals having 69% or more fixed carbon on the dry, mineral-
matter-free basis shall be classified according to fixed carbon,
regardless of calorific value.
»It is recognized that there may be nonagglomerating varieties in
these groups of the bituminous class, and there are notable excep-
tions in high volatile C bituminous group.
Reprinted with permission
of Babcock & Wiled*
3-19
-------
Attachment 3-11, Selected Coal Analysis2
M
O
Coal
Anthracite
Location
Lackawanna Co., PA
Low-Vol. Bituminous McDowell Co., WV
Subbituminous A
Subbituminous C
Lignite A
Moisture
2.5
1.0
High-Vol. Bituminous Westmoreland Co., PA 1.5
Musselshell Co., MT 14.1
Campbell Co., WY 31.0
Mercer Co., ND 37.0
Volatile
Matter
6.2
16.2
30.7
32.2
31.4
37.0
High
Fixed Heating
Carbon Ash Sulfur Value
79.4 11.9 0.60 12,925
77.3 5.1 0.74 14,715
56.6 11.2 1.82 13,325
46.7 7.0 0.43 11,140
32.8 4.8 0.55 8,320
32.2 4.2 0.40 7,255
Reprinted with permission
of Babcock and Wilcox
-------
Attachment 3-12, Example Coal Analyses2
Proximate Analysis
Component
Moisture (Free)
Volatile matter
Fixed carbon
Ash
Total
Heating value,
Btu/lb
Weight, %
2.5
37.6
52.9
7.0
100.0
13,000
Ultimate Analysis
(as received)
Component
Moisture (Free)
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash
Total
Weight, %
Ultimate Analysis
(dry basis)
Component
Weight,
2,5
75.0
5.0
2.3
1.5
6.7
7 n
/ • V
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash
Total
76.9
5.1
2.4
1.5
6.9
7.2
100.0
100.0
Reprinted with permission
of Babcock & Wilcox
-------
Attachment 3-13, Analyses of Typical U.S. Coke, as Fired1
Proximate analysis
per cent
Low temperature coke
Beehive coke
Byproduct coke
High temperature coke breeze
Cos works coke. Horiz. retorts
Vertical retorts
Petroleum coke
Pitch coke
5
2.8
0.5
0.8
12.0
0.8
1.3
1.1
0.3
>l. motter
15.1
1.3
1.4
4.2
1.4
2.5
7.0
1.1
c
•O O
* -O
72 1
86.0
87 1
65.8
88.0
86.3
90.7
97.6
100
11.7
107
18.0
9.8
99
1.2
1 0
0
5
•So
2.8
05
0.8
12.0
0.8
1 3
1.1
0.3
g
JO
u u
74.5
84.4
85.0
66.8
86.8
85.4
90.8
96.6
Ultimate analysis
per cent
c
a
S*
•5
X X
3.2
0.7
0.7
1.2
0.6
1.0
3.2
0.6
1
"""
1.8
1.0
1.0
0.6
0.7
0.7
0.8
OJ
S 1
2 o
O O T.-Z.
6.1
0.5
0.5
0.5
0.2
0.3
.6
.2
.3
.1
.4
2.1 0.8
0.3 07
10.0
11.7
10.7
18.0
9.3
9.9
1.2
1.0
Heating value
Btl> per Ib
j:
X
12600
12527
12690
10200
12820
12770
15060
14097
J
o
12258
12453
12613
9950
12753
12659
14737
14036
3
0 *
S 2
a S.
~ 0
1!
763
805
801
805
807
8!0
773
813
c
s
0 ,t
U 0
20 7
19.3
20.5
20.5
20.1
20.6
114
19.5
20.7
Reprinted with permission
of Combustion Engineering
3-22
-------
Attachment 3-14, Typical Analyses of Wood, Dry1
Ptr nnt by wtight
Heating valu*
Btu per Ib
SOFTWOODS"
Cedar, whit*
Cypress
Fir. Douglas
Hemlock, Western
Pin*, pilch
while
yellow
Redwood
HARDWOODS'*
Ash, whit*
Beech
Birch, whit*
Elm
Hickory
Maple
Oak, black
red
whit*
Poplar
j
a
u u
48.80
54.98
52.3
50.4
59.00
52.55
52.60
53.5
49.73.
51.64
49.77
50.35
49.67
50.64
4878
49.49
50.44
5' 64
D>
1 Ji
ii A ^
6.37 —
6.54 —
6.3 —
5.8 0.1
7.19
6.08 —
7.02 —
5.9 —
6.93 —
6.26 —
6.49 —
6.57 —
6.49 —
6.02
6.09 —
6.62 —
6.59 —
6.26 —
c
V
2
5 6
44.46
38.08
40.5
41.4
32.68
41.25
40.07
40.3
43.04
41.45
43.45
42.34
43.11
41.74
44.98
43.74
42.73
41.45
1
Z Z
—
—
0.1
0.1
—
—
—
0.1
—
—
—
—
—
0.25
—
—
—
—
-S
0.37
0.40
0.8
2.2
1.13
0.12
1.31
0.2
0.30
0.65
0.29-
0.74
0.73
1.35
0.15
0.15
0.24
0.65
j
01
I
8400'
9870*
9050
8620
11320*
8900*
9610*
8840
8920'
8760'
8-.50*
86.0*
8670*
8580
8180'
8690'
8810'
8920'
3
7780
9234
8438
8056
10620
8308
8927
8266
8246
8151
8019
8171
8039
7995
7587
8037
8169
8311
'5 '5
i s
< £
709
712
719
705
702
722
709
707
709
728
714
717
712
719
713
711
713
715
N **
fiJ
20.2
19.5
19.9
204
18.7
20.2
19.2
20.2
19.5
20.1
20.0
19.8
19.9
20.3
20.5
19.9
19.8
20.0
* Calculated from reported higher heating value of kiln-dried wood assumed to contain eight p*r cent
moisture.
"The terms hard and soft wood, contrary to popular conception, have no reference to the actual hard-
ness of the wood. According to the Wood Handbook, prepared by the Forest Products Laboratory of
the U.S. Department of Agriculture, hardwoods belong to the botanical group of trees that are broad
leaved whereas softwoods belong to the group that have needle or scalelike leaves, such as ever-
greens; cypress, larch and tamarack are exceptions.
Reprinted with permission
of Combustion Engineering
Attachment 3-15, Analyses of Hogged Fuels1
Kind of fuel
Western
Hemleck
Devglas
Fir
Pin*
Sawdmt
Moistun
Moisturl
as received
air dried
Per cent
Proximal* analysis, dry fuel
Volatile matter Per cent
Fixed carbon "
Ash "
57.9
7.3
74.2
.»»23'6
* 2.2
35.9
6.3
82.0
17.2
0.8
6.3
79.4
20.1
0.5
Ultimate analysis, dry fuel
Hydrogen Per cent
Carbon "
Nitrogen "
Oxygen "
Sulfur "
Ash
Heating value, dry Btu per Ib
5.8
50.4
0.1
41.4
0.1
2.2
8620
6.3
52.3
0.1
40.5
0
0.8
9050
6.3
51.8
0.1
41.3
0
0.5
9130
Reprinted with permission
of Combustion Engineering
3-23
-------
Attachment 3-16, Typical Analyses of Bagasse
Cuba
Hawaii
Java
Mexico
P.TU
Puerto Rico
Per cent by weight
Carbon
C
43.15
46 20
46.03
47,10
49.00
4421
H dro
H-J
6.00
6.40
6.56
6.08
5.89
631
_
N;
47.95
45.90
45.55
35.30
43.36
47 T2
N't
N;
—
—
0.18
—
—
0 41
Ash
2.90
1.50
1.68
11.32
1.75
1 35
Heating
Value
Btu per Ib
Higher
7985
8160
8631
9140
8380
8386
towef
7402
7538
8043
8543
7807
7773
At ' *
Ib per 10" BID
625
687
651
667
699
623
per cent
21.0
20.3
20.1
19.4
20.5
20.5
Reprinted with permission
of Combustion Engineering
3-24
-------
Attachment 3-17, Composition and Analysis of Average Municipal Waste*
Component
Percent
of All
Refuse
by Weight
Moisture
(percent
by
weight)
Analysis (percent dry weight)
Volatile
Matter
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Noncom-
bustibles*
Calorific
Value
(Btu/lb)
Rubbish, 64%
Paper
Wood
Grass
Brush
Green*
Leaves
Leather
Rubber
Plastics
Oils, paints
Linoleum
Rags
Street
sweepings
Dirt
Unclassified
Garbage
Fats
42.0
2.4
4.0
1.5
1.5
5.0
0.3
..0.8
0.7
0.8
0.1
0.6
3.0
1.0
0.5
10.0
2.0
10.2
20.0
65.0
40.0
62.0
50.0
10.0
1.2
2.0
0.0
2.1
10.0
20.0
3.2
4.0
72.0
0.0
84.6
84.9
—
_
70.3
—
76.2
85.0
_ _
—
65.8
93.6
67.4
21.2
—
53.3
—
43.4
50.5
43.3
42.5
40.3
40.5
60.0
77.7
60.0
66.9
48.1
55.0
34.7
20.6
16.6
Food
45.0
76.7
5.8
6.0
6.0
5.9
5.6
6.0
8.0
10.4
7.2
9.7
5.3
6.6
4.8
2.6
2.5
44
42
41
41
39
45
11
22
5
18
31
35
4
18
.3
.4
.7
.2
.0
.1
.5
.6
.2
.7
.2
.2
.0
.4
0.3
0.2
2.2
2.0
2.0
0.2
10.0
_
__
2.0
0.1
4.6
0.1
0.5
0.05
0.20
0.05
0.05
0.05
0.05
0.05
0.40
2.0
_
—
0.40
0.13
0.20
0.01
0.05
6.0
1.0
6.8
8.3
13.0
8.2
10.1
10.0
10.2
16.3
27.4
2.5
25.0
72.3
62.5
7572
8613
7693
7900
7077
7096
8850
11330
14368
13400
8310
7652
6000
3790
3000
Wastes, 12%
6.4
12.1
Noncombustibles,
Metals
Glass and
ceramics
Ashes
All refuse
8.0
6.0
10.0
100
3.0
2.0
10.0
20.7
0.5
0.4
3.0
—
0.8
0.6
2S.O
Composite
28.0
0.04
0.03
0.5
Refuse, as
3.5
28
11
24%
0
0
0
.8
.2
.2
.1
.8
3.3
0
__
_
—
0.52
0
_
__
0.5
16.0
0
99.0
99.3
70.2
8484
16700
124
65
4172
Received
22
.4
0.33
0.16
24.9
6203
-------
CHAPTER 4
COMBUSTION SYSTEM DESIGN
Introduction
Combustion systems are normally designed for the conversion of fossil
fuels or other combustible substances to forms of energy more suitable
for a particular end use and for the accomplishment of this conversion at
the lowest possible cost. Such systems are many and varied, including
steam electric power plants, industrial boilers for process steam and by-
product electric power, recovery boilers in paper making, and dryers
which use gaseous combustion products for drying veneer and agricultural
crops, to name just a few. Combustion can be used for air pollution abate-
ment, through the use of direct flame and catalytic fume incinerators.
Incineration of solid wastes and wood wastes is a combustion application
where waste disposal has been the primary intent, with energy utilization
a secondary consideration, at least in the past.
The design of a combustion system includes the selection of a fuel
and the hardware in which the energy conversion is to be carried out for
the particular application. Many factors enter into the choice of the
fuel, not the least of which is its availability. The fuel, along with the
method of energy utilization will then influence the type of hardware to
be employed. The design process is a complex one, involving thermodynamics,
fluid mechanics, heat transfer, automatic control theory, and economic
consideration. Thermodynamic principles govern the basic energy release
4-1
-------
and utilization potential for each part as well as the system as a whole.
Fluid mechanics will govern the fuel and gas flows which the system needs
to handle in its various parts. Fans must be sized to overcome the resis-
tance of gas flows at the operating temperatures and pressures. Flow
resistance arises from the dissipation by turbulence, in addition to the
fluid friction at physical boundaries, such as walls of ducts, furnaces,
heat transfer surfaces, and air quality control equipment. All these
equipment pieces must be integrated to produce a system of the most eco-
nomic configuration within the imposed restraints of the desired energy
conversion rate and the environmental quality. The economic considera-
tion includes hardware first-cost, the availability and cost of the fuel,
and other system operating and maintenance costs. Careful consideration
needs to be given to trade-offs between the capital and the operating
costs.
The purpose of this chapter is to develop a design methodology and to
illustrate it with numerical examples where possible. We will not be con-
cerned with the detailed design and sizing of the various parts of the
combustion installation. The following will be emphasized:
a. The importance of establishing the operating temperatures, and
b. Typical methods of heat utilization.
The nomenclature used throughout the chapter is defined in Attach-
ment 4-2.
Design Methodology
Design methodology is essentially a process whereby each of the
several system components is sized and detailed. Against this backdrop
of complexity suggested above, it is reasonable to ask what the flow-diagram
4-2
-------
of the design process looks like. In general terms, such a flow-diagram
might include the following:
a. Determine the quantity and.load characteristics of energy required.
b. Select the kind of fuel or fuels to be burned. Identify
probable sources along with any bulk storage requirements.
c. Determine the combustion air requirements for proper burning
of the selected fuel.
d. Estimate the total gas flows generated by the combustion. This
determination involves several secondary but important aspects.
For example:
1. Thermal efficiency of the unit is determined by mini-
mizing the total of the annual capital and operating
cost. Whether or not to include an economizer will
be determined from an analysis of the return on the
investment.
2. The amount of fuel to be burned and the combustion prod-
ucts generated are determined from the useful energy to
be generated and the efficiency of this conversion process.
e. Determine the required furnace volume and heat transfer areas.
f. Layout the air distribution ducts and the fuel gas breaching.
Size the fans and the stack.
g. Identify and design any apparatus required to either prevent
or abate air pollution problems.
The manner in which the above tasks are carried out is subject to
wide variations from designer to designer. Selected parts of the above-
mentioned design process will be considered in the following sections.
4-3
-------
Furnace
The combustion chamber is a volume where the fuel and air mixture (in
proper proportion) is exposed to an ignition source and burned. The resi-
dence time needed to achieve complete oxidation of the fuel depends on
the temperature maintained in the combustion chamber, commonly referred
to as the furnace. From the temperature effect on the reaction rate (see
Chapter 2), we know that the higher the furnace temperature, the faster
the oxidation reaction and hence the smaller the furnace would need to be.
This size reduction, however, is limited by Charles' Law (see page 2-9).
Adiabatic flame temperatures (see page 2-14), which are the highest
temperatures which may be theoretically attained in the furnace, are for
most fuels considerably higher than the commonly used furnace materials
can tolerate. Uncooled furnace walls constructed of refractory materials
normally require the furnace gas temperatures not to exceed 1,800 to
2,200°F. Furnace temperature control, therefore, takes on primary impor-
tance. This can be accomplished by:
a. Using excess air in amounts great enough to produce desired
temperature;
b. Heat removal across heat transfer surfaces; or
c. Some combination of a. and b.
The following example illustrates the furnace temperature calculation
procedures.
Example 4.1 — Furnace Temperatures
Consider a furnace burning No. 6 fuel oil having a specific gravity
of 0.986; a HHV of 18,640 Btu/lb, and an ultimate analysis of 85.7% C,
10.5% H2, 0.92% 02, 2.8% S, 0.8% ash, and a net heating value, H , of
4-4
-------
17,620 Btu/lb.
Determine;
a. The furnace gas temperature with the following system design
alternatives:
Case 1. Adiabatic combustion (no loss or useful heat trans-
fer) with stoichiometric air;
Case 2. Stoichiometric air, and 5% energy loss from the fur-
nace to the surroundings.
b. Excess air or heat transfer necessary to achieve 2,200°F fur-
nace temperature:
Case 3. Excess air but no heat transfer other than 5% energy
loss;
Case 4. Excess air limited to 10%, 5% energy loss, and heat
transfer is needed to limit the temperature to 2,200°F.
Solution for Case 1;
First we need to determine the amount of stoichiometric (theoretical)
air required for complete combustion. This calculation uses Equation 2.3
(page 2-6).
Afc = 11.53 C + 34.34 (H2 - -p) + 4.29 S 4.1
For the No. 6 fuel oil given here, Equation 4.1 is
A,. = 11.53 (0.857) + 34.34 (0.105 - -^^•) + 4.29 (.028)
u 8
13.57
Ib oil
4-5
-------
When a fuel is burned, mass must be conserved. It is possible then
to predict the mass of combustion gas from the air required and the com-
bustible matter actually burned. The mass of flue gas produced is there-
fore:
mf G = (mf - m^c) + mfAt 4.2
The noncombustibles , m™, , here are either the ash in fuel or the ash
together with the unburned combustible in solid form. Gaseous unburned
components would remain part of the flue gas. With one pound of fuel as
a basis (mf = 1), G for the No. 6 oil specified here becomes:
G = (1 - .008) + (13.57) = 14.56 lb
Ib fuel
The mass of each individual gas in the product can be calculated, and an
average or effective specific heat for the mixture can be computed. A
value applicable to oil combustion gas temperatures is approximately 0.29
Btu/lb F. With this value, one can estimate the adiabatic flame tempera-
ture , t , , from
ad
tad =
where t is the combustion air intake temperature. For the oil under
consideration, t , computed using Equation 4.3 with t = 100°F is
17,620 0
14.57 (0.29) + 10° = 4'27°
4-6
-------
Note that this temperature is considerably greater than the furnace mate-
rials of construction can tolerate. Therefore, Case 1 is not a viable
option.
Solution for Case 2 ;
A second approach involves predicting the gas temperature when the
system has heat transfer losses to the structure and surroundings. Equa-
tion 4.3 must be modified by the loss term, Q , to yield the nonadia-
batic furnace temperature, t^ , as given by
H - QL
t = - + t 4.4
G Cp a
Here, with QT = 0.05 H , the furnace temperature is
j-i
H - -Q5H = °-95 <17'62<" = °
t, = - + t = - ' + 100 = 4,061F
G Cp a (14.57) (0.29)
This gas temperature, while lower than that calculated for the adiabatic
situation (Case 1) , is still too high to be practical.
Solution to Case 3;
The third alternative proposes imposing a limit to the furnace tem-
perature, with a 5% energy loss and no other heat transfer. This can be
realized only through the use of excess air. The quantity of excess air
needed is determined by a calculation of the mass of combustion product
gas, Gf , required to absorb the net heating value of the fuel, H , with
the gases leaving the furnace at the specified temperature (2,200°F). The
gas per pound of fuel is
Gf = (AE + G).
4-7
-------
The applicable energy relationship is given by
H = Gf Cp (tf - ta) + QL 4.5
Now if the tf = 2,200°F condition is imposed on the system and assum-
ing C = 0.29 Btu/lb°F as before G_ can be calculated from
Cp (tf - tjjT 0.29 (2,200 - 100)
The excess air needed to reduce the temperature is then
= Gf - G = 27.49 - 14.57 = 12.92 lb' air or
27.49 Ibs 4.6
Ib fuel
— = (12.92/13.57) x 100% = 95%
AT
This is substantially greater than the excess air normally found necessary
for proper combustion of No. 6 oil.
Solution to Case 4;
The logical next alternative is to limit the temperature by transfer-
ring energy to some useful purpose while limiting the excess air to the
amount required for complete combustion. The governing energy equation
for this case becomes
H = Gf Cp
-------
temperature at tf. Rearranging Equation 4.7:
2u " H - QL - Gf CP 4'8
Recalling that Case 4 prescribes 10% excess air
Ib air Ib air
Gf = G + AJJ where A£ = 0.10 x 13.57 lb fuei • 1-36 ^ fuel
and substituting the appropriate numerical values into Equation 4.8 gives
Qu = 17,620 - 0.05 (17,620) - (14.57 + 1.36) (.29) (2,200 - 100)
= 16,739 - 9,701 = 7,038 Btu/lb fuel
Here 0 represents 39.9% of the net heating value of the fuel. Useful
application of this energy obviously depends upon the primary purpose of
the combustion system. Steam generation would dictate water walls in the
furnace to absorb this energy. Other systems would have to utilize this
energy in some other appropriate manner with the heat transfer surface
and medium compatible with the intended end use.
Summarizing the design process to this point, the primary alterna-
tives for controlling the furnace temperature to use a great deal of
excess air or to use some appropriate heat transfer surface to remove
sufficient energy from the combustion gas to effect a control of tempera-
ture. The use of excess air alone as a control is wasteful of energy and
should be avoided whenever possible. This potentially wasteful aspect is
4-9
-------
is also evident when considering the utilization of the energy remaining
in the combustion products after they leave the furnace.
Energy Utilization in Nonfumace Regions
Further utilization of energy, represented by the elevated tempera-
tures of gases leaving a furnace, has a significant impact on the overall
combustion system thermal efficiency, n , defined as:
n
TI = 1$. 4.9
QH
QH is the energy total input to the system given by
QH = mf HHV
4.10
and Q , the total energy transferred for a useful purpose, is given by
Qs = mf qs = QH - Q 4.11
where qg is the useful energy per pound of fuel.
Losses identified earlier were limited to the energy transferred to
the structure and the surroundings in the furnace, QL . Additional losses
occur in the regions through which the gas must flow upon leaving the fur-
nace. A major loss is due to the heat content of flue gases leaving the
system. This loss-, Of , arises from the fact that the flue gas stack
temperature, tf_ , is higher than ambient and is expressed as
Qfg - Gf cp
-------
Equation 4.12 indicates that Qf is directly proportional to the total
mass of the flue gases, Gf , the specific heat of the gas and the differ-
ence between the flue gas and the ambient. Increasing excess air beyond
that which is required to insure proper combustion, increases Gf which
tends to increase the flue losses. The desirability of reducing the flue
gas temperature, tf , is also apparent. In almost all combustion energy
utilization devices, it is impractical to reduce tf to tg^- Design,
material, and economic factors prevent this and, in fact, dictate limits
for various cases. Flue gas temperatures in steam boilers are limited to
a low of about 250 to 300°F because of the potential dew-point and SOX-
associated corrosion problems which can develop at lower temperatures.
Achieving even these flue gas exit temperatures requires considerable
energy recovery equipment such as economizers and air preheaters.
The overall energy utilization pattern is summarized in Attachment
4-1, and by the following terms of the energy balance relationship.
Input: HHV
Losses: I Qloss = QL + Qfg + Qv
Available (utilized) energy: qs = Qu + QNF
q - HHV-
Note that in terms of the net heating value of the fuel, H , the energy
balance would become
4-11
-------
H = HHV - Q_,
The interaction of these several energy quantities is illustrated by the
next example which presumes a steam boiler where the fuel is already
identified.
Example 4.2 — System Thermal Efficiency
A steam generator is to be designed for firing the No. 6 fuel oil
of Example 4.1. Its rated output is to be 60,000 Ibs/hr output steam at
p = 650 psia, t = 800°F with the feedwater at 320°F.
Determine:
The distribution of the available energy utilization in this steam
generator.
Solution;
The design begins with a determination of Qg for this unit. This
is done by accounting for the energy which is added to the working fluid
(water) as it passes through the unit.
m_ = 60,000 Ib/hr
Fuel,
HHV
800°F
STEAM
GENERATOR
Flue gas
Feed water
320°F
4-12
-------
Letting m represent the steaming rate, Q becomes:
^ s
Qs = ms (h2 - h^ 4.13
where h, and h_ are the enthalpies of the entering feedwater and the
output steam respectively (obtained from steam tables). For this case
Q_ = 60,000 Ibs/hr (1,406.0 - 290.3) = 66.9 x 106 Btu/hr
This is the available useful energy represented by m^ (O^ +
fuel supply rate needed to provide this energy depends on the overall
efficiency, TI , which in turn depends on the energy recovery devices
incorporated into the design. Again, with information developed in
Example 4.1,
HHV - Qv - QL - Qfg = H - QL - Qfg
qs = 17,620 - QL - Qfg 4.14
Suppose that QL can be limited to a maximum of 5% of HHV. Before the
remaining loss term, Q^ , can be determined, it is in order to consider
some of the temperatures in the system.
Gas leaves the furnace at tf =. 2,200 F, while steam leaves the
Steam superheater at t = 800°F, and the
5
Steam boiler temperature tB is = 495°F (saturation temperature
at 650 psia)
4-13
-------
The reason for listing these temperatures is to emphasize the limitations
imposed by thermodynamic and heat transfer considerations. Energy ex-
change by heat transfer requires a temperature difference between the
energy source and the heated medium. The superheater, if located in the
convection zone, might reduce the gas temperature typically from 2,200°F
to say 1,000°F, which will still allow a 200°F temperature difference for
heat transfer requirements. The boiler operating at the 495°F boiling tem-
perature can remove enough energy to bring the gas temperature to about
700°F. These temperatures are practical values, that is, they recognize
the need for a finite temperature difference for heat exchange at realis-
tic rates. In any event, temperatures lower than 800 F for the super-
heater outlet, and 495°F for the boiler cannot be realized even with
infinite heat transfer areas.
If the steam generator design does not include either an economizer
or an air preheater, the gas temperature leaving the system would be
approximately 700°F. For this case the energy loss in the flue gas is
given by
Qfg = Gf Cp (tfg - tamb) = 15.93 (0.25)(700 - 100)
= 2,390 Btu/lb fuel
The useful energy per pound of fuel, q , is calculated by solving Equa-
5
tion 4.14, noting QL = 0.05 (18,640) = 930 Btu/lb
qs = 17,620 - QL - Qf = 17,620 - 930 - 2,390
= 14,300 Btu/lb oil
4-14
-------
The efficiency from Equation 4.9, with Q and QH each based on one
pound of fuel, is
n = 14'298 x 100% = 76.7%
18,640
The fuel firing rate can now be determined noting that the total use-
ful energy, Qg , is 66.9 x 106 Btu/hr and solving for mf from Equa-
tion 4.14:
_ Qs _ 66.9 x 106 Btu/hr _ .-„_ lb oil
— — — 4boU . ——
qs 14,300 Btu hr
lb oil
The specific gravity of this No. 6 fuel oil was specified (Example 4.1)
to be 0.986, therefore a required fuel flow of approximately 569 gal/hr
is indicated.
The efficiency obtainable with a unit which extracts useful energy
only in the furnace water walls, superheater, and boiler is not as
high as could be realized. Continuing the design process, one would
seek means to reduce the flue gas temperature still further, thereby reduc-
ing the flue losses and increasing the thermal efficiency. Recall that
the feedwater temperature was specified to be 320°F. This is 175° lower
than the boiler temperature of 495°F. It would therefore appear to be
possible to insert a heat exchange surface in the flue gas stream to
extract energy by transferring energy to the colder feedwater. Such ex-
change surface is called the economizer, and, with temperatures as hypo-
thesized here, flue gas temperature could be reduced to 500°F. With this
lower flue gas temperature, the flue losses, Qf , would be reduced to
1,590 Btu/lb, a would increase to 15,100 Btu/lb, and the efficiency
5
would increase to 80.0%.
4-15
-------
Continuing the design analysis, one would note the flue gas leaves the
economizer at 500°F and that the ambient air enters at 100°F. Why not preheat
combustion air? A decision to do so or not should, at least in part, be based
upon economics. The additional hardware would have a higher first-
cost and operating cost, which would have to be balanced against the value of
the energy saved. An air preheater could certainly be expected to reduce
flue gas temperatures to 350°F. At 350°F flue gas temperature the loss Qf
is down to 996 Btu/lb.
Now, from Equation 4.14,
qs = 17,620 - 932 - 996 = 15,692 Btu/lb fuel
15,692 OA „
and " = = 84'2%
The fuel firing rate would be
66.9 x 1
5tu =
al
15,692 5tu
Ib fuel
The energy relationships outlined in Examples 4.1 and 4.2 are shown
graphically in Attachment 4-1 which pictorially illustrates the effect of
greater energy utlization.
An over-all summary of how energy utilization influences the design
problem is presented here.
A. Energy utilization determines fuel/air ratio for a given furnace
temperature, since more excess air is used with smaller units.
B. Energy utilization involves
1. Energy absorbed by water walls in the furnace by radiant
exchange ;
2. Energy absorbed by superheater;
3. Energy absorbed by boiler convection surface;
4. Energy absorbed by the economizer; and
5. Energy absorbed by air preheater.
4-16
-------
C. Energy losses involve
1. Stack gas losses;
2. Loss due to heat transfer through structure; and
3. Loss due to incomplete combustion.
D. A given design is based on a fuel selection as to ultimate
analysis, energy content and ash, if any.
System control, to be discussed in a later chapter, must provide for
a suitable working range for output and for variations of fuel composition
and energy. Drastic changes in any part of a system can substantially
alter energy performance or require major modification to avoid loss of
performance. Fuel property changes can have some effect since initial
design is based on fuel choice.
With the preliminary energy transfer considerations completed as out-
lined above, various heat transfer calculations are made to design the actual
surface configurations. Gas flows, both air and flue gases, together
with fluid flow considerations, can be used to establish fan size require-
ments. A system obviously has many details which have not been displayed
here but they are details influenced by the economics of energy utilization.
References
1. Steam, Its Generation and Use, 38th Edition, published by Babcock
and Wilcox, 161 East 42nd Street, New York, New York, 10017 (1972).
2. Reynolds, W. C. and Perkins, H. C. , Engineering Thermodynamics,
McGraw-Hill, Inc., New York (1977).
3. Morse, F. T., Power Plant Engineering, D. Van Nostrand, Inc.,
New York, 1953.
4-17
-------
Attachment 4-1, Energy Distribution
Qv= 5.5% QL= 5% Q = 12.8%
HHV = 100%
= 76.7%
Energy Distribution without Energy Recovery
Q = 5.5%
QL= 5%
Qfg= 5.3%
1»5 % Energy
Recovery by
Economizer and
Air Preheater
HHV = 100%
q = 84.2%
s
Energy Distribution with Energy Recovery by Economizer and
Air Preheater
4-18
-------
Attachment 4-2, Nomenclature
Symbol
Aa
AE
At
S
G
Gf
h
H
HHV
mf
"NC
Qfg
QH
-ad
Units
Ib/lb fuel
Ib/lb fuel
Ib/lb fuel
Btu/lb°F
Ib/lb fuel
Ib/lb fuel
Btu/lb
Btu/lb fuel
Btu/lb fuel
Ibs/hr
Ibs/hr
Ibs/hr
Btu/lb fuel
Btu/hr
Btu/lb fuel
Btu/lb fuel
Btu/hr
Btu/lb
Btu/lb fuel
Btu/lb fuel
°F
OF
Definition
Actual combustion air per Ib of fuel
Excess air per Ib of fuel
Theoretical (stoichiometric) air per Ib of fuel
Constant pressure specific heat
Flue gas for theoretical combustion per Ib of fuel
Flue gas for combustion with excess air per
Ib of fuel
Specific enthalpy
Net heating value of fuel
Higher heating value
Fuel firing rate
Noncombustibles in fuel
Steaming rate
Energy loss as sensible heat in flue gas
Total energy input
Energy losses as transfer to structure and
surroundings
Useful energy per Ib of fuel, transferred in
non-furnace region
Total energy to useful end purpose
Energy to useful purpose per Ib of fuel
Useful energy -transferred in the furnace
per Ib p'f fuel
Energy loss due to latent heat of the water
vapor formed by combustion
Combustion air temperature
Adiabatic flame temperature
4-19
-------
Attachment 4-2, Nomenclature (continued)
Symbol Units Definition
t , °F Ambient air temperature
amb
tf °F Furnace temperature
t, °F Flue gas temperature
4-20
-------
CHAPTER 5
POLLUTION EMISSION CALCULATIONS
Introduction
Combustion sources constitute a significant air quality control problem
because of the gaseous and particulate emissions which can be produced. With
a variety of combustion systems devised for a multitude of end uses, control
regulations must be formulated based upon selected standards reasonable for
comparison with any given system. Accordingly, emission standards usually
establish the maximum allowable limit for the discharge of specific pollutants.
These limits are usually based upon volume or mass flows at specified condi-
tions of temperature and pressure. Actual field measurements of gas flow
likely would not be made with gas at standard conditions. It is therefore
necessary to adjust the observed volume flow to account for difference in pres-
sure and temperature.
Emissions can be measured in terms of the concentration of pollutant per
volume or mass of flue (stack) gas; the pollutant mass rate or a rate applicable
to a given process. Standards therefore fall into the same three general clas-
sifications: concentration standards, pollutant mass-rate standards and process-
rate standards. Federal ambient air quality standards are examples of concen-
tration standards where allowable limits are set forth in micrograms per cubic
meter at t_ = 25°C and p = 760 mm Hg. Pollutant mass rate standards fix the
s s
mass of pollutant which can be emitted per unit time such as Ib/hr or kg/hr.
Process-rate standards usually establish the allowable emission in terms of
either the input energy or the raw material feed of a process. New source
5-1
-------
standards for fossil-fired steam power plants are an example of an energy
basis standard. Allowable emissions for such operations as acid plants are
based upon the mass of acid produced, while a Portland cement plant emission
standard is in terms of the number of tons of material fed into the kiln.
Values for the standards mentioned together with others may be found in
Attachment 5-1. Where combustion sources are involved,a standard may include
not only the allowable concentration, but may specify the quantity of excess
air the system may use while achieving this concentration. The standard for
solid waste incinerators of 50 T/day or greater is an example of this type of
standard. Such incinerators are limited to particulate emissions not to
exceed 0.08 grain/dscf corrected to 12 percent carbon dioxide.
Volume Correction
Since combustion devices always produce flue gas which is at higher
temperature and pressure than those of the standards, corrections for the dif-
ference must be made. Consider one cubic foot of gas at some specified condi-
tion, say 14.7 psia and 70°F. Does this volume increase or decrease if one
raises the gas temperature? Ask a similar question regarding the effect of a
pressure increase. What volume would the gas occupy if both pressure and
temperature were raised? The answer to these questions can be
developed using the equation of state for the gas. A very familiar equation
is that for an ideal gas (see Attachment 5.2 for Nomenclature):
P V = MRT 5.1
o o o
where the subscript o denotes some observed condition. Here the mass M is
fixed and the quantity R is a constant, so that upon rearrangement, one may
write ;
Pov0 = MR = constant 5.2
To
5-2
-------
Recalling the questions posed above, no gas was added or removed in the specu-
lation of what would happen to the volume as pressure and temperature are
changed. Therefore, at some new condition denoted by a subscript s, one expects
PsVs
= MR
5.3
and MR can be eliminated by equating 5.2 and 5.3 to give
PsVs
5.4
Equation 5.4 may be rearranged to give whatever combination may be most useful.
For example, suppose the subscript s is used to denote standard conditions and
the observed conditions are subscripted with an o. The observed volume, V ,
measured at temperature, T , and pressure, P , would occupy volume, V , if
O O 5
measured at conditions T and P_ as can be seen from a solution of equation 5.4.
s s
V.
(Equation 1, Attachment 5-3)
Other parameters may be handled in the same manner. Consider density as an
example, noting that the gas law can be modified as follows to explicitly
express density
MRT,.
5.5
Rearrangement of equation 5.5 yields ,
= R = constant
5.6
5-3
-------
ps
po
To
Ts
Repeating the reasoning employed above for the case of volume, the density of
a gas at new conditions denoted by subscript s is :
(Equation 3, Attachment 5-3)
Further manipulations of equations can be made to obtain whatever formulation
may be useful in a particular case.
As an applied example, consider using the equation of state to help develop
a conversion factor with which ppm can be reduced to ug/m . Beginning with the
definition
1 ppm = moles of product =
10 moles of air
10~ moles of product . 5.7
moles of air
Note that this is basically a volume measure, and that the definition is based
on T = 25°C and P = 760 mm Hg.
Recall here that a mole of any gas will occupy a volume of 22.4 liters
o o
when P = 760 mm Hg and T = 0 C. The definition of ppm is based on T = 25 C;
therefore, one must calculate the new volume using Equation 1, Attachment 5-3
V = V
vs vo
22.4
273 + 25 =
=24.5 liter
273
is:
In turn, there are 10 meter3/liter and the mass of the moles of product
molecular weight x gm/mole
Combining these conversions:
1 ppm = 10~ [moles prod/mole aij x MW
24.5 ["liters/mole air]
io
-3
liter
5-4
-------
10
MW
24.5
gm
~~
x 10
yg
gm
40
•8 H
5.8
Example: SO,
1 ppm S02 = 40.8(64) = 2611 yg/m3
Excess Air Corrections
Another type of calculation often necessary involves combustion equipment
stack gas samples obtained by Orsat analysis. Before outlining the fundamental
basis of corrections here, it would be well to note several aspects of the
problem. The stack sampling is directed to determine the pollutants emitted
by equipment and compar ed to standards. The raw gas leaving a combustion
device contains certain levels of pollutants, which can be made to appear
smaller if the total gas quantity is increased by adding non-pollutant gas to
the stream. For example, consider the ideal combustion of carbon monoxide with
air
CO + i Q2 + 1.88 N2 ->• CO2 + 1.88 N2 5.9
Here, the percentage of CO2 in the flue gas is:
2.88
= 34.8% by volume.
Suppose the same mole of CO were burned with 100% excess air? The combustion
reaction now is given by :
CO + 2 (£ 02) + 2 (1.88 N2)
Now the total moles of product is given by t
+ Q2 + 3.76
5.10
1 mole CO2 + — mole O2 + 3.76 mole N2 = 5.26 moles
5-5
-------
and CO. = = 19.0% by volume.
2 5.26
Here the volume fraction of CO- was reduced by adding more air, in effect a
dilution of the products by additional air.
The original 2.88 moles of flue gas also could have been diluted through
the addition of steam, a practice which is fundamentally possible since flue
gas temperatures are normally higher than dew-point temperatures. Suppose
one added two moles of steam to the flue gas of Equation 5.9:
CO- + 1.88 N + 2 moles steam 5.11
Now there are 4.88 moles of product and the CO- percentage would be ,
C09 = —-— = 20.5% by volume.
2 4.88
Clearly, the volume fraction of any gas present in the flue gas can be
reduced by dilution, either by adding air or steam. It is for this reason
that combustion equipment emission standards are written with a specified
amount of excess air and based on dry flue gas. Flue gases which indicate
combustion occurred with excess air different from 50% require correction of
observed concentration to that which would have been realized with 50% excess
air.
Stack gas measurements are usually made with the Orsat apparatus, an
absorption device with separate chambers to remove C02, CO, and 02 from the
flue gas in a manner permitting measurement of percentage of each present on
a volume basis. The device is designed so that a dry basis measurement is
realized. Excess air can be determined from the Orsat readings by computation
as follows:
5-6
-------
Consider the complete combustion of carbon with air:
C + 02 + 3.76 N2 -*• C02 + 3.76 »2 5.12
Here the product contains only CC>2 and N-. With excess air, the
reaction becomes ;
C + (1 + a) 02 + (1 + a) 3.76 NZ •*• C02 + a02
+ (1 + a) 3.76 N2 5.13
where a is the number of moles of excess O~ in the excess air. By definition,
the percent of excess air is:
% EA = Actual Air - Theo Air x 10Q% 5>14
Theo Air
The theo air is 02 + 3.76 N2 from equation 5.12 with the actual air
(1 + a) 02 + (1 + a) 3.76 N2 as given by equation 5.13. Combining equations
5.12, 5.13, and 5.14:
a02 + a 3.76
02 + 3.76
100% 5'15
Equation 5.15 requires knowledge of the excess oxygen, a, in order to compute
the excess air. Actually, the Orsat analysis contains the information to
accomplish the same result based on knowledge of the product composition alone.
Note that oxygen can only appear in the product if excess air is present,
assuming complete combustion. Noting product with a subscript :
C + (1 + a) O, + (1 + a) 3.76 N- + CO + O + N 5.16
& *• 4P ^p 2p
where 0- = aO , the excess oxygen provided, and N2 the nitrogen which was part
of the total air supplied. Now the nitrogen present in the product came from
the combustion air (unless fuel contained significant nitrogen) . Therefore ,
5-7
-------
the actual 02 supplied can be determined by computing the moles O2 which were
associated with N2 . Assuming air is 20.9% O~ ^d 79.1% N2 by volume, the
oxygen supplied is given by:
0.264 N2 = O supplied 5.17
The theoretical O is 0.264 N0 - 0 5.18
O-
and the %EA = - =E - x 100% 5.19-
0.264 N2p - 02p
If the combustion produced both CO and CO2 (case of incomplete combustion) ,
the 0_ measured must be reduced by the amount of oxygen which would have com-
2p
bined with CO to form CO_.
Then:
0 - 0.5CO
%EA = - 2E - E - x 100% 5.20
0.264 N2p- (02p - 0.5COp)
In each case, the quantity introduced is the percentage of each constituent
as measured by the Orsat analyzer.
Example :
Orsat Analysis
CO2 = 10%
°2 = 4%
CO = 1%
by difference:
N2 = 100 - (10 + 4 + 1) = 85%
Find % EA from equation 5.20:
0.264 es, 0.5 (1,)
5-8
-------
One caution must be mentioned regarding the CO- measurement as determined
by an Orsat analyzer. The chemical, caustic potash, employed to absorb CO2
also absorbs SO2. Therefore, S02 must be measured separately from CO2 and the
percentage S02 determined must be subtracted from the observed CO2 reading.
Also, the cuprous chloride solution used to absorb CO also absorbs O2; therefore,
a sample which is not correctly analyzed could erroneously indicate 02 for CO.
Correction of concentrations where EA is different from 50% is accomplished
by adjusting the gas volume to that which would have been present if 50% excess
air had been used. Equation 5.20 and correction factors for 50% excess air,
12% C02 and 6% O2 are presented in Attachment 5-4 (Equations 1 through 13).
Application of these equations is best illustrated by an example as follows:
Example 5.1
Given: Power plant steam generator data
Stack gas temperature = 756 R
Pressure = 28.49 in Hg
Wet gas flow = Q = 367,000 acfm, 6.25% moisture by volume
Apparent molecular weight of gas is 29.29
Orsat analysis is CO2 = 10.7%; 02 = 8.2%; CO = 0
Pollutant mass rate (PMR) is 103 Ib/min
With these data, find the following:
A. Pollutant Mass Rate, Tons/day
B. Mass and volume basis concentration
Standards: TS = 530R; PS = 29.92 in Hg; ps = 0.0732 lb/ft3
C. % excess air in effluent
D. Concentrations found in B corrected to 50% EA
E. Concentrations corrected to 12% CO2
F. Concentrations corrected to 6% O2
5-9
-------
Solution
A. Pollutant mass rate (PMR), Tons/day ;
,„,,,,. 60 min 24 hr Ton
103 Ibs/min x —: x — x
hr
day
2000 Ib
= 74.2
Tons
day
B. Concentration - mass and volume basis ;
VQ dry = 367,000 (1-0.0625) = 344,062 acfm
"vo
PMR
V.
103
vo 344,062
Using Equation 2, Attachment 5-3:
103
29.92
756
vs
344,062 28.49 530
or 3.14
Cvs = 4.48 x 10
-4 Ib _ . . arain
ms
= C
Ib
Vsft3
1000 = 6.12 Ib
1000 Ib
C. % Excess air in effluent using Equation 1, Attachment 5-4
<°
% EA =
2p
C0
0.264 N^ - (CL - 0.5 CO )
2p 2p p'
(8.2 - 0)(1QO)
0.264 (81.1) - 8.2
= 61.3 %
D. Concentration corrected to 50% EA is accomplished using Equations
2 and 3 for the volume basis, 4 and 5 for the mass basis concentrations - all
equations taken from Attachment 5-4.
50v
= 1 -
1.5
- 0.133
- 0.75 GO
0.21
1.5 (0.082) - 0.133 (0.811)
0.21
0.928
5-10
-------
'50v
"vs
50v
_ 3.14
0.928
= 3.38
scf
50m
M
1.50 0,n - 0.133 N. - 0.75 CO_
^P 2p P_
0.21
= ms
6.12
= 6.56 lb/1000 Ib dry
0.930
0.930
50m
E. Correction to 12% C0_ is accomplished with Equations 6 and 7,
Attachment 5-3.
Cvs C
F12v C02/0.12
12v
(0.12)
CO
= 3.52
dscf
2p
1.14
0.12
0.107
F. Correction for 6% O is
6v
-6v
0.21 - 0.082
0.15
0.85
3.14
0.85
3.69
dscf
Example 5.1 clearly illustrates how one applies corrections for tempera-
ture, pressure and excess air. The emissions in this example were expressed
as a concentration given a PMR and volume flow rate.
Process-Rate Factors
Process rates are normally based on either energy or material input to a
process, and Example 5.2 illustrates application of a process-rate standard
applied to a combustion source. Figure 5.1 is process rate standard for
particulates taken from the State of Virginia air quality control regulations.
5-11
-------
Figure 5.1, Allowable Particulate Emissions From Fuel Burning Equipment
m
M3
o
•o
I
1.0
.4
.3
.2
.1
.05
H - Total Heat Input in Millions of BTtf per Hour.
E = Maximum Emissions in Pounds of Particulate
Hatter per Million BTU Heat Input,
-°°2314
E = 0.8425 H
( H = 25 to 10tOOO )
1.0
M
nn~
i!i
i i i i
i l
,35
H? Total Heat Input, Million Btu/hour
-------
Example 5.2
Given: (PMR) part - 1800 gm/sec
Fuel: coal @ 23 tons/hour, HHV = 12,500 Btu/lb
Proposed abatement uses an electrostatic precipitator with
99% rated collection efficiency.
Determine whether this plant meets the standard imposed by the Virginia
code.
Solution;
A. Find the process energy rate, H
H = mass of coal x energy value per unit mass
= 23 g" x 12,500 2*2. x 2000 Ib
lb ton
= 575 x 106 Btu/hr
B. Find the allowable emission rate from Figure 1.
From graph @ H = 575 x 106 Btu/hr
E = 0.19 pounds/106 Btu
or calculate from E = 0.8425 (575) ~°'2314 = 0.194 lb
106 Btu
C. Now find actual particulate weight rate
1800 gm/sec x 1£ x 3600 £®£ (1 - 0.99)
= 454 gm hr
: T—
575 x 106 SSi
hr
E
.
actual 106 Bfcu
0.25 > 0.19. Therefore, this unit does not conform.
5-13
-------
F-Factors
So far the discussion has been directed to the correction of observed
field data to account for temperature, pressure and excess air conditions
different from those of a standard. Actual volume flow and gas composition
were required input. The Federal Register of October 6, 1975
promulgated the F-factor method for the determination of a pollutant emission
rate, E, expressed as lbs/10 Btu or g/10° kJ.
The emission rate E is related to concentration and mass rate. The pol-
lutant mass rate, expressed in terms of volume flow rate and concentration is
given by:
PMR = CVSVS 5.21
The emission rate, E, in terms of the energy input H is:
E = PMR = °vsvs 5 22
Consider the ratio _§., the ratio of gas volume flow to energy input in terms
H
of basic combustion chemistry. For theoretical combustion, the volume Vg can
be predicted by computing the products of combustion realized from the burning
of a unit mass of fuel. When excess air is used the volume flow is larger
than the theoretical, but only by the volume of excess air. It is possible
therefore, to compute the volume flow, Vg, in terms of the theoretical volume
(stoichiometric) and an excess air correction. Defining the theoretical
volume of combustion gases as Vgt, the volume V is:
Vg = ^§t _^_ 5.23
excess air
^1
ionj
,correction]
and equation 5.22 becomes
E = C..J st|_l ^24
fexcess air~|
l_ correctionj
5-14
-------
The F-factor is defined as:
F = vst
H
and the excess air correction is given by:
'°-9 - °2P"
20.9
Substitution of Equations 5.25 and 5.26 into 5.24 yields:
E = C F,
vs d
20.9
20.9 - O,
5.25
5.26
5.27
The terms in Equation 5.27 are C , the dry basis concentration corrected to
standard conditions; the excess air correction based on the percent O in the
sampled gas; and F , a factor which can be computed knowing fuel composition.
Volume flow and fuel flow measurements are not necessary, thus simplifying
the task of emission rate determination. For a fuel of known chemical com-
position and higher heating value H, the factor F^ is given by:
= Q.64 H2 + 1.53 C + 0.57 S + 0.14 N2 - 0.46 O
— — — '• """• -'•' ' . . - .-..- .-.- - - - _ - _. _ ..
HHV
dscf
10b Btu
5.28
The values for H2, C, S, N2, O2 and the percentages of each element are taken from
the ultimate analysis. Here F, is noted as the F-f actor when dry O- percentage
was used as the measure of excess air. Should one choose to use CO as the
indicator of excess air, a factor F is used where:
and
E = C F
vs c
100 I
j»2p]
Ibs
106 Btu
5.29
[321 x 103J
Ivs dscf
HH.V
106 Btu
5.30
5-15
-------
C as used in Equation 5.29, can be either wet or dry basis depending on
vs
whether CO_ is determined on a wet or dry basis.
Calculations of F-factors for various fuels indicate a relatively narrow
range of values. For example, F, values for bituminous coal range from 9750
to 9930 dscf/106 Btu. Taking the midpoint value, 9820 dscf/106 Btu, this
range has a maximum deviation of ± 3%. Attachment 5-5 is a tabulation of
calculated mid-range F-factor values with deviations where applicable.
The F-factor method is based on an assumption of complete combustion.
There will be an error if CO or unburned combustible is present when O is
the measured excess air indicator. A correction similar to that discussed
earlier is appropriate as follows:
20.9 - (02r> - 0.5 CO) _ _,
Excess air correction = fP P_ 5.31
20.9
and Equation 5.27 becomes »
CvsFd
20.9
J20.9 -(02p - 0.5 C0p)_
5.32
Loss of combustible (unburned carbon in coal ash for example) represents a
reduction of actual input energy. F-factor assumes all energy released and
since E is proportional to , calculated E is smaller than the actual.
HHV
Removal of CX>2 by wet scrubbing also introduces errors where F or F, is the
factor employed. Accuracy of the Orsat analysis is as important to the use
of F-factors as were the more involved computations discussed previously.
5-16
-------
Use of Emission Factors
EPA publication AP-42 is a compilation of emission factors which have
been gathered from various references. These factors, while quite valuable
when calculations of gross inventory for a large number of sources are in-
volved, are not necessarily valid for a specific single source. A
selected group of tables for various common combustion systems and fuels is
found in Appendix 5.1.
While more precise emission information is needed in order to pinpoint
actual emissions, factors such as those presented in AP-42 can be used to
form estimates of the control required.
Example 5.3, using Table 1.1.2, Appendix 5.1, factors for uncontrolled
bituminous coal combustion, indicates the particulate loading a spreader
stoker might produce is thirteen times the coal ash. This factor tells us
that a larger number of spreader stoker fired units operating without control
would produce on the average, 13 pounds of particulates for each one percent
of ash in the coal burned. Any given unit might produce this amount at some
operating capacity but not at all operating levels. At light loads, for
example, gas flows are reduced compared to design capacity, and particulate
entrainrnent is reduced because of lower gas velocity.
The emission factors are essentially process emission rate values ex-
pressed in terms of mass fired (Ibs per ton). These values are convertible
to pollutant mass rate, PMR, by knowing the firing rate in Ibs per hour.
Example 5.3 Jf one burns 6 tons/hr of coal with A = 10% and a heating
value HHy of 12,500 Btu/lb in a spreader stoker fired boiler, the uncontrolled
emission rate is
E = 13 x (10) = 130 Ibs/ton
5-17
-------
and the pollutant mass rate is:
PMR = 130 ±2— x 6 £2E = 780 Ib/hr
ton hr
Conversion of the emission rate from Ibs per ton to Ibs per million Btu is
Btu
as follows: HHV = 12,500
Ib
= 12,500 x 2,000 -^k- = 25 x 1Q6 Btu/ton
Ib ton
Therefore, E = 130 -^- x i r p. = 5.2 l^f
ton 25 1Q6 Btu 6 .
ton
6
The degree of control required for a source performance standard of 0.1 lbs/10 Btu
would be determined as follows: collected Input-Allowable
n = ' • x j.uu* s _ . A
1 Input Input
= 5'25"2°'1 x 3-00% - 98.1%
This would be an estimate only. More precise emission data for a specific unit
would be desirable.
The SO factor is more nearly representative of an actual case since the
sulfur in the fuel is measureable. The factor, 38S assumes 4% of the sulfur
in the fuel does not appear as SO-. This difference is greater if the system
has a high percentage of unburned fuel in the ash. Where unburned combustible
in the ash is a specified value, the SO- reduction is calculable, again provided
the sulfur appearing as SO, can be predicted. The 38S emission factor is a
valid first approximation of the uncontrolled SO to be expected. Using the
coal in Example 5.3 above with 1.3% sulfur, the following can be seen.
Example 5.4
Compute SO2 emission per 10 Btu for the coal in Example 5.3.
5-18
-------
E =38 (1.3) = 49.4
S02 ton
PMR) = 49.4 — x 6 = 296.4 lb
S02 ton hr hr
3_n = 49.4 i|_ x ton = 1.98 ^-
SO 2
New source standard for SO. is 1.2 lb/10 Btu which would require
1-98 - 1"2 = 39.3%
1.98
reduction of SO- in the flue gas.
Similar calculations of uncontrolled emissions are possible using
factors for EC, NO .
References
1. Reynolds, W. C. and Perkins, H. C., Engineering Thermodynamics,
Chapter 11, McGraw-Hill, Inc., New York (1977).
2. Wark, K. and Warner, C. F., Air Pollution, Its Origin and Control,
Harper & Row Publishers, New York (1976).
3. Perkins, H. C., Air Pollution, McGraw-Hill, Inc., New York (1974).
4. Federal Register, Vol. 30, No. 247, Part II (December 23, 1971).
5. Shigehara, R. T., et al., "Summary of F-Factor Methods for Determin-
ing Emissions from Combustion Sources," Source Evaluation Society Newsletter,
Vol. 1, No. 4 (November 1976).
5-19
-------
ATTACHMENT 5-1
TYPICAL STANDARDS
NEW SOURCE STANDARDS - DECEMBER 23, 1971*
Federal Register Vol. 30, No. 427
1. Fossil-fired steam generators with heat input greater than 25Q million Btu/hr
A. Particulates: 0.10 Ib per 106 Btu input (0.18 g/106 cal) maximum
2 hr average
B. Opacity: 20% except that 40% shall be permissible for not more than
2 minutes in any hour
C. Sulfur dioxide and NO
X
S02 NOX
lb/106 Btu kg/106kJ lb/106 Btu kg/106kJ
Gaseous Fuel - - 0.20 0.09
Liquid Fuel 0.80 0.345 0.30 0.13
Solid Fuel 1.20 0.520 0.70 0.30
2. Solid waste incinerator: charging rate in excess of 50 Tons/day.
Particulate emission standard 0.08 grain/dscf (0.18 g/m3) corrected to
12% C02.
3. Portland cement plants: maximum 2 hour average particulate emission of
0.30 Ityton (0.15 kg/metric ton) and opacity not greater than 20%.
4. Nitric acid plants: maximum 2 hour average nitrogen oxide emission of
3 Ib/Ton of acid produced (1.5 kg per metric ton) expressed as nitrogen
dioxide.
5. Sulfuric acid plants employing the contact process: maximum 2 hour average
emission of SO2 of 4 Ib/Ton of acid produced. Also acid mist standard:
maximum 2 hour average emission of 0.15 Ib/Ton of acid produced (0.75 kg
per metric ton).
*Note: Standards are revised from time to time.
5-20
-------
Attachment 5-2, Nomenclature for Equations
of Chapter 5
Symbol
Cjn Concentration, mass bases
Cv Concentration, volume basis
£ Process Emission
EA Excess Air
F Correction Factor; F-factor
H Energy Rate
HHV Higher Heat Value
Q Volume Flow Rate
M Mass
MM Molecular Weight
P Pressure, absolute
PMR Pollutant Mass Rate
R Gas, constant
T Temperature, absolute
V Volume
p Density
Subscripts
e effluent
p product
m mass ba'sis
o observed conditions
s standard conditions
v per-volume basis
5-21
-------
ATTACHMENT 5-3
GAS VOLUME CORRECTIONS
Volume
V.
V
Concentration
c = c
vs vo
T
Density
_ o _
(1)
(2)
(3)
5-22
-------
ATTACHMENT 5-4
EXCESS AIR CORRECTIONS
DETERMINATION OF EXCESS AIR
% EA
(02p - 0.5 C0p)
0.264N2p - (02p -0.5 C0p)
x 100%
(1)
FACTORS FOR CORRECTION TO 50% EA
50v
1.502p - 0.133 N2p - 0.75 CO
0.21
(2)
"50v
_ Cvs
'50v
(3)
F = 1 - 29
50m
1.502p - 0.133 N2p - 0.75 CO
0.21
(4)
c__ = SllE.
50m
F50m
(5)
FACTOR FOR CORRECTION TO 12% CO-
12v
CO-
0.12
(6)
vs
12v
(7)
12m
.29 r _ Co2pn
Me L OL12 J
(8)
12m
(9)
5-23
-------
FACTOR FOR CORRECTION TO 6% 0,
- °
6v
2P
0.15
(10)
C = vs
6v —
6v
(ID
F, 1 -
6m =
29
- 0.06
0.15
(12)
'6m
6m
(13)
5-24
-------
ATTACHMENT 5-5
F-FACTORS FOR VARIOUS FUELS
a,b
FUEL TYPE
Coal
Anthracite
Bituminous
Lignite
Oil
Gas
Natural
Propane
Butane
Wood
Wood Bark
Paper and Wood Wastes
Lawn and Garden Wastes
Plastics
Polyethylene
Polystyrene
Polyurethane
Polyvinyl Chloride
Garbage
dscf/106 Btu
10140 (2.0)
9820 (3.1)
9900 (2.2)
9220 (3.0)
9173
9860
10010
9120
9640 (4.0)
scf/10° Btu
1980 (4.1)
1810 (5.9)
1920 (4.6)
1430 (5.1)
1380
1700
1810
1480
1790 (7.9)
1.070 (2.9)
1.140 (4.5)
1.0761(2.8)
1.3461(4.1)
8740
8740
8740
9280
9640
9260
9590
(2.
(2.
(2.
(1.
(4.
(3.
(5.
2)
2)
2)
9)
1)
6)
0)
1040
1200
1260
1840
1860
1870
1840
(3.9)
(1.0)
(1-0)
(5.0)
(3.6)
(3.3)
(3.0)
1.
1.
1.
1.
1.
1.
1.
79
10
479
5
056
046
088
(2.9)
(1.2)
(0.9)
(3.4)
(3.9)
(4.6)
(2.4)
1.394
1.213
1.157
1.286
1.110 (5.6)
Numbers in parentheses are maximum deviations (%) from the midpoint F-Factors.
To convert to metri
obtain scm/106 cal.
b -4
To convert to metric system, multiply the above values by 1.123 x 10 to
Source: R. T. Shigehara, etal., "Summary of F Factor Methods for Determining
Emissions from Combustion Sources," Source Evaluation Society
Newsletter, Vol. 1, No. 4, November 1976.
5-25
-------
APPENDIX 5-1
COMPILATION
OF
AIR POLLUTANT EMISSION FACTORS
Third Edition
(Including Supplements 1-7)
U.S. ENVIRONMENTAL PROTECTION AGENCY
, Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1977
5-26
-------
This report is published by the Environmental Protection Agency to report information of general interest in the
field of air pollution. Copies are available free of charge to Federal employees, current contractors and grantees,
and nonprofit organizations—as supplies permit—from the Library Services Office, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711. This document is also available to the public for sale
through the Superintendent of Documents, U.S. Government Printing Office, Washington, D.C
Publication No. AP-42
5-27
-------
1. EXTERNAL COMBUSTION SOURCES
External combustion sources include steam-electric generating plants, industrial boilers, commercial and
institutional boilers, and commercial and domestic combustion units. Coal, fuel oil, and natural gas are the major
fossil fuels used by these sources. Other fuels used in relatively small quantities are liquefied petroleum gas, wood,
coke, refinery gas, blast furnace gas, and other waste- or by-product fuels. Coal, oil, and natural gas currently
supply about 95 percent of the total thermal energy consumed in the United States. In 1970 over 500 million
tons (454 x 106 MT) of coal, 623 million barrels (99 x 109 liters) of distillate fuel oil, 715 million barrels (114 x
109 liters) of residual fuel oil, and 22 trillion cubic feet (623 x 1012 liters) of natural gas were consumed in the
United States.'
Power generation, process heating, and space heating are some of the largest fuel-combustion sources of sulfur
oxides, nitrogen oxides, and participate emissions. The following sections present emission factor data for the
major fossil fuels - coal, fuel oil, and natural gas — as well as for liquefied petroleum gas and wood waste
combustion in boilers.
REFERENCE
1. Ackerson, D.H. Nationwide Inventory of Air Pollutant Emissions. Unpublished report. Office of Air and Water
Programs, Environmental Protection Agency, Research Triangle Park, N.C. May 1971.
1.1 BITUMINOUS COAL COMBUSTION
1.1.1 General
Revised by Robert Rosensteel
and Thomas Lahre
Coal, the most abundant fossil fuel in the United States, is burned in a wide variety of furnaces to produce
heat and steam. Coal-fired furnaces range in size from small handfired units with capacities of 10 to 20 pounds
(4.5 to 9 kilograms) of coal per hour to large pulverized-coal-fired units, which may burn 300 to 400 tons (275 to
360 MT) of coal per hour.
Although predominantly carbon, coal contains many compounds in varying amounts. The exact nature and
quantity of these compounds are determined by the location of the mine producing the coal and will usually
affect the final use of the coal.
1.1.2 Emissions and Controls
1.1.2.1 Particulates1 - Particulates emitted from coal combustion consist primarily of carbon, silica, alumina, and
iron oxide in the fly-ash. The quantity of atmospheric particulate emissions is dependent upon the type of
combustion unit in which the coal is burned, the ash content of the coal, and the type of control equipment used.
4/73
5-28
-------
Table 1.1-1 gives the range of collection efficiencies for common types of fly-ash control equipment. Participate
emission factors expressed as pounds of participate per ton of coal burned are presented in Table 1.1-2.
1.1.2.2 Sulfur Oxides1' • Factors for uncontrolled sulfur oxides emission are shown in Table 1-2 along with
factors for other gases emitted. The emission factor for sulfur oxides indicates a conversion of 95 percent of the
available sulfur to sulfur oxide. The balance of the sulfur is emitted in the fly-ash or combines with the slag or ash
in the furnace and is removed with them.1 Increased attention has been given to the control of sulfur oxide
emissions from the combustion of coal. The use of low-sulfur coal has been recommended in many areas; where
low-sulfur coal is not available, other methods in which the focus is on the removal of sulfur oxide from the flue
gas before it enters the atmosphere must be given consideration.
A number of flue-gas desulfurization processes have been evaluated; effective methods are undergoing full-scale
operation. Processes included in this category are: limestone-dolomite injection, limestone wet scrubbing,
catalytic oxidation, magnesium oxide scrubbing, and the Wellman-Lord process. Detailed discussion of various
flue-gas desulfurization processes may be found in the literature.12-13
1.1.2.3. Nitrogen Oxides1'5 - Emissions of oxides of nitrogen result not only from the high temperature reaction
of atmospheric nitrogen and oxygen in the combustion zone, but also from the partial combustion of nitrogenous
compounds contained in the fuel. The important factors that affect NOX production are: flame and furnace
temperature, residence time of combustion gases at the flame temperature, rate of cooling of the gases, and
amount of excess air present in the flame. Discussions of the mechanisms involved are contained in the indicated
references.
1.1.2.4 Other Gases - The efficiency of combustion primarily determines the carbon monoxide and hydrocarbon
content of the gases emitted from bituminous coal combustion. Successful combustion that results in a low level
of carbon monoxide and organic emissions requires a high degree of turbulence, a high temperature, and
sufficient time for the combustion reaction to take place. Thus, careful control of excess air rates, the use of high
combustion temperature, and provision for intimate fuel-air contact will minimize these emissions.
Factors for these gaseous emissions are also presented in Table 1.1-2. The size range in Btu per hour for the
various types of furnaces as shown in Table 1.1-2 is only provided as a guide in selecting the proper factor and is
not meant to distinguish clearly between furnace applications.
TABLE 1.1-1. RANGE OF COLLECTION EFFICIENCIES FOR COMMON TYPES
OF FLY-ASH CONTROL EQUIPMENT"
Type of
furnace
Cyclone furnace
Pulverized unit
Spreader stoker
Other stokers
Range of collection efficiencies, %
Electrostatic
precipitator
65 to 99.5b
80 to 99.5b
99.5b
99.5b
High-
efficiency
cyclone
30 to 40 ,
65 to 75
85 to 90
90 to 95
Low-
resistance
cyclone
20 to 30
40 to 60
70 to 80
75 to 85
Sent ing
chamber ex-
panded chimney
bases
10"
20"
20 to 30
25 to 50
References 1 and 2.
^The maximum efficiency to be expected for this collection device applied to this type source;
EMISSION FACTORS
5-29
4/73
-------
-^
OS
Table 1.1-2. EMISSION FACTORS FOR BITUMINOUS COAL COMBUSTION WKTHOUT CONTROL EQUIPMENT
EMISSION FACTOR RATING: A
ui
I
00
o
m
x
!•+
9
1.
n
O
cr
g
i-*-
o'
c«
o
Furnace size,
106 Btu/hr
heat input3
Greater than 1006
(Utility and large
industrial boilers)
Pulverized
General
Wet bottom
Dry bottom
Cyclone
10 to 1009 (large
commercial and
general industrial
boilers)
Spreader stoker"
Less than 10'
(commercial and
domestic furnaces)
Underfeed stoker
Hand-fired units
Particulatesb
Ib/ton
coal
burned
16A
13Af
17A
2A
13A'
2A
20
kg/MT
coal
burned
8A
6.5A
8.5A
1A
6.5A
1A
10
Sulfur
oxides0
Ib/ton
coal
burned
38S
38S
38S
38S
38S
38S
38S
kg/MT
coal
burned
19S
19S
19S
19S
19S
19S
19S
Carbon
monoxide
Ib/ton
coal
burned
1
1
1
1
2
10
90
kg/MT
coal
burned
0.5
0.5
0.5
0.5
1
5
45
Hydro-
carbons'1
Ib/ton
coal
burned
0.3
0.3
0.3
0.3
1
3
20
kg/MT
coal
burned
0.15
0.15
0.15
0.15
0.5
1.5
10
Nitrogen
oxides
Ib/ton
coal
burned
18
30
18
55
15
6
3
kg/MT
coal
burned
9
15
9
27.5
7.5
3
1.5
Aldehydes
Ib/ton
coal
burned
0.005
0.005
0.005
0.005
0.005
0.005
0.005
kg/MT
coal
burned
0.0025
0.0025
0.0025
0.0025
0.0025
0.0025
0.0025
a1 Btu/hr = 0552 kcal/hr.
''The letter A on all units other than hand-fired equipment indicates that the weight percentage of ash in the coal should be multiplied by the value given.
Example: If the factor is 16and the ash content is 10 percent, the particulate emissions before the control equipment would be 10 times 16, or 160
pounds of particulate per ton of coal (10 times 8, or 80 kg of particulates per MT of coal).
CS equals the sulfur content (see footnote b above).
Expressed as methane.
e References 1 and 3 through 7.
Without fly-ash reinjection.
9References 1, 4. and 7 through 9.
For all other stokers use 5A for particulate emission factor.
! Without fly-ash reinjection. With fly-ash reinjection use 20 A. This value is not an emission factor but represents loading reaching the control equipment '
' References 7,9. and 10.
-------
References for Section 1.1
1. Smith, W. S. Atmospheric Emissions from Coal Combustion. U.S. DHEW, PHS, National Center for Air
Pollution Control. Cincinnati, Ohio. PHS Publication Number 999-AP-24. April 1966.
2. Control Techniques for Paniculate Air Pollutants. U.S. DHEW, PHS, EHS, National Air Pollution Control
Administration Washington. D.C. Publication Number AP-51. January 1969.
3. Perry, H. and J. H. Field. Air Pollution and the Coal Industry. Transactions of the Society of Mining
Engineers. 238:331-345, December 1967.
4. Heller, A. W. and D. F. Walters. Impact of Changing Patterns of Energy Use on Community Air Quality. J.
Air Pol. Control Assoc. 75:426, September 1965.
5. Cuffe, S. T. and, R. W. Gerstle. Emissions from Coal-Fired Power Plants: A Comprehensive Summary. U.S.
DHEW, PHS, National Air Pollution Control Administration. Raleigh, N. C. PHS Publication Number
999-AP-35. 1967. p. 15.
6. Austin, H. C. Atmospheric Pollution Problems of the Public Utility Industry. J. Air Pol. Control Assoc.
10(4):292-294, August 1960.
7. Hangebrauck, R. P., D. S. Von Lehmden, and J. E. Meeker. Emissions of Polynuclear Hydrocarbons and
Other Pollutants from Heat Generation and Incineration Processes. J. Air Pol. Control Assoc. 74:267-278,
July 1964.
8. Hovey, H. H., A. Risman, and J. F. Cunnan. The Development of Air Contaminant Emission Tables for
Nonprocess Emissions. J. Air Pol. Control Assoc. 16:362-366, July 1966.
9. Anderson, D. M., J. Lieben, and V. H. Sussman. Pure Air for Pennsylvania. Pennsylvania Department of
Health. Harrisburg, Pa. November 1961. p. 91-95.
10. Communication with National Coal Association. Washington, D. C. September 1969.
11. Private communication with R.D. Stern, Control Systems Division, Environmental Protection Agency.
Research Triangle Park, N.C. June 21, 1972.
12. Control Techniques for Sulfur Oxide Air Pollutants. U.S. DHEW, PHS, EHS, National Air Pollution Control
Administration. Washington, D.C. Publication Number AP-52. January 1969. p. xviii and xxii.
13. Air Pollution Aspects of Emission Sources: Electric Power Production. Environmental Protection Agency,
Office of Air Programs. Research Triangle Park, N.C. Publication Number AP-96. May 1971.
EMISSION FACTORS 4/75
5-31
-------
1.2 ANTHRACITE COAL COMBUSTION revised by Tom La/ire
1.2.1 General1'2
Anthracite is a high-rank coal having a high fixed-carbon content and low volatile-matter content
relative to bituminous coal and lignite. It is also characterised by higher ignition and ash fusion tem-
peratures. Because of its low volatile-matter content and non-clinkering characteristics, anthracite is
most commonly fired in medium-sized traveling-grate stokers and small hand-fired units. Some an-
thracite (occasionally along with petroleum coke) is fired in pulverized-coal-fired boilers. None is fired
in spreader stokers. Because of its low sulfur content (typically less than 0.8 percent, by weight) and
minimal smoking tendencies, anthracite is conside^c^ a desirable fuel where readily available.
In the United States, all anthracite is mined in Northeastern Pennsylvania and consumed primarily
in Pennsylvania and several surrounding states. The largest use of anthracite is for space heating;" lesser
amounts are employed for steam-electric production, coke manufacturing, sintering and pelletizing,
and other industrial uses. Anthracite combustion currently represents only a small fraction of the to-
tal quantity of coal combusted in the United States.
1.2.2 Emissions and Controls2'9
Particulate emissions from anthracite combustion are a function of furnace-firing configuration,
firing practices (boiler load, quantity and location of underfire air, sootblowing, flyash reinjection,
etc.), as well as of the ash content of the coal. Pulverized-coal-fired boilers emit the highest quantity of
particulate per unit of fuel because they fire the anthracite in suspension, which results in a high per-
centage of ash carryover into the exhaust gases. Traveling-grate stokers and hand-fired units, on the
other hand, produce much less particulate per unit of fuel fired. This is because combustion takes
place in a quiescent fuel bed and does not result in significant ash carryover into the exhaust gases. In
general, particulate emissions from traveling-grate stokers will increase during sootblowing, fly-
ash reinjection, and with higher underfeed air rates through the fuel bed. Higher underfeed air rates,
in turn, result from higher grate loadings and the use of forced-draft fans rather than natural draft to
supply combustion air. Smoking is rarely a problem because of anthracite's low volatile-matter
content.
Limited data are available on the emission of gaseous pollutants from anthracite combustion. It is
assumed, based on data derived from bituminous coal combustion, that a large fraction of the fuel sul-
fur is emitted as sulfur oxides. Moreover, because combustion equipment, excess air rates, combustion
temperatures, etc., are similar between anthracite and bituminous coal combustion, nitrogen oxide
and carbon monoxide emissions are assumed to be similar, as well. On the other hand, hydrocarbon
emissions are expected to be considerably lower because the volatile-matter content of anthracite is
significantly less than that of bituminous coal.
Air pollution control of emissions from anthracite combustion has mainly been limited to particu-
late matter. The most efficient particulate controls—fabric filters, scrubbers, and electrostatic precipi-
tators-have been installed on large pulverized-anthracite-fired boilers. Fabric filters and venturi
scrubbers can effect collection efficiencies exceeding 99 percent. Electrostatic precipitators, on the
other hand, are typically only 90 to 97 percent efficient due to the characteristic high resistivity of the
low-sulfur anthracite flyash. Higher efficiencies can reportedly be achieved using larger precipitators
and flue gas conditioning. Mechanical collectors are frequently employed upstream from these devices
for'large-particle removal.
Traveling-grate stokers are often uncontrolled. Indeed, particulate control has often been con-
sidered unnecessary because of anthracite's low smoking tendencies and due to the fact that a signifi-
cant fraction of the large-sized flyash from stokers is readily collected in flyash hoppers as well as in the
breeching and base of the stack. Cyclone collectors have been employed on traveling-grate stokers;
4/77 External Combustion Sources
5-32
-------
limited information suggests these devices may be up to 75 percent efficient on particulate. Flyash rein-
jection, frequently employed in traveling-grate stokers to enhance fuel-use efficiency, tends to in-
crease particulate emissions per unit of fuel combusted.
Emission factors for anthracite combustion are presented in Table 1.2-1.
EMISSION FACTORS 4/77
5-33
-------
Table 1.2-1. EMISSION FACTORS FOR ANTHRACITE COMBUSTION, BEFORE CONTROLS
EMISSION FACTOR RATING: B
M
X
ft
o
0"
ui C
I a>
w s*
O
e
a
CB
Type of furnace
Pulverized coal
Traveling grate
Hand-fired
Emissions3
Participate
Ib/ton
17Af
1A9
10h
kg/MT
8.5Af
0.5A9
5*
Sulfur oxidesb
Ib/ton
38S
38S
38S
kg/MT
19S
195
19S
Hydrocarbons0
Ib/ton
Neg
Neg
2.5
kg/MT
Neg
Neg
1.25
Carbon
monoxide"
Ib/ton
1
1
90
kg/MT
0.5
0.5
45
Nitrogen
oxides6
Ib/ton
18
10
3
kg/MT
9
5
1.5
aAII emission factors are per unit of anthracite fired.
"These factors are based on the assumption that, as with bituminous coal combustion, most of the fuel sulfur is emitted as sulfur oxides. Limited data in
Reference 5 verify this assumption for pulverized-anthracite-fired boilers. Generally most of these emissions are sulfur dioxide; however, approximately
1 to 3 percent are sulfur trioxide.
cHydrocarbon emissions from anthracite combustion are assumed to be lower than from bituminous coal combustion because of anthracite's much lower
volatile-matter content. No emissions data are available to verify this assumption.
^The carbon monoxide factors for pulverized-anthracite-fired boilers and hand-fired units are from Table 1.1-2.and are based on the similarity between
anthracite and bituminous coal combustion. The pulverized-coal-fired boilers factor is substantiated by additional data in Reference 10.- The factor
for traveling-grate stokers is based on limited information in Reference 8. Carbon monoxide emissions may increase by several orders of magnitude if
a boiler is not properly operated or well maintained.
*The nitrogen oxide factors for pulverized-anthracite-fired boilers and hand-fired units are assumed to be similar to those for bituminous coal combus-
tion given in Table 1.1-2. The factors for traveling-grate stokers are based on Reference 8.
These factors are based on the similarity between anthracite and bituminous coal combustion and on limited data in Reference 5.' Note that all pulverized-
anthracite-fired boilers operate in the dry tap or dry bottom mode due to anthracite's characteristically high ash-fusion temperature. The letter A on units
other than hand-fired equipment indicates that the weight percentage of ash in the coal should be multiplied by the value given.
9Based on information in References 2,4,8, and 9. These factors account for limited fallout that may occur in fallout chambers and stack breeching.
Emission factors for individual boilers may vary from 0.5A Ib/ton (0.25A kg/MT) to 3A Ib/ton (1.5A kg/MT), and as high as 5A Ib/ton {2.5A kg/MT)
during soot blowing.
"Based on limited information in Reference 2.
-------
References for Section 1.2
1. Coal—Pennsylvania Anthracite in 1974. Mineral Industry Surveys. U.S. Department of the In-
terior. Bureau of Mines. Washington, D.C.
2. Air Pollutant Emission Factors. Resources Research, Inc., TRW Systems Group. Reston, Virginia.
Prepared for the National Air Pollution Control Administration, U.S. Department of Health, Ed-
ucation, and Welfare, Washington, D.C., under Contract No. CPA 22-69-119. April 1970. p. 2-2
through 2-19.
3. Steam—Its Generation and Use. 37th Edition. The Babcock & Wilcox Company. New York, N.Y.
1963. p. 16-1 through 16-10.
4. Information Supplied By J.K. Hambright. Bureau of Air Quality and Noise Control. Pennsyl-
vania Department of Environmental Resources. Harrisburg, Pennsylvania. July 9, 1976.
5. Cass, R.W. and R.M. Broadway. Fractional Efficiency of a Utility Boiler Baghouse: Sunbury
Steain-Electric Station—GCA Corporation. Bedford, Massachusetts. Prepared for Environmental
Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-1438. Publication No.
EPA-600/2-76-077a. March 1976.
6. Janaso, Richard P. Baghouse Dust Collectors On A Low Sulfur Coal Fired Utility Boiler. Present-
ed at the 67th Annual Meeting of the Air Pollution Control Association. Denver, Colorado. June
9-13, 1974.
7. Wagner, N.H. and D.C. Housenick. Sunbury Steam Electric Station-Unit Numbers 1 & 2 - Design
and Operation of a Baghouse Dust Collector For a Pulverized Coal Fired Utility Boiler. Presented
at the Pennsylvania Electric Association, Engineering Section, Power Generation Committee,
Spring Meeting. May 17-18, 1973.
8. Source Test Data on Anthracite Fired Traveling Grate Stokers. Environmental Protection Agen-
cy. Office of Air Quality Planning and Standards. Research Triangle Park, N.C. 1975.
9. Source and Emissions Information on Anthracite Fired Boilers. Supplied by Douglas Lesher.
Bureau of Air Quality Noise Control. Pennsylvania Department of Environmental Resources.
Harrisburg, Pennsylvania. September 27, 1974.
10. Bartok. William et al. Systematic Field Study of NOX Emission Control Methods For Utility
Boilers. ESSO Research and Engineering Company, Linden, N.J. Prepared for Environmental
Protection Agency, Research Triangle Park, N.C. under Contract No. CPA-70-90. Publication No.
APTD-1163. December 31, 1971.
EMISSION FACTORS 4/77
5-35
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1.3 FUEL OIL COMBUSTION by Tom Lahre
1.3.1 General1-2
Fuel oils are broadly classified into two major types: distillate and residual. Distillate oils (fuel oil grades 1 and
2) are used mainly in domestic and small commercial applications in which easy fuel burning is required.
Distillates are more volatile and less viscous than residual oils as well as cleaner, having negligible ash and nitrogen
contents and usually containing less than 0.3 percent sulfur (by weight). Residual oils (fuel oil grades 4, 5, and 6),
on the other hand, are used mainly in utility, industrial, and large commercial applications in which sophisticated
combustion equipment can be utilized. (Grade 4 oil is some limes classified as a distillate; grade 6 is sometimes
referred to as Bunker C.) Being more viscous and less volatile than distillate oils, the heavier residual oils (grades 5
and 6) must be heated for ease of handling and to facilitate proper atomization. Because residual oils are
produced from the residue left over after the lighter fractions (gasoline, kerosene, and distillate oils) have been
removed from the crude oil, they contain significant quantities of ash, nitrogen, and sulfur. Properties of typical
fuel oils are given in Appendix A.
1.3.2 Emissions
Emissions from fuel oil combustion are dependent on the grade and composition of the fuel, the type and size
of the boiler, the firing and loading practices used, and the level of equipment maintenance. Table 1.3-1 presents
emission factors for fuel oil combustion in units without control equipment. Note that the emission factors for
industrial and commercial boilers are divided into distillate and residual oil categories because the combustion of
each produces significantly different emissions of particulates, SOX, and NOX. The reader is urged to consult the
references cited for a detailed discussion of all of the parameters that affect emissions from oil combustion.
1.3.2.1 Particulates 12-13 _ Paniculate emissions are most dependent on the grade of fuel fired. The lighter
distillate oils result in significantly lower particulate formation than do the heavier residual oils. Among residual
oils, grades 4 and 5 usually result in less particulate than does the heavier grade 6.
In boilers firing grade 6, particulate emissions can be described, on the average, as a function of the sulfur
content of the oil. As shown in Table 1.3-1 ( footnote c), particulate emissions can be reduced considerably when
low-sulfur grade 6 oil is fired. This is because low-sulfur grade 6, whether refined from naturally occurring
low-sulfur crude oil or desulfurized by one of several processes currently in practice, exhibits substantially lower
viscosity and reduced asphaltene, ash, and sulfur content - all of which result in better atomization and cleaner
combustion. >
Boiler load can also affect particulate emissions in units firing grade 6 oil. At low load conditions, particulate
emissions may be lowered by 30 to 40 percent from utility boilers and by as much as 60 percent from small
industrial and commercial units. No significant particulate reductions have been noted at low loads from boilers
firing any of the lighter grades, however. At too low a load condition, proper combustion conditions cannot be
maintained and particulate emissions may increase drastically. It should be noted, in this regard, that any
condition that prevents proper boiler operation can result in excessive particulate formation.
1.3.2.2 Sulfur Oxides (SOX) ' - Total sulfur oxide emissions are almost entirely dependent on the sulfur
content of the fuel and are not affected by boiler size, burner design, or grade of fuel being fired. On the average,
more than 95 percent of the fuel sulfur is converted to SOj, with about 1 to 3 percent further oxidized to 803.
Sulfur trioxide readily reacts with water vapor (both in the air and in the flue gases) to form a sulfuric acid mist.
4/77 External Combustion Sources
5-36
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£>•
-4
Table 1.3-1. EMISSION FACTORS FOR FUEL OIL COMBUSTION
EMISSION FACTOR RATING: A
Pollutant
Particulateb
Sulfur dioxided
Sulfur trioxided
Carbon monoxide6
Hydrocarbons
(total, as CH4)f
Nitrogen oxides
(total, as NO2)9
Type of boiler3
Power plant
Residual oil
lb/103gal
c
157S
2S
5
1
1 05(50) "•'
kg/103 liter
c
19S
0.25S
0.63
0.12
12.6(6.25)"-'
Industrial and commercial
Residual oil
lb/103gal
c
157S
2S
5
1
60'
kg/103 liter
c
19S
0.25S
0.63
0.12
7.51
Distillate oil
lb/103gal
2
142S
2S
5
1
22
kg/103 liter
0.25
17S
0.25S
0.63
0.12
2.8
Domestic
Distillate oil
lb/103gal
2.5
142S
2S
5
1
18
kg/ 103 liter
0.31
17S
0.25S
0.63
0.12
2.3
w
E.
ft
o
tr
§
rx
o
i
A
06
Ul
I
u>
aBoilers can be classified, roughly, according to their gross (higher) heat input rate,
as shown below.
Power plant'(utility) boilers: >250x 106Btu/nr
<>63x 10bkfl-cal/hr)
Industrial boilers: >15 x 106, but <250 x 106 Btu/hr
O3.7 x 1fj6. but <63 x 106 kg-cal/hr)
Commercial boilers: >0.5x 106, but <15x 106Btu/hr
(>0.13 x 106, but <3.7 x lOBkg-cal/hr)
Domestic (residential) boilers: <0.5 x 1f)6 Btu/hr
«0.13x 106 kg-cal/hr)
Based on References 3 through 6. Particulate is defined in this section as that
material collected by EPA Method 5 (front half catch)7.
'Particulate emission factors for residual oil combustion are best described, on
the average, as a function of fuel oil grade and sulfur content, as shown below.
Grade 6 oil: lb/103 gal = 10 (S) + 3
[kg/103 liter = 1.25 (S) + 0.38]
Where: S is the percentage, by weight, of sulfur in the oil
Grade 5 oil: 10 lb/1 «3 gall 1.25 kg/1 fj3 liter)
Grade 4 oil: 7 lb/103 gal (0.88 kg/1fj3 liter)
Based on References 1 through 5. S is the percentage, by weight, of sulfur in
the oil.
eBased on References 3 through 5 and 8 through 10. Carbon monoxide emissions
may increase by a factor of 10 to 100 if a unit Is improperly operated or not well
maintained.
'Based on References 1, 3 through 5, and 10. Hydrocarbon emissions are gener-
ally negligible unless unit is improperly operated or not wejl maintained, in
which case emissions may increase by several orders of magnitude.
9Based on References 1 through 5 and 8 through 11.
"Use 50 lb/103 gal (6.25 kg/103 liter) for tangentially fired boilers and 105
lb/103 gal (12.6 kg/103 liter) for all others, at full load, and normal (>15
percent) excess air. At reduced loads, NOX emissions are reduced by 0.5 to
1 percent, on the average, for every percentage reduction in boiler load.
'Several combustion modifications can be employed for NOX reduction: (1)
limited excess air firing can reduce NOX emissions by 5 to 30 percent, (2) staged
combustion can reduce NOX emissions by 20 to 45 percent, and (3) flue gas
recirculation can reduce NOX emissions by 10 to 45 percent. Combinations of
the modifications have been employed to reduce NOX emissions by as much as
60 percent in certain boilers. See section 1.4 for a discussion of these NOX-
reducing techniques.
'Nitrogen oxides emissions from residual oil combustion in industrial and com-
mercial boilers are strongly dependent on the fuel nitrogen content and can be
estimated more accurately by the following empirical relationship:
Ib NO2/103 gal = 22 + 400 (N)2
(kg NO2/103 liters = 2.75 + 50 (N)2)
Where: N is the percentage, by weight, of-nitrogen in the oil. Note: For residual
oils having high ( >0.5%, by weight) nitrogen contents, one should use 120 Ib •
NC-2/103 gal (15 kg NC-2/103 liter) as an emission factor.
-------
1.3.2.3 Nitrogen Oxides (NO*)1"6' 8"n' 14 - Two mechanisms form nitrogen oxides: oxidation of fuel-bound
nitrogen and thermal fixation of the nitrogen present in combustion air. Fuel NOX are primarily a function of the
nitrogen content of the fuel and the available oxygen (on the average, about 45 percent of the fuel nitrogen is
converted to NOX, but this may vary from 20 to 70 percent). Thermal NOX, on the other hand, are largely a
function of peak flame temperature and available oxygen — factors which are dependent on boiler size, firing
configuration, and operating practices.
Fuel nitrogen conversion is the more important N0x-forming mechanism in boilers firing residual oil. Except
in certain large units having unusually high peak flame temperatures, or in units firing a low-nitrogen residual oil,
fuel NOX will generally account for over 50 percent of the total NOX generated. Thermal fixation, on the other
hand, is the predominant NOX-forming mechanism in units firing distillate oils, primarily because of the negligible
nitrogen content in these lighter oils. Because distillate-oil-fired boilers usually have low heat release rates,
however, the quantity of thermal NOX formed in them is less than in larger units.
A number of variables influence how much NOX is formed by these two mechanisms. One important variable
is firing configuration. Nitrogen oxides emissions from tangentially (corner) fired boilers are, on the average, only
half those of horizontally opposed units. Also important are the firing practices employed during boiler operation.
The use of limited excess air firing, flue gas recirculation, staged combustion, or some combination thereof, may
result in NOX reductions ranging from 5 to 60 percent. (See section 1.4 for a discussion of these techniques.)
Load reduction can likewise decrease NOX production. Nitrogen oxides emissions may be reduced from 0.5 to 1
percent for each percentage reduction in load from full load operation. It should be noted that most of these
variables, with the exception of excess air, are applicable only in large oil-fired boilers. Limited excess air firing is
possible in many small boilers, but the resulting NOX reductions are not nearly as significant.
1.3.2.4 Other Pollutants *' 3"5' 8"10' 14 - As a rule, only minor amounts of hydrocarbons and carbon monoxide
will be produced during fuel oil combustion. If a unit is operated improperly or not maintained, however, the
resulting concentrations of these pollutants may increase by several orders of magnitude. This is most likely to be
the case with small, often unattended units.
1.3.3 Controls
Various control devices and/or techniques may be employed on oil-fired boilers depending on the type of
boiler and the pollutant being controlled. All such controls may be classified into three categories: boiler
modification, fuel substitution, and flue gas cleaning.
1.3.3.1 Boiler Modification1"4'8'9'13'14- Boiler modification includes any physical change in the boiler
apparatus itself or in the operation thereof. Maintenance of the burner system, for example, is important to
assure proper atomization and subsequent minimization of any unburned combustibles. Periodic tuning1 is
important in small units to maximize operating efficiency and minimize pollutant emissions, particularly smoke
and CO. Combustion modifications such as limited excess air firing, flue gas recirculation, staged combustion, and
reduced load operation all result in lowered NOX emissions in large facilities. (See Table 1.3-1 for specific
reductions possible through these combustion modifications.)
1.3.3.2 Fuel Substitution3"5'12 - Fuel substitution, that is, the firing of "cleaner" fuel oils, can substantially
reduce emissions of a number of pollutants. Lower sulfur oils, for instance, will reduce SOX emissions in all
boilers regardless of size or type of unit or grade of oil fired. Particulates will generally be reduced when a better
grade of oil is fired. Nitrogen oxide emissions will be reduced by switching to either a distillate oil or a residual oil
containing less nitrogen. The practice of fuel substitution, however, may be limited by the ability of a given
operation to fire a better grade of oil as well as the cost and availability thereof.
4/76 External Combustion Sources
5-38
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1.3.3.3 Flue Gas Cleaning6' 15~21 - Flue gas cleaning equipment is generally only employed on large oil-fired
boiler;,. Mechanical collectors, a prevalent type of control device, are primarily useful in controlling particulates
generated during soot blowing, during upset conditions, or when a very dirty, heavy oil is fired. During these
situations, high efficiency cyclonic collectors can effect up to 85 percent control pf ^articulate. Under normal
firing conditions, however, or when a clean oil is combusted, cyclonic collectors will not be nearly as effective.
Electrostatic precipitators are commonly found in power plants that at one time fired coal, Precipitators that
were designed for coal flyash provide only 40 to 60 percent control of oil-fired particulate. Collection efficiencies
of up to 90 percent, however, have been reported for new or rebuilt devices that were specifically designed for
oil-firing units.
Scrubbing systems have been installed on oil-fired boilers, especially of late, to control both sulfur oxides and
particulate. These systems can achieve SC>2 removal efficiencies of up to 90 to 95 percent and provide particulate
control efficiencies on the order of 50 to 60 percent. The reader should consult References 20 and 21 for details
on the numerous types of flue gas desulfurization systems currently available or under development.
References for Section 1.3
1. Smith, W. S. Atmospheric Emissions from Fuel Oil Combustion: An Inventory Guide. U.S. DHEW, PHS,
National Center for Air Pollution Control. Cincinnatti, Ohio. PHS Publication No. 999-AP-2. 1962.
2. Air Pollution Engineering Manual. Danielson, J.A. (ed.). Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. AP-40. May 1973. p. 535-577.
3. Levy, A. et al. A Field Investigation of Emissions from Fuel Oil Combustion for Space Heating. Battelle
Columbus Laboratories. Columbus, Ohio. API Publication 4099. November 1971.
4. Barrett, R.E. et al. Field Investigation of Emissions from Combustion Equipment for Space Heating. Battelle
Columbus Laboratories. Columbus, Ohio. Prepared for Environmental Protection Agency, Research Triangle
Park, N.C.. under Contract No. 68-02-0251. Publication No. R2-73-084a. June 1973.
5. Cato, G.A. et al. Field Testing: Application of Combustion Modifications to Control Pollutant Emissions
From Industrial Boilers - Phase I. KVB Engineering, Inc. Tustin, Calif. Prepared for Environmental
Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-1074. Publication No.
EPA-650/2-74-078a. October 1974.
6. Particulate Emission Control Systems For Oil-Fired Boilers. GCA Corporation. Bedford, Mass. Prepared foi
Environmental Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-1316.
Publication No. EPA-450/3-74-063. December 1974.
7. Title 40 - Protection of Environment. Part 60 - Standards of Performance for New Stationary Sources.
Method 5 Determination of Emission from Stationary Sources. Federal Register. 5(5(247): 24888-24890,
December 23, 1971.
8. Bartok, W. et al. Systematic Field Study of NOX Emission Control Methods for Utility Boilers. ESSO
Research and Engineering Co., Linden, N.J. Prepared for Environmental Protection Agency, Research
Triangle Park, N.C., under Contract No. CPA-70-90. Publication No. APTD 1163. December 31, 1971.
9. Crawford, A.R. et al. Field Testing: Application of Combustion Modifications to Control NOX Emissions
From Utility Boilers. Exxon Research and Engineering.Company. Linden, N.J. Prepared for Environmental
Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-0227. Publication No.
EPA-650/2-74-066. June 1974. p. 113-145.
10. Deffner, J.F. et al. Evaluation of Gulf Econoject Equipment with Respect to Air Conservation. Gulf
Research and Development Company. Pittsburgh, Pa. Report No. 731RC044. December 18,1972.
EMISSION FACTORf 4/76
5-39
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11. Blakeslee, C.E. and H.E. Burbach. Controlling NOX Emissions from Steam Generators. J. Air Pol. Control
Assoc. 25:3742, January 1973.
12. Siegmund, C.W. Will Desulfurized Fuel Oils Help? ASHRAE Journal. 7 J: 29-33, April 1969.
13. Govan, F.A. et al. Relationship of Particulate Emissions Versus Partial to Full Load Operations For
Utility-Sized Boilers. In: Proceedings of 3rd Annual Industrial Air Pollution Control Conference, Knoxville,
March 29-30, 1973. p. 424-436.
14. Hall, R.E. et al. A Study of Air Pollutant Emissions From Residential Heating Systems. Environmental
Protection Agency. Research Triangle Park, N.C. Publication No. EPA-650/2-74-003. January 1974.
15. Perry, R.E. A Mechanical Collector Performance Test Report on an Oil Fired Power Boiler. Combustion.
May 1972. p. 24-28.
16. Burdock, J.L. Fly Ash Collection From Oil-Fired Boilers. (Presented at 10th Annual Technical Meeting of
New England Section of APCA, Hartford, April 21, 1966.)
17. Bagwell, F.A. and R.G. Velte. New Developments in Dust Collecting Equipment for Electric Utilities. J. Air
Pol. Control Assoc. 21:781-782, December 1971.
18; Internal memorandum from Mark Hooper to EPA files referencing discussion with the Northeast Utilities
Company. January 13, 1971.
19. Pinheiro, G. Precipitators for Oil-Fired Boilers. Power Engineering. 75:52-54, April 1971.
20. Flue Gas Desulfurization: Installations and Operations. Environmental Protection Agency. Washington, D.C.
September 1974.
21. Proceedings: Flue Gas Desulfurization Symposium - 1973. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-650/2-73-038. December 1973.
4/76 External Combustion Sources
5-40
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1 .4 N ATU RAL GAS COMBUSTION Revised by Thomas Lahre
1.4.1 General U
Natural gas has become one of the major fuels used throughout the country. It is used mainly for power gen-
eration, for industrial process steam and heat production, and for domestic and commercial space heating. The
primary component of natural gas is methane, although varying amounts of ethane and smaller amounts of nitro-
gen, helium, and carbon dioxide are also present. The average gross heating value of natural gas is approximately
1050 Btu/stdft3 (9350 kcal/Nm3), varying generally between 1000 and 1100 Btu/stdft3 (8900 to 9800 kcal/
Nm3).
Because natural gas in its original state is a gaseous, homogenous fluid, its combustion is simple and can be pre-
cisely controlled. Common excess air rates range from 10 to 15 percent; however, some large units operate at
excess air rates as low as 5 percent to maximize efficiency and minimize nitrogen oxide (NOX) emissions.
1.4.2 Emissions and Controls 3-16
Even though natural gas is considered to be a relatively clean fuel, some emissions can occur from the com-
bustion reaction. For example, improper operating conditions, including poor mixing, insufficient air, etc., may
cause large amounts of smoke, carbon monoxide, and hydrocarbons to be produced. Moreover, because a sulfur-
containing mercaptan is added to natural gas for detection purposes, small amounts of sulfur oxides will also be
produced in the combustion process.
Nitrogen oxides are the major pollutants of concern when burning natural gas. Nitrogen oxide emissions are
a function of the temperature in the combustion chamber and the rate of cooling of the combustion products.
Emission levels generally vary considerably with the type and size of unit and are also a function of loading.
In some large boilers, several operating modifications have been employed for NOX control. Staged combus-
tion, for example, including off-stoichiometric firing and/or two-stage combustion, can reduce NOX emissions
by 30 to 70 percent. In off-stoichiometric firing, also called "biased firing," some burners are operated fuel-
rich, some fuel-lean, while others may supply air only. In two-staged combustion, the burners are operated fuel-
rich (by introducing only 80 to 95 percent stoichiometric air) with combustion being completed by air injected
above the flame zone through second-stage "NO-ports." In staged combustion, NOX emissions are reduced be-
cause the bulk of combustion occurs under fuel-rich, reducing conditions.
Other N0x-reducing modifications include low excess air firing and flue gas recirculation. In low excess air
firing, excess air levels are kept as low as possible without producing unacceptable levels of unburned combus-
tibles (carbon monoxide, hydrocarbons, and smoke) and/or other operational problems. This technique can re-
duce 'NOX emissions by 10 to 30 percent primarily because of the lack of availability of oxygen during
combustion. Flue gas recirculation into the primary combustion zone, because the flue gas is relatively cool and
oxygen deficient, can also lower NOX emissions by 20 to 60 percent depending on the amount of gas recircu-
lated. At present only a few systems have this capability, however.
Combinations of the above combustion modifications jimy also be employed to further reduce NOX emissions.
In some boilers, for instance, NOX reductions as high as 70 to 90 percent have been produced as a result of em-
ploying several of these techniques simultaneously. In general, however, because the net effect of any of these
combinations varies greatly, it is difficult to predict what the overall reductions will be in any given unit.
Emission factors for natural gas combustion are presented in Table 1.4-1. Flue gas cleaning equipment has
not been utilized to control emissions from natural gas combustion equipment.
5/74 External Combustion Sources
5-41
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Table 1.4-1. EMISSION FACTORS FOR NATURAL-GAS COMBUSTION
EMISSION FACTOR RATING: A
Pollutant
Particulates3
Sulfur oxides (S02)b
Carbon monoxide0
Hydrocarbons
(asCH4)d
Nitrogen oxides
(N02)e
Type of unit
Power plant
Ib/106ft3
5-15
0.6
17
1
700f-n
kg/1 06 m3
80-240
9.6
272
16
11,200f-"
Industrial process
boiler
Ib/106ft3
5-15
0.6
17
3
(1 20-230) i
kg/1 06 m3
80-240
9.6
272
48
(1920-
3680) i
Domestic and
commercial heating
Ib/106ft3
5-15
0.6
20
8
(80-120)i
kg/106 m3
80-240
9.6
320
128
(1280-
1920)i
a References 4,7,8,12.
bReference 4 (based on an average sulfur content of natural gas of 2000 gr/106 stdft3 (4600 g/106 Nm3).
CReferencesS, 8-12.
^References 8, 9, 12.
e References 3-9, 12-16.
f Use 300 lb/106 stdft3 (4800 kg/106 Nm3) for tangentially fired units.
9At reduced loads, multiply this factor by the load reduction coefficient given in Figure 1.4-1.
nSee text for potential NOX reductions due to combustion modifications. Note that the NOX reduction from these modifications
will also occur at reduced load conditions.
' This represents a typical range for many industrial boilers. For large industrial units (> 100 MMBtu/hr) use the NOX factors pre-
sented for power plants.
i Use 80 (1280) for domestic heating units and 120 (1920) for commercial units.
u
1.0
C 0.8
o
o
o
o
0.6
0.4
0.2
40
60
80
LOAD, percent
100
110
Figure 1.4-1. Load reduction coefficient as function of boiler
load. (Used to determine NOX reductions at reduced loads in
large boilers.)
EMISSION FACTORS
5/74
5-42
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References for Section 1.4
1. High, D. M. et al. Exhaust Gases from Combustion and Industrial Processes. Engineering Science, Inc.
Washington, D.C. Prepared for U.S. Environmental Protection Agency, Research Triangle Park, N.C. under
Contract No. EHSD 71-36, October 2,1971.
2. Perry, J. H. (ed.). Chemical Engineer's Handbook. 4th Ed. New York, McGraw-Hill Book Co., 1963. p. 9-8.
3. Hall, E. L. What is the Role of the Gas Industry in Air Pollution? In: Proceedings of the 2nd National Air
Pollution Symposium. Pasadena, California, 1952. p.54-58.
4. Hovey, H. H., A. Risman, and J. F. Cunnan. The Development of Air Contaminant Emission Tables for Non-
process Emissions. New York State Department of Health. Albany, New York. 1965.
5. Bartok, W. et al. Systematic Field Study of NOX Emission Control Methods for Utility Boilers. Esso Research
and Engineering Co., Linden, N. J. Prepared for U. S. Environmental Protection Agency, Research Triangle
Park, N.C. under Contract No. CPA 70-90, December 31,197f.
6. Bagwell, F. A. et al. Oxides of Nitrogen Emission Reduction Program for Oil and Gas Fired Utility Boilers.
Proceedings of the American Power Conference. Vol.32. 1970. p.683-693.
7. Chass, R. L. and R. E. George. Contaminant Emissions from the Combustion of Fuels, J. Air Pollution Control
Assoc. /0:3443, February 1960.
8. Hangebrauck, R. P., D. S. Von Lehmden, and J. E. Meeker. Emissions of Polynuclear Hydrocarbons and
other Pollutants from Heat Generation and Incineration Processes. J. Air Pollution Control Assoc. 14:211,
July 1964.
9. Dietzmann, H. E. A Study of Power Plant Boiler Emissions. Southwest Research Institute, San Antonio, Texas.
Final Report No. AR-837. August 1972.
10. Private communication with the American Gas Association Laboratories. Cleveland, Ohio. May 1970.
11. Unpublished data on domestic gas-fired units. U.S. Dept. of Health, Education, and Welfare, National Air
Pollution Control Administration, Cincinnati, Ohio. 1970.
12. Barrett, R. E. et al. Field Investigation of Emissions from Combustion Equipment for Space Heating.
Battelle-Columbus Laboratories, Columbus, Ohio. Prepared for U.S. Environmental Protection Agency,
Research Triangle Park, N.C. under Contract No. 68-02-0251. Publication No. EPA-R2-73-084. June 1973.
13. Blakeslee, C. E. and H, E. Burbock. Controlling NOX Emissions from Steam Generators. J. Air Pollution
Control Assoc. 25:37-42, January 1973.
14. Jain, L. K. et al. "State of the Art" for Controlling NOX Emissions. Part 1. Utility Boilers. Catalytic, Inc.,
Charlotte, N. C. Prepared for U.S. Environmental Protection Agency under Contract No. 68-02-0241 (Task
No. 2). September 1972.
15. Bradstreet, J. W. and JR. J. Fortman. Status of Control.Techniques for Achieving Compliance with Ah- Pollu-
tion Regulations by the Electric Utility Industry. (Presented at the 3rd Annual Industrial Air Pollution
Control Conference. Knoxville, Tennessee. March 29-30; 1973.)
16. Study of Emissions of NOX from Natural Gas-Fired Steam Electric Power Plants in Texas. Phase II. Vol. 2.
Radian Corporation, Austin, Texas. Prepared for the Electric Reliability Council of Texas. May 8, 1972.
5/74 External Combustion Sources
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1.5 LIQUEFIED PETROLEUM GAS COMBUSTION Revised by Thomas Lahre
1.5.1 General1
Liquefied petroleum gas, commonly referred to as LPG, consists mainly of butane, propane, or a mixture of
the two, and of trace amounts of propvlene and butylene. This gas, obtained from oil or gas wells as a by-product
of gasoline refining, is sold as a liquid in metal cylinders under pressure and, therefore, is often called bottled gas.
LPG is graded according to maximum vapor pressure with Grade A being predominantly butane, Grade F
being predominantly propane, and Grades B through E consisting of varying mixtures of butane and propane. The
heating value of LPG ranges from 97,400 Btu/gallon (6,480 Real/liter) for Grade A to 90,500 Btu/gallon (6,030
kcal/liter) for Grade F. The largest market for LPG is the domestic-commercial market, followed by the chemical
industry and the internal combustion engine.
1.5.2 Emissions1
LPG is considered a "clean" fuel because it does not produce visible emissions. Gaseous pollutants such as
carbon monoxide, hydrocarbons, and nitrogen oxides do occur, however. The most significant factors affecting
these emissions are the burner design, adjustment, and venting.2 Improper design, blocking and clogging of the
flue vent, and lack of combustion air result in improper combustion that causes the emission of aldehydes, carbon
monoxide, hydrocarbons, and other organics. Nitrogen oxide emissions are a function of a number of variables
including temperature, excess air, and residence time in the combustion zone. The amount of sulfur dioxide
emitted is directly proportional to the amount of sulfur in the fuel. Emission factors for LPG combustion are
presented in Table 1.5-1.
References for Section 1.5
1. Air Pollutant Emission Factors. Final Report. Resources Research, Inc. Reston, Va. Prepared for National
Air Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119. April 1970.
2. Clifford, E.A. A Practical Guide to Liquified Petroleum Gas Utilization. New York, Moore Publishing Co.
1962.
4/77 External Combustion Sources
5-44
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Table 1.5-1. EMISSION FACTORS FOR LPG COMBUSTION
EMISSION FACTOR RATING: C
Pollutant
Participates
Sulfur oxides!1
Carbon monoxide
Hydrocarbons
Nitrogen oxides0
Industrial process furnaces
Butane
lb/103 gal
1.8
0.09S
1.6
0.3
12.1
kg/103 liters
0.22
0.01S
0.19
0.036
1.45
Propane
lb/103 gal
1.7
0.09S
1.5
0.3
11.2
kg/103 liters
0.20
0.01S
0.18
0.036
1.35
Domestic and commercial furnaces
Butane
lb/103 gal
1.9
0.09S
2.0
0.8
(8to12)d
kg/103 liters
0.23
0.0 1S
0.24
0.096
(1.0to1.5)d
Propane
lb/103 gal
1.8
0.09S
1.9
0.7
{7to11)d
kg/103 liters
0.22
0.01S
0.23
0.084
(0.8to1.3)d
in
*»
in
"LPG emission factors calculated assuming emissions (excluding'sulfur oxides) are the same, on a heat input basis, as for natural gas combustion.
bS equals sulfur content expressed in grains per 100 ft3 gas vapor; e.g., if the sulfur content is 0.16 grain per 100 ft3 (0.366 g/100 m3) vapor, the SO2 emission factor would be
0.09 x 0.16 or 0.014 Ib SO2 per 1000 gallons (0.01 x 0.366 or 0.0018 kg SO2/103 liters) butane burned.
'Expressed as NO2*
dUse lower value for domestic units and higher value for commercial units.
o
90
to
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1.6 WOOD/BARK WASTE COMBUSTION IN BOILERS Revised by Thomas Lahre
1.6.1 General 1-3
Today, the burning of wood/bark waste in boilers is largely confined to those industries where it is available as
a by-product. It is burned both to recover heat energy and to alleviate a potential solid waste disposal problem.
Wood/bark waste may include large pieces such as slabs, logs, and bark strips as well as smaller pieces such as ends,
shavings, and sawdust. Heating values for this waste range from 8000 to 9000 Btu/lb, on a dry basis; however,
because of typical moisture contents of 40 to 75 percent, the as-fired heating values for many wood/bark waste
materials range as low as 4000 to 6000 Btu/lb. Generally, bark is the major type of waste burned in pulp mills;
whereas, a variable mixture of wood and bark waste, or wood waste alone, is most frequently burned in 'he
lumber, furniture, and plywood industries.
1.6.2 Firing Practices1'3
A variety of boiler firing configurations are utilized for burning wood/bark waste. One common type in
smaller operations' is the Dutch Oven, or extension type of furnace with a flat grate. In this unit the fuel is fed
through the furnace roof and burned in a cone-shaped pile on the grate. In many other, generally larger, opera-
tions, more conventional boilers have been modified to burn wood/bark waste. These units may include spreader
stokers with traveling grates, vibrating grate stokers, etc., as well as tangentially fired or cyclone fired boilers.
Generally, an auxiliary fuel is burned in these units to maintain constant steam when the waste fuel supply fluctu-
ates and/or to provide more steam than is possible from the waste supply alone.
1.6.3 Emissions 1.2,4-8
The major pollutant of concern from wood/bark boilers is particulate matter although other pollutants, par-
ticularly carbon monoxide, may be emitted in significant amounts under poor operating conditions. These
emissions depend on a number of variables including (1) the composition of the waste fuel burned, (2) the degree
of fly-ash reinjection employed, and (3) furnace design and operating conditions.
The composition of wood/bark waste depends largely on the industry from whence it originates. Pulping op-
erations, for instance, produce great quantities of bark that may contain more than 70 percent moisture (by
weight) as well as high levels of sand and other noncombustibles. Because of this, bark boilers in pulp mills may
emit considerable amounts of particulate matter to the atmosphere unless they are well controlled. On the other
hand, some operations such as furniture manufacture, produce a clean, dry (5 to 50 percent moisture) wood
waste that results in relatively few particulate emissions when properly burned. Still other operations, such as
sawmills, bum a variable mixture of baik and wood waste that results in particulate emissions somewhere in be-
tween these two extremes.
Fly-ash reinjection, which is commonly employed in many larger boilers to improve fuel-use efficiency, has a
considerable effect on particulate emissions. Because a fraction of the collected fly-ash is reinjected into the
boiler, the dust loading from the furnace, and consequently from the collection device, increases significantly
per ton of wood waste burned. It is reported that full reinjection can cause a 10-fold increase in the dust load-
ings of some systems although increases of 12 to 2 times are more typical for boilers employing 50 to 100 per-
cent reinjection. A major factor affecting this dust loading increase is the extent to which the sand and other
non-combustibles can be successfully separated from the fly-ash before reinjection to the furnace.
Furnace design and operating conditions are particularly important when burning wood and bark waste. For
example, because of the high moisture content in this waste, a larger area of refractory surface should be provided
to dry the fuel prior to combustion. In addition, sufficient secondary air must be supplied over the fuel bed to
burn the volatiles that account for most of the combustible material in the waste. When proper drying conditions
5/74 External Combustion Sources
5-46
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do not exist, or when sufficient secondary air is not available, the combustion temperature is lowered, incomplete
combustion occurs, and increased particulate, carbon monoxide, and hydrocarbon emissions will result.
Emission factors for wood waste boilers are presented in Table 1.6-1. For boilers where fly-ash reinjection
is employed, two factors are shown: the first represents the dust loading reaching the control equipment; the
value in parenthesis represents the dust loading after controls assuming about 80 percent control efficiency. All
other factors represent uncontrolled emissions.
Table 1.6-1. EMISSION FACTORS FOR WOOD AND BARK WASTE COMBUSTION IN BOILERS
EMISSION FACTOR RATING: B
Pollutant
Particulates3
Barkb.c
With fly-ash reinjectiond
Without fly-ash reinjection
Wood/bark mixture15'6
With fly-ash reinjection01
Without fly-ash reinjection
Woodf.3
Sulfur oxides (S02)h-'
Carbon monoxide)
Hydrocarbons'4
Nitrogen oxides (N02)1
Emissions
Ib/ton
75(15)
50
45(9)
30
5-15
1.5
2-60
2-70
10
kg/MT
37.5 (7.5)
25
22.5 (4.5)
15
2.5-7.5
0.75
1-30
1-35
5
aThese emission factors were determined for boilers burning gas or oil as an auxiliary fuel, and it was assumed all participates
resulted from the waste fuel alone. When coal is burned as an auxiliary fuel, the appropriate emission factor from Table 1.1-2
should be used in addition to the above factor.
'These factors based on an as-fired moisture content of 50 percent.
•^References 2, 4, 9.
'This factor represents a typical dust loading reaching the control equipment for boilers employing fly-ash reinjection. The value
jr^parenthesis represents emissions after the control equipment assuming an average efficiency of 80 percent.
eRef erences 7, 1 0.
f This waste includes clean, dry (5 to 50 percent moisture) sawdust, shavings, ends, etc., and no bark. For well designed and
operated boilers use lower value and higher values for others. This factor is expressed on an as-fired moisture content basis as-
suming no fly-ash reinjection.
SReferences 11-1 a
"This factor is calculated by material balance assuming a maximum sulfur content of 0.1 percent in the waste. When auxiliary
fuels are burned, the appropriate factors from Tables 1.1-2, 1.3-1, or 1.4-1 should be used in addition to determine sulfur oxide
emissions.
'References 1, 5, 7.
'This factor is based on engineering judgment and limited data from references 1 1 through 1 3. Use lower values for well designed
and operated boilers.
kThis factor is based on limited data from references 13 through 15. Use lower values for well designed and operated boilers.
1 Reference 1 6.
References for Section 1.6
1. Steam, Its Generation and Use, 37th Ed. New York, Babcock and Wilcox Co., 1963. p. 19-7 to 19-10 and
3-A4.
2. Atmospheric Emissions from the Pulp and Paper Manufacturing Industry. U.S. Environmental Protection
Agency, Research Triangle Park, N.C. Publication No. EPA-450/1 -73-002. September 1973.
EMISSION FACTORS
5/74
5-47
-------
3. C-E Bark Burning Boilers. Combustion Engineering, Inc., Windsor, Connecticut. 1973.
4. Barren, Jr., Alvah. Studies on the Collection of Bark Char Throughout the Industry. TAPPI. 53(8): 1441-1448,
August 1970.
5. Kreisinger, Henry. Combustion of Wood-Waste Fuels. Mechanical Engineering. 61:115-120, February 1939.
6. Magill,P..L.etal. (eds.). Air Pollution Handbook. New York, McGraw-Hill Book Co., 1956. p. 1-15 and 1-16.
7. Air Pollutant Emission Factors. Final Report. Resources Research, Inc., Reston, Virginia. Prepared for U.S.
Environmental Protection Agency, Durham, N.C. undei Contract No. CPA-22-69-119. April 1970. p. 247 to
2-55..
8. Mullen, J. F. A Method for Determining Combustible Loss, Dust Emissions, and Recirculated Refuse fora
Solid Fuel Burning System. Combustion Engineering, Inc., Windsor, Connecticut.
9. Source test data from Alan Lindsey, Region IV, U.S. Environmental Protection Agency, Atlanta, Georgia.
May 1973.
10. Effenberger, H. K. et al. Control of Hogged-Fuel Boiler Emissions: A Case History. TAPPI. 56(2):111-115,
February 1973.
11. Source test data from the Oregon Department of Environmental Quality, Portland, Oregon. May 1973.
12. Source test data from the Illinois Environmental Protection Agency, Springfield, Illinois. June 1973.
13. Danielson, J. A. (ed.). Air Pollution Engineering Manual. U.S. Department of Health, Education, and Welfare,
PHS, National Center for Air Pollution Control, Cincinnati, Ohio. Publication No. 999-AP-40. 1967.
p. 436439.
14. Droege, H. and G. Lee. The Use of Gas Sampling and Analysis for the Evaluation of Teepee Burners. Bureau
of Air Sanitation, California Department of Public Health. (Presented at the 7th Conference on Methods in
Air Pollution Studies, Los Angeles. January 1967.)
15. Junge, D. C. and R. Kwan. An Investigation of the Chemically Reactive Constituents of Atmospheric Emis-
sions from Hog-Fuel Boilers in Oregon. PNWIS-APCA Paper No. 73-AP-21. November 1973.
16. Galeano, S. F. and K. M. Leopold. A Survey of Emissions of Nitrogen Oxides in the Pulp Mill. TAPPI.
5<5(3):74-76, March 1973.
5/74 External Combustion Sources
5-48
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1.7 LIGNITE COMBUSTION by Thomas Lahre
1.7.1 General^
Lignite is a geologically young coal whose properties are intermediate to those of bituminous coal and peat. It
has a high moisture content (35 to 40 percent, by weight) and a low heating value (6000 to 7500 Btu/lb, wet
basis) and is generally only burned close to where it ic mined, that is, in the midwestern States centered about
North Dakota and in Texas. Although a small amount is used in industrial and domestic situations, lignite is
mainly used for steam-electric production in power plants. In the past, lignite was mainly burned in small stokers;
today the trend is toward use in much larger pulverized-coal-fired or cyclone-fired boilers.
The major advantage to firing lignite is that, in certain geographical areas, it is plentiful, relatively low in cost,
and low in sulfur content (0.4 to 1 percent by weight, wet basis). Disadvantages are that more fuel and larger
facilities are necessary to generate each megawatt of power than is the case with bituminous coal. There are
several reasons for this. First, the higher moisture content of lignite means that more energy is lost in the gaseous
products of combustion, which reduces boiler efficiency. Second, more energy is required to grind lignite to the
specified size needed for combustion, especially in pulverized coal-fired units. Third, greater lube spacing and
additional soot blowing are required because of the higher ash-fouling tendencies of lignite. Fourth, because of its
lower heating value, more fuel must be handled to produce a given amount of power because lignite is not
generally cleaned or dried prior to combustion (except for some drying that may occur in the crusher or
pulverizer and during subsequent transfer to the burner). Generally, no major problems exist with the handling or
combustion of lignite when its unique characteristics are taken into account.
1.7.2 Emissions and Controls 2'8
The major pollutants of concern when firing lignite, as with any coal, are participates, sulfur oxides, and
nitrogen oxides. Hydrocarbon and carbon monoxide emissions are usually quite low under normal operating
conditions.
Particulate emissions appear most dependent on the firing configuration in the boiler. Pulverized-coal-fired
units and spreader stokers, which fire all or much of the lignite in suspension, emit the greatest quantity of flyash
per unit of fuel burned. Both cyclones, which collect much of the ash as molten slag in the furnace itself, and
stokers (other than spreader stokers), which retain a large fraction of the ash in the fuel bed, emit less particulate
matter. In general, the higher sodium content of lignite, relative to other coals, lowers particulate emissions by
causing much of the resulting flyash to deposit on the boiler tubes. This is especially the case in
pulverized-coal-fired units wherein a high fraction of the ash is suspended in the combustion gases and can readily
come into contact with the boiler surfaces.
Nitrogen oxides emissions are mainly a function of the boiler firing configuration and excess air. Cyclones
produce the highest NOX levels, primarily because of the high heat-release rates and temperatures reached in the
small furnace sections of the boiler. Pulverized-coal-fired boilers produce less NOX than cyclones because
combustion occurs over a larger volume, which results in lower peak flame temperatures. Tangentiafly fired
boilers produce the lowest NO levels in this category. Stokers produce the lowest NOX levels mainly because
most existing units are much smaller than the other firing types. In most boilers, regardless of firing
configuration, lower excess air during combustion results in lower NOV emissions.
A
Sulfur oxide emissions are a function of the alkali (especially sodium) content of the lignite ash. Unlike most
fossil fuel combustion, in which over 90 percent of the fuel sulfur is emitted as SOj, a significant fraction of
the sulfur in lignite reacts with the ash components during combustion and is retained in the boiler ash deposits and
flyash. Tests have shown that less than 50 percent of the available sulfur may be emitted as SOj when a
high-sodium lignite is burned, whereas, more than 90 percent may be emitted with low-sodium lignite. As a rough
average, about 75 percent of the fuel sulfur will be emitted as S02, with the remainder being converted to various
sulfate salts.
12/75 External Combustion Sources
5-49
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Air pollution controls on lignite-fired boilers in the United States have mainly been limited to cyclone
collectors, which typically achieve 60 to 75 percent collection efficiency on lignite flyash. Electrostatic
precipitators, which are widely utilized in Europe on lignitic coals and can effeclt 99+ percent particulate control,
have seen only limited application in the United States to date although their use will probably become
widespread on newer units in the future.
Nitrogen oxides reduction (up to 40 percent) has been demonstrated using low excess air firing and staged
combustion (see section 1.4 for a discussion of these techniques); it is not yet known, however, whether these
techniques can be continuously employed on lignite combustion units without incurring operational problems.
Sulfur oxides reduction (up to 50 percent) and some particulate control can be achieved through the use of high
sodium lignite. This is not generally considered a desirable practice, however, because of the increased ash fouling
that may result.
Emission factors for lignite combustion are presented in Table 1.7-1.
Table 1.7-1. EMISSIONS FROM LIGNITE COMBUSTION WITHOUT CONTROL EQUIPMENT9
EMISSION FACTOR RATING: B
Pollutant
Particulateb
Sulfur oxides6
Nitrogen
oxides*
Hydrocarbons'
Carbon
monoxide1
Type of boiler
Pulverized -coal
Ib/ton
7.0AC
30S
14(8)9.h
<1.0
1.0
kg/MT
3.5AC
15S
7(4)9-h
<0.5
0.5
Cyclone
Ib/ton
6A
30S
17
<1.0
1.0
kg/MT
3A
15S
8.5
<0.5
0.5
Spreaker stoker
Ib/ton
7.0Ad
305
6
1.0
2
kg/MT
3.5Ad
15S
3
0.5
1
Other stokers
Ib/ton
3.0A
SOS
6
1.0
2
kg/MT
1.5A
15S
3
0.5
1
3AII emission factors are expressed in terms of pounds of pollutant per ton (kilograms of pollutant per metric ton) of lignite burned,
wet basis (35 to 40 percent moisture,.by weight).
bA is the ash content of the lignite by weight, wet basis. Factors based on References 5 and 6.
cThis factor is based on data for dry-bottom, pulverized-coal-fired units only. It is expected that this factor would be lower for wet-
bottom units.
d Limited data preclude any determination of the effect of flyash reinjection. It is expected that particulate emissions would be
greater when reinjection is employed.
eS is the sulfur content of the lignite by weight, wet basis. For a high sodium-ash lignite (Na2O > 8 percent) use 17S Ib/ton (8.5S
kg/MT); for a low sodium-ash lignite (Na2O < 2 percent), use 35S Ib/ton (17.5S kg/MT). For intermediate sodium-ash lignite, or
when the sodium-ash content is unknown, use 30S Ib/ton (15S kg/MT)). Factors based on References 2, 5, and 6.
Expressed as NO2- Factors based on References 2, 3, 5, 7, and 9.
9Use 14 Ib/ton (7 kg/MT) for front-wall-fired and horizontally opposed wall-fired units and 8 Ib/ton (4 kg/MT) for tangentially
fired units.
"Nitrogen oxide emissions may be reduced by 20 to 40 percent with low excess air firing and/or staged combustion in front-fired
and opposed-wall-fired units and cyclones.
'These factors are based on the similarity of lignite combustion to bituminous coal combustion and on limited data in Reference 7.
References for Section 1.7
1. Kirk-Othmer Encyclopedia of Chemical Technology. 2nd Ed. Vol. 12. New York, John Wiley and Sons, 1967.
p. 381413.
2. Gronhovd, G. H. et al. Some Studies on Stack Emissions from Lignite-Fired Powerplants. (Presented at the
1973 Lignite Symposium. Grand Forks, North Dakota. May 9-10,1973.)
3. Study to Support Standards of Performance for New Lignite-Fired Steam Generators. Summary Report.
Arthur D. Little, Inc., Cambridge, Massachusetts. Prepared for U.S. Environmental Protection Agency,
Research Triangle Park, N.C. under contract No. 68-02-1332. July 1974.
EMISSION FACTORS
5-50
12/75
-------
4. 1965 Keystone Coal Buyers Manual. New York, McGraw-Hill, Inc., 1965. p. 364-365.
5. Source test data on lignite-fired power plants. Supplied by North Dakota State Department of Health,
Bismark, N.D. December 1973.
6. Gronhovd, G.H. et al. Comparison of Ash Fouling Tendencies of High and Low-Sodium Lignite from a North
Dakota Mine. In: Proceedings of the American Power Conference. Vol. XXVIII. 1966. p. 632-642.
7. Crawford, A. R. et al. Field Testing: Application of Combustion Modifications to Control NOX Emissions
from Utility Boilers. Exxon Research and Engineering Co.; Linden, NJ. Prepared for U.S. Environmental
Protection Agency, Research Triangle Park, N.C. under Contract No. 68-02-0227. Publication Number
EPA-650/2-74-066. June 1974.
8. Engelbrecht, H. L. Electrostatic Precipitators in Thermal Power Stations Using Low Grade Coal. (Presented at
28th Annual Meeting of the American Power Conference. April 26-28, 1966.)
9. Source test data from U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, N.C. 1974.
12/75 External Combustion Sources
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1.8 BAGASSE COMBUSTION IN SUGAR MILLS by Tom Lahre
1.8.1 General1
Bagasse is the fibrous residue from sugar cane that has been processed in a sugar mill. (See Section
6.12 for a brief general description of sugar cane processing.) It is fired in boilers to eliminate a large
solid waste disposal problem and to produce steam and electricity to meet the mill's power require-
ments. Bagasse represents about 30 percent of the weight of the raw sugar cane. Because of the high
moisture content (usually at least 50 percent, by weight) a typical heating value of wet bagasse will
range from 3000 to 4000 Btu/lb (1660 to 2220 kcal/kg). Fuel oil may be fired with bagasse when the
mill's power requirements cannot be met by burning only bagasse or when bagasse is too wet to support
combustion.
The United States sugar industry is located in Florida, Louisiana, Hawaii, Texas, and Puerto Rico.
Except in Hawaii, where raw sugar production takes place year round, sugar mills operate seasonally,
from 2 to 5 months per year.
Bagasse is commonly fired in boilers employing either a solid hearth or traveling grate. In the for-
mer, bagasse is gravity fed through chutes and forms a pile of burning fibers. The burning occurs on
the surface of the pile with combustion air supplied through primary and secondary ports located in
the furnace walls. This kind of boiler is common in older mills in the sugar cane industry. Newer boil-
ers, on the other hand, may employ traveling-grate stokers. Underfire air is used to suspend the ba-
gasse, and overfired air is supplied to complete combustion. This kind of boiler requires bagasse with a
higher percentage of fines, a moisture content not over 50 percent, and more experienced operating
personnel.
1.8.2 Emissions and Controls1
Particulate is the major pollutant of concern from bagasse boilers. Unless an auxiliary fuel is fired,
few sulfur oxides will be emitted because of the low sulfur content (<0.1 percent, by weight) of ba-
gasse. Some nitrogen oxides are emitted, although the quantities appear to be somewhat lower (on an
equivalent heat input basis) than are emitted from conventional fossil fuel boilers.
Particulate emissions are reduced by the use of multi-cyclones and wet scrubbers. Multi-cyclones
are reportedly 20 to 60 percent efficient on participate from bagasse boilers, whereas scrubbers (either
venturi or the spray impingement type) are usually 90 percent or more efficient. Other types of con-
trol equipment have been investigated but have not been found to be practical.
Emission factors for bagasse fired boilers are shown in Table 1.8-1.
4/77 External Combustion Sources
5-52
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Table 1.8-1. EMISSION FACTORS FOR UNCONTROLLED BAGASSE BOILERS
EMISSION FACTOR RATING: C
Participate0
Sulfur oxides
Nitrogen oxides6
Emission factors
lb/103lb steam3
4
d
0.3
g/kg steam3
4
d
0.3
Ib/ton bagasse*3
16
d
1.2
kg/MT bagasseb
8
d
0.6
Emission factors are expressed in terms of the amount of steam produced, as most mills do not monitor the
amount of bagasse fired. These factors should be applied only to that fraction of steam resulting from bagasse
combustion. If a significant amount (>25% of total Btu input) of fuel oil is fired with the bagasse, the appropriate
emission factors from Table 1.3-1 should be used to estimate the emission contributions from the fuel oil.
Emissions are expressed in terms of wet bagasse, containing approximately 50 percent moisture, by weight.
As a rule of thumb,, about 2 pounds (2 kg) of steam are produced from 1 pound (1 kg) of wet bagasse.
c Multi-cyclones are reportedly 20 to 60 percent efficient on paniculate from bagasse boilers. Wet scrubbers
are capable of effecting 90 or more percent paniculate control. Based on Reference 1.
dSulfur oxide emissions from the firing of bagasse alone would be expected to be negligible as bagasse typically
contains less than 0.1 percent sulfur, by weight. If fuel oil is fired with bagasse, the appropriate factors from
Table 1.3-1 should be used to estimate sulfur oxide emissions.
eBased on Reference 1.
Reference for Section 1.8
1. Background Document: Bagasse Combustion in Sugar Mills. Prepared by Environmental Science
and Engineering, Inc., Gainesville, Fla., for Environmental Protection Agency under Contract
No. 68-02-1402, Task Order No. 13. Document No. EPA-450/3-77-007. Research Triangle Park, N.C.
October 1976.
EMISSION FACTORS
5-53
4/77
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1.9 RESIDENTIAL FIREPLACES by Tom Lahre
1.9.1 General1.2
Fireplaces are utilized mainly in homes, lodges, etc., for supplemental heating and for their aesthet-
ic effect. Wood is most commonly burned in fireplaces; however, coal, compacted wood waste "logs,"
paper, and rubbish may all be burned at times. Fuel is generally added to the fire by hand on an inter-
mittent basis.
Combustion generally takes place on a raised grate or on the floor of the fireplace. Combustion air
is supplied by natural draft, and may be controlled, to some extent, by a damper located in the chim-
ney directly above the firebox. It is common practice for dampers to be left completely open during
the fire, affording little control of the amount of air drawn up the chimney.
Most fireplaces heat a room by radiation, with a significant fraction of the heat released during com-
bustion (estimated at greater than 70 percent) lost in the exhaust gases or through the fireplace walls.
In addition, as with any fuel-burning, space-heating device, some of the resulting heat energy must go
toward warming the air that infiltrates into the residence to make up for the air drawn up the chimney.
The net effect is that fireplaces are extremely inefficient heating devices. Indeed, in cases where com-
bustion is poor, where the outside air is cold, or where the fire is allowed to smolder (thus drawing air
into a residence without producing apreciable radiant heat energy) a net heat loss may occur in a resi-
dence due to the use of a fireplace. Fireplace efficiency may be improved by a number of devices that
either reduce the excess air rate or transfer some of the heat back into the residence that is normally
lost in the exhaust gases or through the fireplace walls.
1.9.2 Emissions1)2
The major pollutants of concern from fireplaces are unburnt combustibles-carbon monoxide and
smoke. Significant quantities of these pollutants are produced because fireplaces are grossly ineffi-
cient combustion devices due to high, uncontrolled excess air rates, low combustion temperatures, aiid
the absence of any sort of secondary combustion. The last of these is especially important when burn-
ing wood because of its typically high (80 percent, on a dry weight basis)3 volatile matter content.
Because most wood contains negligible sulfur, very few sulfur oxides are emitted. Sulfur oxides will
be produced, of course, when coal or other sulfur-bearing fuels are burned. Nitrogen oxide emissions
from fireplaces are expected to be negligible because of the low combustion temperatures involved.
Emission factors for wood and coal combustion in residential fireplaces are given in Table 1.9-1.
4/77 External Combustion Sources
5-54
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Table 1.9-1. EMISSION FACTORS FOR RESIDENTIAL FIREPLACES
EMISSION FACTOR RATING: C
Pollutant
Paniculate
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Carbon monoxide
Wood
Ib/ton
20b
Od
If
59
120"
kg/MT
1Qb
Od
0.5f
2.59
60h
Coal3
Ib/ton
30C
36Se
3
20
90
kg/MT
15C
36Se
1.5
10
45
aAII coal emission factors, except paniculate, are based on data in Table 1.1-2
of Section 1.1 for hand-fired units.
"This includes condensable paniculate. Only about 30 percent of this is filter-
able paniculate as determined by EPA Method 5 (front-half catch).4 Based
on limited data from Reference 1.
cThis includes condensable paniculate. About 50 percent of this is filterable
particulate as determined by EPA Method 5 (front-half catch}.4 Based on
limited data from Reference 1.
Based on negligible sulfur content in most wood.3
eS is the sulfur content, on a weight percent basis, of the coal.
'Based on data in Table 2.3-1 in Section 2.3 for wood waste combustion in
(conical burners.
9 N on me thane volatile hydrocarbons. Based on limited data from Reference 1.
n Based on limited data from Reference 1.
References for Section 1.9
1. Snowden, W.D., et al. Source Sampling Residential Fireplaces for Emission Factor Development.
Valentine, Fisher and Tomlinson. Seattle, Washington. Prepared for Environmental Protection
Agency, Research Triangle Park, N.C, under Contract 68-02-1992. Publication No. EPA-450/3-
76-010. November 1975.
2. Snowden, W.D., and I. J. Primlani. Atmospheric Emissions From Residential Space Heating. Pre-
sented at the Pacific Northwest International Section of the Air Pollution Control Association
Annual Meeting. Boise, Idaho. November 1974.
3. Kreisinger, Henry. Combustion of Wood-Waste Fuels. Mechanical Engineering. 6J: 115, February
1939.
4. Title 40 • Protection of Environment. Part 60: Standards of Performance for New Stationary
Sources. Method 5 - Detemination of Emission from Stationary Sources. Federal Register. 36
(247): 24888-24890, December 23, 1971.
EMISSION FACTORS
4/77
5-55
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2. SOLID WASTE DISPOSAL
Revised by Robert Rosens tee I
As defined in the Solid Waste Disposal Act of 1965, the term "solid waste" means garbage, refuse, and other
discarded solid materials, including solid-waste materials resulting from industrial, commercial, and agricultural
operations, and from community activities. It includes both combustibles and noncombustibles.
l
Solid wastes may be classified into four general categories: urban, industrial, mineral, and agricultural.
Although urban wastes represent only a relatively small part of the total solid wastes produced, this category has
a large potential for air pollution since in heavily populated areas solid waste is often burned to reduce the bulk
of material requiring final disposal.1 The following discussion'will be limited to the urban and industrial waste
categories.
An average of 5.5 pounds (2.5 kilograms) of urban refuse and garbage is collected per capita per day in the
United States.2 This figure does not include uncollected urban and industrial wastes that are disposed of by other
means. Together, uncollected urban and industrial wastes contribute at least 4.5 pounds (2.0 kilograms) per
capita per day. The total gives a conservative per capita generation rate of 10 pounds (4.5 kilograms) per day of
urban and industrial wastes. Approximately 50 percent of all the urban and industrial waste generated in the
United States is burned, using a wide variety of combustion methods with both enclosed and open
burning3. Atmospheric emissions, both gaseous and particulate, result from refuse disposal operations that use
combustion to reduce the quantity of refuse. Emissions from these combustion processes cover a wide range
because of their dependence upon the refuse burned, the method of combustion or incineration, and other
factors. Because of the large number of variables involved, it is not possible, in general, to delineate when a higher
or lower emission factor, or an intermediate value should be used. For this reason, an average emission factor has
been presented.
References
1. Solid Waste - It Will Not Go Away. League of Women Voters of the United States. Publication Number 675.
April 1971.
2. Black, R.J., H.L. Hickman, Jr., AJ. Klee, A.J. Muchick, and R.D. Vaughan. The National Solid Waste
Survey: An Interim Report. Public Health Service, Environmental Control Administration. Rockville, Md.
1968.
3. Nationwide Inventory of Air Pollutant Emissions, 1968. U.S. DHEW, PHS, EHS, National Air Pollution
Control Administration. Raleigh, N.C. Publication Number AP-73. August 1970.
4/73
5-56
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2.1 REFUSE INCINERATION Revised by Robert Rosensteel
2.1.1 Process Descrip tionl ~4
The most common types of incinerators consist of a refractory-lined chamber with a grate upon which refuse
is burned. In some newer incinerators water-walled furnaces are used. Combustion products are formed by
heating and burning of refuse on the grate. In most cases, since insufficient underfire (undergrate) air is provided
to enable complete combustion, additional over-fire air is admitted above the burning waste to promote complete
gas-phase combustion. In multiple-chamber incinerators, gases from the primary chamber flow to a small
secondary mixing chamber where more air is admitted, and more complete oxidation occurs. As much as 300
percent excess air may be supplied in order to promote oxidation of combustibles. Auxiliary burners are
sometimes installed in the mixing chamber to increase the combustion temperature. Many small-size incinerators
are single-chamber units in which gases are vented from the primary combustion chamber directly into the
exhaust stack. Single-chamber incinerators of this type do not meet modern air pollution codes.
2.1.2 Definitions of Incinerator Categories1
No exact definitions of incinerator size categories exist, but for this report the following general categories and
descriptions have been selected:
1. Municipal incinerators — Multiple-chamber units often have capacities greater than 50 tons (45.3 Ml)
per day and are usually equipped with automatic charging mechanisms, temperature controls, and
movable grate systems. Municipal incinerators are also usually equipped with some type of particulate
control device, such as a spray chamber or electrostatic precipitator.
2. Industrial/commercial incinerators — The capacities of these units cover a wide range, generally between
50 and 4,000 pounds (22.7 and 1,800 kilograms) per hour. Of either single- or multiple-chamber design,
these units are often manually charged and intermittently operated. Some industrial incinerators are
similar to municipal incinerators in size and design. Better designed emission control systems include
gas-fired afterburners or scrubbing, or both.
3. Trench Incinerators - A trench incinerator is designed for the combustion of wastes having relatively high
heat content and low ash content. The design of the unit is simple: a U-shaped combustion chamber is
formed by the sides and bottom of the pit and air is supplied from nozzles along the top of the pit. The
nozzles are directed at an angle below the horizontal to provide a curtain of air across the top of the pit
and to provide air for combustion in the pit. The trench incinerator is not as efficient for burning wastes
as the municipal multiple-chamber unit, except where careful precautions are taken to use it for disposal
of low-ash, high-heat-content refuse, and where special attention is paid to proper operation. Low
construction and operating costs have resulted in the use of this incinerator to dispose of materials other
than those for which it was originally designed. Emission factors for trench incinerators used to burn
three such materials7 are included in Table 2.1-1.
4. Domestic incinerators - This category includes incinerators marketed for residential use. Fairly simple in
design, they may have single or multiple chambers and usually are equipped with an auxiliary burner to
aid combustion.
EMISSION FACTORS
5-57
-------
Table 2.1-1. EMISSION FACTORS FOR REFUSE INCINERATORS WITHOUT CONTROLS"
EMISSION FACTOR RATING: A
Incinerator type
Municipal6
Multiple chamber, uncontrolled
With settling chamber and
water spray system'
Industrial/commercial
Multiple chambers
Single chamber'
Trench'
Wood
Rubber tires
Municipal refuse
Controlled airm
Flue-fed single chamber"
Flue-fed (modified)0-0
Domestic single chamber
Without primary burner*'
With primary bumerr
Pathological5
Particulates
Ib/ton
30
14
7
15
13
138
37
1.4
30
6
35
7
8
kg/MT
15
7
3.5
7.5
6.5
69
18.5
0.7
15
3
17.5
3.5
4
Sulfur oxides'3
Ib/ton
2.5
2.5
2.5h
2.5h
0.1k
NA
2.5h
1.5
0.5
0.5
0.5
0.5
Neg
kg/MT
1.25
1.25
1.25
1.25
0.05
NA
1.25
0.75
0.25
0.25
0.25
0.25
Neg
Carbon monoxide
Ib/ton
35
35
10
20
NA1
NA
NA
Neg
20
10
300
Neg
Neg
kg/MT
17.5
17.5
5
10
NA
NA
NA
Neg
10
5
150
Neg
Neg
Hydrocarbons0
Ib/ton
1.5
1.5
3
15
NA
NA
NA
Neg
15
3
100
2
Neg
kg/MT
0.75
0.75
1.5
7.5
NA
NA
NA
Neg
7.5
1.5
50
1
Neg
Nitrogen oxidesd
Ib/ton
3
3
3
2
4
NA
NA
10
3
10
1
2
3
kg/MT
1.5
1.5
1.5
1
2
NA
NA
5
1.5
5
0.5
1
1.5
I
o
B.
Ul
in
00
aAverage factors given based on EPA procedures for incinerator stack testing.
°Expressed as sulfur dioxide.
cExpressed as methane.
"^Expressed as nitrogen dioxide.
eReferences 5 and 8 through 14.
Most municipal incinerators are equipped with at least this much control: see Table
2.1 -2 for appropriate efficiencies for other controls.
^References 3,5,10,13, and 15.
"Based on municipal incinerator data.
' References 3,5,10, and 15.
i Reference 7.
kBased on data for wood combustion in conical burners.
' Not available.
mReference9.
"References 3,10,11,13,15, and 16.
°With afterburners and draft controls.
PReferences 3.11, and 15.
^References 5 and 10.
r Reference 5.
s References 3 and 9.
-------
5. Flue-fed incinerators - These units, commonly found in large apartment houses, are characterized by
the charging method of dropping refuse down the incinerator flue and into the combustion chamber.
Modified flue-fed incinerators utilize afterburners and draft controls to improve combustion efficiency
and reduce emissions.
6. Pathological incinerators — These are incinerators used to dispose of animal remains and other organic
material of high moisture content. Generally, these units are in a size range of 50 to 100 pounds (22.7 to
45.4 kilograms) per hour. Wastes are burned on a hearth in the combustion chamber. The units are
equipped with combustion controls and afterburners to ensure good combustion and minimal emissions.
7. Controlled air incinerators — These units operate on a controlled combustion principle in which the
waste is burned in the absence of sufficient oxygen for complete combustion in the main chamber. This
process generates a highly combustible gas mixture that is then burned with excess air in a secondary
chamber, resulting in efficient combustion. These units are usually equipped with automatic charging
mechanisms and are characterized by the high effluent temperatures reached at the exit of the
incinerators.
2.1.3 Emissions and Controls1
Operating conditions, refuse composition, and basic incinerator design have a pronounced effect on
emissions. The manner in which air is supplied to the combustion chamber or chambers has, among all the
parameters, the greatest effect on the quantity of particulate emissions. Air may be introduced from beneath the
chamber, from the side, or from the top of the combustion area. As underfire air is increased, an increase in
fly-ash emissions occurs. Erratic refuse charging causes a disruption of the combustion bed and a subsequent
release of large quantities of particulates. Large quantities of uncombusted particulate matter and carbon
monoxide are also emitted for an extended period after charging of batch-fed units because of interruptions in
the combustion process. In continuously fed units, furnace particulate emissions are strongly dependent upon
grate type. The use of rotary kiln and reciprocating grates results in higher particulate emissions than the use of
rocking or traveling grates.14 Emissions of oxides of sulfur are dependent on the sulfur content of the refuse.
Carbon monoxide and unburned hydrocarbon emissions may be significant and are caused by poor combustion
resulting from improper incinerator design or operating conditions. Nitrogen oxide emissions increase with an
increase in the temperature of the combustion zone, an increase in the residence time in the combustion zone
before quenching, and an increase in the excess air rates to the point where dilution cooling overcomes the effect
of increased oxygen concentration.14
Table 2.1-2 lists the relative collection efficiencies of particulate control equipment used for municipal
incinerators. This control equipment has little effect on gaseous emissions. Table 2.1-1 summarizes the
uncontrolled emission factors for the various types of incinerators previously discussed.
Table 2.1-2. COLLECTION EFFICIENCIES FOR VARIOUS TYPES OF
MUNICIPAL INCINERATION PARTICULATE CONTROL SYSTEMS8
Type of system
Settling chamber
Settling chamber and water spray
Wetted baffles
Mechanical collector
Scrubber
Electrostatic precipitator
Fabric filter
Efficiency, %
Oto30
30 to 60
60
30 to 80
80 to 95
90 to 96
97 to 99
References 3,5, 6, and 17 through 21.
EMISSION FACTORS
5-59
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References for Section 2.1
1. Air Pollutant Emission Factors. Final Report. Resources Research Incorporated, Reston, Virginia. Prepared
for National Air Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119.
April 1970.
2. Control Techniques for Carbon Monoxide Emissions from Stationary Sources. U.S. DHEW, PHS, EHS,
National Air Pollution Control Administration. Washington, D.C. Publication Number AP-65. March 1970.
3. Danielson, J.A. (ed.). Air Pollution Engineering Manual. L.S. DHEW, PHS National Center for Air Pollution
Control. Cincinnati, Ohio. Publication Number 999-AP-40. 1967. p. 413-503.
4. De Marco, J. et al. Incinerator Guidelines 1969. U.S. DHEW, Public Health Service. Cincinnati, Ohio.
SW-13TS. 1969. p. 176.
5. Kanter, C. V., R. G. Lunche, and A.P. Fururich. Techniques for Testing for Air Contaminants from
Combustion Sources. J. Air Pol. Control Assoc. 6(4): 191-199. February 1957.
6. Jens. W. and F.R. Rehm. Municipal Incineration and Air Pollution Control. 1966 National Incinerator
Conference, American Society of Mechnical Engineers. New York, May 1966.
7. Burkle, J.O., J. A. Dorsey, and B. T. Riley. The Effects of Operating Variables and Refuse Types on
Emissions from a Pilot-Scale Trench Incinerator. Proceedings of the 1968 Incinerator Conference, American
Society of Mechanical Engineers. New York. May 1968. p. 34-41.
8. Fernandes, J. H. Incinerator Air Pollution Control. Proceedings of 1968 National Incinerator Conference,
American Society of Mechanical Engineers. New York. May 1968. p. 111.
9. Unpublished data on incinerator testing. U.S. DHEW, PHS, EHS, National Air Pollution Control
Administration. Durham, N.C. 1970.
10. Stear, J. L. Municipal Incineration: A Review of Literature. Environmental Protection Agency, Office of Air
Programs. Research Triangle Park, N.C. GAP Publication Number AP-79. June 1971.
11. Kaiser, E.R. et al. Modifications to Reduce Emissions from a Flue-fed Incinerator. New York University.
College of Engineering. Report Number 552.2. June 1959. p. 40 and 49.
12. Unpublished data on incinerator emissions. U.S. DHEW, PHS, Bureau of Solid Waste Management.
Cincinnati, Ohio. 1969.
13. Kaiser, E.R. Refuse Reduction Processes in Proceedings of Surgeon General's Conference on Solid Waste
Management. Public Health Service. Washington, D.C. PHS Report Number 1729. July 10-20, 1967.
14. Nissen, Walter R. Systems Study of Air Pollution from Municipal Incineration. Arthur D. Little, Inc.
Cambridge, Mass. Prepared for National Air Pollution Control Administration, Durham, N.C., under Contract
Number CPA-22-69-23. March 1970.
4/73 Solid Waste Disposal
5-60
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15. Unpublished source test data on incinerators. Resources Research, Incorporated. Reston, Virginia.
1966-1969.
16. Communication between Resources Research, Incorporated, Reston, Virginia, and Maryland State
Department of Health, Division of Air Quality Control, Baltimore, Md. 1969.
17. Rehm, F.R. Incinerator Testing and Test Results. J. Air Pol. Control Assoc. 6/199-204. February 1957.
18. Stenburg, R.L. et al. Field Evaluation of Combustion Air Effects on Atmospheric Emissions from Municipal
Incinerations. J. Air Pol. Control Assoc. 72:83-89. February 1962.
19. Smauder, E.E. Problems of Municipal Incineration. (Presented at First Meeting of Air Pollution Control
Association, West Coast Section, Los Angeles, California. March 1957.)
20. Gerstle, R. W. Unpublished data: revision of emission factors based on recent stack tests. U.S. DHEW, PHS,
National Center for Air Pollution Control. Cincinnati, Ohio. 1967.
21. A Field Study of Performance of Three Municipal Incinerators. University of California, Berkeley, Technical
Bulletin. 6:41, November 1957.
EMISSION FACTORS
5-61
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2.2 AUTOMOBILE BODY INCINERATION
Revised by Robert Rosensteel
2.2.1 Process Description
Auto incinerators consist of a single primary combustion chamber in which one or several partially stripped
cars are burned. (Tires are removed.) Approximately 30 to 40 minutes is required to burn two bodies
simultaneously.2 As many as 50 cars per day can be burned in this batch-type operation, depending on the
capacity of the incinerator. Continuous operations in which cars are placed on a conveyor belt and passed
through a tunnel-type incinerator have capacities of more than 50 cars per 8-hour day.
2.2.2 Emissions and Controls1
Both the degree of combustion as determined by the incinerator design and the amount of combustible
material left on the car greatly affect emissions. Temperatures on the order of 1200°F (650°C) are reached during
auto body incineration.2 This relatively low combustion temperature is a result of the large incinerator volume
needed to contain the bodies as compared with the small quantity of combustible material. The use of overfire air
jets in the primary combustion chamber increases combustion efficiency by providing air and increased
turbulence.
In an attempt to reduce the various air pollutants produced by this method of burning, some auto incinerators
are equipped with emission control devices. Afterburners and low-voltage electrostatic precipitators have been
used to reduce particulate emissions; the former also reduces some of the gaseous emissions.3'4 When
afterburners are used to control emissions, the temperature in the secondary combustion chamber should be at
least 1500°F (815°C). Lower temperatures result in higher emissions. Emission factors for auto body incinerators
are presented in Table 2.2-1.
Table 2.2-1. EMISSION FACTORS FOR AUTO BODY INCINERATION8
EMISSION FACTOR RATING: B
Pollutants
Participates13
Carbon monoxide0
Hydrocarbons (CH4)C
Nitrogen oxides (N02)d
Aldehydes (HCOH)d
Organic acids (acetic)d
Uncontrolled
Ib/car
2
2.5
0.5
0.1
0.2
0.21
kg/car
0.9
1.1
0.23
0.05
0.09
0.10
With afterburner
Ib/car
1.5
Neg
Neg
0.02
0.06
0.07
kg/car
0.68
Neg
Neg
0.01
0.03
0.03
3Based on 250 Ib (113 kg) of combustible material on stripped car body.
References 2 and 4.
"•Based on data for open burning and References 2 and 5.
dReference 3.
4/73
Solid Waste Disposal
5-62
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References for Section 2.2
1. Air Pollutant Emission Factors. Final Report. Resources Research Inc. Reston, Va. Prepared for National Air
Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119. April 1970.
2. Kaiser, E.R. and J. Tolcias. Smokeless Burning of Automobile Bodies. J. Air Pol. Control Assoc. 72:64-73,
February 1962.
3. Alpiser, F.M. Air Pollution from Disposal of Junked Autos. Air Engineering. 10:18-22, November 1968.
\
4. Private communication with D.F. Walters, U.S. DHEW, PHS, Division of Air Pollution..Cincinnati, Ohio. July
19, 1963.
5. Gerstle, R.W. and D.A. Kemnitz. Atmospheric Emissions from Open Burning, J. Air Pol. Control Assoc.
17:324-327. May 1967.
EMISSION FACTORS
5-63
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Z3 CONICAL BURNERS
2.3.1 Process Description1
Conical burners are generally a truncated metal cone with a screened top vent. The charge is placed on a
raised grate by either conveyor or bulldozer; however, the use of a conveyor results in more efficient burning. No
supplemental fuel is used, but combustion air is often supplemented by underfire air blown into the chamber
below the grate and by overfire air introduced through peripheral openings in the shell.
2.3.2 Emissions and Controls
The quantities and types of pollutants released from conical burners are dependent on the composition and
moisture content of the charged material, control of combustion air, type of charging system used, and the
condition in which the incinerator is maintained. The most critical of these factors seems to be the level of
maintenance on the incinerators. It is not uncommon for conical burners to have missing doors and numerous
holes in the shell, resulting in excessive combustion air, low temperatures, and, therefore, high emission rates of
combustible pollutants.2
Paniculate control systems have been adapted to conical burners with some success. These control systems
include water curtains (wet caps) and water scrubbers. Emission factors for conical burners are shown in Table
2.3-1.
4/73 Solid Waste Disposal
5-64
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Ui
Ui
I
90
c/i
Table 2.3-1. EMISSION FACTORS FOR WASTE INCINERATION IN CONICAL BURNERS
WITHOUT CONTROLS3
EMISSION FACTOR RATING: B
Type of
waste
Municipal
refuse*1
Wood refuse6
Participates
Ib/ton
20(10 to 60)c-d
1f
79
20h
kg/MT
10
0.5
3.5
10
Sulfur oxides
Ib/ton
2
0.1
kg/MT
1
0.05
Carbon monoxide
Ib/ton
60
130
kg/MT
30
65
Hydrocarbons
Ib/ton
20
11
kg/MT
10
5.5
Nitrogen oxides
Ib/ton
5
1
kg/MT
2.5
0.5
8Moisture content as fired is approximately 50 percent for wood waste.
'•'Except for participates, factors are based on comparison with other waste disposal practices.
cUse high side of range for intermittent operations charged with a bulldozer.
dBased on Reference 3.
eReferences 4 through 9.
'Satisfactory operation: properly maintained burner with adjustable underfire air supply and adjustable, tangential overfire air inlets, approximately 500 percent
excess air and 700°F (370°C) exit gas temperature.
"Unsatisfactory operation: properly maintained burner with radial overfire air supply near bottom of shell, approximately 1200 percent excess air and 400° F (204°C)
exit gas temperature.
"Very unsatisfactory operation: improperly maintained burner with radial overfire air supply near bottom of shell and many gaping holes in shell, approximately 1500
percent excess air and 400°F (204°C) exit gas temperature.
-------
References for Section 2.3
1. Air Pollutant Emission Factors. Final Report. Resources Research Inc. Reston, Va. Prepared for National Air
Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119. April 1970.
2. Kreichelt. I.E. Air Pollution Aspects of Teepee Burners. U.S. DHEW, PHS, Division of Air Pollution.
Cincinnati, Ohio. PHS Publication Number 999-AP-28. September 1966.
3. Magjll, P.L. and R.W. Benoliel. Air Pollution in Los Angeles County: Contribution of Industrial Products.
Ind. Eng. Chem. 44:1347-1352, June 1952.
4. Private communication with Public Health Service, Bureau of Solid Waste Management, Cincinnati, Ohio.
October 31, 1969.
5. Anderson, D.M.. J. Lieben, and V.H. Sussman. Pure Air for Pennsylvania. Pennsylvania State Department of
Health, Harrisburg. November 1961. p.98.
6. Boubel, R.W. et al. Wood Waste Disposal and Utilization. Engineering Experiment Station, Oregon State
University, Corvallis. Bulletin Number 39. June 1958. p.57.
7. Netzley, A.B. and J.E. Williamson. Multiple Chamber Incinerators for Burning Wood Waste. In: Air Pollution
Engineering Manual, Danielson, J.A. (ed.). U.S. DHEW, PHS, National Center for Air Pollution Control.
Cincinnati, Ohio. PHS Publication Number 999-AP-40. 1967. p.436-445.
8. Droege, H. and G. Lee. The Use of Gas Sampling and Analysis for the Evaluation of Teepee Burners. Bureau
of Air Sanitation. California Department of Public Health. (Presented at the 7th Conference on Methods in
Air Pollution Studies. Los Angeles. January 1965.)
9. Boubel R.W. Particulate Emissions from Sawmill Waste Burners. Engineering Experiment Station, Oregon
State University. Corvallis. Bulletin Number 42. August 1968. p.7,8.
4/73 Solid Waste Disposal
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2.4 OPEN BURNING
2.4.1 General1
revised by Tom Lahre
and Pam Canova
Open burning can be done in open drums or baskets, in fields and yards, and in large open dumps
or pits. Materials commonly disposed of in this manner are municipal waste, auto body component*,
landscape refuse, agricultural field refuse, wood refuse, bulky industrial refuse, and leaves.
2.4.2 Emissions1-19
, Ground-level open burning is affected by many variables including wind, ambient temperature,
composition and moisture content of the debris burned, and compactness of the pile. In general, the
relatively low temperatures associated with open burning increase the emission of particulates, car-
bon monoxide, and hydrocarbons and suppress the emission of nitrogen oxides. Sulfur oxide emissions
are a direct function of the sulfur content of the refuse. Emission factors are presented in Table 2.4-1
for the open burning of municipal refuse and automobile components.
Table 2.4-1. EMISSION FACTORS FOR OPEN BURNING OF NONAGRICULTURAL MATERIAL
EMISSION FACTOR RATING: B
Municipal refuse3
Ib/ton
kg/MT
Automobile
components /c
Ib/ton
kg/MT
Particulates
16
8
100
50
Sulfur
oxides
1
0.5
Neg.
Neg.
Carbon
monoxide
85
42
125
62
Hydrocarbons
(CH4)
30
15
30
15
Nitrogen oxides
6
3
4
2
References 2 through 6.
bUpholstery, belts, hoses, and tires burned in common.
cReference 2.
Emissions from agricultural refuse burning are dependent mainly on the moisture content of the
refuse and. in the case of the field crops, on whether the refuse is burned in a headfire or a backfire.
(Headf ires are started at the upwind side of a field and allowed to progress in the direction of the wind,
whereas backfires are started at the downwind edge and forced to progress in a direction opposing the
wind.) Other variables such as fuel loading (how much refuse material is burned per unit of land area)
and how the refuse is arranged (that is, in piles, rows, or spread out) are also important in certain
instances. Emission factors for open agricultural burning are presented in Table 2.4-2 as a function of
refuse type and also, in certin instances, as a function of burning techniques and/or moisture content
when these variables are known to significantly affect emissions. Table 2.4-2 also presents typical fuel
loading values associated with each type of refuse. These values can be used, along with the correspond-
ing emission factors, to estimate emissions from certain categories of agricultural burning when the
specific fuel loadings for a given area are not known.
Emissions from leaf burning are dependent upon the moisture content, density, and ignition loca-
tion of the leaf piles. Increasing the moisture content of the leaves generally increases the amount of
carbon monoxide, hydrocarbon, and paniculate emissions. Increasing the density of the piles in-
creases the amount of hydrocarbon and paniculate emissions, but has a variable effect on carbon
4/77
Solid Waste Disposal
5-67
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Table 2.4-2. EMISSION FACTORS AiMD FUEL LOADING FACTORS FOR OPEN BURNING
OF AGRICULTURAL MATERIALS3
EMISSION FACTOR RATING: B
'Refuse category
Emission factors
Particulateb
Ib/ton
Field ciopsc
Unspecified 21
Burning technique
not significant1-'
Asparagus6
Barley
Corn
40
kg/MT
11
20
22 11
14 ! 7
Cotton 8
Grasses
Pineapple'
16
4
o
8 4
RiceS 9 4
Saff lower 18 9
Sorghum 18 9
Sugar canen 7 4
Headfire burning'
Alfalfa 45 23
Bean (red) 43 22
Hay (wild) 32
Oats 44
Pea 31
Wheat 22
Backfire burning'
Alfalfa
Bean (red), pea
Hay (wild)
Oats
Wheat
V ne crops
Weeds
Unspecified
Russian thistle
(tumbleweed)
Tules (wild reeds)
Orchard crops0'"'*''
Unspecified
Almond
Apple
Apricot
Avocado
Cherry
Citrus (orange.
lemon)
Date palm
Fig
29
14
17
21
13
5
15
22
5
6
6
4
6
21
8
6
10
7
16
22
16
11
14
7
8
11
6
3
8
11
3
3
3
2
3
10
4
3
5
4
Carbon
monoxide
Ib/ton
117
150
157
108
176
101
112
83
144
77
71
106
186
139
137
147
128
119
148
150
136
108
51
. 85
309
34
52
46
42
49
116
44
81
56
57
kg/MT
58
75
78
54
88
50
56
41
72
38
35
53
93
70
68
74
64
60
72
75
68
54
26
42
154
17
26
23
21
24
58
22
40
28
28
Hydrocarbons
(asC6H14)
Ib/ton
23
85
19
16
6
19
8
10
26
9
10
36
46
22
33
38
17
37
25
17
18
11
7
12
2
27
10
8
4
8
32
10
12
7
10
kg/MT
12
42
10
8
3
10
4
5
13
4
5
18
23
11
16
19
9
18
12
8
9
6
4
6
1
14
5
4
2
4
16
5
6
4
5
Fuel loading factors
(waste production)
ton/acre
2.0
1.5
1.7
4.2
1.7
3.0
1.3
2.9
11.0
0.8
2.5
1.0
1.6
2.5
1.9
0.8
2.5
1.0
1.6
1.9
2.5
3.2
0.1
1.6
1.6
2.3
1.8
1.5
1.0
1.0
1.0
2.2
MT/hectare
4.5
3.4
3.8
9.4
3.8
6.7
2.9
6.5
24.0
1.8
5.6
2.2
3.6
5.6
4.3
1.8
5.6
2.2
3.6
4.3
5.6
7.2
0.2
3.6
3.6
5.2
4.0
3.4
2.2
2.2
2.2
4.9
EMISSION FACTORS
5-68
-------
Table 2.4-2 (continued). EMISSION FACTORS AND FUEL LOADING FACTORS FOR OPEN BURNING
OF AGRICULTURAL MATERIALS8
EMISSION FACTOR RATING: B
Refuse category
Orchard cropsc'k>'
(continued)
Nectarine
Olive
Peach
Pear
Prune
Walnut
Forest residues
Unspecified"1
Hemlock, Douglas
fir, cedar"
Ponderosa pine°
Emission factors
Particulateb
Ib/ton
4
12
6
9
3
6
17
4
12
kg/MT
2
6
3
4
. 2
3
8
2
6
Carbon
monoxide
Ib/ton
33
114
42
57
42
47
140
90
195
kg/MT
16
57
21
28
21
24
70
45
98
Hydrocarbons
(asC6H14)
Ib/ton
4
18
5
9
3
8
24
5
14
kg/MT
2
9
2
4
2
4
12
2
7
Fuel loading factors
(waste production)
ton/acre
2.0
1.2
2.5
2.6
1.2
1.2
70
MT/hectare
4.5
2.7
5.6
5.8
2.7
2-7
157
aFactors expressed as weight of pollutant emitted per weight of refuse material burned.
"Paniculate matter from most agricultural refuse burning has been found to be in the submicrometer size range.12
^References 12 and 13 for emission factors; Reference 14 for fuel loading factors.
"For these refuse materials, no significant difference exists between emissions resulting from headfiring or backfiring.
^These factors represent emissions under typical high moisture conditions. If ferns are dried to less than IS percent
moisture, particulate emissions will be reduced by 30 percent, CO emission by 23 percent, and HC by 74 percent.
'When pineapple is allowed to dry to less than 20 percent moisture, as it usually is, the firing technique it not important.
When headfired above 20 percent moisture, particulate emission will increase to 23 Ib/ton (11.5 kg/MT) and HC will
increase to 12 Ib/ton (6 kg/MT). See Reference 11.
^his factor is for dry «15 percent moisture) rice straw. If rice straw is burned at higher moisture levels, paniculate
emission will increase to 29 Ib/ton (14.5 kg/MT), CO emission to 161 Ib/ton (80.5 kg/MT). and HC emission to 21
Ib/ton (10.5 kg/MT).
.See Section 6.12 for discussion of sugar cane burning.
.'See accompanying text for definition of headfiring.
'See accompanying text for definition of backfiring. This category, for emission estimation purposes, includes another
technique used occasionally for limiting emissions, called irtto-the-wind strip!ighting, which involves lighting fields in
strips into the wind at 100-200 m (300-600 ft) intervals.
^Orchard prunings are usually burned in piles. No significant difference in emission results from burning a "cold pile"
as opposed to using a roll-on technique, where prunings are bulldozed onto a bed of embers from a preceding fire.
'if orchard removal is the purpose of a burn, 30 ton/acre (66 MT/hectare) of waste will be produced.
mReference 10, Nitrogen oxide emissions estimated at 4 Ib/ton (2 kg/MT).'
"Reference 15.
°Reference 16.
monoxide emissions. Arranging the leaves in conical piles and igniting around the periphery of the bot-
tom proves to be the least desirable method of burning. Igniting a single spot on the top of the pile
decreases the hydrocarbon and particulate emissions. Carbon monoxide emissions with top ignition
decrease if moisture content is high but increase if moisture content is low. Particulate, hydrocarbon,
and carbon monoxide emissions from windrow ignition (piling the leaves into a long row and igniting
one end, allowing it to burn toward the other end) are intermediate between top and bottom ignition.
Emission factors for leaf burning are presented in Table 2.4-3.
For more detailed information on this subject, the reader should consult the references cited at the
end of this section.
4/77
Solid Waste Disposal
5-69
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Table 2.4-3. EMISSION FACTORS FOR LEAF BURNING18'19
EMISSION FACTOR RATING: B
Leaf species
Black Ash
Modesto Ash
White Ash
Catalpa
Horse Chestnut
Cottonwood
American Elm
Eucalyptus
Sweet Gum
Black Locust
Magnolia
Silver Maple
American Sycamore
California Sycamore
Tulip
Red Oak
Sugar Maple
Unspecified
Particulatea-b
Ib/ton
36
32
43
17
54
38
26
36
33
70
13
66
15
10
20
. 92
53
38
kg/MT
18
16
21.5
8.5
27
19
13
18
16.5
35
6.5
33
7.5
5
10
46
26.5
19
Carbon monoxide3
Ib/ton
127
163
113
89
147
90
119
90
140
130
55
102
115
104
77
137
108
112
kg/MT
63.5
81.5
57
44.5
73.5
45
59.5
45
70
65
27.5
51
57.5
52
38.5
68.5
54
56
Hydrocarbons3'0
Ib/ton
41
25
21
15
39
32
29
26
27
62
10
25
8
5
16
34
27
26
kg/MT
20.5
12.5
10.5
7.5
19.5
16
14.5
13
13.5
31
5
12.5
4
2.5
8
.17
13.5
13
aThese factors are an arithmetic average of the results obtained by burning high* and low-moisture content conical piles ignited
either at the top or around the periphery of the bottom. The windrow.arrangement was only tested on Modesto Ash, Catalpa,
American Elm, Sweet Gum, Silver Maple, and Tulip, and the results are included in the averages for these species.
"The majority of particulates are submicron in size.
°Tests indicate hydrocarbons consist, on the average, of 42% olefins, 32% methane, 8% acetylene, and 13% other saturates.
References for Section 2.4
1. Air Pollutant Emission Factors. Final Report. Resources Research, Inc., Reston, Va. Prepared for
National Air Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-
69-119. April 1970.
2. Gerstle, R.W. and D.A. Kemnitz. Atmospheric Emissions from Open Burning. J. Air Pol. Control
Assoc. 12:324-327. May 1967.
3. Burkle, J.O., J.A. Dorsey, and B.T. Riley. The Effects of Operating Variables and Refuse Types on
Emissions from a Pilot-Scale Trench Incinerator. In: Proceedings of 1968 Incinerator Confer-
ence, American Society of Mechanical Engineers. New York. May 1968. p. 34-41.
4. Weiaburd. M.I. and S.S. Griswold (eds.). Air Pollution Control Field Operations Guide: A Guide
for Inspection and Control. U.S. DREW, PHS, Division of Air Pollution, Washington, D.C. PHS
Publication No. 937. 1962.
EMISSION FACTORS
5-70
-------
5. Unpublished data on estimated major air contaminant emissions. State of New York Department
of Health. Albany. April 1, 1968.
6. Darley, E.F. et al. Contribution of Burning of Agricultural Wastes to Photochemical Air Pollu-
tion. J. Air Pol. Control Assoc. 76:685-690, December 1966.
7. Feldstein, M. et al. The Contribution of the Open Burning of Land Clearing Debris to Air Pollu-
tion. J. Air Pol. Control Assoc. 73:542-545, November 1963.
8. Boubel, R. W., E.F. Darley, and E. A. Schuck. Emissions from Burning Grass Stubble and Straw.
J. Air PoL Control Assoc. 19:497-500, July 1969.
9. Waste Problems of Agriculture and Forestry. Environ. Sci. and Tech. 2:498, July 1968.
10. Yamate, G. et al. An Inventory of Emissions from Forest Wildfires, Forest Managed Burns, and
Agricultural Burns and Development of Emission Factors for Estimating Atmospheric Emissions
from Forest Fires. (Presented at 68th Annual Meeting Air Pollution Control Association. Boston.
June 1975.)
11. Darley, E.F. Air Pollution Emissions from Burning Sugar Cane and Pineapple from Hawaii.
University of California, Riverside, Calif. Prepared for Environmental Protection Agency, Re-
search Triangle Park, N.C. as amendment to Research Grant No. R800711. August 1974.
12. Darley, E.F. et al. Air Pollution from Forest and Agricultural Burning. California Air Resources
Board Project 2-017-1, University of California. Davis, Calif. California Air Resources Board
Project No. 2-017-1. April 1974.
13. Darley, E.F. Progress Report on Emissions from Agricultural Burning. California Air Resources
Board Project 4-011. University of California, Riverside, Calif. Private communication with per-
mission of Air Resources Board, June 1975.
14. Private communication on estimated waste production from agricultural burning activities. Cal-
ifornia Air Resources Board, Sacramento, Calif. September 1975.
15. Fritschen, L. et al. Flash Fire Atmospheric Pollution. U.S. Department of Agriculture, Washing-
ton, D.C. Service Research Paper PNW-97. 1970.
16. Sandberg, D.V., S.G. Pickford, and E.F. Darley. Emissions from Slash Burning and the Influence
of Flame Retardant Chemicals. J. Air Pol. Control Assoc. 25:278, 1975.
17. Wayne, L.G. and M.L. McQueary. Calculation of Emission Factors for Agricultural Burning
Activities. Pacific Environmental Services, Inc., Santa Monica, Calif. Prepared for Environ-
mental Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-1004, Task
Order No. 4. Publication No. EPA-450/3-75-087. November 1975.
18. Darley, E.F. Emission Factor Development for Leaf Burning. University of California, Riverside,
Calif. Prepared for Environmental Protection Agency, Research Triangle Park, N.C., under Pur-
chase Order No. 5-02-6876-1. September 1976.
19. Darley, E.F. Evaluation of the Impact of Leaf Burning - Phase I: Emission Factors for Illinois
Leaves. University of California, Riverside, Calif. Prepared for State of Illinois, Institute for En-
vironmental Quality. August 1975.
4/77 Solid Waste Disposal
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2.5 SEWAGE SLUDGE INCINERATION By Thomas Lahre
2.5.1 Process Description i-3
Indneration is becoming an important means of disposal for the increasing amounts of sludge being produced
in sewage treatment plants. Incineration has the advantages of both destroying the organic matter present in
sludge, leaving only an odorless, sterile ash, as well as reducing the solid mass by about 90 percent. Disadvantages
include the remaining, but reduced, waste disposal problem and the potential for air pollution. Sludge inciner-
ation systems usually include a sludge pretreatment stage to thicken and dewater the incoming sludge, an inciner-
ator, and some type of air pollution control equipment (commonly wet scrubbers).
The most prevalent types of incinerators are multiple hearth and fluidized bed units. In multiple hearth
units the sludge enters the top of the furnace where it is first dried by contact with the hot, rising, combustion
gases, and then burned as it moves slowly down through the lower hearths. At the bottom hearth any residual
ash is then removed. In fluidized bed reactors, the combustion takes place in a hot, suspended bed of sand with
much of the ash residue being swept out with the flue gas. Temperatures in a multiple hearth furnace'are 600PF
(3:0°C) in the lower, ash cooling hearth; 1400 to 2000°F (760 to 1100°C) in the central combustion hearths,
and 1000 to 1200°F (540 to 650°C) in the upper, drying hearths. Temperatures in a fluidized bed reactor are
fairly uniform, from 1250 to 1500°F (680 to 820°C). In both types of furnace an auxiliary fuel may be required
?ithcr during startup or when the moisture content of the sludge is too high to support combustion.
2.5.2 Emissions and Controls 1.2,4-7
Because of the violent upwards movement of combustion gases with respect to the burning sludge, particu-
lates are the major emissions problem in both multiple hearth and fluidi/ed bed incinerators. Wet scrubbers are
commonly employed for paniculate control and can achieve efficiencies ranging from 95 to 99+ percent.
Although dry sludge may contain from 1 to 2 percent sulfur by weight, sulfur oxides are not emitted in signif-
icant amounts when sludge burning is compared with many other combustion processes. Similarly, nitrogen
oxides, because temperatures during incineration do not exceed 1500°F (820°C) in fluidized bed reactors or
1600 to 2000°F (870 to 1100°C) in multiple hearth units, are not formed in great amounts.
Odors can be a problem in multiple hearth systems as unburned volatiles are given off in the upper, drying
hearths, but are readily removed when afterburners are employed. Odors are not generally a problem in fluid-
ized bed units as temperatures are uniformly high enough to provide complete oxidation of the volatile corn-
pounds. Odors can also emanate from the pretreatment stages unless the operations are properly enclosed.
Emission factors for sludge incinerators are shown in Table 2.5-1. It should be noted that most sludge incin-
erators operating today employ some type of scrubber.
5/74 Solid Waste Disposal
5-72
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Table 2.5-1. EMISSION FACTORS FOR SEWAGE SLUDGE INCINERATORS
EMISSION FACTOR RATING: B
Pollutant
Particulatec
Sulfur dioxide*
Carbon monoxide6
Nitrogen oxidesd (as NOj)
Hydrocarbons*
Hydrogen chloride gas*
Emissions a
Uncontrolled13
Ib/ton
TOO
1
Neg
6
1.5
1.5
kg/MT
50
0.5
Neg
3
0.75
0.75
After scrubber
Ib/ton
3
0.8
Neg
5
1
0.3
kg/MT
1.5
0.4
Neg
2.5
0.5
0.15
aUnit weights in terms of dried sludge.
bEstimated from emission factors after scrubbers.
^References 6-9.
^Reference 8.
References 6, 8.
References for Section 2.5
1. Calaceto, R. R. Advances in Fly Ash Removal with Gas-Scrubbing Devices. Filtration Engineering. 1(7): 12-15,
March 1970.
2. Balakrishnam, S. et al. State of the Art Review on Sludge Incineration Practices. U.S. Department of the
Interior, Federal Water Quality Administration, Washington, D.C. FWQA-WPC Research Series.
3. Canada's Largest Sludge Incinerators Fired Up and Running. Water and Pollution Control. 707(1 ):20-21,24,
January 1969.
4. Calaceto, R. R. Sludge Incinerator Fly Ash Controlled by Cyclonic Scrubber. Public Works. 94(2): 113-114,
February 1963.
5. Schuraytz, I. M. et al. Stainless Steel Use in Sludge Incinerator Gas Scrubbers. Public Works. /03(2):55-57,
February 1972.
6. Liao, P. Design Method for Fluidized Bed Sewage Sludge Incinerators. PhD. Thesis. University of Washington,
Seattle, Washington, 1972.
- -*.
7. Source test data supplied by the Detroit Metropolitan Water Department, Detroit, Michigan. 1973.
8. Source test data from Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, N.C. 1972.
9. Source test data from Dorr-Oliver, Inc., Stamford, Connecticut. 1973.
EMISSION FACTORS
5-73
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CHAPTER 6
COMBUSTION CONTROL AND INSTRUMENTATION
A portion of the material presented in this chapter
was adapted and edited from Chapter 35, Steam, Its
Generation and Use, Babcock & Wilcox Company, 39th
Edition, 1978.
Introduction
This chapter presents a brief overview of the logic that governs com-
bustion controls. Emphasis is placed on the overall purpose of control, and
several examples of logic-sequencing are presented. Instrumentation is dis-
cussed, both in terms of requirements for good operation and in terms of
long-term recordkeeping.
Combustion processes are normally designed to provide thermal energy
for a particular end use. The most common application is to generate
steam for electric power production or for a multitude of other manufac-
turing or heating processes. Systems which do not produce steam usually
produce hot gases, either directly as combustion products or indirectly
using heat exchangers. Gas turbine-drive electric generation is an exam-
ple of the direct application of hot gases; a gas-fired space heater is an
example of indirect application.
All applications of combustion usually provide for a variable energy
demand because the end use is seldom constant with time. Variable energy
demand introduces varying fuel and air requirements, since energy output
6-1
-------
rates can only be altered through corresponding changes of input energy.
Control of the thermal energy source requires realization of two major ob-
jectives:
1. Maintain high combustion efficiency at all energy input rates
and do so while maintaining emissions which are within accept-
able standards, and
2. Maintain appropriate thermal energy states in the equipment
for which energy is supplied (steam pressure, temperature).
The thermal energy states cited are the common variables which are
used to key the combustion control system. Steam pressure as well as tem-
perature are both important to the proper operation of a steam turbine-
driven alternator. Steam pressure, however, is the more important of the
two, since steam turbine speed control is pressure sensitive. A power de-
mand change requires either an increase or decrease of steam flow. This
change in turn requires combustion control which increases or decreases the
energy release rate and the steam generation. Increased steam flow which
is not accompanied by corresponding increased steam generation will cause
a drop in steam pressure. The allowable pressure fluctuation is usually
less than ±2% of the design value, which serves to illustrate the precision
a system can be expected to have.
Process applications may require control of both rate of energy sup-
ply and temperature. Where heat exchange is employed, temperature control
may be possible at the exchanger, within limits; however, the energy rate
control would influence the combustion process. Various drying processes,
such as lumber-drying kilns, veneer dryers, crop dryers, etc., are exam-
ples of this kind of system.
6-2
-------
Combustion Control
The general requirements outlined above can be translated into ifcore
specific requirements for combustion control systems. All combustion sys-
tems must meet a variable load demand through an adjustment of the fuel
input rate proportional to the load, with a simultaneous adjustment to air
flow, to assure maintenance of the most efficient air-fuel ratio.
This seemingly straightforward concept suggests a relatively simple solu-
tion is probably available. Such a conclusion would be wrong, because the
interactions which occur are not simple. Furnace air is generally supplied
through a forced-draft fan assembly that involves one or more fans. Where
one fan is utilized, distribution may be through several alternate paths,
such as primary and secondary air for burners. Air pressure and quantity
must be controlled by altered fan speed and damper settings. A change in
the forced draft (to follow a change in fuel flow) requires a change in the
induced draft if the desired furnace pressure (draft) is to be maintained.
Small systems, which utilize chimney draft to produce the required induced
draft, must have adequate dampers.
The above sequence of control is made more difficult by the variability
of fuel properties. The basic chemistry of combustion, shown in Equations
2.1 and 2.3 in Chapter 2 of this manual, clearly sets the air requirement
per unit of fuel and thereby the energy production which can be expected.
Any change in composition is immediately reflected by an increase or de-
crease in the energy output and air requirements. A combustion control
system designed to operate with fuel flow keyed to steam flow would require
simultaneous sampling of flue gas composition to insure property variation
would be accommodated.
6-3
-------
This aspect of the combustion control problem can be pinpointed by
considering a system which suddenly receives fuel having a higher moisture
content than normal. This situation occurs in mass-burning incinerators,
when especially wet municipal waste comes into the flow, or in a coal-
burning plant, where very wet coal suddenly enters the feeders. Increased
moisture reduces the input-energy rate and lowers the furnace temperature
making an increase in fuel flow necessary. If the unit involved is a
radiant steam generator, high-moisture fuel would cause reduced load capa-
bility. An example is a coal-fired unit designed to operate on eastern1
coal that has been switched to high-moisture western coal. The flame tem-
perature would be reduced, which would cause a reduction of the radiant
energy transfer. This reduction would be accompanied by increased energy
input in the convective superheater. This change could very well exceed
the capability of the "attemperator control" (superheater steam temperature
controller). The superheater-steam temperature would become excessive,
requiring that the unit load be reduced to bring the situation back under control.
Combustion controls must be designed to deal with the particular fuels
to be fired and the fuel rates inherent to the fuel-feeding mechanism. A
great variety of combustion control systems have been developed over the
years to fit the needs of particular applications. Load demands, operating
philosophy, plant layout, and types of firing must be considered before the
selection of a system is made. Attachments 6-2 through 6-5 illustrate
several of the systems that have been developed for various types of fuel
firing. The control symbols shown in these illustrations have been tabu-
lated in Attachment 6-1.
6-4
-------
Stoker-Fired Boilers
Stoker-fired boilers are regulated by positioning fuel and combustion
air from changes in steam pressure. A change in steam demand initiates a
signal from the steam-pressure controller — through the boiler master con-
troller — to increase or decrease both fuel and air simultaneously and in
parallel to satisfy the demand. As long as the pressure differs from the
set-point value, the steam-pressure controller will continue to integrate
the fuel and air until the pressure has returned to its set-point (see Attach-
ment 6-2).
A second part of the control system senses the steam-flow and air-flow
and makes a comparison with calibrated values for the unit. Any differences
sensed will create an error signal which is used to fine-tune the forced-
draft damper, thereby assuring the desired fuel-air ratio.
Furnace draft is regulated separately through the use of a furnace-
draft controller and a power operator that positions the uptake damper.
Gas and Oil-Fired Boilers
Attachment 6-3 illustrates a system applicable to the burning of gas
and oil, separately or together. The fuel and air flows are controlled by
steam pressure through the boiler master, with the fuel readjusted by the
fuel-flow air-flow controller. The oil- or gas-header pressure may be used
as an index of fuel flow and the windbox-to-furnace differential as an index
of air flow on a per-burner basis. Such indices are often used for single-
burner boilers.
6-5
-------
Pulverized Coal-Fired Boilers
Attachment 6-4 illustrates a sophisticated combustion control system
used on larger boilers having several pulverizers, each supplying a group
of burners. Both primary and secondary air are admitted and controlled on
a pulverizer-unit basis.
The boiler firing-rate demand is compared to the total measured fuel
flow (summation of all feeders delivering coal) to develop the demand to
the pulverizer master controller. The pulverizer master demand signal is
then applied in parallel to all operating pulverizers. All pulverizers
have duplicate controls.
The individually biased pulverizer demand signal is applied in a par-
allel mode, as demands vary for coal-feeder speed, primary-air flow, and
total air flow for the pulverizer group. When an error develops between
demanded and measured primary-air flow or total-air flow, proportional and
integral action will be instituted through the controllers to adjust the
primary or secondary air dampers to reduce the error to zero. A low
primary-air flow or total-air flow cutback is applied in the individual
pulverizer control. If either measured primary-air flow or total-air flow
is low,relative to coal rate (feeder speed) demand, this condition is
sensed in the coal-feeder control, which reduces the demand to that equiva-
lent to the measured primary-air flow. A minimum pulverizer-load limit, a
minimum primary-air-flow limit, and a minimum total-air-flow limit are
applied to the respective demands to keep the pulverizers above their mini-
mum safe operating load. This maintains sufficient burner nozzle velocities
at all times and assures the primary and total air-fuel ratios are continu-
ously controlled at prescribed levels.
6-6
-------
Cyclone-Fired Furnaces
Cyclone-furnace controls shown in Attachment 6-5 are similar to those
for pulverized-fired units, although the cyclone functions as an individual
furnace.
Where a unit employs multi-cyclones, feeder drives are calibrated so
that all feeders operate at the same speed for a given master signal. The
total-air flow is controlled by the velocity damper in each cyclone to main-
tain the proper fuel-air relationship. This air flow is automatically com-
pensated for temperature in order to provide the correct amount of air under
all boiler loads. The total-air flow to the cyclone is controlled by the
windbox-to-furnace differential pressure, which is varied as a function of
load, to increase or decrease the forced-draft-fan output.
Automatic compensation for the number of cyclones in service has been
incorporated, along with the added feature of an oxygen analyzer. This gas
analyzer is a component for most control systems and serves as an important
aid to the operator in monitoring excess air for optimum firing condition.
Instrumentation
Instruments are installed in combustion systems for a number of rea-
sons. Codes, both national and local, may prescribe minimum requirements
necessary for the protection of the public safety, health, and welfare.
Aside from these obvious public requirements, however, proper plant opera-
tion requires the operating personnel to have a working knowledge of pres-
sures, temperatures, and flows throughout" the system. Accurate records of
fuel flows, steam or gas flows, power, etc., are required in order to cal-
culate and control operating costs. For a given plant burning selected
fuels, predetermined instrument values can assist crews in maintaining
6-7
-------
proper combustion. Instuments can be categorized as serving the following
functions:
1. Operating guidance
2. Performance computation and analysis
3. Costs and cost allocation
4. Maintenance guidance (particularly preventive maintenance).
Instruments employed to provide useful information for operating guid-
ance can also provide information for other functions listed. Steam-flow,
air-flow, and fuel-flow measurements aid operators to assure good combustion.
Readout from these devices can be recorded, processed by computer, and ren-
dered into cost analyses, efficiency studies, or other management functions.
Measurements in a combustion system can be broken down into a variety of
general categories. A brief outline of the types of information or their
applications is included within these general categories:
1. Flow measurements — normally accomplished by differential-head
meters:
a. Steam-flow meters — usually provided for each individual
boiler, as well as for the collective output from a group
of boilers, turbine or pump supply, industrial processes,
and auxiliary uses
b. Air-flow meters — main combustion air, secondary air flows
c. Water-flow meters— boiler feed water flow, condensing
water flow, process water flow, auxiliary uses.
2. Fuel flow:
a. Coal— weighed in batches, or by devices capable of
continuous-stream weighing
6-8
-------
b. Gas — usually metered by differential head devices —
also measured by positive displacement meters
c. Liquid fuels— metered by positive displacement meters
d. Solids other than coal — usually measured by weighing de-
vices similar to those employed for coal.
3. Pressure Measurements:
a. Steam pressure— steam generator outlet; turbines or pumps;
inlet-to-feed water heaters, steam condensers, industrial
processes
b. Furnace Draft
c. Forced-air supply— primary air; secondary air; overfire air
jet supply air
d. Induced-draft fan outlet
e. Emission-control device, inlet and outlet.
4. Temperature:
a. Steam temperature at various points in a system where steam
is expected to be superheated
b. Air temperatures:
(1) Into and out of preheaters
(2) At appropriate places in primary- or secondary-air supply
for various fuel burners.
c. Flue gas:
(1) At furnace outlet
(2) Superheater inlet and outlet
(3) Inlet and outlet of air preheater
(4) Into and out of emission-control devices
6-9
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d. Miscellaneous equipment where temperature measurement is
important, such as direct flame afterburner combustion
chambers, veneer dryers, etc.
5. Flue gas analysis
a. CC^and &2 meters aid combustion control
b. S02 and NOX meters aid in proper emissions evaluation and
control.
The degree of control sophistication is a plant-size function, which
is another way of saying an economic one. Combustion systems which consume
very large quantities of fuel will usually be well instrumented and will
provide highly automatic control and data processing. Microprocessors are
used to ensure closed loop control of excess air to ensure high combustion
efficiency. Small plants normally have less sophisticated controls and
may not employ computers for data processing.
References
1. Steam, Its Generation and Use, 39th Edition, published by Babcock
and Wilcox, New York, N.Y. (1978).
2. Morse, F. T., Power Plant Engineering, 3rd Edition, D. Van Nostrand
Company, New York, N.Y. (1953).
3. May, O. L., "Cutting Boiler Fuel Costs with Combustion Controls,"
Chemical Engineering (December 22, 1975).
4. "Overfire Air Technology for Tangentially Fired Utility Boilers
Burning Western Coal," EPA-600/7-77-117, IERL, USEPA (October 1977).
5. Lord, H. C., "CC>2 Measurements Can Correct for Stack-Gas Dilu-
tion," Chemical Engineering (January 31, 1977).
6-10
-------
6. Gilbert, L. F., "Precise Combustion-Control Saves Fuel and. Power,"
Chemical Engineering (June 21, 1976).
7. North American Combustion Handbook, 2nd Edition, North American
Manufacturing Company, Cleveland, Ohio (1978).
6-11
-------
Attachment 6-1, Control Symbols
Table 1
Control Symbols
—Transmitter
—Proportional action (gain)
—Integral action
—Summing action
—Difference or subtracting action
—Low select auctioneer
—High select auctioneer
—Low limiting
—High limiting
—Derivative (rate)
—Averaging
-Hand-automatic selector station
(analog control)
-Hand-automatic selector station
(analog control) with bias
-Hand-automatic selector station
(digital control)
-Transfer
-Bias action
-Power device (valves, drives, etc.)
Attachment 6-2, Diagram of a Combustion Control for a
Spread Stoker, Fired Boiler^
Steam
Pressure
9
Steam-
r* Pressure
Error
Steam-
Pressure
Controller
,
-*l
Stoker 5
VV
Air Steam
Flow Flow
9. 9 ,
1 Combustion-
!••••* Controller
Air System
Boiler
, Master
\Controller
,
rS
<
"J-
/f(x)\
. Air-Flow
"* Demand
XrS
(kx Forced
X s\ r\v^«t
Stoker-Feed- Forced-Draft-
Control Drive Fan Damper-
Control Drive
Furnace
Draft
9
Furnace-
Draft
Error
*1
Set
Point
, N
Furnace-
Draft
Controller
Uptake •
DraftVT\
\A/KA/~
JL,
liW\
Uptake
Draft
•^
6-12
-------
Attachment 6-3, Diagram of Combustion Control for a Gas-
and Oil-Fired Boiler*
9 Steam Oil /""N
Pressure Flow ^ J
»| Pressure Error
1
Pressure
Control
\ Boiler
^Master
-
Fuel-Flow
Cross Limit
\
Air-Flow
Error
1
Air-Flow
Control
_i ;
J
«-
[/-NGas X-
()F,OW (
Fuel Flow
*
Combustion
Controller-
Fuel/Air
*
Fuel-Flow
Demand
\
Air-Flow
Cross Limit
Fuel-Flow
Error
\
Fuel-Flow
Control
\
N. Air
J FOow
Steam-Oil
Pressure
Differential, AP
Forced-Draft-Fan Oil Control Gas Control Atomizing-Steam
Damper-Control Drive Valve Valve Valve
Attachment 6-4, Diagram of Combustion Control for a
Pulverized-Coal Boiler*
Firing-Rate Demand
Coal- From Other
Feeder Coal Feeders
Speed j | j
OH
Firing-Rate Error
to Load Run back
ToOther
PulverizerGroups
' x Pulverizer
J/ Master
Pulverizer Group
Secondary-Air Flow
Pulverizer
, x Group No. 1
JXMaster
AXA;
Primary-
Air Flow
O
Primary-Air-Flow Minimum Limit]
*
[ Primary-Air-Flow Error]
I Primary-Air-Vlow Control |
To Secondary-
Air Damper
To Primary-
Air Damper
To Coal-Feeder
Speed Control
6-13
-------
Attachment 6-5, Diagram of Combustion Control for a
Cyclone-Fired Boiler1
Firing-
Demand
Firing-
Error
to
Load
Runback
To
1 Other
Cyclones <
c
ToCoa
From Other Coal' Feeders
t
'
Corrected Firing- ,.
Rate Demand
:uel-Flow ,_
Error
J
1 1 1
_ Total Flow »,
Control
-o
Coal-
Feeder
Speed
4-
Minimum Cyclone
Firing Rate
A. Cyclone
/V/ Master
>/T\Cyclone No. 1
Indiv
Cyclon
e Bias \
[ 1
VIU» l-llllll
i
.Feeder-
Speed Error
I
Feeder- ^^
Speed Control *¥"
41-
l-Feeder Speed Cent
Secondary-
Primary- Air Air
Air Flow Flow Temp
p?q
. Total C
vclonp- i
£ ~" Airflow '
1
Feeder-
Speed
Cross
Limit
I—,
NCoa l-Feeder
) Speed
rol To C
*• *
Flue-Gas-
Oxygen
Compensatio
*
Cyclone-
Air-Flow
Control
,o
Flue-
Gas-
Analyzer
^/i
KClone-Air-Velocity Damper
6-14
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CHAPTER 7
GASEOUS FUEL BURNING
Introduction
Burning gaseous fuels is perhaps the most straightforward of all com-
bustion processes. No fuel preparation is necessary because gases are
easily mixed with air, and the combustion reaction proceeds rapidly, once
the ignition temperature is reached.
The amount of air required for complete combustion of gaseous fuels
has already been discussed in Chapter 2. This chapter will present some
special characteristics of gas flames, as well as the characteristic of
various burners in proportioning, mixing, and burning the fuel-air mix-
tures in an environmentally acceptable manner.
Of the many gaseous fuels, natural gas is the most important one for
large-scale stationary combustion installations. Pipeline natural gas is
perhaps the closest approach to an ideal fuel. It is virtually free of
sulfur and solid residues, and it is the cleanest burning of all fossil
fuels. The relative ease of burning gaseous fuels, particularly natural
gas, has on occasion led to reduced surveillance by the operator and
resulted in surprisingly high levels of carbon monoxide in the exhaust
gases (1, p. 552). This, and other air pollution concerns associated with
burning gaseous fuels, will be discussed in the last section of this chap-
ter.
7-1
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Flame Combustion
There are two principal mechanisms of flame combustion producing
flames of quite different appearance: blue flame and yellow flame. Blue
flame results when gaseous fuel is mixed with air prior to ignition. In
this instance the combustion mechanism is represented by the hydroxylation
theory: hydrocarbon molecules are oxidized gradually in stages passing
through hydroxylated compounds (alcohols), to aldehydes and ketones, to
carbon monoxide, and eventually to C02 and H20. Incomplete combustion
results in the emission of the intermediate partially oxidized compounds.
However, no soot can be developed, even if the flame is quenched, since
the carbon is converted to alcohols and aldehydes during the early stages
of the combustion.
Yellow flame results when the fuel and air enter the combustion zone
separately —without having been intimately mixed prior to ignition. The
carbonic theory explains the mechanism of combustion in this instance.
Hydrocarbon molecules decompose to form solid carbon particles
and hydrogen when exposed to high furnace temperatures before they
have had an opportunity to combine with oxygen. This process is called
thermal cracking. The carbon particles are incandescent at the elevated
temperatures and give the flame a yellowish appearance. Eventually suffi-
cient oxygen, if available, will diffuse into the flame to form CO2 and
H_O as the ultimate combustion products. Insufficient oxygen or incom-
plete combustion due to flame quenching will result in soot and black
smoke.
Which of these two combustion mechanisms is preferable, depends on
the particular application, as will be discussed later in this chapter.
7-2
-------
These theories apply also to the combustion of fuels other than gas and
again point out the importance of understanding the effects of tempera-
ture, turbulence (mixing), and time on achieving complete combustion.
Gas Burning Characteristics
The function of a gas burner is to deliver fuel and air in a desired
ratio to the combustion chamber, and to provide mixing and ignition of the
combustible mixture.
Most gas burners employ the Bunsen principle, where at least a part
of the combustion air is mixed with the gas prior to ignition (see Attach-
ment 7-1). Under normal operation the flame consists of a bright blue
inner cone at the end of the burner tube, surrounded by an envelope of
lower luminosity (Attachment 7-2). The outer envelope or mantle is less
sharply defined. It is blue at the base and may terminate in a yellow tip.
Flame luminosity increases at low primary air rates with the inner blue
cone almost disappearing into the now luminous outer cone at the lowest
premix level.
The shape of the flame will depend on the mixture pressure and the
amount of primary air. The latter is the percentage of the combustion air
which has been premixed with the gas before combustion and is also referred
to as percent premix. The remainder of the combustion air is known as the
secondary air and enters the furnace directly, without having passed through
the burner first. For a given burner, increasing mixture pressure will
broaden the flame. Increased primary air will shorten it, as shown in
Attachment 7-2 (1). Burner design, however, will have much more effect
on the size and shape of the flame. Rapid mixing is likely to produce a
short "bushy" flame, while delayed mixing and low velocities result
in long and more slender flames.
7-3
-------
Burning characteristics of different fuel gases are of primary im-
portance in the burner design, and they will also determine the stable
.operating range for a given burner. • Among these characteristics are the
flame propagation velocities, some of which are listed in Attachment 7-3.
Note that the maximum velocity does not occur at the stoichiometric com-
position. Gases with high flame propagation velocities, such as hydro-
gen, acetylene, ethylene, etc., are more prone to flash-back through the
burner at low firing rates. On the other hand, these fast-burning gases
are less likely to blow off or lift from the burner tip than flames of
natural gas (mostly methane) or liquefied petroleum gases. Burners for
gases with high flame velocities are, therefore, normally operated at
somewhat higher primary air rates than natural gas or LPG burners.
The locations of stable flame boundaries are illustrated qualitatively
in Attachment 7-4 as a function of the gas input rate. Very low amounts
of primary air will lead to the yellow flame (carbonic theory) combustion
mechanism with the possibility of smoke and soot formation with incom-
plete combustion.
Turndown is the range of maximum to minimum fuel gas input rates
over which a burner will operate satisfactorily. The maximum input rate
is limited by the lifting, and the eventual blow-off, of the flame when
the mixture velocity exceeds the flame propagation velocity. The mini-
mum gas rate is set by flash-back, where mixture velocity is less than flame
velocity. The tapered venturi section of atmospheric burners (Attachment
7-1) is designed not only to provide mixing of the fuel gas and air, but
also an increased velocity near the throat to help prevent flash-
back. Theoretically the flame will be stationary at a point where the
7-4
-------
flame velocity equals the mixture velocity in or out of the mixing tube.
Actually, however, a relatively cool burner port will also serve to sta-
bilize the flame. Operation of the atmospheric type burner (with natural
gas) is generally satisfactory with 30 - 70% premix which permits about
4 to 1 turndown ratio. A high turndown ratio is desirable for cyclic
loads and for applications where high heat input rates are needed during
initial heat-up, but cannot be tolerated during steady operation. Consi-
derably lower turndown ratios are adequate for continuous furnaces which
are seldom started cold. Occasional longer start-up periods may be less
costly than the larger, more sophisticated equipment required by a high
turndown capability. If temperature distribution is not too critical,
higher modulation of heat input may be achieved by either lighting or shut-
ting off burners.
Gas Burners
There are many ways to categorize gas burners. One classification
depends on how the gaseous fuel and air are brought together and mixed;
such as by (a) premixing, (b) nozzle mixing, or (c) long-flame burners (2).
In gas burners of the premixing type the primary air and gas are
mixed upstream from the burner ports. Most domestic gas burners are of
this type, and consist of a manifold with a number of small ports. This
type of burner is not capable of high heat release rates within confined
volumes, thereby seriously limiting the temperatures to which objects can
be heated. Multiple port gas burners are widely used for heaters, boilers,
and vapor incinerators. Over a given cross-section, a multiple-port burner
provides better distribution of flame and heat than a single-port unit.
7-5
-------
Attachment 7-5 illustrates a few of the multitude of designs and
techniques which have been used to deliver the fuel-air mixture to a com-
bustion chamber. The atmospheric burner (Attachments 7-1 and 7-5.1) has
already been discussed. Multiple gas jets with natural or fan draft air
supply are widely used for boiler firing ^Attachment 7-5.2, 7-5.3, 7-5.4,
and 7-5.7). Refractory tunnels assist in heating the mixture for ignition
and help protect the metal parts from high temperatures. Improved mixing
can be obtained by the orientation of gas jets (7-5.2), vanes (7-5.3), or
by a rotating spider (7-5.7). In the case of very low gas pressures, com-
pressed air can be injected, as with the inspirator governor (7-5.5), which
supplies complete fuel-air mixture to a number of individual burners,
usually of a tunnel type. Similar burners can also be used with high
pressure gas and atmospheric air. Good practice dictates that manufac-
tured gas be available at 5 psig or higher and natural gas at 10 psig or
even higher for inspirator-type burners. Inspirators cannot be used
with propane or butane at any normally available gas pressures since these
gases require 24 to 31 volumes of air per volume of gas. A combustion
air blower will greatly increase the flexibility of a burner compared
to an atmospheric unit, as well as make it capable of providing better
combustion through improved control.
Nozzle-mixing gas burners do not mix the gas and air until they leave
the burner port. Nozzle orifices are designed for rapid mixing of fluids
as they leave. The main advantage of these burners is a greater turndown
ratio. External regulators or proportioning valves are their major dis-
advantage .
Long (luminous) flame gas burners are used in larger furnaces where
a good portion of the heat is to be transformed by radiation. Long
7-6
-------
flames are produced by injecting a low-velocity central core of gas com-
pletely surrounded by an annular air stream. With a low mixing rate,
combustion will take place at the air-gas interface; radiant
energy causes the gas to crack and produce luminous carbon particles in
the central core. Burners based on a similar principle are also used for
firing radiant tubes where delayed mixing is necessary to prevent hot spots
on the tubes.
Specialized Gas Burners
There are many gas burners designed specifically for a particular
application. The following is a brief presentation of typical burners
to illustrate the wide range of burners available.
Excess-air gas burners are used for metallurgical heat treating fur-
naces, kilns, air heaters, dryers, and similar applications where superior
temperature uniformity is required. These are sealed-in, nozzle-mix burn-
ers capable of producing a stable flame with several thousand percent ex-
cess air.
A mixing-plate-type burner (1, p. 181) is shown in Attachment 7-6.
It operates over a very wide range of air-gas mixtures and its stability
is not affected by fluctuating fuel supply. A mixing-plate burner can be
used to burn waste gases with heat content as low as 55 Btu/ft (4).
A lean-fuel burner has recently been patented by British Petroleum,
London. This burner consists of a double, flat tubular spiral with the
gas-air mixture entering from the outer edge and being preheated as it
flows toward the center where the combustion takes place. Combustion
products spiral outward through the adjacent tube, and transfer heat across
the wall to the incoming mixture. By varying the number of turns in the
7-7
-------
spiral, sustained stable burning can be obtained with a mixture contain-,
ing as little as 1% methane. Furthermore, the flame temperatures are so
low that no nitric oxide is produced.
"VorTuMix"R (NAO Burner Co. trademark) burners (5) are designed to
handle dirty gases, such as in ground flares. A special vane con-
figuration is used to generate a highly turbulent vortex. A two-stage com-
bustion process minimizes NOV formation: 10% of the air by-passes the
A
burner throat where the rich mixture is burned at a relatively low tem-
perature. The by-passed air is then introduced to the second stage to
ensure complete combustion. These units can also burn waste
gases with heat contents in the 60-200 Btu/ft3 range. Even gases with
heat content as low as 30 Btu/ft3 could be burned with injection of some
natural gas at the burner throat.
"HGE Sulzer"R (Trane Thermal Co. trademark) is an example of high
heat release combustor with single-unit outputs as high as 200 x 106 Btu/
hr (6). Because of the extreme turbulence and high flame temperatures,
the combustion is complete within the chamber and there is very little
flame beyond the burner outlet (Attachment 7-7).
The "Blue Flame Isomax" (U. E. Corporation trademark) (7) is an
example of a multi-fuel burner where the liquid fuel is converted to gas
immediately prior to ignition by recirculating hot combustion gases as
shown in Attachment 7-8.
In addition to the above designs, there are also:
Integral-blower burners for dryers and ovens;
Immersion-tube burners for submerged heating of liquid;
Flat-flame burners for slab heaters and glass tanks;
7-8
-------
Hot-spot burners for spot heating by radiation and convection;
Flame-grid burners for fume destruction by direct incineration;
and a myriad of other special designs.
System Design Considerations
Energy released by combustion should be placed where it will achieve
an effective heat utilization with a minimum of heat loss. One of the
advantages of gaseous fuel is that the heat of combustion can be dis-
tributed with relative ease —by many small burners, a single large one,
or by something in between, suitable for that particular application.
The selection of the burner type and number, therefore, is tied to the
application: the furnace volume, shape, and mode of heat utilization/
transfer. All these important factors are interrelated.
The characteristics of different burner types, along with special
designs, were discussed in the previous section. The turndown ratio may
be one of the more important requirements, but only when the need for
modulation exists.
The combustion volume is the space occupied by the fuel and by the
various intermediate products of combustion during burning. This volume
varies considerably with fuel composition and properties, with the type
of heat exchanger or vessel to be fired, and with the burner design.
Generally speaking, it is desirable that the flame just fill the primary
combustion volume to avoid unnecessary quenching of the oxidation reac-
tions. A wide furnace cannot be fired properly with a single burner. A
short furnace may require several smaller burners to prevent flame im-
pingement on the rear wall.
7-9
-------
The heat release rate with gaseous fuels is generally quite high,
particularly at high mixture pressures and with thorough mixing. In the
primary combustion zone, where 70 - 90% of the oxidation occurs, heat
release rates of 200,000 Btu/hr-ft3 produce good flame temperatures with-
out the danger of flame impingement. Specially designed high intensity
burners can operate quite satisfactorily at 10 x 10 Btu/hr-ft3 levels.
The overall heat release rate (for complete combustion) ranges from
30,000 to 70,000 Btu/hr-ft3 for more conventional gas-burning installa-
tions .
The pressure against which a burner must operate is another impor-
tant consideration. Furnaces normally operate at +0.01 to -1 inches
of water column gauge pressure. Air leaking into the furnace is pre-
ferable — in most applications — over leakage from the combustion chamber
to the ambient. However, too much vacuum could lead to excessive furnace
roar and an unstable flame.
The exhaust system is yet another component deserving careful
attention. It handles approximately 10 - 12 scf combustion products
for each cubic foot of natural gas burned. Larger installations
use either extended natural draft stacks or mechanized draft devices,
with the latter becoming more common because they control gas flows
better. Without mechanical draft equipment, it is extremely diffi-
cult to specify definite purge periods for start-ups and shut-downs, since
the available natural draft depends on the temperature difference
between the stack and the ambient, which can vary considerably. Stack
temperatures below 200°F will cause corrosive condensation. Flue gas
temperatures cause problems when the firing rate is low and when flue
7-10
-------
gas scrubbers or heat recovery devices are used.
Operation and Control r
Safety should be the foremost consideration in operating gas-fired
combustion installations. Regulations and procedures for safe operation
of burners and firing-system operation have been developed by AGA, UL,
FM, NFPA, as well as through local ordinances. There should always be a
purge period after a flame-out, regardless of the reason. This will ensure
that any combustible (explosive) mixture is eliminated from the combustion
chamber before reignition is attempted. Before firing with natural gas,
inspect the gas injection orifices and verify that all passages are un-
obstructed. Filters and moisture traps should be in place, clean, and
operating effectively to prevent any plugging of gas orifices. Proper
location and orientation of diffusers, spuds, gas canes, etc., should also
be confirmed. Look for any burned off or missing burner parts.
Many burners will function satisfactorily under adverse conditions
(particularly in cold surroundings) only if the mixture is rich and the
flame is burning in free air. With burners of this type, it is necessary
to leave the furnace doors open during the start-up period. If the doors
are not left open, the free air in the furnace will be used up after a
few seconds of operation, and the burner flame will be extinguished.
Under these conditions the presence of a pilot light is a potential
source of danger, because combustible gases will collect quickly after
the flame has been extinguished and could be ignited — explosively —
by the pilot (2).
Always consult knowledgeable personnel before attempting to switch
fuel or alter the firing rate.
7-11
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Proper operation of a gas-fired installation requires that the fuel
rate be controlled in relation to the demand, and the air supply must be
appropriate to the fuel supply. This can be accomplished either manually
or by automatic control. The incoming gas supply is regulated
at a constant pressure upstream of the control valve. This valve can
be used to control the gas flow, based on a signal from the output of the
heat exchanger. Combustion air regulatiori is achieved through manipulat-
ing dampers or by a special draft controller. Larger installations are
likely to use more elaborate systems where the fuel and air flows are
metered with automatic adjustment to compensate for any changes or dis-
turbances .
Gaseous fuels pass through one or more fixed orifices before enter-
ing the combustion chamber. Since flow through an orifice is propor-
tional to the square root of the pressure drop across it, small fluctua-
tions of the upstream pressure will not have a very significant effect on
the gas flow rate. However, should it be necessary to reduce the firing
rate to 25% of its peak value (4-to-l turndown), for example, a 16-fold
decrease in gas pressure would be required, with the air flow-rate
adjusted accordingly. This factor presents quite a control problem,
particularly with firing-rate modulation in pre-mix type burners.
Failure to maintain proper air-fuel ratios can lead to operation with
insufficient air or with high excess air. The most common cause of insuf-
ficient air is inadequate fresh air openings into the boiler room. Among
the indicators of insufficient air are:
1. Hot, stuffy feeling in the boiler room
2, Burner pulsations
7-12
-------
3. Extremely "rich" flame that seems to "roll" in the furnace
4. Flame front detached from the nozzle
5. Excessive gas consumption
6. Soot deposits on heat exchange surfaces
7. Smoke from the stack
8. Carbon monoxide produced by incomplete combustion.
Too high excess air is indicated by:
1. Extremely blue and "hard" (lean) flame appearance
2. Combustion roar
3. Burner vibrations or pulsations
4. Flame front blows off burner nozzle
5. Excessive gas consumption
6. Sharp, acrid odor of aldehydes and other partial oxidation
products
7. Flame extinction.
Flue-gas analyzers are frequently used to give an indication of com-
bustion quality. Chemical or electrical analyzers are available for this
purpose. Normal concentration ranges of combustion products in natural
gas-fired installations are: 9 - 11% CC^; 6 - 3% C^; no CO and H2.
Attachment 7-9 shows the qualitative effect of air-fuel ratio on the
flue-gas composition, as well as the results of incomplete or poor mixing.
If only the flue-gas C02 concentration is measured, it is possible to be
misled about which side of the stoichiometric air-to-fuel ratio one is
operating.
Stack gas temperature in conjunction with its CC^ concentration can
be used to determine the "flue losses" and hence the approximate combustion
7-13
-------
efficiency with the help of Attachment 7-10, which has been developed for
natural gas-fired installations (8).
Air Pollution Considerations
Most gaseous fuels, with the possible exception of some waste gases,
are considered to be clean fuels. Pipeline-grade natural gas is virtually
free of sulfur and particulates. Its combustion products do not pollute
water. Natural gas transportation and distribution facilities have a mini-
mal adverse ecological impact. However, leakage of natural gas or LNG
can pose a very serious explosion hazard indeed.
The principal air contaminants from gaseous fuels, which are affected
by the combustion system design and operation, are the oxidizable materials
carbon monoxide, carbon, aldehydes, organic acids, and unburned hydrocar-
bons. Burner design also affects the production of the oxides of nitro-
gen, particularly in large steam power plant boilers. The NOX problem
and techniques for controlling it are discussed in Chapter 16.
Attachments 7-11 and 7-12 give the uncontrolled emission factors for
natural gas and liquefied petroleum gas (LPG), respectively (9). Nitrogen
oxide emissions from these fuels are a function of the temperature in the
combustion chamber and the cooling rate of the combustion products.
These values vary considerably with the type and size of unit. Emissions
of aldehydes are increased when there is an insufficient amount of com-
bustion air or an incomplete mixing of the fuel and the combustion air.
It has been stated often that gas-burning installations do
not produce a pollution problem. Since areas of stable flame (Attach-
ment 7-4) cover a wide range of flow rates, often with less than 100%
theoretical air, many gas-fired units have been found to operate with
7-14
-------
insufficient air resulting in high CO emissions (1). Typically, gas-
fired units do not need as much attention from the operator as coal and
fuel oil furnaces. A smoking stack of an oil-fired unit is perhaps
a better indication of improper combustion. When a natural gas burning
installation does smoke, or even emits a light haze, it usually has a
burner problem. With atmospheric-type burners the problem is likely to
have originated from a flash-back which destroyed the burner body or
clogged the throat with soot.
To help alleviate the natural gas shortage, as well as reduce the
pollutant emissions from gas-fired installations, efforts are now being
made to increase the average seasonal efficiencies of existing gas fur-
naces to about 60% and for new furnaces to approximately 85%. These
gains in efficiency could be achieved by retrofitting existing furnaces
with components such as advanced burners, improved heat exchangers and
heat pipes, and by replacing old furnaces with pulse-combustion units or
condensing furnaces.
References
1. Danielson, J. A., Editor, Air Pollution Engineering Manual,
AP-40, Second Edition, pp. 181, 544, 552, USEPA (May 1973).
2. Combustion Handbook, published by The North American Manufac-
turing, Cleveland, Ohio (1952).
3. Griswold, J., Fuels, Combustion, and Furnaces, McGraw-Hill
Book Co. (1949).
4. Waid, D. E., "Energy from Waste Gases," Chem. Eng. Progress,
vol. 74, No. 5, 77-80 (1978).
7-15
-------
5. "High-Intensity Burners for Dirty, Low-Btu Gases," National Air
Oil Burner Company, Philadelphia, PA, Bulletin No. 42 (1977).
6. "Industrial Burners," The Trane Thermal Company, Conshocken, PA,
Bulletin No. 143-A (1976).
7. "Blue Flame Multi-Fuel Burner," U. E. Corporation, Ringoes, NJ,
Bulletin 475 (1976).
8. Jaeger, K. S. , "Natural Gas Fired Instllations —Design Considera-
tions," unpublished paper, Forney Engineering Company, Dallas, TX
9. "Compilation of Air Pollution Emission Factors," AP-42, Third
Edition, USEPA (August 1977).
7-16
-------
Attachment 7-1, Atmospheric Premix-Type Gas Burner
BURNER ORFICE SPUD
GAS MANIFOLD
FLAME RETENTION ZONE
PRIMARY AIR/
(INSPIRATED)
-------
Attachment 7-2, Natural Gas Flamns wi Mi Vuryiruj Primary Air
I
M
CD
66.8
G3.4
60.4 57.
. PRIMARY AIR
-------
Attachment 7-3, Composition and Flame Propagation for Maximum-Speed
Mixtures with Small Burner Tubes3
% Gas
% of
Theoretical Air
V flame, cm/s
Hydrogen
Carbon Monoxide
Methane
Acetylene
Ethylene
Ethane
Propane
Butane
Pentane
42
45
9.8
9.5
7.2
6.4
4.7
3.65
2.9
58
50
95
80
90
87
85
85
88
225
43
37
145
70
45
35
7-19
-------
Attachment 7-4, Atmospheric Burners— Flams Stability
LIFTING OF FLAME ZONE
g
•rt
4J
s
o
o
€
*4
O
*>
a
STABLE
FLAME
YELLOH TIP
Increasing Gas Rate per Port, Btu/hr-ft2
7-20
-------
Attachment 7-5, Selected Gas Burner Types
Primary air Ufftf
^JSai tutor/
Atmoiphorlc go* bvnwrt pull In mob- primary
combustion by Hi* action at • itraam
at low-prouuro gal aMpanm'ng through on orlflco
IAtmoipl
air far
2*romlxlng of fuol gat and air naadad A Vonat placod In mo path of lncoM> ' M Oa> luvai fram a mimaar af ipudt can-
fr combustion takot laca In a mix* ^ In air ta Hilt tunnol bumar ac ^
gat and air naadad A Vonat placod In mo p
far combustion takot placa In a mix*, ^ Ing air ta Hilt tunnol bumar act ^ nacflng fa varflcal and horizontal manl-
Ing chambor autilda ma fvrnaca propar fa Impart twirling motion ta ttraam laMt. Primary air antart around ma ipudt
bontor oporoto* on hlgh-prottvro got;
potioi It through two vonturl loctlont In torlat.
«ry olr ontort fhvttor, at loft, • vndor Induction
•F Hlgh-prtJi.uro ga» Ntuoi fram |ot« In Iho spider
* and rooctlon tplnt tho tpldor to rototo Iho fan.
Ro*vHlng turbulonco glvoi prompt, thorough ml«lng
*• colUd low*pr«Muro fai-lHinwr tyttamt work with olr undor prosHiro
end ga> M otmoiphorlc condltlotit. An huptrotor govomor, loft vbovo,
ffoi-alr mlvtwro of propor proitvro to twrftor blocki, right obovo
7-21
-------
Attachment 7-6, Mixing Plate Burner (Maxon Corp.,
Muncie, IN)^
7-22
-------
Attachment 7-7, HGE Sulzer Combustion Burner (Trane Thermal
Co., Conshohocken, PA)
SECONDARY AIR
SWIRLER
PRIMARY AIR
SWIRLER
-J
I
to
LJ
FUELAND
ATOMIZING
FLUID
REFRACTORY LINED
COMBUSTION CHAMBER
COMBUSTION
AIR INLETS
-------
Attachment 7-8, Multi-Fuel Oil Gasifying Burner
(U. E. Corp., Ringoes, NJ)7
IGNITOR
(SPARK PLUG)
FUEL GAS INLET
REFRACTORY
' BURNER.
BLOCK
COOLING AIR
INLET FOR
GAS FIRING
START-UP
OIL INLET
Attachment 7-9, Flue Gas Analysis 2
Poor Mixing*
Good Mixing *
O air deficiency O excess ai
chemically correct
AIR-FUEL RATIO
*Note: The differences between poor and good mixing of the
fuel and air are shown by the solid and broken lines, respec-
tively. This chart is for qualitative comparisons only; hence
no numerical values are shown.
7-24
-------
Attachment 7-10, Flue Heat Losses with Natural-Gas-
Fired Installations8
600 _
500-=
400-
300—
250-
200 —
150-
100—1
\
\
OJ
S-
\
\
\
% C02
% Excess in Flue
Air Gases
% Flue
Heat Loss
50-
40-
30 :
•
X
15-
m
. V
\
^
600—
500—
400—
300—
200-
;
-
100-
s.
\ soi
\ -
\:
0-
-1.5
-2
-3
-4
•
-5
•
-6
-7
-8
-9
HO
-11
-12
Note: Average dew-point for flue gas products
of natural gas combustion is 178°F.
Example: Heat loss for flue gases at 400°F
temperature difference above room and 10%
C02 is found to be 19%. Therefore, the com-
bustion efficiency is 81%.
7-25
-------
Attachment 7-11, Emission Factors for Natural Gas Combustion
Emission Factor Rating: A^
Pollutant
Particulates3
Sulfur oxides (SC>2)b
Carbon monoxide0
Hydrocarbons
(asCH4)d
Nitrogen oxides
(N02)e
Type of unit
Power plant
Ib/106ft3
5-15
0.6
17
1
700f-h
kg/106m3
80-240
9.6
272
16
11,200f-h
industrial process
boiler
Ib/106ft3
5-15
0.6
17
3
(1 20-230) i
kg/1 06 m3
80-240
9.6
272
48
(1920-
3680) i
Domestic and
commercial heating
Ib/106ft3
5-15
0.6
20
8
(80-120)1
kg/1 06 m3
80-240
9.6
320
128
(1280-
1920)i
a References 4,7,8,12.
bReference 4 (based on an average sulfur content of natural gas of 2000 gr/106 stdft3 (4600 g/106 Nm3).
c References 5, 8-12.
dReferences 8, 9, 12.
eReferences 3-9, 12-16.
f Use 300 lb/106 stdft3 (4800 kg/106 Nm3) for tangentially fired units.
9At reduced loads, multiply this factor by the load reduction coefficient given in Figure 1.4-1.
"See text for potential NOX reductions due to combustion modifications. Note that the NOX reduction from these modifications
will also occur at reduced load conditions.
' This represents a typical range for many industrial boilers. For large industrial units l> 100 MMBtu/hr) use the NOX factors pre-
sented for power plants.
i Use 80 (1280) for domestic heating units and 120 (1920) for commercial units.
7-26
-------
Attachment 7-12, Emission Factors for LPG Combustiona, Emission Factor Rating: C'
Pollutant
Particulates
Sulfur oxidesb
Carbon monoxide
Hydrocarbons
Nitrogen oxides0
Industrial process furnaces
Butane
lb/103 gal
1.8
0.09S
1.6
0.3
12.1
kg/103 liters
0.22
0.01S
0.19
0.036
1.45
Propane
lb/103 gal
1.7
0.09S
1.5
0.3
11.2
kg/103 liters
0.20
0.01S
0.18
0.036
1.35
Domestic and commercial furnaces
Butane
lb/103 gal
1.9
0.09S
2.0
0.8
(8 to 12)1'
kg/103 liters
0.23
0.0 1S
0.24
0.096
(1.0 to 1.5)d
Propane
lb/103 gal
1.8
0.09S
1.9
0.7
(7to11)d
kg/103 liters
0.22
0.0 IS
0.23
C.084
(0.8 to 1.3)d
to
-J
"UPC emission factors calculated assuming emissions (excluding sulfur oxides) are the same, on a heat input basis, as for natural gas combustion.
bS equals sulfur content expressed in grains per 100 ft3 gas vapor; e.g., if the sulfur content is 0.16 grain per 100 ft3 (0.366 g/100 m3) vapor, the SO2 emission factor would be
0.09 x 0.16 or 0.014 Ib SO2 pet 1000 gallons (0.01 x 0.366 or 0.0018 kg SO2/I03 liters) butane burned
Expressed as NO2.
dUse lower value for domestic units and higher value for commercial units.
-------
CHAPTER 8
FUEL OIL BURNING
Introduction to Oil Combustion
The overall purpose of fuel burning is to generate hot combustion
gases in a useful, efficient, and environmentally acceptable manner. This
is achieved typically by burning the fuel completely, with a minimum prac-
tical quantity of air, and by discarding the flue gas at a reasonably low
temperature.
The rate of combustion of a liquid fuel is limited by vaporization.
Light distillate oils (such as kerosene, No. 1 fuel oil) readily vaporize
in simple devices. Other fuel oils, because of their heavier composition,
require more complicated equipment to assure vaporization and complete com-
bustion .
In order to achieve complete combustion, oils are atomized into small
droplets for rapid vaporization. The rate of evaporation is dependent on
surface area, which is greater as the atomized droplet size is smaller (for
a given quantity of oil). Atomization size distribution varies with the
type of burner, as illustrated in Attachment 8-1. The desired shape of the
atomization pattern (hollow cone, solid cone, etc.), as well as the droplet
sizes, are influenced adversely if fuel viscosity is improper or if the
nozzles become carbonized, clogged, eroded, or cracked.
Viscosity is a measure of the fluid's internal resistance to flow. It
varies with fuel composition and temperature, as was illustrated in Chapter 3,
8-1
-------
Attachment 3-6. At ambient temperature, No. 2 fuel oil may be atomized
properly, but typically No. 6 fuel oil must be heated to around 210°F to
assure proper atomization. No. 5 may require neating to 185°F and No. 4
to 135°F-
Dirt and foreign matter suspended in the oil may cause wear in the oil
pump and blockage of the atomizing nozzles. Strainers or replaceable fil-
ters are required in the oil suction line, as well as in the discharge line.
Some burners may have a fine mesh screen or a porous plug-type filter to
prevent nozzle damage and the resulting poor droplet atomization. Other
systems may have pumps with design features to collect particles of foreign
matter and to mechanically reduce their size to minute particles which flow
through the pump, filter, and nozzle (1).
Proper mixing of droplets with air, a continuous source of ignition,
and adequate time to complete combustion (before the hot gases are quenched
on the furnace surfaces) are other requirements. However, if too much un-
even mixing or turbulence is present in the flame zone, hot spots may
occur which will result in higher NO emissions.
X
During combustion of a distillate fuel oil, the droplet becomes uni-
formly smaller as it vaporizes. By contrast, a residual oil droplet under-
goes thermal and catalytic cracking, and its composition and size undergoes
various changes with time. Vapor bubbles may form, grow, and burst within
a droplet in such a way as to shatter the droplet as it is heated in the
combustion zone. If adequate time and temperature are not available for
complete combustion, carbonaceous materials (soot) may be deposited on
metal surfaces or be emitted with smoke.
8-2
-------
Oil Burning Equipment
Oil burning furnaces or boilers are classified typically as either
domestic, commercial, industrial, or utility-sized units. Although the
limits which separate the size designations are not clearly established,
each group has important characteristics. As displayed in Attachment 8-2,
small residential heating units use considerably more excess air and burn
with a much shorter residence time than the larger units. The larger volu-
metric heat release rate of the smaller sized units results from the favor-
able area-to-volume ratio for small units. As units of larger size are con-
sidered, special heat transfer design provisions are required for adequate
energy extraction.
Domestic oil burners typically burn No. 2 fuel oil at a rate of be-
tween 0.5 and 3 gph (gallons per hour). These units are mass-produced
packages which include the combustion air fan, oil pump, gun or nozzle
assembly, and transformer with ignition electrodes. Typical domestic units
have simple automatic combustion control features, with around 40% excess air
required for complete combustion. These units should have the oil filter
cleaned or replaced and the nozzle replaced at least annually.
Commercial-sized oil burners typically burn No. 4, 5, or 6 fuel oil at
a rate of between 3 and 100 gph. Although electric heating of oil is typi-
cal, steam may be used. These units may also burn No. 2 fuel oil. Around
30% excess air is provided for complete combustion. An example of a com-
mercial-sized oil unit would be that of a Scotch marine (fire tube) boiler
•. '* *
shown in Attachment 8-3. Commercial-sized units may also be designed as
integral furnace (water-wall) heaters or boilers.
8-3
-------
Industrial-sized oil-fired furnaces or boilers typically burn No. 4,
5, or 6 fuel oil at a rate of 70 to 3,500 gph. These units may be con-
structed either at the site or in a factory, depending on the size. Gener-
ally steam is produced for purposes such as process heating, space heating,
and electric generation. Combustion occurs with around 15% excess air. One
example of an industrial-sized furnace is that of a D-type integral furnace
boiler as shown in Attachment 8-4. Many units are capable of burning either
oil or gas.
Utility boilers which are oil fired burn No. 6 fuel oil, Bunker C, at
rates of 3,500 to 60,000 gph. These are large installations having proper
combustion-control systems and maintenance for maximum efficiency with com-
bustion at around 3% excess air.
Examples of Burners
A large number of oil burner (atomizer) designs have been developed
to meet objectives such as economy, durability, and reliability in provid-
ing the atomization or flame requirements of the various furnace designs.
Examples of burners are presented in the following paragraphs.
A high-pressure atomizer for domestic applications is illustrated in
Attachment 8-5. Units of this type may burn No. 2 fuel oil (0.5 to 30 gph)
at oil pressures of 100 psi. Note the cone nozzle and swirl vanes which
provide an increase in air/fuel mixing. Electrodes provide a continuous
source of ignition. Control of the oil pump, typically, is by a thermo-
statically controlled on/off switch. High-pressure atomizers for commer-
cial and industrial applications may burn No. 4 or 5 fuel oil (up to
200 gph) with oil pressure up to 300 psi.
8-4
-------
A low-pressure air atomizer is illustrated in Attachment 8-6. In
domestic applications, No. 2 fuel oil is burned (0.5 to 6 gph) with oil
and air pressures around 3 psi. Note the tangential air passages which
produce swirl of primary air prior to impacting film of oil. In commercial
applications No. 4 and 5 fuel oils also may be burned (5 to 150 gph) with
air and oil pressures from 12 to 50 psi.
Steam or air atomizers for commercial, industrial, and utility appli-
cations (up to 1,100 gph) may have oil pressure up to 1,000 psi and steam
pressure 20 to 40 psi greater than oil pressure. The burners may be exter-
nal mixing with a typical atomization cone and flame (see Attachment 8-7)
or internal mixing with a short, bushy flame (see Attachment 8-8). If
steam is used, a steam trap is provided to remove condensate which would
cause nozzle erosion.
Mechanical atomizers, with provisions for firing control by return-flow
(spill-back) pressure regulation, are illustrated in Attachments 8-9 and
8-10. Oil pressure may vary from 450 to 1,000 psi in typical industrial
and utility applications with a fuel rate up to 1,250 gph.
The horizontal rotary cup oil burner was formerly in widespread use.
However, as was indicated in Attachment 8-1, the droplet sizes formed are
considerably larger than for other burners. ' Smoking tendencies have re-
sulted in sources changing to burners of other designs. In the rotary cup,
as illustrated in Attachment 8-11, an oil film inside a hollow cup (spin-
ning at around 3,500 rpm) is subjected to centrifugal forces which cause
the atomization. If the cup becomes eroded or cracked, atomization quality
deteriorates.
8-5
-------
Factors Influencing Air Pollutants from Oil Combustion
The properties of the oil and the characteristics of the combustion
equipment influence the air pollution emissions from stationary sources.
Air pollutant emission factors for oil combustion are presented in Attach-
ment 8-12.
The emission factors for sulfur oxides (expressed as lb./l,000 gal.)
depend primarily on the sulfur content and to a lesser extent on the type
of fuel (distillate or residual, because of their different densities).
Nitrogen oxide emission factors are larger for larger combustion instal-
lations. This is dependent upon the combustion temperature and nitrogen com-
position in the fuel, both of which are more favorable with smaller installa-
tions.
Fuel oil has a small ash composition from a trace amount in No. 2 to
0.08% in No. 6. Particulate emissions depend on the completeness of com-
bustion as well as the ash content. The emission factor for particulate
emissions from residual oil burning is related to the sulfur content. This
results from the fact that lower sulfur No. 6 fuel oil typically has sub-
stantially lower viscosity and reduced asphatene and ash content. Conse-
quently, lower sulfur fuel oils atomize and burn easier. This applies
regardless of whether the fuel oil is refined from naturally occurring low-
sulfur crudes or is desulfurized by current refinery practice.
The vanadium content in fuel oil may be deposited in the ash on boiler
metallic surfaces. These deposits act catalytically in converting SC^ to
SOj, thereby creating dew-point and acid smut problems. Oil-fired burners
may emit acid smuts (particulates) which fall out near the stack and stain
or etch painted surfaces. Acid smuts may be caused by the metallic surfaces
8-6
-------
operating well below the acid dew-point of the flue gas with soot absorbing
sulfuric acid vapor. Switching to a negligible vanadium content fuel may
reduce the conversion of SC>2 to SO3 and thereby avoid the acid smut prob-
lem.
Both sodium and vanadium from fuel oil may form sticky ash compounds
having low melting temperatures. 'These compounds increase the deposition
of ash (fouling heat exchange surfaces) and are corrosive. Soot blow-
ing should be frequent enough so that ash deposits cannot build up to a
thickness where the surface becomes molten and thereby difficult to clean.
Fuel oil additives, such as alumina, dolomite, and magnesia, have been
found effective in reducing superheater fouling, high-temperature ash corro-
sion, and low-temperature ash corrosion. Additives may either produce high
melting point ash deposits (which do not fuse together) or form refractory
sulfates which are easily removed in soot-blowing.
Other fuel oil additives may reduce smoke and particulate emissions.
Organometallic compounds of manganese, iron, nickel, cobalt, barium, and
calcium have a catalytic influence either on oxidation of soot or on the
promotion of free radicals which react with soot.
Maintenance of atomizing nozzles includes removing them from the fur-
nace, cleaning them to remove deposits and foreign materials, and inspect-
ing them for wear or cracks. A major installation may require maintenance
of nozzles during each eight-hour shift. On the other hand, a small resi-
dential installation may require nozzle replacement and strainer cleaning
•' •!>
only once a year. Poor atomization results in flames which are longer and
darker and which increase the soot or slag buildup on furnace walls. Soot or
slag act as insulators and thereby reduce the heat transfer efficiency.
8-7
-------
Draft is the negative pressure difference between the inside of the
furnace (or stack) and the outside. If draft is too high the hot gases are
accelerated too fast with inadequate residence time for complete combustion.
If stack draft is too low, adequate pressure drop may not be available
to pull the gases across the convection breeching. If furnace pressure
becomes greater than atmospheric, cooling air is no longer drawn in through
various cracks and apertures, and there is outward movement of hot gases,
quenching of combustion gases, and overheating of the furnace structure.
Draft should be set at original design value for proper residence time,
air/fuel mixing, and settling velocities for blown soot.
Poor ingition and unstable flames can cause smoke. Ignition provisions
vary with fuel and atomizer type. A domestic unit firing No. 2 fuel oil
may have a continuous spark between two electrodes which is driven by a
7,000 to 10,000-volt transformer. By contrast, a utility or industrial
unit may have a fully programmed staging sequence which uses pilot, auxi-
liary fuel igniters, staged burner controls, and safety interlocks (which
may use optical, pressure, or temperature-sensing equipment).
Smoking may occur during a cold start unless the design provides for
adequate ignition energy and controlled delivery and mixing of the fuel and
air. Ignition energy must compensate for the extra high heat loss to the
cold combustion chamber. In order to reduce smoke and reduce furnace damage
due to thermal shock, some systems provide for slow heating of combustion
chamber prior to full fuel firing rate.
The U. S. Environmental Protection Agency has published adjustment pro-
cedures for packaged industrial, commercial, and domestic units (5, 6, 7).
These procedures will be discussed in Chapter 17.
8-8
-------
References
1. Burkhardt, C. H., Domestic and Commercial Oil Burners, Third Edi-
tion, McGraw-Hill Book Co., New York (1969).
2. Fryling, G. R., Combustion Engineering, Revised Edition, published
by Combustion Engineering, Inc., New York (1966).
3. Steam; Its Generation and Use, 38th Edition, published by Babcock
and Wilcox, New York (1972).
4. Reed, R. D., Furnace Operations, Second Edition, Gulf Publishing
Co., Houston (1976).
5. "Guidelines for Residential Oil Burner Adjustment," EPA-600-2-75-069a
(Oct. 1975).
6. "Guidelines for Burner Adjustments of Commercial Oil-Fired Boilers,"
EPA-600/2076-008, published by Industrial Env. Res. Lab, USEPA (March 1976).
7. "Guidelines for Industrial Boiler Performance Improvement," EPA-
600/8-77/003a, published by Industrial Env. Res. Lab, USEPA (Jan. 1977).
8. Percival, J., "Fuel Oil Burning —Design Parameters and Good Oper-
ating Practice," unpublished paper, ESSO Research and Engineering Co.,
Linden, N.J. (Feb. 17, 1969).
9. "Commercial and Industrial Fuel Oil Equipment and Its Preventive
Maintenance," Publication No. 67-100, National Oil Fuel Institute, Washing-
ton, D.C. (1967).
10. Johnson, A. J., and Auth, G. H., Fuels and Combustion Handbook,
McGraw-Hill Book Co. (1951).
11. Compilation of Air Pollutant Emission Factors, 3rd Edition, AP-42,
Part A, U. S. Environmental Protection Agency, 1977.
8-9
-------
Attachment 8-1, Atomizing Characteristics of Different Burners-
Distributions of Droplet Size
50 100 150 200 250 300 350 400
02
A = steam atomizing
B = pressure-jet atomizing
C = rotary cup atomizing
Attachment 8-2, Typical Oil Combustion Design Parameters8
Unit Type
Home Heat
Apartment Boiler
Ship's Boiler
60 MW Power
Station
Heat Input
Million
Btu/hr
0.18
2.2
80
600
Excess
Air, %
40
27
15
3
co2
11
13
14
15.7
Volumetric
Heat Release
Btu/hr ft3
340,000
100,000
70,000
20,000 to 40,000
Residence
Time
Sec.
0.13
0.50
0.80
2.2 to 1.1
8-10
-------
Attachment 8-3, Scotch-Marine (Fire-Tube) Boiler
Attachment 8-4, D-Type Integral Furnace Boiler
8-11
-------
Attachment 8-5, Typical Pressure Atomizing #2 Oil Burner-
COMBUSTION
oo
i
-------
Attachment 8-6, Low-Pressure, Air-Atomizing Oil Burner®
Attachment 8-7, External Mix Steam or Air-Atomizing Burner9
**H or I/Mm M«p/s
Attachment 8-8, Internal Mix Steam-Atomizing Burner^
I -MIXING NOZZLE
2-SPRAVER PLftTE
'•NOZZLE BODY
4-ATOMIZER BARREL
5- INLET TUBE
V/s?//////,
8-13
-------
Attachment 8-9, Mechanical Atomizer, Return-Flow Type
10
Oil return
inlet. \
Whirling
chamber
- , Sprayer plafe
Sprayer / nut
Orifice P'°
-------
Attachment 8-
-------
Attachment 8-12, Emission Factors for Fuel Oil Combustion
Pollutant
Particulateb
Sulfur dioxide1*
Sulfur trioxided
Carbon monoxide6
Hydrocarbons
(total, as CH4)f
Nitrogen oxides
(total, as N02)9
Type of boiler3
Power plant
Residual oil
lb/103gal
c
157S
2S
5
1
105(50)"-'
kg/103 liter
c
19S
0.25S
0.63
0.12
12.6(6.25)"-'
Industrial and commercial
Residual oil
lb/103gal
c
157S
2S
5
1
60)
kg/103 liter
c
•19S
0.25S
0.63
0.12
7.5J
Distillate oil
lb/103gal
2
142S
2S
5
1
22
kg/103 liter
0.25
17S
0.25S
0.63
0.12
2.8
Domestic
Distillate oil
lb/103gal
2.5
142S
2S
5
1
18
kg/ 103 liter
0.31
17S
0.25S
0.63
0.12
2.3
T
cn
aBoilers can be classified, roughly, according to their gross (higher) heat input rate,
as shown below.
.Power plant (utility) boilers: >250 x 106 Btu/hr
(>63x 10bk9-cal/hr)
Industrial boilers: >15 x 106, but <250 x 106 Btu/hr
O3.7 x 106, but <63 x 106 kg-cal/hf)
Commercial boilers: >0.5 x 106, but <15 x 106 Btu/hr
(>0.13 x 106, but <3.7 x
Domestic (residential) boilers: <0.5 x 106 Btu/hr
«0.13x lOSkg-cal/hr)
bBased on References 3 through 6. Particulate is defined in this section as that
material collected by EPA Method 5 (front half catch)7.
cParticulate emission factors for residual oil combustion are best described, on
the average, as a function of fuel oil grade and sulfur content, as shown below.
Grade 6 oil: lb/103 gal = 10 (S) + 3
[kg/103 liter = 1.25 (S) + 0.38]
Where: S is the percentage, by weight, of sulfur in the oil
Grade 5 oil: 10 Ib/IO* gal (1.25 kg/lfP liter)
Grade 4 oil: 7 lb/103 gal (0.88 kg/103 liter)
Based on References 1 through 5. S is the percentage, by weight, of sulfur in
the oil.
eBased on References 3 through 5 and 8 through 10. Carbon monoxide emissions
may increase by a factor of 10 to 100 if a unit is improperly operated or not well
maintained.
'Based on References 1, 3 through 5, and 10. Hydrocarbon emissions are gener-
ally negligible unless unit is improperly operated or not well maintained, in
which case emissions may increase by several orders of magnitude.
9Based on References 1 through 5 and 8 through 11.
"Usv! 50 lb/103 gal (6.25 kg/103 liter) for tangentiaily fired boilers and 105
lb/103 gal (12.6 kg/103 liter) for all others, at full load, and normal (>15
percent) excess air. At reduced loads, NOX emissions are reduced by 0.5 to
1 percent, on the average, for every percentage reduction in boiler load.
'Several combustion modifications can be employed for NOX reduction: (1)
limited excess air firing can reduce NOX emissions by 5 to 30 percent, (2) staged
combustion can reduce NOX emissions by 20 to 45 percent, and (3) flue gas
recirculation can reduce NOX emissions by 10 to 45 percent. Combinations of
the modifications have been employed to reduce NOX emissions by as much as
60 percent in certain boilers. See section 1.4 for a discussion of these NOX-
reducing techniques.
'Nitrogen oxides emissions from residual oil combustion in industrial and com-
mercial boilers are strongly dependent on the fuel nitrogen content and can be
estimated more accurately by the following empirical relationship:
Ib NO2/1Q3 gal = 22 + 400 (N)2
[kg NO2/103 liters = 2.75 + 50 (N)2]
Where: N is the percentage, by weight, of-nitrogen in the oil. Note: For residual
oils having high ( >0.5%, by weight) nitrogen contents, one should use 120 Ib •
NO2/103 gal (15 kg NO2/103 liter) as an emission factor.
-------
CHAPTER 9
COAL BURNING
The problem of energy supply has refocused attention upon coal as a
viable energy resource, and the changeover of coal-burning facilities to either
oil or natural gas has halted. This changeover, which became popular in the
1960's, was stimulated by both economic and air quality considerations.
In the late 1960's natural gas was available at an average cost of $0.64
per 106 Btu, low-sulfur oils at $0.72 per 10 Btu, and coal at around $0.50
per 10 Btu. Due to the considerably greater capital investment required to
burn coal acceptably, there was little incentive for burning coal. Although
\
today the physically and environmentally cleaner fuels have much to recom-
mend them, federal energy policy as well as major energy users are vitally
concerned with fuel availability, which has become a most important feature
of the economics involved.
This chapter introduces the fundamental practical aspects of coal com-
bustion. Additional details may be found in the references.
Coal, as found in nature, occurs in seams of varying thickness and at
various depths in the earth. As mined, coal will contain varying amounts of
fixed carbon, volatile matter, sulfur, clay, and slate. It is classed into
four broad ranks in accordance with ASTM D-388 (1) (see Attachment 3-10),
which essentially categorizes it by considering fixed carbon and calorific
values. An obvious air pollution concern relates to its sulfur content,
which ranges from 0.5 percent or less, to something over 8 percent, depend-
ing on source. Table 9.1 lists estimates of coal reserves by rank in terms
of sulfur content. Bituminous coals are the more commonly used steaming
coals, though sub-bituminous coal is increasing. The distribution of
9-1
-------
£T
major bituminous coal sources is shown in Table 9.2 (see Attachment 3-9
for a more complete total). As!h content is an important parameter, both
in terms of firing equipment and particulate emissions. Sulfur and ash
content are somewhat interrelated, in that some of the coal "ash" is due
to the presence of iron pyrites, which also contain sulfur.
TABLE 9.1
ESTIMATED COAL RESERVES - BILLIONS OF TONS
COAL RANK
Bituminous
Sub-bituminous
Lignite
Anthracite
TOTALS
' Percent of 1500
SULFUR CONTENT
<0.7
104
256
344
14
720
46
0.8-1.0
111
130
61
96
.
303
19
1.1-1.5
49
41
90
6
>1.5
464
1.3
0.5
466
29
9-2
-------
TABLE 9.2
BITUMINOUS COAL SOURCE DISTRIBUTION
Billions of Tons, Estimated (4)
Location of Some Major Deposits
STATE
Alaska
Colorado
'. Illinois
Kentucky
Missouri
Ohio
Pennsylvania
West Virginia
Wyoming
i
SULFUR CONTENT %
<0.7
20
25
18.6
20.7
6.2
0.8-1.0
37
6.5
26.7
1.1-1.5
4.9
3.3
7.6
21.8
6.6
>1.5
138
40
78.7
41
49 |
33
I
Source: U. S. Bureau of Mines Circular 8312
The sulfur in coal is found in both organic and inorganic forms, with
somewhat over fifty percent as inorganic iron pyrite and marcasite (2). Coal
cleaning at the mine will reduce the ash content and simultaneously reduce
the sulfur content by removing some of the iron pyrites. Cleaning is accom-
plished by gravimetric separation, which is a successful method because
pyrites are about five times more dense than coal. Unfortunately, methods
•" ' i''
to reduce organic sulfur are not economic at this time. Consequently, flue-
gas-desulfurization may be required. Although the costs are very high,
successful schemes have recently been demonstrated (5). The urgent need
for sulfur emission control and the limited availability of low-sulfur
9-3
-------
fuels will continue to stimulate economic and legal incentive to speed
the development of improved control systems.
To choose coal as a fuel for a given plant site, its storage must be
considered. Fresh coal slowly deteriorates when exposed to weathering.
Careful attention must be given to the manner in which the coal is stock-
piled; large piles loosely formed can ignite spontaneously. This problem
is most severe with smaller sizes and high sulfur content. Where very large
storage is needed, such as at power stations, stock piles are created by us-
ing large equipment to form piles several hundred feet wide, several thousand
feet long, and about twenty feet high. Coal is distributed in layers and com-
pacted with "sheep's foot" rollers to minimize air pockets. Where smaller
quantities are stored and turnover is rapid, conical piles are used with a
12-foot depth or less. Where open piles are not permitted, silos are used
for coal storage. These are equipped with fugitive dust control for use
during loading.
Coal is burned in a wide variety of devices, depending on the rate of
energy release desired, the type and properties of the coal burned, and the
form in which it is fired. In general, firing can be accomplished by using
either overfeed or underfeed stokers, with residence burning on grates, or by
using pulverized feed where coal burns in suspension essentially as a fluid-
ized-solid. Spreader stoker-fired units tend to combine an overfeed scheme
with suspension burning. Cyclone furnaces operate with the coal converted
to molten slag.
What characteristics of coal influence the choice of firing
equipment and operational procedures? Combustion requires oxygen,
commonly provided by admitting atmospheric air. The chemical analysis
of the fuel determines the amount of air needed. The combustibles
9-4
-------
in coal are carbon, hydrogen, and sulfur. The minimum theoretical (stoichi-
ometric) air supply is that which will fully oxidize these combustibles.
To compute this quantity requires the knowledge of the quantities of each
element present in a coal, information which is provided by the ultimate
analysis. To determine such an analysis requires a well-trained chemist
in a well-equipped laboratory.
A second analysis containing less chemical data, but still quite useful
nevertheless, is the proximate analysis. This analysis gives the fixed car-
bon, volatile matter, ash, and "free moisture" found in a given coal. While
it cannot provide specific chemical data, it does provide relative burning
data. For example, fixed carbon is that carbon in coal which is a solid,
as opposed to that which may be combined in volatile matter and can be "boiled
off" as a gas when coal is heated. For a given size of coal, the required
burning time is increased as the fixed carbon increases. While this may seem
of importance only for grate-fired units, it is also important in pulverized
firing. A coal with higher fixed carbon probably would have to be pulverized
to a higher percentage fines compared to one of lesser fixed carbon content.
Because of fuel variability, some plants routinely sample each railcar of coal
for analysis.
A typical "as-received" proximate analysis is given in Table 9.3.
TABLE 9.3
PROXIMATE ANALYSIS - AS RECEIVED (6)
Percent by weight
Fixed Carbon 75.26
Volatile Matter 17.91
Moisture 3.10
Ash 3.73
100.00
9-5
-------
The moisture of the proximate analysis is the "free moisture," and will vary
according to how the coal is handled. An ultimate analysis of the same fuel is
given in Table 9.4.
TABLE 9.4
ULTIMATE ANALYSIS - AS RECEIVED (6)
Percent by weight
Carbon 84.02
Hydrogen 4.50
Oxygen 6 .'03
Sulfur 0.55
Nitrogen 1.17
Ash 3.73
100.00
As mentioned earlier, the data provided by the ultimate analysis are
useful in computing theoretical air requirements. For example, the theoreti-
cal air computation for the coal in Table 9.4 is:
theoretical air = 11.53 C + 34.34 (H2 - £2_ ) + 4.29 S
8
= 11.53 (.8402) + 34.34 (.0450 - -s-) 9.1
+ 4.29 (0.0055)
= 11.00 Ibs. per Ib. of coal
The excess air required for this coal would vary depending, upon the method
of firing, but may range from a low of 10 percent, for pulverized firing, to
60 percent, for small stoker-fired units. The mass of gas flow required in
a given system can be determined for the fuel, which in turn establishes the
9-6
-------
gas volume at a specified temperature and pressure. Operation with a fuel
that varies from the design analysis may be accommodated by proper controls
and training of operating personnel. As an example, spreader stokers with
a traveling grate are normally operated with an ash depth of two to four
inches. An increase of coal ash content requires increased running speed
for the grate to maintain the same ash thickness. This is consistent with
the need to feed more coal to achieve a desired energy release rate. Air-
flow adjustment must also be in proper proportion to insure good burning.
There are other characteristics of coal which influence the design and
operation of firing equipment. Among these are: ash fusion temperature,
free-swelling index, and grindability. Grindability reflects the relative
ease with which coal can be ground. The free-swelling index and ash fusion
temperature are important indicators of the behavior of the ash under differ-
ent conditions. For burning on grates, the free-swelling index is important,
since it is a measure of ash's tendency to agglomerate or cake. For sys-
tems where the grates have no motion to break up the crust, a free-swelling
index of five or less is needed. Ash fusion temperature must be high enough
to prevent molten ash from forming clinkers in the case of grate units, or
from adhering to heat exchange surfaces in pulverizing units. Cyclone fur-
nace or wet-bottom furnaces require ash fusion temperatures high enough to
insure good operation.
Methods of Firing
A large variety of mechanical stokers has been developed for burning
coal. The operating principles vary" in terms of how the coal is introduced
into the furnace. Feeding can take place from below, from above, or by
broadcasting onto a grate. Each of these feeding methods has considerable
9-7
-------
influence upon the design of the furnace, boiler, and associated subsystems.
Stokers tend to fall into one of the categories given in Table 9.5;
their steam-generating capacities fall in the following ranges:
Underfeed — 30,000 Ibs/hr or less
Spreader — 75,000 Ibs/hr to 400,000 Ibs/hr
Vibrating— 50,000 Ibs/hr to 200,000 Ibs/hr
TABLE 9.5
STOKER TYPES AND ENERGY RATE
Energy Rate
Type Btu/ft2 hr.
Underfeed— Single Retort 400,000 max
Underfeed— Multiple Retort 600,000 max
Chain and Traveling Grate 300,000 - 500,000
Spreader — Dump Grate 250,000
— Traveling with continuous
ash discharge 750,000 max
Vibrating Grate 400,000 max
Spreader stokers are more commonly found in existing units than are vibrat-
ing grate systems. Pulverized-fired units are becoming more common for
100,000 Ib/hr or greater capacity. This trend is due to the cost of stoker
coal, compared to coal suitable for pulverizers. Stoker coal is usually low
ash, preferably less than 10 percent with volatile matter from 5 to 20 per-
cent and a size consist range between 1/4" and 1.5". Coal for pulverized
firing can be run-of-mine with ash content to 30 percent. Prior to the
fall of 1973 the price per 106 Btu for stoker coal was considerably greater
than run-of-mine coal. Prices for both types of coal are variable, and it is
9-8
-------
not possible to state a cost differential at this time. Also note
that demand for low sulfur coal exceeds supply to the extent that usual
quality control at the mine has deteriorated.
For a given energy input, Table 9.5 may be used to establish the grate
area required. This is illustrated by assuming a spreader stoker fired
unit with a traveling grate which must produce 108 Btu/hr from burning coal
with a HHV of 26 x 106 Btu/ton. The HHV of 26 x 106 Btu/ton is equivalent
to 13,000 Btu/lb, which is a good quality coal that could be fired at the
2
maximum rate of 750,000 Btu/hr ft in Table 9.5. Therefore, the area
needed is:
108 Btu/hr 2 2
= 1.33 x 10 ft , and the feed rate
.75 x 106 Btu/ft2 hr
8
is: = 3.85 Ton/hr
.26 x 10B
The net grate area establishes the furnace cross section, since the
grate i-s usually designed with a length approximately 1.2 x width. The
energy release per unit volume for burning coal is about 30,000 Btu/hr ft .
Utilizing data from the example, the furnace volume would be given by:
108 Btu/hr » 3.33 x 103 = 3330 ft3
30,000 Btu/hr ft3
This dimension,coupled with area previously calculated, would result in a
furnace about 25 feet high.
Table 9.6 summarizes the volumetric energy release rates normally em-
ployed in coal-burning systems.
9-9
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TABLE 9.6
HEAT RELEASE RATES - DESIGN VALUES
Btu/hr per cu. ft.
Pulverized Coal 20,000 to 30,000
Stokers - continuous ash removal 30,000 to 35,000
Stokers - dump or stationary 15,000 to 25,000
Mechanical stokers universally require coals with ash fusion tempera-
ture high enough to prevent molten ash formation on grates. Cyclone coal
furnaces, shown in Attachment 9-1, on the other hand, are designed to
operate with the. ash in molten slag condition. These units are usually
fired with coal that has been ground fine enough to pass through a "No.4"
screen. Coal is fed into one end of a cylindrical furnace and air is ad-
mitted tangentially- Gases therefore rotate as they flow down through the
water-cooled furnace structure. The ash reaches fluidity temperature and
flows through the furnace as a molten slag. Slag temperatures range from
2,500 to 3,000°F. Energy release rates for these furnaces range between
450,000 to 800,000 Btu/ft . Large steam generators may employ two or more
of these furnaces. A significant characteristic of this firing method is
very low fly ash entrainment, a definite advantage for particulate emission
control. Cyclone furnaces are no longer being built due to high NOX emissions.
Air Supply and Distribution
The determination of combustion air has been previously presented;
but questions remain about how and where the air should be introduced.
Resolution of these questions depends upon the type of firing and rank of
coal. Lower design values,as specified for heat release rates given in
9-10
-------
Table 9.6 apply to lower rank coals. Where the air is to be introduced is in-
fluenced by the method of firing and the amount of volatile matter. Under-
feed retort stokers usually require very little overfire air, regardless of
the type of fuel fired. This can be explained by examining Attachments 9.2
and 9.3. The coal retort is normally the region in which "green" coal
undergoes distillation as it moves up through the fuel bed. Volatile gases
flow upward through a burning carbon region and as they flow, air from the
tuyeres provides good mixing, and therefore good burning. Since gaseous
hydrocarbons which may leave the fuel bed are well mixed with air, additional
air is not required either for turbulence or to maintain proper oxidation.
Mechanical stokers which employ overfeed or spreader feed represent a
different problem, both with respect to excess air and air distribution.
Underfeed stokers would employ 50 to 60 percent excess air with all entering
as underfire air. Overfeed units, such as the chain-grate stoker shown in
Attachment 9.4, require some overfire air in addition to a controlled air
flow along the grate itself. The chain grate unit operates with coal fed
from the gate which maintains a 5" to 7" fuel bed thickness, with ignition
occuring downstream of the gate. Ignition progresses from the top surface
down as the coal moves from left to right. Gases which evolve as the
coal is heated leave this fuel bed near the feed end. Therefore, air must
be added from above to provide the needed oxygen and turbulence for oxidation
of the combustible gases. Depending upon the coal's volatility, overfire
air can be as much as 20 percent of the total air supplied. Excess air
ranges from 25 to 50 percent, depending upon coal rank and upon size consist.
Overfire air is normally supplied from a booster fan system as seen in
Attachments 9.6 and 9.7, rather than from a forced-draft system.
9-11
-------
Underfire air must be regulated to provide greatest flow where coal
ignites and along the region where fixed carbon burns in residence. .Since
grate sections are all alike, underfire air flow is regulated by con-
trols in each compartment.
The vibrating grate stoker, Attachment 9-6, represents another varia-
tion. Here the ash end of the grate is below a low arch which causes air
flow through the bed to move back into the main furnace region. The low
arch tends to radiate energy back to the fuel bed, thus helping to keep
temperature up and ensure good burn-out. Arches of this type would be
used with low volatile matter coals and will be found in chain or traveling
grate units where such coals are burned (see Appendix 9-1).
The spreader stoker-traveling grate unit illustrated in Attachment 9-7
represents still another variation. In these units the spreader distributes
coal by broadcasting it from front to back. Large pieces go to the rear,
fines burn in suspension. Here overfire air must be provided at the back
and from the sides as well. Air jets are sometimes placed near the
spreaders to prevent fines from piling locally. Suspension burning also
results in carbon carryover, part of which normally settles out in one or
more gas pass regions of the boiler. This particulate is reinjected with
the overfire air, again using a separate forced draft fan to supply the
needed air at high enough pressure to operate the reinjection arrangement.
Spreader stokers were quite popular in the past since they were able to
handle a wide variety of coals and were suitable for steam generators with
capacities to 400,000 ibs. of steam per hour. They do require a consist
ranging from 1/4" to 1-1/4" equivalent round hole with no more than 10 per-
cent passing a 1/4 mesh screen. Consist of 1/4" to 3/4" is even better,but
coal costs are higher when closer size consist control is specified. Cost
9-12
-------
and availability of good stoker coals has caused a shift to pulverized coal
firing in recent years for units as small as 100,000 Ibs. per hour steam
capacity. Pulverized coal burning can be accomplished using run-of-the-
mine consist coal, with ash content to 20 or even 30 percent. Mechanical
stokers usually do not operate properly with high ash content coal. One
other area of difficulty with spreader stokers occurs when the unit is opera-
ting at light loads (less than 25 percent). When loads are small, it be-
comes difficult to maintain a proper fuel bed on the grates.
Air distribution in pulverized fired coal burners (see Attachment 9.8)
is divided between primary and secondary air. Primary air is used to trans-
port coal from the pulverizers to the burners. About 2 Ibs. of air per Ib.
of coal is required. Transport velocities are typically 4000 to 5000 fpm
with 3000 fpm a minimum. Secondary air is usually introduced at the burners,
but can be introduced at other locations in the furnace.
Cyclone furnaces introduce approximately 20 percent of the required
combustion air with the coal feed to the burner. Secondary air is admitted
tangentially into the main barrel of the furnace. A small amount of air,
up to 5 percent, can be admitted at the center of the radial burner.
In general, coal-fired steam generators will smoke when air quantity
is inadequate, or when the air is improperly distributed, or when too
much excess air is used. Improper distribution can be caused by faulty
control,or by improper fuel bed conditions where burning occurs on grates
with poor air distribution through the fuel bed. This condition can be
caused by a too-deep or non-uniform fuel bed, or by low ash-fusion
temperature. Ash fusion gives rise to air flow pattern distortion, since
it causes clinkers or crusts to form through which air cannot flow.
9-13
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Normally this problem can be spotted visually by the boiler operator,
and the clinkers can then be removed. A good coal fire has
a bright yellow-orange flame with slightly hazy tips. A whitish or "cold"-
looking fire probably has too much air. Proper combustion control requires
either a CO2 or G>2 flue gas monitor. The 02 meter is preferable
where several fuels can be fired. Generally, C02 should range from 10 to
13 percent in flue gas from stoker-fired units and from 13 to 15 percent for
pulverized units. ©2 content ranges from 2 to 8 percent, depending on the
type of firing.
Air Pollution Considerations
Coal combustion is responsible for a significant fraction of the annual
SOX and particulate inventory. SOX control can be accomplished by either
prevention or abatement. Prevention requires either a_ priori removal of
sulfur from coal or limiting coals fired to those with very low sulfur
content. Very probably, both approaches will be needed if the nation's
energy needs are to be adequately met, at least in the next decade or
so.
A short-term solution which seems to be available is the use of low-
sulfur western coal as a replacement for high-sulfur eastern coal. Such
coal can theoretically be transported by pipeline or rail or both. Unfor-
tunately, as is so often true of a particular technology, boilers designed
for eastern coal do not thrive on a diet of western coal. The difficulty
arises from the fuel properties: high inherent moisture content, lower
calorific value, and fouling characteristics.
Sub-bituminous coal found in parts of Wyoming and Montana contain
20 to 30 percent moisture which is inherent in the coal. This moisture is
9-14
-------
part of the coal's fixed carbon content. The resulting lower heating value
is further aggravated by the energy needed to vaporize the moisture. The
combined effect of these two variables is a reduced flame temperature, which
means reduced radiant energy transfer to the furnace walls.
In addition, the vapor present has a higher specific heat than
other constituent gases which raises the flue gas specific heat. This
is shown by the basic thermodynamic relationship:
r
.£, N. C . r
r - 1=1 x P1 - V v C •
upm ~ r " .V1 pl
I % 1=1
where Cpm is the molal specific heat of a mixture of r gases , and yi
and Cpi are the mole fractions and specific heats of the i-th component,
respectively. This increase in specific heat, coupled with lower heat uti-
lization in the furnace (see Chapter 4) causes high heat transfer, with high
temperatures in the convective superheaters,because the attemperator control
range is exceeded. Reduced-capacity operation is therefore often necessary.
The reduced energy content means more coal must be used for a given
output, thus increasing storage, handling, and grinding requirements. If
calorific content is low, the sulfur dioxide emission standard (per million Btu)
may be exceeded, despite the supposedly low sulfur content. Ash content
may also be a significant burden, due to increased total quantity of coal
which must be fired. In general, the use of western coal is not a simple
proposition. Uncontrolled emission factors, while not necessarily appli-
cable to any one system, serve as a gauge for the relative impact of a
number of sources.
9-15
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Uncontrolled equipment emission factors are given in Table 1.1.2, page 5-30,
Appendix 5-1. These factors provide estimates of the pollutant load enter-
ing the control device, based on the fuel's firing rate. These data illus-
trate that uncontrolled particulate emissions are near the same for large coal-
fired units (100 x 10 Btu/hr) with the exception of the cyclone furnace.
The lower particulates emitted from a cyclone furnace illustrate the advan-
tage of feeding a course grind and operating with molten ash. There is a
penalty, however, in the form of an increased NOX emission, because the
operation takes place at significantly elevated temperatures. This same
situation can be seen in slag-top (wet-bottom) pulverized coal units.
Chapters 16 and 17 will present NOx-control theory and experience.
An economic "state of the art" has not yet evolved. However, two tech-
niques currently receiving major attention are: excess air control and staged
firing. Flue gas recirculation, which is effective in controlling NOX from
gas combustion, is much less effective with coal combustion. It is diffi-
cult to predict which of several techniques will emerge as more practical
and useful. The amount of NOX control which is required and economics will
both play a large part in this picture. Expensive oil may very well serve
to accelerate the development of better coal pollution control methods.
At the present time, electrostatic precipitators and wet scrubbers
appear to be the acceptable methods to control particulate and SOy emis-
sions from relatively large sources. Concern about the emissions of fine
particulates may result in increased use of baghouses.
References
1. American Society for Testing Materials, Specification D 338.
2. Steam, Its Generation and Use, 38th Edition, The Babcock and Wil-
cox Company, 1973.
9-16
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3. Steam, Its Generation and Use, 37th Edition, The Babcock and
Wilcox Company, 1963.
4. U. S. Bureau of Mines, Circular 8312.
5. Quig, Robert H., "Recycling SO, from Stack Gas: Technology
Economics Challenge," Professional Engineering, May 1974.
6. Morse, F. T., Power Plant Engineering, Third Edition, D. Van Nos-
trand Company, Inc. (1953).
7. Field Surveillance and Enforcement Guide; Combustion and Incinera-
tion Sources, Environmental Protection Agency APTD-1449 (June 1973).
8. Compilation of Air Pollutant Emission Factors, Third Edition,
AP-42, U. S. Environmental Protection Agency (1977).
9. Gray, R. J. and Moore, G. F., "Burning the Sub-Bituminous Coals
of Montana and Wyoming in Large Utility Boilers," ASME Paper No. 74-WA/FU-l.
10. Overfire Air Technology for Tangentially Fired Utility Boilers
Burning Western U. S. Coal, EPA-600-7-77-117, IERL, U. S. Environmental Pro-
tection Agency (October 1977).
11. Kilpatrick, E. R. and Bacon, H. E., Experience with a Flue Gas
Scrubber on Boilers Burning Colstrip Sub^Bituminous Coals, ASME Paper No.
74-WA/APC-3.
12. Corey, R. C., "Burning Coal in CPI Boilers," Part I, Chemical
Engineering (January 16, 1978).
13. Richards, C. L. , "Conversion to Coal— Fact or Fiction," Combus-
tion (April 1978).
9-17
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Attachment 9-1, Cyclone Furnace-
Emergency Standby
Oil Burner
Secondary Air
Gas Burners
Replaceable
Wear Liners
Re-entrant
Throat
Slag Tap Opening
Reprinted with permission
of Babcock & Wilcox
Attachment 9-2, Single Retort Underfeed Stoker-
LONGITUDINAL SECTION
Reprinted with permission
of Babcock & Wilcox
9-18
-------
Attachment 9-3, Section Thru Underfeed Stoker'
Reprinted with permission
of Babcock & Wilcox
Attachment 9-4, Chain Grate Stoker:
Attachment 9-5, Chain Grate Fired Steam
Generator
GRAVITY
CINDER
RETURNS
TO GRATE
A
Reprinted with permission
of Babcock & wilcox
Reprinted with permission
of Babcock & Wilcox
9-19
-------
Attachment 9-6, Vibrating Grate Stoker1
con HOPPE«"
M»L OJTE-i 1
OVERFIBE-AIR HOZZUS '
Coal Hopper
Feeder
Stoker
Chain
Reprinted with permission
of Babcock & Wilcox
Attachment 9-7, Spreader Stoker
4*2
Traveling Grate Unit
Air Register Door
(Secondary Air) (Oil) Lighter Windbox
Coal Nozzle :
Regulating
Rod \
Attachment 9-8, Pulverized Coal Burner^
Water-Cooled Coal Impeller
Furnace Wall
Refractory Throat
with Studded Tubes
9-20
Reprinted with permission
of Babcock & Wilcox
-------
APPENDIX 9-3
CORROSION AND DEPOSITS FROM COMBUSTION GASES
William T. Reid*
A rough estimate a few years ago by the
Corrosion and Deposits Committee of ASME
placed the direct out-of-pocket costs of ex-
ternal corrosion and deposits in boiler fur-
naces at several million dollars a year. It
is difficult to pinpoint costs directly, but
certainly the unscheduled shut-down of a
large steam generator through failure of a
superheater element can be an expensive
operation. Crossley of CEGB in England
estimates that an outage of a 550-megawatt
unit for one week costs $300, 000. Hence
extensive efforts have been made in this
country and abroad to learn more about the
factors that lead to metal wastage and de-
posits and how to control them in combustors
of all kinds.
Of the fuels being used for central-station
power plants, only natural gas is free from
the ''impurities" that cause these problems.
Ash in coal and in fuel oil and the presence
of sulfur lead to a wide variety of difficulties.
In boilers, deposits form within the furnace,
on the superheater and reheater elements,
in the economizer, and in the air heater.
In gas turbines, combustor problems are not
so severe, but deposits on turbine blading
can be disastrous.
Although deposits may be objectionable in
themselves, as thermal insulators or flow
obstructors, usually it is the corrosion con-
ditions accompanying deposits that cause the
greatest concern. This has been particularly
true in boiler furnaces. Here, deposits
interfere with heat transfer and gas move-
ment, but these can be compensated in part
by engineering design. On the other hand,
corrosion beneath such deposits can cause
rapid metal wastage, forcing unscheduled
outages for replacement of wall tubes or
Superheater elements.
With the recent trend to larger and larger
steam generators, even up to 1130 megawatts,
the importance of eliminating such outages
grows in importance. This is the reason
mainly, why so much attention has been
paid recently to investigating the causes of
corrosion and deposits, and to seeking
corrective measures.
IMPURITIES IN FUELS
Although natural gas, with its low sulfur
content and complete freedom from metallic
elements, is the only fuel not causing
troubles with corrosion and deposits, its
availability and cost limit its use for steam-
electric plants to geographical areas where
gas is less expensive than other fuels on a
Btu basis. Thus, despite its freedom from
corrosion and deposits, natural gas is the
source of energy for only a fifth of the
electricity generated in this country. It is
important to realize, then, that although
corrosion and deposits are indeed trouble-
some in the operation of steam-electric
plants, it is only one of many factors that
play an important role in selecting a fuel
or designing a power plant to operate at
minimum cost.
Residual fuel, which provides the energy
for about 6 percent of our generated
electricity, usually contains all the impuri-
ties present in the original crude oil. Of
these, sodium, vanadium, and sulfur are
most troublesome. Typical limits for these
impurities are, for sodium, 2 to 300 ppm in
residual fuel, or about 0. 1 to 30 percent
Na2O in the ash; for vanadium, 0 to about
500 ppm in residual fuel, or 0 to 40 percent
V2O5 in the ash; and for sulfur, up to 4 per-
cent in residual fuel, with a maximum of
40 percent SO3 appearing in oil ash depending
upon the method of ashing.
9-21
*Senior Fellow, Battelle Memorial Institute, Columbus,
Ohio. Presented at the Residential Course on Combustion
Technology, Pennsylvania State University, 1966.
PA.SE, 26. 12.66
-------
Corrosion and Deposits From Combustion Gases
With coal, which furnishes more than half
of the energy converted into electricity, the
impurities consist mainly of SiO2. A^Og,
Fe2O3, CaO, MgO, the alkalies, and, of
course, sulfur. The range of these ash
constituents varies widely, and they may
exist in many mineralogical forms in the
original coal. Sulfur may be present even
up to 6 percent in some commercial coals,
but the sulfur content usually is below 4
percent. Sulfur retained in coal ash as 803
ranges up to about 35 percent, depending
upon the method of ashing and the amount
of CaO and MgO in the ash. In coal-ash
slags it is seldom more than 0. 1 percent.
Chlorine is frequently blamed for corrosion
with English coals in which it occurs up to
1 percent; it seldom exceeds 0. 3 percent in
American coals, and it usually is less than
0. 1 percent. Because less than 0. 3 percent
chlorine in coal does not cause problems
through corrosion and deposits, chlorine in
American coals generally may be neglected
as a source of trouble. Phosphorus, which
occurs up to about 1 percent as P2^5 m coal
ash, was a frequent source of deposits when
coal was burned on grates. With pulverized-
coal firing, however, it is seldom held
responsible for fouling.
PROPERTIES OF COAL AND OIL ASHES
Coal Ash
Most of the earlier studies of coal ash
were aimed at clinkering problems in
fuel beds. Later, studies of ash were
concerned with the unique problems in-
volved with slag-tap pulverized-coal-
fired boiler furnaces. Ash deposits,
collecting on heat-receiving surfaces,
cause no end of trouble because they
interfere with heat transfer. In the
combustion chamber, particularly in
pulverized-coal-fired slag-tap furnaces,
the layers of slag are fluid and can cover
much of the heat-receiving surface.
In dry-bottom furnaces, wall deposits
are made up largely of sticky particles
that coalesce to cover the tubes in
irregular patterns. As the gases cool on
passing through superheaters and re-
heaters in either type of furnace, adherent
ash deposits sometimes become so ex-
tensive as to block gas flow. In air
heaters, ash accumulations again can be
troublesome.
The flow properties of coal-ash slags
were investigated extensively in this
country nearly three decades ago when
slag-tap furnaces were still quite new.
More recently, those early data have been
rechecked and affirmed in England. Al-
though coal ash makes up a 6-component
system, it has been found possible to
combine compositional variables so as to
provide a relatively simple relationship
between viscosity, temperature, and
composition. It has been found, for
example, that slag viscosity above the
liquidus temperature can be related
uniquely to the "silica percentage" of
the slag, where
Silica percentage =
SiO2
Si02
CaO + MgO
X 100.
Here SiO2, Fe2O3, CaO, and MgO repre-
sent the percentage of these materials in
the melt. This relationship was found to
hold for widely varying ratios of Fe2O3
to CaO + MgO and to be almost completely
independent of the A12O3 content. The
relationship, admittedly an empirical
one, can be simplified still further to
the form
log (ri - 1) = 0. 066 (SiO2 percentage) - 1.4
where rj is the viscosity in poises at 2600
F. A much more elaborate treatment of
this relationship was one of the useful
results of the recent work in England.
The rate of change of viscosity with
temperature also is relatively simple,
of the form
-0.1614
= (4. 52 X 10 "4 t) - B
9-22
-------
Corrosion and Deposits From Combustion Gases
where r) is the viscosity in poises at
temperature t in degrees F, and B is
a constant fixed for each slag. The vis- ,
cosity at 2600 F can be inserted in this
equation to determine B, after which the
viscosity of the slag can be calculated
for other temperatures. Again, the
British have worked out a more elaborate
but equally empirical relationship.
At some point when coal-ash are cooled,
a solid phase separates which radically
affects viscosity by changing the flow
from Newtonian to pseudoplastic. Re-
lated to the liquidus temperature, this
is known as the "temperature of critical
viscosity" (Tcv) for coal-ash slags. At
this point, important changes occur in
flow behavior, and the slag may no
longer deform under gravitational forces.
This, in turn, greatly affects the thick-
ness of slag that can accumulate on the
furnace walls, the thickness being
greater as TCV is higher and as the New-
tonian viscosity is greater, all other
factors being constant.
The temperature at which this pseudo-
plastic behavior begins is related to
composition in a most complicated fashion.
No such simple relationship as the silica
percentage has been found to apply to
Tcv, which is also affected by such factors
as the rate of cooling of fluid slag. For
the present, it is enough to know that this
is an important factor in fixing the thick-
ness of slag on heat-receiving surfaces,
particularly where the temperature of
the slag is well below 2600 F. The
relationships here between slag accumu-
lation, coal-ash properties, and furnace
conditions are extraordinarily complex,
at least a dozen parameters being in-
volved. Little use has been made of this
analysis, largely because Tcv is not
related simply to composition and may
have to be determined experimentally for
each slag composition.
Oil Ash
Possibly because the ash content of
residual fuels seldom is greater than 0. 1
percent, exceedingly low compared with
coal, the properties of oil ash have not
been investigated systematically. Sili-
cate minerals in crude oil vary much
more widely than in coal ash, and A12C>3
and Fe2O3 also cover broad limits.
Alkalies may be high in residual fuel,
often because of contamination in refining
the crude oil, or in handling. Seawater,
unavoidably present in bunkering, is a
common contaminant in residual fuel.
Sulfur occurs in oil in a wide variety of
forms ranging from elemental sulfur to
such complexes as thiophene and its
homologues.
The uniqueness of most oil ashes is that
they contain, in addition to extraneous
materials, metallic complexes of iron,
nickel, and vanadium present as oil-
soluble organometallic compounds. These
are frequently porphyrin-type complexes,
so stable that temperatures in excess of
800 F usually are necessary to dissociate
them. As a result, they are difficult to
remove from fuel oil economically. An
undescribed scheme for removing essen-
tially all the nickel and vanadium from
residual fuel at a cost as low as 15
-------
Corrosion and Deposits From Combustion Gases
Hence it is a liquid at the temperature
of superheater elements, thereby adding
to its aggressiveness in causing corrosion.
The fusion characteristics of oil ash are
poorly known. Cone fusion and other
arbitrary schemes such as hot-stage
microscopes have been used to check on
the melting characteristics of oil ashes,
but no systematic investigation has been
made as with coal ash.
EXTERNAL CORROSION
Tube wastage first posc'd serious problems
in boiler maintenance beginning about 1942,
when a sudden rash of wall-tube failures in
slag-tap furnaces was traced to external
loss of metal. In the worst cases, tubes
failed within three months of installation.
Measurements of tube wall temperature
showed that the tube metal was not over-
heated, typical maximum wall temperature
being 700 F. Heat transfer also was nominal.
The only unusual condition was that some
flame impingement appeared likely in the
affected areas.
It was soon found that an "enamel" was
present beneath the slag layer where
corrosion had occurred. This material,
which was found in thin flakes adhering
tightly to the tube wall, resembled a fired-
porcelain coating with a greenish blue to pale
blue color. These flakes of enamel were
moderately soluble in water, giving a
solution with a pH as low as 3. 0. They also
contained large amounts of Na2O, K2O,
Fe2O3, and 803, and were obviously a
complex sulfate. Following considerable
work in the laboratory, the "enamel" was
finally identified as KgFe(SO4)3. There is
a corresponding sodium salt, as well as a
solid solution of these sodium and potassium
iron trisulfates.
Alkali ferric trisulfates were formed by
reaction of 803 with Fe2O3 and either K2SO4
or Na2SO4, or with mixed alkali sulfates.
At 1000 F, at least 250 ppm SO3 is necessary
for the trisulfates to form. At this tempera-
ture, neither the alkali sulfates nor the
3 alone will react with this concentra-
tion of 303. Only when both the sulfates
and Fe2Og are present will the reaction
occur. The trisulfates dissociate rapidly
at higher temperatures unless the 303
concentration in the surroundings is
increased. Quantitative data are few, but
it appears that the concentration of SO3
required to prevent dissociation of the tri-
sulfates at 1200 F to 1300 F, as would'be
the case on superheater elements, greatly
exceeds any observed SO., levels in the gas
phase. Accordingly, some unique but as yet
unexplained action must go on beneath super-
heater deposits that can provide the equiva-
lent of, perhaps, several thousand ppm of
803 in the gas phase. Lacking any better
explanation for the time being, "catalysis"
is usually blamed.
THE IMPORTANCE OF SO3
Any discussion of external corrosion and
deposits in boilers and gas turbines would
be meaningless without reference to the
occurrence of 303 in combustion gases.
Many investigators, both in the laboratory
and in the field, have studied the conditions
under which SO3 is formed, on the basis that
303 is a major factor both in high^
temperature corrosion and in low-temperature
corrosion and deposits. These studies
have been going on for more than 30 years.
The reasons are not difficult to state. In
the hot end of coal-fired equipment - furnace-
wall tubes and superheater elements, for
example - deposits taken from areas where
corrosion has occurred invariably contain
appreciable quantities of sulfates, some-
times as much as 50 percent reported as
SOg. Slag layers from the high-temperature
zone of oil-fired boilers also contain 803,
typically from 25 to 45 percent reported as
Na2SO4. In the 1959 Battelle report to
ASME, many examples are given of slag
deposits where there was more than 15
percent 303 in the deposit.
As has already been noted, the alkali iron
trisulfates cannot exist at 1000 F unless at
least 250 ppm of 303 is present in the
9-24
-------
Corrosion and Deposits From Combustion Gases
surrounding atmosphere, or the equivalent
SO3 level is provided some other way. At
higher temperatures, even more SOg must
be present if these compounds are to form.
In the absence of SO3, the trisulfates could
not be produced and corrosion would not
occur.
Bonding of ash to superheater tubes
frequently attributed to a layer of alkalies
that condenses on the metal wall and serves
as the agent to attach the ash to the tube.
Further buildup of ash deposits, however,
depends on some other mechanism. One
explanation with fuels such as some subbi-
tuminous coals, lignite, and brown coal
containing large quantities of CaO in the ash
is that CaSO^ is formed. This substance,
well distributed in the ash deposit, is con-
sidered by many investigators to be the
matrix material that bonds the whole deposit
together into a coherent mass. Although
CaSO4 might be formed when CaO reacts
with SO2 and O2» it seems more reasonable
to expect that 303 is responsible.
At low temperatures, as in air heaters, there
is no question but that 803 is the major
offender. It combines with alkalies to plug
air-heater passages, and if the metal
temperature is below the dewpoint, H2SO4
formed from SO3 condenses as a liquid film
on the metal surfaces to cause serious
corrosion. Acid smuts, where carbon
particles are saturated with this I^SO^, also
depend on the presence of 803.
These are the reasons why the formation of
SOs has been given so much attention. In
addition to the boiler manufacturers and the
fuel suppliers working in their own labora-
tories and in the field, Battelle has studied
the production of SOs m flames and by
catalysis for the ASME Committee on
Corrosion and Deposits. This work has pro-
vided a basic understanding of many of the
thermochemical reactions leading to
corrosion and deposits.
LOW EXCESS AIR
A revolutionary approach has been taken over
the past decade in Europe toward
9-25
eliminating the formation of SO3 in boiler
furnaces fired with oil by limiting the excess
air to an absolute minimum. Low excess air
seems to have been proposed first in
England as a means of-decreasing corrosion
and deposits when burning residual fuel.
In 1960, Glaubitz in Germany reported
highly favorable results burning residual
fuel with as little as 0. 2 percent excess
oxygen. By carefully metering fuel oil to
each burner and properly adjusting air
shutters, he found it possible to reduce ex-
cess oxygen to as little as 0. 1 percent before
incomplete combustion became troublesome.
By operating at these low levels of excess
air, Glaubitz was able to operate boilers on
residual fuel for more than 30, 000 hours
without any corrosion and with no cleaning
being required.
Low excess air in oil-fired equipment also
has proven satisfactory in the United States
and is being used successfully in many large
boiler plants. Precise metering of fuel and
air to each burner has proven to be less
troublesome than had been expected earlier,
and in some instances with high furnace
turbulence ordinary controls have been found
satisfactory. In other cases, unburned com-
bustibles have made low excess air undesir
able. Sound principles guide the use of low
excess air, but applying these principles
usefully is still largely a matter of judgment
by boiler operators. It has been shown
repeatedly, however, that SOs largely is
eliminated, irrespective of the amount of
sulfur in the fuel, when the products of
combustion contain no more than about 0. 2
percent oxygen. At this level, the dewpoint
of the flue gas can be as low as 130 F where
the dewpoint for the moisture in the flue
gas is 105 F.
The important factors whereby low excess
air is beneficial include, in addition to a
decrease in SO3, a limitation on the oxida-
tion of vanadium. Low excess air leads to the
formation of V2O3 and V2O4, which have
melting points much higher than V2O5. There-
fore, these reduced forms of vanadium are
considered less objectionable from the
standpoint of corrosion.
-------
Corrosion and Deposits From Combustion Gases
Work done recently in the laboratory shows
that the main benefits of low excess air, as
would have been expected, result from lack
of formation of SO3. Flame studies have
shown that stoichiometric sulfur-bearing
flames do not show the usual conversion of
part of the sulfur oxides to 803 by reaction
with oxygen atoms. Competing reactions
within the flame simply keep the oxygen-
atom level too low. Also, not enough oxygen
is present to convert an appreciable amount
of SC>2 to SOg catalytically on surfaces. The
result is an 303 level of only a few ppm with
a correspondingly low dewpoint, minimizing
troubles throughout the boiler, from the
superheater through the air heater.
Opinion at present is that corrosion and de-
posits when burning residual fuel can be
essentially eliminated by operating with
low excess air. Such procedures presumably
will not be possible with coal unless radical
changes are made in the combustion system.
In the meantime, studies of corrosion and
deposits continue in the search for still
better ways of eliminating these causes of
increased operating expense. Factors
involving the formation of 803 are now under-
stood fairly well. The next major step will
be to develop an equally good knowledge of
the mechanism whereby the trisulfates form,
the other complex metal sulfates that also
can be produced, and the role of vanadium.
Meticulous, well-planned research in the
laboratory and in the power plant will
answer those questions as effectively as it
has brought us to our present level of know-
ledge on the causes of corrosion and deposits.
9-26
-------
CHAPTER 10
SOLID VfrSTE AND WOOD BURNING
Municipal incineration has been considered a last resort in solid
waste management. The major problems have been: high capital cost, high
operating costs, site selection, and a long history of objectionable en-
vironmental effects. Municipal incineration's limited acceptance has
stunted its technological development in this country. However, the grow-
ing shortage of suitable, available sites for landfill adjacent to large
population centers has left some municipalities with no alternative.
In the last two decades, European incineration methods have experi-
enced steady development. The U.S. has imported European technology to
help meet our own needs for improved hardware. Increased fuel prices,
resulting from the petroleum crisis of 1973, have focused new attention
upon energy recovery from solid waste. One obvious result is the increas-
ing consideration of solid waste for boiler fuel. Major cities such as
Montreal (1), Chicago (1, 2), and Harrisburg (3) are operating modern steam-
raising incinerators. The Union Electric Company in East St. Louis (4, 5)
has been burning solid waste simultaneously with pulverized coal in a power
boiler. Their arrangement burns shredded waste in amounts of up to 10 per-
cent of the total fuel fired.
Systems which utilize pyrolysis, rather than oxidation, are under
development but are not yet available in large-scale units. Fluidized-bed
combustion is also under development, both as a potential retro-fit for
coal-burning steam generators and as a source of combustion gas for gas-
turbine generator systems. These innovative methods have not yet reached
10-1
-------
"state-of-the-art" status, and long-term operating costs are unknown.
For this reason, discussion here will be limited to incinerator types
currently being operated or constructed.
Solid waste can be considered a fuel with an average ultimate analy-
sis, as shown in Table 10.1 (see Attachment 3-17).
TABLE 10.1
AVERAGE ULTIMATE ANALYSIS OF MUNICIPAL WASTE — AS RECEIVED
%, by weight
Carbon 28.0
Hydrogen 3.5
Oxygen 22.4
Nitrogen 0.33
Sulfur 0.16
Glass, Metal, and Ash 24.9
Moisture 20.7
Individual loads or daily averages at a given site may differ slightly from
values given in Table 10.1. The waste produced is a function of population
density and affluence. Communities tend to produce between four and seven
pounds of solid waste per person per day, with 4.0 to 4.5 Ib/person/day be-
ing a good rule of thumb. An incinerator design for a particular munici-
pality should not be finalized without careful determination of both waste
quantity and its ultimate analysis.
Firing Properties
The amount of air required to burn solid waste can be computed by using
the data provided in an ultimate analysis. Such an analysis can be calcu-
lated from the "as received" analysis by computing the
10-2
-------
hydrogen and oxygen as shown in Table 10.1. For this example, the computa-
tion is :
Hydrogen in moisture = 0,207 x — • = 0.023 Ib H/lb waste
18
Oxygen in moisture = 0.207 - 0.023 = 0.184 Ib O/lb waste
Total hydrogen is then 3.5 + 2.3 = 5.8%, and the total oxygen is 22.4 +
18.4 = 40.8%. The air required for combustion "as received" is computed
using Equation 9.1.
A<_ = 11.53 C + 34.34 (H, - £?_ ) + 4.29 S
r ^ 8
= 11.53 (.28) + 34.34 (.058 - •—. ) + o = 3.47 lb'air
8 ' -" Ib.waste
The stoichiometric air is significantly less for a pound of waste than
would be for a pound of coal. Municipal solid waste contains approximately
35 percent as much energy per ton as coal, and requires approximately
35 pergent as much air if fired "as received." Therefore, if one computes
the air requirement on an energy-content basis, the air requirements are
similar. Since it is possible to remove glass and metal from the waste
by shredding and air-separation techniques (7,8), the energy content per
pound of waste fired can be improved considerably.
Site Considerations
A primary problem in any waste management program is site selection.
This involves public acceptance and careful systems engineering. The
site chosen should attempt to minimize the total trucking costs, which in-
clude the removal of incinerator residue. In order to limit transportation
cost, waste may be processed to remove metal and glass. This usually in-
creases original waste of 300 Ib/yd density to around 700 Ib/yd . This
reduced transport truck volume should permit planning of collection and
10-3
-------
processing to minimize the number of collection trucks required. Careful
systems study will insure optimal location for both the processing and
incinerator plants.
Plant Design Considerations
The relatively small number of modern incinerators which have been
built in this country in recent years, coupled with the evolution of new
technology in Europe, has given rise to an unsettled "state of the art."
Past practice dictated the need for primary and secondary combustion cham-
bers. The primary chamber included a so-called "drying zone" where vola-
tile materials were gasified and then directed into the secondary chamber
to complete the oxidation. With the primary chamber operating on a large
batch-fed basis, the volitization and oxidation rates varied with time,
causing non-uniform furnace temperatures.
A modern incinerator may or may not have a secondary combustion cham-
•
ber, depending upon whether it is designed for energy recovery. Refuse is
continuously charged by mechanical stokers designed to produce uniform burn-
ing. Since solid waste does not flow when a section of piled material is
torn away from the base of the pile, positive tumbling or shearing action
must be provided by the stoking and feeding equipment to move waste into the
furnace and onto the burning grates. A wide variety of mechanical equipment
has been used but, in general, waste is charged onto a first-stage feeder
from a hopper-fed vertical or near-vertical chute. The hopper is usually
charged by a crane-operated grapple, but it may be fed directly by truck or
front loader.
10-4
-------
The feeder can be a ram which simply pushes waste through a gate and
onto a stoker within the furnace, or it may be a short section of grate inclined
o o
at an angle of 20 to 30 placed directly beneath the charging chute.
Attachment 10-1 illustrates a ram feed unit combined with a two-section
reciprocating stoker.
The reciprocating stoker employs alternate rows of moving and station-
ary sections, shown schematically in Attachment 10-2, to move the waste
through the furnace.
Attachments 10-3 and 10-4 illustrate use of a short section of chain
grate stoker arranged to feed waste into the furnace with a long section of
chain grate stoker to provide for residence burning.
Each of the sections can be separately controlled to adjust feed and
burning rates as needed. The underfire air supply to each section is also
individuall controlled. A three-section reciprocating stoker assembly is
shown installed in an incinerator, Attachment 10-6, with a water-walled
furnace, at the Norfolk Navy Base, Norfolk, Virginia (9).
Other types of grates are employed in which sections may be oscillated
or rolled to provide a tumbling action which agitates the waste. This
tumbling action is especially desirable since waste tends to burn from the
upper surface down and also tends to mat in a manner which interferes with
proper air flow.
Oscillating grates and barrel grates are shown in Attachments 10-7 (a,b).
There are other types of grate assembly but all attempt to provide a
feeder section which also serves to begin"the waste drying, followed by
one or more sections of grate to provide for complete refuse burnout.
Multiple-section units are usually longer than they are wide. One design,
the Martin Grate ('9) , is wider than it is long and has only one section.
10-5
-------
This unit agitates the fuel bed through a "reverse" reciprocating action.
Local motion tends to drive the refuse up the slope of the stoker assembly,
thus achieving a tumbling action.
In general, the use of continuous feed has become common enough to be
considered a "standard" configuration, and the rate of feed is based on an
energy release criterion of 300,000 Btu/hr ft2. For a "typical" waste
2
with 5,000 Btu/lb energy content this corresponds to a 60 Ib/hr ft mass
feed rate. Combined with an energy release design of 20,000 Btu/hr ft , the
area factor establishes the physical volume of furnace needed for a speci-
fied type and quantity of waste. Example 10.1 illustrates use of these
rule of thumb.
Example 10.1; Determine grate area and furnace volume required to burn
40 ton/hr of 10 million Btu/ton solid waste:
Energy Input Rate = 40 Ton/hr x 10 x 10 Btu/ton
= 400 x 10 Btu/hr
r* ,. * „ ^ j 400 x 106 Btu/hr
Grate Area Needed = L
300 x 103 Btu/hr ft2
= 1330 ft2
Volume Needed = 400 x 106 Btu/hr
20 x 103 Btu/hr ft3
= 20,000 ft3
Furnace design is influenced by a number of factors, including whether
or not the walls are cooled,and what cooling medium is used. Uncobled
refractory-wall incinerators usually require 200 to 400 percent excess air
to prevent excessive furnace temperatures which may damage the refractory.
With air-cooled walls, constructed by locating tuyeres in either a silicon
10-6
-------
carbide brick or special cast iron side wall structure, excess air can be
reduced to approximately 150 percent. Water-cooled walls, as used in
modern water-walled steam generators (Attachment 10-6) allow operation with
only 50 percent excess air. The quantity of excess air is especially rele-
vant to air pollution control, because the NOX and total gas to be handled
by any cleanup technique escalates with increasing excess air. Conse-
quently, the size and operating costs for fans, ducts, and air quality
control devices become larger as excess air 'increases. Pumping power also
increases proportionately, assuming other factors remain constant. The
reduced excess air requirement clearly explains why steam-raising incinera-
tors , with water-walled furnaces, are more desirable than either air-cooled
or plain refractory-walled units — aside from energy recovery considerations.
Corrosion, however, can be a significant problem in steam-raising inci-
nerators where metal temperatures are above 500°F (11). Since superheaters
usually operate at temperatures above 700°F, special care will be required
to avoid significant corrosion.
Air Quality Control Considerations
Municipal incinerators are sources of both gaseous and particulate
pollution and can be indirectly responsible for water pollution as well,
since water is used to quench residues before their removal from the inci-
nerator. In general, residue quench water will be alkaline. Water from
spray chambers or scrubbers will be acidic, as a direct consequence of the
vinyl chloride plastics found in waste. Water also may be used in sprays
to cool effluent gases. In wet scrubbers it is employed to remove both
particulate and gases. Work has been done in an operating incinerator (12)
that indicates HC1 emission increases with increasing plastic content, but
10-7
-------
that wet scrubbing can remove from 80 to 90 percent of this gaseous pollu-
tant.
Here again, there is an evolving "state of the art," and no optimum
method has yet emerged. Municipal incinerator (50 T/D) standards for new
sources (13) limit particulate emission to 0.08 gr/scf at 12 percent C02.
Electrostatic precipitators have been installed on new designs with the
expectation that they can meet the standard. Electrostatic precipitators
normally operate at temperatures between 275°F and 550°F. When precipita-
tors are applied to steam-raising incinerators, whether of waste heat
boiler type or full water-walled steam generator design, the lower tempera-
ture typically is specified. Incinerators without heat recovery, however,
require cooling of gases from temperatures of 1,200°F to 500°F. This is
accomplished in one of several ways:
1. Gas cooling through the addition of ambient air
2. Water sprays to cool the gases
3. A combination of added air and water sprays.
Adding air alone significantly increases physical volume, which means larger
fans and greater power. Water by itself can result in a water carryover to
the precipitator. Method three usually represents a reasonable compromise.
Venturi-type high-energy wet scrubbers show promise, but require con-
siderable power and therefore have high operating costs. Scrubber effici-
encies .of 99 percent can be achieved if a pressure drop of 40 to 50 inches
of water column can be tolerated. Wet scrubbers operate with water ph as
low as 1.6, which means corrosion is also a problem. Water treatment must
be provided, producing additional first-cost and operating cost. This is
not a serious disadvantage where an incinerator can be located near a municipal
10-8
-------
waste water treatment facility, as has been reported (17) — but this is
not an arrangement which is ordinarily possible. Wet scrubbers have the
serious disadvantage of poor plume bouyancy. Gas leaves the scrubber at
a temperature in the range of 165°F to 175°F and forms a visible plume
due to water vapor. The poor plume bouyancy means a short stack is un-
desirable. Reheating flue gases after scrubbing by employing hot un-
scrubbed gases is one possible solution to this problem, but it is one
which complicates both hardware design and operation. Where scrubbers
are added as a retrofit, this reheat requirement can reduce furnace capa-
city.
Baghouses do not appear to be in favor with designers of modern inci-
nerators, most likely because of economic reasons.
Economics
The reported costs, both capital and operating, are high. Refractory-
walled, non-energy recovery units have ranged in capital cost from a low
of $4,000 to a high of $12,000 per ton of capacity. Energy recovery water-
walled units range from $15,000 for large units to $30,000 per ton for small
(150 to 300 T/D) steam-raising units. Operating costs also show a wide
variation, depending on incinerator type, location, and mode of operation.
Where units are located within city business areas to provide energy for
municipal buildings, as in Harrisburg, Pennsylvania and Nashville, Tennes-
see, costs reflect the site choice. A modern energy recovery incinerator
is a high-technology undertaking when properly designed, and can be ex-
pected to become more so as development continues.
10-9
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Wood and Wood Wastes
Wood and wood wastes are similar to municipal solid waste with metal,
glass, and ash removed. Noting the high paper content (see Attachment 3-13),
this similarity is not surprising, since papeis are largely cellulose— derived
from wood. A comparison of the ultimate analysis presented in Table 10.1,
with those for wood and wood wastes given in Attachments 3-10 and 3-11, would
suggest similar air requirements relative to both quantity and distribution.
The high volatile matter content of these fuels means very little of
the combustible will burn on grates. Therefore, the air supply must be
divided between underfire air and overfire air jets, and each separately con-
trolled. Wood wastes produce ash different from that which can be expected
from "white" wood because of handling. Hogged fuel is made up of bark and
nonuseful wood scraps which may contain considerable dirt and grit. Where
logs are salt-water stored, bark will contain considerable salt which will
be emitted in the stack plume.
Spreader stoker feed of either solid or wood wastes can produce higher
particulate loading than those from the suspension burning of coal. This
elevated loading derives from the density of wood, compared with that of
coal. Woods vary in density, with specific gravity as low as 0.1, but typi-
cally 0.3 to 0.5. Because the settling velocity of a particle is propor-
tional to its density, particles of wood or solid waste will remain entrained
at conditions where coal particles would either settle out or be removed.
Residence times for wood and solid waste range from 2 to 4.5 seconds (14),
compared with 1 to 2 seconds for oil and pulverized coal. Particles with
a mean diameter on the order of one mm will not be consumed in this time, and
therefore leave as a fragment of char. Where fuel preparation (usually a
10-10
-------
hogging operation) produces a large fraction of particles in the one mm range,
particulate loading will be greater for equipment fired by air spreaders.
Typical Wood Burning Equipment
Wood, wood waste and solid waste firing arrangements are similar.
Dutch ovens with waste heat boilers (Attachment 10-8) illustrate the use of a
separate volatizing region where fuel enters from above. Combustion air
enters as primary air under the grates,with secondary air entering through
ports in the bridge wall at a point just beneath the drop-nose arch.
The fuel cell illustrated in Attachment 10-9 is a variation of the
Dutch oven design. It differs in its method of air introduction. A volatizing
region is surrounded with an annulus through which the overfire air flows.
Air is preheated as it flows through the passage way. This design does not
use separate forced draft fans to supply underfire and overfire air.
Attachments 10-10,-10-11, and 10-12 illustrate modern designs using
inclined water-cooled grates and pneumatic spreaders. Note the
use of an uncooled refractory section at the 'entry region of the inclined
grate. This is the drying or volatizing zone and the furnace has an arch
above it to deflect gases to the region over the hottest part of the fuel
bed. In some designs arches are used at the burnout end of travelling grates
to radiate energy down onto the fuel bed at the place where little fuel
remains in the ash.
References
1. "Plants Burn Garbage, Produce Steam," Environmental Science and
Technology, Vol. 5, No. 3, March 1971, pp. 207-209.
2. Stabenow, G., "Performance of the New Chicago Northwest Incinerator,"
1972 ASME National Incinerator Conference Proceedings, pp. 178-194.
10-11
-------
3. Rogus, C. A., "Incineration with Guaranteed Top Level Performance,"
Public Works, September 1970. pp. 92-97.
4. Shannon, L. J., Schrag, M. P., Honea, F. I., and Bendersky, D.,
"St. Louis/Union Electric Refuse Firing Demonstration Air Pollution Test
Report," Publication No. EPA-650/2-74-073.
5. Shannon, L. J., Fiscus, D. E. and Gorman, P. G., "St. Louis
Refuse Processing Plant," Publication No. EPA-650/2-75-044.
6. Corey, R. C., Principles and Practices of Incineration, Wiley-
Interscience, 1969.
7. Hershaft, A., "Solid Waste Treatment Technology," Environmental
Science and Technology, Vol. 6, No. 5, May 1972, p. 412.
8. Kenahan, C. B., "Solid Waste, Resources Out of Place,"
Environmental Science and Technology, Vol. 5, No. 7, July 1972, p. 595.
9. Municipal Incineration, A Review of Literature, U. S. Environmental
Protection Agency, AP-79, 1971.
10. Field Surveillance and Enforcement Guide; Combustion and Incinera-
tion Sources, U. S. Environmental Protection Agency, APTD-1449.
11. Thoeman, K. H., "Contribution to the Control of Corrosion Problems
on Incinerators with Water Wall Steam Generators," 1972 ASME National
Incinerator Conference Proceedings, pp. 310-318.
12. Kaiser, E. R. and Carotti, A. A., "Municipal Incineration of Refuse
with 2 Percent and 4 Percent Additions of Four Plastics," 1972 ASME Incin-
erator Conference Proceedings, pp. 230-244.
13. Federal Register, Vol. 36, No- 247, Part II, December 23, 1971.
14. Adams, T. N., Mechanisms of Particle Entrainment and Combustion and
How They Affect Emissions from Wood-Waste Fired Boilers, Proceedings of 1976^
National Waste Processing Conference, ASME, pp. 175-184 (May 1976).
10-12
-------
15. Junge, D. C., "Boilers Fired with Wood and Bark Residues,"
Research Bulletin 17, Forest Research Laboratory, Oregon State University,
1975.
16. Junge, D. C., "Investigation of the Rate of Combustion of Wood
Residue Fuel," Report RLO-2227-T22-2, Oregon State University, September
1977.
17- Backus, E. S., "Incinerator Designed to Anticipate Problems,"
Public Works, April 1971, p. 79.
18. Steam, Its Generation and Use, 38th Edition, The Babcock and
Wilcox Company (1973)-
10-13
-------
Attachment 10-1, Cross Section of Ram-Feed Incinerator9
CRANE AND
GRAPPLE
CHANGING HOPPER
RAH FEEDER
JL*'
OVERFIRE AIR DUCTS
IGNITION BURNE^X.
SETTLING CHAMBER
'USTIONNX
r^JI
OUCNCM TANK AKD DRAG OUT COHVETOR
CONVEYOR
Attachment 10-2, Schematic of Reciprocating Grates10
MOVING
GRATES
FIXED -
GRATES
10-14
-------
Attachment 10-3, Front View of Reciprocating
Grate Stoker^
Attachment 10-4, Chain Grate Stoker-Fed Furnace^
J-— J
/s
• -
rn
? —
\ \ i
i "
1 — 1
10-15
-------
Attachment 10-5, Chain-Grate Stoker"
. ~*?-tJi'j±/jj.'LjJ^L* ;J_
tj^'i^'i'/S///.'(111! _/ j j l.l_j j.
111 m.t^v.4.
10-16
-------
Attachment 10-6, Reciprocating Stoker in a Water-Wall Furnace"
WATER-COOLED
FEED CHUTE-)
STOKER
10-17
-------
Attachment 10-7, Oscillating and
RAISED POSITION
NORMAL POSITION
Oscillating Grate
Barrel Grate
Attachment 10-8, Dutch-Oven-Fired Boiler15
TO STACK
=! A«M
10-18
-------
Attachment 10-9, Fuel-Cell-Fired Wood Waste Boiler
15
EXHAUST
•lucres
•MOUAD DRAFT
RAN
10-19
-------
Attachment 10-10, Inclined-Grate Wood Waste Fired Boiler
15
" ROTATING
DUST
DISCHARGERS
REFRACTORY
HEARTH
34AST ^ \ APPROXIMATE CONTOUR
^\ OF WOOD REFUSE
V^FUEl BED
\\ WATER COOLED
INCLINED GRATE
LATERAL
ZONING
WAIL
34UILLOTINE TYPE
ASH REMOVAL BOOKS
SHIELD
FOR mntcnoN
OFOPEHATOR
WWIU RDDOVING
ASH
SEPARATEY
CONTROLLED
OVERF1RE
MR SUPPLY
10-20
-------
Attachment 10-11, Wood Waste-Fired Boiler with
Air Spreader Stoker
J.D
PNEUMATIC
DISTRIBUTOR
T ft
Attachment 10-12, Air-Swept Distributor Spout for Spreader Stoker
Bark Feed
Distributor
Spout Air
Rotating Damper
for Pulsating Air Flow
Reprinted with permission
of Babcock & Wilcox
10-21
-------
CHAPTER 11
ON-SITE INCINERATION OF COMMERCIAL AND INDUSTRIAL WASTE
Background Information
The design of small incinerators has undergone considerable change
during the last 20 years. Until the mid-1950's backyard incinerators and
single-chamber incinerators were very common devices for reducing the volume
and weight of solid waste. They were, however, characterized by high smoke,
CO, HC, and particulate emissions.
In 1957, the Los Angeles County Air Pollution Control District banned
open fires and single-chamber incinerators (Attachment 11-1), because of
their contribution to urban air pollution (1). During this period, in
New York City, considerable interest focused on the use of auxiliary fuel
burners and other design modifications to reduce the emissions from flue-
fed apartment house-type incinerators (2). Their combustion problems
included a poor ability to control the residence time of the combustion
gases, poor turbulence, and low combustion temperatures caused by high
excess air. In addition, high emissions resulted from the widespread lack
of skilled incinerator operators and by the flue-fed feature which caused
overloading and combustion disturbances.
One design for a modified single-chamber flue-fed incinerator is
equipped with a roof-mounted afterburner, as illustrated in Attachment 11-2.
This modification provides a hinged damper which could be dropped down against
the flue-wall during refuse charging. The damper prevents excessive draft
and limits combustion gas flow to the roof afterburner during the initial
burning stage.
11-1
-------
In 1960 the Los Angeles County Air Pollution Control District pub-
lished design standards for multiple-chamber incinerators (1). The stand-
ards established design values for certain velocities, temperatures, and
dimensions (see Attachment 11-3), along with procedures for certain stand-
ard design calculations. These standards also stressed the importance of
operational features, such as refuse-charging method and auxiliary fuel
burner requirements. Similar design standards for multiple-chamber inci-
nerators were also published by the Incinerator Institute of America (3).
As shown in Attachment 11-4, multiple-chamber incinerators typically
have emissions which are 50% lower than single-chamber units. Among the
design improvements were gas speed and directional changes (which increased
turbulence), secondary air and auxiliary fuel burners (to improve combustion
in the second chamber), larger sizes and damper controls (to provide longer
residence time). Barometric dampers required proper design for size to main-
tain draft at around 0.2 inches of water in the primary chamber. Some multi-
ple-chamber incinerator designs included water scrubbers (Attachment 11-5).
In the 1960"s various governmental agencies set emission standards
for incinerators which were to be purchased with their funds. In 1969, the
Public Health Service established an interim design guide for selection or
modification of multiple-chamber incinerators (4). This design guide was
to provide control to either 0.2 or 0.3 grains of particulate per
standard cubic foot of flue gas, corrected to 12% CC^. The 0.3 value was
for units with burning rates at 200 pounds per hour or less, and the 0.2
value for units rated over 200 pounds per hour. Incinerators sized over
200 pounds per hour required scrubbers.
The 1972 results were presented of stack tests on seven representa-
tive, yet fairly new, apartment house incinerators in New York City,
11-2
-------
Cincinnati, Philadelphia, and Miami (5). The particulate emissions of the
two single-chamber units, considerably exceeded the Federal
standards cited, but the five multiple-chamber units met the standard.
Temperatures in the secondary combustion chamber were low, ranging from
650 to 1,145°F — compared with a recommended range of 1,200 to 1,400°F.
This indicates too much excess air. Other problems included plugged water
spray nozzles, and the inability of some units to operate at their
rated capacity.
In the early 1970's, most states considerably tightened their stand-
ards for incinerator emissions. This was part of the State Implementation
Plans for the Clean Air Amendments of 1970. In many cases the emission
standards prohibited typical multiple-chamber incinerators. In fact, be-
cause of local sources and ambient conditions, some areas still do not permit
new incinerators.
Controlled-Air Incinerators
Controlled-air incinerators are an innovative adaptation of the mul-
tiple-chamber incinerator design using forced draft rather than natural
draft for the air supply. Because considerably less air is
used than for multiple-chamber incinerators, final combustion temperatures
are much higher, providing more complete combustion. Also, low combustible
particulate loading is achieved by limiting turbulence and air velocities
in the primary chamber.
The reduced emissions characteristics of controlled-air incinerators
and of modern municipal incinerators having adequate stack cleaning, have
demonstrated adequate emission control for acceptance in most areas.
11-3
-------
Although commercial designs have varied with time and manufacturer,
the distinguishing design feature is the restrictive control of air supply.
As illustrated in Attachment 11-6, a sealed primary chamber acts as a
volatilization zone. Air is supplied under the refuse bed at approximately
50% of the stoichiometric value.
Temperature in the primary chamber is controlled to around 1,400°F with
the minimum being assured by auxiliary fuel. The maximum may be limited by
cutting off the primary air or by the use of water sprays (6, 7). Con-
tinuous charging of waste materials generally ensures that less than
stoichiometric primary air is present and that a reducing atmosphere will
be maintained.
The combustion gases move to a second chamber,or afterburner,for com-
plete oxidation of the smoke, CO, and hydrocarbon gases. The balance of
the required air is strategically introduced to provide proper tur-
bulence without quenching the combustible gases. The overall excess air
rate may be around 100%. Temperatures in the second chamber are usually
controlled at from 1,600 to 1,800°F by the auxiliary fuel and excess air.
Typical residence times are from .7 to 1.0 second (8).
The relative size of the secondary chamber may vary with manufacturer,
as illustrated in Attachments 11-6, 11-7, and 11-8. Originally "starved-air"
units described those with relatively small secondary chambers or after-
burners, and "controlled-air" units had relatively large secondary chambers.
However, today, "controlled air" is used to describe both designs.
Typically controlled-air incinerators are factory manufactured. Each
given model has a standardized design and is shipped to the site prepackaged.
Loading rates for individual modules are modest with waste rates varying
11-4
-------
from 400 to 3,000 Ib/hr. Larger waste rates are achieved by using multiple
numbers of modular units. For example, eight 12.5 T/day units have a com-
bined 100 T/day capability.
Most of the units which have been installed are of the batch type,
without continuous ash removal. These units typically operate on a 24-hour
cycle, with batch charging at 8- to 10-minute intervals. The full burning
rate may be maintained for 7 to 9 hours (7). Then approximately three
/
hours are utilized for burning down the charge with the.afterburner operat-
ing. Finally, cooling occurs overnight, and in the morning the ash residue
is removed. This is followed by preheating the refractory and repeating the
daily cycle.
Solid waste weight reduction is around 70%; volume reduction is well
over 90%. The amount of auxiliary fuel required for low emissions depends
on waste characteristics. Type 0, 1, and 2 waste typically are burned with
little auxiliary fuel used during the full burning rate. Of course auxi-
liary fuel is required for burning down the charge and for preheating the
incinerator. Pathological waste may be burned with multiple auxiliary
fuel burners in primary as well as secondary chambers.
Most designs have been refined to provide particulate or smoke con-
trol adequate to meet most state standards without utilizing a scrubber or
other flue gas treatment. Particulate emissions of "dry catch," or the sam-
ple collected on or before the filters in EPA sample train, have been re-
corded from 0.03 to .08 grains per standard cubic foot corrected to 12%
C02 (7).
11-5
-------
Design and Operational Modifications for Improved Performance
The problems inherent in a poorly operating controlled-air incinera-
tor are generally related to either the waste material, charging tech-
nique, or the operation of the auxiliary burners.
Higher emissions will occur with the overloading of a unit, because
of fly ash entrainment with the higher air velocity in the primary cham-
ber, and the reduced residence time in the second chamber. Emissions also
increase as the batch charging disturbs the fire bed. If the charge con-
sists of compressed or packaged materials, rather than loose materials, the
rates of volatization and the air delivery can get out of balance and smoke
may be observed. Variable moisture in the charge also will cause a com-
bustion imbalance and possible smoking conditions.
The main control method is to modify the charging techniques to cause
less disturbance to the fuel bed. .Smaller and more frequent charges may
be desirable. A design modification that provides a ram feed system with
a double-door interlock, illustrated in Attachmend 11-8, should avoid the
extra air inflow during charging. A more significant design modification
would provide continuous feed, fuel-bed agitation, and continuous ash re-
moval. Factory-manufactured controlled-air incinerators are now being mar-
keted with continuous ram feed and ash removal features. These units oper-
ate 24 hours per day and thereby have increased loading capability. In
addition, the refractory damage due to temperature cycling is considerably
reduced.
Reducing the auxiliary fuel used may cut the auxiliary fuel costs,
but, of course, the smoke and particulate emissions will probably rise.
The automatic controller temperature setting should be adjusted to obtain
the proper auxiliary fuel firing rate. Maintenance of burners, refractory
11-6
-------
walls, and underfire air supply should be done at the intervals recommended
by the manufacturer .
A controlled-air incinerator may be abused if it is operated as an
excess air incinerator with extra primary air blowers used to increase the
energy release rate. Although this modification will cut the afterburner
fuel costs, the reduced residence time will increase the smoke and par-
ticulates emissions. Maintenance costs may also increase becuase of the
higher temperature cycling of the refractory.
Waste-heat boilers can be provided to produce steam or hot water
from stack gas waste energy (7) . One design is illustrated in Attach-
ment 11-9. The economics, of course, are most favorable if the refuse
waste stream is guaranteed, and if a customer is available who will pur-
chase all the steam or hot water produced. The economic picture for too
many major steam-generating solid-waste incinerator facilities has been
made difficult by the absence of one or the other of these features.
Incinerator Operation for Minimized Pollutant
A most important aspect of good minimum-pollutant emission incineration
is the way in which it is operated. It must be charged properly in order
to reduce fly- ash entrainment and to maintain adequate flame and air con-
ditions. When the charging door of some units is opened, considerable air
rushes in and smoke is observed from the stack. Many units are now being
designed with ram feeders, as previously described.
The ignition chamber of multiple-chamber units are normally filled to
a depth two-thirds of the distance between the grate and the top arch prior
to light-off. After approximately half the refuse has been burned, refuse
may be charged with a minimum of disturbance of the fuel bed. The charge
11-7
-------
should be spread evenly over the grates so that the flame can propagate
over the surface of the newly charged material. Variations in underfire
and overfire air will give the operator an opportunity to determine the
best settings for various types of waste material, depending upon the stack
emission.
Auxiliary fuel burners should be started prior to igniting the waste
material so that the chamber can be preheated to operating temperature.
This will considerably reduce the particulate/smoke emissions.
11-8
-------
References
1. Williamson, J. E., et al., "Multiple-Chamber Incinerator Design
Standards for Los Angeles County," Los Angeles County Air Pollution Control
District (October 1960).
2. Kaiser, £. R., et al., "Modifications to Reduce Emissions from
Flue-Fed Incinerators," New York University, College of Engineering Tech.,
Report 555.2 (June 1959).
3. /'Incinerator Standards," 7th Edition, Incinerator Institute of
America, New York (Nov. 1968).
4. "Interim Guide of Good Practice for Incineration at Federal Faci-
lities," AP-46, National Air Pollution Control Administration, Public Health
Service, Raleigh, N.C. (November 1969).
5. Stableski, J. J., Jr., and Cote, W. A., "Air Pollution Emissions
from Apartment House Incinerators," JAPCA, Vol. 22, No. 4, pp. 239-247 (April
1972).
6. Incineration, A State of the Art Study, prepared by National
Center for Resources Recovery. Inc., published by Lexington Books, Lexing-
ton, Massachusetts, 1974.
7. Hoffman, Ross, "Evaluation of Small Modular Incinerators in
Municipal Plants," Final Report of Contract No. 68-01-3171, Office of Solid
Waste Management, USEPA (1976).
8. Theoclitus, G., et al., "Concepts and Behavior of Controlled
Air Incinerators," Proceedings of th% 1972 National Incinerator Conference,
ASME, pp. 211-216 (June 1972).
9. Smith, L. T., et al., "Emissions Standards and Emissions from
Small Scale Solid Waste Incinerators," Proceedings of_ 1976 National Waste
Processing Conference, ASME, pp. 203-213 (May 1976).
11-9
-------
10. Cross, F. L. , and Flower, F. B., "Controlled Air Incinerators,"
paper presented to Third Annual Environmental Engineering and Science Con-
ference, University of Louisville, Louisville, Kentucky (March 1973).
11. Hoffman, R. E., "Controlled-Air Incineration, Key to Practical
Production of Energy from Waste," Public Works (September 1976).
12. Danielson, J. A., Air Pollution Engineering Manual, Second Edi-
tion, U. S. Environmental Protection Agency (May 1973).
13. "Workbook for Operators of Small Boilers and Incinerators,"
EPA-450/9-76-001, U. S. Environmental Protection Agency (March 1976).
14. "Compilation of Air Pollution Emission Factors," AP-42, Second
Edition, Part A, U. S. Environmental Protection Agency (August 1977).
11-10
-------
Attachment 11-1, Single-Chamber
Incineratorl2
Attachment 11-2, Modified Single-Chamber
Flue-Fed Incinerator
12
V-BAFFLE
/\
BURNER
Ist-FLOOR LEVEL
r£ ELECTRIC LOCK
^fCHUTE DOOR
DRAFT CONTROL
DAMPER
CHARGING DOOR
/OVERFIRE
/AIR PORT
CLEANOUT DOOR
UNOERFIRE AIR PORT
COMBUSTION CHAMBER
\
BRUTES >J
ilst-FLOOR LEVELS \
CLEANOUT DOOR
UNOERFIRE
AIR PORT
11-11
-------
Attachment 11-3, Design Standards for Multiple-Chamber In-Line Incinerators1
I—II-
Vw-l, |.j ,—1.|
PLAN VIEW
SIDE ELEVATION
1 . STACK
2. SECONDARY AIR PORTS
3. ASH PIT CLEANOUT DOORS
4. GRATES
5. CHARGING DOOR
6. FLAME PORT
7. IGNITION CHAMBER
8. OVERFIRE AIR PORTS
9. MIXING CHAMBER
10. COMBUSTION CHAMBER
t 1. CLEANOUT DOORS
12. UNDERFIRE AIR PORTS
13. CURTAIN WALL PORT
14. DAMPER
IS. GAS BURNERS
ISIZE OF INCINERATOR
POUNDS PER HOUR
LENGTH IN INCHES
ABCD E FGH 1 JKL*MNOPQR SI UVWXY
750
1000
1500
2000
85*
941
99
108
491
54
761
90
511
54
65
694
45
47*
55
57i
15*
IB
18
221
54
63
72
791
27
31*
36
401
27
311
36
401
•0
91
11
121
15
24
29
32
36
•ins i on
18
221
27
311
"i"
32
35
38
40
41
41
41
41
5
5
5
5
71
10
71
10
9
9
9
9
21
21
41
41
givtn ir. f • e t •
21
21
41
41
30
30
30
30
9
9
9
9
41
41
41
41
5
7
a
9
11
12
14
15
51
52
611
631
T
0
9
10
11-12
-------
Attachment 11-4, Emission Factors for Refuse Incinerators without Controls14
Incinerator type
Municipal8
Multiple chamber, uncontrolled
With settling chamber and
water spray system'
Industrial/commercial
Multiple chambers
Single chamber'
Trench*
Wood
Rubber tires
Municipal refuse
Controlled airm
Flue-fed single chamber"
Flue-fed (modified)0-?
Domestic single chamber
Without primary burner1*
With primary burner r
Pathological5
Particulates
Ib/ton
30
14
7
15
13
138
37
1.4
30
6
35
7
8
kg/MT
15
7
3.5
7.5
6.5
69
18.5
0.7
15
3
17.5
3.5
4
Sulfur oxides6
Ib/ton
2.5
2.5
2.5h
2.5h
0.1k
NA
2.5h
1.5
0.5
0.5
0.5
0.5
Neg
kg/MT
1.25
1.25
1.25
1.25
0.05
NA
1.25
0.75
0.25
0.25
0.25
0.25
Neg
Carbon monoxide
Ib/ton
35
35
10
20
NA1
NA
NA
Neg
20
10
300
Neg
Neg
kg/MT
17.5
17.5
5
10
NA
NA
NA
Neg
10
5
150
Neg
Neg
Hydrocarbons0
Ib/ton
1.5
1.5
3
15
NA
NA
NA
Neg
15
3
100
2
Neg
kg/MT
0.75
0.75
1.5
7.5
NA
NA
NA
Neg
7.5
1.5
50
1
Neg
Nitrogen oxidesd
Ib/ton
3
3
3
2
4
NA
NA
10
3
10
1
2
3
kg/MT
1.5
1.5
1.5
1
2
NA
NA
5
1.5
5
0.5
1
1.5
M
00
aAverage factors given based on EPA procedures for incinerator stack testing.
bExpressed as sulfur dioxide.
cExpressed as methane.
^Expressed as nitrogen dioxide.
eReferences 5 and 8 through 14.
'Most municipal incinerators are equipped with at least this much control: see Table
2.1 -2 for appropriate efficiencies for other controls.
^References 3,5,10,13, and 15.
"Based on municipal incinerator data.
' References 3,5,10, and 15.
Reference 7.
^
Based on data for wood combustion in conical burners.
1 Not available.
""Reference 9.
"References 3,10,11,13,15, and 16.
°With afterburners and draft controls.
pReferences 3,11, and 15.
''References 5 and 10.
r Reference 5.
* References 3 and 9.
-------
Attachment 11-5, Multiple^Chamber Flue-Fed Incinerator with Scrubber
13
-<--- SPARh ABRESTOR
HOPPER DOOR--
CHARGING FLUE
- - PURGE DAMPER
GARBAGE
AUTOMATIC BY-PASS DAMPER
WATER LINE
CHARGING FLUE GATE
OVERFIRE AIR..
.1PERATURE CONTROL --
/CLING TIME CLOCK
GAS BURNER
- - WATER NOZZLI
<- - SCRUBBER
FLUE GAS FLOW
FIRE DOOR *r£% A*
ri ••"/
GRATE th"A-A-|
UNDERFIRE AIR -
CLEAN OUT DOOR
-.'.'• ' U-SETTLINGTW
J
SUMP
STRAINER
AUTOMATIC DRAFT CONTROL
11-14
-------
Attachment 11-6, Controlled-Air Incinerator8
Attachment 11-7, Controlled-Air Incinerator
10
SECONDARY
CHAMBER
PRIMARY CHAMBER
11-15
-------
Attachment 11-8, Controlled-Air Incinerator with Ram Feeder7
HEAT DUMPING
• TACK
DUAL ruiL •U«NCII
( (.000.000 BTU/Hftl
*ULL OPCMIH* OOME_
AIFNACTO** LINED \
INSPCCTIOM OOO*
ASH HCMOVAL PAD
STACK •
LINING: CASTACLC
HCPMACTOIIV
CHAMtfft ( 9SO CO.
LININ0: FINE BMICK LOWCH SECTION
CASTABLE "EFHACTOHY \tffllt
SECT OM.
AUTOMATIC LOAOEN
IMEMOTELV CONTHOLLEO)
•AH fltOt*
roo OIL an «A« 1900.000 •TU/MH I
-------
Attachment 11-9 , Controlled-Air Incinerator with Waste Heat Boiler
NORMAL EXHAUST-
STEAM
SEPARATION
RECOVERY SECTION
POLLUTION CONTROL CHAMBER
AUTOMATIC
ASH REMOVER
(OPTIONAL)
• HEAT DUMPING STACK
AUTOMATIC
FEED (OPTIONAL)
LOADING DEVICE
11-17
-------
Attachment 11-10, Controlled-Air Incinerator with Waste Heat Boiler '
SECONDARY STACK
DUMP STACK
SECONDARY
COMBUSTION
CHAMBER
PRIMARY
COMBUSTION
CHAMBER
11-18
-------
CHAPTER 12
MUNICIPAL SEWAGE SLUDGE INCINERATION
Introduction to Sludge Incineration
Incineration is an acceptable method for volume reduction and steri-
lization of municipal sewage sludge. Disposing sludge into the ocean
depths, in sanitary landfills, and by landspreading have been widely
1
practiced, but these methods are increasingly subject to environmental
concern. Ocean dumping has an apparent adverse effect upon life on the
sea floor (1). Landspreading disposal is of concern because of aesthe-
tic and health reasons. Every year there are even fewer acceptable
sites available.
On-site sludge incineration may have certain economic advantages
related to automation (labor costs) and transportation. However, the
moisture content of typical sewage sludge is such that considerable
auxiliary fuel is required.
Air pollution emissions from sludge incineration vary widely, de-
pending on the sludge being fired, the operating procedures, and the air
pollution control device. Particulates may be controlled to the New
Source Performance Standards (1.2 Ib/ton or 0.65 g/kg dry sludge input)
by using a venturi scrubber having approximately 18 inches of water
pressure drop. Other acceptable control "devices for particulates could
be impingement scrubbers, with auxiliary fuel burners (controlled by 02
sensors), or electrostatic precipitators.
12-1
-------
Sludge Characteristics
Typical moisture content for mechanically de-watered sludge ranges
from 70 to 80%, depending mainly on the ratio of primary to secondary treat-
ment and the drying equipment used. Notice in Attachment 12-1 that most
components of sludge have considerable heating values in their dry
form (2).
A sample sludge having 25% solids may contain only enough combus-
tion energy to raise the combustion products and moisture to 900°F. This
temperature is far below the 1,350 to lr400°F necessary for deodorizing the
stack gases of a conventional combustion unit. If this sludge were dried
(de-watered) to 30% solids, the steady use of auxiliary fuel would be unneces-
sary. The combustion energy from this sample sludge would heat the com-
bustion products and moisture to the required temperature even after considering
the various heat losses (1).
Most of the combustibles present in sludge are volatile, much in the
form of grease. The fraction of ash or inert materials depend on the sludge
digestion as well as the de-gritting treatment process. Hydrocyclones have
been shown to remove up to 95% of the plus 200 to 270 mesh inorganics.
This de-gritting process may increase the volatile content of sludge by
approximately 10% (1).
A flocculation process used with the clarifying agent in the primary
treatment will increase the settling rate and therefore the ratio of pri-
mary to secondary sludge. This provides sludge of higher heating son-
tent and better de-watering properties.
Wastewater sludges may contain metals which potentially are hazajfflous
if discharged into the atmosphere during incineration. With the exception of
12-2
-------
mercury, hazardous or potentially hazardous metals (such as
cadmium, lead, magnesium, and nickel) will be converted mainly to
oxides which will be found in the ash or be removed with the particulates
by scrubbers or precipitators.
Mercury is a metal which presents special problems in incineration.
In the high-temperature region of incinerators, mercury compounds decompose
to volatile mercuric oxide or metallic mercury. Mercury concentrations of
sewage sludges nationally average about 5 ppm on a dry solids basis. The
average emissions for five incinerators with impingement-type scrubbers
were found to be 1.65 grams of mercury per metric ton of dry sludge (3)-
Water scrubbers removed from 70 to 96% of the mercury.
A hazardous pollutant standard has been established by EPA to limit
the atmospheric discharge of mercury from incineration and sludge drying
facilities to 3,200 g/day.
Lead removal from incinerated sludge is very good, with around 1%
entering the atmosphere, 88% remaining in the ash, and the balance collected
in the scrubber.
Sludge also may contain toxic pesticides and other organic com-
pounds such as polychlorinated-biphenyls (PCB's) at low concentrations
(1.2 to 2.5 ppm). Such materials appear to be destroyed by multiple-hearth
incineration of sludge. Up to 95% destruction has been reported where ex-
haust temperatures were 700°F, and total destruction occurs with exhaust
gas temperatures at 1,100°F (3).
Multiple-Hearth Furnaces
The most widely used sludge incineration system is the multiple-
hearth furnace illustrated in Attachment 12-2. The present air-cooled
12-3
-------
multiple-hearth design is an adaptation of the Herreshoff design of 1889
(4). This design was previously used for roasting ores. In 1935 it was
first adapted for sewage sludge incineration with oil-fired auxiliary fuel
and manual operation controls (5). Wet scrubbers were added to typical
designs in the 1960's, and combustion was improved as automatic controllers
became sophisticated in the 1970's.
Multiple-hearth furnaces are in wide use because they are simple
and durable and have the ability to burn completely a wide variety of sludge
materials, even with fluctuating water content and feed rate. They are most
popular in large cities where alternate disposal techniques are inconvenient
or too expensive. Over 175 multiple-hearth furnaces were reported operating
in 1972 (6).
The typical design features include a cylindrical refractory-lined
steel shell having multiple (4 to 12) horizontal solid refractory hearths.
Each hearth has an opening that allows the sludge to be dropped to the
next lower level and for the gases to pass through in a counterflow direc-
tion.
Stoking is provided by a motor-driven revolving central shaft which
typically has 2 or 4 "ramble" arms extended over each hearth. "Ramble"
teeth are attached to the "ramble" arms and act as ploughs to agitate the
sludge material moving it continuously across the hearth to openings
for passage to the next lower hearth. This plowing process breaks up lumps and
exposes fresh sludge surface area to heat and oxygen.
The central shaft and "ramble" arms are air cooled, in order to pre-
vent damage from the high temperatures.
12-4
-------
Combustion in multiple-hearth furnaces is typically characterized by
four zones. The drying zone is where only moisture is driven off from par-
tially de-watered sludge, by heat transfer from the hot combustion gases.
There sludge temperatures are typically increased from room temperature up
to 160°F, and the moisture content is reduced from the initial amount
(e.g., 75%) down to 45 or 50%. Gases exit this zone at 800 to 900°F.
If the gas temperature were to drop to around 500 to 600°F, more auxiliary
fuel would be needed in the combustion region; but if it were to increase
above 800°F, more excess air would be needed to prevent furnace damage.
The volatization zone is where volatiles are distilled and burned.
They have characteristic, long, yellow flames and combustion temperatures of
around 1,300 to 1,700°F. Following this zone is the fixed-carbon burning
zone, where burning is characterized by short,blue flames. The fourth zone
is where the ashes are cooled by heat transfer to the combustion air prior
to. ash quenching and removal.
The location of the combustion region varies with the sludge feed
rate and moisture content, as well as the use of auxiliary fuel. For a
given operating condition, if the feed rate or moisture content is reduced,
the combustion region may move to a higher hearth. On the other hand, if
the feed rate or moisture is increased, the combustion region may move to
a lower hearth, because longer drying time is required. Of course, if the
combustion zone drops too low, auxiliary fuel burners should provide energy
to control the location of the combustion zone and the completeness of
combustion.
12-5
-------
Combustion control systems may include temperature-indicating con-
trollers , proportionate fuel burners (with electric ignition), ultraviolet
scanners, motorized valves in air headers, automatic draft control, and a
controller driven by a flue gas oxygen analyzer.
The amount of excess air is important for assuring odor control and
complete combustion. Insufficient combustion air results in smoke emitted
from furnace doors as well as stack. However, too much excess air also may
act to reduce the normal combustion temperature, thereby causing increased
auxiliary fuel usage. Typically the excess air rate is between 50 and 125%.
Attachment 12-2 illustrates the cooling air from the central shaft
and "ramble" arms which may be from 350 to 400°F. This air may be used as pre-
heated combustion air or as reheat energy to aid in dissipating the plume
associated with the wet scrubbers.
Hot flue gases leaving the incinerator are typically cooled by water
sprays, air dilution, or energy recovery heat transfer prior to arriving at
the scrubber. The cleaned gases may then be reheated by an afterburner or
by heat exchange to assist in plume dispersion. Other uses of flue gas
waste heat may be for preheating combustion air, for building environmental
control, or for thermal conditioning of sewage sludge to reduce moisture.
Although multiple-hearth furnaces are capable of continuous operation,
many units have been oversized and operate on an intermittent schedule. The
cyclic temperature variations must be tempered by auxiliary heating to limit
the possible structural damage caused by thermal stresses. In addition, the
furnace must be preheated prior to the beginning of sludge incineration in
order to prevent smoke and odor problems. Thermal losses from shut down
and restart may account for as much as 80% of the auxiliary fuel demand (1) •
12-6
-------
Fluidized-Bed Combustion
Fluidized-bed technology has been developed primarily by the petro-
chemical industry. The method has been proved for various applications:
catalyst recovery in oil refining, metallurgical roasting, spent sulfite
liquor combustion, and the incineration of wood wastes, as well as muni-
cipal and industrial sludges. Considerable demonstrations also have shown
the application of fluidized-bed combustion to electric and steam energy
production by burning coal.
Typical cross sections of fluidized bed combustion units (reactors)
for sewage sludge are found in Attachments 12-3 and 12-4. Bed material
is composed of graded silica sand. Air is directed upward through the bed
at a flow rate calibrated to cause the bed to be fluidized, resembling rapid
boiling agitation.
Sludge is fed in only after the bed has been preheated by auxiliary
fuel to around 1,400°F, to avoid improper combustion and odor problems.
Fuel sludge may be introduced directly onto the bed through
pipes in the side wall or through spray nozzles above the bed at the top of
the disengagement zone. In the latter case, water is vaporized from the
sludge in the disengagement zone by heat transfer from the hot combustion
gases.
Thermal oxidation of sludge solids occurs in the hot fluidized bed
due to the mixing of air and combustible materials. Heat transfer between
the solids and gases is rapid because of the large surface area avail-
able. Although the bed may glow and incandescent sparks may be seen above
the bed, there is no flame.
12-7
-------
The heat required for raising sludge to the kindling point must come
from the hot fluidized bed which must have a volume of adequate
size to act as stabilizing heat sink. The disengagement zone above the bed
permits larger entrained solid particles to settle out for burnup in the flui-
dized bed.
The bed retains organic particles until they are essentially reduced
to ash. The bed agitation prevents the buildup of clinkers. Ash is
removed through the entrainment of small particles by the combustion gases.
These particulates must be adequately controlled by a scrubber or some other
collection device.
As in multiple-hearth furnaces, the amount of auxiliary fuel used
depends on the properties of the sludge and the operating conditions.
The operating temperatures and excess air requirements for fluidized
bed combustion are low, so that NOy formation is modest. Sufficient air,
however, is required to keep the bed (sand) in suspension, but not so great
as to carry this sand out of the reactor.
References
1. Rubel, F. N., Incineration of Solid Wastes, Noyes Data Corp.,
Park Ridge, N.J. (1974).
2. "Background Information on National Emission Standards for
Hazardous Pollutants — Proposed Amendment to Standards for Asbestos and
Mercury," U. S. Environmental Protection Agency. Office of Air and Waste
Management, Pub. No. EPA-450/2-74-009a (1974).
3. "Air Pollution Aspects of Sludge Incineration," EPA Technology
Transfer Seminar Publication, EPA-625/4-75-009 (June 1975).
12-8
-------
4. Unterberg, W., et al., "Component Cost for Multiple-Hearth
Sludge Incineration from Field Data," Proceedings of the 1974 National
Incinerator Conference, ASME, pp. 289-309 (May 1974).
5. Burd, R. S., "A Study of Sludge Handling and Disposal," U. S.
Dept. of Interior, Federal Water Pollution Control Administration, Publica-
tion No. WP-20-4 (May 1968).
6. Cardinal, P.J., Jr., and Sebastian, F. P., "Operation, Control,
and Ambient Air Quality Considerations in Modern Multiple Hearth Incinerators,"
Proceedings of 1972 National Incinerator Conference, ASME, pp. 290-299 (June
1972).
7. Fair, G, M. , et al. , Elements of_ Water Supply and Wastewater
Disposal, 2nd Edition, John Wiley and Sons, New York (1971).
8. Petura, R. C., "Operating Characteristics and Emission Perfor-
mance of Multiple Hearth Furnaces with Sewer Sludge," Proceedings of 1976
National Waste Processing Conference, ASME, pp. 117-124 (May 1976).
12-9
-------
Attachment 12-1, Average Characteristics of Sewage Sludge2
Material
Grease and scum
Raw sewage solids
Fine screenings
Ground garbage
Digested sewage
solids and ground garbage
Digested sludge
Grit
Combustibles
88.5
74.0
86.4
84.8
49.6
59.6
30.2
Ash
ill
11.5
26.0
13.6
15.2
50.4
40.4
69.8
Heat
(cal/g)
9300
5710
4990
4580
4450
2940
2220
Content
(Btu/lb)
(16,750)
(10,285)
( 8,990)
( 8,245)
( 8,020)
( 5,?90)
( 4,000)
12-10
-------
Attachment 12-2, Typical Section of Multiple-Hearth Incinerator*
FLUE GASES OUT
RABBLE ARM
AT EACH HEARTH
DRYING ZONE
COMBUSTION
ZONE
COOLING AIR DISCHARGE
FLOATING DAMPER
SLUDGE INLET
COOLING ZONE
ASH
DISCHARGE
BUSTION
AIR RETURN
RABBLE ARM
DRIVE
COOLING AIR FAN
12-11
-------
Attachment 12-3, Typical Section of a Fluid-Bed Reactor
SIGHT GLASS
EXHAUSTS I
SAND FEED
PRESSURE
TAP
PREHEAT BURNER
ACCESS
DOORS
THERMOCOUPLE
= : SLUDGE INLET
FLUIPIZING
AIR INLET
12-12
-------
Attachment 12-4, Fluidized Bed for Sewage Sludge Incineration
LIQUID WASTE FEED
ENTRAINED MATERIAL
FEED SPRAY DISPERSION
REACTION VESSEL
DILUTE PHASE
FLUIDIZED BED
DENSE PHASE
FLUIDIZED BED
SOLID PRODUCT
*- EXHAUST GASES
CYCLONE
SEPARATOR
DUST RETURN
ORIFICE PLATE
FLUIDIZING GAS
12-13
-------
CHAPTER 13
DIRECT FLAME AND CATALYTIC INCINERATION
Atmospheric oxidants are primarily the result of a series of chemi-
cal reactions between organic compounds and nitrogen oxides in the pres-
ence of sunlight. The level of oxidants in the atmosphere depends
significantly on the organics initially present, and on the rate
at which additional organics are emitted. (The contribution of nitro-
gen oxides is the subject of Chapter 16 and will not be discussed here.)
Photochemical oxidant control strategies are therefore aimed at control-
ling NOjj and the emissions of volatile organic compounds (VOC) by:
1. Substitution of VOC by solvents of less volatility and
lower photochemical reactivity;
2. Process and material changes to reduce VOC emissions;
3. Add-on emission control devices.
The control of objectionable gases and vapors by add-on devices
usually relies on one of the following methods:
1. Absorption in a liquid (scrubbing);
2. Adsorption on a solid;
3. Thermal or catalytic incineration;
4. Chemical conversion.
These methods are discussed in detail in another EPA Air Pollution Train-
ing Institute Course—#415: Control of Gaseous Emissions. To avoid un-
necessary duplication, only those methods which are related to combustion
will be outlined here.
13-1
-------
The objective of incineration is to oxidize completely the organic
vapors and gases from a process or operation that emits them. Some
emissions, of course, include particulate as well as gaseous matter.
If the particulates are combustible, they may also be handled by the
combustion process. Incineration is ore of the most widely used methods
for controlling VOC emissions from industrial manufacturing processes and
from other man-made sources.
Devices in which dilute concentrations of organic vapors are burned
by the use of added fuel are known as afterburners. These are capable of
handling waste gases which have too low a heating value to maintain sus-
tained combustion. Waste gases with heating values of about 50 Btu/ft
or higher can be burned directly without auxiliary fuel in specially
designed burners (see Chapter 7). Preheating the gases to 600-700°F
may permit direct burning (without auxiliary fuel) of even lower heating
value wastes.
The usefulness of afterburners has been well documented. Their
popularity has been mainly due to their ease of operation and the avail-
ability of low-cost natural gas, at least in the past. Although waste
gas incineration is simple in principle, the actual equipment can get
somewhat complex due to requirements for controls, as shown in Attach-
ment 13-1.
One of the biggest drawbacks to even wider use of afterburners is
the cost of that equipment, especially due to the size needed to handle
the large volumes and low concentrations of organics in the various
effluent streams. This, coupled with ever-increasing fuel costs and
decreasing fuel availability, has raised some serious questions about
13-2
-------
the continued viability of gas incineration techniques for the control
of VOC emissions. Answers to these questions are beyond the scope of
this discussion. It should be mentioned, however, that heat recovery
devices incorporated in some newer installations are changing the after-
burner economics picture considerably as will be discussed later.
The two major types of combustion units are (a) the thermal inci-
nerator and (b) the catalytic incinerator. Catalytic units, a schematic
of which is shown in Attachment 13-2, permit the use of a lower tempera-
ture than the thermal incinerators for complete combustion, and there-
fore use less fuel and lighter construction materials. The lower fuel
cost can be offset, however, by the added cost of catalysts and typically
higher maintenance requirements for the catalytic units.
The physical size of an afterburner is dictated by the volume of
the effluent to be treated and the residence or dwell time required at
the elevated temperatures. These vary somewhat with the type of effluent,
but they are generally in the order of 0.3 to 0.6 seconds at 1,200 to
1,500°F for 99.9+% destruction of organics by thermal incineration. Fur-
thermore, the oxidation requires less time at higher temperatures (see
Chapter 2). More detailed information on residence time requirements are
found in the Appendix to this chapter. Burner type and arrangement have
a considerable effect on burning time. The more thorough the flame con-
tact is with the effluent gases, the shorter is the time required to
achieve complete combustion. Turbulence in the combustor zone achieves
much the same benefit of reducing required retention time, as actual flame
contact.
13-3
-------
The concentration of combustibles in the fumes to be incinerated
cannot exceed 25% of the lower explosive limit (LEL) for safety reasons.
This is necessary to avoid any danger of flash-backs to other process
units. In practice, it would usually be unwise to attempt to control
organic vapors that contain halogens or sulfur solely by combustion,
since the combustion products of these elements are even less desirable
and often corrosive. A secondary control system, such as a scrubber, may
be required in series with the afterburner to remove these contaminants.
The gaseous waste streams usually contain sufficient oxygen for
complete combustion of the auxiliary fuel, should the latter be required.
An efficient afterburner design can produce complete combustion of the
auxiliary fuel with fumes containing as little as 16% by volume of oxy-
gen. The available heat (which is needed to raise the effluent fumes
to the incineration temperature) from burning natural gas with 0% out-
side primary air is considerably higher than the available heats dis-
cussed in Chapter 2 and is termed the "hypothetical" available heat.
Calculations for fuel requirements using the hypothetical available heat
concept are outlined in the Air Pollution Engineering Manual, AP-40, on
pages 176 and 935 (1).
Using oxygen from the waste gases reduced the auxiliary fuel re-
quirements. Other possibilities for reducing afterburner operating costs
include (a) the use of heat recovery devices for preheating incoming
fumes or for other plant uses and (b) burning combustible waste liquids
through center-fired gun-type burners. A typical regenerative method of
heat recovery is illustrated in Attachment 13-3. This particular system
operates in a cyclic fashion by switching gas flows from one ceramic bed
13-4
-------
to another. Continuous operation, without the involved ducting scheme,
is possible with a heat wheel. Another frequently used energy-saving
approach is the recuperative, heat recovery method which is based on con-
tinuous heat transfer to another fluid separated by a heat transfer
surface. The net cost of using an afterburner to control gaseous pollu-
tants could be reduced further by using the clean, but hot and inert,
exhaust gases in some other part of the operation, such as a dryer, etc.,
if possible.
Commercial afterburner designs are widely available, including
systems with heat recovery. Many of these are packaged units with capa-
cities to 3,000 scfm, typically capable of treating the effluent stream
at up to 1,500 F°for 0.5 seconds. More detailed design and operating
conditions can be found in the Appendix and from the references listed
at the end of this chapter.
A very readable discussion of the basic principles involved in
incinerating combustible gaseous pollutants is available from the book
by Edwards (2). Considerable space is devoted there also to catalysts
and catalytic devices.
Air Pollution Engineering Manual, AP-40 (1) is oriented more
towards specific hardware and actual design and operating characteris-
tics. It contains worked examples of afterburner designs, and an evalua-
tion of an existing afterburner performance.
More detailed calculation procedures are presented by Worley and
Motard (3). Modular subroutines were developed which are suitable for
inclusion in a larger computer code for Control Equipment Design and
Analysis (CEDA) for gaseous pollutants. These subroutines will provide
13-5
-------
the size of gaseous pollutant control equipment when used in the design
mode. In the analysis mode these subroutines are also capable of determining
the proper operating conditions for an existing piece of equipment.
A recently completed study of the systems for heat recovery from
operating afterburners (4) has concluded that not only are such systems
technically feasible, but they can also be economically advantageous.
Attachments 13-4 and 13-5 show the magnitudes of energy savings actually
being obtained from surveyed operating units.
EPA has issued a series of reports entitled "Control of Volatile
Organic Emissions from Existing Stationary Sources" which is directed
entirely at the control of volatile organics contributing to the forma-
tion of photochemical oxidants. Volume I of this series (5) contains
much useful information on the effectiveness and costs of various control
options, including both catalytic and non-catalytic (thermal) incinera-
tors. The section of this volume devoted to incineration is reproduced
as an Appendix to this chapter. Subsequent volumes of the series deal
with the control of VOC from specific industries and processes, and should
be consulted for more detailed background and information applicable to
a specific problem.
References
1. Danielson, J. A., Editor, Air Pollution Engineering Manual,
AP-40, Second Edition, USEPA (May 1973).
2. Edwards, J. B., Combustion —• The Formation and Emission of_
Trace Species, Ann Arbor Science Publishers, Inc., Ann Arbor, Michigan.
3. Worley, F. L., Motard, R. L., "Control Equipment Design and
Analysis (CEDA): Gaseous Pollutants," USEPA Contract No. 68-02-1084,
13-6
-------
University of Houston Report (January 1976).
4. "Study of Systems for Heat Recovery from Afterburners,"
USEPA Contract No. 68-02-1473 (Task 23), Industrial Gas Cleaning Insti-
tute, Inc. Report (April 1978).
5. "Control of Volatile Organic Emissions from Existing Stationary
Sources —Vol. I: Control Methods for Surface-Coating Operation," USEPA
Report No. EPA-450/2-76-028 (OAQPS No. 1.2-067)(November 1976).
Vol. II— EPA-450/2-77-008
Vol. Ill — EPA-450/2-77-032
Vol. IV— EPA-450/2-77-033
Vol. V— EPA-450/2-77-034
13-7
-------
Attachment 13-1, Sectional View of Direct-Flame Afterburner
(Gas Processors, Inc., Brea, Calif.)
FLAME SENSOR-
BURNC*-
REFRACTORY-
1NSULATION-
TURBULENT EXPANSION 7.ONE-
STEEL SHELL •
CAS SYSTEM
CMtral
CONTROL PANEL
(rWMte •fttmnml)
UNITIZEO MOUNTING
SAMPLE PORT
TEMPERATURE SENSOR
Note: The turbulent expansion zone promotes mixing, as
gases decrease their velocity for proper residence time.
The compression zone in this design allows for better con-
trol and a modest blower size.
13-8
-------
Attachment 13-2, Catalytic Incinerator with Recycle and Heat Economizer
FUEL
Contaminated
• Stream
Stream
A. Blower Motor
B.' Blower (Mixer)
C. Fuel Burner
D. Catalytic Element
E. Temperature Controller
F. Recycle Damper
G. Heat Exchanger
Catalytic Oxidation
Low Temp. Feed With
Recycle and Heat
Exchanger
13-9
-------
Attachment 13-3, Ceramic Bed Regenerative-Type Incineration
and Heat Recovery System
TO
ATMOSPHERE
6,000 scfm
i
A Jr A 1
n n
BAKE OVEN
t|
Mtf
f
J
0,000 scfm
DAMPER
DAMPER
Stf'V—<*?.:•
*.* *•". '"it •".• -•"*.•.
;? CERAMIC!?
I
GAS, 500cfh
13-10
-------
Attachment 13-4, Reported Range of Heat Recovery Per Stage by Application
and Type of Afterburner Equipment"*
Application
Recovery range, %
per stage
1. Gas/Gas Heat Transfer
A. Recuperative
1. Heat fumes before combusting
2. Heat makeup air
B. Regenerative
1. Heat fumes before combusting
2. Heat makeup air'
2. Gas/Liquid Heat Transfer
A. Economizer
B. Boiler
3. Recycle
31 to 78
31 to 78
40 to 50
43 to 85
70 to 85
43 to 75
9 to 62
20 to 80
70 to 80
13-11
-------
Attachment 13-5, Energy Savings from Afterburner Exhausts
SYSTEM
NO.
(1)
1
2
3
4
5
6
7
8
9
10
HEAT ENERGY3
DISCHARGED TO
ATMOSPHERE FROM
AFTERBURNING WITHOUT
HEAT RECOVERY,
106 Btu/yr
(2)
52,243
192,920
127,600
38,198
160,583
149,463
180,145
63,120
128,163
76,184
HEAT ENERGY
DISCHARGED TO
ATMOSPHERE FROM
AFTERBURNER
WITH HEAT RECOVERY,
106 Btu/yr
(3)
12,690
44,118
16,313
5,177
37,930
27,443
34,100
12,284
25,633
16,370
HEAT ENERGY
SAVED
FROM
PROCESS
EXHAUST,
106 Btu/yr
(4)
39,553
148,302
111,287
33,021
122,653
122,020
146,045
55,836
102,530
59,314
IEAT. ENERGY
SAVED
FROM
PROCESS
EXHAUST,
%
(5)
76
77
87
86
76
82
31
82
80
73
PURCHASED ELECTRICITY
TO OPERATE
HEAT RECOVERY
WITH AFTERBURNER ,
106 Btu/yr
(6)
497
4,058
(153)
205
766
411
1,075
4,535
900
497
NET
ENERGY
SAVINGS,
106 Btu/yr
(7)
39,056
144,744
111.440
32,816
12 i.837
121,609
144,970
51.299
101 .630
59,317
NET
ENERGY
SAVINGS,
X
(8)
74.7
75.0
87.3
85.9
7b.9
31.4
80.5
75.3
79.3
77.9
Ul
I
a Based on 1400°F Incinerating and exhaust.
-------
EPA-450/2-76-028
(OAQPS NO. 1.2-067)
APPENDIX 13-1
CONTROL OF VOLATILE
ORGANIC EMISSIONS FROM EXISTING
STATIONARY SOURCES -
VOLUME I: CONTROL METHODS
FOR SURFACE-COATING OPERATIONS
Emission Standards and Engineering Division
Chemical and Petroleum Branch
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
November 1976
13-13
-------
3.2.2 Incineration
3.2.2.1 Introduction — Incineration destroys organic emissions by
oxidizing them to carbon dioxide and water vspor. Incineration is the
most universally applicable control method for organics; given the
proper conditions, any organic compound will oxidize. Oxidation proceeds
more rapidly at higher temperatures and higher organic pollutant content.
Incinerators (also called afterburners) have been used for many years on
a variety of sources ranging in size from less than 1000 scfm to greater
than 40,000 scfm.
Use of Existing Process Heaters for Incineration — The use of
existing boilers and process heaters for destruction of organic emissions
provides for the possibility of pollution control at small capital cost
and little or no fuel cost. The option is, however, severely limited in
its application. Some of the requirements are:
1. The heater must be operated whenever the pollution source is
operated; will be uncontrolled during process heater down time.
2. The fuel rate to the burner cannot be allowed to fall below
that required for effective combustion. On-off burner controls
are not acceptable.
3. Temperature and residence time in the heater firebox must be
sufficient.
4. For proper control, the volume of polluted exhaust gas must be
much smaller than the burner air requirement and be located
close to the process heater. For most plants doing surface
13-14
-------
coating, especially if surface coating is their main business,
the combustion air requirement is smaller than the coater-
related exhaust. In many diversified plants, the coating
operation may be distant from heaters and boilers.
5. Constituents of the coating-related exhaust must not damage
the internals of the process heater
Few boilers or heaters meet these conditions.
Use of add-on incinerators -- In noncatalytic incinerators (sometimes
called thermal or direct flame incinerators), a portion of the polluted
gas may be passed through the burner(s) in which auxiliary fuel is fired.
Gases exiting the burner(s) in excess of 2000°F are blended with the
bypassed gases and held at temperature until reaction is complete. The
equilibrium temperature of mixed gases is critical to effective combustion
of organic pollutants. A diagram of a typical arrangement is shown in
Figure 3-10.
The coupled effect of temperature and residence time is shown in
Figure 3-11. Hydrocarbons will first oxidize to water, carbon monoxide
and possibly carbon and partially oxidized organics. Complete oxidation
converters CO and residuals to carbon dioxide and water. Figure 3-12
shows the effect of temperature on organic vapor oxidation and carbon
monoxide oxidation.
A temperature of 1100 to 1250°F at a residence time of 0.3 to 0.5
2
second is sufficient to achieve 90 percent oxidation of most organic
vapors, but about 1400 to 1500°F may be necessary to oxidize methane,
cellosolve, and substituted aromatics such as toluene and xylene.^
Design -- Incineration fuel requirements are determined by the con-
centration of the pollutants, the waste stream temperature and oxygen
13-15
-------
FUME INLET
CONNECTION
PATH OF FUME FLOW (FUME ITSELF IS
USED AS SOURCE OF BURNER COMBUSTION
OXYGEN, ELIMINATING NEED FOR OUTSIDE
AIR ADMISSION AND INCREASED Btu LOAD.)
GAS
CONNECTION
U)
I
I-1
(Jl
PILOT
ASSEMBLY
INCINERATION
CHAMBER
FUME INLET PLENUM
REFRACTORY-LINED
IGNITION CHAMBER
Figure 3-10. Typical burner and chamber arrangement used in direct-flame incinerator.
-------
100
I
M
~J
v>
INCREASING RESIDENCE TIME
1000
1800 2000
1200 1400 1600
TEMPERATURE. °F
Figure 3-11. Coupled effects of temperature and time on rate of pollutant oxidation.
-------
OJ
I
oo
HYDROCARBONS
ONLY
HYDROCARBON AND CARBON
MONOXIDE (PER LOS ANGELES
AIR POLLUTION CONTROL
DISTRICT RULE 66)
1150 1200 1250, 1300 1350 1400
TEMPERATURE, °F
1450
1500
1550
'Figure 3-12. Typical effect of operating temperature on effectiveness of thermal afterburner
for destruction of hydrocarbons and carbon monoxide.''
-------
level, and the incineration temperature required. For most organic
solvents, the heat of combustion is about 0.5 Btu/scf for each percent
of the LEL. This is enough to raise the waste stream temperature about
27.5°F for each percent of the LEL (at 100 percent combustion). Thus,
at 25 percent of the LEL, the temperature rise will be 620°F for
90 percent conversion.
Fuel —• Natural gas, LPG and distillate and residual oil are used to
fuel incinerators. The use of natural gas or LPG results in lower
maintenance costs; at present, natural gas also is the least expensive
fuel. However, the dwindling natural gas supplies make it almost a
necessity to provide newly installed incinerators with oil-burning
capabilities.
In most cases where natural gas or LPG is not available, incinerators
are fixed with distillate fuel oil; residual oil is seldom employed.
Oil flames are more luminous and longer than gas flames, thus require
longer fireboxes. Almost all fuel oils, even distillate, contain measurable
sulfur compounds. Residual oils generally have greater sulfur and
particulate contents and many have appreciable nitrogen fractions.
Sulfur oxides, particulates and NO in combustion products from fuel
/\
oil increase pollution emissions and cause corrosion and soot accumulation
or incinerator work and heat transfer surfaces.
Heat recovery -- Heat recovery offers a way to reduce the energy
consumption of incinerators. The simplest method is to use the hot
cleaned gases exiting the incinerator to pVeheat the cooler incoming
gases. Design is usually for 35 to 90 percent heat recovery efficiency.
13-19
-------
The maximum usable efficiency is determined by the concentration of
the organics in the gases, the temperature of the inlet gases, and the
maximum temperature that the incinerator and heat exchangers can withstand.
In a noncatalytic system with a primary heat exchanger, the preheat
temperature should not exceed 680°F, at 25 percent LEL, in order to limit
incinerator exit temperatures to about 1'150°F for the protection of the
heat exchanger. The auxiliary fuel would heat the stream about 150°F and
oxidation of the solvent would heat it about 620°F for an exit temperature
of 680 + 150 + 620 = 1450°F- At 12 percent LEL the preheat temperature
should not exceed 930°F. Most burners have not been designed to tolerate
temperatures above 1100°F-
There are several types of heat recovery equipment using different
materials at various costs. The most common is the tube and shell heat
exchanger. The higher temperature exhaust passes over tubes, which have
lower temperature gas or liquid flowing through the tubes; thus increasing
the temperature of that gas or liquid. Another method uses a rotating
ceramic or metal wheel whose axis is along the wall between two tunnels.
Hot exhaust flows through one tunnel and heats half of the wheel. Lower
temperature air flows through the other tunnel and is heated as the wheel
rotates. Another method uses several chambers containing inert ceramic
materials with high heat retention capability. The hot gas (e.g. from
the incinerator) passes through these beds and heats the ceramic material.
The air flow is then reversed, and lower temperature gas passes through
the heated beds; thus raising the temperature of that gas to near
incineration temperature. Further details on various heat recovery
methods and equipment can be obtained from the vendors of incinerators.
13-20
-------
The use of incinerator exhaust to preheat Incinerator Inlet air 1s
often referred to as "primary" heat recovery as Illustrated 1n Case 2 of
Figure 3-13. Since some systems have a maximum allowable inlet tempera-
ture for the Incinerator, 1t may not be possible to recover all of the heat
available in the incinerator exhaust. In such case, the Inlet to the
incinerator is controlled to minimize fuel requirements. Note that a non-
catalytic incinerator always requires some fuel to Initiate combustion.
"Secondary" heat recovery uses incinerator exhaust from the primary heat
recovery stage (or from the incinerator directly 1f there 1s no primary heat
recovery) to replace energy usage elsewhere 1n the plant. This energy can
be used for process heat requirements or for plant heating. The amount of
energy that a plant can recover and use depends on the Individual circum-
stances at the plant. Usually recovery efficiency of 70 to 80 percent is
achievable, making the net energy consumption of an Incinerator minimal or
even negative if gases are near or above 25 percent of the LEL. The use of
primary and secondary heat recovery 1s illustrated in Case 3 of Figure 3-13.
It should be noted that heat recovery reduces operating expenses for fuel at
the expense of increased capital costs. Primary heat recovery systems are
within the incinerator and require no long ducts. Secondary heat recovery
may be difficult to install on an existing process because the sites where
recovered energy may be used are often distant from the Incinerator. In
applying calculated values for recovered energy values 1n Case 3 to real
plants, the cost of using recovered energy must be considered. If secondary
heat recovery 1s used, often the plant cannot operate unless the control
system is operating because it supplies heat required by the plant.
13-21
-------
w
I
to
to
SOLVE
CONTAir
OFF-G
CASE 1 - BASIC SYSTEM
CATALYST, IF ANY
NT- (
IIING | * 1
ASJ L TO
^«Z_ ,*f r i— O w ATMOSPHERE
\)J I
FUEL INCINERATOR
PROCESS
CA
PROCE
SE 3 - PROCESS HEAT RECOVERY WITH GAS PREHEAT
1 CATALYST, IF ANY *
) U
n > n/5 r
PREHEATER 1 FUEL INCINERATOR
^. /s. HEAT
S >. / > 4 1 RECOVERY
v^ >< FLUID
•
1 r Donrccc UCAT Bcrni/Env
55 > 1 S fcT°
<^ ( W ATMOSPHERE
J
CASE 2 - BASIC SYSTEM WITH GAS PREHEAT
i k
TO
ATMOSPHERE
FUEL ^CATALYST'IFANY
m > n n
L_ * I 1 |
PREHEATER f INCINERATOR , r
PROCESS
CASE 4 - INERT GAS GENERATOR
COMBUSTION
A(R CATALYST. IF ANY
^ li^1
-> O J-. —B * k. VENTED 10
I /*y I ATMOSPHERE
FUEL INCINERATOR
INERT GAS
PROCESS «
Figure 3-13. Configurations for catalytic and noncatalytic incineration.
-------
If the gases in an oven are inert, that is, contain little oxygen,
explosions are not possible and high concentrations of organic solvent
vapor can be handled safely. The oven exhaust can be blended with air
and burned with minimal auxiliary fuel. The incinerator may be the
source of inert gas for the oven. Cooling of the incinerator gas is
necessary, removing energy that can be used elsewhere. Case 4 of
Figure 3-13 illustrates this scheme. A modification of the'scheme shown
is the use of an external inert gas generator. This scheme can have a
significant energy credit because the otherwise discarded organics are
converted to useful energy. Because of the specialized nature of Case 4,
it may not be applicable to retrofits on existing ovens and costs for this
case are not included in this study. Note that in this case the incinerator
exhaust is in contact with the product. This limits the available fuel
for this option to natural gas or propane. The use of this option would
probably be impossible if any compounds containing appreciable sulfur or
halogens are used.
To illustrate a specific case, Figure 3-14 outlines a source
controlled by a noncatalytic incinerator. The source is assumed to
operate 25 percent of the LEL and the incinerator has primary and
secondary heat recovery. The primary heat exchanger raises the temperature
to 700°F, at 35 percent heat recovery efficiency. The heat of combustion
of the organic vapors provides a 620°F additional temperature rise at
90 percent combustion and the burner must supply only enough heat to
raise the gases 80°F to reach the design combustion temperature of 1400°F.
Combustion products pass through the primary heat exchanger -- where
13-23
-------
W
to
ATCOMBUSTIONFUEL = 8° F
PROCESS HEAT RECOVERY
Figure 3~14. Example of incinerator on oven with primary and secondary heat recovery.
-------
they are cooled to 1025°F -- and enter a 35 percent efficient secondary
heat exchanger. In the secondary heat exchanger, further energy is
recovered for use in other areas. In this example, makeup air for the
source is heated from ambient temperatures to source entrance temperatures
(higher than oven exit temperatures).
The energy implications of this scheme can be seen by comparing the
energy input of this controlled source with an uncontrolled source. In
an uncontrolled source, fuel would be necessary to raise the temperature
of the makeup air from 70°F to 425°F or 355°F. For a controlled source,
fuel would only need to raise the temperature 800F. Thus, the energy
input would be reduced by over 80 percent by use of incineration simply
because the organic vapors contribute heat when they burn.
In the above analysis, the assumptions made are important. If the
organic vapors are more dilute, the temperature rise due to combustion
will be less. Heat recovery can be more efficient than 35 percent, making
up for all or some of this difference. Finally, the analysis assumes
that the heat recovered in the secondary heat exchanger can be used in the
plant. The heat can be used to produce steam, heat water, supply process
heat or heat buildings. Obviously, a case-by-case analysis is necessary
to ascertain how much recovered heat could be used.
Particulates -- The level of particulate concentration found in
surface coating operations should not pose any problems for noncatalytic
volatile organic combustion. However, an incinerator designed for
hydrocarbon removal usually will not have sufficient residence time to
13-25
-------
efficiently combust organic particulates.
Safety of preheat -- (At 25 percent of the LEL), oxidation rates
at temperatures below 1100°F are slow. Complete oxidation can take
several seconds. Because the gases are in the heat exchanger for less
than a second preignition should not be a problem using heat recovery
if temperatures are below 1000°F to 1100°F.
Some problems have occurred in the past with accumulations of
condensed materials or particulates igniting in the heat recovery devices.
If this occurs, the accumluations must be periodically removed from the
heat transfer surfaces. The user should give careful consideration for
his particular set of circumstances to potential safety problems. This
is especially true if gases at a high percent of the LEL are preheated.
Adverse environmental effects -- Sulfur-containing compounds will
be converted to their oxides;-halogen-containing compounds will be
converted to acids. A portion of nitrogen-containing compounds will be
converted to NC) and additional NOV will result from thermal fixation.
X A
If use of these compounds cannot be avoided, the benefit from incineration
should be evaluated against the adverse effects and alternate methods
of control should be thoroughly explored.
The concentration of oxides of nitrogen (NO ) is about 18 to 22 ppm for
X
natural gas-fired noncatalytic incinerators and 40 to 50 ppm for oil-fired
noncatalytic incinerators at a temperature of 1500°F, assuming no nitrogen
containing compounds are incinerated.
13-26
-------
Effect of Technical Assumptions on Cost Models — In the cost estimates
(Section 4.2.2.1) for noncatalytic incineration, the organic was assumed
to be 50 molar percent hexane and 50 molar percent benzene. For
noncatalytic incineration, the two important factors are the heat
available per unit volume at the LEL and the temperature necessary for
combustion. For most solvents, the heat of combustion at the LEL is
2
about 50 Btu/scf. This will vary about +.20 percent for almost the entire
range of solvents used (methanol and ethanol are slightly higher). Thus,
there is little variation due to the type of solvent.
The assumed temperature of combustion (1400°F) is sufficient to
obtain 95+ percent removal of the entire range of organics used as solvents.
3.2.2.2 Catalytic Incineration -- A catalyst is a substance that speeds up
the rate of chemical reaction at a given temperature without being perma-
nently altered. The use of a catalyst in an incinerator reportedly enables
satisfactory oxidation rates at temperatures in the range of 500 to 600°F
inlet and 750 to 1000°F outlet. If heat recovery is not practiced,
significant energy savings are possible by use of a catalyst. The fuel
savings become less as primary and secondary heat recovery are added.
Because of lower temperatures, materials of construction savings are
possible for heat recovery and for the incinerator itself. A schematic
of one possible configuration is shown in Figure 3-15.
Catalysts are specific in the types of reactions they promote. There
are, however, oxidation catalysts available that will work on a wide range
of organic solvents. The effect of temperature on conversion for solvent
hydrocarbons is shown in Figure 3-16. Common catalysts are platinum or
other metals on alumina pellet support or on a honeycomb support. All-metal
catalysts can also be used.
13-27
-------
CLEAN,HOT
GASES
CATALYST
ELEMENTS
OVEN
FUMES
PREHEATER
Figure 3-15. Schematic diagram of
catalytic afterburner using torch-
type preheat burner with flow of
preheater waste stream through fan
to promote mixing.!
13-28
-------
I
to
400
600
TEMPERATURE. °F
BOO
1000
1200
Figure 3-16. Effect of temperature on conversion for catalytic incineration.
-------
The initial cost of the catalyst and its periodic replacement
represents, respectively, increased capital and operating costs. The
lifetime of the catalyst depends on the rate of catalyst deactivation.
Catalyst Deactivation -- The effectiveness of a catalyst requires the
accessability of "active sites" to reacting molecules. Every catalyst
will begin to lose its effectiveness as soon as it is put into service.
Compensation for this must be made by either overdesigning theanount of
catalyst in the original charge or raising the temperature into the
catalyst to maintain the required efficiency. At some time, however,
activity decays to a point where the catalyst must be cleaned or replaced.
Catalysts can be deactivated by normal aging, by use at excessively high
temperature, by coating with particulates, or by poisoning. Catalyst life-
time of greater than 1 year is considered acceptable.
Catalyst material can be lost from the support by erosion, attrition,
or vaporization. These processes increase with temperature. For metals on
alumina, if the temperature is less than 1100°F, life will be 3 to 5 years
if no deactivation mechanisms are present. At 1250 to 1300°F, this drops
to 1 year. Even short-term exposure to 1400 to 1500°F can result in near
total loss of catalytic activity.
The limited temperature range allowable for catalysts sets constraints
on the system. As mentioned earlier, at 25 percent of the LEL and
90 percent combustion there will be about a 620°F temperature rise as
a result of organic combustion. Because an inlet temperature of 500 to
600°F is necessary to initiate combustion, the catalyst bed exit
temperature will be 1120 to 1220°F at 25 percent of the LEL. This is
13-30
-------
the upper limit for good catalyst life and thus concentrations of
greater than 25 percent of the LEL cannot be incinerated in a catalytic
incinerator without damage to the catalyst. Restrictions on heat
recovery options are also mandated. These will be discussed later.
Coating with particulates — The buildup of condensed polymerized
material or solid particulate can inhibit contact between the active
sites of the catalyst and the gases to be controlled. Cleaning is the
usual method for reactivation. Cleaning methods vary with the catalyst
and instructions are usually given by the manufacturer.
Poisoning -- Certain contaminants will chemically react or alloy with
contnon catalysts and cause deactivation. A common list includes phosphorus,
bismuth, arsenic, antimony, mercury, lead, zinc, and tin. The first five
are considered fast acting; the last three are slow acting, especially
below 1100°F. Areas of .care include avoiding the use of phosphate metal
cleaning compounds and galvanized ductwork. Sulfur and halogens are also
considered catalyst poisons, but their effect is reversible.
Fuel -- Natural gas is the preferred fuel for catalytic incinerators
because of its cleanliness. If properly designed and operated, a
catalytic incinerator could possibly use distillate oil. However, much
of the sulfur in the oil would probably be oxidized to S03 which would
subsequently form sulfuric acid mist. This would necessitate corrosive
resistant materials and would cause the emission of a very undesirable
pollutant. Therefore, the use of fuel oil (even low sulfur) in a
catalytic incinerator is not recommended.
13-31
-------
Heat Recovery -- The amount of heat that can be transferred to the
cooler gases is limited. The usual design is to have the exit
temperature from the catalyst bed at about 1000°F. If the gas is at
15 percent of the LEL, for example, the temperature rise across the
bed would be about 375°F, and the gas could only be preheated to about
625°F. Secondary heat recovery is limited by the ability to use the
recovered energy. If a gas stream is already at combustion temperature,
it is not useful to use "primary" heat recovery but "secondary" heat
recovery may still be possible. Note that for catalytic incineration,
no flame initiation is necessary and thus it is possible to have no fuel
input.
As in noncatalytic systems, heat recovery equipment may need
periodic cleaning if certain streams are to be processed. For a discussion
of the safety of preheat, see Section 3.2.2.2.
Adverse environmental effects of catalytic incineration — As in non-
catalytic incineration, if sulfur- or nitrogen-containing compounds are
present, their oxides will be generated. If halogenated compounds are
present, their acids will be formed. If it is impossible to avoid using
these compounds in quantity, incineration may be unwise.
The concentration of NOX from catalytic incinerators is low, about
2
15 parts per million, assuming no nitrogen compounds are incinerated.
Effect of technical assumptions on cost models — In the cost estimates
for catalytic incineration, the solvent was assumed to be 50 molar percent
hexane and 50 molar percent benzene. For catalytic incineration, the two
important factors are the heat available per unit volume at the LEL and
the temperature necessary for catalytic oxidation.
13-32
-------
As discussed earlier, there is little variation in the available
heat from combustion at the LEL.
The assumed temperature into the catalytic incinerator is sufficient
to obtain 95 percent removal of the entire range of organics used in
solvents.
3.4 REFERENCES
1. Package Sorption Systems Study, MSA Corporation, Evans City, Pa.,
Prepared for U.S. Environmental Protection Agency, Research Triangle
Park, N.C. under Contract EHSD 71-2. Publication No. KPA R2-73-202.
April 1973.
2. Rolke, R.W. et al. Afterburner Systems Study, Shell Development
Company, Emeryville, Cal.', Prepared for U.S. Environmental Protection
Agency, Research Triangle Park, N.C. under Contract No. ESHD 71-3.
Publication No. EPA-R2-72-062. August 1972.
13-33
-------
CHAPTER 14
WASTE-GAS FLARES
The material presented in this chapter is an edited ver-
sion of the work of D. I. Walters and H. B. Couglin, published
in Air Pollution Engineering Manual, EPA Publication AP-40,
second edition, Chapter 10 (May 1973).
Introduction
Large volumes of hydrocarbon gases are produced in modern refinery
and petrochemical plants. Generally, these gases are used as fuel or as
raw material for further processing. In the past, however, large quanti-
ties of these gases were considered waste gases, and along with waste
liquids, were dumped to open pits and burned, producing large volumes of
black smoke. With modernization of processing units, this method of waste-
gas disposal, even for emergency gas releases, has become less acceptable
to the industry. Local and state governments have adopted ordinances (some
of which were part of the State Implementation Plans for air pollution
control in the early 1970's) limiting the opacity of smoke to 20% or less.
Nevertheless, petroleum refineries are still faced with the problem
of safe disposal of volatile liquids and gases resulting from scheduled
shut-downs and sudden or unexpected upsets in process units. Emergencies
that can cause the sudden venting of excessive amounts of gases and vapors
include fires, compressor failures, overpressures in process vessels,
14-1
-------
line breaks, leaks, and power failures. Uncontrolled releases of large
volumes of gases also constitute a serious safety hazard to personnel and
equipment.
A system for disposal of emergency and waste refinery gases consists
of a manifolded pressure-relieving or blowdown system, and a blowdown
recovery system or a system of flares for the combustion of the excess
gases, or both. Many refineries, however, do not operate blowdown recovery
systems. In addition to disposing of emergency and excess gas flows, these
systems are used in the evacuation of units during shutdowns and turnarounds.
Normally a unit is shut down by depressuring into a fuel gas or vapor recov-
ery system with further depressuring to essentially atmospheric pressure, by
venting to a low-pressure flare system.
A blowdown or pressure-relieving system consists of relief valves,
safety valves, manual bypass valves, blowdown headers, knockout vessels,
and holding tanks. A blowdown recovery system also includes compressors
and vapor surge vessels, such as gas holders or vapor spheres. This
equipment must be designed to permit safe disposal of excess gases and
liquids in case operational difficulties or fires occur. These materials
are usually removed from the process area by automatic safety and relief
valves, as well as by manually controlled valves, manifolded to a header
that conducts the material away from the unit involved. The preferred
method to dispose of the waste gases, which cannot be recovered in a
blowdown recovery system, is by burning them in a smokeless flare. Liquid
blowdowns are usually conducted to appropriately designed holding ves-
sels and reclaimed.
A pressure-relieving system used in one modern petroleum refinery is
shown in Attachment 14-1. The system is used not only as a safety measure,
14-2
-------
but also as a means of reducing the emission of hydrocarbons to the atmos-
phere. This installation actually includes four separate collecting sys-
tems, as follows: (a) the low-pressure blowdown system for vapors from
equipment with working pressure below 100 psig, (b) the high-pressure
blowdown system for vapors from equipment with working pressures above
100 psig, (c) the liquid blowdown system for liquids at all pressures,
and (d) the light-ends blowdown for butanes and lighter hydrocarbon blow-
down products.
The liquid portion of light hydrocarbon products released through
the light-ends blowdown system is recovered in a drum near the flare.
A backpressure of 50 psig is maintained on the drum, which minimizes the
amount of vapor that vents through a backpressure regulator to the high-
pressure blowdown line. The high-pressure, low-pressure, and liquid-
blowdown systems all discharge into the main blowdown vessel. Any en-
trained liquid is dropped out and pumped to a storage tank for recovery.
Offgas from this blowdown drum flows to a vertical vessel with baffle
trays in which the gases are in direct contact with water, which con-
denses some of the hydrocarbons and permits their recovery. The over-
head vapors from this so-called sump tank flow to the flare system mani-
fold for disposal by burning in a smokeless flare system.
The Air Pollution Problem
The air pollution problem associated with the uncontrolled disposal
of waste gases is the venting of large volumes of hydrocarbons and other
odorous gases and aerosols. The preferred control method for excess
gases and vapors is to recover them in a blowdown recovery system and,
failing that, to incinerate them in an elevated-type flare. Such flares
14-3
-------
introduce the possibility of smoke and other objectionable gases such as
carbon monoxide, sulfur dioxide, and nitrogen oxides. Flares have been
further developed to ensure that this combustion is smokeless and, in some
cases, nonluminous. Luminosity, while not an air pollution problem, does
attract attention to the refinery operation and in certain cases can cause
bad public relations. Noise also can result in a nuisance problem if the
refinery is located in an area zoned for residential expansion into the
property surrounding the plant or if a new facility is built close to a
residential area.
Smoke from Flares
The natural tendency of most combustible gases is to smoke when
flared. While smoke is the result of incomplete combustion, the impor-
tant parameter is the H/C ratio of the gas. Gases with an H/C ratio of
less than 0.28 will smoke when flared unless steam or water is injected
into the flare zone. Further discussion of the importance of the H/C
ratio is found in Mandell's paper, Appendix 14-1.
Types of Flares
There are, in general, three types of flares for the disposal of
waste gases: elevated flares, ground-level flares, and burning pits.
The burning pits are reserved for extremely large gas flows caused
by catastrophic emergencies in which the capacity of the primary smoke-
less flares is exceeded. Ordinarily, the main gas header to the flare
system has a water seal bypass to a burning pit. Excessive pressure
in the header blows the water seal and permits the vapors and gases to
vent a burning pit where combustion occurs.
14-4
-------
The essential parts of a flare are the: burner, stack, seal, liquid
trap, controls, pilot burner, and ignition system. In some cases, vented
gases flow through chemical solutions to receive treatment before com-
bustion. As an example, gases vented from an isomerization unit that may
contain small amounts of hydrochloric acid are scrubbed with caustic be-
fore venting to the flare.
Elevated Flares
Smokeless combustion can be obtained in an elevated flare by the
injection of an inert gas to the combustion zone to provide turbulence
and inspirate air. A mechanical air-mixing system would be ideal but is
not economical in view of the large volume of gases handled. The most com-
monly encountered air-inspirating material for an elevated flare is steam.
Attachment 14-2 is an illustration of one type of multiple nozzle
flare assembly. Steam injection is accomplished by several small jets
placed concentrically around the flare tip. These jets are installed at
an angle, causing the steam to discharge in a converging pattern imme-
diately above the flare tip.
Attachment 14-3 shows a recent modification of the multiple-nozzle
type tip. Modern refining process units with large capacities and greater
use of high operating pressures have increased the mass-flow rates to
flares, thus requiring larger diameter tips. To ensure satisfactory opera-
tion under varied flow conditions, internal injector tubes along with a
center tube have been added. The injector tubes provide additional tur-
bulence and combustion air, while the central steam jet and attached
diffuser plate provide additional steam to eliminate smoke at low flow
conditions. The flare continues to employ steam jets placed concentrically
14-5
-------
around the tip, as shown in Attachment 14-2, but in a modified form.
Noise problems may result at the injector tubes if muffling devices are
not used.
A second type of elevated flare has a flare tip with no obstruction
to flow, that is, the flare tip is the same diameter as the stack. The
steam is injected by a single nozzle located concentrically within the
burner tip. In this type of flare, the steam is premixed with the gas
before ignition and discharge.
A third type of elevated flare has been used by the Sinclair Oil
Company (4). It is equipped with a flare tip constructed to cause the
gases to flow through several tangential openings to promote turbulence.
A steam ring at the top of the stack has numerous equally spaced holes
about 1/8-inch in diameter for discharging steam into the gas stream.
The injection of steam in this latter flare may be automatically or
manually controlled. In most cases, the steam is proportioned "automati-
cally to the rate of gas flow; however, in some installations, the steam
is automatically supplied at maximum rates, and manual throttling of a
steam valve is required for adjusting the steam flow to the particular
gas flow rate. There are many variations of instrumentation among various
flares, some designs being more desirable than others. For economic rea-
sons, all designs attempt to proportion steam flow to the gas flow rate.
Steam injection is generally believed to result in the following
benefits: (a) energy available at relatively low cost can be used to
inspirate air and provide turbulence within the flame, (b) steam reacts
with the fuel to form oxygenated compounds that burn readily at relatively
low temperatures, (c) water-gas reactions also occur with this same end
14-6
-------
result, and (d) steam reduces the partial pressure of the fuel and retards
polymerization. (Inert gases such as nitrogen have also been found effec-
tive for this purpose; however, the expense of providing such a diluent
is prohibitive.)
Multistream-Jet-Type Elevated Flare
A multistream-jet-type elevated flare (3) is shown in Attachment 14-4.
All relief headers from process units combine into a common header that
conducts the hydrocarbon gases and vapors to a large knockout drum. Any
entrained liquid is dropped out and pumped to storage. The gases then
flow in one of two ways. For emergency gas releases that are smaller
than or equal to the design rate, the flow is directed to the main flare
stack. Hydrocarbons are ignited by continuous pilot burners, and steam
is injected by means of small jet fingers placed concentrically about
the stack tip. The steam is injected in proportion to the gas flow.
The steam control system consists of a pressure controller, having a
range of 0 to 20 inches water column, that senses the pressure in the
vent line and sends an air signal to a valve operator mounted on a 2-inch
V-Port control valve in the steam line. If the emergency gas flow ex-
ceeds the designed capacity of the main flare, backpressure in the vent
line increases, displacing the water seal, and permitting gas flow to the
auxiliary flare. Steam consumption of the burner at a peak flow is
about 0.2 to 0.5 pound of steam per pound of gas, depending upon the
amount and composition of hydrocarbon gases being vented. In general,
the amount of steam required increases with increased molecular weight
and the degree of unsaturation of the gas.
14-7
-------
A small amount of steam (300 to 400 pounds per hour) is allowed to
flow through the jet fingers at all times. This steam not only permits
smokeless combustion of gas flows too small to actuate the steam control
valves but also keeps the jet fingers cooled and open.
Esso-Type Elevated Flare
A second type of elevated, smokeless, steam-injected flare is the
Esso type. The design is based upon the original installation in the
Bayway Refinery of the Standard Oil Company of New Jersey (7 and 8). A
typical flare system serving a petrochemical plant using this type burner
is shown in Attachment 14-5. The type of hydrocarbon gases vented can
range from a saturated to a completely unsaturated material. The injec-
tion of steam is not only proportioned by the pressure in the blowdown
lines but is also regulated according to the type of material being flared.
This is accomplished by the use of a ratio relay that is manually con-
trolled. The relay is located in a central control room where the operator
has an unobstructed view of the flare tip. In normal operation the relay
is set to handle feed gas, which is most common to this installation.
In this installation, a blowdown header conducts the gases to a
water seal drum as shown in Attachment 14-6. The end of the blowdown
line is equipped with two slotted orifices. The flow transmitter senses
the pressure differential across the seal drum and transmits an air sig-
nal to the ratio relay. The signal to this relay is either amplified
or attenuated, depending upon its setting. An air signal is then trans-
mitted to a flow controller that operates two parallel steam valves.
The 1-inch steam valve begins to open at an air pressure of 3 psig and
is fully open at 5 psig. The 3-inch valve starts to open at 5 psig and
14-8
-------
is fully open at 15 psig air pressure. As the glas flow increases, the
water level in the pipe becomes lower than the water level in the drum,
and more of the slot is uncovered. Thus, the difference in pressure
between the line and the seal drum increases. This information is trans-
mitted as an air signal to actuate the steam valves. The slotted orifice
senses flows that are too small to be indicated by a Pitot-tube-type flow
meter. The water level is maintained lh inches above the top of the ori-
fice to take care of sudden surges of gas to the system.
A 3-inch steam nozzle is so positioned within the stack that the
expansion of the steam just fills the stack and mixes with the gas to pro-
vide smokeless combustion. This type of flare is probably less efficient
in the use of steam than some of the commercially available flares,but it
is desirable from the standpoints of simpler construction and lower main-
tenance costs.
Sinclair-Type Elevated Flare
A diagram (4) of an installation using a Sinclair-type elevated flare
is shown in Attachment 14-7. Details of the burner design are shown in
Attachment 14-8.
The flow of steam from the ring inspirates air into the combustion
area, and the shroud protects the burner from wind currents and provides
a partial mixing chamber for the air and gas. Steam is automatically
supplied when there is gas flow. A pressure-sensing element actuates
a control valve in the steam supply line. A small bypass valve permits
a small, continuous flow of steam to the ring, keeping the ring holes
open and permitting smokeless burning of small gas flows.
14-9
-------
Ground-Level Flares
There are four principal types of ground-level flare: horizontal
venturi, water injection, multi-jet, and vertical venturi.
Horizontal, Venturi-Type Ground Flare
A typical horizontal, venturi-type ground flare system is shown in
Attachment 14-9. In this system, the refinery flare header discharges
to a knockout drum where any entrained liquid is separated and pumped
to storage. The gas flows to the burner header, which is connected to
three separate banks of standard gas burners through automatic valves of
the snap-action type that open at predetermined pressures. If any or all
of the pressure valves fail, a bypass line with a liquid seal is provided
(with no valves in the circuit), which discharges to the largest bank of
burners.
The automatic-valve operation schedule is determined by the quantity
of gas most likely to be relieved to the system. The allowable back-
pressure in the refinery flare header determines the minimum pressure for
the control valve on the No. 1 burner bank. On the assumption that the
first valve was set at 3 psig, then the second valve for the No. 2 burner
bank would be set for some higher pressure, say 5 psig. The quantity of
gas most likely to be released then determines the size and the number of
burners for this section. Again, the third most likely quantity of gas
determines the pressure setting and the size of the third control valve.
Together, the burner capacity should equal the maximum expected flow rate.
A small flare unit of this design, with a capacity of 2 million scf
per day, reportedly cost approximately $5,000 in 1953 (2). Another large,
horizontal, venturi-type flare that has a capacity of 14 million scfh and
14-10
-------
requires specially constructed venturi burners (throat diameter ranges
from 5 to 18 inches), and costs were about $63,000.
Water Injection-Type Ground Flare
Another type of ground flare used in petroleum refineries has a water
spray to inspirate air and provide water vapor for the smokeless combustion
of gases (Attachment 14-10). This flare requires an adequate supply of
water and a reasonable amount of open space.
The structure of the flare consists of three concentric stacks. The
combustion chamber contains the burner, the pilot burner, the end of the
ignitor tube, and the water spray distributor ring. The primary purpose
of the intermediate stack is to confine the water spray so that it will
be mixed intimately with burning gases. The outer stack confines the
flame and directs it upward.
Water sprays in elevated flares are not too practical for several
reasons. It is difficult to keep the water spray in the flame
zone, and scale formed in the waterline tends to plug the nozzles.
In one case it was necessary to install a return system that permitted
continuous waterflow to bypass the spray nozzle. Water main pressure
dictates the height to which water can be injected without the use of a
booster pump. For a 100- to 250-foot stack, a booster pump would undoubt-
edly be required. Rain created by the spray from the flare stack is
objectionable from the standpoint of corrosion of nearby structures and
other equipment.
Water is not as effective as steam for controlling smoke with high
gas flow rates, unsaturated materials, or wet gases. The water spray
flare is economical when venting rates are not too high and slight
14-11
-------
smoking can be tolerated. In Los Angeles County, where restrictions on
the emission of smoke from flares are very strict, a water spray smokeless
flare is not acceptable.
Multijet-Type Ground Flare
A recent type of flare developed by the refining industry is known
as a multijet (6). This type of flare was designed to burn excess hydro-
carbons without smoke, noise, or visible flame. It is claimed to be less
expensive than the steam-injected type, on the assumption that new steam
facilities must be installed to serve a steam-injected flare unit. Where
the steam can be diverted from noncritical operations such as tank heating,
the cost of the multijet flare and the steam-inspirating elevated flare
may be similar.
A sketch of an installation of a multijet flare is shown in Attach-
ment 14-11. The flare uses two sets of burners; the smaller group han-
dles normal gas leakage and small gas releases, while both burner groups
are used at higher flaring rates. This sequential operation is con-
trolled by two water-sealed drums set to release at different pressures.
In extreme emergencies, the multijet burners are bypassed by means of a
water seal that directs the gases to the center of the stack. This seal
blows at flaring rates higher than the design capacity of the flare. At
such an excessive rate, the combustion is both luminous and smoky, but
the unit is usually sized so that an overcapacity flow would be a rare
occurrence. The overcapacity line may also be designed to discharge
through a water seal to a nearby elevated flare rather than to the cen-
ter of a multijet stack.
14-12
-------
Vertical, Venturi-Type Ground Flare
Another type of flare based upon the use of commercial-type venturi
burners is shown in Attachment 14-12. This type of flare has been used
to handle vapors from gas-blanketed tanks, and vapors displaced from the
depressuring of butane and propane tank trucks. Since the commercial
venturi burner requires a certain minimum pressure to operate efficiently,
a gas blower must be provided. Some installations provide two burners
which operate at a pressure of 1/2 to 8 psig. A compressor takes vapors
from storage and discharges them at a rate of 6,000 cfh and 7 psig through
a water seal tank and a flame arrestor to the flare. This type of arrange-
ment can readily be modified to handle different volumes of vapors by
installing the necessary number of burners.
This type of flare is suitable for relatively small flows of gas of
a constant rate. Its main application is in situations where other means
of disposing of gases and vapors are not .available.
Effect of Steam Injection
A flare installation that does not inspirate an adequate amount of
air, or does not mix the air and hydrocarbons properly, emits dense, black
clouds of smoke that obscure the flame. The injection of steam into the
zone of combustion causes a gradual decrease in the amount of smoke, and
the flame becomes more visible. When trailing smoke has been eliminated,
the flame is very luminous and orange with a few wisps of black smoke
around the periphery. The minimum amount of steam required produces a
yellowish-orange, luminous flame with no smoke. Increasing the amount of
steam injection further decreases the luminosity of the flame. As the
steam rate increases, the flame becomes colorless and finally invisible
14-13
-------
during the day. At night this flame appears blue.
An injection of an excessive amount of steam causes the flame to
disappear completely and be replaced with a steam plume. An excessive
amount of steam may extinguish the burning gases and permit unburned
hydrocarbons to discharge to the atmosphere. When the flame is out,
there is a change in the sound of the flare because a steam hiss re-
places the roar of combustion. The commercially available pilot burners
are usually not extinguished by excessive amounts of steam, and the flame
reappears as the steam injection rate is reduced. As the use of automatic
instrumentation becomes more prevalent in flare installations, the use of
excessive amounts of steam and the emission of unburned hydrocarbons de-
crease and greater steam economies can be achieved. In evaluating flare
installations from an air pollution standpoint, controlling the volume of
steam is important. Too little steam results in black smoke, which, obvi-
ously, is objectionable. Conversely, excessive use of steam produces a
white steam plume and an invisible emission of unburned hydrocarbons.
Design of a Smokeless Flare
The choice of a flare is dictated by the particular requirements of
the installation. A flare may be located either at ground level or on an
elevated structure. Ground flares are less expensive, but locations must
be based upon considerations such as proximity of combustible materials,
tanks, and refinery processing equipment. In a congested refinery area,
there may be no choice but to use an elevated flare.
The usual flare system includes gas collection equipment, the liquid
knockout tank preceding the flare stack. A water seal tank is usually
located between the knockout pot and the flare stack to prevent flashbacks
14-14
-------
into the system. Flame arresters are sometimes used in place of or in con-
junction with a water seal pot. Pressure-temperature-actuated check valves
have been used in small ground flares to prevent flashback. The flare
stack should be continuously purged with steam, refinery gas, or inert gas
to prevent the formation of a combustible mixture that could cause an ex-
plosion in the stack (5). The purge gas should not fall below its dew
point under any condition of flare operation.
To prevent air from entering a flare stack which is used to dispose
of gases that are lighter than air, a device known as a molecular seal
(John Zink Company) is sometimes used in conjunction with purge gas. It
is installed within the flare stack immediately below the flare tip and
acts as a gas trap by preventing the lighter-than-air gas from bleeding
out of the system and being displaced with air. A cross-section of a flare
stack and seal is shown in Attachment 14-13.
The preferred method of inspirating air is to inject steam either in-
to the stack or into the combustion zone. Where there is an abundant sup-
ply, water has sometimes been used in ground flares. There is, however,
less assurance of complete combustion when water is used, because the
flare is limited in its operation by the type and composition of gases it
can handle efficiently.
The diameter of the flare stack depends upon the expected emergency
gas flow rate and the permissible backpressure in the vapor relief mani-
fold system. The stack diameter is usually the same or greater than that
of the vapor header discharging to the stack, and should be the same dia-
meter as,or greater than, that of the burner section. The velocity of the
gas in the stack should be as high as possible to permit use of lower
14-15
-------
stack heights, promote turbulent flow with resultant improved combustion,
and prevent flashback. Stack gas velocity is limited to about 500 fps
in order to prevent extinction of the flame by blowout. A discharge
velocity of 300 to 400 fps,based upon pressure drop considerations,is the
optimum design figure for a patented flaro tip manufactured by the John
Zink Company. The nature of the gas determines optimum discharge velo-
city.
Three burner designs for elevated flares have been discussed—the
multisteam-jet, or Zink, and the Esso and Sinclair types. The choice of
burner is a matter of personal preference. The Zink burner provides more
efficient use of steam, which is important in a flare that is in constant
use. On the other hand, the simplicity, ease of maintenance, and large
capacity of the Esso burner might be important considerations in another
installation.
As previously mentioned, the amount of steam required for smokeless
combustion varies according to the maximum expected gas flow, the molecu-
lar weight, and the percent of unsaturated hydrocarbons in the gas. Data
for steam requirements for elevated flares are shown in Attachment 14-14.
Actual tests should be run on the various materials to be flared in order
to determine a suitable steam-to-hydrocarbon ratio. In the typical refi-
nery, the ratio of steam to hydrocarbon varies from 0.2 to 0.5 pounds of
steam per pound of hydrocarbon. The John Zink Company's recommendation
for their burner is 5 to 6 pounds per 1,000 cubic feet of a 30-molecular-
weight gas at a pressure drop of 0.65 psig.
Pilot Ignition System
The ignition of flare gases is normally accomplished with one of
14-16
-------
three pilot burners. A separate system must be provided for the igni-
tion of the pilot burner to safeguard against flame failure. In this sys-
tem, an easily ignited flame with stable combustion and low fuel usage
must be provided. In addition, the system must be protected from the
weather. To obtain the proper fuel-air-ratio for ignition in this sys-
tem, the two plug valves are opened and adjustments are made with the
globe valves, or pressure regulator valves. After the mixing, the fuel-
air mixture is lit in an ignition chamber by an automotive spark plug,con-
trolled by a momentary-contact switch. The ignition chamber is equipped
with a heavy Pyrex glass window through which both the spark and ignition
flame can be observed. The flame front travels through the ignitor pipe
to the top of the pilot burner. The mixing of fuel gas and air in the
supply lines is prevented by the use of double check valves in both the
fuel and air line. The collection of water in the ignitor tube can be pre-
vented by the installation of an automatic drain in the lower end of the
tube at the base of the flare. After the pilot burner has been lit, the
flame front generator is turned off by closing the plug cocks in the fuel
and air lines. This prevents the collection of condensate and the over-
heating of the ignitor tube.
On elevated flares, the pilot flame is usually not visible, and an
alarm system to indicate flame failure is desirable. This is usually
accomplished by installing thermocouples in the pilot burner flame. In
the event of flame failure, the temperature drops to a preset level, and
an alarm sounds.
Instrumentation and Control of Steam and Gas
For adequate prevention of smoke emission and possible violations of
14-17
-------
of air pollution regulations, an elevated, smokeless flare should be
equipped to provide steam automatically and in proportion to the emergency
gas flow.
Basically, the instrumentation required for a flare is a flow-sensing
element, such as a Pitot tube, and a flow transmitter that sends a signal
i
(usually pneumatic):';*<$-a ^control valve in the steam line. -.Although the
Pitot tube has been used extensively in flare systems, it is limited by
the minimum linear velocity required to produce a measurable velocity head.
Thus, small gas flows will not actuate the steam control valves. This
problem is usually overcome by installing a small bypass valve to permit
a constant flow of steam to the flame burner. Attachments 14-5 through
14-7 show the steam-flow proportioning systems.
References
1. American Petroleum Institute, Manual on Disposal of Refinery
Wastes, 5th Edition, Vol. II (1957).
2. Beychok, M., "Build a Flare for Under $5,000," Petroleum Process-
ing, Vol. 8, p. 1162-1163 (1953).
3. Cleveland, D. L., "Design and Operation of a Steam Inspirating
Flare," Paper presented to API, Division of Refining Midyear Meeting (May,
1952).
4. Decker, W. H., "Safe, Smokeless Combustion Features Waste Gas
Burner at Sinclare Refinery," Petroleum Processing, Vol. 5, p. 965-966
(September, 1950).
5. Hajek, J. D., and Ludwig, E. E., "How to Design Safe Flare Stacks
Parts I and II, Petroleum Engineering, Vol. 32, p. C-31-38 (1960).
6. Miller, P. D., et al., "The Design of Smokeless, Nonluminous
Flares," Paper presented to 21st API Division of Refining Midyear Meet-
ing (May, 1956).
14-18
-------
7. Smolen, W. H., "Smokeless Flare Stacks," Petroleum Processing,
Vol. 6, pp. 978-982 (Sept. 1951).
8. Smolen, W. H., "Design of Smokeless Flares," Paper presented at
17th API, Division of Refining Midyear Meeting (May 1952).
9. Reed, R. D., Furnace Operations, Second Edition, Gulf Publishing
Co., Houston (1976).
14-19
-------
Attachment 14-1, Typical Modern Refinery H>
TO HiRE STJCK
LIGHT ENDS CONDENSATE RECOVERY
Attachment 14-2, View of John Zink
Smokeless Flare Burner
(John Zink Company, Tulsa, Okla.
14-20
-------
PILOT
ASSEMBLY
STEAM
HEADER,
\
STEAM
DISTRIBUTION
RING
TIP SHELL
PLAN
STEAM JETS
DJFFUSER
STEAM HEADER
INTERNAL
STEAM
INJECTOR
TUBES
PILOT AND
MIXER
ENTER STEAM
JET
CONTINUOUS
MUFFLER
CENTER STE*
JET
Attachment 14-3, Detail of Flare
Tip Showing Internal Steam
Injection (John Zink Company,
Tulsa, Okla.)
ELEVATION
Attachment 14-4, Waste-Gas Flare System Using Multisteam-Jet Burner3
3-tn. SUIK RING
HIM COLLECTION SYSTEM
HYDROGEN REACTOR
DROPOUT
PETROCHEKICU
SISTEH
•
i
CITALYTIC CRICKING COKPRE
(
^ i
SSORS
f
?»
-------
Attachment 14-5, Waste-Gas Flare System Using Esso-Type Burner
3 !->» Hill tUMCIIS
•120° IM.li
MCSSUIt StNSOK
met FIOI
k ^
CH;_
Sltll FIOI
fU«C[ G1S
sot
mssune TIPS
• HIC" LCI »
i
'N».
D ,.,._.,..._ ..,41
FIME IIKESTOI
SEtl
OHK
j
^SIOITEO 1 1 1 SC>1
n"llD U 1
i
^,
Attachment 14-6, Water Seal Drum with Slotted Orifice
for Measuring Gas Flow to Flare
VENTED C1SES
SHU
C»S
U
i.
1
0=
»««£-U> <1IE*
/Cpk ViL
axcz
-in »OTO«
VE
.10 Fl»BE
J..
I- • ; in. ^y\
SLOT TIC
OIIIFICE
->n. KOTOt VtLVt
tNOO OUT VEISEl
SOI
SC»«»TO«
14-22
-------
Attachment 14-7, Diagram of Waste-
Gas Flare System Using a
Sinclair Burner
PU«
SECTION I >
fUVIIION
PROTECTINC SHROUO
ST£«» SUPPLY PIPES
FlUE IMESTEII
Attachment 14-8, Detail of Sinclair
Flare Burner, Plan and Elevation4
14-23
-------
Attachment 14-9, Typical Venturi Ground Flare,
Igniters Not Shown1
BUME* MIU
CIS TO Midi 1UBNEIS
STEEl CE«E«T.O«
REFMCTORY llll
Attachment 14-10, Typical Water-Spray-Type Ground Flare.
Six water sprays are shown. Two pilots and two
ignitors are recommended.
M
\
\,SPR*Y /
y PATTERNS^
sAj-m. 7y
x\LES y
BOTTLED GAS
VENTURI BURNER
DAS TO PILOT
IGNITOR TUBE
OIL TO PILOT
WMER SUPPLY
HATER STRAINERS
14-24
-------
Attachment 14-11, Flow Diagram of Multijet-Flare System
JETS-
STICK SHELl
SECOND-SHOE -C-l
BURNERS V]
sx, STEEl SHEU
Sjj • REFRICTORY
3 It DIMETER I 10 ft NICN
Attachment 14-12, Vertical,
Venturi-Type Flare
14-25
-------
Attachment 14-13, John Zink
Molecular Seal (John Zink
Company, Tulsa, Okla.}
Attachment 14-14, Steam Requirements for Smokeless Burning
of Unsaturated Hydrocarbon Vapor1
I
NJ
cn
IWMO
MAM
SEM.MG CAP
fl«St 1IPMUKI Ft««C£
20
40 50 60
UNSIIUAUES. Of >(i|hl
10
90
100
-------
APPENDIX 14-1
FLARE COMBUSTION
Leonard C. Mandell, P.E.*
I INTRODUCTION
"Flare Combustion" is a highly-specialized
type of unsteady state, exposed-flame-
burning into the free atmosphere.
It has been developed mainly by and for the
Petroleum Industry. Flares provide a means
of safe disposal whenever it is impractical
to recover large and/or rapid releases of
combustible or toxic gases/vapors. These
releases may occur under emergency con-
ditions resulting from power or compressor
failures, fires or other equipment break-
downs; or under day-to-day routine conditions
of equipment purging, maintenance and
repair, pressure-relieving and other un-
wanted accumulations - - - - such disposal
being compatible with the public health and
welfare. Flaring has become more of a
safety or emergency measure. Combustible
releases with heat contents as high as
4, 000, 000, 000 Btu/Hr. have been
successfully flared.
Flares must burn without smoke, without
excessive noise, or radiant heat. They
should have a wide capacity to handle vary-
ing gas-rates and Btu contents. Positive
pilot ignition and good flame stability during
adverse weather conditions are also
necessary.
Typical gases that can be successfully flared
range from the simple hydrocarbon alkanes
through the olefins, acetylenes, aromatics,
napthenes, as well as such inorganic gases
as anhydrous ammonia, carbon monoxide,
hydrogen, and hydrogen sulfide — - — in
fact, almost any combustible gas - - if
feasibility so indicates.
Air Pollution can result from flare combus-
tion. As we realize, pollution implies an
adverse ecological situation. Air being
man's universal and most vital environment
makes the control of air pollution a major
responsibility of The Public Health
Profession.
A survey would indicate that air pollution
means different things to people. However,
all of these meanings can be placed in one
of three categories, namely:
A. Adverse effects upon our health
B Nuisance irritation to our basic senses
C Economic loss
These affects may occur singularly or in
various combinations with each other.
Experience has shown that the slightest
unwanted change in the air causes great
consternation among people. We have
become accustomed to expect certain things
from the air: that is, odorless, tasteless,
and invisible - that it should be neutral
in regard to its physical and bio-chemical
effects. Further, air is expected to fulfill
certain requirements that relate to our
well-being and enjoyment, namely:
When respired, air will effect the
metabolic needs for our activities without
adverse physiological consequences of
either an acute or chronic nature.
That air not be offensive to our basic
senses of hearing, seeing, feeling,
tasting or smelling.
That air not cause damage to our property,
be it buildings, furniture, automobiles,
livestock, vegetation, or other physical
or animal assets - all of which would
result in economic loss.
Accordingly, anything that modifies the
nature of air as we have learned to know
and enjoy it, may be called an Air Pollutant.
Flares may rightly be classed as significant,
potential sources of local pollution because
they can emit gases that are not only toxic
but that can cause property damage, person-
al injury, nuisance and psychosomatic illness.
*Consulting Engineer, Leonard C. Mandell Associates,
66 Pitman Street, Providence, Rhode Island.
PA.C. ce. 38. 1.67 14-27
-------
Flare Combustion
Toxiuity may evolve from the nature of
the raw vent gases - as the highly
dangerous carbonyl chlorides and phthalic
anhydrides, chlorine, hydrogen cyanide
--or from products of incomplete incom-
bustion as phenols, aldehydes, organic
acids, or from products of complete
combustion as sulfur oxides and hydro-
chloric acid vapors.
Property damage may vary from being
rather apparent as soiling from soot/smoke
or heat-damage from radiant flames; or
more subtle as from corrosive damage of
sulfur trioxide, mist-size aerosols.
Personal injury may occur from falling
and burning liquid aerosols that somehow
should not have arrived at the burner-tip
for flaring.
The nuisance aspect is excellently brought
out by the odor problem from say hydrogen
sulfide or the organic mercaptans. It
should be noted that noise is also becom-
ing a problem -- especially with high,
specific steam ratios.
The psychosomatic aspect can be involved
with ones knowledge of just the presence
of the flare, (in his effective environment)
whether it is creating an invisible-plume
or a smokey, sunlight obscuring plume.
Hence, it behooves the "operators" to
minimize these effects — any of which can
cause not only poor community relations but
even costly litigation. It has been the author's
experience that, as a rule, industry is
desirous of being a good neighbor and will
do the right thing if shown the need and if
properly handled.
II BASIC THERMODYNAMICS
It should be noted that very few if any text-
books on combustion or thermodynamics con-
tain any information on flares -- not
withstanding the fact that successful flare-
burning is a highly-specialized thermodynamic,
combustion process. Perhaps, the reasons
are that the universal need for flares is
relatively very small and what information
has been learned is treated as proprietary -
and so kept confidential for business reasons.
El COMBUSTION - In General:
Any combustion gas can be completely
oxidized if exposed to an adequately high
temperature level for a long period of
time in an atmosphere of sufficient oxygen
and turbulence.
For purposes of this lecture let us look at
combustion as a continuous, highly-complex,
high-temperature, gas-phase oxidation
process with very specific characteristics,
namely:
A It involves a very rapid chemical reaction
between the elements and compounds of
hydrogen, carbon and sulfur and the
oxygen in the air.
B That this reaction in order to be rapid
enough requires fuel/air mixture temper-
atures much higher than the conventional
ambient of 70°F, and within definite
ranges of concentrations for various
combustible compounds.
C That concurrent heat energy will for the
most part be liberated and/or occasionally
be required by the reaction to maintain
its continuity. The common oxidation
reactions of carbon, hydrogen and sulfur
are exothermic liberating 14, 500 BTU'S
and 4000 BTU'S per Ib. solid of carbon and
sulfur, and 61, OOOBTU'S/lb. of gaseous
hydrogen respectively.
The water-gas reactions of:
1 C + H2 O -- CO + H2
These reactions
are quite rapid
2 C + 2H20~C02 + 2H2 ^temperatures
^ " ^ greater than
1650°F.
require heat inputs of approximately
5900-6000 BTU/lb. carbon.
14^28
-------
Flare Combustion
That the combustion process requires
close control of adequacy and intimacy of
contact between the gas fuel and the
oxygen molecules in order to obtain
complete combustion; otherwise undesir-
able pollutants such as soot, smoke,
aldehydes and carbon monoxide, etc. will
be formed.
That the reaction occurs with presence
of a luminous flame. Certain Basic
Concepts must be understood:
L. E. L. or Lower Explosive Limit or
lower inflammable limit This is the
leanest mixture (minimum concentration)
of the gas-in-air which will support
combustion (where flame propagation
occurs on contact with an ignition source).
U.E. L. or Upper Explosive Limit: This
is the richest (Maximum proportion) of
the gas in air which will propagate a
flame.
Autogenous Ignition Temperature or
Auto Ignition Temperature: The minimum
temperature at which combustion can be
initiated:
It is not a property of the fuel but of the
fuel/air system. It occurs when the rate
of heat gain from the reaction is greater
than the rate of heat loss so that self-
sustained combustion occurs.
Flame Propagation - The speed at which
a flame will spread through a combustible
gas-air mixture from its ignition source,
it is usually lower at L. E. L. and the
U. E. L., and higher at the middle of
range.
Flame: A mass of intensely, heated
gas in a state of combustion whose
luminosity is due to the presence of
unconsumed, incandescent, fractional-
sized, particles - mainly carbon. (Small
particles of suspended carbon/ soot formed
by cracking of hydrocarbons). Visibility
ceases at complete combustion or where
the glow of the ash ceases.
Infra Red Radiation: Is, for the most
part an invisible, electromagnetic
phenomena. Relatively large amounts
of heat are radiated at elevated tempera^
tures. by such gases as carbon dioxide,
water vapor, sulfur trioxide, and hydro-
gen chloride. The I. R. spectrum begins
at 0.1 micron wave length and extends up
to 100 microns. For reference, I. R.
solar radiation (10, 240°F) lies within
the 0.1 to 3 micron range. (We know
that a large proportion is emitted in the
visible band of 0. 4 to 0. 8 micron. A
2300°F black body emits most of its
energy between 0. 7 and 40 microns. For
the discussion at hand, (temps between
1500 and 2500°F) radiant emission may
be assumed between 0. 5 micron and 50
microns with maximum intensity occur -
ring at the 2 micron wave-length.
Timing is important in that the attainment
of satisfactory combustion requires
sufficient, high-ambient, reaction
temperatures, and an adequate oxygen-
fuel mixing. Both phenomena are related
to time/probability functions.
W BASIC COMBUSTION CONCEPTS AS
APPLIED TO FLARES:
A Gaseous fuels alone are flared because
they:
• Burn rapidly with very low percentage
of excess air resulting in high flame
temperatures.
Leave little or no ash residue.
Are adaptable to automatic control.
B The natural tendency of most combustible
gases when flared is smoke:
An important parameter is the H/C ratio.
Experience has shown that with hydro-
carbon gases such as: Acetylene (C2H2)
with a H/C ratio = 0. 083, real black
soot will result from simple burning.
Propane (CaHg) with a H/C ratio = 0. 22
creates black smoke.
14-29
-------
Flare Combustion
Ethane (C2HG> with a H/C = 0. 25 - a
bright yellow flame with light trailing
smoke will result. A H/C of 0. 28 gives
very little if any smoke, and methane
(CH4) with a H/C of 0. 33 gives a bright
yellow flame with no smoke.
If the H/C is less than 0. 28, then steam-
injection close to the point of ignition into
the flame makes the flare smokeless. It
should be noted that steam injection can be
applied to the point of clearing up the
smoke and reducing luminosity before
reaching the point of extinguishing the
flame. Hydrogen is the cleanest, most
rapid and highest-heat evolving fuel
component. It helps to: heat the carbon
and also provides for better carbon/oxygen
contact which results in cleaner burning;
also, the reaction of carbon monoxide to
carbon dioxide goes much easier in the
presence of water vapor.
In flare burning of sulfur-bearing com-
pounds: approximately 90% or more
appears as sulfur dioxide and 10-30% of
the (SO2) mutually appears as sulfur
trioxide. Blue grey smoke becomes
visible as the sulfur trioxide falls below
its dew point temperature.
In flare burning of chlorine-bear ing
compounds, most will appear as hydrogen
chloride vapor. However, appreciable
quantities of chlorine will remain.
A relation exists between the auto-ignition
temperature of the gas, its calorific
value and its ease of successful flare
burning.
At 800°F AIT: A minimum H. V.
200 BTU/cu. ft. is required.
of
At 1.150°F AIT: A minimum H. V. of
350 BTU/ cu. ft. is required.
At 1300°F AIT: A minimum H. V.
500 BTU/cu. ft. is required.
of
H
complete burning is required regardless
of the weather; pilots are used to initiate
ignition of the flare gas mixtures, -- and
to help maintain flame temperatures to
attain rapid burning.
Yellow-flame combustion results from
the cracking of the hydrocarbon gases that
evolve incandescent carbon due to inade-
quate mixing of fuel and air. - Some flames
can extend to several hundred feet in
length.
Blue-flame combustion occurs when water
(steam) is injected properly to alter the
unburnt carbon.
I Actual Flare Burning Experience (John
Zink Company)
(Dilution/ Temperature Effects for
acetylene in air)
C2H2 @1800°F temperature will burn com-
pletely in 0. Oil sec -- 50% Dilution
C2H2 @ 1800°F temperature will burn com-
pletely in . 016 sec. — 75% Dilution
C2H2 @ 1800°F temperature will burn
completely in . 034 sec --90% Dilution
C2H2 @ 1800°F temperature will burn com-
pletely in . 079 sec --95% Dilution
Since the heat content of many gases vary
much below 100 BTU/cu. ft. and since
@ 1800°F temperature will burn com-
pletely in 1. 09 sec --99% Dilution
C2H2 @ 1800°F temperature will burn com-
pletely in 4. 08 sec --99. 5% Dilution
Note: The 4.08 sec. time @ 1800°F falls to
less than 1 sec. @ 2000°F temperature.
J Flared gases must be kept at temperatures
equal to or greater than auto ignition
temperature until combustion is complete.
K Carbon monoxide burns rapidly with high
heat and flame temperature, whereas
carbon burns relatively slow.
14-30
-------
Flare Combustion
L A smokeless flare results when an ade-
quate amount of air is mixed sufficiently
with fuel HO that it burns completely be-
fore side reactions cause smoke.
What is Required? Premixing of air+ fuel
Inspiration of excess air into the
combustion zone
Turbulence (mixing) and time
Introduction of steam: to react with
the fuel to form oxygenated compounds
that burn readily at relatively lower
temperatures; retards polymerization;
and inspirates excess-air into the
flare.
Note: 1) Steam also reduces the length of
an untreated or smokey flare by
approximately 1/3 of its length.
2) With just enough steam to eliminate
trailing smoke, the flame is usually
orange. More and more steam
eliminates the smoke and decreases
the luminosity of the flame to yellow
to nearly white. This flame appears
blue at night.
M The luminosity of a flare can be greatly
reduced by using say 150% of steam
required for smokeless operation. Since
a major portion of flame originates from
contained incandescent carbon.
N Water sprays, although effective in low-
profile, ground-flares, have not been
effective to date in elevated flares. The
water although finely atomized, passes out
and away from the flame without vaporiz-
ing or intimately mixing with burning
gases -- especially where any kind of wind
occurs. The plugging of spray nozzles
is also a problem - the "Rain" from
spray that may fall near base of stack
is very corrosive.
Note: Recent water shortages dictate the use
of steam since specific water wastes of
1-2 Ibs. water/lb. of gas is customary.
Approximately 2-3 times as much
water as steam is needed for ground-
level flaring.
O The following table summarizes some
pertinent gas characteristics for flaring.
GAS PROPERTIES RE-FLARING
Element/
Compound
H2
C2H2
NH3
H2S
CO
C3H8
CH4
HCN
C
S
C2H4
C4H6
Mol.
Wt.
2
26
17
34
28
44
16
28
54
H/C AIT
1000-1100°F
.083 600- 800°F
1200
550- 700
1200
.222 1000-1100
.33
1000
750°
470°
. 17
. 13
I0 by Vol.
LEL
4.1
2.5
16
4.3
12.5
2. 1
5.3
3
2
in Air"
UEL
74
80
27
46
74
11.4
14.0
29
11.5
Btu/ cu.
ft.. Net
275
1435
365
590
321
2360
914
1512
2840
Flame Flame
Temp-°F Speed
4100°F l-16'/Sec,
4200 2-5
4200 1-4
3800 .8-2.2
14-31
-------
Flare Combustion
V TYPES OF FLARES:
Flares are arbitrarily classed by the elevation
at which the burning occurs; i.e. -- The
elevated-flare, the ground-flare and the-Pit.
Each has its pros and cons. As should be
expected, the least expensive flare will
normally be used to do the required job-
compatible with the safety/welfare of the
Company and the Public.
A The Pit: The venturi type is, as a rule,
the least expensive. It can handle large
quantities such as 14,000 cfm or
20, 000, 000 cu. ft. /day. It consists of
one or more banks of burners set hori-
zontally in a concrete/refractory wall.
The other three-sides are earth-banks
approximately 4 ft. high. The typical
ground-area may be approximately
30 ft X 40 ft. The pit excavation may be
C ft. deep, all burners discharge hori-
zontally. The burners may vary from the
simple orifice to the better venturi -
aspirating units with pressure-valve re-
gulation. Piping and appurtenances include
proper pitch, knock-out drums, liquid
seals, and constant-burning, stable pilots.
As a rule, burning pits are the least
satisfactory but also are least expensive.
However, if location and air pollution are
not significant, the pit method becomes
attractive.
Note: Rothschild Oil built a 2, 000, 000 Scfd
(standard cubic feet per day unit) in 1953
for $5,000.00.
B Ground Flares: In general, ground flares
require approximately 2'/j times as much
steam to be smokeless as elevated flares.
They also require much more ground
space. At least a 500 feet radius should
be allowed all around the flare. In addi-
tion to the burner and combustion
auxiliaries, ground flares also require a
ground-shield for draft control and at
times a radiant shield for heat and fire
protection. Hence, large open areas are
needed for fire-safety (plenty of real-
estate) and air pollution attenuation.
Ground flares do however offer the ad-
vantages of less public visibility and easier
burner maintenance. The cost of present-
day, ground flares as a rule are more
expensive than elevated flares. However,
they may also cost less depending upon
location requirements. Ground flares are
normally designed for relatively small
volumes, with a maximum smokeless
operation up to approximately 100, 000
standard cubic feet per hour of butane
or equivalent. There is heat sterilization
of areas out to a radius of approximately
100 ft. At least 3 types are known to the
author; the Esso multi-jet smokeless
and Non-Luminous Flare, the conventional
center nozzle with spray water for inspira-
tion of combustion-air; and the dry-type
for clean burning gases.
Typical water spray flare-design
requirements are;
The spray must intimately mix with
the burning gases
These gases require an outer shell to
retain heat and flame.
Combustion air of at least 150% must
be allowed to enter the base through
the surrounding shells. The higher the
molecular weight of the gas, the
greater the spray rate: Example:
200, 000 Scfhr. M. wt. r 28
200, 000 Scfhr. M. wt. = 37
30-40 psig.
@35 gpm.
is required.
120 psig.@
80 gpm.
is required.
Back in 1959, Esso Research developed
the Multi-Jet Flare. It operates in a
smokeless and non-luminous manner
with very little noise. The flare requires
little of the conventional auxiliaries. It
consisted of a series of rows of horizontal
pipes containing 1 inch diameter jets that
served as burners. These burners were
located at the base of the stack approxi-
mately 2 ft. above ground level. The jets
require flame-holders (rods) to provide
time and turbulence for adequate air-mixing
14-32
-------
Flare Combustion
for smokeless combustion. A 32 ft. high
(.stack was required to shield the flame.
A 3 ft. diameter flare handled up to
140, 000 standard cubic feet per day and
a 6 ft. diameter stack up to 600, 000 Scf/
day. It operated with a 25 ft. high flame.
A cost comparison with other flares
types at that time was made: - Based on
12, 000, 000 Scf/day of a 40 Mol. wt. gas,
the multi-jet cost $148,000. This was
twice the cost of an elevated flare without
steam, or one half the cost of an elevated
flare with steam. This was also about
the same cost as a ground-flare with
water.
C Elevated Flares:
This type of flare provides the advantages
of desirable location in associated
equipment-areas with greater fire and
heat safety: also considerable diffusion/
dilution of stack concentrations occur
before the plume-gases reach ground
level.
Major disadvantages are:
1 Noise problems result if too much
steam is used
2 Air vibrations severe enough to rattle
windows 1/2 mile or more away.
There are 3 general types:
The non-smokeless flare which is
recommended for relatively clean,
open-air, burning gases such as hydro-
gen, hydrogen sulfide, carbon monoxide,
methane, and ammonia.
The smokeless flare which incorporates
steam injection to obtain clean burning
of low H/C ratio gases such as
acetylene, propylene, and butadiene.
The endothermic type which incorporates
auxiliary means of adding heat energy
to the vent gases of low heat contents
in the 50-100 BTU/cu. ft.). This flare
may or may not operate smokelessly.
Elevated flares require special burner
tips, special pilots and igniters, wind
screens, refractory lining, and instru-
mentation— for acceptable performances.
Let us take a moment and review what
happens at the flare-tip.
HAPPENINGS AT THE FLARE TIP:
2 ROWS OF
SUBORDINATE PORTS
FLARED GASES
TO ATMOSPHERE
PILOT TIP
STEAM JETS
STEAM
MANIFOLD
SUPPLY
RISER
COOLING
AIR-UP
I FLAME FRONT
IGNITER-TIP
IGNITER
•-TUBE
PRE-MIXED
PILOT
GAS-AIR MIXTURE
DIAMETER SIZE OF FLARE
14-33
-------
Flare Combustion
Gas is ignited just as it reaches the top
of the stack. Before adequate oxygen/fuel
mixing can occur throughout the entire
gas profile certain things occur:
Part of the gas burns immediately
resulting in an oxygen deficiency which
induces carbon-formation.
The unburned-gases crack to form
smaller olefins and paraffins; and at
the same time some molecules poly-
merize to longer chain hydrocarbons.
More carbon is created from combus-
tion of these newly formed compounds
in a reducing atmosphere.
The long, luminous-flame in ordinary
flaring is made up of incandescent,
carbon particles which form smoke
upon cooling. Steam-mixing suppresses
carbon formation by.
a) Separating the hydrocarbon mole-
cules, thereby minimizing
polymerization.
b) Simultaneously forming oxygenated
compounds which burn at a reduced
rate / temperature not conducive to
cracking/polymerization.
Note: The absence of incandescent carbon
also gives the appearance of a shorter
flame.
That the idea of injecting water/steam
into flares originated at Esso Refinery
in Everett, Massachusetts.
VI TYPICAL DESIGN CONSIDERATIONS AND
PARAMETERS
A Ignition and stable-burning must be
insured.
B Capacity must handle the maximum
expected quantity if toxic, or a statistical
compromise of the maximum expected
release. This may indicate normal
operation of 1-5% of these capacities.
C Pilots must be stable in high winds (80 mph)
and heavy rains.
D Pilots must be ignitable in high winds
(80 mph) and heavy rains.
E The height of the flare is determined
by fire and heat safety. Dilution may
also be important from an air pollution
standpoint.
F Steam requirements are related to the
H/C ratio (wt.). For H/C ratios greater
than 0. 33 - no steam is needed. Lower
ratios can demand up to 2 Ibs. steam/lb.
of vent-gas to obtain smokeless operation.
As a rule, 0. 6 Ib/lb. appears to be the
average required. Steam requirements
are proportional to the degree of
unsaturation and the molecular weight
of the gas being flared. Flares are
designed to be smokeless for up to 15%
of capacity only.
G Sizes may vary from lj inch pipe to
120 inch diameter.
H The burning rate can vary from 0. 5% -
100% of design.
I Systems up to 1, 000, 000 Ib/hr. of 43 mol.
wt. @ 700°F have been flared. (Zink)
J Typical data for hydrogen sulfide flares
would appear as follows:
14-34
-------
Flare Combustion
DATA
Ibs/hr:
cfm
cfday
flare size
cost installed
type
steam
flame dimensions
Ht. above ground
to negate heat
effects from flame
SIZE OF FLAME
600 Ibs/hr.
112 cfm
164,000 of day
2 inch diameter
$2300
non smoking
no1
10 ft. ht. X 1 ft. diam.
50 inch*
10, 000 Ibs/hr
1900 cfm
2,750, 000 cf day
12 inch diameter
$5800
non smoking
no1
40 ft. long X 3 ft. diam.
85 inch*
May be much higher for air pollution control.
K It should be noted that radiant, flame
effects can be serious. Radiation and
solar heating should not exceed 1000
BTU/HrJSq. Ft. at ground level with
700 BTU/Hr./Sq. Ft. from the flame and
300 from the sun. (Zink)
L The igniters operates only to start the
pilot. The pilot burns continuously. A
2-3 inch diameter flare requires one pilot.
A 4- 6 inch diameter flare requires two
pilots and flares greater than 6 inch dia-
meter requires three pilots.
M Auxiliary heat is needed for gases with
lower heating values of from 50-100 BTU/
cu. ft.
N Flare heights range from 25-375 ft. with
flame radiation being the determining
factor.
0 Hydrogen, carbon monoxide, and ammonia
burn smokelessly without assistance.
P Tendency for smoking begins at H/C of
0. 25 and becomes heavy @H/C of 0. 20.
Q In general, flare operation of gases less
than 150 BTU/cu. ft. heat content becomes
quite critical in point of maintenance
of ignition in all-weather conditions.
Here endothermic design is needed. Only
very few are in use. Usually they are
limited by economics to sizes less than
5, 000, 000 BTU/hr equivalent of
auxiliary fuel.
R Steam may also be required for preheating
in very cold areas -- besides being
needed for smoke control.
AUXILIARIES REQUIRED FOR SUCCESS-
FUL FLARE OPERATIONS:
A Flare Tips of Inconel or other stainless
alloys with steam jets, air cooling,
stabilizing parts, etc.
B Igniters are used to light the pilot at
start-up or at Pilot flame failure.
C Pilot Burners to light flare and keep it
lit
D Mist Trap: to remove fine, liquid aerosols
from reaching the stack.
E Flame arrestor: to prevent flame- travel
back into piping.
F Liquid seal: To reduce pulsations from
surges: to prevent air from entering
vent- gas lines: to prevent reverse-flame,
flash-back.
G Flow Sensors for steam control
H Pilot flame detectors
I Auto reignition system for pilots
14-35
-------
Flare Combustion
J Shrouds are not of real value in smoke
control, however, they can be used in
preventing downwash.
Note: The pilots initiate combustion of the
flared gases. They also help to heat
and maintain name temps. The ig-
nition system consists of premixed
15 psig. fuel gas/^ir mixture that is
pre-ignited in a special in-line, pipe-
chamber by a spark plug. The flame-
front, under How-pressure, travels
through a 1 inch igniter pipe to the
tip of the pilot burner. Once the pilot
is ignited, the fuel and air valves are
closed. Time for ignition of all 3
pilots averages 1-2 minutes. Pilots
must burn at a rate of at least
30, 000 BTU/hr. each.
VIE MATERIALS OF CONSTRUCTION:
Reflection will indicate that many flare-gases
are corrosive at normal atmosphere temper-
atures. Chemical activity, as a rule,
increases with increasing temperatures.
Hence, the selection of suitable materials
for the handling/conveying of these gases
— especially at the flare-tip becomes signi-
ficant to the feasibleness of this particular
method of combustible, gas disposal.
It should be remembered that metals or
alloys provide the function of corrosion-
resistance by either formation of a surface
film or resistance to chemical activity with
the environmental materials. Accordingly,
other corrosive factors as gas velocity, •
thermal shock and catalytic influences must
be considered in addition to temperature
effects. Another practical consideration
is the deleterious carbide precipitation that
results from the welding process. It removes
some of the corrosion resistant and strength
constituents from the alloy.
The stainless-steel, iron alloys (approxi-
mately 74% steel) are at present, the most
feasible metals for flare construction. The
stainless steels compose a class of nickel
and chrominum alloys that owe their
corrosion resistance to the high metal content
and the strength to the chromium. Tenacious.
protective film develops ----- especially
in oxidizing atmosphere. Typical stainless
compositions are:
ALLOY
Cr
TYPICAL STAINLESS STEEL ALLOYS
% Ni % C % Mo % Si
% Mu
Co
304
316
347
430
Hastelloy
18-20
16-18
17-19
14-18
's X
8-10
10-14
9-12
X
. 08 max.
.10 2-3
.10
.12
X
.75
.75
.75
.75
max.
max.
max.
max.
2.
2.
2.
0.
0
0
0
max.
max.
max.
1. 0% max.
50
Inconel
(6% Fe)
10
84
14-36
-------
Flare Combustion
Leading suppliers of special stainless steels
are International Nickel Company; Haynes
Stellite, Division of Union Carbide; Carpenter
Steels, etc.
Experience has shown that:
Typej304 s. steel is satisfactory for
1600°F -sulfur exposure
Type 309 s. steel is satisfactory for
2000°F -sulfur exposure
Incon'el - a high heat resistant alloy for
hydrogen sulfide, but not sat-
isfactory for hydrogen chloride,
sulfur dioxide or sulfuric acid
vapors.
Hastelloy - (special s. steel) manufac-
tured by Haynes Stellite is
good for SO3, H2SO4 and Hcl.
Hastelloy B for chlorine resistance,
H2SO4
Hastelloy A for Hcl, H2S, SO3, H2SO4
Type 430 is suitable for general use up
to 1600°F
In the final analysis of material selection,
the cost of replacement must be carefully
weighed against the longer life and higher
initial cost of the most resistant materials.
REFERENCES
1 American Petroleum Institute, N. Y.
Manual on Disposal of Refinery Wastes,
Volume II Waste Gases and Particulate
Matter, 1957.
2 Reed, Robert D. John Fink Co., Tulsa,
Oklahoma, Private Communications,
1966.
3 Smith, Richard H. J. Arthur Moore Co.,
N. Y. C., Private Communications.
1966.
4 The Various Petroleum Companies, (such
as Shell, Esso, Gulf) Research and
Engineering Departments.
5 Petroleum Processing Journals.
14-37
-------
CHAPTER 15
COMBUSTION OF HAZARDOUS WASTES
Government, industry, and environmental groups have become increas-
ingly aware of the need for environmentally acceptable ways of treating
and disposing of industrial wastes in general and hazardous wastes in par-
ticular. Incineration provides one possible method to dispose of a
large number of combustible waste materials.
Among the advantages of using incineration for waste disposal are:
. Combustion technology is reasonably well developed.
• Incineration is applicable to most organic wastes
• Heating value of combustible wastes may be recoverable
• Large volumes can be handled
• Large land area is not required
There are, of course, some disadvantages as well:
• Requires costly equipment which may be complicated to operate
• May require auxiliary energy
Not always the ultimate disposal — solid residue (ash) may be
toxic
• Combustion products may be pollutants which are hazardous to
health or damaging to property
The decision on whether or not to use incineration will depend on its
environmental adequacy and total costs, in comparison with other disposal
options.
15-1
-------
Many types of incinerators have been used for thermal destruction
of hazardous materials. These include rotary kilns, multiple-hearth in-
cinerators, liquid-injection incinerators, fluidized beds, molten salt
devices, wet oxidation, plasma destructors, multiple-chamber incinerators,
gas combustors, and pyrolysis units. The operation and capabilities of
these devices has been summarized (1), based primarily on the TRW Systems,
Inc. report entitled "Recommended Methods of Reduction, Neutralization,
Recovery, and Disposal of Hazardous Waste" (2), where some results on
incineration of specific materials are presented as well.
Knowledge of specific incineration criteria for individual wastes
is still very limited. Generally speaking, only organic materials are can-
didates for incineration, although some inorganics can be thermally de-
graded. Halogen-containing organics emit extremely corrosive hydrogen
halides necessitating careful selection of materials for construction and
scrubbing of emissions. Organic materials containing dangerous heavy
metals (such as Hg, As, Se, Pb, Cd) should not be incinerated unless the
emissions of the metal components into the environment are known to be harm-
less or can be controlled by pollution control equipment. SOX emissions
from sulfur-containing materials may need to be removed if present in appre-
ciable concentrations. NOX formation can be minimized by keeping incinera-
tion temperatures low — below about 2,000°F. The destruction ratio of a
given material by incineration depends to a large extent on the tempera-
ture and the dwell (residence) time at that temperature. Incinerators
burning hazardous wastes should be equipped with automatic feed cut-off
provisions in the event of either a flame-out or a reduction in reactor
temperature below that required for complete combustion.
15-2
-------
Halogenated and Sulfonated Materials
Chlorinated and sulfonated solvents can be handled by incineration,
but this alone will not eliminate air pollution. Chlorinated hydrocar-
bons with hydrogen-to-chlorine ratios of at least 5:1 yield hydrogen
chloride; those hydrocarbons with ratios less than this are likely to
yield other chlorinated products which are difficult to collect. To avoid
the latter problem, excess natural gas or steam needs to be injected to
produce HC1, which will then have to be scrubbed from exhaust gases. Note
that flaring chlorine-containing substances is not an acceptable control
technique, and it is to be considered for emergencies only.
Scrubbing of incinerator exhaust can be accomplished by conventional
spray or packed-tower-type scrubbers, or by submerged combustion incinera-
tion (3) as shown in Attachment 15-1. Similar systems for liquid waste
disposal are discussed in References (4, 12). The scrubber liquor has to
be neutralized before disposal. Attachment 15-2 illustrates a water
quench and a scrubber combination for cleaning the incinerator exhaust
from halogenated liquid waste which was treated at 1,800°F for one sec-
ond (12). Water scrubbing will not be sufficient to eliminate SOjj pro-
duced by the incineration of sulfonated materials. Caustic solution or
lime slurry are used for this purpose.
Chlorinated and fluorinated plastics— such as PVC, Teflon, and
others — can present considerable disposal problems. Incinerations of
these materials or their gaseous monomers will release HC1 and HF, which
are not only serious pollutants, but also very, corrosive. Exhaust gas
cleaning is therefore required, usually by some type of scrubbing device.
15-3
-------
Pesticides and Toxic Wastes
Incineration, in addition to being used for volume reduction and
energy recovery, can be used to detoxify many organic materials if the
toxicity or the hazardous property is due to the chemical structure of the
molecule, rather than a property of the elements it contains. A large
number of compounds of nominal toxicity are thus amenable to thermal
destruction. Pesticides, which have been withdrawn from use or have be-
come obsolete, and components of hazardous industrial wastes fall into this
category. Thermal destruction of such materials is an extremely complex
process, and little is known about the mechanisms of this disposal tech-
nique.
However, the following general conclusions.can be drawn from the
experience gained so far with pesticide incineration (5, 6):
• Most pesticides can be destroyed by incineration with over 99.99%
of the active ingredient detoxified.
• The most important operating variables are temperature and reten-
tion time in the combustion chamber.
• Certain conventional incinerators have the potential for inciner-
ating pesticides if adequate retention times at the appropriate
temperatures can be obtained and emission control devices pro-
vided.
Residues left from the incineration of formulations with inert
binders and carriers, generally contain very low levels of pes-
ticides, e.g. less, than 20 ppm.
Incineration of organonitrogen pesticides can generate measur-
able quantities of cyanide (CN~) at temperatures tested (650 -
1,050°C).
15-4
-------
• Odor can be a potential operational problem, particularly with
organosulfur pesticide incineration.
Temperatures and retention (dwell) time requirements for pesticide
incineration are generally higher than for hydrocarbons in conventional
afterburners, as shown in Attachment 15-3 (5), Zone A represents operat-
ing conditions where less than 99.99% destruction may result, whereas con-
ditions in Zone B are anticipated to yield greater than 99.99% destruction.
In the operating zone, the acceptable range for excess air is estimated
at 80 to 160%.
Since smaller quantities of pesticides and other toxic materials will
inevitably escape any type of combustion and air pollution control system,
environmental considerations must be emphasized when pesticide incinera-
tors are sited and sized.
All types of incinerators are not compatible with disposal of all
classes of pesticides. While requirements for combustion of certain
classes of pesticides are readily achieved by many incinerators, other
classes require extreme conditions which necessitate custom designs with
sophisticated operating and monitoring programs.
The serious environmental contamination of a Kepone manufacturing
facility and its environs near Hopewell, Virginia have increased the
efforts to develop acceptable technologies for the disposal of un-
wanted pesticides and pesticide-contaminated solid wastes. Work on Kepone
has found it to be slightly more thermally stable than DDT (7). A com-
parison of the thermal destruction of several pesticides is shown in
Attachment 15-4. Any incineration requirements for Kepone should there-
fore, at a minimum, meet those for DDT, which have been established at
15-5
-------
1,000°C for two seconds (8). This could be accomplished in a system illus-
trated in Attachment 15-5 consisting of a rotary kiln pyrolyzer, followed
by a fume incinerator (afterburner) and a scrobber. Destruction effici-
encies in excess of 99.999% were achieved in such a device capable of
maximum feed rates of approximately 100 Ib/hr (7).
Incineration of PCB's
Polychlorinated biphenyls (PCB) are extremely stable and persistent
synthetic compounds which have been found to be dangerous to certain spe-
cies and ecosystems. Studies have been undertaken to establish the cri-
teria for thermal destruction of PCB's and related compounds (9). It was
found that PCB's are more stable thermally than Mirex— a very stable pes-
ticide, as shown in Attachment 15-4. When exposed to a very high tempera-
ture (1,000°C for one second in air), PCB destruction of greater than 99.995%
can be achieved. Under thermal stress, PCB's can decompose to lower mole-
cular weight products which were not identified in this study (9). Com-
pounds related to PCB's exhibit similar thermal destruction behavior as
PCB mixtures.
Waste Propellants, Explosives, and Pyrotechnics
Incineration appears, for the foreseeable future at least, to be the
primary acceptable destruction method for waste ordnance and propellants,
explosives, and pyrotechnics (PEP) materials. The method of feeding the
ordnance and PEP to an incinerator for disposal is very important for
safety reasons. In the batch process, an even layer of PEP is distributed
in the incinerator prior to disposal. The continuous feed method dilutes
the PEP materials with sand, sawdust, or water. The amount of feed and.
15-6
-------
the dilution ratio is limited by safety considerations.
A rotary kiln-type incinerator with fire-brick lining (Attachment 15-6)
has been used for disposal of PEP materials which do not detonate. Water
slurry of the explosive or propellant is prepared first. Incineration of
such a slurry has been found to be relatively safe. No. 2 fuel oil is
used as auxiliary fuel with incinerator fired to 1,600°F. The operating
control station is located underground at some distance from the kiln and
feed preparation area.
A rotary furnace is similar to the kiln, except that a heavy steel
drum is provided and the refractory lining is omitted, because it cannot
withstand the detonation of even small-caliber ordnance. Control of emis-
sions may be achieved with both of these devices, but is not always prac-
ticed.
Fluidized-bed incineration (Attachment 15-7) is another method for
munitions disposal. A novel feature of this system is that very low
levels of NOX emissions are possible by using less than stoichiometric
air (about 60% of theoretical) for fluidization where most of the com-
bustion takes place. The remainder of the theoretical air, along with
approximately 20% excess, is introduced near the top of the bed (10, 11).
Very little information is available on the pollutants arising from
PEP incineration. Small arms ammunition and pyrotechnic items are ex-
pected to give off gases, metallic fumes, vapors, and particulates com-
prised of metals and metallic compounds.* Carbon monoxide and nitrogen
oxides are the most objectionable of the gases, while combined or ele-
mental forms of cadmium, lead, chromium, mercury, silver, and antimony
are the most objectionable of the particulate matter.
15-7
-------
Summary
Incineration appears to be a serious contender as a means of disposing
of hazardous waste materials. There are no universally applicable incinera-
tion methods available for this purpose, however. Careful attention must
be paid to the physical and chemical properties of the specific waste
streams, as well as their combustion products. Rotary kilns (cement kilns)
may be used to dispose of toxic chemical wastes because their temperatures
are in excess of 2,500°F and they have long residence times. Gas cleaning
equipment must be added where gaseous products are not suitable for direct
discharge to the atmosphere. Safe and environmentally-acceptable disposal
of solid residues (ash) cannot be overlooked.
References
1. Scurlock, A. C., et al., "Incineration in Hazardous Waste Manage-
ment," SW-141, U. S. Environmental Protection Agency (1975).
2. "Recommended Methods of Reduction, Neutralization, Recovery, and
Disposal of Hazardous Waste," TRW Systems, Inc. (1973). Publication
No. PB 224-579, NTIS, Springfield, Va.
3. Ross, R. D., "Incineration of Solvent-Air Mixtures," Chem. Eng.
Progress, 6!3_, No. 8, 59-64 (1972).
4. Kiang, Y. H., "Liquid Waste Disposal System," Chem. Eng. Progress,
T±, No. 1 (1976).
5. "Determination of Incinerator Operating Conditions Necessary for
Safe Disposal of Pesticides," Report No. EPA-600/2-75-041 (December 1975).
6. "Summation of Conditions and Investigations for the Complete
Combustion of Organic Pesticides," Report No. EPA-600/2-75-044 (October
1975).
15-8
-------
7. Carries, R. A., "Combustion Characteristics of Hazardous Waste
Streams," USEPA/MERL/SHWRD, Paper No. 78-37.5, Cincinnati, Ohio
8. Kennedy, M. V., et al., "Chemical and Thermal Methods for Dis-
posal of Pesticides," Res. Rev., Vol. 29, 89-104 (1969).
9. "Laboratory Evaluation of High-Temperature Destruction of Poly-
chlorinated Biphenyls and Related Compounds," Report No. EPA-600/2-77-228
(December 1977).
10. Santos, J., et al., "Design Guide for Propellant and Explosive
Waste Incineration," Picatinny Arsenal, Technical Report 4577 (October
1973).
11. Kalfadelis, C. D., "Development of a Fluidized Bed Incinerator
for Explosives and Propellants," Esso Research and Engineering Co.,
Government Research Laboratory Report (October 1973).
12. "Liquid Waste Incinerator," Bulletin STD IN-72-1C, C & H Com-
bustion Co., Troy, Michigan
15-9
-------
Attachment 15-1, Submerged Combustion Incinerator
Chlorinated
Hydrocarbon
Combustion Air
Wstei
Auxiliary Fuel Gas
Entrainment
Separator
Submerged
combustion
incinerator.
15-10
-------
Attachment 15-2, Liquid Waste Incinerator"
ui
I
STACK
VENTURI SCRUBBER
INCINERATOR-
QUENCH
DEMISTER-
ID FAN-
-------
1200 r-
u
I
8
I
1
J
u
fc-
1000!
800
600
ZONE B
3 4
Retention Time, sec
Attachment 15-4, Comparison of Thermal Destruction of Kepone,
DDT, Mirex, and PCB's7'9
O
2QO 400 600 800
TEMPERATURE,°C
1000
15-12
-------
Attachment 15-5, Kepone Incineration Test System'
ui
M
CO
KEPONE
SOLUTION
KEPONE INJECTION
POINT
t
BURNER
AIR & FUEL
1
J
FUEL
SCRUBBER
SAMPLE
PORT
STACK
vBURNER
AIR
Note: Kiln temperature
was 900°F.
Afterburner temp.
was 2,300°F.
Afterburner residence
time was 2 sec.
DRAIN
-------
FUEL
WATER
ROTARY CYLIXIOER
Attachment 15-7, Fluidized Bed Incinerator
11
r i I
> Cyclone
1 I Separator I »
Solids
Receiver
Fluid Bed
Combustor
—*- Vent
To Flue-Gas
Analytical
Train
Feed
Electrical
Prehoater
Air Plenum
Chamber
Slgmanotor
Metering
Pump
15-14
-------
CHAPTER 16
NOX CONTROL THEORY
Background
Emission of nitrogen oxides has been a major air pollution concern
since the early 1950"s when Professor A. J. Haagen-Smit presented a theory
of photochemical smog (1). Although the photochemical reactions are not
simple, Professor Haagen-Smit was able to demonstrate that the conditions
necessary for smog to develop included bright sunshine into an unventilated
region containing nitrogen oxides and hydrocarbon contaminants in the air.
Photochemistry is the study of chemical reactions in the ambient air
which are influenced by the sun, air pollution sources, and meteorology.
Attachment 16-1 illustrates the transient behavior of measurable gases in
the Los Angeles air during a day having smog (2). One could predict the
changes of air pollution emissions and of solar intensity associated with
the time of day. Photochemists have performed many smog chamber experi-
ments (see Attachment 16-2) which have helped to refine their theories and
have led them to some important conclusions.
A brief and oversimplified set of photochemical equations for atmos-
pheric smog is presented in the Attachment 16-3. Note that in the first
equation a high-energy photon of solar energy is absorbed by N©2 causing
dissociation into NO and 0 (atomic oxygen). The formation of ozone and
other unstable, radical products give rise to the highly reactive, oxidant
character of smog.
16-1
-------
Emissions of NO require control because of photochemical participa-
A
tion in producing oxidants. Although very high concentrations of NOX may
be directly hazardous inside certain industrial facilities, ambient levels
are seldom within 5% of the direct health hazard threshold limit. Ambient
levels are of concern because of photochemical involvement.
Nitrogen oxides are produced by natural sources (volcanoes and forest
fires), as well as by man-made sources. Of the man-made NOx slightly more
than half.is from mobile, vehicular sources, and slightly less than half is
from stationary sources.
The distribution of NOV emissions from various stationary sources is
A
illustrated in Attachments 16-4. Utility boilers account for 42%, inter-
nal combustion engines provide 22%, industrial boilers contribute 18%, and
space heating is responsible for 9%.
Projections of future NOV emissions are dependent upon the future
A
energy supply, as well as the amount of NO., emission control which will be
applied in the future. Attachment 16-5 provides a set of projections which
does not assume considerably stricter NOX controls in the future. Because
of the potential growth in NOy emissions and the resulting photochemical
smog (ozone), NOX control is becoming a major regulatory concern.
NO emission factors for a large number of fuel and combustion equip-
A
ment combinations are tabulated in Attachment 16-6.
NOX Formation
•Hie dominant oxide of nitrogen which is formed in combustion pro-
cesses is NO. The NO will oxidize to NO2 fairly slowly in ambient
air, with only 5% typically being oxidized to NO- before leaving the
stack (except for gas turbine and diesel engines). Other oxides
16-2
-------
of nitrogen, such as N2O, nitrous oxide; N203, nitrogen trioxide; and
N2°5' nit10^611 pentoxide, are of minor consequence. All the nitrogen
oxides/ when referred to as a group are called NO...
Emissions of NO arise from two different methods of formation during
A
combustion. Thermal fixation of nitrogen ^.n the combustion air produces
the so-called "thermal NOX." The NOX produced by oxidation of the nitrogen
found in the chemical composition of the fuel is called "fuel NOX."
i
Formation of "Thermal NOX"
When ambient air is heated in a combustion chamber to a temperature
above 2800°F, part of the nitrogen and oxygen will combine to form NO. The
classical "Zeldovich" chemical model for NO formation assumes high tempera-
ture dissociation of oxygen molecules:
20
and nitrogen reactions:
0 + N2 + NO + N
N + 02 ^± NO + O.
A simplified model used for illustrative purposes is:
N2 * °2
where the NO formation is endothermic, i.e., energy is required rather than
produced. This simplified model provides the following equation for the
rate of production of NO:
16-3
-------
(N2) (02) - %(NO)2,
where (NO) , (N2) , and (02) represent the respective concentrations at
a particular instant of time, and where values of Kp and KR increase con-
siderably with temperature.
If the appropriate rate equation is set equal to zero, equilibrium
values of NO as a function of temperature may be computed. Typical equi-
librium values of NOjj concentration as a function of temperature are pre-
sented in Attachment 16-7. The calculation required assumed values for
KF and KR (the forward and reversed reaction rates, which increase greatly
with temperature) and also values for the N2 and O2 concentrations.
Formation of "Fuel
Nitrogen of differing amounts is contained in the chemical composi-
tion of fuels. Coal may contain nitrogen from 0.5 to 2.0% by weight,
whereas No. 6 fuel oil may contain from 0.1 to 0.5% and No. 2 contains
approximately 0 . 01% .
When fuel is burned, 10 to 60% of the nitrogen may be oxidized to
NO (5) . This fraction depends on the amount of oxygen available after the
fuel molecules decompose. If combustion zone is fuel rich, the fuel mole-
cules may crack and much of nitrogen will form N2. On the other hand, if
combustion zone is lean, that is, oxygen is available, more fuel nitrogen
oxidizes to NO.
High fuel volatility and intensive fuel/air mixing also increase the
fuel nitrogen fraction which oxidizes to NO.
Changing fuels can be an effective method for reducing NOX. For
example, one might change from a high nitrogen content No. 6 fuel oil to
16-4
-------
No. 2 fuel oil. If it is available, one might specify a low-nitrogen con-
tent No. 6 fuel oil. The nitrogen content is influenced by refining pro-
cesses, blending, and the original crude stock.
Changing from coal to oil or oil to gas usually is controlled by fac-
tors such as furnace adaptability, fuel availability, and costs. Because
of fuel availability, it is expected that more coal rather than less will
be used as boiler fuel in the future, so other techniques of fuel NOX con-
trol will be required.
NO Control Theory
X
The three methods for reducing NOjj are to change the fuel, to modify
the combustion system, and to treat or clean the flue gas.
Excess air reduction is an obvious combustion modification control tech-
nique, as may be seen from the simplified model of "thermal" NOy formation.
Excess air reduction is very effective for "fuel NOjj" because the reduced
availability of oxygen encourages fuel nitrogen to form molecular nitrogen
(5). Note that the high chemical reactivity of oxygen with fuel assures
that most of the theoretical oxygen will react with fuel. It is the excess
oxygen which reacts with nitrogen.
Limits on excess oxygen in coal and oil combustion is important, not
only for NOX control, but also to limit the conversion of SC>2 to SOg. The
formation of SOg causes dew point and corrosion problems in furnaces. Because
of this fact, oil-fired units, which formerly operated with excess air
values from 10 to 20% excess air (2 to 4%' excess 02), typically have been
modified to operate at 2 to 5% excess air (0.4 to 1% excess 02). In gas-
fired boilers, it appears that a minimum desirable value of excess ©2 exists
16-5
-------
for many units, as shown in Attachment 16-8. As the excess air is reduced
below this minimum, the temperature increases enough to increase the NO^
emissions (5). In coal combustion, burning with very low values of excess
oxygen may present operational problems.
NOx control has been achieved by designing for two-stage combustion,
as illustrated in Attachment 16-9. In the first stage fuel-rich combustion
occurs with less than stoichiometric oxygen. Energy is transferred to
heat exchange surfaces, and the combustion product gases move to the second
stage. Excess air is introduced (lean combustion in this stage), so that
adequate oxygen is available for complete combustion. NOX emissions are
reduced, partly because NO is not formed when the combustion is rich. The
other reason is because of the energy extraction prior to lean combustion,
which results in lower peak temperatures than would occur under normal com-
bustion. Two-stage combustion may be applied through use of overfire air
ports, as shown in Attachment 16-10, or through burner redesign. In each
case the fuel and air delivery to the combustion zone is designed to delay
the mixing of the secondary air.
As previously indicated, the other significant fundamental con-
c
cept in NOX control is to limit the maximum combustion temperature. This
effectively limits the value of the forward reaction rate coefficient, KF.
For temperatures above 2,800°F, the value of KF is said to essentially
double for each additional 70°F temperature increase.
One should note that in most combustion equipment, the combustion
reactions occur so quickly that equilibrium behavior associated with a
peak temperature is not achieved. Typically, less NO is formed than would
be expected for a given peak temperature. However, the combustion gases
16-6
-------
cool down so rapidly that the NO formed does not dissociate but is said to
"freeze" and be emitted with the flue gases.
One method for reducing the maximum combustion temperature is to elimi-
nate the development of "hot spots" in the combustion gases. These are
locations where very rapid mixing of fuel and air occur. By slowing the
mixing or swirl of gases, a more uniform flame temperature may result and
lower NOX will be formed.
The type of firing design of the furnace also influences the fuel/
air mixing, the proximity of the flames to the heat exchange surface, and
the influence of combustion energy from one burner on an adjacent burner.
Cyclone furnaces used for coal combustion have the largest uncontrolled
NOX emissions. Front wall (horizontal) and opposed wall furnaces have some-
what less, and tangential-fired furnaces have considerably less emissions,
as illustrated in Attachment 16-11.
Flue gas recirculation is a technique for lowering the peak tempera-
ture, as illustrated in Attachment 16-12. Flue gas acts as a heat sink.
It also acts to slow the rate of combustion, by reducing the frequency of
successful oxidation collisions between the fuel and oxygen molecules.
Proper heat exchange design is required to prevent a considerable loss of
efficiency due to the lower combustion temperatures.
Reducing the rate of combustion by reducing the fuel rate or load
also will reduce the peak temperatures and NOX emissions. The load reduc-
tion may be achieved by energy conservation (lower demand) or by install-
ing or using additional combustion units. The effect of load reduction
is shown in Attachmend 16-13.
16-7
-------
Scheduling frequent soot blowing will provide cleaner heat exchange
surfaces around the flame and thereby will limit the peak combustion tem-
perature .
Water injection, as shown in Attachment 16-14, is an accepted NOX
control technique for use in stationary gas turbines. Water acts as a heat
sink, similar to the water injection which was used in supercharged air-
craft engines in the 1940's (to provide controlled combustion with increased
power). Water injection in piston engines was terminated with the adoption
of tetraethyl-lead as a more convenient heat sink material.
Flue Gas Treatment
Dry flue gas treatment with gases from 100 to 700°F is used widely in
Japan for NOX control in oil and gas furnaces (7). This technique requires
a reducing atmosphere (typically with ammonia injection) and a catalyst.
Developmental work is underway to apply this concept to the particulate and
S0_-laden gas streams from coal combustion. If ammonia is injected as the
combustion gases reach the convection zone of a large boiler, up to 70%
NOx reduction can be demonstrated (5). However, the convection zone tem-
perature must be controlled carefully to around 1,300°F, as illustrated in
Attachment 16-15.
Wet flue gas techniques involve a strong oxidant, such as ozone or
chlorine dioxide to convert NO to NO- and ^0 for subsequent absorption by
a scrubbing solution. These scrubbers are operated at 100 to 120°F,
the same operating temperature for SOX scrubbers. This technique is very
expensive, because of the cost of chlorine dioxide and ozone, in addition to
the cost of disposing of the chlorine containing discharges. However, hope
16-8
-------
is expressed for the possibility of this technique being effective for con-
trolling NOX, SOX, and particulates from coal-fired power plants.
Fluidized Bed Combustion
A non-traditional combustion scheme is that of fluidized bed combus-
tion. It appears promising for future low NO^ applications, mainly because
combustion occurs with low temperatures and because SOX control can be
achieved also (5). Various fluidized bed applications are being demon-
strated, such as for:
1. Solid waste and sewage sludge incineration;
2. Hog fuel combustion;
3. Coal in a utility boiler (30 MW electricity by Monongahela Power
Co., Rivesville, West Virginia); and
4. Coal in a similar fired industrial boiler (100,000 Ib. steam/hr.
by Georgetown University, Alexandria, Va.).
References
1. Haagen-Smit, A. J., "Chemistry and Physiology of Los Angeles Smog,"
Ind. Eng. Chem., Vol. 44, p. 1423 (1952).
2. Seinfeld, J. H., Air Pollution, Physical and Chemical Fundamentals,
McGraw-Hill Book Co., New York (1975).
3. Strauss, Werner, Air Pollution Control, Part I, Wiley Interscience,
New York (1971).
4. Wark, K., and Werner, C. F., Air Pollution, Its Origin and Con-
trol, Harper and Row, Publishers, New York (1976).
16-9
-------
5. "Control Techniques for Nitrogen Oxide Emissions from Stationary
Sources," Second Edition, EPA-450/1-78-001, U. S. Environmental Protection
Agency (Jan. 1978).
6. "Reference Guideline for Industrial Boiler Manufacturers to
Control Pollution with Combustion Modification," EPA-600/8-77-003b, Indus-
trial Environmental Research Laboratory, U. S. Environmental Protection
Agency (Jan. 1977).
7. Muzio, L. J., et al., "Gas Phase Decomposition of Nitric Oxide
in Combustion Products," paper No. P-158, 16th Symposium (International)
on Combustion, Cambridge, Mass. (Aug. 15-21, 1976).
8. Sensenbaugh, J. D., "Formation and Control of Oxides of Nitrogen
in Combustion Processes," Unpublished paper, Combustion Engineering, Inc.,
Windsor, Conn. (1966).
9. Muzio, L. J., Arend, J. K., and Teixeira, D. P., "Gas Phase De-
composition of NOX in Combustion Products," Paper No. P-158, 16th Inter-
national Symposium on Combustion, Cambridge, MA (Aug. 15, 1976).
10. "Electric Utility Steam Generating Units — Background Information
for Proposed NOX Emission Standards," EPA-450/2-78-005a, Office of Air
Quality Planning and Standards, U.S.E.P.A., Research Triangle Park, NC
(July 1978).
16-10
-------
Attachment 16-1, Concentrations of Total Hydrocarbons, NO, NO2, and
at Downtown Los Angeles (Sept. 29, 1969)2
50
40
£ 30
r»
O
10
10
8 9 10 11 12
Hr, Pacific Daylight Time
13
14
15
Attachment 16-2, Experimental Smog Chamber Data with
Propylene, NO, and NO-j in Air
0.500
0.375
a NO
. N02
o Oxidant
O Propylene
X Pan
100
200
Time (min)
400
16-11
-------
Attachment 16-3, Generalized Photochemical Reaction Equations^
N02 + hV »- NO + O
O + O2 + M ^ 03 + M
03 + NO ^- N02 + 02
0 + hydrocarbons ^ stable products + radicals
03 + hydrocarbons >• stable products + radicals
Radicals + hydrocarbons ^- stable products + radicals
Radicals + NO >* radicals + NO2
Radicals + N©2 ^ stable products
Radicals + radicals ^. stable products
16-12
-------
Attachment 16-4, 1974 Stationary Source
NOX Emissions
Commercial/
residential
space heating
9.0%
Utility boilers
41.9%
Reciprocating 1C
engines 19.8%
Industrial
boilers 18.2%
Incineration 0.31
Gas turbines 2.0%
Others 3.6%
Noncombustion 1.7%
Industrial process
heating 3.SZ
Attachment 16-5, Annual NOX Emissions Projections-
Source Category
Stationary Fuel Combustion
Electric Generation
Industrial
Commercial -Institutional
Residential
Industrial Process Losses'*
Solid Waste Disposal
Miscellaneous
TOTAL
NOX Emissions (10s tons)
• 1972
12.27
5.94
5.39
0.65
0.29
0.70
0.18
0.59
13.74
i
1980
15.96
(17.12)a
8.16
(9.32)
6.73
0.76
0.31
0.95
0.22
0.74
17.87
(19.03)
1985
16.82
(21.43)
8.20
(12.81)
7.46
0.84
0.32
1.14
0.25
0.87
19.08
(23.69)
1990
18.46
(27.14)
8.88
(17.56)
8.31
0.93
0.34
1.38
0.28
1.02
21.14
(29.82)
2000
21.74
(44.46) -
10.24
(32.96)
10.01
1.11
0.38
1.85
0.34
1.32
25.25
(47.97)
*NOX emissions for no new nuclear power plants after 1975 are given in parentheses.
16-13
-------
Attachment 16-6, Emission Factors for Utility Boilers, 1974!
Equipment Type
Field -Erected
Watertube Boilers
Field-Erected
Watertube Boiler
Stoker
Firing Type
Tangential Firing
Horizontally Opposed
Wall Firing
Front Wall Firing
Vertical Firing
Cyclone
Spreader
Underfeed
Fuel
Coal
011
Gas
Coal , Dry Bottom
Coal , Wet Bottom
Oil
Gas
Coal , Dry Bottom
Coal , Wet Bottom
011
Gas
Coal , Dry Bottom
Coal , Wet Bottom
Oil
Coal
Coal
Fuel Type
Bituminous
Lignite
Distillate
Residual
-
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
—
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
-
Anthracite
Bituminous
Lignite
Bituminous
Lignite
Distillate
Residual
-
—
Fuel
Usage
1012 Btu
4140.66
41,72
45.23
1086.57
867.55
1229.22
11.97
548.06
16.12
33.08
792.40
1378.23
1229.22
11.97
540.23
14.32
33.08
792.40
954.22
29.86
378.83
2.99
1020.62
12.64
2.92
55.53
131.98
56.60
Emission
Factors
Ib N02/10« Btu
0.64
0.64
0.357
0.357
0.30
0.75
0.88
1.25
0.88
0.75
0.75
0.70
0.75
0.88
1.25
0.88
0.75
0.75 ;
0.70
0.75
0.75
0.75
1.30
0.88
0.75
0.75
0.57
0.57
16-14
-------
Attachment 16-6 (cont'd). Emission Factors for Industrial Boilers, 19745
Equipment Type
'Field- Erected
Hatertube Boilers
>100 x 10' 8tu/hr
field-Erected
Watertube Boilers
10-100 x 10' Btu/hr
Held- Erected
Hater-tube Boilers
Stokers
Firing Type
Tangential Firing
Horizontally Opposed-
Wall Firing
Front- Wall Firing
Vertical Firing
Cyclone
Wall Firing
Spreader
Underfeed
Overfeed
General ,
Not Classified
Fuel
Coal
011
Gas
Coal , Dry Bottom
Coal , Wet Bottom
Oil
Gas
CoaJ , Dry Bottom
Coal , Wet Bottom
Oil
Gas
Coal , Dry Bottom
Coal, Wet Bottom
Oil
011
Gas
Coal
Coal
Coal
Coal
Fuel Type
-
Residual
Natural
Process
-
—
Residual
Natural
Process
—
—
Residual
Natural
Process
-
-
Residual
Distillate
Res i dua 1
Natural
Process
-
-
-
«•»
Fuel
Usage
1012 Btu
141.32
427.56
391.47
54.99
42.40
8.48
414.67
462.61
123.74
42.40
8.48
414.67
313.64
95.92
9.36
61.83
35.21
58.61
292.77
806.41
37.14
768.8,0
435.28
209.16
101.75
Emission
Factors
Ib N02/10S Btu
0.640
0.357
0.301
0.230
0.750
1.250
0.573
0.301
0.230
0.750
1.250
0.573
0.301
0.230
0.750
1.660
0.573
0.150
0.429
0.230
0.230
0.417
0.417
0.625
0.417
16-15
-------
Attachment 16-6 (cont'd), Emission Factors for Industrial Boilers, 1974
Equipment Type
Packaged Water-tube
Bent Tube
Straight Tube
(Obsolete)
Packaged Water-tube
Stoker
Packaged Firetube
Scotch
Packaged Firetube
Firebox
Packaged Firetube
Firebox Stoker
Packaged Firetube
HRT
Packaged Firetube
HRT Stoker
Firing Type
Wall Firing
Spreader
Underfeed
Overfeed
General ,
Not Classified
Wall Firing
Wall Firing
Spreader
Underfeed
Overfeed
Wall Firing
Spreader
Underfeed
Overfeed
Fuel
Coal
Oil
Gas
Coal
Coal
Coal
Coal
Oil
Gas
Oil
Gas
Coal
Coal
Coal
Oil
Gas
Coal
Coal
Coal
Fuel Type
-
Distillate
Residual
Natural
Process
-
-
—
—
Distillate
Residual
Natural
Process
Distillate
Residual
Natural
Process
-
-
-
Distillate
Residual
-
-
-
-
Fuel
Usage
1012 Btu
42.40
146.81
788.44
2535.75
132.43
363.91
567.60
90.45
59.36
146.81
735.15
802.60
18.96
56.45
290.32
693.23
18.96
16.96
84.80
11.31
28.23
152.79
364.82
8.48
42.40
5.65
Emission
Factors
Ib N02/10« Btu
0.750
0.157
0.429
0.230
0.230
0.417
0.417
0.625
0.417
0.157
0.429
0.230
0.230
0.157
0.429
0.230
0.230
0.417
0.417
0.625
0.157
0.429
0.230
0.417
0.417
0.625
16-16
-------
Attachment 16-6 (cont'd), Emission Factors for Commercial Boilers5
Equipment Type
Packaged Flretube Scotch
Packaged Firetube
Firebox
Packaged Flretube Firebox, Stoker
Packaged Firetube HRT
Packaged Flretube HRT, Stoker
Packaged Firetube, General,
Not Classified
Packaged Cast Iron Boilers
Packaged Watertube Coll
: Packaged Watertube Firebox
Packaged Watertube General,
Not Classified
Firing Type
Wall Firing
Wan Firing
All Categories
Wall Firing
All Categories
Wall Firing
Stoker and Handfire
Wall Firing
Wall Firing
Wall Firing
Wall Firing
Fuel
Oil
Gas
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Fuel Type
Distillate
Residual
-
Distillate
Residual
-
-
Distillate
Residual
-
-
Distillate
Residual
-
-
Distillate
Residual
-
Distillate
Residual
-
Distillate
Residual
-
Distillate
Residual
—
Fuel Usage
1012 Btu
516.65
516.65
655.41
516.65
516.65
655.41
165.72
258.33
258.33
327.71
82.86
86.91
79.91
109.24
18.41
258.33
258.33
409.63
28.01
34.28
43.69
16.85
22.84
18.21
28.01
34.28
43.69
Emission
Factors
Ib N02/10* Btu
0.157
0.430
0.230
0.157
0.430
0.230
0.417
0.157
0.430
0.230
0.417
0.157
0.430
0.103
0.25
0.157
0.430
0.120
0.157
0.430
0.103
0.157
0.430
0.103
0.157
0.430
0.103
16-17
-------
Attachment 16-6 (cont'd), Emission Factors for Residential Units, 1974-*
Equipment Type
Steam or Hot Water Heaters
Hot A1r Furnaces
Floor, Hall, or Plpeless Heaters
Room Heater With Flue
Room Heater Without Flue
Firing Type
Single Burner
Single Burner
Single Burner
Single Burner
Single Burner
Fuel
on
Gas
Oil
Gas
Oil
Gas
011
Gas
Oil
Fuel Type
Distillate
-
Distillate
-
Distillate
—
Distillate
-
Distillate
Fuel
Usage
1012 Btu
1207.49
1000.11
1331.93
2929.80
199.11
675.04
298.67
700.06
190.79
Emission
Factor
Ib N02/10« Btu
0.128
0.082
0.128
0.082
0.128
0.082
0.128
0.082
0.082
Attachment 16-6 (cont'd), Emission Factors for Various Engines, 19745
Equipment Type
Reciprocating
Engines
Gas turbines
Firing Type
Spark ignition
Diesel >500 hp
Diesel <500 hp
Fuel
Gas
Oil
Oil
Dual
Gas
Oil
Fuel Usage
1012 Btu
1007.73
63.76
139.30
51.01
608.86
285.64
Emission Factors,
Ib N02/106 Btu
4.40
4.16
3.41
2.91
0.45
0.85
16-18
-------
Attachment 16-7, Theoretical Curves of NO Concentration vs.
Temperature for Oil and Gas Firing'
8
1000
800
600
a.
a.
400
200
2600
3000 3200
TEMPERATURE (°F)
3400
16-19
-------
Attachment 16-8, Effect of Excess Oxygen, Fuel, and Equipment
on Nitrogen Oxides Emissions'
*-
(Single lines for water-tube boilers;
shaded areas represent all fire-tube boilers)
O
4-1
•o
•a
0
8
d
•H
W
in
800
600
400
200
600
400
200
400
200
I ^1
I I
Coal
Fuel
46 8 10 12 14
I I I I I
Oil
Fuels
6 8 10 12 14
I
Natural
Gas Fuel
02 4 6 8 10 12 14
Flue Gas Excess Oxygen, %
16-20
-------
Attachment 16-9, NOX vs. Theoretical Air, with Overfire Air'
LEGEND
Alabama Power Co.
Barry #2
3/4 Load
Wisconsin Power & Light Co.
Columbia II
Full Load
3 Utah Power & Light Co.
Huntington 12
Full Load
80 90 100 110 120 130
Theoretical air-to-fuel firing zone, %
16-21
-------
Attachment 16-10, Corner Windbox Showing Overfire Air
Two-Stage Combustion System^
WINDBOX
SECONDARY AIR DAMPERS
SECONDARY AIR
DAMPER DRIVE UNIT
OVERFIRE AIR
NOZZLES
SIDE IGNITOR
NOZZLE
SECONDARY
AIR NOZZLES
— COAL NOZZLES
OIL GUN
x
0
16-22
-------
Attachment 16-11, NOjj Emissions from Horizontal and Tangential
Fired Oil Boilers8
700
600
500
400
x
O
300
200
100
PLANT p
HORIZONTAL FIRING
PLANT 6
TANGENTIAL FIRING
I '
PERCENT
16-23
-------
Attachment 16-12, Effect of FGR on NO Emissions from
Tangentially-Fired Gas Boilers5
300
250
200 -
tsi
o
S 150 •
E
o.
OL
100 •
50 -
Data from different
units of same type
20
recirculation,
+ w.
where, w = mass flowrate
RG = recirculated gas
f = fuel
a - air
16-24
-------
Attachment 16-13, Effects of NOX Control Methods, including Load Reduction
for an Oil, Wall-Fired Utility Boiler5
500
400
300
CM
O
a.
a.
200
100
0
200 400 600
Load, HW (electrical)
Original
firing method
Two stage
combustion
Two stage
combustion
plus gas
recircu-
lation
through
burners
800
1000
16-25
-------
Attachment 16-14, NOX Emissions with Water Injection Rate for
Natural Gas-Fired Gas Turbines^
BO
cr*
N)
CO
CO
o
oc
Q
rf
O
in
60.
40-
i
0.
Q.
20-
i
0.4
0.8
i
1.2
j
1.6
i
2.0
. i
2.4
% WATER INJECTED (% OF COMBUSTION AIR)
-------
Attachment 16-15, Effect of Temperature on Reducing NO with Ammonia^
1.0
0.8
-J
F
E
o
_j
Lu
O
0.6
0.4
0.2
1
I r
=(NH3)/(NO)
i
i
i
1000 1100 1200 1300 1400 1500
TEMPERATURE, °K
16-27
-------
CHAPTER 17
IMPROVED PERFORMANCE BY COMBUSTION MODIFICATION
Introduction
Prior to the mid-1960's the main emphasis for preventive maintenance
for most combustion equipment was to assure safe operation and to prevent
major damage which could result in costly repairs and loss of service. An
annual boiler inspection was required typically by the insurance company.
With the enforcement of air pollution emission regulations, preven-
tive maintenance gained importance. Considerably increased fuel costs
since the "energy crisis of 1973" have provided an increasing emphasis
on conscious maintenance necessary to preserve high boiler effici-
encies (1).
Efficiency-related maintenance of combustion equipment is directed
toward correcting conditions which may increase fuel utilization. Among
these conditions are high stack gas temperatures, elevated combustible content
in ash, high excess air, and other factors involving heat loss.
This chapter will describe the maintenance and adjustments recom-
mended by EPA for reducing air pollutants and improving thermal efficiencies
for residential, commercial, and industrial combustion units. In addition,
examples of the influence of various combustion design modifications for
industrial and utility boilers will be discussed.
17-1
-------
Residential Oil-Burner Maintenance and Adjustments
Residential and commercial oil combustion units, with proper main-
tenance and adjustment, can achieve improved thermal efficiency and mini-
mized smoke, particulate, CO, and hydrocarbon emissions (2).
Annual maintenance should be performed by a skilled technician.
Among the items recommended is the annual nozzle replacement. As
the nozzle typically is made of brass, slight wear can cause a change in
the spray pattern and droplet formation. Combustion deposits or other
foreign materials also will cause poor atomization. The replacement nozzle
should be that recommended by the manufacturer. An oversize nozzle could
cause short cycling; lower efficiency and higher air pollution emissions
would probably result.
Dirt and lint should be cleaned from the blast tube, housing, and
blower wheel. If any air leaks into the combustion chamber are found, they
should be sealed. The electrodes should be adjusted for proper ignition,
and the oil pump pressure should be set to the manufacturer's specifica-
tions if necessary.
Following the EPA recommended adjustment procedure, a smoke versus
flue gas C02 plot for the given installation can be obtained experimentally,
using different settings of the air gate (2). Among the equipment required
is a draft gauge to be used in adjusting the barometric draft regulator
to the manufacturer's recommended value, a Bacharach smoke tester, and
an Orsat or Fyrite apparatus for measuring CO2 in the flue gases.
An example of the above-mentioned plot is given in Attachment 17-1.
Note the "knee" of the curve is where the smoke number begins to rise
sharply. The air setting should be adjusted for a CO2 level from 0.5 to
17-2
-------
1.0% lower than the level at the "knee." This will provide reasonable
assurance that the unit can operate properly, without smoke, under normal c
operational fluctuations of fuel,air pressure, air temperature, etc.
The results of the adjustment should be compared with the appropri-
ate standard values in Attachment 17-2. The smoke level should not be
greater than No. 2 and the CO2 level not less than the table value. Devia-
tion can be caused by air leakage into the combustion chamber,or by poor air-
fuel mixing. Changing the nozzle to one with different spray angle and
pattern may result in better performance.
Next the stack temperature, under steady operation, should be mea-
sured. The net stack temperature can be computed.by subtracting the room
air temperature from the thermometer reading. This value can be compared
with those shown in Attachment 17-3. Excessive stack loss is indicated if
the net stack temperature exceeds 400 to 600°F for matched-package units or
600 to 700°F for conversion burners, stack loss may result from operating
the unit at an excessive firing rate which will generate more heat than the
heat exchanger can utilize.
Commercial Oil-Fired Boiler Adjustments
The EPA recommended maintenance for commercial oil-fired boilers (3)
is almost the same as for residential units. The skilled technician should
confirm that the oil temperature or viscosity range is suitable for the
installation. Typical viscosity values are given in Attachment 17-4. In
some cases, the technician may determine if the combustion is cycling too
rapidly for the fuel being burned. For example, No. 6 fuel oil cannot
burn completely in a rapidly cycling installation due to the cool condition
of the refractory wall. A switch to No. 2 fuel oil usually is suggested.
17-3
-------
The recommended adjustment procedure, like that for residential
burners, involves taking smoke and CO2 data for various air settings with
the fuel at the full,,firing rate. A characteristic plot is found in Attach-
ment 17-5. After the "knee" of the curve has been identified, the air set-
ting should be adjusted to where the CO2 level is about 0.5% lower than
the "knee" value.
The smoke level at the above adjustment should be below the "maximum
desirable" shown in Attachment 17-6, with a CO2 level at 12% or higher. If
not, it is likely that the atomization and/or the fuel-air mixing are poor.
The trouble may be with an improper or dirty nozzle, the atomizing pressure
or temperature, or the air handling parts.
For modulating burners, the above procedure should be repeated at
low-fire and intermediate-fire settings. Typically, the optimum air setting
at low-fire will be at lower CC>2 than at the high-fire condition.
If the boiler is equipped for gas firing, the same procedure should
be used. Note, however, that for the same excess air, the CO2 level will
be lower with gas than with oil firing, as illustrated in Attachment 17-7.
Also, it is important to check the CO reading. It should be below the
recommended 400 ppm as CO can be emitted from gas units even without smoke.
Industrial Boiler Maintenance and Adjustment
Industrial boilers, with proper maintenance and adjustment for opera-
tion at lowest practical excess oxygen level, can achieve improved overall
thermal efficiency and reduced NOx emissions.
Thermal efficiency improvement with lowering excess air is shown in
Attachment 17-8. The improved efficiency results from the fact that less
flue gas is available to carry energy loss out the stack. However, as
17-4
-------
excess oxygen is reduced in coal and oil-fired industrial units, a "smoke
limit" or "mimimum ©2 level" is reached where the unit begins to smoke.
This is illustrated in Attachment 17-9.
Similarly for a natural-gas-fired unit, as excess oxygen is reduced,
the CO emissions rise (see Attachment 17-10). Therefore, a "CO limit" or
"minimum ©2 level" has been recommended corresponding to 400 ppm CO.
The EPA has published a recommended step-by-step adjustment procedure
to provide for the low excess oxygen operation of existing industrial-sized
combustion units (4). The main differences between this procedure and those
for residential and commercial units has to do with size and equipment fea-
tures, including the instrumentation available and the sophistication of the
combustion control system. Because of the large geometries, the location
of the sampling site is important in order to obtain a representative sam-
ple. Boiler load characteristics typically requires operation with
considerable burner modulation. Among the instruments often available are
continuous monitors for excess ©2 and C02, CO, NOjj, opacity, and stack tem-
perature.
The "minimum ©2 level" determined for an existing unit should be
compared with typical values given in Attachment 17-11. A value which is
higher than the range shown may result from burner malfunctions or other
fuel or equipment-related problems. Note also that many burners will exhi-
bit higher "minimum 02" at lower firing rates.
The recommended operational value for excess air is called the
"lowest practical excess air," a value 0.5 to 2.0% greater than the mini-
mum excess air described above. The extra excess air is required to accom-
modate operating variables at a particular installation, such as variation
17-5
-------
in fuel properties, rapid burner modulation, variation in ambient condi-
tions, and "play" in automatic controls. Changes in air flow rate result-
ing from barometric pressure changes may be accommodated by the lowest
practical excess air. Other ambient variations, such as changes in tempera-
ture and wind, may be minimized if the unit is located inside a building.
Units located outside may require additional excess air or sophisticated
combustion control systems (5).
The above-mentioned adjustments procedures for minimizing excess air
typically will improve thermal efficiency and reduce NOx emissions. How-
ever, as was discussed in Chapter 16, more extensive design modifications
may be required for considerable NOjj control. These will be discussed in
the next sections.
Industrial Boiler Combustion Modifications
Industrial boiler manufacturers can adopt important combustion
design modification techniques for reducing NOjj emissions. From Attach-
ment 17-12, one may conclude that NOX emissions depend on the fuel, the
excess air, and the design of the particular installation.
In general, NOjj emissions from coal, characterized mainly by fuel
NOX, are very sensitive to excess oxygen. The NC^ from fuel oil is
sensitive to excess oxygen, but less so than coal, because of
the lower nitrogen in oil. The NOjj emissions from natural gas, character-
ized as thermal NOX, are typically lower than for coal or oil. This is
due to very low nitrogen content of gas and because burning is more uniform
with fewer hot spots. Note in Attachment 17-12 that some gas-fired units
may show an increase of NOX with decreasing excess oxygen. This is because
of the increasing combustion temperatures.
17-6
-------
Staged combustion has been demonstrated as an effective combustion
modification technique for NOX control of an oil or gas-fired 40,000 Ib/hr
water tube boiler (see Attachment 17-13). Burners were operated on less
than stoichiometric air, with the balance of the air being provided through
special NOjj ports. The corresponding NOx control for gas and oil firing
is shown in Attachments 17-14 and 17-15. The location and air velocity in
the NOx ports influence the degree of NOX control, as it is possible to
create hot spots with rapid air injection. Note in Attachment 17-16,
however, that thermal efficiency is usually reduced with this
technique.
Reduced combustion air temperature has been shown to be effective
for NOx control on three water tube boilers burning gas and/or No. 6 fuel
oil. This is shown in Attachment 17-17. Note, however, that reduced air
preheat is effective for coal combustion only if high excess air is used,
as illustrated in Attachment 17-18. Generally, lower thermal efficiency
occurs with reduced combustion air preheat since energy recovery devices
are not used, as illustrated in Attachment 17-19.
Flue gas recirculation, FGR, is an effective technique for NOx con-
trol in industrial boilers, particularly for those using natural gas (9,
10)- As more flue gas is recirculated, the NOx control effect becomes
greater, as illustrated in Attachment 17-20. Notice that the effects appear
to be dependent on the particular combustion equipment design. The recir-
culated flue gases may be delivered with the primary air, the secondary air,
or the total air. It may be possible to obtain some improved thermal effi-
ciency with flue gas recirculation; but this is probably not a cost-^
effective method of NO control.
17-7
-------
Utility Boiler Combustion Modification
NOx control effectiveness for utility boilers depends on furnace
design characteristics (geometry and operational flexibility), fuel-air
handling systems, automatic controls, and the operational problems that
result from combustion modifications (11). Modifications are limited by
the emission of other pollutants (CO, smoke, and carbon in flyash), the
onset of slagging and fouling, and flame stability problems.
Depending on the NOX emission limits to be reached, combustion modi-
fication should proceed in stages. First, the combustion conditions should
be fine-tuned by lowering excess air through adjustment of burner settings
and air distribution. Second, soot-blowing frequency should be increased
to improve flame heat transfer. This will lower the maximum combustion
temperature. Next, consider implementing two-stage combustion through bur-
ner-biased firing or burner-out-of-service. The final stage would include
major retrofit changes, such as including overfire air ports, flue gas re-
circulation, and new burners.
Gas-fired utility boilers produce only thermal NOjj, which is the easi-
est to control by combustion modification. As Attachment 17-21 indicates,
larger units tend to produce more NOy because of the higher combustion tem-
perature (thermal NOX). Low excess air is used routinely in gas-fired
utility boilers for NOX control. This reduction, however, depends on fur-
nace design and firing method. Generally, a slight increase in thermal
efficiency is noted, and flame stability is not a serious problem.
Two-stage combustion with flue gas recirculation, shown in
Attachments 17-21 and 17-22, results in substantial NOX control for gas-
fired utility boilers. Overfire air, biased firing, and burners-out-of-
17-8
-------
service are effective designs for achieving off-stoichiometric combustion.
Oil-fired utility boilers produce fuel NOjj as an important part of
the total N0x« As expected, low excess air is used routinely in oil-fired
burners for NOjj control, as well as improve thermal efficiency and to
reduce the conversion of SO2 to S03. Larger residual oil-fired units do
not appear to produce more NOX than smaller units, illustrated in
Attachment 17-23. This is an indication of the importance of fuel NOX as
opposed to thermal NOx in oil-fired units.
Overfire air ports, shown in Attachment 17-24, are the
accepted technique for providing two-stage combustion in wall-fired oil-
burning units. Burners-out-of-service in the upper part of the firing
pattern is used for NOjj control in wall and tangentially fired oil units.
The effect of combining two-stage combustion with flue gas recirculation
is shown in Attachment 17-25. NOx reductions of 40 to 60% have been
demonstrated, but this may require de-rating the unit in order to be suc-
cessful. Also with flue gas recirculation, flame stability problems may
occur at higher burner velocities.
Coal burned in utility boilers contains fuel-bound nitrogen, which
accounts for up to 80% of the NOX emitted by the staqk. Wall-fired burners
may obtain reduced NOX through modifications such as low excess air, staged
firing, load reduction, and flue gas recirculation. However, the latter is
much less effective with coal-firing than with oil or gas.
Tangentially-fired boilers with overfire air emit considerably less
NOx than normally operated boilers, as illustrated in Attachment 17-26.
Off-stoichiometric firing is an effective additional combustion modifica-
tion for NOX control, as shown in Attachment 17-27. However, fuel-rich
17*9
-------
burner conditions can produce excessive smoke and CO and flame instabi-
lity.
It is unfortunate that NOx emissions from coal-fired utility boilers
are so great even after combustion modification. It appears that NOx
emissions will be of increasing regulatory concern because coal supply
creates incentives for increased burning of coal. Consequently, as
mentioned in Chapter 16, considerable research is now directed toward
the development of adequate N^ flue gas treatment, as well as coal-
cleaning and fluidized-bed coal combustion techniques.
References
1. Industrial Boiler User's Manual, Vol. II, prepared by KVB, Inc.
of Tustin, CA, Report No. FEA/D-77/026, NTIS No. PB-262577, Federal Admin-
istration (Jan. 1977).
2. "Guidelines for Residential Oil-Burner Adjustments," Report No.
EPA-600/2-75-069-a, Industrial Environmental Research Laboratory, USEPA
(Oct. 1975).
3. "Guidelines for Burner Adjustments for Commercial Oil-Fired
Boilers," Report No. EPA-600/2-76-008, Industrial Environmental Research
Laboratory, USEPA (Mar. 1976).
4. "Guidelines for Industrial Boiler Performance Improvement,"
Report No. EPA-600/8-77-003a, Industrial Environmental Research Laboratory,
USEPA (Jan. 1977).
5. Reed, R.D., Furnace Operations, Gulf Publishing Co., Houston
(1976).
17-10
-------
6. "Reference Guideline for Industrial Boiler Manufacturers to
Control Pollution with Combustion Modification," Report No. EPA-600/8-77-003b,
Industrial Environmental Research Laboratory, USEPA (Nov. 1977). "
7. Cato, G. A., et al., "Reduction of Pollutant Emissions from
Industrial Boilers by Combustion Modification," paper no. 76-WA/FU-5,
presented at ASME Winter Annual Meeting in New York City (Dec. 1976).
8. Crawford, A. R., et al., "Control of Utility Boiler and Gas
Turbine Pollutant Emissions by Combustion Modification Phase 1," Report
No. EPA-600/7-78-036a, Industrial Environmental Research Laboratory, USEPA
(March 1978).
9. Hunter, S. C., et al., "Evaluation of Two Industrial Boilers with
Combustion Modification for Reduced Pollution Emission," paper no. 77-WA/APC-l,
presented to ASME Winter Annual Meeting in Atlanta, Ga (Dec. 1977).
10. Carter, W. A., et al., "Emission Reduction on Two Industrial
Boilers with Major Combustion Modifications," Report No. EOA-600/7-78-009a,
Industrial Environmental Research Laboratory, USEPA (June 1978).
11. "Control Techniques for Nitrogen Oxides Emissions from Stationary
Sources," Second Edition, Report No. EPA-450/1-78-001, Office of Air
Quality Planning and Standards, USEPA (Jan. 1978).
17-11
-------
Attachment 17-1, Typical Smoke-C02 Characteristic Plot
for a Residential Oil Burner^
E
3
0)
1C.
o
E
c/>
o
o
L.
O
£
o
o
00
High air settings
Low air settings
Smoke-C02 Curve
Tolerance to "knee"
Normal adjustment range
\ .
Test points
"Knee"
8 10
Percent COa in Flue Gas
12
17-12
-------
Attachment 17-2, Typical Air Adjustments for Different Types
of Residential Burners2
OIL-BURNER TYPE
Typical CO-
in Flue Gas
When Tuned*
HIGH-PRESSURE GUN-TYPE BURNERS
• Old-Style Gun Burners 8 7.
- No internal air-handling parts other
than an end cone and stabilizer
• Newer-Style Gun Burners
- special internal air-handling parts
• Flame-Retention Gun Burners
- flame-retention heads
9 7.
10 7.
OTHER TYPES OF BURNERS
• Atomizing Rotary Burners
- ABC, Hayward, etc.
• Rotary Wall-Flame Burners
- Timken, Fluid-Heat, Torridheet, etc.
• Miscellaneous Low-Pressure Burners
8 7.
12 7.
**
* Based on acceptable Bacharach smoke -- generally No. 1 or trace, but
not exceeding No. 2.
Caution should be used in leaving burners with CO. level higher
than 137..
** See manufacturer's instructions.
17-13
-------
Attachment 17-3, Effect of Stack Temperature and Q02 on Thermal Efficiency
85
80
75
UJ
9 70
i"
o
60
55
50
Net Stock Temperature
400 F
500 F
600
10
11
12
Percent COZ in Flue Gas
Basis: • Continuous operation
• No. 2 heating oil
• Heat lost from jacket is assumed
to be useful heat.
13
14
15
Source:
Bulletin 42, University of Illinois, Engineering Experiment
Station Circular Series 44 (June 1942).
17-14
-------
Attachment 17-4, Usual Range of Firing Viscosity3
Atomization
Method
Pressure
Steam or Air
Rotary
Viscosity
Saybolt Seconds
Universal
35-150 SSU
35-250 SSU
150-300 SSU
Equivalent
Kinematic
Viscosity,
Centistokes
4-32 ca
4-55 cs
32-60 cs
Attachment 17-6, Maximum Desirable Smoke3
Fuel Grade
Maximum Desirable
Bacharach Smoke Number
No. 2 1 or less
No. 4 2
No. 5 (light and heavy), 3
and low-sulfur resid
No. 6 4
Attachment 17-7, CO2 Variation with Excess Air and Fuels3
Percent
Excess Air
0
10
25
50
75
Gas
Firing
12.0
10.8
9.4
7.9
6.6
Percent CO., in Flue
No. 1 Oil
Firing
15.0
13.5
11.8
9.8
8.3
Gas
No. 6 Oil
Firing
16.5
15.0
13.0
11.0
9.3
17-15
-------
Attachment 17-5, Smoke-CO Characteristic for a Typical Commercial
Oil Boiler Firing Residual Oil3
8
0)
.o
6 6
0)
J£
o
E
-5
o
^
o
JZ.
u
o
CD
High air settings
Normal adjustment range
Tolerance to "knee"
Low air settings
Smoke-CO, Curve
"Best" air setting
1
,.
Knee
8 10 12
Percent C02 in Flue Gas
14
17-16
-------
Attachment 17-8, Variation of Boiler Efficiency Losses with Excess O2
25
20
w 15
H
M
u
h 10
b
U
Total Efficiency
Loss
Flue Moisture
Dry Flue Gas
Radiation
Combustibles (Carbon Monoxide)
I i I
EXCESS Cy %
17-17
-------
Attachment 17-9, Typical Smoke-O2 Characteristic Curves for Coal
or Oil-Fired Industrial Boilers4
o
Ck
en
,
o
£
cn
Low Air Settings
Curve
High Air Settings
Test Points
Curve (1
Appropriate Operating
Margin From Minimum O_
Automatic Boiler
Controls Adjusted
to This Excess O_
Minimum 0
Percent 0 in flue gas
Curve 1 - Gradual smoke/O characteristic
Curve 2 - Steep smoke/0 characteristic
17-18
-------
Attachment 17-10, Typical CO-O2 Characteristic Curves for Gas-Fired
Industrial Boilers^
Q*
tO
0)
3
i-l
-------
Attachment 17-12, Effect of Excess Oxygen and Fuel on NOX Emissions
(Single lines for water-tube boilers;
shaded areas for fire-tube, boilers)
0
-p
JJ
U
2
u
0
o
E
a
c
0
• H
V)
O
800
600
400
200
600
400
200
Coal
Fuel
8 10 12 14
Oil
Fuels
8 10 12 14
400
200
I
I
Natural
Gas Fuel
02 4 6 8 10 12 14
Flue Gas Excess Oxygen, %
17-20
-------
Attachment 17-13, Schematic Diagram of Staged-Air System Installed
on a 40,000-lb/hr Watertube Boiler6
Wir.dbox
Windbox
36 cm dia.
Manifold
(a) TOP VIEW Sidefire Air Fan
cm
Furnace
86 on 80 cm
©- •£
^;
rPort 6,7 8
Noa.
14,15
83 cm .61 cmC/T"
T 1 -
^ n rv
j \j \j
,9 10,11 12,13
w-
/
36(
k
b <
(b) SIDE VIEW
Dividing Wall
17-21
-------
Attachment 17-14, Reduction in Nitrogen Oxides from Staged Combustion
Air, Natural Gas Fuel6
120
iioJ.
lool
90
X
«
^
u
•o
160
0*140
120
100
— — TTFT RTPH
COMBUSTION
Baseline (1.9%
Other Points (2.9^-3.4%)
Symbol Port Open
None (Baseline)
90
95
100
105
110
115
T20
Theoretical Air at Burner, % of Stoichiometric
17-22
-------
Attachment 17-15, Reduction in Nitrogen Oxides Emissions from Staged
Combustion Air, .No. 6 Fuel Oil
200.
175-
tn 150.
a;
T3
•- 1
X
O
• *
•a 200
fc
t
at
150
100
•
50
| 1 1 1 1 1
^.FUEL RICH I AIR RICH ^
COMBUSTION ' COMBUSTION O^*
— o a
g^—i BASELINE NO r\O^
(3.0% 02) X ^Y
- C> 00
/ /^
/^/4
/ /rx ^
o <5/^
r //
^ O
x<
oc? jy
t ^r
/^ 0
^
& Symbol Port Open
O None d.6<02<6.2)
O 6 & 7 »
Q 8 fi 9
Q 10 & 11
— O 12 & 13
0 14 & 15
Q 10,11,14 & 15
Q 8,9,10 & 11
/"N fi 7 R c Q
- 1 i i i v ' r i
•
•••^
••••••
•?
ro
. CM
O
V
(N
80 ^0 100 110 120 130 1
Theoretical Air at Burner, % of Stoichiometric
17-23
-------
Attachment 17-16, Effect of NO Ports on Boiler Efficiency6
X
o
§
•r<
O
•H
W
C
fl
5
Most Desirable Quadrant
D
+3
+2
r-d1
D
D
D
+10 +30 +50
-1
-2
-3
Change in Total Nitrogen Oxides. %
A Coal Fuel
O Oil Fuel
DNatural Gas Fuel
17-24
-------
Attachment 17-17, Effect of Combustion Air Temperature on Total Nitrogen Oxides
Emissions with Gas and Oil Fuels for Three Watertube Boilers6
200-
150-
w -<
0) -H
•O O
-H
X U
O 0
MJ
c
C
50.
0_
•*uu
300
(N
O
tH>
m
• fr2°°
•O
|
100
0
1 1 1 1
,
0Q^
— y^V. *°i.ler rated —
p-XT) \ at 44500 Ib/hr
^r & steam flow
\
Boiler rated at 40000 1
Ib/hr steam flow j£\
— J^^ ^J"1^ "~"
-^^^^«^— ^"CTj^^k^ '^^1
sA^^KS *J*^^^ ^^
C_??3-J LJ
r-+/ /^
\ 1
^r~^ (f~l
^*^ D
>D Q /
Boiler rated at r-i
•250000 Ib/hr ^ —
steam flow
^ | Baseline Air Temp.
Q Natural Gas
O No. 6 Oil
1 1 1 1
0 100 200 300 400 500
•P
1 1 II 1
300 350 400 450 500
K
Combustion Air Temperature
17-25
-------
Attachment 17-18, NOY Control by Air Preheat Reduction
1000
I
a,
500
Coal
Gas
500
Preheat, °F
1000
Effect of air preheat at normal excess air levels.
1000
§3 500
o
z
Oil
Gas
I
0 500
Preheat, °F
Effect of air preheat at high excess air.
1000
17-26
-------
Attachment 17-19, Effect of Combustion Air Preheat Temperature on
Boiler Efficiency6
>i
u
01
•i-4
u
•r-l
U-l
UH
W
C
••-I
O
6
4-
I
Most Desirable Quadrant
Open Symbols Represent
Reduced Preheat Tempera-
3 ture
Solid Symbols Represent
Increased Preheat Temp.
Q-n
-50 -30
n i i i
D
-2
Change in Total Nitrogen Oxides, % ->• +
Coal Fuel
Q Oil Fuel
Natural Gas Fuel
17-27
-------
Attachment 17-20, Reduction in Total Nitrogen Oxide Emissions by Flue
Gas Recirculation with Constant Excess Air°
100
Q No. 6 Fuel Oil, Air Atomized
No. 6 Fuel Oil, Steam Atomized
Natural Gas Fuel
Natural Gas Fuel & No. 6 Fuel
Oil, Air Atomized
20 30
Flue Gas Recirculation, %
17-28
-------
Attachment 17-21, NOX Emissions from Gas, Tangentially-Fired Utility Boilers11
500 ,.
CM
V)
OJ
u
X
d>
»e
400 ••
300 .-
i.
•a
E
a.
a.
200-•
100 .-
L
J Normal operation
kyM^W Overf i re air
Flue gas recirculation
EPA standard for new
gas -fired boilers
73 78 82 105 110 121 160 160 IbO 8U 230
Megawatt size per furnace
250 418 550
17-29
-------
Attachment 17-22, Effects of NOX Control Methods on a Gas, Wall-Fired
Utility Boiler
11
OO
O
CO
Q.
CL
1600
UOO
1200
1000
800
600
400
200
200 400 600
Load, MW (electrical)
Original
firing
method
Reduced
excess
air firing
Two stage
combustion
•
Two stage combustion
plus gas reclrcula-
tion through burners
800
1000
17-30
-------
Attachment 17-23,
Emissions from Residual Oil, Tangentially-Fired
Utility Boilers
11
CM
o
I/I
VI
O
o
X
-------
Attachment 17-24, Two-Stage Combustion
T- Secondary oxidizing zone
' \
/ CO + 0 -> C02 \
"Over.fi re air port"
2
.
2CO + 4H0
CH
2
C + 2H20
//• Furnace wall
V
I
V//
o:
1 C + 02 •* CO + 0
\ 0, •* 0 + 0
\ 2
\ N + 0, -»• NO + 0
\ 2
^^•^2 + 0 -^ NO + N
CH
4 •*
S^——-.
«1
r
^-
Primary reducing zone
/
\
Fuel nozzle
Air register
17-32
-------
Attachment 17-25, Effects of NOX Control Methods11
500
CM
O
n
400
300
200
100
Original
firing method
200 400 600
Load, MM (electrical)
Two stage
combustion
\
Two stage
combustion
plus gas
recircu-
lation
through
burners
800
1000
17-33
-------
Attachment 17-26, NOX Emissions from Tangential, Coal-Fired Utility Boilers
11
700 -
600-
(SI
o
S 500
o
X
400
f>
300-
i.
a.
^ 2004
100- -
t.
I
\
I\X\\\\1
mat
mmt
' T
V
52 100
Normal operation . . EPA standard
Top el
Top el
HBa
\\Q
e1
e
mm
/ation not Tinny — no uvt
/ation firing - overfire t
•r.
:•:'
|
X
s,
\
s
//////////
'v
Ha
W
• *\
^>
!
^
TI
X
V
\
X
X
X
X
X
^
^
1 J
«3
3
o
ii
Jl
^
i i i c a
r
T
s
X
*
\
s
X
s
s
x
\
s
s
s
s
s
\
s
s
N,
122 170 206 215 250 250 265 37C
(80)*
I
mm
3K*.
-
J
for new coa
fired boile
\
urn
—
mm
mm
x
X
X
x
1
1
s
§426485 565
157)* (158)* (395)'
iOJ* I lt>>)" lli>o;*
Megawatt size (electrical) per furnace
"(Reduced rating when top elevation not firing)
17-34
-------
Attachment 17-27, Effect of Burner Stoichiometry on NOX Production in
Tangential, Coal-Fired Boilers
11
700
600
6 500 -
400 -
D.
7 300
o
200
100
40.00 60.00 80.00 100.00 120.00 140.00 160.00 180.00
STOICHIOMETRY TO ACTIVE BURNERS (PERCENT)
17-35
-------
Attachment 17-28, Pulverized Coal Burner Adapted for Low NO Emissions
X
to
Adjuitabl* air
•net and rttUter*
fUtractibt* Itchier
and auxiliary burner any tir
Observation door
and burner
(lame detector
------- |