United States Air Pollution Training Institute EPA 450/2-80-063
Environmental Protection MD 20 February 1980
Agency Environmental Research Center
Research Triangle Park NC 27711
Air
&EPA APTI
Course 427
Combustion Evaluation
Student Manual
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United States
Environmental Protection
Agency
Air Pollution Training Institute
MD20
Environmental Research Center
Research Triangle Park NC 27711
EPA 450/2-80-063
February 1980
Air
APTI
Course 427
Combustion Evaluation
Student Manual
Prepared By:
J. Taylor Beard
F. Antonio lachetta
Lembit U. Lilleleht
Associated Environmental Consultants
P.O. Box 3863
Charlottesville, VA 22903
Under Contract No.
68-02-2893
EPA Project Officer
James O. Dealy
United States Environmental Protection Agency
Manpower and Technical Information Branch
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
V,
G0604
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Notice
This is not an official policy and standards document. The opinions, findings, and
conclusions are those of the authors and not necessarily those of the Environmental
Protection Agency. Every attempt has been made to represent the present state of
the art as well as subject areas still under evaluation. Any mention of products or
organizations does not constitute endorsement by the United States Environmental
Protection Agency.
Availability of Copies of This Document
This document is issued by the Manpower and Technical Information Branch, Con-
trol Programs Development Division, Office of Air Quality Planning and Standards,
USEPA. It was developed for use in training courses presented by the EPA Air Pollu-
tion Training Institute and others receiving contractual or grant support from the
Institute. Other organizations are welcome to use the document for training purposes.
Schools or governmental air pollution control agencies establishing training programs
may receive single copies of this document, free of charge, from the Air Pollution
Training Institute, USEPA, MD-20, Research Triangle Park, NC 27711. Others may
obtain copies, for a fee, from the National Technical Information Service, 5825 Fort
Royal Road, Springfield, VA 22161.
Ij S. Environmental Protc-ction
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POLLUTION TRAINING INSTITUTE
MANPOWER AND TECHNICAL INFORMATION BRANCH
CONTROL PROGRAMS DEVELOPMENT DIVISION
OFFICE OF AIR QUALITY PLANNING AND STANDARDS
The Air Pollution Training Institute (1) conducts training for personnel working on the develop-
ment and improvement of state, and local governmental, and EPA air pollution control programs,
as well as for personnel in industry and academic institutions; (2) provides consultation and other
training assistance to governmental agencies, educational institutions, industrial organizations, and
others engaged in air pollution training activities; and (3) promotes the development and improve-
ment of air pollution training programs in educational institutions and state, regional, and local
governmental air pollution control agencies. Much of the program is now conducted by an on-stte
contractor, Northrop Services, Inc.
One of the principal mechanisms utilized to meet the Institute's goals is the intensive short term
technical training course. A full-time professional staff is responsible for the design, development,
and presentation of these courses In addition the services of scientists, engineers, and specialists
from other EPA programs governmental agencies, industries, and universities are used to augment
and reinforce the Institute staff in the development and presentation of technical material.
Individual course objectives and desired learning outcomes are delineated to meet specific program
needs through training. Subject matter areas covered include air pollution source studies, atmos-
pheric dispersion, and air quality management. These courses are presented in the Institute's resi-
dent classrooms and laboratories and at various field locations.
R. Alan Schueler
Program Manager
Northrop Services, Inc.
./James A. Jahirne
Technical Director
Northrop Services, Inc.
Jeanjf Schueneman
Chief, Manpower & Technical
Information Branch
m
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Table of Contents
Chapter 1
Introduction to Combustion Evaluation in
Air Pollution Control [[[
Appendix 1-1, Instructional Objectives
er 2
Fu
Chapter 3
Chapter 2
Fundamentals of Combustion ..................................................
Fuel Properties [[[ ^
Chapter 4
Combustion System Design
Chapter 5
Pollution Emission Calculations
Appendix 5-1, "Compilation of Air Pollution
Control Factors" [[[ 5"23
Chapter 6
Combustion Control and Instrumentation ........................................ 6-1
Chapter 7
Gaseous Fuel Burning [[[ ' "1
Chapter 8
Fuel Oil Burning [[[ 8-1
Chapter 9
Coal Burning [[[ 9-1
Appendix 9-1, "Corrosion Deposits from
Combustion Gases" by William T. Reid ......................................... 9-17
Chapter 10
Solid Waste and Wood Burning ................................................ 10-1
Chapter 11
On-Site Incineration of Commercial
and Industrial Waste [[[ H'l
Chapter 12
Municipal Sewage Sludge [[[ 12"1
Chapter 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 .................................................. 13-1°
Chapter 14
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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. Emissions include particulates and
gaseous chemicals which damage both the public health and the general welfare.
Combustion Evaluation in Air Pollution Control presents the fundamental and
applied aspects of state-of-the-art combustion technology, which influence the con-
trol of air pollutant emissions. Emphasis will be placed on controlling combdstion
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 combustion, as well as an overview of
the state-of-the-art of combustion technology 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:
a. Combustion sources burning fossil fuel for the generation of steam or
direct heat; i
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 quantities of emissions and the
requirements for complete combustion. Participants 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 performance of malfunctioning combus-
tion equipment.
The detailed instructional objectives, which are presented in Appendix 1-1, are
discussed below.
1-1
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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 monoxide, and other unoxidized or
partially oxidized hydrocarbon gases.
Fundamental concepts must be considered in the analysis of combustion-related
air pollution problems. For example: the temperature of a fuel oil establishes its
viscosity; viscosity (and other design variables) determines the atomized-droplet size
in an oil burner; droplet size influences evaporation rate, which in turn sets the
time requirements 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 understanding of these characteristics
will be used to determine the corrective action needed for malfunctioning combus-
tion 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 combustion 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 accomplished,
individuals will be (a) familiar with combustion principles, (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 com-
bustion sources.
1-2
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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, combustion system design,
emission calculations, various combustion equipment topics, NOX
control);
c. Present two reasons for applying the fundamental concepts of combus-
tion 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 relationships for typical
combustion situations;
c. Distinguish between different types of combustion as characterized by
carbonic theory (yellow flame) and hydroxylation 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;
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 combustion of a given fuel;
1-3
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i. Recite the conditions for equilibrium;
j. Describe how an excess quantity of one reactant will affect other concen-
trations 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 com-
bustion 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 combus-
tion of a fuel oil;
f. Describe the influence of variations in fuel oil viscosity on droplet forma-
tion and on completeness of combustion and emissions:
g. List the important components in the proximate and ultimate analyses;
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
Objectives: 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.
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5. Subject: Pollution Emission Calculations
Objective: The student should be able to:
a. Describe the nature and origin of most of the published emission 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 determine
estimates of emissions from typical combustion sources;
c. Define and distinguish between concentration standards (Cvs and Cms),
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 anticipated 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 installation;
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% C>2', and
j. Use F-factors to estimate emissions from a combustion source.
6. Subject: Combustion Control and Instrumentation
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 C>2 in stack gases) on
the boiler efficiency, fuel rate, and economics 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;
1-5
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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 air-to-fuel ratio;
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 influence 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 fac-
tors to compute uncontrolled emissions from oil-burning sources.
9. Subject: Coal Burning
Objective: The student will be able to:
a. Describe the design characteristics and operating practice of coal burn-
ing equipment, including overfeed, underfeed, and spreader stokers, as
well as pulverized and cyclone furnaces;
b. Discuss the parameters that influence the design of overfire and under-
fire 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 car-
• bon 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.
10. Subject: Solid Waste and Wood Burning
Objective: The student will be able to:
a. List the important similarities and differences in both physical and
chemical properties of solid waste, wood waste, and coal;
b. Describe the mechanical configurations required to complete combus-
tion 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.
1-6
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11. Subject: Controlled-Air Incineration
Objective: The student will be able to.
a. Describe the combustion principles and pollution emission
characteristics of comrolled-air incinerators contrasted with those of
single and multiple-chamber designs
b. Identify operating featuies which mav 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 afterburnei.
12. Subject: iVtunicipal 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 sewage 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.
13. Subject: Direct-Flame and Catalytic Incineration
Objective: The student will be able to:
a. Cue 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 application;
e. List three reasons for loss of catalytic activity and ways of preventing
such loss; and
f. Cite methods available for reducing afterburner operating costs.
14. Subject: Waste Gas Flares (Optional)
Objective: The student will be able 10:
a. Calculate the carbon to hydrogen ratio oi a uas:e i^as stream and
determine when and how mm h steam HI;! l><- ..-quired tor smokeless
tlare operation;
1-7
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b. Understand the diiieience between eU^aieu an,I giound level fLues and
the design consulc; auons which unde.iie 'he < hone of one or i he oilier:
and
e. Describe provisions loi leveling was < gas ti.m ;aies tioin miei mittent
sources.
15. 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 incineiation operations;
c. List examples of substances and or elements which cannot be
controlled by incineration;
d. Describe the fuel requirements necessary to dispose of hazardous waste
materials; and
e. List, a number of hazardous waste materials (including polychlorinated
biphenyls —PCBs pesticides, and some other halogenated organics)
which may be disposed of successfully through proper liquid incinera-
tion devices; give the required temperatures and residence times to
achieve adequate destruction.
16. Subject: NOX Control
Objective: The student will be able to:
a. Identify three ot the major stationary sources of NO% emissions;
b. Locate and use emission factors to estimate the amount of NOX emit-
ted 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 recirculalion.
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.
17. 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;
b. List three important features to check during the maintenance of
commercial oil-fired burners:
c. Discuss the difference between "minimum O? and "lowest practical
O? and why these are important in industrial boilers.
1-8
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Chapter 2
Fundamentals of
Combustion
INTRODUCTION
Combustion is a chemical reaction. It is the rapid oxidation of combustible
substances accompanied by the release of energy (heat and light) while the consti-
tuent elements are converted to their respective oxides.
The products of complete combustion of hydrocarbon fuels are innocuous carbon
dioxide and water vapor. Incomplete combustion, however, can lead to serious air
pollution problems with the emissions of smoke, carbon monoxide, and/or other
partially oxidized products, and should therefore 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 emissions, 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 fac-
tors influencing the completeness of combustion are temperature, time, and tur-
bulence. These are sometimes referred to as the "three T's of combustion," and
need to be given careful consideration when evaluating existing or proposed com-
bustion processes, as well as designs for new installations.
Each combustible substance has a characteristic minimum ignition temperature
which must be attained or exceeded, in the presence of oxygen, for the oxidation
reaction to proceed at a rate which would qualify it as combustion. Above the igni-
tion temperature heat is generated at a higher rate than its losses to the surroun-
dings 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 particle in the high-
temperature region should exceed the time required the combustion of that particle
to take place. This will therefore set constraints on the size and shape of the fur-
nace 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 raising 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 essential for
efficient combustion processes. Inadequate mixing of combustible gases and air in
the furnace can lead to emissions of incomplete combustion products, even from
an otherwise properly sized unit with sufficient oxygen. Turbulence will speed up
the evaporation of liquid fuels for combustion 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 combustion rate by decreasing availability of oxygen to the surface reaction.
2-1
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Proper control of these four factors — oxygen, temperature, time, and tur-
bulence—are necessary in order to achieve efficient combustion with a minimum of
air pollutant emissions. This chapter will concentrate on the combustion fun-
damentals associated with theoretical air and thermochemical 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
equilibria will also be discussed in general terms. Subsequent chapters will discuss
the applications of these principles to the burning or oxidation of specific com-
bustible 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 combustible 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:
(2.1)
- x CO2+—H2O
z Z
2 0.21 2 2
where Q represents the heat of combustion.
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 reducing air
requirements;
• fuel contains no combined nitrogen, so no "fuel NOx" is produced;
• "thermal NOx v'a tne nitrogen fixation is small, so that it is neglected in
Stoichiometric air calculations;
• sulfur in fuel is oxidized to SO2 with negligible SO) 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.
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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 combustion of
methane, C//^, using Equation 2.1.
Referring to Equation 2.1, for CH^: x = 1; y = 4; z = w = 0.
Thus balancing the combustion equation gives:
(2.2) CH4 + 2O2+2x3.76N2 - CO2 + 2H2O+ 7.52 N2
(2.2a)
moles or relative
volumes: 1+2 + 7.524-1 + 2+7.52 Error
total air flue products —
(2.2b)
mass: 16 + 64 + 211-44+36 + 211
(2.2c)
mass/ 211 F
combustibles: 1+4+ =13.108=13.19-2.75 + 225+1319 or
16 0.75%
The above expression gives not only the theoretical air requirements in terms of
moles or volume, Equation 2.2a, and mass (2.2b, c), but it also permits the deter-
mination of the resulting combustion products which the flue needs to handle.
Attachment 2-1 (page 2-14) 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 example and
all substances listed in Attachment 2-1, the x, y, z, and w indices have interger or
zero values in the generalized combustion equation, Equation 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 these cases the x, y, etc.
indices may take on fractional values and the general chemical formula is in-
dicative only of the relative abundance of the atomic species rather than of any ex-
act molecular architecture. However, Equation 2.1 could still be used —even with
2-3
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non-integer coefficients. The indices in the chemical formula for a mixture can be
obtained from its ultimate chemical analysis by dividing the percent (by weight) of
composition of each of the constituent elements by their respective atomic weights.
After having thus established the formula for the fuel, one could then apply Equa-
tion 2.1 to make the desired combustion calculations. "
It is often easier, however, to incorporate the conversion from (he ultimate
analysis to the chemical formula of the fuel into a general expression which gives
the amount of air required. One such expression frequently used with solid and
liquid fuels is:
(2.3) M^=11.53 C + 34.34 (H2-~ O2) + 4.29 S
8 i
where MA>t is the mass of stoichiometric air per unit mass of fuel, and C, H2, O2,
and 5 now represent the weight fractions, i.e., percent/100, of carbon, hydrogen,
and sulfur in the fuel, respectively. Note that the numerical coefficients in Equa-
tion 2.3 are the same as the mass (pounds) of air per mass (pounds) of com-
bustibles 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 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, V^t, also in standard cu.ft., is:
(2-4) VAt = 2.38 (CO + H2) + 9.53 CH4+\6.68 C2H6+\4.29 C2H4
11.91 C2H2 + ... +7.15 H2S-4.16 °2
where the molecular symbols now represent the volume fractions of the indicated
components, and the numerical coefficients are again found in Attachment 2-1,
but this time from the "mole per mole of combustibles or cu. ft. per cu. ft. com-
bustibles" column. Should the gas mixture obtain other combustible substances not
already included in Equation 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
Equation 2.4.
The products of complete combustion are CO 2, H2O, SO2, and N2 from com-
bustion 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:
2-4
-------
(2.5) MC02=3.66 C
M
1 ik ;k
26.41
where the atomic and molecular symbols once again represent the weight fraction
of the respective constituents in the fuel, and:
H2O* is the weight fraction of water in the fuel as moisture, and
Af2** is the weight fraction of N2 in the fuel as nitrogen.
Note also that any moisture in the combustion air needs to be added to the
theoretical combustion products from Equation 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 condi-
tions 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 pro-
portional to the absolute pressure, p.
(2.6) t,*=Z=/?Z
n p
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, Equation 2.6. Values of R for
some more frequently used sets of units are listed in Attachment 2.2 (page 2-15).
According to Equation 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 indicator of the relative numbers of
molecules or moles involved. Molar volumes of ideal gases at several such "stan-
dard" conditions are given in Attachment 2.3 (page 2-16). The ideal gas law, Equa-
tion 2.6, is quite adequate for the gas phase pressure-volume-temperature relations
in most combustion processes. 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, nor-
mally close to one atmosphere, the volume of gases at some other temperatures can
be calculated using Charles' law:
2-5
-------
Tl
(2.7) Vi = VQ [ —
Note that one needs to use absolute temperatures, either degrees Rankine (°F +
460) or Kelvin (°C + 273.15) in Equation 2.7. Charles' law is merely a special
application of the ideal gas law by taking the ratio of Equation 2.6 written at con-
ditions 0 and 1 for a fixed amount of gas (UQ-UI) at constant pressure (pQ-pl)-
Boyle's law, Equation 2.8, relates the volume to pressure at constant temperature
(TQ= Tj) and amount of gas (n,Q = ni), and can also be obtained from Equation 2.6.
(2.8)
Pi
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, pj, 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. Dalton's law states that the total pressure, p, exerted by a
mixture is the sum of the partial pressures of each of its components:
(2.9) P = Zpi = PA+PB + Pc+ .....
[nzT
— p '
n \ ?
Flammability Characteristics of Gases and Vapors
A homogeneous mixture of a combustible gas and air is said to be flammable if it
can propogate 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 con-
centrated (combustible-rich limit) end of the flammable range is the upper flam-
mability 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 propogation or sustained combustion.
Above the upper flammability limit, there is less than the necessary amount of
oxygen, with the result that the flame does not propogate due to the local deple-
tion of oxygen, thus causing the temperature, and hence the oxidation rate, to
drop below the levels required for sustained combustion.
The rate of flame propogation 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
propogation rate is maximum at or near the stoichiometric mixture composition,
and drops off to zero at the upper and lower explosive limits.
2-6
-------
Attachment 2-4 (page 2-17) is typical of the effect of temperature on the limits of
flammability. Here TL is defined as the lowest temperature at which a liquid com-
bustible 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 (page 2-18). 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 exother-
mic reaction. Energy, which is released as the result of rearranging chemical
bonds, can be utilized for power generation, space heating, drying, or for air pollu-
tion abatement, just to mention a few applications. Thermochemical calculations,
which are the subjects of the next several secctions of this chapter, are concerned
with the heat effects associated with combustion. These calculations permit deter-
mination 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 chapters. The efficiency of a combustion
installation reflects how well the designer succeeded in this respect. The percent ef-
ficiency 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 thermochemical calculations, one
needs to be able to determine the fuel heating values, heat contents on 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 combustible
substance with oxygen to form CO2, ^O (and SC>2) as the end products,
with both the reactants starting, and the products ending at the same condi-
tions, usually 25°C and 1 atm.
Gross or Higher Heating Value—H^Q 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.
Net or Lower Heating Value—HV^ or LHV—Similar to the higher
heating value except that the water produced by the combustion is not con-
densed 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.
2-7
-------
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) pur-
poses. The difference between the gross heat input to a combustion chamber
and all the losses.
According to a heat balance, energy outflow from a system and accumulation
within the system equals the energy input to the system. For steady-state operations
the accumulation term is zero. Therefore:
i
(2.10) Heat In (sensible + HHV) = Heat Out (sensible + latent + available)
Attachment 2-6 (page 2-19) illustrates the various quantities in the heat balance
and their interrelations. The length of each bar (Parts 2-6.b, d) represent 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 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 temperature 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 temperature, the higher
these losses are, and the less heat remains for useful work. Conversely, the extrac-
tion 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, howe/er, 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) combustion is not instantaneous and some heat
losses to the surroundings are likely to occur, and (b) at temperatures above about
3,000°F some CC?2 and -f^O w^ begin to dissociate absorbing some heat. Note
that preheating fuel and combustion air permits the generation of higher
temperatures 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, all because of the
absence of flue gas nitrogen heat losses.
Attachment 2-6 is rather idealized and should be used only in a qualitative sense.
For example, no radiation or conduction (through furnace walls) is considered.
The boundary between the sensible and latent heat contributions cannot be
segregated as sharply as indicated —condensation will occur over a range of
2-8
-------
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 content of
exiting combustion products. Consider a general case where the stack gases are
made up of n components, the quantities of each, mj, having been determined
earlier in this chapter
The total mass flow rate of the stack gases rh{0f (Ib/hr) is:
(2.11)
z = 1
Assuming no latent heat effects (no phase changes), the enthalpy of each compo-
nent hj (Btu/lb) at temperature T2 is:
(2.12) >
where Cp { = specific heat of i-th component, Btu/lb F and
TQ = reference temperature for enthalpy (h-0 at T= TQ), °F.
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 calcula-
tions. Heat contents at intermediate temperatures can be obtained by linear inter-
polation.
Enthalpy of a mixture, hm^x (Btu/lb), at T2 is then:
n n
(2.13) hmix= L xi h; = L xjCpj(T2-T0)
i=l i=l
where xj is the weight fraction of component i in the mixture, i.e., xj = mi/m-tot
and L xj= 1.0.
Any latent heat effects need to be accounted for by adding terms such as
(mj \i), is the latent heat of vaporization (condensation) of the z'-th component.
The total flue loss, qflue ]oss (Btu/hr), is then the sum of all the enthalpies of
the stack gas components:
(2.14) q
The sensible heat input by air and fuel can be calculated by an equation analogous
to Equation 2.14 and is:
(2.15) qfud> air = (T1 - TQ) L bj Cpj
where Tj is the fuel and air inlet temperature, and the subscript j represents input
components.
2-9
-------
With the higher (gross) heating value of the fuel, Q// (Btu/lb fuel), the available
heat, Qj± (Btu/hr), from this installation will be:
(2.16) QA = ™fuel QH + 3/uel, air ~ qflue losses
Note again that the above has not included any radiation or conduction losses.
Should these occur, they need to be subtracted 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 combus-
tion 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 giv-
ing 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 Btui 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 at higher air/fuel ratios (excess air). The
exact location of this minimum depends not only on the degree of mixing of the
fuel and combustion air, but also on the characteristic burning rate of the par-
ticular fuel. Recommended excess air quantities for an optimal combustion effi-
ciency 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 concentrations 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 Equation 2.1. All reactions are considered to be rever-
sible to some extent. How far a reaction proceeds depends on the relative rates of
the forward and reverse reactions. Consider a reaction where reactants A and B
form products C and D:
2-10
-------
(2.17)
A+B - C + D
From the law of mass action, the rates of reactions are proportional to the concen-
trations of reactants. Hence the forward rate, rj; is:
(2.18) rj=kj[A][B]
and the reverse rate:
(2.19) rr = kr[C][D]
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:
(2.20) .kf[A] [B]=kr[C] [D]
It is now convenient to define an equilibrium constant K:
„ kf [C][D]
(9 9]\ K= — = ———~
(2'21) kr [A][B]
The equilibrium constant, K, is a function of temperature through the temperature
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 concentration 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 is formed from the reactants. This com-
plex 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 activa-
tion energy, 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 represents the total number of
molecules in the system. The energy spectrum is a function of temperature, and
shifts to a higher energy level as temperature increases (e.g., dashed curve at
2-11
-------
Only these molecules which are in energy states equal to or higher than the transi-
tion state will be able 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 Tj. Therefore, 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 Attach-
ment 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 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 increase. The bottom half of Attachment 2-14 illustrates how a catalyst
increases the reaction rate through an increased &-value at constant temperature,
or that the same rate could be obtained with catalyst at a higher l/T (or lower
absolute temperature, T).
Practical applications of the above are found in the catalytic incineration of
combustible gases and vapors discussed in Chapter 13. Temperatures 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:
(2.22) C + -^-02-CO
^ *•
With additional oxygen the carbon monoxide can be converted to CO2:
(2.23)
Even gaseous fuels, such as methane, could produce pollutants wnen burned with
too little oxygen:
(2.24) CH4 + 02 - C (S0ud) + 2H20
2-12
-------
The solid carbon particles can agglomerate resulting in smoke and soot. Somewhat
more oxygen, but still less than theoretical, could lead to carbon monoxide forma-
tion by the following reaction:
(2.25) CH4 + — O2 - CO + 2 H2O
LJ
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 burn-
ing process, as a result of inadequate mixing or turbulence, (b) the flame is
chilled too rapidly, and/or (c) the residence time is too short. These "3 T's of Com-
bustion" 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,
Cleveland, 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).
2-13
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-------
Attachment 2-2. Ideal (perfect) gas law
pv _
= R
where p = absolute pressure
v =molal volume
T=absolute temperature
- R —universal gas constant
Selected values of R:
R = 1545.33-
10.73-
Ib-mole °R
psia-ft3
Ib-mole °R
0.7302-
1.987
at m -ft3
Ib-mole °R
cal
g-mole °K
82.06
8.315
atm—
g — mole °K
Pa-m?
kg — mole °K
2-15
-------
Attachment 2-3. Molar volumes of ideal gases at standard conditions
Standards
Universal
Scientific
Natural Gas
^ Industry
Temperature
Pressure
Molar Volume
0°C - 273.00 K
1 atm - 1.013 X 105 Pa
22.4 litre/g—mole
22.4 mVkg mole
359 fts/lb-mole
60 °F (520 R)
30 in. Hg
S79ft3/lb-mofe
2-16
-------
Attachment 2-4. Temperature effect on limits of
flammability in
Saturated vapor-
air mixtures
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
temperature is elevated sufficiently (to Point B) by a localized energy
source.
2-17
-------
Attachment 2-5. Limits of flammability,a lower temperature limits
, and autoignition temperatures (AIT) for selected substances^
Combustion
Acetylene
n- Butane
Carbon, Fixed
Charcoal
Bituminous Coal
Semibituminous Coal
Anthracite
Carbon Monoxide
Ethane
Ethyl Alcohol
Ethylene
Gasoline
Hydrogen
Hydrogen Sulfide
Jet Fuel (JP-4)
Methane
Methyl Alcohol
Propane
Sulfur
Formula
C2H2
C4H10
C
CO
C2H6
C2H5OH
C2H4
H2
H2S
CH4
CH3OH
C3H8
S
LEL25°C
(vol %)
2.5
1.8
12.5
3.0
3.3
2.7
1.2
4.0
4.0
1.3
5.0
6.7
2.1
2.0
UEL25°C
(vol %)
100
8.4
74
12.4
19
36
7.1
75
44
8
15.0
36
9.5
TL
(°C)
-72
-130
-187
-102
247
AIT
(°C)
305
405
340
400
465
450-600
515
365
490
270-440
400
a A f\
240
540
385
450
aFlammability is for mixtures of combustibles in air at standard pressure and temperature.
2-18
-------
Part 2-6.a
Attachment 2-6. Furnace heat balance relations
/x*""
/
Air £>•
Fuel I >
"*x.
\
\
\
Furnace >C~~i 1
\
\
X
P /
OUT:
^ • .
•1 Ul
^
System boundary
Part 2-6.b
Part 2-6.C
Part 2-6.d
OUTPUT
Flue
Latent 1
i
Ad abatic
gas losses
Sensible
flame temperature
Available
heat
H
<
ft
»
eu
S
w
H
60 °F Ref.
INPUT
Flue gas temperature
, .
REACTANTS
GROSS H.V.
ENTHALPY
GROSS HEATING VALUE
Air
&
Fuel
2-19
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------- An error occurred while trying to OCR this image.
-------
Attachment 2-9, Available heats for some typical fuels
140,000
I I I I II II 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 sura of the moisture loss
and the dry flue gas loss at any particular exit gas temperature may be evaluated by subtracting the
available heat from the gross heating value. Note that all available 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.
2-22
-------
Attachment 2-10. Generalized available heat chart for all fuels at
various flue gas temperatures and various excess combustion air^
(Refer to 60°F)
200
400
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.
2-23
-------
Attachment 2-11. Variation in furnace losses with air-to-fuel ratio4
S
'e
I
J3
Poor mixing
mummmi^mm
Good mixing
Radiation and wall losses
Chemically correct
•Air-fuel ratio
2-24
-------
Attachment 2-12. Rate of chemical reactions
Reactants
Activated
complex
Products
C + D
E?
V
W
No. of molecules
Rate: R + k[A][B]
No. of molecules
React, vel. const. k = function of T, AE, ...
2-25
-------
Attachment 2-13. Temperature effect on reaction rate
Arrhenius equation:
Logk
k = a e
AE
RT
Where:
k = Reaction velocity constant
a = Frequency
AE = Activation energy
R = Gas constant
T = Absolute temperature
Slope= -
AE
2.303 R
l/T
2-26
-------
Attachment 2-14. Effect of catalyst on reaction rate
A+B
C + D
'ADS^
Logk
1/T
2-27
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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 con-
ditioning.
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 remaining 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.
The heating value of fuels may be determined experimentally in devices which
operate at either constant volume (bomb calorimeter) or constant pressure (con-
tinuous flow gas calorimeter). Because of the possible loss of energy due to expan-
ding 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 pro-
ducts of combustion are cooled to standard temperature and the water vapor is
condensed.
The lower heating value is energy released when products of combustion 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 concentration (%
volume) of gases or vapors in air below which flame propogation 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
3-1
-------
maintain waste gas or vapor concentrations at less than 25% of the lower flam-
mability limit. It is important to provide oxygen-free storage with delivery of the
material to a combustion system where oxygen is added and the combustion con-
trolled. 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 illustrated in
Attachment 3-1. Natural gas is the typical gaseous fuel burned. 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 hydrogen 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 may be liquefied
under moderate pressure (80 to 200 psig). This is a considerable advantage in ship-
ping considerations, because the chemical energy storage on a volume basis is con-
siderably increased. LPG is composed of blends of paraffinic (saturated) hydrocar-
bons such as propane, isobutane, and normal 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 carboniza-
tion 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 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.
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 equipment are
described in Attachment 3-3. Note that No.2 fuel oil is the distillate 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.
3-2
-------
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.
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:
141-.5
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 atomiz-
ing 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. Explo-
sions 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 techniques 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 sample 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).
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 SO2 which is emitted with the flue gas. Some of the sulfur,
however, may produce acidic emissions which cause dew-point problems and corro-
sion of the metal furnace surfaces (economizers, air heaters, ducts, etc.) Sulfur can
3-3
-------
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.l, 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 diesel 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 hi the combustion zone. The distillation
temperatures for different fractions of the fuel provide an indication of fuel
volatility. A low 50% distillation 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 operation 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 nondepositing and noncorrosive.
For variable-speed and variable-load gas turbines special fuel specifications 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 (rnin), and a very
low aromatic content. It is similar to the Jet A and JP-1 fuels, as indicated in At-
tachment 3-8. Aircraft turbojets operate at high altitudes with low air
temperatures; therefore, fuel freezing, volatility, and boiling temperatures are im-
portant requirements (4).
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, relative to other fuels.
Control of air pollution emissions from coal may include the techniques of fuel
modification, combustion modification, and flue gas cleaning.
As illustrated in Attachment 3-9 and 3-10, coal is generally classified as an-
thracite, 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.
Because the composition and properties of coal are variable, depending on the
source, standard sampling and laboratory procedures have been established by
ASTM.
As illustrated hi 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
mositure, volatile matter, fixed carbon, 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 temperature. 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 decomposition (combined water) and water of hydration, which
are part of the volatile matter in the proximate 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 stan-
dard temperature. It is composed of hydrocarbons and other gases from distillation
and decomposition.
Fixed carbon is the combustible fraction remaining after the volatiles are
removed. The ash is the noncombustible residue remaining after complete combus-
tion of the coal. This is not to be confused with fly ash, which is airborne par-
ticulate 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 removed mechanically by gravimetric techni-
ques. 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 destructive heating of coal in the absence of air.
Attachment 3-13 illustrates the fact that the properties of coke depend on the cok-
ing 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
maybe required for proper combustion of wood wastes.
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).
3-5
-------
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 composition 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. New York (1951).
8. Obert, E.F., Internal Combustion Engines and Air Pollution, 3rd Edition, Intext Educational
Publishers, New York (1973).
3-6
-------
Attachment 3-1. Analyses of samples of natural gas2
Sample No. 12345
Source of Gas Pa. So. Cal. Ohio La. Okla.
Analyses
Constituents, % by vol
H2 Hydrogen _ _ 1.82 — _
CH4 Methane 83.40 84.00 93.33 90.00 84.10
C2H4 Ethylene — 0.25
C2H6 Ethane 15.80 14.80 — 5.00 6.70
CO Carbon monoxide —' — Q.45
CO2 Carbon dioxide — 0.70 0.22 0.80
N2 Nitrogen 0.80 0.50 3.40 5.00 840
02 Oxygen _ _ 0.35 — _
H-jS Hydrogen sulfide — — 0.18
Ultimate, % by.wt
S Sulfur __ o.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 0.636 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
3-7
-------
Attachment 3-2. Selected analysis of gaseous fuels derived from coal2
Analyses, % by vol
H£ Hydrogen
CH4 Methane
C2H4 Ethylene
CO Carbon monoxide
CC>2 Carbon dioxide
N2 Nitrogen
O2 Oxygen
C5H5 Benzene
H2O Water
Specific gravity
(relative to air)
Higher heat value — Btu/cu ft
@ 60F & 30in. Hg
@ 80F & SOin. Hg
Coke-oven
gas
47.9%
33.9
5.2
6.1
2.6
3.7
0.6
—
• —
0.413
590
Blast-furnace
gas
2.4%
0.1
—
23.3
14.4
56.4
—
—
3.4
1.015
—
83.8
Carbureted
water gas
34.0%
15.5
4.7
32.0
.4.3
6.5
0.7
2.3
—
0.666
534
Producer
gas
14.0%
3.0
—
27.0
4.5
50.9
0.6
—
—
0.857
163
Reprinted with permission of Babcock & Wilcox
3-8
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Attachment 3-4. Typical analyses and properties of fuel oils*
Cr.de
Type
Color
API gro»ity. 60 F
Specific grovity, 60 '60 F
Ib per U S gallon, 60 F
Viscoi., Centistokes. 100 F
Viscoi., Soybolt Univ., 100 F
Viscos , Saybalt Furol, 122 F
Four point, F
Temp, for pumping, F
Temp, for atomizing, F
Carbon residue, per cent
Sulfur, per cent
Oxygen and nitrogen, per cent
Hydrogen, per cent
Carbon, per cent
Sediment and water, per cent
Ash, per ceit
Btu per gallon
Ne 1
Fuel OH
Distillate
(Kerosene)
light
40
0.8251
6870
1 6
31
—
Below zero
Atmospheric
Atmospheric
Trace
0 1
02
132
865
Troce
Trace
137.000
Ne 1
Fuel OH
Distillate
Amber
32
08654
7206
2.68
35
—
Below zero
Atmospheric
Atmospheric
Trace
04-07
02
127
86.4
Troce
Trace
141.000
Ne 4
Fuel Oil
Very light
Residual
N.I. 5
Fuel Oil
light
Risidue)!
Black Black
21
09279
7727
15.0
77
~~
10
15 min.
25 min.
2.5
0.4-1. J
0.48
11 9
86 10
0.5 max.
002
146.000
»7
0 «52»
7 »35
50 Cl
232
.10
15 min.
no
.1.0
2.0 max.
0.70
11 7
8.155
1 0 max.
005
1 411,000
Ne. 6
Fuel Oil
Residual
Black
12
0 9861
8.212
360.0
170
100
200
12.0
2.8 max.
092
8570
2.0 max.
• 008
150.000
• Technical information from Humble Oil I Refining Company.
Reprinted with permission of Combustion Engineering
3-10
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Attachment 3-7. Diesel fuel oil specifications?
Requirements
Cetane rating, min
Flash point, min. °F
Pour point, max. °F
Viscosity, min-max. SU see 100 °F. . .
API. min
ASTM distillation, °F, 10%, max. . .
90%, max, or min-max
C on 10% bottoms, percent, mass. . . .
Ash, percent, mass
Water, sediment, percent, vol
Sulfur, percent, mass
Distillate fuel oils
1
100
0
30-34
35
420
550
0.15
Trace
ID
40
100
30-34
550
0.15
0.01
Trace
0.50
2
100
20
33-38
30
540-640
0.35
0.10
2D
40
125
33-45
540-675
0.35
0.02
0.10
1.0
4
130
20
45-125
0.10
0.50
4D
30
130
45-125
0.10
0.50
2.0
Residual fuel oils
5
130
350-750
0.10
1.00
6
150
900-9000
2.00
Attachment 3-8. Aviation turbine oils?
Requirement
Designation
Flash point, °F (min-max). .
Freezing point, °F (max)
Gravity, API (min-max). . . .
Vapor pressure, Reid psig
(min-max)
Distillation, °F
1 0 percent max . .
20 percent max ...
50 percent max
90 percent max
EP max
Heating value, lower,
(Btu/lbm) min
Sulfur, (percent by mass)(max)
Smoke point, t mm (min)
Aromatics, vol. percent, (max).
Potential gum,
mg/ 100 ml (max)
ASTM D1655
Jet A
110-150
-40 +
39-51
400
450
550
18,400
0.3
25
20
14
Jet B
-60
45-57
0-3
290
370
470
18,400
0.3
20
14
Mil-J-5624
JP-1
HO(min)
-76
3.5(max)
410
490
572
18,300
0.2
20
8
JP-3
-76
50-60
5-7
240
350
470
18,400
0.4
25
14
JP-4
-55
45-57
2-3
290
370
470
18,400
0.4
25
14
JP-5
140(min)
-65
36-48
400
550
18,300
0.4
20
25
14
JP-6
-67
37-50
18,400
0.4
25
14
Mil-F-4600A§
CITE- 11
3
200
325
550
0.4
25
14
3-13
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Attachment 3-12. Example coal analyses2
Component Weight, % Component Weight, % Component Weight, %
Moisture (Free)
Volatile matter
Fixed carbon
Ash
Total
Heating value,
Btu/lb
2.5
37.6
52.9
7.0
100.0
13,000
Moisture (Free)
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash
Total
2.5
75.0
5.0
2.3
1.5
6.7
7.0
100.0
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash
Total
76.9
5.1
2.4
1.5
6.9
7.2
100.0
Reprinted with permission of Babcock & Wilcox
3-17
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Attachment 3-15. Analyses of hogged fuels!
Kind of fuel
Moisture as received Percent
Moisture air dried "
Proximate analysis, dry fuel
Volatile matter Percent
Fixed carbon
Ash
Ultimate analysis, dry fuel
Hydrogen Percent
Carbon
Nitrogen
Oxygen "
Sulfur
Ash
Heating value, dry Btu per Ib
Western
Hemlock
57.9
7.3
74.2
23.6
2.2
5.8
50.4
0.1
41.4
0.1
2.2
8620
Douglas
Fir
35.9
6.5
82.0
17.2
0.8
6.3
52.3
0.1
40.5
0
0.8
9050
Pine
Sawdust
. 6.3
79.4
20.1
0.5
6.3
51.8
0.1
41.3
0
0.5
9130
Reprinted with permission of Combustion Engineering
3-20
-------
Attachment 3-16. Typical analyses of bagasse 1
Cuba
Hawaii
Java
Mexico
Peru
Puerto Rico
Percent by weight
Carbon
C
43.15
46.20
46.03
47.30
49.00
44.21
Hydrogen
H2
6.00
6.40
6.56
6.08
5.89
6.31
Oxygen
N2
47.95
45 90
45.55
35.30
43.36
47.72
Nitrogen
N2
—
-
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
8681
9140
8380
8386
Lower
7402
7538
8043
8548
7807
7773
Atmos. air at
zero excess air
Ib per 106 Btu
625
687
651
667
699
625
CO^ at zer
excess air
percent
?] 0
20 3
20 1
'9 4
>
'•) 5
Reprinted with permission of Combustion Engineering
3-21
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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, inlcuding 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
abatement, 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
cosideration, at least in the past.
The design of a combustion system includes the selection of a fuel and the hard-
ware 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 considertion. Thermodynamic prinicples govern the basic
energy release 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 varous parts. Fans must be sized to overcome the resistance 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 economic configuration within the imposed restraints of the desired
energy conversion rate and the environmental quality. The economic consideration
includes hardware first-cost, the availability and cost of the fuel, and other system
operating and mainteriance'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 concerned 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 Attachment 4-2.
4-1
-------
Design Methodology
Design methodology is essentialy a process whereby each of the several system com-
ponents is sized and detailed. Against this backdrop of complexity suggested above,
it is reasonable to ask what the flow-diagram of the design process looks like. In
general terms, such a flow-diagram might include the following:
a. Determine the quality 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 determina-
tion involves several secondary but important aspects.
For example:
1. Thermal efficiency of the unit is determined by minimizing 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 products
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.
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 residence 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 2-6).
Adiabatic flame temperatures (see page 2-8), 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 importance. This can be accomplished by:
4-2
-------
a. Using excess air in amounts 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% //2> 0-92%
O2, 2.8% S, 0.8% ash, and a net heating value, H, of 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 transfer) with
stoichiometric air;
Case 2. Stoichiometric air, and 5% energy loss from the furnace to the
surroundings.
b. Excess air or heat transfer necessary to achieve 2,200°F furnace
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).
(4.D
= 11.53 C+ 34. 34(7/2- — j + 4.29 S
8
For the No. 6 fuel oil given here, Equation 4.1 is
At= 11. 53(0. 857)+ 34. 34(0. 105- - ) + 4.29(.028)
8
= 13.57-lbair
Ib oil
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 combustible matter actually
burned. The mass of flue gas produced is therefore:
my G = (mf- mNC) + mfAt
4-3
-------
The noncombustibles, mNC, here are either the ash in fuel or the ash together with
the unburned combustible in solid form. Gaseous unburned components would re-
main part of the flue gas. With one pound of fuel as a basis (mj-= 1), F for the No.
6 oil specified here becomes:
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 temperature, ta^, from
(4.3) H . ,
tad G Cp a
where ta is the combustion air intake temperature. For the oil under consideration,
tad computed using Equation 4.3 with ta= 100°F is
17,620 +10o = 4,270°F
aa 14.57(0.29)
Note that this temperature is considerably greater than the furnace materials 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. Equation 4.3 must be
modified by the loss term,, Q^, to yield the nonadiabatic furnace temperature, tf,
as given by
(4.4) H
tf=
J
G C
Here, with QL = 0.05 H, the furnace temperature is
H-.05H 0.95(17.620) +10Q = 4()610F
f 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.
4-4
-------
Solution to Case 3:
The third alternative purposes imposing a limit to the furnace temperature, 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).
The applicable energy relationship is given by
(4.5) ff=GfCp(tf-ta)+QL
Now if the ^=2,200°F condition is imposed on the system and assuming Cp = 0.29
Btu/lb °F as before Gf can be calculated from
(4.6) Gf= H~^ = 0-95(17.620) = 27 49 Ibs
J Cp(tf-ta) 0.29(2,200-100)
The excess air needed to reduce the temperature is then
Ib air
AE=Gf- G = 27.49 - 14.57 = 12.92
Ib fuel
or
= (12. 92/13. 57)xlOO% = 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 transferring energy to
some useful purpose while limiting the excess air to the amount required for com-
plete combustion. The governing energy equation for this case becomes
(4.7) H= Gf Cp(tf- ta)
4-5
-------
is the energy to be transferred in order to maintain the furnace temperature at
tf. Rearranging Equation 4.7:
(4.8)
Gf Cp(tf- to)
Recalling that Case 4 prescribes 10% excess air
where ^£=0.10X 13.57 = 1.36
.
Ib fuel Ib fuel
-\
and substituting the appropriate numerical values into Equation 4.8 gives
Q^ = 17,620 - 0.05 (17,620) - (14.57 + l.S6)(.29)(2,200 - 100)
= 16,739-9,701 = 7,038 Btu/lb fuel
Here Q^ 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 alternatives for con-
trolling the furnace temperature to use a great deal of excess afr or to use some
appropriate heat transfer surface to remove sufficient energy from the combustion
gas to effect a control of temperature. The use of excess air alone as a control is
wasteful of energy and should be avoided whenever possible. This potentially
wasteful aspect is also evident when considering the utilization of the energy
remaining in the combustion products after they leave the furnace.
Energy Utilization in Nonfurnace Regions
Further utilization of energy, represented by the elevated temperatures of gases
leaving a furnace, has a significant impact on the overall combustion system .
thermal efficiency, 77, defined as:
(4.9) Oj
OH
Qjf is the energy total input to, the system given by
(4.10)
4-6
-------
and Qs, the total energy transferred for a useful purpose, is given by
(4.11) Qs = mqs
where qs 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, Q^. Additional losses occur in the regions
through which the gas must flow upon leaving the furnace. A major loss is due to
the heat content of flue gases leaving the system. This loss, Q/g, arises from the
fact that the flue gas stack temperature, tfo, is higher than ambient and is
expressed as
(4.12) Qfg = Gf Cp(tfg - tamb)
Equation 4.12 indicates that Q/> is directly proportional to the total mass of the
flue gases, Gf, the specific heat of the gas and the difference 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, tfa, is also apparent. In almost
all combustion energy utilization devices, it is impractical to reduce tfo to iamb-
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 enregy balance relationship.
Input: HHV
Losses: EQ/ow =
Available (utilized) energy: qs = QM +
Note that in terms of the net heating value of the fuel, H, the energy balance
would become
H = HHV-QV
4-7
-------
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 Q^ for this unit. This is done by accoun-
ting for the energy which is added to the working fluid (water) as it passes through
the unit.
ms = 60,000 Ib/hr
Fuel, mf
HHV
Air
STEAM
GENERATOR
p = 650 psia
t = 495°F
mfg
Flue gas
Feed water
t = 320°F
Qi/
Letting ms represent the steaming rate, Q$ becomes:
(4.13) =
where hi and h,2 are the enthalpies of the entering feedwater and the output steam
respectively (obtained from steam tables). For this case
= 60,000 Ibs/hr (1,406. 0-290. 3) = 66.9
Btu/hr
,4-8
-------
This is the available useful energy represented by mj- (Q^ + Qxp). The fuel supply
rate needed to provide this energy depends on the overall efficiency, 77, which in
turn depends on the energy recovery devices incorporated into the design. Again,
with information developed Example 4.1,
(4.14) qs
ft = 17,620 -
Suppose that Q^ 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 £/-=2,200°F, while steam leaves the
Steam superheater at ts = 800 °F, and the
Steam boiler temperature tB is = 495 °F (saturation temperature at 650 psia)
The reason for listing these temperatures is to emphasize the limitations imposed by
thermodynamic and heat transfer considerations. Energy exchange 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 temperature 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 realistic rates. In any
event, temperatures lower than 800 °F for the superheater 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
Q/g = Gf Cp(tfg-tamb) = 15.93 (0.25)(700-100)
= 2,390 Btu/lb fuel
The useful energy per pound of fuel, qs, is calculated by solving Equation 4.14,
noting
= 0.05(18,640) = 930 Btu/lb
^=17,620 - QL- Qfg= 17,620 - 930 - 2,390
= 14,300 Btu/lb oil
4-9
-------
The efficiency from Equation 4.9, with Qj and Q^ each based on one pound of
fuel is
T? = 14'3°° x 100% = 76.7%
18,640
The fuel firing rate can now be determined noting that the total useful energy, Qj
is 60.33 X 10*> Btu/hr and solving for m/from Equation 4:14:
Qs 66.9X106 Btu/hr Aconlb oil
mf- — =4680
J qs 14,300 Btu hr
Ib 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 reducing the flue losses and increasing the ther-
mal 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 of extract
energy by transferring energy to the colder feedwater. Such exchange surface is
called the economizer, and, with temperatures as hypothesized here, flue gas
temperature could be reduced to 500 °F. With this lower flue gas temperature, the
flue losses, Q/g, would be reduced to 1,590 Btu/lb, qs would increase to 15,000
Btu/lb, and the efficiency would increase to 80.0%.
Continuing the design analysis, one would note "he 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 Q/g is down to 996 Btu/lb.
Now, from Equation 4.14,
qs =17,620 -932 -996 = 15,692 Btu/lb fuel
_ 15,692
and *?- —
The fuel firing rate would be '
Btu
66.9 X1Q6 hr =426Q Ibsfuel or ^ gal/hr
J 15,692 Btu hr
Ibfuel
4-10
-------
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
utilization.
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.
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 outlined above,
various heat transfer calculations are made to design the actual surface configura-
tions. Gas flows, both air and flue gases, together with fluid flow considerations,
can be used to establish fan size requirements. 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.
4-11
-------
Attachment 4-1. Energy distribution
Qfg=12.8%
JI
HHV=100%
= 76.7%
1
Energy distribution without energy recovery
Q = 5.5% QL = 5% Qfg = 5.3%
7.5% Energy
recovery by
economizer and
aiir preheater
Energy distribution with energy recovery by economizer and air preheater
4-12
-------
Attachment 4-2. Nomenclature
Symbol
Aa
AE
At
QNF
Qs
qs
Qu
Q.V
tad
Units
Ib/lb fuel
Ib/lb fuel
Ib/lb fuel
Btu/lb °F
Ib/lb fuel
Ib/lb fuel
h
H
HHV
mf
mNC
ms
Qfg
OH
QL
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
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 s 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 of fuel
Energy loss due to latent heat of the
water vapor formed by combustion
Combustion air temperature
Adiabatic flame temperature
Ambient air temperature
Furnace temperature
Flue gas temperature
4-13
------- An error occurred while trying to OCR this image.
-------
Chapter 5
Pollution Emission Calculations
INTRODUCTION
Combustion sources constitute a significant air quality control problem because of
the gaseous and paniculate 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 conditions 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 pressure 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 classifications: concen-
tration standards, pollutant mass-rate standards and process-rate standards.
Federal ambient air quality standards are examples of concentration standards
where allowable limits are set forth in micrograms per cubic meter at ts = 25 °C and
ps = 760 mm Hg. Pollutant mass rate standards fix the 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 standards for fossil-fired steam power plants
are an example of an energy basis standard. Allowable emissions for such opera-
tions 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 stan-
dard. Such incinerators are limited to paniculate 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 difference must be
made. Consider one cubic foot of gas at some specified condition, say 14.7 psia and
70 °F. Does this volume increase or decrease if one raises the gas temperature? Ask
5-1
-------
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):
(5.1) P0V0
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:
P V
(5.2) ° ° = MR = constant
o
Recalling the questions posed above, no gas was added or removed in the specula-
tion 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
(5.3) -^ =MR
s
and MR can be eliminated by equating 5.2 and 5.3 to give
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, Vo, measured
at temperature, To, and pressure, Po, would occupy volume, Vs, if measured at
conditions Ts and Ps as can be seen from a solution of equation 5.4.
— (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
(5.5) P0= MRTo = QoRT0
Rearrangement of equation 5.5 yields:
(5, g) = R = constant
QoTo
5-2
-------
Repeating the reasoning employed above for the case of volume, the density of a
gas at new conditions denoted by subscript s is:
Qs=Qo
(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:
(5.7)
_ moles of product _ _ g moles of product
- — £ — 1 U
10" moles of air 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 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.
Tr.
= 22.4
273
=24.5 liter
In turn, there are 10 ^ meters/liter and the mass of the moles of product is:
molecular weight X gm/mole.
Combining these conversions:
/^
i h/h _ moles product MW rgm/mole~^-
24.5 liter 10-3
[—1
L liter J
(5.8)
Example: SO2
10-3
24.5
m
=40.8
gm
ppm SO2 = 40.8(64) =
m
5-3
-------
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 com-
pared 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 in-
creased by adding non-pollutant gas to the stream. For example, consider the ideal
combustion of carbon monoxide with air
(5.9) CO + — O2 +1.88 N2~CO2 + 1.88 N2.
2
Here, the percentage of CO2 in the flue gas is:
1
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:
/ 1 \ 1
(5.10) CO + 2 [ —O2} +2(1.88 N2)~CO2+—O2 + 3.76 N2
\ 2 / ~ 2
Now the total moles of product is given by:
1 mole CO2 H mole O2 + 3.76 mole N2 = 5.26 moles
2
and CO2= — = 19.0% by volume.
5.26
Here the volume fraction of CO2 was reduced by adding more air, in effect a dilu-
tion 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:
(5.11) CO2 + 1.88 A/2 + 2 moles steam
5-4
-------
Now there are 4.88 moles of product and the CO2 percentage would be
CO2 = - =20.5% by volume.
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 equip-
ment 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 absorp-
tion device with separate chambers to remove CO2, CO, and O2 from the flue gas
m 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:
Consider the complete combustion of carbon with air:
(5.12)
C+O2 + 3.76 7V2-CO2 + 3.76 N2
Here the product contains only CO2 and N2. With excess air, the reaction
becomes:
C+(l+a) 02 + (l+a)3.76 N2~
+ (l+a) 3.76 A/2
where a is the number of moles of excess O2 in the excess air. By definition, the
percent of excess air is:
(5.14) %EA = Actual Air -Theo Air
X 100%'
Theo Air
The theo air is O2 + 3.76 N2 from equation 5.12 with the actual air (1+a)
(l +a) 3.76 N2 as given by equation 5.13. Combining equations 5.12 5 13
and 5.14:
X10Q%
5-5
-------
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, assum-
ing complete combustion. Noting product with a subscript p:
(5.16)
where O2p = aO2, the excess oxygen provided, and N2p 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, the ac-
tual O2 supplied can be determined by computing the moles O2 which were
associated with N2p. Assuming air is 20.9% O2 and 79.1% N2 by volume, the
oxygen supplied is given by:
(5.17) 0.264 N2p = 02 supplied
(5.18) The theoretical O2 is 0.264 N2p- O2p
(5.19) and the %EA = °2P X 100%
0.264 N2p-O2p
If the combustion produced both CO and CO2 (case of incomplete combustion),
the O2p measured must be reduced by the amount of oxygen which would have
combined with CO to form CO2.
Then:
(5.20)
In each case, the quantity introduced is the percentage of each constituent as
measured by the Orsat analyzer.
Example:
Orsat Analysis
CO2 = IQ%
CO=1%°
by difference:
N2 = 100 - (10 + 4 + 1) = 85%
5-6
-------
Find % EA from equation 5.20:
%EA = 4 °'5^ x 100% - 18.3%
0.264 (85)-(4-0.5 (1))
One caution must be mentioned regarding the CC>2 measurement as determined
by an Orsat analyzer. The chemical, caustic potash, employed to absorb CO2 also
absorbs SC>2- Therefore, SC>2 must be measured separately from CO2 and the
percentage SC>2 determined must be subtracted from the observed CC>2 reading.
Also, the cuprous chloride solution used to absorb CO also absorbs C>2', therefore, a
sample which is not correctly analyzed could erroneously indicate 02 f°r 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% CO2
and 6% <>? are presented in Attachment 5-4 (Equations 1 through 13). Applica-
tion 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%; C>2 = 8.2%; CO=O
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; QS = 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% C>2
5-7
-------
3
pq
to
-a
e
I
H
1.0
.3
.2
.1
.05
.01
z1
_
II Illl — 1 1 1 III 1 HIM — TTTT
II 1 HIM — 1 Illl"
^^
- H = Total heat input in millions of Btu per
~
-
_
1 1
E = Maximum emissions in
Btu heat input.
E= 0.8425 H-°-2314(H =
i i ii ii i i i 1 1 1 i 1 1 in i MI
1.0 10 *
1 I 1 Mil 1 1 1 1 II 1 1 Illl II
^-^_
hour.
1 II Ii
-
~
pounds of paniculate matter per million ~
25 to 10,000)
1 1 i 1 1 in I i i 1 1
100
i i mil MM ii
1000 10,000
-
-
Ill 1 L
10
.35 25
H, total heat input, million Btu/hour
Figure 5.1. Allowable paniculate emissions from fuel burning equipment
5-8
-------
Solution
A. Pollutant mass rate (PMR), Tons/day:
i na it / • w 60 ram 24 /jr Ton „, „ Tons
103 Ibs/mznX x x = 74 2 •
2000
B. Concentration-mass and volume basis
V0 dry = 367,000(1- 0.0625) -344,062 acfm
. = PMR 103
V°~ V0 ~ 344,062
Using Equation 2, Attachment 5-3
103 29.92 756
-X X
344,062 28.49 530
dscf dscf
C =c — x fi3 x 100° = 6-12 lb
ms VS ft3 0.0732 lbm 1000 ~ 1000 lb
C. % Excess air in effluent using Equation 1, Attachment 5-4.
Q* ri * ' ^p ' X?x
~ 0.264 N2p-(02p- 0.5 C0p)
= (8.2-0)(100) ^6
(0.264 (81.1)-8.2 =
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.
50"
= 1_ f 1.5 (0.082)-0.133 (0.811)
0.21
] ._
J "
5-9
-------
°-928
= 3.38
Me
f 1-50'02p-0.133 N2*-0.75 COp ]
*- £ £- = 0.<
L 0.21 J =
29
".930
Cfne fi 1 2
= 6.56 /ft/1000 Ib dry
y
0.930
E. Correction to 12% CO2 is accomplished with Equations 6 and 7,
Attachment 5-3.
Cvs Cv (0.12) r o
=0.14
v C02/0.12 C02, 0
= 3.52
.l2 ]
.107 J
dscf
F. Correction for 6% O2 is:
0.21-0.082
C6v= = 3.69
6U 0.85 =
Example 5.1 clearly illustrates how one applies corrections for temperature,
pressure and excess air. The emissions in this sample were expressed as a concen-
tration 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.
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.
5-10
-------
Solution:
A. Find the process energy rate, H
H=mass of coal x energy value per unit mass
= 23-^-xl2,500^-x 20°° b
hr Ib ton
= 575xl06 Btu/hr
B. Find the allowable emission rate from Figure 1.
From graph @ H= 575 X 106 Btu/hr
£ = 0.19 pounds/106 Btu -0.2314 Ib
or calculate from £=0.8425(575) =0.194
106 Btu
C. Now find actual particulate weight rate
I800gm/secx lb x 3600 — (1-0.99)
454 gm hr
575 x 106
hr
Btu
0.25 >0.19. Therefore, this unit does not conform.
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 pollutant
mass rate, expressed in terms of volume flow rate and concentration is given by:
(5.21) PMR = CVS Vs
The emission rate, E, in terms of the energy input H is:
(5.22) E= = —&—£
H H
5-11
-------
Consider the ratio VS/H, the ratio of gas volume flow to energy input in terms of
basic combustion chemistry. For theoretical combustion, the volume Vs 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 com-
pute the volume flow, Vs, in terms of the theoretical volume (stoichiometric) and
an excess air correction. Defining the theoretical volume of combustion gases as
Vst, the volume V5 is:
(5.23)
and equation 5.22 becomes
(5.24)
s f excess air ~\
correction I
• J
E=C
excess air
correction
The F-factor is defined as:
(5.25) ' Fd = ~^
and the excess air correction is given by:
(5.26)
\20.9-02p]
L 20.9 J
Substitution of Equations 5.25 and 5.26 into 5.24 yields:
20.9
20.9-
The terms in Equation 5.27 are Cvs, the dry basis concentration corrected to stan-
dard conditions; the excess air correction based on the percent C>2 in the sampled
gas; and Frf, 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 composition and higher
heating value H, the factor Fj is given by:
(5.28)
[3.64 H2+1.53 C + 0.57 S + 0.14 AT2-0.46 O2]
HHV
106-
dscf
106 Btu
5-12
-------
The values for H2, C, S, N2, O2 an<^ tne percentages of each element are taken
from the ultimate analysis, here Fj is noted as the F-factor when dry O2 percen-
tage was used as the measure of excess air. Should one choose to use CO2 as the in-
dicator of excess air, a factor Fc is used where:
(5.29)
and
(5.30)
cvs Fc
100
C02p
[321x103]
HHV
"VS
Ibs
106 Btu
dscf
106 Btu
Cvs, as used in Equation 5.29, can be either wet or dry basis depending on whether
CO2p 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 O2 is the
measured excess air indicator. A correction similar to that discussed earlier is
appropriate as follows:
(5.31) Excess air correction =
and Equation 5.27 becomes:
20.9-
(02p
-0.5 CO
20.9
(5.32)
Fd
20.9
COp)
Loss of combustible (unburned carbon in coal ash for example) represents a reduc-
tion of actual input energy. F-factor assumes all energy released and since E is pro-
portional to \/HHV, calculated E is smaller than the actual. Removal of CO2 by
wet scrubbing also introduces errors where Fc or Frf 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.
5-13
-------
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 calcula-
tions of gross inventory for a large number of sources are involved, 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 com-
pared to design capacity, and particulate entrainment is reduced because of lower
gas velocity.
The emission factors are essentially process emission rate values expressed 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
If one burns 6 tons/hr of coal with A = 10% and a heating value HHV of 12,500
Btu/lb in a spreader stoker fired boiler, the uncontrolled emission rate is:
x (10)- 130 Ibs/ton
ton v ' '
and the pollutant mass rate is:
PMR = 130-^- x 6-^- = 780 Ib/hr .
ton hr
Conversion of the emission rate from Ibs per ton to Ibs per million Btu is as follows:
Btu
HHV= 12,500-
Ib
= 12,500^- x 2,000-^- = 25 x 106 Btu/ton .
lb ton
5-14
-------
Therefore, £=130-^-X - - - = 5.2
- - - - .—
ton 10 tu
ton
The degree of control required for a source performance standard of 0.1
Ibs/lO^Btu would be determined as follows:
collected x 1QO% = Input-Allowable
Input Input
5-2 °'1 xlOO% =
5.2
This would be an estimate only. More precise emission data for a specific unit
would be desirable.
The SC>2 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 S02- 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 SO2 reduction is calculable, again provided the sulfur appearing as SOj
can be predicted. The 38S emission factor is a valid first approximation of the
uncontrolled SO 2 to be expected. Using the coal in Example 5.3 above with 1.3%
sulfur, the following can be seen.
Example 5.4
Compute SO 2 emission per 10^ Btu for the coal in Example 5.3.
ton
(PMR)SO, = 49.4-^- X fr = 296.4
^ ton hr hr
*„ A lb ton , _.„ Ib
= 49.4 - x - = 1 .98-
ton 25X106 Btu 106 Btu
New source standard for SC>2 is 1.2 lb/10^ Btu which would require
reduction of SO2 in the flue gas.
Similar calculations of uncontrolled emissions are possible using factors for HC,
NOX.
5-15
-------
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 Determining Emissions from
Combustion Sources," Source Evaluation Society Newsletter, (November 1976).
5-16
-------
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 250 million Btu/hr.
A. Particulates: 0.10 Ib per 106Btu 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 NOX
Gaseous Fuel
Liquid Fuel
Solid Fuel
, S02
lb/106 Btu
—
0.80
1.20
kg/106kj
—
0.345
0.520
lb/106
0.20
0.30
0.70
NOX
Btu kg/106kj
0.09
0.13
0.30
2. Solid waste incinerator: charging rate in excess of 50 Tons/day.
Particulate emission standard 0.08 grain/dscf (0.18 g/m^) corrected to 12%
C02.
3. Portland cement plants: maximum 2 hour average particulate emission of 0.30
Ib/ton (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: max-
imum 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.
5-17
-------
Attachment 5-2. Nomenclature for equations of Chapter 5
Symbol
Cv
E
EA
F
H
HHV
a
M
MW
P
PMR
R
T
V
Q
Concentration, mass basis
Concentration, volume basis
Process emission
Excess air
Correction factor; F-factor
Energy rate
Higher heat value
Volume flow rate
Mass
Molecular weight
Pressure, absolute
Pollutant mass rate
Gas constant
Temperature, absolute
Volume
Density
Subscripts
e
P
m
o
s
V
effluent
product
mass basis
observed conditions
standard conditions
per-volume basis
5-18
-------
Attachment 5-3. Gas volume corrections
Volume
Concentration
Density
5-19
(2)
(3)
-------
Attachment 5-4. Excess air corrections
Determination of Excess Air
,.
%EA = —=• x 100% (1)
0.264 N2p-(02p-0.5 COp)
Factors for Correction to 50% EA
ri.502*-0.133 A-0.75 CO
- -
01
"I
J
29 [ 1.502^-0.133
"1"
C™ (5)
Factor For Correction to 12% CO?
.^t • (•)
0.12
Me 0.12
F12m
5-20
-------
Factor For Correction to 6%
0.21-
02p
0.15
C6v =
29
C6m =
-0.06
(10)
(11)
(12)
(13)
5-21
-------
Attachment 5-5. F-Factors for various fuelsa»b
Fuel Type d
Coal
Anthracite
Bituminous
Lignite
Oil
Gas
Natural
Propane
Butane
Wood
Wood Bark
Paper and Wood Wastes
Lawn and Garden Wastes
Plastics
Polyethylene
Polystyrene
Polyure thane
Polyvinyl Chloride
[scf/10b Btu scf/10
10140
9820
9990
9220
8740
8740
8740
9280
9640
9260
9590
9173
9860
10010
9120
(2.
(3
(2
(3
(2
(2
(2
(1
(4
(3
(5
.0)
.1)
•2)
.0)
•2)
•2)
•2)
.9)
•1)
.6)
-0)
1980
1810
1920
1430
1040
1200
1260
1840
1860
1870
1840
1380
1700
1810
1480
bBtu
(4.
(5
.1)
.9)
(4.6)
(5
(3
(1
(1
(5
(3
(3
(3
.1)
.9)
.0)
.0)
.0)
.6)
.3)
.0)
1.070
1
1
1
1
1
1
1
1
1
1
1
1
1
1
.140
.0761
.3461
.79
.51
.479
.05
.056
.046
.088
.394
.213
.157
.286
(2.9)
(4
(2
(4
(2
.5)
.8)
•1)
.9)
(1.2)
(0
(3
(3
(4
(2
.9)
•4)
.9)
.6)
-4)
Garbage 9640 (4.0) 1790 (7.9) 1,110 (5.6)
aNumbers in parentheses are maximum deviations (%) from the midpoint F-Factors.
bTo convert to metric system, multiply the above values by 1.123 X 10'4 to obtain scm/106 cal.
Source: R.T. Shigehara et al., "Summary of F-Factor Methods for Determining Emissions from
Combustion Sources," Source Evaluation Society Newsletter, Vol. 1. No. 4, November 1976.
5-22
-------
Appendix 5-1
(The following pages 5-23 through 5-70 are exerpts from AP-42
which relate to combustion sources)
COMPILATION
OF
AIR POLLUTANT EMISION 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
5-23
-------
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, B.C.
Publication No. AP-42
5-24
-------
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
10* liters) of residual fuel oil, and 22 trillion cubic feet (623 x I012 liters) of natural gas were consumed in the
United States.1
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 Revised by Robert Rosensteel
and Thomas Lahre
1.1.1 General
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 bum 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
1.1.11 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
5-25
-------
Table 1.1-1 gives the range of collection efficiencies for common types of fry-ash control equipment. Particulate
emission factors expressed as pounds of participate per ton of coal burned are presented in Table 1.1-2.
1.1.2.2 Sulfur Oxides11 - 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.12nd z.
*>Th« maximum efficiency to be txpecwd for this collection device applied to thit type source.
EMISSION FACTORS
4/73
5-26
------- An error occurred while trying to OCR this image.
-------
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. 255:337-345, 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. 7.5:426, 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
/0(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. 14:267-278,
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. 76:362-366, July 1966.
9. Anderson, D. M., J. Lieben, and V. H. Sussman. Pure Air or Pennsylvania. Pennsylvania Department of
Health. Hanisburg, Pa. November 1961. p. 91-95.
10. Communication with National Coal Association. Washington, D. C. September 1:969.
II. Private communication with RJ>. Stem, Control Systems Division, Environmental Protection Agency.
Research Triangle Park, N.C. June 21.1972.
II 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-%. May 1971.
EMISSION FACTORS 4/76
5-28
-------
1.2 ANTHRACITE COAL COMBUSTION revised by Tom Lahre
1.2.1 General M
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 characterized 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-f ired 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 considered 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-f ired 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
5-29
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limited information suggests these devices may be up to 75 percent efficient on paniculate Flyash rein-
jection, frequently employed in traveling-grate (token to enhance fuel-uae efficiency, tends to in-
crease paniculate emissions per unit of fuel combusted.
Emission factors for anthracite combustion are presented in Table 1.2-1.
EMISSION FACTORS 4/77
5-30
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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-
rania Department of Environmental Resources. Harrisburg, Pennsylvania. July 9, 1976.
5 Ca»s, R.W. and R.M. Broadway. Fractional Efficiency of a Utility Boiler Baghouse: Sunbury
Steam-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 Fi-ed 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
5-32
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1.3 FUEL OIL COMBUSTION by Turn Laftrt
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 sometimes 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 Particulates3"6' !2'13 - 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)1"5 - 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 SO^, 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
5-33
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1.3.2.3 Nitrogen Oxides (NOX) ' -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 oik, 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, s':aged 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 *' 5> ' l4 - 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 tuning 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
5-35
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1.3.3.3 Flue Gas Cleaning6' l l - 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 of .paniculate. 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 fiyash 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 S02 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. Cincinnati!, 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. 36(247): 24888-24890,
December 23,1971.
8. Bartok, W. et al. Systematic Field Study of NO* Emission Control Methods for Utility Boilers. ESSO
Research and Engineering Co., Linden, NJ. 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, NJ. 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.l 13-145.
10. Deffner, J.F. et al. Evaluation of Gulf Econpject Equipment with Respect to Aii Conservation. Gulf
Research and Development Company. Pittsburgh, Pa. Report No. 731RC044. December 18,1972.
EMISSION FACTORf 4/76
5-36
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11. Blakeslee, C.E, and H.E. Burbach. Controlling NOX Emissions from Steam Generators J Air Pol Contro'
Assoc. 23:37-42, January 1973.
12. Siegmund, C.W. Will Desulfurized Fuel Oils Help? ASHRAE Journal. ]]: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. 27:781-782, 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.
External Combustion Sources
5-37
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1.4 NATURAL GAS COMBUSTION ***** b*
1.4.1 General 1.2
Natural gas has become one of the major fuels used throughout the_country. I^^J«^< ^
Because natural gas in its original state is a gaseous, homogenous fluid, its combustion is simple and can be pre-
cisely " roUeT Common excess air rates range from 10 to 15 percent; however, some hige umts , op«£ rt
eSssTrates as low as 5 percent to maximize efficiency and minimize mlxogen oxide (NO,) 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-
hJ£T reacu?n For eSmple improper operating conditions, including poor mixing, insufficient air, etc., may
produced in the combustion process.
oxides are the major pollutants of concern when burning natural gas. Nitrogen oxide emissions are
?£ emp^ rature in the combustion chamber and the rate of cooling of the combustion product .
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-
^^
« «
-------
Table 1.4-1. EMISSION FACTORS FOR NATURAL-GAS COMBUSTION
EMISSION FACTOR RATING: A
Pollutant
Particulatesa
Sulfur oxides (SO2>b
Carbon monoxidec
Hydrocarbons
(as CH4)d
Nitrogen oxides
(N02)e
Type of unit
Power plant
Ib/106ft3
5-15
0.6
17
1
700*-b
kg/1 06 m3
80-240
9.6
272
16
11,200f-r>
Industrial process
boiler
Ib/106ft3
5-15
0.6
17
3
(120-230)'
J 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.
LOAD, percent
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
5-39
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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 31,197}.
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. ;0:34-43, 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. 14:271,
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.
Battellfc-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. Blakeske, C. E. and H. E. Burbock. Controlling NOX Emissions from Steam Generators. J. Air Pollution
Control Assoc. 2?:3742, January 1973.
14. Jain, L. K. et al. "State of the Art" for Controlling NO, 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|R. J. Fortman. Status of Control Techniques for Achieving Compliance with Air 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
5-40
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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 kcal/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 Publishine Co
1962.
External Combustion Sources
5-41
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1.6 WOOD/BARK WASTE COMBUSTION IN BOILERS Revised by Ttiomas Ljhrs
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^
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.
1.63 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 SO percent moisture) wood
waste that results in relatively few particulate emissions when properly burned. Still other operations, such as
sawmills, burn a variable mixture of bark and wood waste that results in particulate emissions somewhere in be-
tween these two extremes.
Fry-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
bum the volatiles that account for most of the combustible material in the waste. When proper drying conditions
5/74 External Combustion Sources
5-43
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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.
Tabte 1.6-1. EMISSION FACTORS FOR WOOD AND BARK WASTE COMBUSTION IN BOILERS
EMISSION FACTOR RATING: B
Pollutant
Particulates*
Bartcb.c
With fly-ash reinjectiond
Without fly-ash reinjection
Wood/bark mixture0'8
With fly-ash reinjectiorrd
Without fly-ash reinjection
WoodU
Sulfur oxides (S02)h-'
Carbon monoxide!
Hydrocarbons1*
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
These emission factor* were determined for boilers burning gas or oil as an auxiliary fuel, and it was assumed all particulates
resulted from the waste fuel alone. When coal is burned 0* en auxiliary fuel, the appropriate emission factor from Table 1.1-2
should be used in addition to the above factor.
'These factors based on en as-fired moisture content of 50 percent.
CReference* 2.4.9.
''This factor represents a typical dust loading reaching the control equipment for boilers employing fly-ash reinjection. The value
jii parenthesis represents emissions after the control equipment assuming an average efficiency of 80 percent.
•Reference*?, 10.
*IWs waste includes dean, dry (5 to 50 percent moisture) sawdust, shavings, ends, etc., and no bark. For well designed and
operated boilers use lower value and higher value* for others. This factor is expressed on an as-fired moisture content basis as-
suming no fly-ash reinjection.
QReferenca* 11-11
"This facto; 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.
'Reference* 1, 5, 7.
JThis factor is based on engineering judgment and limited data from references 11 through 13. Use lower values for well designed
and operated boiler*.
'This factor n based on limited data from references 13 through 15. Use lower values for well designed and operated boilers.
1 Reference 10.
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
5-44
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3. C-E Bark Burning Boilers. Combustion Engineering, Inc., Windsor, Connecticut. 1973.
4. Barron, Jr., Alvah. Studies on the Collection of Bark Char Throughout the Industry. TAPPI. .5.7(8): 1441-144£
August 1970.
5. Kreisinger, Henry. Combustion of Wood-Waste Fuels. Mechanical Engineering. 61:115-120, February 1939.
6. MagiU.P.L.etal. (eds.). Air Pollution Handbook. New York, McGraw-Hill Book Co., 1956. p. MS 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. under Contract No. CPA-22-69-119. April 1970 o 2-47 to
2-55.
8. Mullen, J. F. A Method for Determining Combustible Loss, Dust Emissions, and Recirculated Refuse for a
Solid Fuel Burning System. Combustion Engineering, Inc., Windsor, Connecticut.
9. Source test data from Alan Lindsey, Region IV, U.S. Environmental Protection Agency, Atlanta Georria
May 1973. '
10. Effenberger, H. 1L et al. Control of Hogged-Fuel Boiler Emissions: A Case History. TAPPI. 5
-------
1 .7 LIGNITE COMBUSTION & Thomas Lahre
1.7.1 General14
is a eeoloocallv voune coal whose properties are intermediate to those of bituminous coal and peat. It
has ai moSSontLt (Ts'to 40 percent, b'y weight) and a low headng value (6000 to 7500 Btu/lb wet
bSis) and is generally only burned close to where it fc mined, that is, in the midwestern States centered abou
North Dakota and in Texas. Although a small amount is used in industrial and domesuc situations. lignite^
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«oal-fired or cyclone-fired boilers.
The major advantage to firing lignite is that, in certain geographical areas, it is plentiful relativelyJ°^n "f;
and low in sulfur content (0.4 to 1 percent by weight, wet basis). Disadvantages are that more fue and larger
facilities are necessary to generate each megawatt of power than is the case with bituminous coal. »>ere are
Sveral reasons for thL First, the higher moisture content of lignite means that more energy is lost in the gaseous
owSheatng va^ore fuel must be handled to produce a given amount of power because lignite « no
oeneLflv cleaned o dried prior to combustion (except for some drying that may occur in the crusher or
Serizer anHuring sequent 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~*
•n, • 11 tants of concern when firing lignite as with any coal, are participates, sulfur oxides, and
nitrogtn^Sdes0 Hydrocarbon and carbon monoxide ernissions are usually quite low under normal operating
conditions.
Paniculate emissions appear most dependent on the firing_configuration in the, boiler
come into contact with the boiler surfaces.
SrProdu« Te lowest NcT 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 NOX emissions.
sulfate salts.
12/75 External Combustion Sources
5-46
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Ail friu,ii;.«..n 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 effect 99+ percent paniculate 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 EQUIPMENT3
EMISSION FACTOR RATING: B
Pollutant
Particulateb
Sulfur oxides*
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
7.0A<1
30S
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
"All 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 perticulate 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 (NajO > 8 percent) use 17S Ib/ton (8 5S
kg/MT); for a low sodium-ash lignite (Na20 < 2 percent), use 35S Ib/ton (17.5S kg/MT). For intermediate sodium-ash ligrme 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 NC>2. Factors based on References 2, 3, 5, 7, and 9.
9 Use 14 Ib/ton (7 kg/MT) for front-wall-fired and hor.zontally 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-f,red
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
12/75
5-47
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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, NJ). 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 UJS. 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 Ail Quality Planning and Standards,
Research Triangle Park, N.C. 1974.
12/75 External Combustion Sources
5-48
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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). FueJ 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, wh^re 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 overf ired air is supplied to complete combustion. This kind of boiler requires bagasse with a
higher percentage of fines, s moisture content not over 50 percent, end more experienced operating
personnel.
1.8.2 Emissions and Controls1
Paniculate 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 paniculate 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
5-49
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Table 1.8-1. EMISSION FACTORS FOR UNCONTROLLED BAGASSE BOILERS
EMISSION FACTOR RATING: C
Paniculate0
Sulfur oxides
Nitrogen oxides6
Emission factors
Ib/I03|b steam8
4
d
0.3
g/kg steam3
4
d
0.3
Ib/ton bagasse*1
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 mill* 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 tha 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 I
c Multi-cyclone* 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.
•Based 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
4/77
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1.9 RESIDENTIAL FIREPLACES by Tom Lahrf
1.9.1 General1.*
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 fay natural draft, and may be controlled, to some extent, by a damper located in the chim-
ney directly above the firebox. It ia 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 walk
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, and
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)* 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
5-51
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Table 1.9-1. EMISSION FACTORS FOR RESIDENTIAL FIREPLACES
EMISSION FACTOR RATING: C
Pollutant
Particulate
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Carbon monoxide
Wood
Ib/ton
2Qb
Od
If
59
120"
kg/MT
10b
Od
0.5*
2.59
60"
Coal3
Ib/ton
3QC
36Se
3
20
90
kg/MT
15C
36S«
1.5
10
45
*AH coal emission factors, except paniculate, ore beted on data in Tabto 1.1-2
of Section 1.1 for hand-find units.
bThi» induces condensable paniculate. Only about 30 percent of this i» filter-
able paniculate as determined by EPA Method 5 (front-half catch}.4 Based
on limited data from Reference 1.
eThi» includes condensable paniculate. About 50 percent of this is filterable
paniculate as determined by EPA Method 5 (front-half catch).4 Based on
limited data from Reference 1.
dBased on negligible sulfur content in most wood.3
*S is the sulfur content, on a weight percent basis, of the coal.
*iBased on data in Table 2.3-1 in Section 2.3 for wood waste combustion in
(conical burners.
9 Nonmethane 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 Fir, .'places for Emission Factor Development
Valentine, Fisher and Tomlinaon. 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. PrimlanL 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-WasteFuels.Mech«nicalEngineering.il: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. 3J>
(247): 24888-24890, December 23, 1971.
EMISSION FACTORS
4/77
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2. SOLID WASTE DISPOSAL
Revised by Robert Rosensteel
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.
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.
Z 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
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2.1 REFUSE INCINERATION Revised by Robert Rosensteel
2.1.1 Process Description1-4
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 MT)
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 participate
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 nozztes 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
5-54
------- An error occurred while trying to OCR this image.
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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.
11.3 Emissions and Controls1
Operating conditions, refuse composition, and bask 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 underfue 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/4 Emissions of oxides of sulfur tre 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 tone, an increase in *he 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 PABTICULATE CONTROL SYSTEMS'
Type of system
Settling chamber
Settling chamber and water spray
Wetted baffles
Mechanical collector
Scrubber
Electrostatic preciprutor
Fabric filter
E;ff iciency, %
Oto30
30 to 60
60
30 to 80
80 to 95
90 to 96
97 to 99
*R*ftf«ncM3.5,6.and 17 through 21.
EMISSION FACTORS
5-56
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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. Danieison, J.A. (ed.). Air Pollution Engineering Manual. U.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^: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. Fernandas, 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. OAP 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.
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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
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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.^ 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 INCINERATION*
EMISSION FACTOR RATING: B
Pollutants
Participates6
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.
cBased on data for open burning and References 2 and 5.
dReference 3.
4/73
Solid Waste Disposal
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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, PM. Air Pollution from Disposal of Junked Autos. Air Engineering. 10:18-22, November 1968.
4. Private communication with D.F. Walters, UJS. DHEW, PHS, Division of Air Pollution. Cincinnati, Ohio. July
19,1963.
5. Gentle, R.W. and D.A. Kemnitz. Atmospheric Emissions from Open Burning. J. Air Pol. Control Assoc.
77:324-327. May 1967.
EMISSION FACTORS
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2.3 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
Particulate 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
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References for Section 2.3
1. Air Pollutant Emission Factors. Final Report. Resources Research Inc. Reston, Va. Prepared for National Air
Pollution Control Admimstration, Durham, N.C., under Contract Number CPA-22-69-1 19. April 1970.
in
Pl""'': Hea"h SetViCe' BU"aU °f S°M WasK Ma°»8«m=nl. Cincinnati. Ohio.
" state
Engineerln8 Expeitaent station' Ore8°n siatt
7. Netzley, A.B. and J.E. Williamson. Multiple Chamber Incinerators for Burning Wood Waste. In- Air Pollution
^
of AireSanita"d ° C^T ^ ^^ °f ^ Sampling and Analysis for toe Evaluation of Teepee Burners. Bureau
Air Pollution Studies, Los Angeles. January 1965.) " rence on e hods in
9. Boubel R.W Paniculate Emissions from Sawmill Waste Burners. Engineering Experiment Station Oregon
State Uruversay, Corvallis. Bulletin Number 42. August 1968. p.7,8. P^nmenc station, uregon
Solid Waste Disposal
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2.4 OPEN BURNING
2.4.1 General1
revised by Tom Lahre
and Pom Canova
Open burning can be done in open drum* 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 Emissions'-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 24-1. EMISSION FACTORS FOR OPEN BURNING OF NONAQRICULTURAL MATERIAL
EMISSION FACTOR RATING: B
Municipal refuse"
Ib/ton
kfl/MT
Automobile
b c
components '
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
•Raftrancst 2 through 6.
y. pah*. hons. and tirst bumad in common.
Emissions from agricultural refuse burning are dependent mainly on the moisture content of the
refuse and, in the ease of the field crops, on whether the refuse is burned in a headf ire or a backfire.
(Headfires *re 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
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Table 2.4-2 (continued). EMISSION FACTORS AND FUEL LOADING FACTORS FOR OPEN BURNING
OF AGRICULTURAL MATERIALS*
EMISSION FACTOR RATING: B
Refuse category
Orchard crops0' •
(continued)
Nectarine
Olive
Peach
Pear
Prune
Walnut
Forest residues
Unspecified111
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
(8fC6H14)
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
'Factors expressed as weight of pollutant emitted per weight of refute materiel burned.
^articulate matter from mott agricultural refute burning ha* been found to be in the wbmicronrwtar size rang*.12
References 12 and 13 for emission factors; Reference 14 for fuel loading factors.
dFor these refuse materials, no significant difference exists between emissions resulting from hwedfiring or backfiring.
*The*e factors represent emissions under typical high moisture conditions. If ferns are dried to lew than 15 percent
moisture, participate emissions wilt 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 is not important.
When headf ired above 20 percent moisture, paniculate 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.
*Thit factor is for dry (<15 percent moisture) ricattraw. If rice strew 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).
hSee 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, include* another
technique used occasionally for limiting emissions, called into-the-wind ttriplighting. which involves lighting fields in
strips into the wind at 100-200 m (300-600 ft) intervals.
^Orchard pruning* 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 pruning* are bulldozed onto e bed of embers from a preceding fire.
'if orchard removal is the purpose of a burn. 30 ton/acre (66 MT/hectare) of wane 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.
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Solid Waste Disposal
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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
*These factors are an arithmetic average of the results obtained by burning high- and tow-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% olefim. 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. Gentle, 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. Weisburd, M.I. and S.S. Griswold (eds.). Air Pollution Control Field Operations Guide: A Guide
for Inspection and Control. U.S. DHEW, PHS, Division of Air Pollution, Washington, D.C PHS
Publication No. 937. 1962.
EMISSION FACTORS
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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. 79:497-500, 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 Service*, 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 o' 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.
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2.5 SEWAGE SLUDGE INCINERATION By Thomas Lahre
2.5.1 Process Description 1-3
Incineration 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
gises. and then burned as it moves slowly down through the lower hearths. At the bottom hearth any residual
>h 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 600°F
( >:0°C) in the lower, ash cooling health; 1400 to 2000°F (760 to 1100°C) in the central combustion hearths,
.md 1000 to 1200°F (540 to 650°C) in the upper, drying hearths. Temperatures in a fluidized bed reactor are
f urly uniform, from 1250 to 1500°F (680 to 820°C). In both types of furnace an auxiliary fuel may be required
: thcr during startup or when the moisture content of the sludge is too high to support combustion.
1.5.2 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 TTuidized 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
liearths. but are readily removed when afterburners are employed. Odors are not generally a problem in fluid-
ved bed units as temperatures are uniformly high enough to provide complete oxidation of the volatile com-
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
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Table 2.5-1. EMISSION FACTORS FOR SEWAGE SLUDGE INCINERATORS
EMISSION FACTOR RATING: B
— . . •
Pollutant
Paniculate6
Sulfur dioxide*1
Carbon monoxide8
Nitrogen oxides'1 (as N02)
Hydrocarbons*1
Hydrogen chloride gas*1
Emissions •
Uncontrolled19
Ib/ton
100
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/Ml
1.5
0.4
Neg
.5
0.5
0.15
•Unit weights in term* of dried sludge.
b&timeted from emission factor* afw scrubbers.
((Reference 8.
•References 6, 8.
References for Section 2.5
1. Calaceto.R.R. Advances in Fly Ash Removal with Gas-Scnibbing Devices. Filtration Engineering. jf(7):12-15,
March 1970.
2. Balakrishnam, S. et al. State of the Art Review on Sludge Incineration Practices. US. Department of the
Interior, Federal Water Quality Administration, Washington, D.C. FWQA-WPC Research Scries.
3. Canada's Largest Sludge Incinerators Fired Up and Running. Water and Pollution Control /07(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. 703(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, Detrc.it, Michigan. 1973.
8. Source test data from Office of Air Quality Planning and Standards, US. Environmental Protection Agency,
Research Triangle Park, N.C. 1972.
9. Source test data from Dorr-Oliver, Inc., Stamford, Connecticut. 1973.
EMISSION FACTORS
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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 Genera-
tion and Use, Babcock & Wilcox Company, 39th Edition,
1978.
INTRODUCTION
This chapter presents a brief overview of the logic that governs combustion con-
trols. Emphasis is placed on the overall purpose of control, and several examples of
logic-sequencing are presented. Instrumentation is discussed, 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 par-
ticular end use. The most common application is to generate steam for electric
power production or for a multitude of other manufacturing 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 example 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 rates can only be
altered through corresponding changes of input energy. Control of the thermal
energy source requires realization of two major objectives:
1. Maintain high combustion efficiency at all energy input rates and do so
while maintaining emissions which are within acceptable 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 temperature 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 demand 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.
6-1
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Process applications may require control of both rate of energy supply and
temperature. Where heat exchange is employed, temperature control may be possi-
ble 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 examples of this kind of system.
Combustion Control
The general requirements outlined above can be translated into more specific
requirements for combustion control systems. All combustion systems 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 solution 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 decrease 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.
This aspect of the combustion control problem can be pinpointed by considering
a system which suddenly receives fuel having a higher moisture content than nor-
mal. 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 capability. An example is a coal-fired unit designed to operate on
eastern coal that has been switched to high-moisture western coal. The flame
temperature 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.
6-2
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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. Loan 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 tabulated in Attachment 6-1.
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 controller 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 Attachment 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 con-
troller 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 con-
troller. 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.
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 (sum-
mation 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 parallel 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
6-3
-------
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 equivalent 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 minimum safe operating load. This
maintains sufficient burner nozzle velocities at all times and assures the primary
and total air-fuel ratios are continuously controlled at prescribed levels.
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 maintain the proper fuel-air
relationship. This air flow is automatically compensated 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 incor-
porated, 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 reasons. 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 operation requires the operating per-
sonnel to have a working knowledge of pressures, temperatures, and flows
throughout the system. Accurate records of fuel flows, steam or gas flows, power,
etc., are required in order to calculate and control operating costs. For a given
plant burning selected fuels, predetermined instrument values can assist crews in
maintaining proper combustion. Instruments 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 guidance 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 rendered into cost analyses,
6-4
-------
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-steam
weighing
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 devices 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
d. Miscellaneous equipment where temperature measurement is impor-
tant, such as direct flame afterburner combustion chambers, veneer
dryers, etc.
5. Flue gas analysis
a. CO2 and C>2 meters aid combustion control
b. SC>2 and NOX meters aid in proper emissions evaluation and control.
6-5
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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 nor-
mally 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,
NY (1978).
2. Morse, F. T., Power Plant Engineering, 3rd Edition, D. Van Nostrand Company, New York,
NY (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., "CO2 Measurements Can Correct for Stack-Gas Dilution," Chemical Engineering
(January 31, 1977).
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 Com-
pany, Cleveland, Ohio (1978).
6-6
-------
Attachment 6-1. Control symbols 1
Table 1
Control Symbols
O —Transmitter
K—Propotional action (gain)
j — Integral action
E — Summing action
A—Difference or subtracting action
< — Low select auctioneer
> — High select auctioneer
> — Low limiting
< —High limiting
d/dt—Derivative (rate)
E /n — Averaging
/O/—Hand-automatic selector station (analog
NX control)
—Hand-automatic selector station (analog
control) with bias
H/A—Hand-automatic selector station (digital
control)
T—Transfer
± —Bias action
f(x)— Power device, (valves, drives, etc.)
6-7
-------
Attachment 6-2. Diagram of a combustion control
for a spread stoker, fired boiler^
Steam
pressure
9
Air
flow
Steam-
pressure
error
i
r
Steam-
pressure
controller
\
Boile
maste
contro
Stoker-feed-
control drive
Steam
flow
9
Combustion-
controller
air system
Air-flow
demand
Forced
draft
Forced-draft-
fan damper-
control drive
Furnace
draft
9
Furnace-
draft
error
Set
point
Furnace-
draft
controller
Uptake
draft
Uptake
draft
6-8
------- An error occurred while trying to OCR this image.
-------
Attachment 6-4. Diagram of combustion control
for a pulverized-coal boiler 1
Firing-rate demand
Firing-rate demand
:error
to load runback
To other
, .
pulverizers
to air-flow control
1
r
Firing-
rate
error
t
Air-flow
cross limit '
^
i
Air-flow error from
r
i
Corrected
firing-rate
demand
«*
J
Fuel-flow
error
f
>-J
1
air-flow control
From other Coal_
coal, feeders feedef
^ w W speed
Tc.tal ^
coal flow
Fuel-f low error
*rO
_ ,
Pulverizer
to air-flow calibration
Minimum pulverizer loading
Pulverizer number 1
mill master
Individual pulverizer bias
I
}J
Minimum primary-air-flow limit
Primary-air-flow error r^K
Primary-air-flow control
To primary-
air damper
/
Primary
air flow
n
Low-select
auctioneer
speed error
To coal-f
speed control
6-10
-------
Attachment 6-5. Diagram of combustion control
for a cyclone-fired boiler 1
Firing-
demand
Firing
rate
to
load
runback
To
other ~«
cyclones
r
^
Correc
rate
i
ted firing-
demand
'
Minimum cyclone
firing rate
From other coal
* *
Fuel-flow ^^^ Total fl<
error ^""™" contro
feeders
*
,„ r^
' ^X>
Coal-
feeder
speed
t
/\ Cyclone
X T >
/\ S master
^ A jf Secondary-
\/^ Primary- air Air
*— -Hf airflow flow temp.
S-r\ Cyclone no. 1 ^-^ x — >. x — ^
s\ V\ A \ /^ A / \
"\AyKA/ / V J v
Individual .^«^™^M^i^™ IBIBIB i mi
cyclone bias I A ^^
\
S *
Air-flow ^ 1
cross limit
t
Feeder-
speed error
*
Feeder- ^
speed control ^^^
X TT
, r
Feeder- Flue-§
-. speed oxyg{
cross compens
limit
I 1 Cyclone-
^^^•^•^M air-flow "^
error
f
Cyclone-
air-flow
control
J speed A
Total cyclone- . ^
air flow
"IT
/^
™ K J
ation \<__^/
Ji'lue-
gas-
oxygen
analyzer
To coal-feeder speed control
To cyclone-air-velocity damper
6-11
-------
Chapter 7
Gaseous Fuel Burning
INTRODUCTION
Burning gaseous fuels is perhaps the most straightforward of all combustion pro-
cesses. 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 mixtures 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 chapter.
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 CO2 and H2O.
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 incandes-
cent at the elevated temperatures and give the flame a yellowish appearance
Eventually sufficient oxygen, if available, will diffuse into the flame to form CO?
and H20 as the ultimate combustion products. Insufficient oxygen or incomplete
combustion due to flame quenching will result in soot and black smoke
7-1
-------
Which of these two combustion mechanisms is preferable, depends on the par-
ticular application, as will be discussed later in this chapter. These theories apply
also to the combustion of fuels other than gas and again point out the importance
of understanding the effects of temperature, 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 com-
bustion air is mixed with the gas prior to ignition (see Attachment 7-1). Under nor-
mal 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 ter-
minate 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 pro-
duce a short "bushy" flame, while delayed mixing and low velocities result in long
and more slender flames.
Burning characteristics of different fuel gases are of primary importance 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 stiochiometric composition. Gases with high flame propagation
velocities, such as hydrogen, 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 Attach-
ment 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 incomplete 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
7-2
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the flame propagation velocity. The minimum 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
flashback. Theoretically the flame will be stationary at a point where the flame
velocity equals the mixture velocity in or out of the mixing tube. Actually,
however, a relatively cool burner port will also serve to stabilize the flame. Opera-
tion 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.
Considerably 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 shutting 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.
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 combustion 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, compressed 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 manufactured 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.
7-3
-------
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 disadvantage.
Long (luminous) flame gas burners are used in larger furnaces where a good por-
tion of the heat is to be transformed by radiation. Long flames are produced by
injecting a low-velocity central core of gas completely 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 furnaces, kilns, air
heaters, dryers, and similar applications where superior temperature uniformity is
required. These are sealed-in, nozzle-mix burners capable of producing a stable
flame with several thousand percent excess 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 fluc-
tuating 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 spiral, sustained stable burning can be obtained
with a mixture containing 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 configuration is used to
generate a highly turbulent vortex. A two-stage combustion process minimizes NOX
formation: 10% of the air by-passes the burner throat where the rich mixture is
burned at a relatively low temperature. 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 10f) 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).
7-4
-------
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;
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 distributed 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 the 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 con-
siderably 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 reactions. A wide furnace cannot be fired properly with
a single burner. A short furnace may require several smaller burners to prevent
flame impingement on the rear wall.
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 without the danger of flame impinge-
ment. Specially designed high intensity burners can operate quite satisfactorily at
10 X 106 Btu/hr-ft3 levels. The overall heat release rate (for complete combus-
tion) ranges from 30,000 to 70,000 Btu/hr-ft3 for more conventional gas-burning
installations.
The pressure against which a burner must operate is another important con-
sideration. Furnaces normally operate at +0.01 to - 1 inches of water column
gauge pressure. Air leaking into the furnace is preferable in most applica-
tions—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
7-5
-------
mechanized draft devices, with the latter becoming more common because they
control gas flows better. Without mechanical draft equipment, it is extremely dif-
ficult 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 gas scrubbers or heat recovery devices are used.
Operation and Control
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 unobstructed. 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 extin-
guished. 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.
Proper operation of a gas-fired installation requires that the fuel rate be con-
trolled 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 con-
trol valve. This valve can be used to control the gas flow, based on a signal from
the output of the heat exchanger. Combustion air regulation is achieved through
manipulating 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 disturbances.
Gaseous fuels pass through one or more fixed orifices before entering the com-
bustion chamber. Since flow through an orifice is proportional to the square root
of the pressure drop across it, small fluctuations 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.
7-6
-------
Failure to maintain proper air-fuel ratios can lead to operation with insufficient
air or with high excess air. The most common cause of insufficient air is inade-
quate 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
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 combustion
quality. Chemical or electrical analyzers are available for this purpose. Normal
concentration ranges of combustion products in natural gas-fired installations are:
9 — 11% CO2\ 6-3% 02' no co and H^. 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 CO2 concentration is measured, it
is possible to be misled about which side of the stiochiometric air-to-fuel ratio one
is operating.
Stack gas temperature in conjunction with its CC>2 concentration can be used to
determine the "flue losses" and hence the approximate combustion 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 par-
ticulates. Its combustion products do not pollute water. Natural gas transportation
and distribution facilities have a minimal 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 hydrocarbons. Burner
design also affects the production of the oxides of nitrogen, particularly in large
steam power plant boilers. The NOX problem and techniques for controlling it are
discussed in Chapter 16.
7-7
-------
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 insuffi-
cient amount of combustion air or an incomplete mixing of the fuel and the com-
bustion air.
It has been stated often that gas-burning installations do not produce a pollution
problem. Since areas of stable flame (Attachment 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 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 emis-
sions from gas-fired installations, efforts are now being made to increase the
average seasonal efficiencies of existing gas furnaces to about 60% and for new fur-
naces 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 Manufacturing, Cleveland, Ohio
(1952).
3. Griswold, J., Fuels, Combustion, and Furnaces, McGraw-Hill Book Co. New York (1949)
4. Waid, D. E., "Energy from Waste Gases," Chem. Eng. Progress, Vol. 74, No. 5, 77-80 (1978).
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 Installations — Design Considerations,' unpublished paper,
Forney Engineering Company, Dallas, TX.
9. "Compilation of Air Pollution Emission Factors," AP-42, Third Edition, USEPA (August
1977).
7-8
-------
Attachment 7-1. Atmospheric premix-type gas burner
Burner orifice spud
Gas manifold
Primary air, 40% (inspirated)
'•~v— Gas/air mixture —
Firing wall
Attachment 7-2. Natural gas flames with varying primary ai
66.8
63.4
60.4 57.1
Primary air
53.3
49.1
7-9
------- An error occurred while trying to OCR this image.
-------
Attachment 7-5. Selected gas burner types
Primary air supply
Venturi tube
1 Gas supply
1. Atmospheric gas burners pull in their primary
air for combustion by the action of a stream of
low-pressure gas expanding through an orifice.
2. Premising of fuel gas and air needed for com-
bustion takes place in a mixing chamber outside
the furnace proper.
3. Vanes placed in the path of incoming air to
this tunnel burner act to impart swirling motion
to stream.
Governor valve
Pilot opening
Inspirator or
manifold
connection
Mixture outlet
Gas inlet
Air inlet Insert
Spud holder
Inspirator body
Combustion
tunnel
5. So called low-pressure gas-burner systems work
with air under pressure and gas at atmospheric
conditions. An inspirator governor, left above,
delivers gas-air mixture at proper pressure to
burner blocks, right above.
Two stage inspirator action
6. Two-stage burner operates on high-pressure
gas; passes it through two venturi sections in
series. Primary air enters shutter, at left, under
induction.
Air louver control lever
Gas manifold
4. Gas issues from a number of spuds connecting
to vertical and horizontal manifolds. Primary air
enters around the spuds.
7. High-pressure gas issues from jets in the spider
and reaction spins the spider to rotate the fan.
Resulting turbulence gives prompt, thorough
mixing.
7-11
-------
Attachment 7-6. Mixing plate burner
(Maxon Corp., Muncie, IN)1
7-12
-------
Attachment 7-7. HGE Sulzer combustion burner
(Trane Thermal Co., Conshohocken, PA)6
Primary air swirler
Secondary air swirler
Fuel and automizing fluid
Combustion air inlets
Refractory lined
combustion chamber
7-13
-------
Air inlet
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
(A)
Start-up
oil inlet
Running
oil inlet
(M
O
U
v
£
~Q
Attachment 7-9. Flue gas analysis2
Poor mixing*
Good mixing*
Air deficiency
Chemically correct
Air-fuel ratio
Excess air
*Note: The differences between poor and good mixing of the fuel and air are shown by the
solid and broken lines, respectively. This chart is for qualitative comparisons only;
hence no numerical values are shown.
7-14
-------
Attachment 7-10. Flue heat losses with natural-gas-fired
installations^
600 -
500 -
400 —
300 —
250 —
200 —
150 -
100—I
\
\
\
\
\
% Flue
heat loss
50- r
40-r
30 -i:
\ ::
"20--
15- -
\
%Co2
% Excess m flue
gases
air
600 —
500 —
400 -
300 -
200 -
100-
\
50 -
\
0—
-1.5
- 2
-4
- 5
6
7
8
9
10
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% COg is
found to be 19%. Therefore, the combustion efficiency is 81%.
7-15
-------
Attachment 7-11. Emission factors for natural gas
combustion emission factor rating:
Pollutant
Participates3
Sulfur oxides (SO2)b
Carbon monoxide0
Hydrocarbons (as CH^)^
Nitrogen oxides (NO2)e
Type of unit
Power plant
lb/106ft3
5-15
0.6
17
1
700f-h
kg/106m3
80-240
9.6
272 •
16
ll,200f'h
Industrial process
boiler
Lb/106ft3
5-15
0.6
17
3
(120-230)1
kg/106m3
80-240
9.6
272
48
(1920-3680)1
Domestic and
commercial heating
lb/106ft3
5-15
0.6
20
8
(80-120)1
kg/106m3
80-240
9.6
320
128
(1280-1920)1
aReferences 4, 7, 8, 12.
bReference 4 (based on an average sulfur content of natural gas of 2000 gr/106 stdft3
(4600 g/106Nm3).
cReferences 5, 8-12.
dReferences 8, 9, 12.
eReferences 3-9, 12-16.
fUse 300 lb/106 stdft3 (4800 kg/106 Nm3) for tangentially fired units.
SAt 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 (>100
MMBtu/hr) use the NOX factors presented for power plants.
JUse 80 (1280) for domestic heating units and 120 (1920) for commercial units.
------- An error occurred while trying to OCR this image.
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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 practical 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 combustion.
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, 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 heating 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 filters 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 ade-
quate time to complete combustion (before the hot gases are quenched on the fur-
nace surfaces) are other requirements. However, if too much uneven mixing or tur-
bulence is present in the flame zone, hot spots may occur which will result in
higher NOX emissions.
During combustion of a distillate fuel oil, the droplet becomes uniformly smaller
as it vaporizes. By contrast, a residual oil droplet undergoes 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
arc not available for complete combustion, carbonaceous materials (soot) may be
deposited on metal surfaces or be emitted with smoke.
-------
Oil Burning Equipment
Oil burning furnaces or boilers are classified typically as either domestic, commer-
cial, 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 volumetric heat release rate of the smaller sized units results from the
favorable 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 between 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 con-
trol 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 typical, 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 commercial-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.
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 constructed either at the site or in
a factory, depending on the size. Generally 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 combustion 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 providing 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
8-2
-------
mixing. Electrodes provide a continuous source of ignition. Control of the oil
pump, typically, is by a thermostatically controlled on/off switch. High-pressure
atomizers for commercial and industrial applications may burn No. 4 or 5 fuel oil
(up to 200 gph) with oil pressure up to 300 psi.
A low-pressure air atomizer is illustrated in Attachment 8-6. In domestic applica-
tions, 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 applications (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 external 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 resulted in sources
changing to burners of other designs. In the rotary cup, as illustrated in Attach-
ment 8-11, an oil film inside a hollow cup (spinning at around 3,500 rpm) is sub-
jected to centrifugal forces which cause the atomization. If the cup becomes eroded
or cracked, atomization quality deteriorates.
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 Attachment 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 combusion installations.
This is dependent upon the combustion temperature and nitrogen composition in
the fuel, both of which are more favorable with smaller installations.
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 combustion 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 substantially lower viscosity and reduced asphatene and
ash content. Consequently, 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.
8-3
-------
The vanadium content in fuel oil may be deposited in the ash on boiler metallic
surfaces. These deposits act catalytically in converting SO2 to SOj, thereby creating
dew-point and acid smut problems. Oil-fired burners may emit acid smuts (par-
ticulates) which fall out near the stack and stain or etch painted surfaces. Acid
smuts may be caused by the metallic surfaces operating well below the acid dew-
point of the flue gas with soot absorbing sulfuric acid vapor. Switching to a negligi-
ble vanadium content fuel may reduce the conversion of SO2 to SOj and thereby
avoid the acid smut problem.
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 blowing 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 corrosion, 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 furnace,
cleaning them to remove deposits and foreign materials, and inspecting them for
wear or cracks. A major installation may require maintenance of nozzles during
each eight-hour shift. On the other hand, a small residential installation may
require nozzle replacement and strainer cleaning only once a year. Poor atomiza-
tion results in flames which are longer and darker and which increase the soot or
slag buildup on furnace walls. Soot or slag act as i.isulators and thereby reduce the
heat transfer efficiency.
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 aper-
tures, 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 ignition 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 con-
tinuous 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, auxiliary fuel igniters, staged burner controls,
and safety interlocks (which may use optical, pressure, or temperature-sensing
equipment).
8-4
-------
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.
REFERENCES
1. Burkhardt, C. H., Domestic and Commercial Oil Burners, Third Edition, McGraw-Hill Book Co
New York (1969).
2. Fryling, G. R., Combustion Engineering, Revised Edition, published by Combustion Engineer-
ing, 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 (October 1975).
6. "Guidelines for Burner Adjustments of Commercial Oil-Fired Boilers," EPA-600/2-76-088,
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 (January 1977).
8. Percival, J., "Fuel Oil Burning - Design Parameters and Good Operating Practice," unpub-
lished paper, ESSO Research and Engineering Co., Linden, NJ (February 17, 1969).
9. "Commercial and Industrial Fuel Oil Equipment and Its Preventive Maintenance," Publication
No, 67-100, National Oil Fuel Institute, Washington, DC (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. Environmen-
tal Protection Agency, (1977).
8-5
-------
Attachment 8-1. Atomizing characteristics of different
burners—distributions of droplet size
1.2
1.0
0.8
0.6
0.4
0.2
50
100
150
200
250
A = steam atomizing
B = pressure-jet atomizing
C = rotary cup atomizing
300
350
400
*• D
Attachment 8-2. Typical oil combustion design parameters^
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
8-6
-------
Attachment 8-3. Scotch-marine (fire-tube) boiler
Attachment 8-4. D-type integral furnace boiler
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Attachment 8-9. Mechanical atomizer, return-flow type
10
Oil return ^Nozzle body
Atomizer barrel
Path of flow
indicated by arrows
Oil return to
tank or suction
pump
Attachment 8-10. Example pressures for return-flow type
mechanical atomizationlO
450 psi
High fire
445 psi
Low fire
450 psi
250 psi
8-10
-------
Attachment 8-11. Typical rotary cup burner9
Stamped no. on fuel
tip to be in this position
Standard frame
3450 rpm motor
Fuel oil hole
must be at
top to avoid
after drip
/•
^
j.
1 W 3450 rpm fj
on no. 11-20
d 41CO rpm
jjl B on no. 25-230 ,
f/fSfftfSns/sjjfsjss.
^.
I
J
J
\
&m
Steel cable
type belts
single belt drive
on no. 11-110
double belt drive
on no. 125-230
Low
Center nozzle
around cup by
shifting fan
case coyer
Hollow main
shaft
8-11
------- An error occurred while trying to OCR this image.
-------
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 1960s, was stimulated
by both economic and air quality considerations.
In the late 1960s natural gas was available at an average cost of $0.64 per 106
Btu, low-sulfur oils at $0.72 per 106 Btu, and coal at around $0.50 per 106 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 recommend 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 combustion.
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 accor-
dance 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, depending 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 major
bituminous coal sources is shown in Table 9-2 (see Attachment 3-9 for a more com-
plete total). Ash content is an important parameter, both in terms of firing equip-
ment and paniculate 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
9-1
-------
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
Sulfur content %
<0.7
20
25
18.6
20.7
6.2
0.8-1.0
37
6.5
26.7
6.6
1.1-1.5
4.9
3.3
7.6
21.8
>1.5
138
40
78.7
41
49
33
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 in organic 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 accomplished by gravimetric separa-
tion, which is a successful method because pyrites are about five times more dense
than coal. Unfortunately, methods 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
fuels will continue to stimulate economic and legal incentive to speed the develop-
ment 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 stockpiled; 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 using large equipment to form piles several hundred feet wide,
several thousand feet long, and about twenty feet high. Coal is distributed in layers
and compacted 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
9-2
-------
where coal burns in suspension essentially as a fluidized-solid. Spreader stoker-fired
units tend to combine an overfeed scheme with suspension burning. Cyclone fur-
naces operate with the coal converted to molten slag.
What characteristics of coal influence the choice of firing equipment and opera-
tional procedures? Combustion requires oxygen, commonly provided by admitting
atmospheric air. The chemical analysis of the fuel determines the amount of air
needed. The combustibles in coal are carbon, hydrogen, and sulfur. The minimum
theoretical (stoichiometric) air supply is that which will fully oxidize these com-
bustibles. 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 never-
theless, is the proximate analysis. This analysis gives the fixed carbon, volatile mat-
ter, 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
The moisture of the proximate analysis is the "free moisture," and will vary accord-
ing to how the coal is handled. An ultimate analysis of the same fuel is given in
Table 9-4.
9-3
-------
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 theoretical air computa-
tion for the coal in Table 9-4 is:
(9.1) theoretical air = \\.bS C+34.34 (Hz-— ) + 4.29S
8
= 11.53 (.8402) + 34.34 (.0450- — --)
8
+ 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 .he 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 per-
sonnel. 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 different 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 systems where the grates have no motion to break up
9-4
-------
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 furnace 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 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.
Type
Underfeed — single retort
Underfeed — multiple retort
Chain and traveling grate
Spreader— dump grate
— Traveling with continuous
ash discharge
Vibrating grate
Energy rate
Btu/ft2 hr.
400,000 max
600,000 max
300,000-500,000
250,000
750,000 max
400,000 max
Spreader stokers are more commonly found in existing units than are vibrating
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 per-
cent with volatile matter from 5 to 20 percent 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 per-
cent. Prior to the fall of 1973 the price per 10^ Btu for stoker coal was con-
siderably greater than run-of-mine coal. Prices for both types of coal are variable,
and it is 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 travel-
ing grate which must produce 10^ Btu/hr from burning coal with a HHV of
9-5
-------
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 maximum rate of 750,000
Btu/hr ft2 in Table 9-5. Therefore, the area needed is:
\Q8Btu/hr o 9
= 1.33 x W2 hz, and the feed rate
.75X106 Btu/ffi hr
108
is: =3.85 Ton/hr
.26X108
The net grate area establishes the furnace cross section, since the grate is 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 ftA Utilizing data from the exam-
ple, the furnace volume would be given by.
10*Btu/hr = 3.33 X103 = 3330/,3
30,000 Btu/hr ft
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 employed in
coal-burning systems.
Table 9-6. Heat release rates—design values.
Pulverized coal
Stokers — continuous ash removal
Stokers — dump or stationary
Btu/hr per cu. fit.
20,000 to 30,000
30,000 to 35,000
15,000 to 25,000
Mechanical stokers universally require coals with ash fusion temperature 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 admitted 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/ftA Large steam generators may employ two or more of these fur-
naces. A significant characteristic of this firing method is very low fly ash entrain-
ment, a definite advantage for paniculate emission control. Cyclone furnaces are
no longer being built due to high NOX emissions.
9-6
-------
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 Table 9-6 apply to lower rank coals. Where
the air is to be introduced is influenced by the method of firing and the amount of
volatile matter. Underfeed 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 pro-
gresses 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 oxida-
tion 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.
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 controls in each compartment.
The vibrating grate stoker, Attachment 9-6, represents another variation. 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. Suspen-
sion 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
9-7
-------
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 V4" to 1V4" equivalent round hole
with no more than 10 percent passing a 14 mesh screen. Consist of Vi" to %" is
even better, but coal costs are higher when closer size consist control is specified.
Cost 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. Pul-
verized 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 operating at light loads (less than 25 percent).
When loads are small, it becomes 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 transport 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 admit-
ted at the center of the radial burner.
In general, coal-fired steam generators will smoke when air quantity is inade-
quate, 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 distor-
tion, since it causes clinkers or crusts to form through which air cannot flow. Nor-
mally 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. Pro-
per combustion control requires either a CC>2 or C>2 flue gas monitor. The C>2
meter is preferable where several fuels can be fired. Generally, CO2 should range
from 10 to 13 percent in flue gas from stoker-fired units and from 13 to 15 percent
for pulverized units. C>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
paniculate inventory. SOX control can be accomplished by either prevention or
abatement. Prevention requires either a priori removal of sulfur from coal or
9-8
-------
limiting coals fired to those with very low sulfur content. Very probably, both ap-
proaches 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. Unfortunately, as is so often true of a par-
ticular 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 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 thermo-
dynamic relationship:
where Cpm is the molal specific heat of a mixture of r gases, and yj and Cpj are
the mole fractions and specific heats of the «"-th component, respectively. This
increase in specific heat, coupled with lower heat utilization 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 mission 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 applicable to any one system, serve as a gauge for the relative
impact of a number of sources.
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 entering the
control device, based on the fuel's firing rate. These data illustrate that uncon-
trolled 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 advantage of feeding a course grind and
operating with molten ash. There is a penalty, however, in the form of an
9-9
-------
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 AfOx-control theory and experience. An
economic "state of the art" has not yet evolved. However, two techniques currently
receiving major attention are: excess air control and staged firing. Flue gas recir-
culation, which is effective in controlling NOX from gas combustion, is much less
effective with coal combustion. It is difficult 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 coall pollution control
methods.
At the present time, electrostatic precipitators and wet scrubbers appear to be
the acceptable methods to control particulate and SOX emissions 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 Wilcox Company, New York (1973).
3. Steam, Its Generation and Use, 37th Edition, The Babcock and Wilcox Company, New York (1963).
4. U.S. Bureau of Mines, Circular 8312.
5. Quig, Robert H., "Recycling SO£ from Stack Gas: Technology Economics Challenge," Pro-
fessional Engineering, (May 1974).
6. Morse, F. T., Power Plant Engineering, Third Edition, D. Van Nostrand Company, Inc.
(1953).
7. Field Surveillance and Enforcement Guide: Combustion and Incineration 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-QA/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 Protection 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," Combustion Vol. 49 No. 10 (April 1978)
9-10
-------
Attachment 9-1. Cyclone furnace^
Emergency standby
oil burner
Secondary air
Crushed coal inlet
Gas burners
Oil burner
Replaceable
wear liners
Re-entrant
throat
Slag tap opening
Reprinted with permission of Babcock & Wilcox.
9-11
-------
Attachment 9-2. Single retort underfeed stoker3
Dumping
grate Coal
Transverse section
Longitudinal section
Reprinted with permission of Babcock & Wilcox
9-12
-------
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^.
Reprinted with permission of Babcock & Wilcox
Reprinted with permission of Babcock & Wilcox
9-13
-------
Attachment 9-6. Vibrating grate stoker^
Grate tuyere
blocks
Overfire-air nozzles
A Coal hopper
Coal gate
Flexing
plates
Attachment 9-7. Spreader stoker traveling grate unit2
Coal hopper
Feeder
Stoker
chain
Ash hopper
9-14
------- An error occurred while trying to OCR this image.
-------
Appendix 9-1
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 now
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.
*Senior Fellow, Battelle Memorial Institute. Columbus,
Ohio. Presented at the Residential Course on Combustion
Technology, Pennsylvania State University, 1966.
PA. SE. 26. 12. 66 9-17
-------
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^Oo.
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 P2Oc ^ 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 ala^ viscosity above the
liquidus temperature can be related
uniquely to tbe"ns'ilica percentage" of
the slag, where "
Silica percentage =
SiO2
SiO2
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 (rj - 1) s 0. 066 (SiO2 percentage) - 1.4
where n 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
9-18
-------
Corrosion and Deposits From Combustion Gases
where n 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 A12O3
and Fe2C>3 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$ a
barrel was mentioned at the Marchwood
Conference in 1963. but the scheme has
not been applied commercially as yet.
Usually, water-washing and centrifuging
are the only procedures economically
possible for upgrading low-cost residual
fuel.
During combustion, all these complexes
are destroyed, probably liberating the
metals as oxides. With vanadium, for
example, there seems to be a progressive
oxidation from V2C«3 to V^C^. and even-
tually with enough excess air to V2O5.
The melting point and vapor pressure of
these oxides vary widely, with the re-
duced forms having a higher melting
point than the oxidized material. At the
high temperatures in flames, there is a
further tendency to produce a whole
series of vanadates, of which sodium
vanadyl vanadate, Na2OV2O4 • 5V2O3,
is typical. Melting points vary widely
too, being only 1157 F for this compound.
9-19
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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 posed 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
name 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-
porcelair 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" waa
finally identified as K3Fe(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 SO3 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 SO3. Only when both the sulfates
and Fe2O3 are present will the reaction
occur. The trisulfates dissociate rapidly
at higher temperatures unless the SO^
concentration in the surroundings is
increased. Quantitative data are few, but
it appears that the concentration of 803
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 SO3 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
SO3 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 SO3 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
SO- 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
SO3. Slag layers from the high-temperature
zone of oil-fired boilers also contain SO3,
typically from 25 to 45 percent reported as
Na2SO4. to the 1959 Battelle report to
ASME, many examples are given of slag
deposits where there was more than 15
percent SO3 in the deposit.
As has already been noted, the alkali iron
trisulfates cannot exist at 1000 F unless at
least 250 ppm olt SO3 is present in the
9-20
-------
Corrosion and Deposits From Combustion Gases
surrounding atmosphere, or the equivalent
SOj level is provided some other way. At
higher temperatures, even more SO, 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 CaSO4 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 ©2. it seems more reasonable
to expect that SO^ ia 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 303 condenses as a liquid film
on the metal surfaces to cause serious
corrosion. Acid smuts, where carbon
particles are saturated with this H2SO4, 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 in 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
eliminating the formation of SOo 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 V,O5. There-
fore, these reduced forms of vanadium are
considered less objectionable from the
standpoint of corrosion.
9-21
-------
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 803. Flame studies have
shown that stoichiometric sulfur-bear ing
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 SO3 catalytically on surfaces. The
result is an 803 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 SOs 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.
9-22
-------
Chapter 10
Solid Waste and Wood Burning
Municipal incineration has been considered a last resort in solid waste manage-
ment. The major problems have been: high capital cost, high operating costs, site
selection, and a long history of objectionable environmental effects. Municipal
incineration's limited acceptance has stunted its technological development in this
country. However, the growing shortage of suitable, available sites for landfill adja-
cent to large population centers has left some municipalities with no alternative.
In the last two decades, European incineration methods have experienced 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 increasing 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 percent 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 "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 analysis, 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
10-1
-------
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 being a good rule of
thumb. An incinerator design for a particular municipality 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 calculated from the "as
received" analysis by computing the hydrogen and oxygen as shown in Table 10.1.
For this example, the computation is:
2
Hydrogen in moisture = 0.207 x — = 0.023 Ib H/lb waste
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 by
using Equation 9.1.
(\
H2 — J +4.29 S
Ib air
= 11.53 (.28) + 34.34 f.058- "-^- J +0 = 3.47
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 percent 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 include the removal of
incinerator residue. In order to limit transportation cost, waste may be processed to
remove metal and glass. This usually increases original waste of 300 lb/yd^ density
to around 700 Ib/yd3. This reduced transport truck volume should permit plan-
ning of collection and processing to minimize the number of collection trucks
required. Careful systems study will insure optimal location for both the processing
and incinerator plants.
10-2
-------
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 chambers. The primary chamber included a so-
called "drying zone" where volatile 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 chamber,
depending upon whether it is designed for energy recovery. Refuse is continuously
charged by mechanical stokers designed to produce uniform burning. 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.
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 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 stationary sec-
tions, 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 individual 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 sec-
tion 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. 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.
10-3
-------
In general, the use of continuous feed has become common enough to be con-
sidered 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 with 5,000 Btu/lb
energy content this corresponds to a 60 Ib/hr ft2 mass feed rate. Combined with an
energy release design of 20,000 Btu/hr ft3, the area factor establishes the physical
volume of furnace needed for a specified 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/hrx 10 X 106 Btu/ton
= 400x W6Btu/hr
400 X 106 Btu/hr
Grate Area Needed^
400 X
Volume needed - 20xW3Btu/hrftS
= 20, 000 ft*
Furnace design is influenced by a number of factors, including whether or not
the walls are cooled, and what cooling medium is used. Uncooled refractory-wall
incinerators usually require 200 or 400 percent excess air to prevent excessive fur-
nace temperatures which may damage the refractory. With air-cooled walls, con-
structed by locating tuyeres in either a silicon 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 relevant 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 proportion-
ately, assuming other factors remain constant. The reduced excess air requirement
clearly explains why steam-raising incinerators, 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 incinerators
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.
10-4
-------
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 incinerator. 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 HCl emission increases with increasing plastic con-
tent, but that wet scrubbing can remove from 80 to 90 percent of this gaseous
pollutant.
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 CO^. 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 precipitators are applied to steam-raising incinerators,
whether of waste heat boiler type or full water-walled steam generator design, the
lower temperature 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 considerable
power and therefore have high operating costs. Scrubber efficiencies 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 corro-
sion 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 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 unde-
sirable. Reheating flue gases after scrubbing by employing hot unscrubbed gases is
one possible solution to this problem, but it is one which complicates both hard-
ware design and operation. Where scrubbers are added as a retrofit, this reheat
requirement can reduce furnace capacity.
Baghouses do not appear to be in favor with designers of modern incinerators,
most likely because of economic reasons.
10-5
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Economics
The reported costs, both capital and operating, are high. Refractory-walled, non-
energy recovery units have ranged in capital costs 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, Tennessee, costs reflect the site choice. A modern energy recovery
incinerator is a high-technology undertaking when properly designed, and can be
expected to become more so as development continues.
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 papers are largely cellulose — derived from wood. A com-
parison 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 combusti-
ble will burn on grates. Therefore, the air supply must be divided between under-
fire air and overfire air jets, and each separately controlled. 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 con-
tain considerable salt which will be emitted in the stack plume.
Spreader stoker feed of either solid or wood wastes can produce higher par-
ticulate loading than those from the suspension b-raing 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 typically 0.3 to 0.5. Because the
settling velocity of a particle is proportional to its density, 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. Par-
ticles 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
hogging operation) produces a large fraction of particles in the one mm range,
paniculate 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.
10-6
-------
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 sur-
rounded 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 refrac-
tory section at the entry region of the inclined grate. This is the drying or vola-
tizing 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, pp. 207-209, (March 1971).
2. Stabenow, G., "Performance of the New Chicago Northwest Incinerator," ASME National
Incinerator Conference Proceedings, pp 178-194, (1972).
3. Rogus, C. A., "Incineration with Guaranteed Top Level Performance," Public Works, Vol. 101,
pp. 92-97, (September 1970).
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-650/2-75-044.
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, p.412, (May 1972).
8. Kenhan, C. B., "Solid Waste, Resources Out of Place, " Environmental Science and
Technology, Vol. 5, No. 7, p.595, (July 1972).
9. Municipal Incineration, A Review of Literature, U.S. Environmental Protection Agency
AP-79, (1971). S "
10. Field Surveillance and Enforcement Guide: Combustion and Incineration 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," ASME National Incinerator Conference Proceedings
pp. 310-318, (1972). 5 '
12. Kaiser, E. R. and Carotti, A. A., "Municipal Incineration of Refuse with 2 Percent and 4
Percent Additions of Four Plastics," ASME Incinerator Conference Proceeding's
pp. 230-244, (1972).
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).
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, (April 1971).
18. Steam, Its Generation and Use, 38th Edition, The Babcock and Wilcox Company (1973).
10-7
-------
Attachment 10-1. Cross section of ram-fed incinerator^
Crane and
grapple
Charging hopper
Ram feeder
Overfire air ducts
Ignition burner
Settling chamber
f Breeching
Charging Combustion
Sate chamber.]
•^dZ. Stokers
'Combustion
l(*-air inlets-**"
uench tank and drag out conveyer
Cross conveyor
Attachment 10-2. Schematic of reciprocating grates
Moving
grates
10-8
-------
Attachment 10-3. Front view of reciprocating grate stoker^
Attachment 10-4. Chain grate stoker-fed furnace^
10-9
-------
Attachment 10-5. Chain-grate stoker9
10-10
-------
Attachment 10-6. Reciprocating stoker in a water-wall furnace9
Water-cooled
feed chute
Forced-draft
10-11
-------
Attachment 10-7. Oscillating and barrel grates
10
Raised position
Normal position I f
Oscillating grate
Barrel grate
10-12
-------
Attachment 10-8. Dutch-oven-fired boiler 15
Fuel in
To stack
Air ii
10-13
------- An error occurred while trying to OCR this image.
-------
Attachment 10-10. Inclined-grate wood waste fired boiler^
Steam out
10-15
-------
Attachment 10-11. Wood waste-fired boiler with
air spreader stoker 15
M II II II
Water wall furnace
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
10-16
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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-1950s 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 contribu-
tion 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.
In 1960 the Los Angeles County Air Pollution Control District published design
standards for multiple-chamber incinerators (1). The standards established design
values for certain velocities, temperatures, and dimensions (see Attachment 11-3),
along with procedures for certain standard 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 incinerators 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 maintain draft at
around 0.2 inches of water in the primary chamber. Some multiple-chamber
incinerator designs included water scrubbers (Attachment 11-5).
11-1
-------
In the 1960s 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 paniculate per standard cubic foot of flue gas, corrected
to 12% CO2- 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 representative, yet fairly
new, apartment house incinerators in New York City, Cincinnati, Philadelphia,
and Miami (5). The particulate emissions of the two single-chamber units con-
siderably 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 1970s, most states considerably tightened their standards 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, because 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 multiple-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.
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). Continuous charg-
ing 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 complete
oxidation of the smoke, CO, and hydrocarbon gases. The balance of the required
air is strategically introduced to provide proper turbulence without quenching the
11-2
-------
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 aux-
iliary fuel and excess air. Typical residence times are from .7 to 1.0 second (8).
Originally "starved-air" units described those with relatively small secondary
chambers or afterburners, 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 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 combined 100 T/day capability.
Most of the units which have been installed are of the batch type, without con-
tinuous 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 operating. 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 auxiliary 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 control adequate
to meet most state standards without utilizing a scrubber or other flue gas treat-
ment. Particulate emissions of "dry catch," or the sample collected on or before the
filters in EPA sample train, have been recorded from 0.03 to .08 grains per stan-
dard cubic foot corrected to 12% CO2 (7).
Design and Operational Modifications for Improved Performance
The problems inherent in a poorly operating controlled-air incinerator are gen-
erally related to either the waste material, charging technique, 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 chamber, and the reduced
residence time in the second chamber. Emissions also increase as the batch
charging disturbs the fire bed. If the charge consists 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 combustion 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
11-3
-------
interlock, illustrated in Attachment 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 removal. Factory-manufactured controlled-
air incinerators are now being marketed with continuous ram feed and ash removal
features. These units operate 24 hours per day and thereby have increased loading
capability. In addition, the refractory damage due to temperature cycling is con-
siderably 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 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 particulates emissions. Maintenance
costs may also increase because 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 Attachment 11-8. The economics, of
course, are most favorable if the refuse waste stream is guaranteed, and if a
customer is available who will purchase 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 Emissions
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 conditions. 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 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 oppor-
tunity 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 con-
siderably reduce the particulate/smoke emissions.
11-4
-------
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, E. 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 Facilities," AP-46, National
Air Pollution Control Administration, Public Health Service, Raleigh, NC (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, Lexington, 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 the 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).
10. Cross, F. L., and Flower, F. B., "Controlled Air Incinerators," paper presented to Third
Annual Environmental Engineering and Science Conference, 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 Edition, 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).
11-5
-------
Attachment 11-1. Single-chamber incinerator^
Combustion chamber
Charging door
Underfire air port
Basement
floor
Cleanout door
11-6
-------
Attachment 11-2. Modified single-chamber flue-fed incinerator 12
Blower
Draft control
damper
Combustion
chamber
Grates
Electric lock
Chute door
--^.
Ist-floor level
Charging
Door
Overfire
air port
Burner
Basement
floor
Cleanout door
Underfire
air port
11-7
-------
Attachment 11-3. Design standards for multiple-chamber in-line
incinerators 1
Plan view
Side elevation
1. Stack 6. Flame port
2. Secondary air ports 7. Ignition chamber
3. Ash pit cleanout doors 8. Over fire air ports
4. Grates 9. Mixing chamber
11. Cleanout doors
12. Underfire air ports
13. Curtain wall port
14. Damper
5. Charging door
10. Combustion chamber 15. Gas burners
2 S
2 2
V •*>
a >,
* *•
£ -3
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a *•
Length in inches
ABCDE FGHI J KL*MNOPQ
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1500
2000
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54
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*Dimension "L" given in feet.
11-8
------- An error occurred while trying to OCR this image.
------- An error occurred while trying to OCR this image.
-------
Attachment 11-6. Controlled-air incinerator**
Attachment 11-7. Controlled-air incinerator
ll-ll
-------
Attachment 11-8. Controlled-air incinerator with ram feeder7
2nd waste heat boiler
Heat dumping stack
Gas diverter section
Dual fuel burner
(2,000,000 Btu/hr)
Full opening dome
refractory lined
Inspection door
Ash removal pad \
.1 jl
Primary chamber (550 cu. ft.);
lining: fire brick lower section;
castable refractory upper section
Recovery section
Pollution control chamber
Stack
»
Lining: castable
refractory
Automatic loader
(remotely controlled)
Hydraulic unit
Dual fuel burner (2)
for oil or gas (500,000 Btu/hr)
11-12
-------
Chapter 12
Municipal Sewage Sludge Incineration
Introduction to Sludge Incineration
Incineration is an acceptable method for volume reduction and sterilization of
municipal sewage sludge. Disposing sludge into the ocean depths, in sanitary land-
fills, and by landspreading have been widely 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 aesthetic 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, depending 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 approx-
imately 18 inches of water pressure drop. Other acceptable control devices for par-
ticulates could be impingement scrubbers, with auxiliary fuel burners (controlled
by O2 sensors), or electrostatic precipitators.
Sludge Characteristics
Typical moisture content for mechanically de-watered sludge ranges from 70 to
80%, depending mainly on the ratio of primary to secondary treatment 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 combustion energy
to raise the combustion products and moisture to 900 °F. This temperature is far
below the 1,350 to 1,400°F necessary for deodorizing the stack gases of a conven-
tional combustion unit. If this sludge were dried (de-watered) to 30% solids, the
steady use of auxiliary fuel would be unnecessary. The combustion energy from this
sample sludge would heat the combustion 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 primary to secondary
sludge. This provides sludge of higher heating content and better de-watering
properties.
12-1
-------
Wastewater sludges may contain metals which potentially are hazardous if
discharged into the atmosphere during incineration. With the exception of mer-
cury, 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 mer-
curic oxide or metallic mercury vapor. Mercury concentrations of sewage sludges
nationally usually average less than 5 ppm on a dry solid basis but are occasionally
as high as 10-15 ppm. For high mercury sludges, greater than 5 ppm dry solid
bases, make a mercury balance across the incinerator. Mercury emissions should be
held to less than 3200 g/per day.
The above hazardous pollutant standard was established by EPA to limit the
atmospheric discharge of mercury from any one site for sewage sludge incinerators.
Lead emissions from sewage incinerators have been less than 10% of their inlet
concentrations.
Sludge also may contain toxic pesticides and other organic compounds such as
polychlorinated biphenyl (PCBs) usually at low concentration, less than 25 ppm
dry solid basis. Such materials are very refractory and may need 800° —1000 °C for
0.7 to 1.0 second residence time to approach total destruction. Read chapter 15,
incineration of PCBs.
Multiple-Hearth Furnaces
The most widely used sludge incineration system is the multiple-hearth furnace
illustrated in Attachment 12-2. The present air-cooled 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 'b). Wet scrubbers were added
to typical designs in the 1960s, and combustion was improved as automatic con-
trollers became sophisticated in the 1970s.
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 direction.
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 con-
tinuously 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.
12-2
-------
The central shaft and "ramble" arms are air cooled, in order to prevent damage
from the high temperature.
Combustion in multiple-hearth furnaces is typically characterized by four zones.
The drying zone is where only moisture is driven off from partially 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 con-
tent 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.
Combustion control systems may include temperature-indicating controllers, pro-
portionate 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 preheated combus-
tion 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 com-
bustion 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 inter-
mittent schedule. The cyclic temperature variations must be tempered by auxiliary
heating to limit the possible structural damage caused by thermal stresses. In
12-3
-------
addition, the furnace must be preheated prior to the beginning of sludge incinera-
tion 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).
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 municipal and industrial sludges. Con-
siderable demonstrations also have shown the application of fluidized-bed combus-
tion 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 wide 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 available. Although the bed may glow
and incandescent sparks may be seen above the bed, there is no flame.
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 fluidized 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 entrain-
ment of small particles by the combustion gases. These particulates must be
adequately controlled by a scrubber or some other collective 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 com-
bustion are low, so that NOX 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.
12-4
-------
REFERENCES
1. Rubel, F. N., Incineration of Solid Wastes, Noyes Data Corp., Park Ridge, NJ (1974).
2. "Background Information on National Emission Standards for Hazardous Pollutants —
Proposed Amendment to Standards for Asbestos and Mercury," U.S. Environmental Pro-
tection 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 Publi-
cation, EPA-625/4-75-009 (June 1975).
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, Publication 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 Performance of Multiple Hearth Fur-
naces with Sewer Sludge," Proceedings of 1976 National Waste Processing Conference,
ASME, pp. 117-124 (May 1976).
12-5
-------
Attachment 12-1. Average characteristics of sewage sludge^
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
(%)
11.5
26.0
13.6
15.2
50.4
40.4
69.8
Heat content
(cal/g) (Btu/lb)
9300
5710
4990
4580
4450
2940
220
(16,750)
(10,285)
( 8,990)
( 8,245)
( 8,020)
( 5,290)
( 4,000)
12-6
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Attachment 12-3. Typical section of a fluid-bed reactor
Sight glass
Exhaust
Sand feed
Fluidized sand
Pressure tap
Access doors
Preheat burner
Thermocouple
Sludge inlet
« Fluidizing air inlet
12-8
------- An error occurred while trying to OCR this image.
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Chapter 13
Direct Flame and Catalytic
Incineration
Atmospheric oxidants are primarily the result of a series of chemical reactions
between organic compounds and nitrogen oxides in the presence 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 contribu-
tion of nitrogen oxides is the subject of Chapter 16 and will not be discussed here.)
Photochemical oxidant control strategies are therefore aimed at controlling NOX
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 Training
Institute Course-#415: Control of Gaseous Emissions. To avoid unnecessary
duplication, only those methods which are related to combustion will be outlined
here.
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 paniculate as well as gaseous matter. If the particulates are combustible
they may also be handled by the combustion process. Incineration is one of the
most widely used methods for controlling VOC emissions from industrial manufac-
turing 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 sustained 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 heatine
value wastes.
The usefulness of afterburners has been well documented. Their popularity has
been mainly due to their ease of operation and the availability 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 Attachment 13-1.
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 ques-
tions about 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 afterburner economics picture considerably as
will be discussed later.
The two major types of combustion units are (a) the thermal incinerator and (b)
the catalytic incinerator. Catalytic units, a schematic of which is shown in Attach-
ment 13-2, permit the use of a lower temperature than the thermal incinerators for
complete combustion, and therefore 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. Furthermore, 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 arrange-
ment have a considerable effect on burning time. The more thorough the flame
contact is with the effluent gases, the shorter is the time required to achieve com-
plete combustion. Turbulence in the combustor zone achieves much the same
benefit of reducing required retention time, as actual flame contact.
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 com-
bustion of the auxiliary fuel, should the latter be required. An efficient afterburner
design can produce complete combustion of the auxiliary fuel with fumes con-
taining as little as 16% by volume of oxygen. The available heat (which is needed
to raise the effluent fumes to the incineration temperature) from burning natural
gas with 0% outside 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 requirements.
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)
13-2
-------
burning combustible waste liquids through center-fired gun-type burners. A typical
regenerative method of heat recovery is illustrated in Attachment 13-3. This par-
ticular system operates in a cyclic fashion by switching gas flows from one ceramic
bed 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 continuous heat transfer to
another fluid separated by a heat transfer surface. The net cost of using an after-
burner to control gaseous pollutants 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 capacities 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 com-
bustible 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 characteristics. It contains worked
examples of afterburner designs, and an evaluation 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 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 after-
burners (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 formation of ohotochemical 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)
incinerators. 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.
13-3
-------
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 (1974).
3. Worley, F. L., Motard, R. L., "Control Equipment Design and Analysis (CEDA): Gaseous
Pollutants," USEPA Contract No. 68-02-1084, 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 Institute, 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. III-EPA-450/2-77-032
Vol. IV-EPA-450/2-77-033
Vol. V-EPA-450/2-77-034
13-4
-------
Attachment 13-1. Sectional view of direct-flame afterburner
(Gas Processors, Inc., Brea, CA)1
Flame sensor
Burner
Refractory
Insulation
Turbulent expansion zone
Steel
Compression zone
Cooling air
induction system
\ (adjustable)
Sample port
Pressure tap
Straightening
vanes
^Blower
Insulation
Gas system
control
Control panel
(remote optional)
Unitized 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 control and a
modest blower size.
13-5
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Attachment 13-2. Catalytic incinerator with recycle
and heat economizer
B
Fuel
Clean
Contaminated stream
Stream
Catalytic oxidation
low temp, feed with
recycle and heat exchanger
A. Blower motor
B. Blower (mixer)
C. Fuel burner
D. Catalytic element
E. Temperature controller
F. Recycle damper
G. Heat exchanger
13-6
-------
Attachment 13-3. Ceramic bed regenerative-type incineration
and heat recovery system
Bake oven
To atmosphere
6,000 scfm
T
14,000 scfm -
13-7
-------
Attachment 13-4. Reported range of heat recovery per stage
by application and type of afterburner equipment4
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
13-8
------- An error occurred while trying to OCR this image.
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Appendix 13-1
(Partial Exerpt)
EPA-450/2-76-028
(OAQPS No. 1.2-067)
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
13-11
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3.2.2 Incineration
3.2.2.1 Introduction — Incineration destroys organic emissions by oxidizing them to
carbon dioxide and water vapor. 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. Emissions
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 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 dis-
tant 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 ther-
mal 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 converts CO and residuals to car-
bon 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 second^ is suf-
ficient 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 zylene.2
Design — Incineration fuel requirements are determined by the concentration of
the pollutants, the waste stream temperature and oxygen level, and the incinera-
tion temperature required. For most organic solvents, the heat of combustion is
13-12
-------
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
Pilot assembly
Incineration chamber
Fume inlet plenum
Refractory-lined
ignition chamber
Figure 3-10. Typical burner and chamber arrangement used in direct-flame incinerator.
13-13
-------
a
V
u
i
I
•B
«rf
C
•M
"e
Increasing residence time
1000
1200
1400
1600
11800
2000
Temperature, °F
Figure 3-11. Coupled effects of temperature and time on rate of pollutant oxidation.1
13-14
-------
V
u
s,
u
3
rt
§
u
u
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.1
13-15
-------
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 NOX in combustion products from fuel
oil increase pollution emissions and cause corrosion and soot accumulation on
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 preheat the cooler incoming gases. Design is usually for 35 to 90 per-
cent heat recovery efficiency.
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 1450 °F for the protection of the heat exchanger. The aux-
iliary 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 per-
cent 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.
13-16
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The use of incinerator exhaust to preheat incinerator inlet air is often referred to
as "primary" heat recovery as illustrated in Case 2 of Figure 3-13. Since some
systems have a maximum allowable inlet temperature for the incinerator, it may
not be possible to recover all of the heat available in the incinerator exhaust. In
such cases, 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 if there is no primary heat recovery)
to replace energy usage elsewhere in 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 circumstances at the plant. Usually
recovery efficiency of 70 to 80 percent is achievable, making the net energy con-
sumption 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 is 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 in Case 3 to real plants, the cost of
using recovered energy must be considered. If secondary heat recovery is used,
often the plant cannot operate unless the control system is operating because it
supplies heat required by the plant.
13-17
-------
Case 2—Basic: system with gas preheat
Catalyst, if any
Solvent-containing r- ^ '~i
*•$— , x»_ ,-a >
I I ~y To atmosphere
p-uel Incinerator
Case 3 — Process heat recovery with gas preheat
> i Catalyst, if any i k
^ } U ' U
1 / 1 I /x 1
Preheater ^ Fuel Incinerator
/N^ /^ ^ Heat recovery
SX N/ fluid
_J_,Procpss heat recovery
^j
^ * To atmosphere
Fuel ^taiyst, it
I \ 1 1 I K) 1
t * ^r j[
i y rn _r
Pr«.h<.atpr^ Incinerator >
Process
Case 4 — Inert gas generator
air ^x. r" ' i
^r-^ "-1 +.
A Q — - Jiy r-O - -*- Ventec
1 J f \ atmosph
Fuel locinerator
Inert gas
Figure 3-13. Configurations for catalytic and noncatalytic incineration.
13-18
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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 retrofit 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 non-
catalytic 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
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 80 °F. 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 combus-
tion. However, an incinerator designed for hydrocarbon removal usually will not
have sufficient residence time to efficiently combust organic particulates.
13-19
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300°F
25% of
theLEL
1400 °F
Process heat recovery
r „ 620°F
Incinerator
ATCombustion
Makeup
air 70°F
Figure 3-14. Example of incinerator on oven with primary and secondary heat recovery.
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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
accumulations 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 por-
tion of nitrogen-containing compounds will be converted to NOX and additional
NOX will result from thermal fixation. 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 (NOX) is about 18 to 2.2 ppm for natural ga.s-
fired noncatalytic incinerators and 40 to 50 ppm for oil-fired noncatalytic
incinerators at a temperature of 1500 °F, assuming no nitrogen containing com-
pounds are incinerated.
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 per-
cent 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 about 50 Btu/scf.2 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 permanently 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 configura-
tion 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 sup-
port or on a honeycomb support. All-metal catalysts can also be used.
13-21
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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. *
13-22
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The initial cost of the catalyst and its periodic replacement represents, respec-
tively, 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 the amount 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 lifetime of
greater than 1 year is considered acceptable.
Catalyst material can be lost from the support by erosion, attrition, or vaporiza-
tion. 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. 1
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 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 common
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 SO) 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.
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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 possib1 s
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 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.
As discussed earlier, there is little variation in the available heat from combus-
tion 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, NC under contract
EHSD 71-2. Publication no. EPA R2-73-202. (April 1973).
2. Rolke, R. W. et al. Afterburner Systems Study, Shell Development Company, Emeryville,
CA, prepared for U.S. Environmental Protection Agency, Research Triangle Park, NC
under contract no. ESHD 71-3. Publication no. EPA-R2-72-062. (August 1972).
13-25
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Chapter 14
Waste-Gas Flares
The material presented in this chapter is an edited version 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 quantitites of these gases were con-
sidered waste gases, and along with waste liquids, were dumped to open pits and
burned, producing large volumes of black smoke. With modernization of process-
ing 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 1970s) 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 sud-
den 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, 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 evacua-
tion of units during shutdowns and turnarounds. Normally a unit is shut down by
depressuring into a fuel gas or vapor recovery system with further depressuring to
essentially atmospheric pressure, by venting to a low-pressure flare system.
A blowdown or pressure-relieving system consist? of relief and 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 con-
ducted to appropriately designed holding vessels and reclaimed.
14-1
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A pressure-relieving system used in one modern petroleum refinery is shown m
Attachment 14-1. The system is used not only as a safety measure, but also as a
means of reducing the emission of hydrocarbons to the atmosphere. This installa-
tion actually includes four separate collecting systems, 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
blowdown 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 vesel. Any entrained 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 condenses
some of the hydrocarbons and permits their recovery. The overhead vapors from
this so-called sump tank flow to the flare system manifold 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 ordorous 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 introduce the possibility of smoke and other objec-
tionable gases such as carbon monoxide, sulfur dioxide, and nitrogen oxides. Flares
have been further developed to ensure that this conbustion 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 important 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.
14-2
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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 smokeless 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.
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 combustion. As an example, gases
vented from an isomerization unit that may contain small amounts of hydroflouric
acid are scrubbed with caustic before 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 commonly encountered air-inspirating
material for an elevated flare is steam.
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 operation under varied flow conditions, inter-
nal injector tubes along with a center tube have been added. The injector tubes
provide additional turbulence 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 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 con-
trolled. In most cases, the steam is proportioned automatically to the rate of gas
flow; however, in some installations, the steam is automatically supplied at max-
imum 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 instrumen-
tation among various flares, some designs being more desirable than others. For
economic reasons, all designs attempt to proportion steam flow to the gas flow rate.
14-3
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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 result, and (d) steam reduces the partial pressure of the fuel
and retards polymerization. (Inert gases such as nitrogen have also been found
effective for this purpose; however, the expense of providing such a diluent is pro-
hibitive.)
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 to 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 exceeds the designed capacity of the main flare, backpressure
in the vent lines 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 and the degree of
unsaturation of the gas.
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 combus-
tion 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 injection 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 controlled. 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.
14-4
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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 signal 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 is fully open at 15 psig air pressure.
As the gas 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
transmitted 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 1 V£ inches above the top of the orifice 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 provide 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 maintenance 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.
Ground-Level Flares
There are four principal types of ground-level flare: horizontal venturi, water injec-
tion, 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.
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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 requires specially con-
structed venturi burners (throat diameter ranges from 5 to 18 inches), reportedly
cost 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 (Attach-
ment 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 dif-
ficult 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 undoubtedly 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 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 multijet (6).
This type of flare was designed to burn excess hydrocarbons without smoke, noise,
or visible flame. It is claimed to be less expensive than the steam-injected type, on
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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 Attachment 14-11. The
flare uses two sets of burners; the smaller group handles normal gas leakage and
small gas releases, while both burner groups are used at higher flaring rates. This
sequential operation is controlled by two water-sealed drums set to release at dif-
ferent 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 center of a multijet stack.
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 i/£ 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
arrangement 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 invisi-
ble during the day. At night this flame appears blue.
An injection of an excessive amount of steam causes the flame to disappear com-
pletely 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
14-7
-------
because a steam hiss replaces 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 decrease 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, obviously, 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 into the system. Flame
arresters are sometimes used in place of or in conjunction 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 explosion 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 into the stack or
into the combustion zone. Where there is an abundant supply, water has sometimes
been used in ground flares. There is, however, less assurance of complete combus-
tion 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 manifold 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 diameter 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 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 flare tip manufactured by the John Zink Company. The
nature of the gas determines optimum discharge velocity.
14-8
-------
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 per-
sonal 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 con-
siderations in another installation.
As previously mentioned, the amount of steam required for smokeless combus-
tion varies according to the maximum expected gas flow, the molecular weight, and
the percent of unsaturated hydrocarbons in the gas. Data for steam requirements
for elevated flares are shown in Attachment 14-4. 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 refinery, 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 three pilot
burners. A separate system must be provided for the ignition of the pilot burner to
safeguard against flame failure. In this system, 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
system, 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, controlled 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
prevented 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 from generator
is turned off by closing the plug cocks in the fuel and air lines. This prevents the
collection of condensate and the overheating 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 ther-
mocouples 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 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 Pilot tube, and a flow transmitter that sends a signal (usually pneumatic) to a
control valve in the steam line. Although the Pilot tube has been used exlensively
14-9
-------
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 per-
mit 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 Processing, 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., "Scfe, Smokeless Combustion Features Waste Gas Burner at Sinclair
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 Meeting (May 1956).
7. Smolen, W. H., "Smokeless Flare Stacks" Petroleum Processing, Vol. 6, pp. 978-982
(September 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).
14-10
-------
Attachment 14-1. Typical modern refinery blowdown system
To flare stack
Low -pressure blowdown
Liquid blowdown
Fuel gas purge
High-pressure blowdown
Light-ends blowdown
1 Light-ends
Jlowdown drum
IMain
blowdown drum
Scrubber
Water pump
Water
Liquid to slops tank
Light ends condensate recovery
Attachment 14-2. View of John Zink
smokeless flare burner
(John Zink Company, Tulsa, OK)
14-11
-------
Attachment 14-3. Detail of flare tip showing internal steam
injection (John Zink Company, Tulsa, OK)
Steam jets
Pilot
assembly
Diffuser
Steam header
Internal
steam
injector
tubes
Steam *™ r % Center steam
distribution Tip shell j«
ring
Continuous
muffler
Pilot and
mixer
Center steam
jet
Plan
Elevation
Attachment 14-4. Waste-gas flare system using
multisteam-jet burner^
Steam
Pilot
Main collection system
Hydrogen reactor
dropout
Petrochemical
system
( Drip \ n I lo ft 5-in water
tank ) 00 Wai tank!
V tanK J water
seal
Condensate
idei
ical I
1. Blinds
-------
Attachment 14-5. Waste-gas flare system using Esso-type burner
3 Ignitors
(typical 3 places) 3 2-in. Pilot burners
>
1,
•MM
Si
^ •
f** —
s*.
-)}}
XXSfr/
^\
Flare ti
detail
^
i
-K
\
pj
^^
p
1 (120° apart)
Steam
I '
controller
Instrument air/-\
^^J
Ratk
relay
Waste gas
Water
Large flow
i —*•
~iJ
Smalf flow — *"
Purge gas
'ressure sensor
.- 1 1 -u -• ^
M ! n *
) Pressure taps u "
V Flame arrestor
^ •* T
High LOW.> .
* Seal
/ i n L°°p
II ^ seal
Slotted
orifice
n ^
Stack
u
Attachment 14-6. Water seal drum with slotted orifice for measuring
gas flow to flare
Purge gas
Vented gas
V~
Air
Ratio
relay
Flow
con- **"
troller
n
XfTrans-
Steam
mitter
Make-up water-
T
m
3-in. motor
valve
To flare
Gas to
flare
Slotted
orifice
Ti
H20
seal
I
n
f
Separator
1-in. motor valve Knock out vessel
14-13
-------
Attachment 14-7. Diagram of waste gas flare system
using a Sinclair Burner
Refined
blowdown
manifold
system
— •*
-P-]
[ t
(Knock out^
. drum /
Condensate 1
kJ
b"
*H
.__^
G
a
«J
^•MB
•^^•1
••MM
D Steam ring
Flare stack
A Pilot
1 . [gnitor
1 T Fuel eas
D Steam ring
Flare stack
t^Ignitor
1 | Fuel eras
14-14
-------
Attachment 14-8. Detail of Sinclair flare burner,
plan and elevation4*
Plan
2-in. O D
steam ring
Section AA
Elevation
Gas pilot
Cover plate
Steel shroud
Gusset plate
Plastic insulation
Gas standpipe
Protecting shroud
Steam supply pipes
Flame arrester
14-15
-------
Attachment 14-9. Typical venturi ground flare,
ignitors not shown 1
Steel cement or
refractory wall
Gas to pilot burners
Refinery
flare header
Liquid
knockout
I tank I
in
Condensate
to sump or
recovery
Burner banks
Automatic snap action valves
Emergency or bypass line
Liquid seal
Attachment 14-10. Typical water-spray-type ground flare
Six water sprays are shown. Two pilots and
two ignitors are recommended 2
Water spray
distributor ring
Bottled gas
Venturi burner
Gas to pilot
Ignitor tube \
Oil to pilotVjl
^ «| ^ f ,_„.
— V | ' tv^1
Spark ignitor \
fH
igi Water supply
^^
Water strainers
14-16
------- An error occurred while trying to OCR this image.
-------
Attachment 14-13. John Zink molecular seal
(John Zink Company, Tulsa, OK)
Liquid f
drain
Flare tip mount flange
Sealing cap
Molecular
seal
(gas seal)
Flare stack
14-18
-------
Attachment 14-14. Steam requirements for smokeless burning of
unsaturated hydrocarbon vapor 1
& 3
V
ex
0 10 20 30 40 50 60 70 80 90 100
Unsaturates by weight
14-19
-------
Appendix 14-1
FLARE COMBUSTION
Leonardo. Mandril, P. K. *
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.
1
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,
GG Pitman Street, Providence, Rhode Island.
PA.C. ce. 38. 1. 67
14-21
-------
Flare Combustion
Toxlcity may evolve from the nature of
the ra*r 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 me reap tans. 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 orJy 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.
H 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.
HI 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 Th-*.t 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;
, _ „ _ -,rt „
1 C+H20-CO + H2
9 r * TH n-.m + 2H
2 C + 2H20-C02 + 2H2
These reactions
^eqmte^pid
at temperatures
^^
1650°F.
require heat inputs, of approximately
5900-6000 BTU/lb. carbon.
14-22
-------
Flare Combustic
D 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.
E 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. £. 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, L 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.
IV 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 (C,H2)
with a H/C ratio = 0.083. real black
soot will result from simple burning.
Propane (C3H8) with a H/C ratio . 0. 22
creates black smoke.
14-23
-------
Flare Combustion
Ethane (C2H6> 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.
C 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.
D In flare burning of chlorine-bearing
compounds, most will appear as hydrogen
chloride vapor. However, appreciable
quantities of chlorine will remain.
E A relation exists between the auto-ignition
temperature of the gas, its calorific
value and its ease of successful flare
burning.
At 800°F ATT: A minimum H. V. of
200 BTU/cu. ft. is required.
At 1150°F AIT: A minimum H. V. of
350 BTU/ cu. ft. is required.
At 1300°F AIT: A minimum H. V. of
500 BTU/cu.ft. is required.
F Since the heat content of many gases vary
much below 100 BTU/cu. ft. and since
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.
G 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.
H 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
C^2 ® 1800°F temperature will burn com-
pletely in .079 sec — 95% Dilution
C2H2 @ 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. 081 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.
14-24
-------
Flare Combustion
L A smokeless flare results when an ade-
quate amount of air is mixed sufficiently
with fuel so that it burns completely be-
fore side reactions cause smoke.
What is Required? Premixing of air+ fuel
Inspiration of excess air into the
combustion /.one
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
M ,
H/C AIT
1000-1100°F
.083 600- 800°F
1200
550- 700
1200
.222 1000-1100
.33
1000
750°
470°
. 17
.13
', by Vol.
LEL
4.1
2.5
16
4.3
12.5
2. 1
5.3
3
2 .
in Air"
UEL
74
80
27
4G
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
14-25
-------
Flare Combustion
V TYPES OF FLARES:
Flares are arbitrarily classed by the elevation
at which the burning occurs; L e. — The
elevated-flare, the ground-flare and the-Pit.
Fach 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
6 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'/£ 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. = 28 30-40 psig.
@35 gpm.
is required.
200,000 Scfhr. M. wt. = 37
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 flarne-holders (rods) to provide
time and turbulence for adequate air-mixing
14-26
-------
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 ignitors, 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 pilot tip
to atmosphere
Steam jets
Steam
manifold
Supply
riser
Cooling
air-up
Diameter size of flare
Flame front
igniter-tip
Igniter
tube
Pre-mixed
pilot
gas-air mixture
14-27
-------
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
indue esc arbon- 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 toe 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 Sixes may vary from l| inch pipe to
120 inch diameter.
H The burning rate can vary from 0. 5% -
100% of design.
I Systems up to 11,000. 000 Ib/hr. of 43 mol.
wt. @ 700°F have been flared. (Zink)
J Typical data for hydrogen sulfide flares
would appear as follows:
14-28
-------
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
no'
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/Hr JSq. Ft. at ground level with
700 BTU/Hr./Sq. Ft. from the flame and
300 from the sun. (Zink)
L The ignitors 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.
O 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.
VII 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 Ignitors are used to light the pilot at
start-up or at Pilot name 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 arrester: 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
14-29
-------
Fit
ibustion
J Shrouds are not of real value in smoke
control, however, they can be used in
preventing downwasb.
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/air mixture that is
pre-ignited in a special in-line, pipe-
chamber by a spark plug. The flame-
front, under flow-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.
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.
Kence. 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:
TYPICAL STAINLESS STEEL ALLOYS
ALLOY % Cr
304 18-20
316 16-18
347 17-19
430 14-18
HasteUoy's X
%Ni
8-10
10-14
9-12
X
% c
.08 max.
.10
.10
.12
%Mo
2-3
X
% Si
. 75 max.
. 75 max.
. 75 max.
.75 max.
% Mu Co
2.0 max.
2.0 max.
2. 0 max. 1. 0% max.
0.50
Inconel
(6*Fe)
10
84
H-30
-------
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, HgS, 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 H 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.
14-31
------- An error occurred while trying to OCR this image.
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Chapter 15
Combustion of Hazardous Wastes
Government, industry, and environmental groups have become increasingly aware
of the need for environmentally acceptable ways of treating and disposing of
industrial wastes in general and hazardous wastes in particular. Incineration pro-
vides 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 polluters 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.
Many types of incinerators have been used for thermal destruction of hazardous
materials. These include rotary kilns, multiple-hearth incinerators, 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 candidates for incineration,
although some inorganics can be thermally degraded. 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
harmless or can be controlled by pollution control equipment. SOX emissions from
sulfur-containing materials may need to be removed if present in appreciable con-
centrations. NOX formation can be minimized by keeping incineration
temperatures low-below about 2,000°F. The destruction ratio of a given material
by incineration depends to a large extent on the temperature and the dwell
(residence) time at that temperature. Incinerators burning hazardous wastes should
15-1
-------
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.
Halogenated and Sulfonated Materials
Chlorinated and sulfonated solvents can be handled by incineration, but this alone
will not eliminate air pollution. Chlorinated hydrocarbons 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 incineration (3) as
shown in Attachment 15-1. Similar systems for liquid waste disposal are discussed
in References 4 and 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 second (12). Water scrubbing will not be sufficient to eliminate
SOX produced 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.
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 become 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 technique.
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 retention time in
the combustion chamber.
• Certain conventional incinerators have the potential for incinerating pesticides
if adequate retention times at the appropriate temperatures can be obtained
and emission control devices provided.
15-2
-------
• Residues left from the incineration of formulations with inert binders and car-
riers, generally contain very low levels of pesticides, e.g., less than 20 ppm.
• Incineration of organonitrogen pesticides can generate measurable quantities
of cyanide (CN~) at temperatures tested (650 —1,050°C).
• 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 operating conditions where less than
99.99% destruction may result, whereas conditions 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 con-
siderations must be emphasized when pesticide incinerators 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 unwanted pesticides and pesticide-
contaminated solid wastes. Work on Kepone has found it to be definitely more
thermally stable than DDT (7). A comparison of the thermal destruction of several
pesticides is shown in Attachment 15-4. Any incineration requirements for Kepone
should therefore, at a minimum, meet those for DDT, which have been established
at 1,000°C for two seconds (8). This could be accomplished in a system illustrated
in Attachment 15-5 consisting of a rotary kiln pyrolyzer, followed by a fume
incinerator (afterburner) and a scrubber. Destruction efficiencies in excess of
99.999% were achieved in such a device capable of maximum feed rates of approx-
imately 100 Ib/hr (7).
Incineration of PCBs
Polychlorinated biphenyls (PCB) are extremely stable and persistent synthetic com-
pounds which have been found to be dangerous to certain species and ecosystems.
Studies have been undertaken to establish the criteria for thermal destruction of
PCBs and related compounds (9). It was found that PCBs are more stable ther-
mally than Mirex —a very stable pesticide, as shown in Attachment 15-4. When
exposed to a very high temperature (1,000°C for one second in air), PCB destruc-
tion of greater than 99.995% can be achieved. Under thermal stress, PCBs can
decompose to lower molecular weight products which were not identified in this
study (9). Compounds related to PCB's exhibit similar thermal destruction behavior
as PCB mixtures.
15-3
-------
Waste Propellants, Explosives, and Pyrotechnics
Incineration appears, for the foreseeable future at least, to be the primary accept-
able 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 con-
tinuous feed method dilutes the PEP materials with sand, sawdust, or water. The
amount of feed and 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 emissions may be achieved with both of
these devices, but is not always practiced.
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 combustion 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 incinera-
tion. Small arms ammunition and pryotechnic items are expected to give off gases,
metallic fumes, vapors, and particulates comprised of metals and metallic com-
pounds. Carbon monoxide and nitrogen oxides are the most objectionable of the
gases, while combined or elemental forms of cadmium, lead, chromium, mercury,
silver, and antimony are the most objectionable of the paniculate matter.
Summary
Incineration appears to be a serious contender as a means of disposing of
hazardous waste materials. There are no universally applicable incineration
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 com-
bustion 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 pro-
ducts are not suitable for direct discharge to the atmosphere. Safe and
environmentally-acceptable disposal of solid residues (ash) cannot be overlooked.
15-4
-------
REFERENCES
1. Scrulock, A. C., et al., "Incineration in Hazardous Waste Management," 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, 68, No. 8,
59-64 (1972).
4. Kiang, Y. H., "Liquid Waste Disposal System," Chem. Eng. Progress, 71, No. 1 (1976).
5. "Determination of Incinerator Operating Conditions Necessary for Safe Disposal of Pesti-
cides," 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).
7. Carnes, 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 Disposal of Pesticides,"
Res. Rev., Vol. 29, 89-104 (1969).
9. "Laboratory Evaluation of High-Temperature Destruction of Polychlorinated 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 Propel-
lants," Esso Research and Engineering Co., Government Research Laboratory Report
(October 1973).
12. "Liquid Waste Incinerator," Bulletin STD IN-72-1C, C&H Combustion Co., Troy Michigan.
15-5
-------
Attachment 15-1. Submerged combustion incinerator^
Auxiliary fuel gas_
(if required).,
Chlorinated
hydrocarbon
Combustion air
Water -»Q Q 1}
Emrainment
separator
Downcomer
15-6
-------
Attachment 15-2. Liquid waste incinerator 12
Stack
Relief stack
—Venturi scrubber
Incinerator -
Quench
Demister —^ ID fan -
15-7
------- An error occurred while trying to OCR this image.
-------
Attachment 15-5. Kepone incineration test system'
Kepone injection
point
Kepone
solution
Sample
port
Stack
burner
Air
Note: Kiln temperature
was 900 °F.
Afterburner temp.
was 2,300 °F.
Afterburner residence
time was 2 sec.
Drain
15-9
-------
Attachment 15-6. Rotary kiln incinerator
Feed
Fuel
Water
Rotary cylinder Wet ^rubber
Exhaust
stack
Water
Attachment 15-7. Fluidized bed incinerator H
Propane
o
-GS-
Cyclone
separator
Vent
_,,. To flue-gas
analytical train
0
solids
receiver
fluid bed
combustor
O
Feed
Sigmamoter
15-10
-------
Chapter 16
Control Theory
Background
Emission of nitrogen oxides has been a major air pollution concern since the early
1950s 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 predicts the changes of air pollution emissions
and of solar intensity associated with the time of day. Photochemists have per-
formed many smog chamber experiments (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 atmospheric smog
is presented in the Attachment 16-3. Note that in the first equation a high-energy
photon of solar energy is absorbed by NC>2 causing dissociation into NO and O
(atomic oxygen). The formation of ozone and other unstable, radical products give
rise to the highly reactive, oxidant character of smog.
Emissions of NOX require control because of photochemical participation in pro-
ducing oxidants. Although very high concentrations of NOX may be directly haz-
ardous 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 NOX emissions from various stationary sources is illustrated
in Attachment 16-4. Utility boilers account for 42%, internal combustion engines
provide 22%, industrial boilers contribute 18%, and space heating is responsible
for 9%.
Projections of future NOX emissions are dependent upon the future energy
supply, as well as the amount of NOX emission control which will be applied in the
future. Attachment 16-5 provides a set of projections which does not assume con-
siderably stricter NOX controls in the future. Because of the potential growth in
NOX emissions and the resulting photochemical smog (ozone), NOX control is
becoming a major regulatory concern.
NOX emission factors for a large number of fuel and combustion equipment
combinations are tabulated in Attachment 16-6.
16-1
-------
NOX Formation
The dominant oxide of nitrogen which is formed in combustion processes is NO.
The NO will oxidize to NO 2 fairly slowly in ambient air, with only 5 % typically
being oxidized to NO2 before leaving the stack (except for gas turbine and diesel
engines). Other oxides of nitrogen, such as N2O, nitrous oxide; N2O^, nitrogen
trioxide; and N2Oj, nitrogen pentoxide, are of minor consequence. All the
nitrogen oxides, when referred to as a group, are called NOX.
Emissions of NOX arise from two different methods of formation during combus-
tion. Thermal fixation of nitrogen in 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."
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 temperature dissocia-
tion of oxygen molecules:
and nitrogen reactions:
A simplified model used for illustrative purposes is:
Where the NO formation is endothermic, i.e., energy is required rather than pro-
duced. This simplified model provides the following equation for the rate of pro-
duction of NO:
at
where (NO), (N2), and (02) represent the respective concentrations at a particular
instant of time, and where values of KF and KR increase considerably 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 equilibrium values of NOX
concentration as a function of temperature are presented in Attachment 16-7. The
calculation required assumed values for KF and KR (the forward and reversed reac-
tion rates, which increase greatly with temperature) and also values for the N2 and
O2 concentrations.
16-2
-------
Formation of "Fuel NOX"
Nitrogen of differing amounts is contained in the chemical composition 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 molecules may crack and
much of nitrogen will form A/2- On the other hand, if combustion zone is lean,
that is, oxygen is available, more fuel nitrogen oxides 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 No. 2 fuel oil. If it is
available, one might specify a low-nitrogen content No. 6 fuel oil. The nitrogen
content is influenced by refining processes, blending, and the original crude stock.
Changing from coal to oil or oil to gas usually is controlled by factors 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 control will be required.
NOX Control Theory
The three methods for reducing NOX are to change the fuel, to modify the com-
bustion system, and to treat or clean the flue gas.
Excess air reduction is an obvious combustion modification control technique, as
may be seen from the simplified model of "thermal" NOX formation. Excess air
reduction is very effective for "fuel NOX" 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 SO2 to SO). The formation of
SOj 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 O2). In gas-fired boilers, it appears that a minimum
desirable value of excess O2 exists 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 NOX 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 intro-
duced (lean combustion in this stage), so that adequate oxygen is available for
complete combustion. NOX emissions are reduced, partly because NO is not
16-3
-------
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 combustion. 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 concept in NOX con-
trol 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 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 eliminate
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 combus-
tion 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 somewhat 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 temperature, 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 reduction may be
achieved by energy conservation (lower demand) or by installing or using additional
combustion units. The effect of load reduction is shown in Attachment 16-13.
Scheduling frequent soot blowing will provide cleaner heat exchange surfaces
around the flame and thereby will limit the peak combustion temperature.
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 aircraft engines in the 1940s
(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.
16-4
-------
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 SO2-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 temperature 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 NO2 and A^O 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 is expressed for the possibility of this
technique being effective for controlling NOX, SOX, and particulates from coal-
fired power plants.
Fluidized Bed Combustion
A non-traditional combustion scheme is that of fluidized bed combustion. It
appears promising for future low NOX applications, mainly because combustion
occurs with low temperatures and because SOX control can be achieved also (5).
Various fluidized bed applications are being demonstrated, 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 Control, Harper and Row, Pub-
lishers, New York (1976).
5. "Control Techniques for Nitrogen Oxide Emissions from Stationary Sources," Second
Edition, EPA-450/1-78-001, U.S. Environmental Protection Agency (January 1978).
6. "Reference Guideline for Industrial Boiler Manufacturers to Control Pollution with Com-
bustion Modification," EPA-600/8-77-003b, Industrial Environmental Research
Laboratory, U. S. Environmental Protection Agency (January 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.
(August 15-21, 1976).
16-5
-------
8. Sensenbaugh, J. D., "Formation and Control of Oxides of Nitrogen in Combustion Pro-
cesses," Unpublished paper, Combustion Engineering, Inc., Windsor, Conn. (1966).
9. Muzio, L. J., Arend, J. K., and Teixeira, D. P., "Gas Phase Decomposition of NOX in Com-
bustion Products," Paper No. P-158, 16th International Symposium on Combustion, Cam-
bridge, MA (August 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).
16-6
-------
Attachment 16-1. Concentrations of total hydrocarbons, NO, NOg,
and 03 at Downtown Los Angeles (Sept. 29, 1969)2
50i-r
8 9 10 11 12
Hr, Pacific daylight time
13 14 15
Attachment 16-2. Experimental smog chamber data with propylene,
NO, and NO2 in air2
0.500
0 NO
* NO,
O Oxidant
O Propylene
X Pan
0.0
100 200
Time (min)
300
400
16-7
-------
Attachment 16-3. Generalized photochemical reaction equations4
O3 + NO-NO2+O2
O + hydrocarbons —stable products + radicals
Oj + hydrocarbons ~ stable products + radicals
Radicals + hydrocarbons — stable products + radicals
Radicals + NO - radicals + NO2
Radicals + NO2~stable products
Radicals + radicals-' stable products
Attachment 16-4. 1974 stationary source NOx Emissions5
Commercial/
residential
space head
9.0%
Utility boilers
41.9%
Reciprocating 1C
engines 19.
Industrial
boilers 18.2%
Incineration 0.3%
Gas turbines 2.0%
Others 3.6%
Noncombustion 1.7%
Industrial process
heating 3.5%
16-8
------- An error occurred while trying to OCR this image.
-------
Attachment 16-6. Emission factors for utility boilers, 19745
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
Oil
Gas
Coal, dry bottom
Coal, wet bottom
Oil
Gas
Coal, dry bottom
Coal, wet bottom
Oil
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
II)12 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
94.22
29.86
378.83
2.99
1020.62
12.64
2.92
55.53
131.98
56.60
Emission
factors
Ib NO2/106 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
16-10
-------
Attachment 16-6 (cont'd). Emission factors for industrial boilers,
19745
Equipment type
Field-erected
watertube boilers
>100xl06Btu/hr
Field-erected
watertube boilers
10-100 xl06Btu/hr
Field-erected
watertube 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
Oil
Gas
Coal, dry bottom
Coal, wet bottom
Oil
Gas
Coal, dry bottom
Coal, wet bottom
Oil
Gas
Coal, dry bottom
Coal, wet bottom
Oil
Oil
Gas
Coal
Coal
Coal
Coal
Fuel type
_
Residual
Natural
Process
-
-
Residual
Natural
Process
—
—
Residual
Natural
Process
—
—
Residual
Distillate
Residual
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
768.80
435.28
209.16
101.75
Emission factor
Ib NO2/106 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
16-11
-------
Attachment 16-6 (cont'd). Emission factors for industrial boilers,
19745
Equipment type
Packaged watertube
bent tube
straight tube
(obsolete)
Packaged watertube
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
f^QC
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 factor
Ib NO2/106 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
16-12
-------
Attachment 16-6 (cont'd). Emission factors for commercial boilers5
Equipment type
Packaged firetube
scotch
Packaged firetube
firebox
Packaged firetube
firebox, stoker
Packaged firetube
HRT
Packaged firetube
HRT, stoker
Packaged firetube,
general, not
classified
Packaged cast
iron boilers
Packaged watertube
coil
Packaged watertube
firebox
Packaged watertube
general, not
classified
Firing type
Wall firing
Wall 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 factor
Ib NO2/106 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
16-13
-------
Attachment 16-6 (cont'd). Emission factors for residential units. 19745
Equipment type
Steam or hot
water heaters
Hot air furnaces
Floor, wall, or
pipeless heaters
Room heater
with flue
Room heater
without flue
Firing type
Single burner
Single burner
Single burner
Single burner
Single burner
Fuel
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Fuel type
Distillate
—
Distillate
—
Distillate
—
Distillate
—
Distillate
Fuel
usage
1»12 Btu
1207.49
1000.11
1331.93
2929.80
199.11
675.04
298.67
700.06
190.79
Emission factor
Ib NO2/106 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 factor
Ib NOj/lO6 Btu
4.40
4.16
3.41
2.91
0.45
0.85
16-14
-------
Attachment 16-7. Theoretical curves of NO concentration vs.
temperature for oil and gas firing®
1000
800 -
200 -
2800
3000
3200
3400
Temperature (°F)
16-15
-------
Attachment 16-8. Effect of excess oxygen, fuel, and equipment on
nitrogen oxides emissions7
(Single lines for water-tube boilers; shaded areas
represent all fire-tube boilers)
ei
O
#
at)
2
1
8
I
I
800
600
400
200
600
400
200
400
200
Coal fuel
02 4 6 8 10 12 14
I I
Oil fuels
02 4 6 8 10 12 14
i J I
Natural gas fuel
02 4 6 8 10 12 14
Flue gas excess oxygen, %.
16-16
------- An error occurred while trying to OCR this image.
------- An error occurred while trying to OCR this image.
-------
Attachment 16-11. NOx emissions from horizontal and tangential
fired oil boilers8
700
600
500
400
X
o
300
200
100
Plant C
horizontal firing
Plant G
tangential firing
Percent Og
16-19
------- An error occurred while trying to OCR this image.
-------
Attachment 16-13. Effects of NOX control methods, including load
reduction for an oil, wall-fired utility boiler^
500
400
.2
o
*
S2
g
a
a
300
200
100
1
1
200 400 600
Load, MW (electrical)
Original
firing method
Two stage
Q combustion
6
Two stage
combustion
plus gas
recirculation
through
burners
800
1000
16-21
-------
Attachment 16-14. NOx emissions with water injection rate for
natural gas-fired gas turbines5
80
'wa'
•x
g 60
»*
^ 40 -
o
fc
PH
PM
0.4
0.8
i
1.2
1.6
2.0
T
2.4
Water injected (% of combustion air)
16-22
-------
Attachment 16-15. Effect of temperature on reducing NO
with ammonia9
i.o
0.8
0.6
a
j? 0-4
0.2
-L
1000 1100
1.1
1.6
_L
_L
1200 1300
Temperature, °K
_L
1400 1500
16-23
-------
Chapter 17
Improved Performance by Combustion
Modification
INTRODUCTION
Prior to the mid-1960s 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, preventive
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 efficiencies (1).
Efficiency-related maintenance of combustion equipment is directed toward cor-
recting 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 recommended 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.
Residential Oil-Burner Maintenance and Adjustments
Residential and commercial oil combustion units, with proper maintenance and
adjustment, can achieve improved thermal efficiency and minimized smoke, par-
ticulate, 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 for-
mation. 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 iginition, and the oil pump pressure
should be set to the manufacturer's specifications if necessary.
17-1
-------
Following the EPA recommended adjustment procedure, a smoke versus flue gas
CO2 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 Backarach 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 set-
ting should be adjusted for a CO2 level from 0.5 to 1.0% lower than the level at
the "knee." This will provide reasonable assurance that the unit can operate pro-
perly, without smoke, under normal operational fluctuations of fuel, air pressure,
air temperature, etc.
The results of the adjustment should be compared with the appropriate 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. Deviation 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 measured. 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 oil usually is suggested.
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 Attachment 17-5. After the "knee" of
the curve has been identified, the air setting should be adjusted to where the CC>2
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 selling at low-fire will be at
lower CO2 than at the high-fire condition.
17-2
-------
If the boiler is equipped for gas firing, the same procedure should be used.
Note, however, that for the same excess air, the COj? 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 operation 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 excess oxygen is reduced in coal and
oil-fired industrial units, a "smoke limit" or "minimum 02 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 emis-
sions rise (see Attachment 17-10). Therefore, a "CO limit" or "minimum O2 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 features, 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 sample. Boiler load characteristics typically
require operation with considerable burner modulation. Among the instruments
often available are continuous monitors for excess 0£ and CO£, CO, NOX,
opacity, and stack temperature.
The "minimum O_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 exhibit 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 minimum excess air described
above. The extra excess air is required to accommodate operating variables at a
particular installation, such as variation in fuel properties, rapid burner modula-
tion, variation in ambient conditions, and "play" in automatic controls. Changes in
air flow rate resulting from barometric pressure changes may be accommodated by
the lowest practical excess air. Other ambient variations, such as changes in
temperature 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. However, as was
discussed in Chapter 16, more extensive design modifications may be required for
considerable ATOX control. These will be discussed in the next sections.
17-3
-------
Industrial Boiler Combustion Modifications
Industrial boiler manufacturers can adopt important combustion design modifica-
tion techniques for reducing NOX emissions. From Attachment 17-12, one may
conclude that NOX emissions depend on the fuel, the excess air, and the design of
the particular installation.
In general, NOX emissions from coal, characterized mainly by fuel NOX, are
very sensitive to excess oxygen. The NOX from fuel oil is sensitive to excess oxygen,
but less so than coal, because of the lower nitrogen in oil. The NOX emissions from
natural gas, characterized 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.
Staged combustion has been demonstrated as an effective combustion modifica-
tion 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 NOX 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 control 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 Attach-
ment 17-20. Notice that the effects appear to be dependent on the particular com-
bustion equipment design. The recirculated 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 efficiency with flue gas recirculation; but this is probably not a
cost-effective method of NOX control.
Utility Boiler Combustion Modification
NOX control effectiveness for utility boiler 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.
17-4
-------
Depending on the NOX emission limits to be reached, combustion modification
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 burner-biased firing or burner-out-of-
service. The final stage would include major retrofit changes, such as including
overfire air ports, flue gas recirculation, and new burners.
Gas-fired utility boilers produce only thermal NOX, which is the easiest to con-
trol by combustion modification. As Attachment 17-21 indicates, larger units tend
to produce more NOX because of the higher combustion temperature (thermal
NOX ). Low excess air is used routinely in gas-fired utility boilers for NOX control.
This reduction, however, depends on furnace 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-service are effective designs for achieving off-
stoichiometric combustion.
Oil-fired utility boilers produce fuel NOX as an important part of the total NOX.
As expected, low excess air is used routinely in oil-fired burners for NOX control,
as well as improve thermal efficiency and to reduce the conversion of SO2 to SO_j.
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 NOX 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
successful. 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 stack. 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 nor-
mally operated boilers, as illustrated in Attachment 17-26. Off-stoichiometric firing
is an effective additional combustion modification for NOX control, as shown in
Attachment 17-27. However, fuel-rich burner conditions can produce excessive
smoke and CO and flame instability.
17-5
-------
It is unfortunate that NOX emissions from coal-fired utility boilers are so ?reat
even after combustion modification. It appears that NOX emissions wil be of
increasing regulatory concern because coal supply create? incentives for increased
burning of coal. Consequently, as mentioned in Chapter 16, conside ab e re eTrch
is now directed towar L°nS1QerabJe ^search
,
is now directed toward the development of
we., as coal-deanin, and fluidij-bed
REFERENCES
1. Industrial Boiler User's Manual, Vol. II, prepared by KVB
No. FEA/D-77/026 NTIS N<-> PR 9«9K7>7 -c j i . , '
* "^ INU. .r .D "^OiCD// H ffi f>T"^* I A /"1»-»-i
o "r- -j i- r ' cueral Aamimsiraiion (lanuarv 19771!
2. Guidelmes for Residential Oil-Burner Adjustments," Report No EPA 600/^75 069
Industnal Environmental Research Laboratory, USEPA (October 1975?
J . CrUlClCllnPS fVlT RllTTI^T- A rl ' t- C rf~i * "
EPA 600/2 7fi nns T ^ • ^/ii~rirea rioilers, Report No
(March 1976). Environmental Research Laboratory, USEPA
4' ^Epf^O/t??^1"13!1 H0"" ferf°rmance I-Provement," Report No.
EPA-600/8-77-OOS., Industnal Environmental Research Laboratory, USEPA Qanuary 1977)
5. Keed, R. D., Furnace Operations, Gulf Publishing Co., Houston (1976)
6. "Reference Guideline for Industrial Boiler Manufacturers to Control Pollution with Com
busnon Modoficauon," Report No. EPA-600/8-77-003b, Industrial Env^Hntl
Research Laboratory, USEPA (November 1977). environmental
;;Ze.du±: °1 ^r^r0™from 1^^ BOUCT, by 0^.
t ASME
«uotl^i nuuniLiiu - w*£l1 MaJor Com-
ReserrchTrbrra!o0ry!'uSETraune ^g^60077-78-0093' Industrial Environmental
H' '^Ed^R^No^PA^8™ °XideS EmiSSi°nS fr°m Stati°nary Sources," Second
17-6
-------
Attachment 17-1. Typical smoke-COg characteristic plot for a
residential oil burner2
I
v
1
u
2
«
1
pa
Normal adjustment range
12
Percent COg in flue gas
17-7
-------
Attachment 17-2. Typical aid adjustments for
different types of residential burners^
Oil-burner type
Typical CO
in flue gas
when tuned*
High-pressure gun-type burners
• Old-style gun burners
- 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
Other types of burners
• Atomizing rotary burners
- ABC, Hayward, etc.
• Rotary wall-flame burners
- Timkin, fluid-heat, Torridheet, etc.
• Miscellaneous low-pressure burners
8%
9 %
10 %
8 %
12 %
* Based on accpetable Bacharach smoke — generally No. 1 or trace, but not exceeding No. 2.
Caution should be used in leaving burners with CO% level higher than 13%.
** See manufacturer's instructions.
17-8
-------
Attachment 17-3. Effect of stack temperature and COg on thermal
efficiency
U
u
Net stack temperature
400 F
55
50
9 10 11 12
Percent COg in flue gas
Basis: • Continuous operation
• No. 2 heating oil
• Heat lost from jacket is assumed
to be useful heat.
14 15
Source: Bulletin 42, University of Illinois, Engineering Experiment Station Circular Series 44
(June 1942).
Attachment 17-4. Usual range of firing viscosity^
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 cs
4-55 cs
32-60 cs
17-9
-------
Attachment 17-6. Maximum desirable smoke3
Fuel grade
Maximum desirable
Bacharach smoke number
No. 2
No. 4
No. 5 (light and heavy),
and low-sulfur resid
No. 6
1 or less
2
3
Attachment 17-7. COg variation with excess air and fuels3
Percent
excess air
0
10
25
50
75
Percent COg in flue gas
Gas
firing
12.0
10.8
9.4
7.9
6.6
No. 1 oil
firing
15.0
13.5
11.8
9.8
8.3
No. 6 oil
firing
16.5
15.0
13.0
11.0
9.3
17-10
------- An error occurred while trying to OCR this image.
-------
Attachment 17-8. Variation of boiler efficiency losses with excess
25
20
u
'o
15
10
Total efficiency loss
Flue moisture
Dry flue gas
Radiation
Combustibles (carbon monoxide)
I I I
Excess Og, %
17-12
-------
Attachment 17-9. Typical smoke-Og characteristic curves for coal or
oil-fired industrial boilers^
t
fc
SO
CO
>~^
I
c
i.
o
CO
Low air settings
Curve (2
High air settings
Curve (T)
Test points
Appropriate operating
margin from minimum Og
Automatic boiler
controls adjusted
to this excess O
Minimum Og
Percent Og in flue gas
Curve 1—Gradual smoke/Og characteristic
Curve 2—Steep smoke/Og characteristic
17-13
-------
Attachment 17-10. Typical CO-Og characteristic curves for gas-fired
industrial boilers'*
1
Low air settings
Curve 2
High air settings
Test points
Curve 1
Appropriate operating
margin from minimum Og
CO limit (400 ppm)
Minimum
Automatic boiler
controls adjusted
to this O
Percent Og in flue gas
Curve 1—Gradual CO/O2 characteristic
Curve 2—Steep CO/Og characteristic
Attachment 17-11. Variation of minimum Og with fuel'1
Fuel Type
Natural gas
Oil fuels
Pulverized coal
Coal stoker
Typical range of minimum
excess Og at high
firing rates
0.5-3.0%
2.0-4.0%
3.0-6.0%
4.0-8.0%
17-14
-------
Attachment 17-12. Effect of excess oxygen and fuel on
'*
emssons
(Single lines for water-tube boilers;
shaded areas for fire-tube boilers)
800
600
400
200
Coal fuel
10 12 14
1
u
u
s.
1
g
ft
ft
oT
I
.a
X!
O
fc
600
400
200
400
200
I I
Oil fuels
10 12 14
1
Natural gas
fuel
2 4 6 8 10 12
Flue gas excess oxygen, %
17-15
-------
Attachment 17-13. Schematic diagram of staged-air system installed
on a 40,000-lb/hr watertube boiler^
t
183 cm
\
Windbox '
Port "-ix">vr— ix~Xl~~— l/C5\T
nos. IJSjl 7 |£>S3) 9 |g$J
Furnace
* . , 310 rm
-i 249 cm *-
-«i 166 cm— »•
86 _J
^"cm~^j
portfeV^8(^i
nos. i^j'i r*jfi r^^i
_ / ^
11 ^| 13, 15
I!
. !!
ii
ii
ii
ii
ii
10 jgj 12, 14
i
T^
/
36 cm dia.
manifold
(a) Top view
320
cm
r^
f^>
Sidefire air fan
. 1
1
Windbox
cm
Furnace
14, 15
86 cm 80 cm 83 cm JjlcitfYjsg
C\ C\ O r\*
\J \^J Vj/ \J
T Port 6, 7 8, 9 10, 11 12, 13
| nos.
i
366
(b) Side view
Dividing wall
17-16
-------
Attachment 17-14. Reduction in nitrogen oxides from staged
combustion air, natural gas
X
o
be
a
o
120 --
110 --
100 --
90 --
80 --
70 --
60 --
50 --
I
240
220
200
180
160
140
120
100
I
Fuel rich
I
Air rich
combustion
combustion
Baseline (1.9% O2)
Other points (2.9—3.4%)
Symbol Port Open
O None (Baseline)
6&7
8 &9
10&11
12 & 13
14 & 15
15 only
14 only
O
o
D
A
90
95
100
105
110
115
120
Theoretical air at burner, % of stoichiometric
17-17
------- An error occurred while trying to OCR this image.
------- An error occurred while trying to OCR this image.
-------
Attachment 17-17. Effect of combustion air temperature on
total nitrogen oxides emissions with gas and oil fuels for
three watertube boilers^
8
O 6*
H G
200 --
150 --
100 --
50 --
0 -1-
200 --
150 --
4*>
(9
l->
O
ioo --
50 --
400
300 -
eo
© 200
J-.
-O
o -L
100
O
\
Boiler rated
at 44500 Ib/hr
steam flow
Boiler rated at 40000
Ib/hr steam flow
\
— Boiler rated at
250,000 Ib/hr
steam flow
• Baseline air temp.
O Natural gas
O No. 6 oil
I I
100
200
300
400
500
300
350
400
450
K
Combustion air temperature
500
17-20
-------
Attachment 17-18. NOx control by air preheat reduction^
1000
a 500
Coal
Oil
Gas
I
500
Preheat, °F
1000
Effect of air preheat at normal excess air levels.
1000
1
O 500
Coal
Oil
Gas
500
Preheat, °F
1000
Effect of air preheat at high excess air.
17-21
------- An error occurred while trying to OCR this image.
------- An error occurred while trying to OCR this image.
------- An error occurred while trying to OCR this image.
-------
Attachment 17-22. Effects of NOX control methods on a gas,
wall-fired utility boiler H
.3
vi
a
(M
o
a,
a,
X
O
1600
1400
1200
1000
800
600
400
200
I
Original
firing
method
Reduced
excess
air firing
Two stage
combustion
Two stage combustion
plus gas recirculation
i through burners
200
400
600
800
1000
Load, MW (electrical)
17-25
------- An error occurred while trying to OCR this image.
-------
Attachment 17-24. Two-stage combustion H
\
Secondary oxidizing zone
CO + O-CO2
^ "Overfire air port"
/ 2CH4 + 302 _ 2CO + 4H2O \
' CH4 + 2O2 - CO2 + 2H2O \
O2-C+2H20
CH
4 •*
f
Primary reducing zone
Fuel nozzle
T
Air register
17-27
-------
Attachment 17-25. Effects of NOx control methodsll
500
400
300
200
100
I
I
200 400 600
Load, MW (electrical)
Original
firing method
Two stage "
combustion
Two stage
combustion
plus gas
recirculation
through burners
800
1000
17-28
------- An error occurred while trying to OCR this image.
-------
Attachment 17-27. Effect of burner stoichiometry on
production in tangential, coal-fired boilers U
a
a,
700
600
500
400
300
200
100
0
40.00 60.00 80.00 100.00 120.00 140.00 160.0 180.00
Stoichiometry to active burners (percent)
17-30
-------
Attachment 17-28. Pulverized coal burner adapted for
low NOx emissions
Retractable lighter
and auxiliary burner ass'y
Adjustable air
vanes and registers
Adjustable
venturi plug
Primary
air/coal venturi
Secondary
combustion
17-31
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-450/2-80-063
2.
4. TITLE AND SUBTITLE
APTI COURSE 427
COMBUSTION EVALUATION
Student Manual
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
JFebruary 1980^
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO
J. Taylor Beard, F. Antonio lachetta, Lembit U. Lilleleht
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Associated Environmental Consultants
P. 0. Box 3863
Charlottesville, Virginia 22903
10. PROGRAM ELEMENT NO.
B18A2C
11. CONTRACT/GRANT NO.
68-02-2893
12. SPONSORING AGENCY NAME AND ADDRESS
U. S. Environmental Protection Agency
Manpower and Technical Information Branch
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Student Manual
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
EPA Project Officer for this manual is James 0. Dealy
EPA RTF, NC 27711
(MD-17)
16. ABSTRACT
This Student Manual is used in conjunction with Course #427, "Combustion Evaluation"
as applied to air pollution control situations. The manual was prepared by the
EPA Air Pollution Training Institute (APTI) to supplement the course lecture
materials and to present detailed reference information on the following topics:
Combustion fundamentals
Fuel properties
Combustion system design
Pollutant emission evaluations
Combustion control
Gas, oil & coal burning
Solid waste & wood burning
Incineration of wastes
Sewage sludge incineration
Flame and catalytic incineration
Waste gas flares
Hazardous waste combustion
NO control
v
Improved combustion systems
Note: There is also an Instructor's Guide to be used in conducting the training
course - (EPA-450/2-80-065) and a Student Workbook to be used for homework and
in-class problem solving - (EPA-450/2-80-64).
7.
KEY WORDS AND DOCUMENT A.MALVSSS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Combustion
Air Pollution Control Equipment
Personnel Development - Training
Incinerators
Nitrogen Oxides
Exhaust Gases
Emissions
Training Programs
Fuels
13B
51
68A
3. DISTRIBUTION STATEMENT Unlimited. Available
From: National Technical Information Serv:
5285 Port Royal Road
Springfield, Virginia 22161
19. SECURITY CLASS (This Report)
ce Unclassified
21. NO. OF PAGES
364
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
17 -32
------- |