United States
Environmental Protection
Agency
Air Pollution Training Institute
MD20
Environmental Research Center
Research Triangle Park, NC 27711
EPA 450/2-84-010.
December 1984
Air
xvEPA
APTI
Course SI:428A
Introduction
to Boiler Operation
Self-instructional
Guidebook
-------
united estates
Environmental Protection
Agency
Air Pollution Training Institute
MD20
Environmental Research Center
Research Triangle Park, NC 27711
EPA 450/2-84-010
December 1984
Air
APTI
Course S 1:428A
Introduction
to Boiler Operation
Self-instructional
Guidebook
Written by:
David S. Beachler
ETS, Inc.
Raleigh, NC
Instructional Design by:
Marilyn M. Peterson
Peterson Communications
Durham, NC
Production by:
Northrop Services, Inc.
P.O. Box 12313
Research Triangle Park, NC 27709
Under EPA Contract No.
68-02-3573
EPA Project Officer
R. E. Townsend
United States Environmental Protection Agency
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
-------
Notice
This is not an official policy and standards document. The opinions and selections
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.
The author requests that any material abstracted from this manual be
appropriately referenced as a matter of professional courtesy in the
following manner:
Beachler, D.S. 1984. Introduction to Boiler Operation —Self Instructional
Guidebook. APTI Course SI:428A, EPA 450/2-84-010.
Acknowledgements
The author would like to thank Wendy Barricks Musser for her tremendous effort
in preparing the graphic materials for this manual. The author would also like to
thank Karen Sampson for reading and deciphering the authors' often times illegible
handwriting and turning it into a finished typeset document.
This document is dedicated to Benjamin Linsky, former professor of the West
Virginia University.
11
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Table of Contents
Page
Course Introduction 1
Description 1
Course Goal and Objectives 1
Prerequisite Skills 1
Requirements for Successful Completion 2
Reading Materials 2
Using the Guidebook 2
Instructions for Completing the Final Examination 3
Lesson 1. Boiler Fundamentals 1-1
Lesson Goal and Objectives 1-1
Introduction 1-1
Heat Transfer 1-1
Boiler Designs 1-2
Summary 1-17
Lesson 2. Combustion Efficiency 2-1
Lesson Goal and Objectives 2-1
Combustion Variables 2-1
Combustion Calculations 2-3
Combustion Limits 2-7
Thermodynamic and Combustion Terms 2-7
Heat Balance _ 2-10
Boiler Efficiency 2-13
Heat Losses 2-14
Lesson 3. Supplying Air and Fuel 3-1
Lesson Goal and Objectives 3-1
Introduction 3-1
Combustion Air 3-1
Draft 3-2
Coal-Fired Boilers 3-3
Oil-Fired Boilers 3-20
Gas-Fired Boilers 3-22
Lesson 4. Operation and Maintenance 4-1
Lesson Goal and Objectives 4-1
Introduction 4-1
Controls and Instruments 4-1
Operation 4-10
Maintenance 4-12
Summary . . 4-16
111
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Page
Lesson 5. Steam Turbines, Condensers, and Cooling Towers 5-1
Lesson Goal and Objectives 5-1
Introduction 5-1
Steam Turbines 5-1
Condensers „ . 5-6
Cooling Water Systems • 5-8
Summary 5-10
Lesson 6. Air Pollution Emissions, Regulations, and Control Techniques
for Industrial and Utility Boilers 6-1
Lesson Goal and Objectives 6-1
Air Pollution Emissions 6-1
Emission Regulations 6-3
New Source Performance Standards for Fossil Fuel-Fired Steam Generators 6-3
New Source Performance Standards for Electric Utility Steam Generators 6-4
Proposed New Source Performance Standards for Industrial Boilers 6-7
Air Pollution Control Equipment 6-7
Summary 6-11
Appendix A. Compilation of Air Pollutant Emission Factors A-l
Appendix B. Conversion Factors B-l
IV
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Course Introduction
Description
Designed for engineers and other technical persons responsible for inspecting boilers,
this course is an introduction to their operation. The course focuses on the major
components of boilers and how boilers operate to produce steam, heat, or electricity.
Major topics related to boilers include the following:
• Fire-tube and water-tube designs
• Combustion efficiency
• Supplying air and fuel
• Operation and maintenance
• Steam turbines, condensers, and cooling towers
• Air pollution emissions and control techniques
Course Goal and Objectives
Goal
To familiarize you with boilers—their operation, use of various fuels, common
operation and maintenance problems, and components and add-on air pollution
control devices which must be inspected.
Objectives
Upon completing this course, you should be able to —
1. briefly describe the overall operation of a boiler,
2. recognize the difference between a fire-tube and a water-tube boiler,
3. calculate boiler efficiency using various figures and tables,
4. briefly describe how air and fuel are introduced into a boiler,
5. recognize various boiler auxiliary equipment and their use, and
6. list three potential air pollution emissions from boilers and at least three
control devices used to reduce these emissions.
Prerequisite Skills
• Completion of SI:422 (3rd edition), Air Pollution Control Orientation
• Completion of SI:431, Air Pollution Control Systems for Selected Industries
It is also recommended that you complete the APTI course series SI:412A,
Baghouse Plan Review; SI:412B, Electrostatic Precipitator Plan Review; and
SL412C, Wet Scrubber Plan Review; particularly if you are evaluating plans for the
installation of a boiler and associated air pollution control devices.
-------
Requirements for Successful Completion
In order to receive 2.0 Continuing Education Units (CEUs) and a certificate of
course completion, you must achieve a final examination grade of at least 70%.
Reading Materials
This text —supplementary reading materials are not required. English units are used
in this document to help simplify calculations. Both metric and English units are
used in Lesson 6 because the New Source Performance Standards are given in both
sets of units. Appendix B contains conversion factors to convert English units into
metric units.
Using the Guidebook
This book directs your progress through the course. Each lesson contains a goal and
objectives, text, and review exercises. To complete a review exercise, place a piece of
paper across the page, covering the questions below the one you are answering. After
answering the question, slide the paper down to uncover the next question. The
answer for the first question will be given on the right side of the page, separated by
a line from the second question, as shown in Figure 1. All answers to review ques-
tions will appear below and to the right of their respective questions. The answer will
be numbered to match the question. Please do not write in this book. Complete
each review exercise in the lessons. If you are unsure about a question or answer,
review the material preceding the question. Then proceed to the next section.
Review Exercise
i.
2.
3.
l--^
Question lonlo
till i cllo >/||
Question > in loi
.jjo nlj i cllo yllon
1. Answer
llllO
2. Answer
Hi-"iill'
Figure 1. Review exercise format.
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Instructions for Completing
the Final Examination
Contact the Air Pollution Training Institute if you have any questions about the
course or when you are ready to receive a copy of the final examination.
After completing the final exam, return it and the answer sheet to the Air Pollu-
tion Training Institute. The final exam grade and course grade will be mailed to
you.
Air Pollution Training Institute
Environmental Research Center
MD 20
Research Triangle Park, NC 27711
-------
Lesson 1
Boiler Fundamentals
Lesson Goal and Objectives
Goal
To familiarize you with the fundamental operation of a boiler.
Objectives
Upon completing this lesson, you should be able to —
1. define heat transfer and recognize the difference between three transfer
methods,
2. distinguish between a water-tube and a fire-tube boiler,
3. list five tube sections of a boiler and identify their use, and
4. recognize the various ratings and classifications used to identify boilers.
Introduction
A boiler is a closed vessel containing water. Water is changed into steam when
heated under controlled conditions. Fuels most commonly used as the heat source for
a boiler are natural gas, oil, and coal—-referred to as fossil fuels. Other fuels such as
wood and solid waste materials are also used. In the boiler, chemical energy
contained in the fuel is convened to thermal energy. Thermal energy heats water
contained in boiler tubes or the shell to make steam. Steam can then be used for
many industrial proceses including refining petroleum, manufacturing automobiles,
paper, chemicals, and for driving turbines to generate electricity.
Heat Transfer
Every boiler is designed to transfer as much heat as possible (produced from burning
fuel) to the water contained in the boiler. Heat is transferred by conduction, radia-
tion, and convection, although the amount of each will vary depending on the boiler
design. Conduction is heat transfer by direct physical contact between a hot object
and a cooler object, or from one part of an object to another part of the same
object. Heat flows from the hot object to the cold object until there is no longer a
temperature difference between the two objects in contact. The rate at which the
heat is transferred will depend on the temperature difference between the two
1-1
-------
objects (or parts of the same object) and the heat carrying abilities of the
material —called conductivity. Metals are very efficient conductors of heat. Fiborous
materials such as fiberglass insulation are inefficient conductors of heat. In a boiler,
heat is conducted through the metal in the shell and tubes.
Radiation is the transfer of heat through space from a hot object to a cooler one.
Radiation does not require any physical contact between the two objects because
radiated heat travels by electromagnetic vibrations. For example, heat is radiated
from the hot coals in a camp fire to people sitting around the fire even though the
air between the two remains relatively cool. The amount of heat absorbed by radia-
tion depends on the temperature difference and the distance between the two
objects, and the nature of the objects. The amount of heat absorbed increases as the
temperature difference and distance between two objects decreases or as the
temperature difference increases. In the boiler heat is radiated by the flames in the
combustion zone, called the firebox. Heat is absorbed by the boiler tubes located in
the firebox, and nearby areas of the furnace.
Convection is the transfer of heat by heated fluid. In the case of a boiler, the fluid
is the hot gases produced by burning fuel. Heat is transferred from the hot gases to
the cold boiler tubes containing water. Convection can be either natural or forced.
Natural convection occurs as the heated fluid expands and rises. Cooler portions of
the fluid move into the space vacated by the hotter fluid. This mixes the fluid,
moving heat from one part of the fluid to another. In forced convection the heated
fluid is moved by devices such as a fan or pump.
Boiler Designs
Boilers are either fire-tube or water-tube designs. In fire-tube boilers, hot combus-
tion products pass through the inside of heat exchanger tubes while water, and even-
tually steam, are contained outside the tubes by an outer shell. In water-tube boilers,
hot combustion products pass over tube sections containing water. Water in the
tubes is boiled to make steam.
Fire-Tube Boilers
Many small- and medium-sized units are fire-tube boilers. They are usually packaged
and sold with burners, blowers, and other equipment all mounted in the same
framework. These units generally produce low-pressure steam or heat for small
industries, commercial businesses, schools, hospitals, and other institutions.
Fire tubes are straight and connected at their ends by tube sheets. A large body of
water, surrounding these tubes and contained in a large shell, boils into steam. The
pressures of the steam produced are usually limited to 250 psig because large
diameter shells cannot withstand very high pressures.
One common fire-tube boiler is the horizontal return tubular (HRT). Figure 1-1
shows a four pass HRT boiler. These boilers are usually designed to burn either
natural gas or oil. The first pass occurs as the hot gases generated during combus-
tion pass through the long furnace tube, or combustion chamber. The gases then
1-2
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move into the tubes at the bottom of the boiler for the second pass. In the third
pass, the gases pass through the tube bank directly above the combustion chamber.
Finally they reverse direction and pass through the bank of tubes in the top of the
furnace and out the stack. HRT boilers vary in size; 4 to 15 ft in diameter and
lengths of 6 to 40 ft.
Water
Heat
exchanger
tubes
Combustion
chamber
Source: Cleaver Brooks brochure.
Figure 1-1. Typical four pass horizontal return
tube boiler.
Another boiler, the Scotch marine, has one or more cylindrical furnaces. The fur-
nace is usually a large-diameter tube made of corrugated metal. Some are fired from
both ends and called double-ended Scotch boilers. Figure 1-2 shows a conventional
Scotch marine boiler with the furnace and tubes contained within the shell. Combus-
tion gases pass through the furnace into the tubes where they heat the surrounding
water. Scotch marine boilers are similar to HRT boilers, except that they usually
don't have as many tube passes. These units can be designed to burn either gas, oil,
or coal. Scotch marine boilers have overall diameters from 3 to 8 ft and lengths of
approximately 4 to 20 ft.
1-3
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Steam outlet
Water inlet
Fire tubes
Fuel grate
Figure 1-2. Typical Scotch marine boiler.
A variation of a horizontal return tube boiler has a refractory lined firebox. In
this unit, hot combustion gases pass through tubes located in the upper portion of
the furnace. Water contained in the outer shell is heated as the hot gases pass
through the tubes (Figure 1-3). These boilers occasionally burn coal but can also
burn gas or oil. The sizes of these units are similar to Scotch marine boilers.
Fire tubes
Bridge wall
Fuel grate
Figure 1-3. Typical fire-tube boiler with a
refractory-lined firebox.
1-4
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Water-Tube Boilers
Water-tube boilers are constructed in a wide range of sizes. All large steam
generators are water-tube boilers. Hot combustion products pass over tube sections
containing water. Water is boiled to make steam that is collected in steam drums in
the furnace. These boilers are used when large amounts of high pressure steam are
needed.
The cross-sectional area of each water tube is much smaller than that of the shell
used in a fire-tube boiler. Therefore, water tubes can handle higher pressures and
temperatures than can fire tubes. Pressure can be as high as 5000 psig and
temperatures can be as high as 1000°F.
The layouts of the tubes and drums vary depending on their size and the type of
fuel burned. Both bent and straight tubes can be connected to one or more drums.
Figure 1-4 shows a water-tube boiler with two drums. The lower drum is usually
called the mud drum and contains water. The upper drum, called the steam drum,
contains both steam and water (condensed steam). Units such as these are usually
assembled in the field.
Steam drum
Water tubes
Burners
Mud drum
Source: Babcock and Wilcox, 1978.
Figure 1-4. Typical water-tube boiler.
1-5
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Figure 1-5 shows a water-tube boiler that has four drums. Water enters the top
drum on the right-hand side of the boiler. This drum contains a mixture of steam
and water. Water flows vertically through tubes called downcomers to the bottom
drum (mud drum). Mud drums are occasionally called water-wall headers. Heated
water moves up through tubes called risers to the center drum and then back to the
top drum. Here, steam is separated, some of it condensing and falling back into this
drum. Separated steam flows through a tube into a steam drum, located in the top
left-hand corner of the boiler. Steam hi the steam drum is drier because most of the
moisture has been removed by steam separators.
Steam drum
Center drum
Top drum
Downcomers
Mud drum
Fuel grate
Figure 1-5. Water-tube boiler with four drums.
Large water-tube boilers that make steam for generating electricity are very com-
plicated in design. Figure 1-6 shows the tube sections of a typical large water-tube
boiler. Each section is designed to extract as much heat as possible from the flue gas.
The five main tube sections of the boiler are the water walls (or fire walls), convec-
tion tubes, superheater, economizer, and air preheater.
1-6
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To
stack
Induced*
draft )
fan I/
Water wall
tubes
Source: Babcock and Wilcox, 1978.
Figure 1-6. Water-tube boiler showing the various
tube sections.
1-7
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Water Walls
Most modern large water-tube boilers have tubes that completely surround the
firebox or furnace, called water walls or fire walls. They are exposed to intense
radiant heat in the firebox. Because these tubes contain water, they also help cool
the walls of the furnace, thus eliminating the need for a thick refractory lining.
Some boilers use tubes that are lined with refractory as shown in Figure 1-7. Others
use water walls that are metal tubes with bars welded between them (Figure 1-8).
Block insulation separates the metal tubes from the outside wall made of metal
lagging. These are called membrane walls. Special refractory materials are occa-
sionally used to help protect them from molten slag and resulting erosion. In addi-
tion, water walls and burners are carefully designed to prevent flames from imping-
ing on tube surfaces which causes them to overheat and eventually burst.
Tube
Steel casing or cement
Block
insulation
• Refractory
Figure 1-7. Water walls with partial
refractory lining.
Tube
.Welded bar
Block ^
insulation
Metal lagging
Source: Babcock and Wilcox, 1978.
Figure 1-8. Membrane water walls.
1-8
-------
Water in the water walls forms steam bubbles which rise through tubes, called
risers, and are collected in a steam drum located in the top part of the boiler. Some
steam condenses out and drains back down to the bottom of the boiler through
downcomer tubes. These tubes are usually not directly exposed to the fire in the
firebox and are, therefore, relatively cool. The downcomers connect to water-wall
headers located in the base of the furnace.
Figure 1-9 shows a simplified representation of a single circuit. The flow of water
and steam in this arrangement occurs because of the difference in densities of water
and steam. Water is denser and will flow down through the downcomers while steam
bubbles up through the risers. The steam and water loops are made by using a
number of drums, many riser tubes, and a few large downcomer tubes, depending
on the boiler design. In large boilers, tube layout becomes quite complex.
Downcomers are exposed to some heat and the force available for natural water cir-
culation becomes smaller. Boilers producing high pressure steam generally use
pumps to circulate the water from the downcomers into the water-wall headers.
Steam drum
Risers
Downcomers
Furnace floor
Water wall header
(mud drum)
Figure 1-9. Simplified representation of a single circuit.
Convection Tubes, Steam Drums, and Superheaters
Hot flue gas is pulled through the boiler by an induced draft fan. Hot flue gas
passes over tubes located in the upper portion of the boiler. Because heat is trans-
ferred by convection, these are called convection tubes. Water in the water wall
tubes turns into steam and is collected in the steam drum or drums located in the
convection section (Figure 1-10). Steam and water that may have condensed when
reaching the steam drum are heated as hot flue gas moves over and around the con-
vection tubes.
1-9
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* Sceam drum
•Convection tubes
Figure 1-10. Convection section.
Steam drums used to collect and separate steam, are long and cylindrical. They
contain approximately 50% steam and 50% water. Some of the water in the drum is
condensed steam, the other is makeup water that is needed when steam is withdrawn
for uses in the plant. A typical steam drum is shown in Figure 1-11.
Steam outlet
Cyclone
separators
Feed pipe
Source: Babcock and Wilcox, 1978.
Figure 1-11. Typical steam drum.
1-10
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Heated feedwater enters the steam drum through internal feed pipes located along
the entire length of the drum bottom. Perforated holes in the feed pipes allow water
to flow into the steam drums. Figure 1-12 shows components of a steam drum in
more detail. Steam and water are usually separated by cyclone separators, open at
the top and bottom. Steam and water from the water-wall tubes enter the base of
each cyclone separator. Water is thrown to the side of the cyclone by centrifugal
force and drains to the bottom of the drum. Steam first passes through baffles or
chevron blades at the top of the cyclone, then through drying screens or chevron
blades at the top of the drum. As the steam touches the screens or chevron blades,
additional moisture will cling to the surfaces and be removed. Steam is now drier
before it enters the superheater.
Downcomers
Chevron blades
Cyclone separator
Risers
Figure 1-12. Detail of steam drum.
Steam leaves the steam drum at approximately 650 °F. In some cases, the steam
would be ready to be used in an industrial process. However, in boilers used in
power plants and many industrial processes, steam is heated to higher temperatures
in tube sections called superheaters (Figure 1-13). Steam leaving superheaters can
have temperatures as high as 1000 °F. Many boilers have a number of superheaters.
Each is named for its location in the boiler. For example, steam from the steam
drum usually passes into a primary superheater, or convection superheater. This
superheater is heated by convection heat —thus its name —convection superheater.
Steam then goes to a radiant superheater that receives radiant heat directly from the
fire in the furnace — thus its name. Steam can then go into pendant superheaters
that hang from the roof of the boiler. These are also called reheaters because steam
that has made one pass through the turbine is reheated in this tube section.
Superheated steam has several advantages over ordinary steam. It is hotter;
therefore, boiler efficiency is increased. Also, since superheated steam is drier, it does
not easily condense into droplets that can corrode and errode turbine parts.
1-11
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Radiant _
superheater
Steam drum
Convection
superheater
Hot flue gas
Figure 1-13. Superheaters.
Economizer
Boiler feedwater, or makeup water, is heated in a tube section called an economizer
before it is delivered to the steam drum. As we said earlier, steam is drawn from the
steam drums to the turbine as the demand for electricity increases, or to the plant as
the demand for process steam increases. To replace this, an equivalent amount of
water, called makeup water, or feedwater, is pumped through economizer tubes
where it is heated before it enters the steam drum (Figure 1-14). Water leaving an
economizer reaches a temperature of at least 212°F. In boilers used in power plants,
the feedwater coming into the economizer is preheated by feedwater heaters to get it
to very high temperatures. Water temperature leaving an economizer/feedwater
heater system can be as high as 600 °F.
Economizer tubes usually have fins that help promote heat transfer from the hot
flue gas to the water flowing through the economizer. Heated water from the
economizer is collected in the outlet header. A header is a long pipe or tube with
holes in its sides to allow water (or steam in the case of a steam header) to be evenly
collected or distributed. From the outlet header, feedwater flows into the steam
drum.
1-12
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Flue gas
Water inlet
Figure 1-14. Economizer.
Air Preheater
An air preheater is a tube section that preheats the air used for burning the fuel in
the furnace. It is usually placed after the economizer and before or after the air
pollution control equipment in a boiler system. The most widely used are tubular,
rotary, and Rothemuhle air preheaters.
A tubular air preheater has a number of small tubes, 1 to 2 in. in diameter,
through which the flue gas flows. Cool air is forced over and around the tubes by a
small forced draft fan (Figure 1-15). The hot flue gas passing through the tubes
transfers heat to the "cool" air. Warmed air leaving the air preheater is sent to
burners where it is used to burn fuel.
1-13
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Cold air inlet
Dampers
Flue gas outlet
By-pass damper
Heated air outlet
Soot hopper
"^Baffle
Hot flue gas inlet
V
Figure 1-15. Tubular air preheater.
Many modern large water tube boilers use rotary, or regenerative, air preheaters.
Regenerative air preheaters are large heat exchanger wheels that contain heat
absorbing materials (Figure 1-16). In these devices, hot flue gas flows through one
portion of the wheel while cool, clean combustion air passes through the remaining
portion. Heat is stored in the absorbing material through which the hot flue gas
flows. As the wheel revolves, the cold combusion air passes through these hot sur-
faces and becomes heated. This preheated air is sent to the burners and is burned
with fuel in the firebox. The absorbing material of the wheel is constructed of cor-
rugated sheet metal plates. The plates, arranged in a honeycomb matrix, provide
both maximum heat transfer and air flow between the plates. These devices are
more efficient than shell-and-tube heat exchangers.
The Rothemuhle regenerative air preheater consists of a stationary heating ele-
ment and two rotating air hoods. Hot flue gas enters a large duct surrounding the
air preheater. The flue gas flows over a portion of the heating surface not blocked
by the hoods, thus heating it. The air hoods rotate slowly around the stationary
heating surface causing the cool air to become heated (Figure 1-17).
Air preheaters can improve the overall boiler efficiency from 2 to 10%. Preheated
air accelerates combustion by producing rapid ignition of fuels. It also allows using a
low amount of excess air (see Lesson 2), thereby increasing boiler efficiency.
1-14
-------
Cooled flue gas outlet
(to induced draft fan)
Cold air inlet
(from forced draft fan)
Hot flue gas Hea£ed ^ (w boiler)
Figure 1-16. Rotary air prcheater.
Heat absorbing
material
Flue gas inlet
Heated air
outlet
(to boiler)
Stationary
heating surface
Rotating
hoods
Rue gas outlet
Cold air inlet
Source: Babcock and Wilcox, 1978.
Figure 1-17. Rothemuhle regenerative air preheater.
1-15
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Boiler Sizes and Ratings
Boilers are usually grouped by capacity on another classification such as the pressure
at which it operates. Capacity refers to the heat or steam output of a boiler. The
terms used to express capacity depend on the size of the boiler. Boiler manufacturers
designate the capacity of medium and large boilers in terms of pounds of steam
generated per hour at a specific temperature and pressure. Small boilers are usually
designated by the total square feet of heating surface, horsepower (hp), or percen-
tage of rating (TPC Training Systems, 1975).
The total heating surface refers to all heat exchanger surfaces exposed to the hot
flue gas on one side and the water or steam on the other side. Boilers are also rated
by boiler horsepower —one boiler hp is equal to a heat output of 33,475 Btu per
hour. The rated hp of a boiler depends on the boiler design and its amount of
heating surface. Occasionally boilers are designated by the percentage of rating—the
actual capacity divided by the rated capacity. This designation is used when a boiler
produces more steam than the rated capacity. Thus, if a boiler produces two times
the amount of its rated capacity, it operates at 200% of rating.
Boilers are also classified by the pressure at which they operate. The five common
groupings are: below 900 psi, 900 to 1000 psi, 1200 to 1500 psi, 1800 to 2500 psi,
and 3500 to 5000 psi. Fire-tube boilers usually operate between 50 and 250 psi.
Water-tube boilers operate at higher pressures. Large power plant boilers can
operate with pressures as high as 5000 psi.
Boilers are also rated by their heat input capacity. The heat input capacity is the
amount of heat, in units of British Thermal Units per hour (Btu/hr), Joules per
hour (J/h), that is generated by burning fuel in the furnace. Boilers are also rated in
terms of Megawatts (MW) of thermal energy produced. A boiler rated at 73 MW
has a heat input of approximately 250 x 10s Btu/hr. Many air pollution control
agencies adopt regulations to limit the air pollution emissions in units of ng/J or
lb/106 Btu.
Comparing Fire-tube and Water-tube Boilers
Fire-tube boilers are usually smaller, occupy a minimum of floor space, have a lower
initial cost, and require very little installation time than do water-tube boilers.
However, they do have some disadvantages. The water volume is very large and cir-
culation is poor, making them slow to respond to changes in steam demand. The
drums, or shells, containing the water are very large and cannot be economically
built to withstand higher operating pressures. Pressures are usually less than 250 psi.
Drums and joints are exposed to the furnace, increasing the likelihood of explosion.
The pressure, temperature, and the amount of steam that can be produced are not
as high as with water-tube boilers.
Both fire-tube and water-tube boilers are constructed as packaged boilers. Pack-
aged boilers are shop assembled with burners, tubes, fans, and controls built into the
boiler as one unit. These units can be placed into service very quickly. The packaged
units have automatic controls, thus reducing labor costs. Because these units are
compact, they can be difficult to get inside of for maintenance. However, because
1-16
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they are more compact, they may be used in locations where field erected units will
not fit. Packaged units generally must burn liquid or gaseous fuels.
Water-tube boilers are available in various sizes to produce high-pressure, high-
temperature steam. Because these units use small diameter tubes, they can produce
high-pressure steam without a great risk of explosion. They can also respond rapidly
to changes in steam demand. Water-tube boilers usually have more elaborate settings
and controls, and the cost per pound of steam is usually higher than for a similar-
sized fire-tube boiler. Large water-tube boilers are usually field erected, making the
installation more difficult and time consuming. Water-tube boilers can be designed
to bum solid, liquid, or gaseous fuels. Table 1-1 lists the general ratings of fire-tube
and water-tube boilers and their various applications.
Table 1-1. General ratings of boilers.
Application
Residential and
small commercial
Commercial and
small industrial
Industrial
Utility
Boiler design
fire- tube
water- tube
fire-tube
water- tube
water- tube
water- tube
Rating
(psi)
50- 250
50- 900
50- 250
50-1800
900-2500
2500-5000
Summary
Selecting a boiler involves evaluating many factors including availability, initial costs,
operating and maintenance costs, labor, space, and the pressure and temperature of
steam needed for the process. One of the most important factors is the fuel to be
burned —its type and cost. During the life of the boiler, the fuel costs can be two to
six times the initial cost of the boiler. It is very important to operate the boiler as it
was designed to help keep the fuel costs low and improve overall boiler efficiency.
These topics will be discussed in the following lessons.
Review Exercise
1. In
boilers, combustion products pass
through the inside of heat exchanger tubes while water
and steam are contained outside the tubes by an outer
shell.
2. In
boilers, hot combustion products pass
1. fire-tube
over tube sections that contain water. Water is boiled to
make steam that is collected in steam drums.
2. water-tube
1-17
-------
3. The
is a section of tubes that heats the
feed-water before it is delivered to the boiler.
a. convection
b. economizer
c. superheater
d. air preheater
4. True or False? The temperature of steam in the super-
heater can be as high as 538 °C (1000 °F).
3. b. economizer
5. Heat transfer through space from a hot object to a
cooler one is called
a. conduction.
b. convection.
c. radiation.
4. True
Heat transferred by hot flue gas flowing over and around
boiler tubes is called
a. conduction.
b. convection.
c. radiation.
5. c. radiation.
The following illustration is of a
a. Scotch marine boiler.
b. horizontal return tube boiler.
c. fire-tube boiler with a refractory-lined firebox.
d. packaged water-tube boiler.
6. b. convection.
8. In water-tube boilers, the tubes surrounding the firebox
are called
a. superheaters or convection tubes.
b. economizers or air preheaters.
c. water walls or fire walls.
7. b. horizontal
return tube
boiler.
8. c. water walls or
fire walls
1-18
-------
In a water-tube boiler, water forms into steam, moves
through tubes called , and is collected in
a
a. risers, steam drum
b. downcomers, steam drum
c. risers, downcomer
10. True or False? Boilers producing high-pressure steam
generally use pumps to circulate the water from the
downcomers into the water-wall headers.
9. a. risers,
steam drum
11. Heated feedwater enters the steam drum through
internal feed pipes located along the length of the drum
a. top.
b. bottom.
c. back wall.
10. True
12. In a steam drum, steam and water are usually
separated by
a. packed beds.
b. cyclone separators.
c. water pools.
11. b. bottom.
13. True or False? Water-tube boilers can have a number of
superheaters called convection, pendant, and radiant
superheaters.
12. b. cyclone
separators.
14. For many water-tube boilers, steam is drawn from the
boiler as makeup water is pumped through a(n)
where it is heated before it enters a(n)
a. preheater, economizer.
b. superheater, mud drum.
c. economizer, steam drum.
13. True
15. True or False? In a tubular air preheater, cool
combustion air is heated by a revolving heat wheel.
14. c. economizer,
steam drum
15. False
1-19
-------
16.
The following illustration is of a
a. rotary air preheater.
b. tubular air preheater.
c. economizer.
d. Rothemuhle regenerative air preheater.
17. Boilers are usually rated by
a. boiler horsepower.
b. operating pressure.
c. heat input capacity.
d. all of the above
16. d. Rothemuhle
regenerative air
preheater.
18. Fire-tube boilers operate at higher/lower pressures than
do water tube boilers.
17. d. all of the
above
18. lower
References
Babcock and Wilcox. 1978. Steam—Its Generation and Use. New York: The
Babcock and Wilcox Company.
Beachler, D. S., Jahnke, J. A., Joseph, G. T., and Peterson, M. M. 1983.
Air Pollution Control Systems for Selected Industries—Self-Instructional
Guidebook. APTI Course SI:431. EPA 450/2-82-006.
TPC Training Systems. 1975. Generating Steam in the Power Plant. Harrington,
Illinois: Technical Publishing Company.
Woodruff, E. B. and Lammers, H. B. 1977. Steam-Plant Operation. New York:
McGraw-Hill Book Company.
1-20
-------
Lesson 2
Combustion Efficiency
Lesson Goal and Objectives
Goal
To familiarize you with combustion principles and with the factors that affect com-
bustion efficiency hi boilers.
Objectives
Upon completing this lesson, you should be able to —
1. describe the three conditions that are necessary for complete combustion and
their relationship to each other,
2. define stoichiometric amount of oxygen,
3. define the terms lower explosive limit, upper explosive limit, excess air, higher
heating value, and net heating value,
4. estimate combustion efficiency using charts, figures, and calculation forms, and
5. list areas of potential heat loss in a boiler.
Combustion Variables
Combustion is a chemical process occurring from the rapid combination of oxygen
with combustible materials, or fuel, that produces heat. In a boiler, fuel such as coal
oil, gas, or wood is mixed with air at elevated temperatures producing heat and the
oxides of many of the elements contained in the fuel.
Most fuels used in boilers are composed of essentially carbon and hydrogen, but
can also contain other elements such as nitrogen and sulfur. The products resulting
from complete combustion of hydrocarbon, or organic fuels are carbon dioxide and
water vapor. However, if the fuel contains oxygen, the resulting flue gas may contain
aldehydes and organic acids creating an air pollution problem. The simplified reac-
tions of carbon and hydrogen are given as:
(Eq. 2-1) C + O2 - CO2 + energy
(Eq. 2-2) 2 H2 + 02 - 2 H2O + energy
Equations 2-1 and 2-2 show that the final products resulting from complete com-
bustion of organic fuels are carbon dioxide, water, and energy in the form of heat.
This is the ideal condition that all boiler operators strive to achieve. However,
2-1
-------
incomplete combustion can occur if combustion conditions are not adequate. When
combustion is incomplete, smoke, carbon monoxide, and other partially oxidized
products will be formed. These are air pollutants or undesired products. In addition,
less heat will be produced when combustion is incomplete.
If the fuel should contain elements such as sulfur and nitrogen, the flue gas pro-
duced will contain the oxides of these elements even when combustion is complete.
Sulfur oxides and nitrogen oxides are air pollutants that can be harmful if emitted
hi significant amounts. Air pollution control techniques will be discussed in
Lesson 6.
To achieve complete combustion once the air (oxygen) and fuel have been
brought into contact, the following conditions are necessary:
• temperature high enough to ignite the fuel and air mixture
• turbulent mixing of the fuel and air, and
• sufficient residence time for the reaction to occur.
Called the "three T's of combustion," turbulence, temperature, and time, these
conditions govern the speed and completeness of a reaction. They depend on each
other, because changing one affects the other two.
Air Supply
The amount of air needed for combustion hi a boiler depends on the fuel, the
equipment used, and the operating conditions of the unit. If there is too much air,
an excessive amount of hot gases will be discharged from the boiler as well as a cor-
respondingly high heat loss. If there is not enough air, unburned fuel will be
discharged from the boiler. Therefore, it is important to design and operate the
boiler with the appropriate amount of air to completely combust the fuel fed to the
furnace.
Turbulence
Turbulent mixing of the air (oxygen) and fuel is essential for efficient combustion.
Each combustible particle must contact oxygen before it will burn. If the air and
fuel mixing hi the combustion chamber or in the fuel bed is poor, there will be too
much combustion air in some places and not enough in others. Inadequate mixing
can result in incomplete combustion products and unburned fuel being emitted from
the boiler.
Temperature
The rate at which a combustible material is oxidized is greatly affected by the
temperature. The higher the temperature, the faster the oxidation reaction will pro-
ceed. The chemical reaction of fuel and oxygen can occur even at ambient
temperatures. For this reason, a pile of coal can be a fire hazard. Small amounts of
heat are given off as the coal slowly oxidizes. This in turn raises the temperature of
the coal pile and increases the oxidation rate, liberating more heat. Eventually, a
full-fledged fire can break out.
2-2
-------
In boilers, when the combustible material reaches its ignition temperature, the
rate of oxidation is accelerated to the combustion point. Once the fuel is ignited, the
heat released during combustion will be high enough to sustain the continual oxida-
tion of the fuel.
Time
Air supply, turbulence, and temperature determine the rate at which combustion
proceeds. However, a sufficient amount of time is required to ensure that the fuel
completely burns. If the residence time is not high enough, unburned fuel or par-
tially oxidized compounds will be emitted from the boiler. This causes an appre-
ciable heat loss in the boiler and pollutants to be emitted into the atmosphere. The
residence time is directly related to the volume of the furnace chamber. The larger
the chamber volume for a set flow rate, the longer the residence time will be.
Combustion Calculations
Stoichiometric Amount of Oxygen
Oxygen is necessary for combustion to occur. To achieve complete combustion of an
organic compound, a sufficient supply of oxygen must be present to convert all of
the carbon to CO2. This quantity of oxygen is referred to as the Stoichiometric or
theoretical amount. The Stoichiometric amount of oxygen is determined from a
balanced chemical equation summarizing the oxidation reactions. Consider a
generalized fuel with a chemical formula dHyStOw 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 (combus-
tion) of this fuel with oxygen from air gives:
,,, „ »v —,, „ ~ / V w\_ 0.79 / v w\^T
(Eq. 2-3) CIHySIOw+ x + ^- + z O2 + (x + -*- + z N2 —
\ 4 21 0.21 \ 4 27
0.79 / . y . ^v,^.
2 0.21 \ 4 2
Where: Q,= 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 inert gases;
• combined oxygen in fuel is available for combustion, thus reducing air
requirements;
• fuel contains no combined nitrogen, so no "fuel NO*" is produced;
• "thermal NOX" via the nitrogen fixation is small, so that it is neglected in
Stoichiometric air calculations;
• sulfur in fuel is oxidized to SO2 with negligible SO3 formation.
2-3
-------
For example, to combust methane (CHO Equation 2-3 reduces to:
(Eq. 2-4) CH4 + 2 O2 + 7.53 N2-CO2 + 2 H2O + 7.53 N2 + Q
Moles or relative volumes
1 + 2_+_7.53 -1 + 2_+_7.53
Total air required Total flue gases
For every mole or standard cubic foot of CH* burned, the reaction requires 9.53
moles or standard cubic feet of air for complete combustion. A listing of the
theoretical air requirements for a number of fuels are given in Table 2-1.
Excess Air
In boilers, more than the stoichiometric amount of air is used to ensure complete
combustion. This extra volume is referred to as excess air. If ideal mixing were
achievable, no excess air would be necessary. However, most combustion devices are
not capable of achieving ideal mixing of the fuel and air streams. The amount of
excess air is held to a minimum in order to reduce heat losses. Excess air takes no
part in the reaction but does absorb some of the heat produced. To raise the excess
air to the combustion temperature, additional fuel must be used to make up for this
loss of heat. Operating at a high volume of excess air can be very costly in terms of
the added fuel required.
Depending on the amount of excess air, different concentrations of CO2 and O2 in
the stack gas will result, as shown in Figure 2-1.
-------
Table 2-1. Combustion constants and approximate limits of flammability
of gases and vapors in air.
Substance
Carbon. C«
Hydrogen, II,
Oxygen. O,
Nitrogen (aim). N,
Carbon monoxide, CO
C^rlmii di ivi 1** I^O
Paraffin series
Methane, Cll,
ttliane. C,ll»
I'lopane. C,llt
n Uutane, C4IIIA
Isohutane. C4II,«
n I'entane. C,ll,,
Isopemane, C,ll,,
Ni-ouentane. C,H,,
it Ilex jut. C.U,,
Olcfiii series
ttliylene. C,ll,
I'ropylene, C,ll,
n Uuicne. C.ll.
Isobuicne. C.ll,
n IVnlenc, C.ll,a
Aromatic series
Heine-tie, C.ll,
1 olucne. C)l I,
Xylcne. Cvl l,«
Miscellaneous gases
Ai etylene. C,ll,
Na|iilialene, CIUH,
M.lliyl alcoliol. Cll, Oil
ttliyl alcohol. ( ,11.011
Aininonia. Nil,
Sullitr. S«
llydiogen sulfide, II, S
Sullni dioxide. SO,
Water vapor, II,O
Air
Casllline
Lb/fi1
_
00053
0 0846
00744
00740
01 1 7n
. 1 1 /U
0.0424
0.080)
011%
0.158?
0.1582
0 1904
0.1904
0.1904
0.2274
0 0746
O.IIIO
0 1480
0 1480
0.1852
0 2060
0 2431
0.2803
0 0697
0.3384
0 0846
0.1216
0 0456
_.
0.0911
0 1733
0 0476
0.0766
Fi'/lb
_
187.723
11.819
13.443
IS 506
8CJU
. 31O
23.565
12.455
8.365
6. 32)
6 32)
5.252
5.252
5.252
4.398
I3.4I2
9.007
6.756
6.756
5 400
4.852
4 II3
3 567
14.344
2.955
II 820
8 22!
2I.9I4
._
10.979
5 770
2I.OI7
13.063
I leat of combustion
(Btu/ft*)
Cross
(high)
_
325
322
IOIS
1 792
2590
3370
3363
4016
4008
3993
4762
I6I4
2336
3084
3068
3836
375I
4484
5230
I499
5854
868
1 600
44!
647
-
—
NCI
(low)
_
275
322
9I3
I64I
2385
3H3
3I05
3709
3716
3693
44I2
I5I3
2 1 86
2885
2869
3586
360 1
4284
4980
I448
5654
768
I45I
365
596
-
--
(Btu/lb)
Cross
(high)
14.093
6I.IOO
4.347
23.879
22.320
2I.66I
21.308
2 1. 257
21, 091
21,052
20,970
20,940
21,644
21,041
20.840
20.730
20,712
18.210
18,440
18.650
21.500
17.298
10,259
13,161
9.668
3.983
7.100
—
-
—
Net
(low)
14.093
51,623
4.347
21.520
20.432
19.944
19.680
19.629
19.517
19.478
19.396
19.403
20.295
19.691
19,496
19.382
19.363
17.480
17.620
17.760
20,776
16,708
9.078
11.929
8.001
3.983
6.545
-
—
For 100% iota! air
(mol/mol of combuiiiblc)
(fl'/ft* of combuiiiblc)
Required
for combustion
o,
1.0
0.5
05
2.0
3.5
5.0
65
6.5
8.0
80
80
9.5
3.0
4.5
60
6.0
7.5
7.5
90
10.5
2.5
12 0
1.5
3.0
0.75
1.0
15
-
-
—
N,
S.76
1.88
1.88
7.53
13.18
18.82
24.47
24.47
30.11
30.11
30.11
35.76
11.29
16 94
22.59
22.59
28.23
28.23
33. B8
39.52
9.41
45.17
5.65
11.29
2.82
3.76
5.65
-
-
-
Air
4.76
2.38
2.38
9.53
1668
23.82
30.97
30.97
38.11
38 II
38 II
45.26
14.29
21.44
28.59
28.59
35.73
35.73
42.88
50.02
11.91
57.17
7.15
14.29
3.57
4.76
7 15
-
-
Hue products
CO,
10
—
1.0
1.0
2.0
3.0
40
4.0
5.0
50
5.0
60
2.0
3.0
40
40
5.0
6.0
7.0
8.0
20
10 0
10
2.0
-
SO,
10
10
-
-
-
11,0
10
—
20
30
4.0
50
5.0
6.0
60
6.0
7.0
20
3.0
40
40
50
3.0
40
5.0
10
40
2.0
3.0
1.5
-
10
-
-
—
N,
376
1.88
1.88
7.53
13.18
18.82
24.47
24.47
30.11
30.11
30.11
35.76
11.29
16.94
22.59
22.59
28.23
28.23
33.88
39.52
9 41
45.17
5.65
II 29
3.32
3.76
5.65
—
-
—
-
For 100% total air
(Ib/lb of combustible)
Required
for combustion
0,
2 66
7.94
0.57
3.99
373
3.63
3.58
3.58
S.55
3.55
3.55
S.5S
3.42
3.42
3.42
3.42
3.42
3.07
3.13
3.17
3.07
3.00
1.50
2.08
1.41
1.00
141
—
-
--
N,
8.86
26.41
1.90
13.28
12.39
12.07
11.91
11.91
11.81
11.81
11.81
II 74
11.39
11.39
11.39
11.39
11.39
10.22
10.40
10.53
10.22
9 97
4 98
6.93
4.69
3.29
4.69
—
-
—
-
Air
11.53
34 34
2.47
1727
16 12
15.70
15.49
15.49
15.35
15.35
15.35
15.27
14.81
14.81
14 81
14.81
14 81
13.30
13.53
13.70
13.30
12.96
6.48
9.02
6 10
4 29
6.10
-
-
—
Flue producit
CO,
3.66
-
1.57
2.74
2.93
2.99
3.03
3.03
3.05
3.05
305
3.06
3.14
3.14
3.14
3.14
3.14
3.38
3.34
3.32
3.38
3.43
1.37
1.92
-
SO.
2.00
1.88
-
-
-
H.O
_
8.94
-
2.25
.80
.68
.55
.55
.50
.50
.50
.46
.29
.29
.29
.29
.29
0.69
0.78
0.65
0.69
0.56
1.13
1.17
1.59
_
0.53
-
-
—
-
N,
8.86
26.41
1.90
13.28
12.39
12.07
11.91
11.91
11.81
11.81
11.81
11.74
11.39
11.39
11.39
11.39
11.39
10.22
10.40
10.53
1022
9.97
4.98
693
5.51
3.29
4 69
—
-
--
-
Flammabiliiy
limits
(% by volume)
LEL
—
4.00
12.50
5.00
3.00
2.12
1.86
1.80
-
-
-
1.18
2.75
2.00
1.75
-
-
1.40
1.27
1.00
-
-
6.72
3.28
15.50
_
4.30
-
-
-
1.40
UEL
-
74.20
-
-
74.20
15.00
12.50
9.35
8.41
8.44
-
-
-
7.40
28.60
11.10
9.70
—
-
7.10
6.75
6.00
-
-
36.50
18.95
27.00
_
45.50
-
-
7.60
(NO
CJl
'Caibnn and sullur are considered as gases lor molal calculations only.
Sources: Adapted from Fuel Hue Gusqs, Ameiican Gas Association.
Combustion Flume and ExfiltHtons of (iitse*. 1051.
-------
Figure 2-1 shows how the amount of excess air is indicated by the amount of CO2 or
O2 measured in the flue gas. Flue gas can be analyzed for the percentage of CO2,
O2, and CO by using an orsat apparatus or continuous monitors. As can be seen
from Figure 2-1, when excess air is kept low, the concentration of CO2 in the flue
gas is high, while that of O2 remains relatively low. The boiler should be operated
with a minimal amount of excess air to promote good combustion and to prevent
high heat loss.
Excess air can be calculated using Equation 2-5.
(Eq. 2-5) % EA = %02-0.5%CO
4
0.264% N2-(% 02-0.5% CO)
Example 2-1 will illustrate how to calculate excess air when the flue gas concentra-
tions are known.
Example 2-1
Assume the flue gas from a boiler was analyzed with an orsat apparatus and found
to contain the following concentrations:
Gas
CO2
02
CO
N2
Percent
17.0
3.5
0.02
79.0
Using Equation 2-5, the percent excess air is:
%EA= 3-5-0.5(0.02) xlOO
0.264(79.0) - [3.5 - 0.05(0.02)]
3-5-°-01.xlOO
20.86-3.49
= 0.201x100
= 20.1%
2-6
-------
Combustion Limits
Not all mixtures of fuel and air are able to support combustion. The flammable, or
explosive limits, for a mixture are the maximum and minimum concentrations of
fuel in air that will support combustion. The lower explosive limit (LEL) is defined
as the concentration of fuel below which combustion will not be self-sustaining. The
upper explosive limit (UEL) is denned as the concentration of fuel mixture that will
not burn because of a lack of oxygen. Table 2-1 listed the flammability limits (LEL
and UEL) for common fuels and solvents.
For example, consider that a mixture of gasoline vapors and air is at atmospheric
conditions. From Table 2-1 the LEL is 1.4% by volume of gasoline vapors and the
UEL is 7.6%. Any concentration of gasoline in air within these limits will support
combustion. That is, once a flame has been ignited it will continue to burn. Concen-
trations of gasoline in air below or above these limits will not burn and can quench
the flame.
Thermodynamic and Combustion Terms
In describing any combustion process, many terms are used to define heat. These
terms can be divided into two categories: thermodynamic and combustion. Thermo-
dynamic terms, applying to all systems, define the energy level, or potential heat,
present in any substance. Combustion terms, initiated to aid in standardizing fuel
usage calculations, are applied to heat produced by combustion methods. Because
the combustion terms are specific examples of the thermodynamic terms, some
overlap is involved in defining them. The following are important terms describing
heat thermodynamically:
Sensible heat (EL): Heat that causes a change in temperature when added or
removed.
Latent heat (Hv): Heat given off by a vapor condensing to a liquid or gained by a
liquid evaporating to a vapor, without a change in temperature. The latent heat of
vaporization of water at 212°F is 970.3 Btu/lb.
Heat content or enthalpy (H): The sum total of latent and sensible heat present
in a substance (gas, liquid, or solid) minus that contained at an arbitrary set of con-
ditions chosen as the base or zero point. Values for various gases are listed in
Table 2-2.
2-7
-------
Table 2-2. Heat contents of various gases.
Temp
<°F)
60
100
200
300
400
500
600
700
800
900
1000
1200
1400
1600
1800
2000
2200
2400
2600
2800
3000
3200
3400
3600
Heat content, H
(Btu/lb at 1 atm)
0,
0
8.8
30.9
53.3
76.2
99.4
123.1
147.2
171.7
196.6
221.7
272.5
324.3
377.3
430.7
484.0
539.3
594.4
649.0
702.8
758.6
316.4
873.4
931.0
N,
0
9.9
34.8
59.9
85.0
110.3
136.1
161.7
187.7
213.9
240.7
294.7
350.8
407.3
465.0
523.8
583.2
642.3
702.8
763.1
824.1
885.8
947.6
1010.3
Air
0
9.6
33.6
57.7
31.8
106.0
130.2
154.5
178.9
203.4
235.0
238.5
343.0
398.0
455.0
513.0
570.7
628.5
687.3
746.6
806.3
866.0
925.9
986.1
CO
0
10.0
34.9
59.9
85.0
110.6
136.3
162.4
188.7
215.6
242.7
297.8
354.3
407.5
465.3
523.8
583.3
643.0
703.2
771.3
832.6
894.0
956.0
1018.3
CO,
0
8.0
29.3
52.0
75.3
99.8
125.1
149.6
177.8
205.6
233.6
290.9
349.7
416.3
470.9
532.8
596.1
659.2
723.2
787.4
852.0
916.7
981.6
1047.3
SO,
0
5.9
21.4
37.5
54.4
71.8
89.8
108.2
127.0
146.1
165.5
205.1
245.4
286.4
327.8
369.1
411.1
452.7
495.2
557.5
580.0
622.5
665.0
707.5
H,
0
137
484
832
1182
1532
1882
2233
2584
2935
3291
4007
4729
5460
6198
6952
7717
8490
9272
10060
10870
11680
12510
13330
CH«
0
21.0
76.1
136.4
202.1
272.6
347.8
427.4
511.2
599.2
691.1
886.2
1094.1
1313.0
1542.6
-
—
—
-
_
_
—
H,O
0
—
—
1165
1212
1259
1307
1355
1404
1454
1505
1609
1717
1829
—
-
—
—
-
—
_
-
Source: North American Combustion Handbook, 1952.
Some useful terms describing heat produced by combustion of a fuel are:
Gross heating value (HVC): The total heat obtained from the complete combus-
tion of a fuel that is at 60 °F when combustion starts, and the combustion products
of which are cooled to 60 °F before the quantity of heat released is measured. Con-
stant pressure, normally 101.3 kPa (1 atmosphere) is maintained throughout the
entire combustion process. Gross heating values are also referred to as total, or
higher, heating values (HHV).
Net heating value (HV^): The gross heating value minus the latent heat of
vaporization of the water formed by the combustion of the hydrogen in the fuel. For
a fuel containing no hydrogen, the net and gross heating values are the same.
Available heat (HA): The gross quantity of heat released within a combustion
chamber minus (1) the sensible heat carried away from the dry flue gases and,
(2) the latent heat and sensible heat carried away in water vapor contained in the
flue gases. The available heat represents the net quantity of heat remaining for
useful heating. Figure 2-2 shows the available heat from the complete combustion
(no excess air) of various fuels at various flue gas temperatures.
2-8
-------
^ 140,000
^
^ 120,000
bo
\
3
a 100,000
8
-c 80,000
= 60,000
<
40,000
\
3000
2400
03
be
u
\
3
A
U
1800
^ 1200
600
Heavy fuel oil 14° API
152,000 Btu/gal
Light fuel oil 36.4° API
138,000 Btu/gal
Commercial butane
3210 Btu/cf
Commercial propane
2558 Btu/cf
Natural gas
1059 Btu/cf
I
I
I
I
I
I
I
I
300
2700
900 1500 2100
Flue gas exit temperature, °F
Source: North American Combustion Handbook, 1965.
Figure 2-2. Available heat for some typical fuels (referred to 60 °F).
2-9
-------
Since all of the previous terms describe heat, they all are expressed in units of
Btu/lb. Figure 2-3 illustrates the interrelation of these terms.
Thermodynamic heat
terms
Combustion heat
terms
Heat content (H)
Sensible
heat (H,)
Latent heat
(H.)
Gross
heating value (HVC)
Available
heat (HA)
J J Heat lost in
C C flue gases
Net heat
(HViV)
L.U. Latent heat
~j ) of vaporization
rr (H.)
Figure 2-3. Heat terms.
Depending on the user, the above terms can also have more than one definition.
For example, a laboratory chemist may describe latent heat as the energy used in the
chemical combustion of a fuel to carbon dioxide and water; while a boiler operator
may describe latent heat as the difference between the gross and net heating values.
Another important term used hi performing combustion calculations is the specific
heat, Cp, of a substance. Specific heat is defined as the amount of heat required to
raise 1 pound of a substance 1 degree fahrenheit. Specific heat is given as Btu/lb «°F
in EngUsh units. Specific heat depends on temperature.
Heat Balance
To design or review the operating performance of a boiler, a heat balance of the
system is usually determined. The first law of thermodynamics states that energy
entering a system must leave the system or be stored in some manner. In a boiler the
heat energy into the system is therefore equal to the heat energy out of the system.
Heat in (sensible + HHV) = heat out (sensible + latent + available)
In order to compute a heat balance, a number of parameters must be measured
including fuel heat content and quantity burned, air quantity, flue gas losses, and
boiler losses.
Fuel Characteristics
The chemical makeup and heat content of the common fuels burned in boilers vary
depending on the type of fuel used. Fossil fuels — natural gas, fuel oil, and coal — are
most often used in boilers. Natural gas consists of varying amounts of methane
(CHO, ethane (C2H«), ethylene (C2H4), carbon dioxide (CO2), carbon monoxide
(CO), hydrogen (H2), oxygen (O2), nitrogen (N2), and hydrogen sulfide (H2S),
depending on where the gas comes from.
2-10
-------
The heat content of natural gas varies from approximately 950 to 1150 Btu/ft3 of
gas. The analyses and heat contents of various samples of natural gas are given in
Table 2-3.
Table 2-3. Various samples of natural gas.
Sample no.
source of gas
Analyses
Constituents, % by vol
HI Hydrogen
CHi Methane
C,H4 Ethylene
C,H« Ethane
CO Carbon monoxide
COi Carbon dioxide
N, Nitrogen
Oi Oxygen
H,S Hydrogen sulfide
Ultimate, % by wt
S Sulfur
Ht Hydrogen
C Carbon
Nt Nitrogen
Oi Oxygen
Specific gravity (rel to air)
Higher heat value
Btu/cu ft@60°F and 30 in. Hg
Btu/lb of fuel
1
Pa.
—
83.40
—
15.80
—
—
0.80
—
—
—
23.53
75.25
1.22
—
0.636
1,129
23,170
2
So. Cal.
—
84.00
—
14.80
—
0.70
0.50
—
—
—
23.30
74.72
0.76
1.22
0.636
1,116
22,904
3
Ohio
1.82
93.33
0.25
—
0.45
0.22
3.40
0.35
0.18
0.34
23.20
69.12
5.76
1.58
0.567
964
22,077
4
La.
—
90.00
—
5.00
—
—
5.00
—
—
—
22.68
69.26
8.06
—
0.600
1,002
21,824
5
Okla.
—
84.10
—
6.70
—
0.80
8.40
—
—
—
20.85
64.84
12.90
1.41
0.630
974
20,160
Source: Babcock and Wilcox, 1978.
Fuel oils, refined from crude oil, contain varying amounts of carbon, hydrogen,
nitrogen, oxygen, ash, and sulfur. Fuel oils are graded according to gravity and
viscosity, the lightest being No. 1 and the heaviest No. 6. Grades 5 and 6 usually
need to be heated before they can be adequately pumped to and burned in the
burner. The heat content of fuel oil varies from approximately 18,000 to 20,000
Btu/lb. The analyses and heat contents of some fuel oils are listed in Table 2-4.
It is common practice to report the components of coal using either a proximate
analysis or an ultimate analysis. In the proximate analysis, the amount of moisture,
volatile matter, fixed carbon, and ash in the coal are determined. In the ultimate
analysis, the amount of carbon, hydrogen, oxygen, nitrogen, sulfur, and ash are
determined. The ultimate analysis is useful in computing the stoichiometric, or
theoretical, air requirements by using Equation 2-6.
(Eq. 2-6)
Theoretical air= 11.53 C +34.34(H2 -
8
Coal is ranked by the amount of fixed carbon, the hardness, and the calorific
value, or heat content. Peat and lignite are the softest coals, sub-bituminous and
bituminous are harder, and anthracite is the hardest. The analyses and calorific
values of some selected coals are given in Table 2-5.
2-11
-------
Table 2-4. Analyses of typical fuel oils.
Grade of fuel oil
Weight, percent
Sulfur
Hydrogen
Carbon
Nitrogen
Oxygen
Ash
Gravity
DegAPI1
Specific
Lb per gal
Pour point, °F
Viscosity
Centistokes@100°F
Saybolt Universal Scale® 100 °F
Saybolt Furol Scale® 122°F
Water and sediment, vol %
Heating value
Btu per Ib, gross (calculated)
Sample
no. 1
0.01-0.5
13.3-14.1
85.9-86.7
Nfl-0.1
40-44
0.825-0.806
6.87-6.71
0 to - 50
1.4-2.2
-
19,670-19,860
Sample
no. 2
0.05-1.0
11.8-13.9
86.1-88.2
Nil-0.1
28-40
0.887-0.825
7.39-6.87
Oto -40
1.9-3.0
32-38
0-0.1
19,170-19,750
Sample
no. 4
0.2-2.0
(10.6-13.0)*
(86.5-89.2)*
0-0.1
15-30
0.966-0.876
8.04-7.30
- 10 to + 50
10.5-65
60-300
tr to 1.0
18,280-19,400
Sample
no. 5
0.5-3.0
(10.5-12.0)*
(86.5-89.2)*
0-0.01
14-22
0.972-0.922
8.10-7.68
- 10 to + 80
65-200
20-40
0.05-1.0
18,100-19,020
Sample
no. 6
0.7-3.5
( 9.5-12.0)*
(86.5-90.2)*
0.01-0.5
7-22
1.022-0.922
8.51-7.68
+ 15 to + 85
260-750
45-300
0.05-2.0
17,410-18,990
•Estimated.
'The API degree scale is commonly
gravity at 60 °F:
used in specifying various grades of oil. It is inversely related to the specific
141.5
Degrees API =
Sp. gr.@60°F
-131.5
Source: Babcock and Wilcox, 1978.
Table 2-5. Typical analyses of wood, peat, and coal.
Kind of fuel
Wood
Peat
Lignite
Subbituminous
Bituminous
Semibituminous
Semianthracite
Anthracite
Proximate analysis
g
3
1
S
—
56.70
34.55
24.28
3.24
2.03
3.38
2.80
u
11
> S
—
26.14
35.34
27.63
27.13
14.47
8.47
1.16
•Sj
.2 M
b <*
u
—
11.17
22.91
44.84
62.52
75.31
76.65
88.21
J3
—
5.99
7.20
3.25
7.11
8.19
11.50
7.83
Ultimate analysis
3
ft-
0.64
1.10
0.36
0.95
2.26
0.63
0.89
1)
I
X
6.25
8.33
6.60
6.14
5.24
4.14
3.58
1.89
s
h
«3
49.50
21.03
42.40
55.28
78.00
79.97
78.43
84.36
a
V
2
Z
1.10
1.10
0.57
1.07
1.23
1.26
1.00
0.63
1
X
O
43.15
62.91
42.13
33.90
7.47
4.18
4.86
4.40
Calorific
value
(Btu/lb)
5,800
3,586
7,090
9,376
13,919
14,081
13,156
13,298
Source: Woodruff and Lammer, 1977.
2-12
-------
Boiler Efficiency
Boiler efficiency is defined as the amount of heat absorbed by the water divided by
the amount of heat contained in the fuel being burned. In equation form, this is
/IT a *\ T> -I .ce • neat absorbed by boiler fluid ^nnfft
(Eq. 2-7) Boiler efficiency = - y- - x 100%
heat contained in fuel
_ steam flow rate (heat of steam - heat of feedwater)
(weight of fuel)(HHV of fuel)
mXHHV)
Where: m, = mass flow rate of steam, Ib/hr
m/ = mass flow rate of fuel, Ib/hr
h, = enthalpy of steam leaving boiler, Btu/lb
Iv* = enthalpy of water entering the boiler, Btu/lb
HHV = higher heating value of fuel, Btu/lb
To calculate boiler efficiency using Equation 2-7, the quantity of energy input to
the boiler and output from the boiler are measured. These measurements can be
taken by using flowmeters, thermometers, or thermocouples, and pressure gauges.
Calculation inaccuracies can occur because of inaccuracies of the measuring devices.
All instruments should be calibrated frequently. The results are usually checked by
calculating a heat balance for the system. Measurements to be taken are:
Feedwater entering the boiler
rh/w = boiler feedwater flow rate
T/w = feedwater temperature
p/w = feedwater pressure
Steam leaving the boiler
m, = steam flow rate
= rhyw — nij, (feedwater flow rate — blowdown flow rate)
T, = steam temperature
p, = steam pressure
Fuel entering boiler
m/=fuel flow rate
T/=fuel temperature
p/ = fuel pressure
HHV = fuel higher heating value
2-13
-------
Heat Losses
Not all of the energy contained in fuel is converted to heat and absorbed by the
boiler equipment. Some of this energy is lost. Some fuel may leave as unburned car-
bon if combustion is not complete. Moisture in the fuel accounts for some heat loss.
Hydrogen in the fuel is converted to water when burned, making this another heat
loss. Moisture hi the air also contributes to heat loss. One of the largest heat losses is
from the dry flue gas because the stack temperature is much higher than the
temperature of air (ambient) used for combustion. Stack temperature is usually
maintained at greater than 300 °F to prevent moisture and acids in the flue gas from
condensing on ductwork, fans, or stack walls.
One method to calculate boiler efficiency is the Btu method (Babcock and
Wilcox, 1978). The amount of air required per pound of fuel burned is calculated
using the theoretical air required per 10,000 Btu heat value of the fuel. Values of
theoretical ah- (Ib of air/lb of fuel) can be obtained by multiplying the heat content
of the fuel as fired, (Btu/10,000)/lb of fuel, by the theoretical air required per
10,000 Btu, Ib air/(Btu/10,000).
If the ultimate analysis of a fuel is known, the value of theoretical dry air
expressed as Ib air/(Btu/l 0,000) is calculated using Equation 2-8.
(Eq. 2-8) Theoretical dry air = 144
y
Where: C = carbon,. % by weight
H2 = hydrogen, % by weight
O2 = oxygen, % by weight
S = sulfur, % by weight
Btu/lb = heat value of the fuel.
Equation 2-8 should only be used when the ultimate analysis of the fuel is given
and when the correct heating value of the fuel is known. When the proximate
analysis of coal is known, Figure 2-4 can be used to obtain the theoretical air in
Ib per 10,000 Btu.
_u
5
u
O
Figure
10 20 30 40 50 60
Volatile matter in dry ash-free coal, %
Source: Babcock and Wilcox, 1978.
2-4. Theoretical air in Ib per 10,000 Btu heat value
of coal with a range of volatile matter.
2-14
-------
Example 2-2
From the proximate analysis of a type of coal given below, calculate theoretical air in
units of Ib of air/lb of fuel. The excess air is 20%. (Source: Babcock and Wilcox, 1978.
Bituminous coal
proximate analysis as fired, % by weight
Moisture 12.0
Volatile matter 25.8
Fixed carbon 46.2
Ash 16.0
Btu/lb 10,900
Solution:
1. The volatile matter on a dry ash free basis is:
volatile matter
volatile matter + carbon
xlOO%
2. Using Figure 2-4, and the abscissa of 35.8, move
up to the line and read the value on the
ordinate.
o
u
_c
7.8
7.7
7.6
7.57
7.5
10 20 30 35.8 40 50 60
Volatile matter in dry ash-free coal, %
25.8
25.8 + 46.2
= 35.8%
xlOO%
Ib of air/10,000
= 7.57
3. The required total dry air including 20% excess
air is:
_ _ .. ... excess air+ 100 heating value of fuel
7.5 Ib of airx x s
100 10,000 Btu
?5X
100 10,000
= 9.81 Ib of air/lb of fuel
Table 2-6 is an example of combustion calculations using the Btu method. This
table is taken from Steam/Its Generation and Use by Babcock and Wilcox.
Bituminous coal is the fuel used in the calculations in Table 2-6. Examples for fuel
oil and natural gas can be found in Steam/Its Generation and Use.
2-15
-------
L
I
I
N
E
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Table 2-6. Combustion calculations.
Based on quantities per 10,000 Btu fuel input
Fuel— Bituminous Coal, Virginia
Analysis As Fired
Ultimate, % by Wt Proximate, % by Wt Tota
C 80.31 Moisture 2.90 Air t
H2 4.47 Volatile 22.05 Airt
S 1.54 Fixed carbon 68.50 Flue
Oj 2.85 Ash 6.55 H20
N2 1.38 100.00
H20 2.90 Unb
Ash 6.55 . Una
700.00 Rad
Btu per Ib, as fired, 14,100
Conditions Date
by test or specification
1 air %
emperature to heater F
emperature from heater F
gas temperature leaving unit F
per Ib dry air Ib
urned fuel loss %
ccounted loss %
ation loss (ABMA), Figure 2-5 %
720
80
350
280
0.013
0.4
1.5
0.8
Quantities per 10,000 Btu Fuel Input
Fuel burned, [100 (100 - line 10) •=- line 121 - .007 x line h
Dry air, line b [(value from Rg. 4, Table 11 or Eq. 6)— .08 x line
H20 in air, line 15 x line f - 9.11 x 0.073
Wet gas, total, lines (14 + 15 + 16)
HjO in fuel, 100 (8.94 x line 5 + line 9) * line 12, or Table 11
H20 in flue gas, total, line 16 + line 18
H20 in flue gas, total, in percent, (line 19 •*• line 17) x 100
Dry gas, total, line 17 - line 19
Ib
h] Ib
Ib
Ib
Ib
Ib
%
Ib
0.66
9.11
0.12
9.89
0.30
0.42
4.31
9.47
Losses per 10,000 Btu Fuel Input
Unburned fuel, 10,000 x line h •*• 100
Unaccounted, 10,000 x line i ->- 100
Radiation, 10,000 x line j ^ 100
Latent Heat, H20 in fuel, 1040 x line 18
Btu
Btu
Btu
Btu
Sensible heat, flue gas, line 17 x Btu from Fig. 1 @ line e and line 20 = 9.89 x 50 Btu
Total losses, lines (23 + 24 + 25 + 26 + 27)
Total losses in percent, (line 28 -H 10,000) x 100
Efficiency, by difference, 100 — line 29
Btu
%
%
40
150
80
312
495
1077
10.8
89.2
Quantities per 10,000 Btu Fuel Input
Combustion temperature, adiabatic
Heat input from fuel
Btu
Heat input from air, lines (15 + 16) x Btu from Fig. 8
-------
No. of cooled furnace walls
420
a.
a
u
J3
o
tat
c
V
a
s.
•o
a
ai
0.75 0
0.87 0
t
inn..
8n .t
60'-
4. n .1
2n . i
1 0 ' •
n a , '.
0.6 '•
0.4 i1
0.2 '•
o.i :!
7/
t
s\
,
^
•
•
X
V X
x \
X
X
V
Sj's
X
^
^\
'
X
N
<1
,
S^
ft
.
k
V
?
^ft
w
S
\
^
»
Scale correction is
' for water walls onl
r \ i i
-^
X
X
X
Jk "V
^f
"x. o.
^
,v
f
-W
; air-cooled walls
• — ™
• i —
• i —
for
X
\
QjT
,
s
^x^
^
X
\
\
b
<
X
p»
s
it
s
^
^
x>
\
X
A fum
project
before
Air thi
if redu
. T7-i
\
X
\
X
££_
1 -^
ace TI
ed si
redu
ough
ction
camp
x
"x
"^
I 1 ^"H
The radiation loss values obtained from this curve are
— for a differential of 50 F between surface and ambien
temperatures for an air velocity of 100 feet per minut
"" over the surface. Any correction for other conditions
should be made in accordance with Fig. 3 page 170 ii
1957 Manual of ASTM Standards on Refractory Mat<
V\2 3 567891 20 30 40 1 60 80 200
\\ 10 50 100 3C
vail
irfa
ctic
CO
in
le:
H
%'
1
U,
e
a tl
:ria
mu.
ce c
>n in
oled
radi
Unit
outp
wate
k
x
— ^s
^«^
ie
Is.
it have at leas
overed by wat
radiation los
walls must b
ation loss is cc
guaranteed i
ut of 400 mil
r cooled walL
xl N
\
\
X
"N
*^J
"R
400 600
0 8(
-^
X
-^
ad
N
X
V *v
X X_
\
X x
\
i>
lation k
t one ti
er cook
s is pen
e used f
3 be ma
"or max
lion Bn.
>.
Loss .
xTLoss
\
X
X
X
x^ \
V \
\\
— ^
>ss at m
lird
•d su
nitte
or cc
de.
imur
i/hr
it 40
it 20
^p
its
rface
d
>mbus
n com
with t
0 = 0.
0 — 0.
X5?7 —
^x,
N
ax. c
ix;
X
X
x
L-^l
ont. c
inuous
hree -
33%
58%
^
\
_A
utput "
llOOO 2000 6000 10,000 20,
30 4000
000
.81
.90
0.88 0.94 1.0 Water wall factor
0.93 0.97 1.0 Air-cooled wall factor
Actual output million Btu/hr
Source: Babcock and Wilcox, 1978.
Figure 2-5. Radiation losses.
Review Exercise
1. To achieve complete combustion of an organic com-
pound, a sufficient supply of oxygen must be present to
convert all of the carbon to CO2. The quantity of
oxygen is called
2. In boilers, more than the stoichiometric amount of air
is required to ensure complete combustion. This volume
of air is referred to as
1. stoichiometric or
theoretical
amount
3. An orsat apparatus is used to measure the concentration
of in the flue gas.
a. particulate matter
b. CO2 and O2 only
c. CO2) H2O, and O2
d. CO2, O2, and CO
2. excess air
3. d. CO2) O2, and
CO
2-17
-------
4.
5.
6.
7.
8.
9.
10.
The is defined as the concentration of fuel
mixture that will not burn because of a lack of oxygen.
a. low amount of excess air
b. lower explosive limit (LEL)
c. upper explosive limit (UEL)
d. sensible heat factor
The amount of heat given off when a vapor condenses
to a liquid or gained when a liquid evaporates to a
vapor without a change in temperature is called
a. sensible heat.
b. latent heat.
c. enthalpy.
d. gross heating value.
The . . is equal to the STOSS heating value
minus the latent heat of vaporization of water formed by
the combustion of hydrogen contained in a fuel.
a. sensible heat (H,)
b. enthalpy (H)
c. net heating value (HV,)
True or False? Natural gas consists of varying amounts
of methane, ethane, ethylene, hydrogen, and other
gases.
Fuel oil(s) usually need tn he beared
before they can be adequately pumped to and burned in
a burner.
a. No. 1 and No. 2
b. No. 1
c. No. 5 and No. 6
d. No. 6
In the , rhe amnnnr of moisture, volatile
matter, fixed carbon, and ash in the coal are
determined.
a. proximate analysis
b. ultimate analysis
c. heat balance
True or False? Bituminous coal is harder, has a higher
heat content and contains more volatile matter than
does anthracite coal.
4. c. upper
explosive limit
(UEL)
5. b. latent heat.
6. c. net heating
value (HVB)
7. True
8. c. Nos. 5 and 6
9. a. proximate
analysis
10. False. The
reverse is true
for each criteria.
2-18
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11. In a boiler, which of the following are heat losses?
a. unbumed carbon
b. moisture in the fuel
c. hydrogen hi the fuel
d. moisture in the combustion air
e. dry flue gas
f. a., b., and d. only
g. all of the above
11. g. all of the
above
References
Babcock and Wilcox. 1978. Steam—Its Generation and Use. New York: The
Babcock and Wilcox Company.
Beard, J. T., lachetta, F. A., and Lembit, U. L. 1980. Combustion Evaluation—
Student Manual. APTI Course 427. EPA 450/2-80-063. U.S. Environmental
Protection Agency.
Joseph, G. T. and Beachler, D. S. 1981. Control of Gaseous Emissions. APTI Course
415 EPA 450/2-81-005. U.S. Environmental Protection Agency.
North American Combustion Handbook. 1965. North American Manufacturing
Co., Cleveland, Ohio.
North American Combustion Handbook. 1952. North American Manufacturing
Co., Cleveland, Ohio.
North Carolina State University. 1982. Measuring and Improving Boiler Efficiency.
Raleigh: Industrial Extension Service School of Engineering.
Woodruff, E. B. and Lammers, H. B. 1977. Steam-Plant Operation. New York:
McGraw-Hill Book Company.
2-19
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Lesson 3
Supplying Air and Fuel
Lesson Goal and Objectives
Goal
To familiarize you with the methods of introducing fuel and air into a boiler.
Objectives
Upon completing this lesson, you should be able to —
1. identify the location where primary, secondary, and tertiary air are brought
into the furnace,
2. briefly describe six types of coal-fired boilers: hand-fired, chain and traveling-
grate stoker, underfeed stoker, spreader stoker, pulverized, and fluidized bed,
and
3. briefly describe how fuel oil and gas are burned in a boiler.
Introduction
Boilers are carefully designed to burn the proper amount of air and fuel in the
firebox of the furnace. Air enters the furnace through burners, registers, or ports
depending on the design of the unit. Fuel enters the furnace through burners,
grates, or fuel beds. To achieve complete combustion air and fuel must be inti-
mately mixed. Combusted fuel produces hot flue gas that moves through the boiler
transferring heat to the boiler tubes. Flue gas is most often pushed through or pulled
through the boiler by a fan before exiting through a stack or chimney. This lesson
will look at how air and fuel are introduced into a boiler.
Combustion Air
As stated in Lesson 2, a stoichiometric amount of air is needed for combustion.
Actually, a small amount of excess air is needed to ensure complete combustion. Air
enters the furnace at different locations depending on the size, sophistication, and •
design of the boiler. In small boilers, combustion air enters through openings in the
burner or through the openings in the bottom of the furnace, called registers. In
larger boilers, the primary air used to support combustion is occasionally brought in
through the burners, through openings in the furnace walls, or through openings in
the grates. Occasionally boilers will be equipped with openings that provide
3-1
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secondary air for combustion. Secondary air helps combust any volatile gases pro-
duced in the initial combustion phase. Some boilers use burners that have openings
for primary, secondary, and tertiary air. Others bring secondary air into the furnace
through a windbox. A forced-draft fan moves air through the windbox into openings
in the furnace wall. Secondary and tertiary air are used in large boilers to ensure
that all of the fuel is completely burned.
Draft
Boilers are usually equipped with chimneys to produce the draft necessary to move
combustion air into the furnace and to discharge the combustion products, or flue
gas, to the atmosphere. Just as in a home fireplace, the draft must be produced high
enough to provide enough air to bum the fuel without causing it to smoke and to
move the flue gas up the chimney. A natural draft boiler system uses chimneys to
move gases through the system.
Natural-draft chimneys are generally used on small, simple boilers that do not use
economizers and air preheaters. Larger boilers that use heat-recovery equipment and
air pollution control devices must use fans to move air through the system because of
the high draft losses produced by this add-on equipment.
Fans applied to boiler systems fall into three categories'—forced draft, induced
draft, and balanced draft. In a forced-draft system, a fan pushes air into the fur-
nace, causing combustion products to flow through the boiler and from the stack.
The boiler is maintained at a pressure above atmospheric pressure to force the flue
gas through it. These boilers are also called pressurized furnaces. In an induced -
draft system, a fan is located after the boiler, pulling the air into the furnace,
through the boiler, and from the stack. The boiler is maintained at a pressure
slightly below atmospheric pressure. In a balanced-draft system, a forced draft fan
pushes air into the furnace and an induced-draft fan (or chimney) produces a draft
to pull flue gas through the boiler to exit from the stack. This boiler is maintained
at a pressure slightly less than atmospheric pressure, usually from 0.05 to 0.10 in. of
water.
Boiler systems generally use centrifugal fans. Gas is introduced into the center of a
revolving wheel, or rotor, and exits at a right angle (90°) to the rotation of the
blades (Figure 3-1). Centrifugal fans are classified by the shape of the blades used in
the fan. The forward-curved fans (Figure 3-la) have blades that are curved toward
the direction of the wheel rotation. The blades are smaller and spaced closer
together than are the blades of other centrifugal fans. These fans are not used to
move flue gas containing dust or sticky materials. They are generally used only as
forced-draft fans. Backward-curved fans (Figure 3-lb) have blades that are curved
away from the direction of the wheel rotation. The blades clog when the fan is used
to move flue gas containing dust or sticky fumes. They may be used on the clean-air
discharge of air pollution control devices or to provide clean combustion air for
boilers. Radial fans (Figure 3-lc) use straight blades that are attached to the wheel
of the rotor. These fans are built for high mechanical strength and can be easily
repaired. Fan blades may be constructed of alloys or coated steel to help prevent
3-2
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deterioration when handling abrasive and corrosive flue gas. Radial fans are fre-
quently used for induced-draft systems —particularly with air pollution control
devices. Airfoil fans (Figure 3-Id) have thick teardrop-shaped blades that are curved
away from the wheel rotation. Airfoil fans can also clog when handling dust or sticky
materials.
a. Forward-curved b. Backward-curved c. Radial
Figure 3-1. Centrifugal fans.
d. Airfoil
Coal-Fired Boilers
Coal is fed into a boiler and then burned in a number of ways depending on the
design and size of the boiler. The oldest and simplest method is that of hand firing.
When coal is stoked, it travels on a moving grate or is fed onto a grate by a moving
ram or spreader. Many large boilers pulverize coal into fine powder and then feed it
into the furnace through burners. Coal-fired boilers will vary depending on the
sophistication of the system and on the type of coal that is burned.
Hand-Fired
Hand firing is seldom used today, only in very small boilers used for heating or in
small industrial processes. Coal is fed manually onto a cast iron grate by a fireman.
The grate is sloped slightly towards the rear of the furnace to aid the fireman in
moving the coal to the furnace rear. The boiler size is limited to 6 or 7 ft long
because of the physical limitation of the fireman to maintain the fire. The actual
area of the grate depends on the heating surface of the boiler and the kind of fuel
burned. To start the boiler, a layer of approximately 3 to 4 inches of coal is shoveled
by hand onto the grate. Wood shavings are placed on top of the coal bed. The bed
3-3
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is usually ignited by using oily rags. Once the coal bed has ignited, coal can be fed
onto the burning bed to keep the fire going. Most of the hand-fired units have been
replaced by more sophisticated designs.
Stoker-Fired
A number of stokers are in use today. They differ in the way coal is fed onto the
grate, and the way ash is removed from the grate. Stokers can be grouped into three
major categories: underfeed stokers, overfeed stokers, and spreader stokers.
Underfeed Stokers
In an underfeed stoker coal is fed into the furnace through long troughs called
retorts. As the name implies, coal is forced up from underneath the burning fuel
bed. Air comes in through openings in the grate, called tuyeres (pronounced
twee-yars). The smallest underfeed stokers use single or double retorts. A screw
feeder on a mechanical ram forces the coal through the length of the retort and
upward. Ash is usually discharged into ash pits by side-dumping grates. Figure 3-2
shows a single-retort underfeed stoker. Single- and double-retort underfeed stokers
fire boilers that can produce 3000 to 30,000 pounds of steam per hour.
Ash pit
Retort Tuyeres
Figure 3-2. Single-retort underfeed stoker.
3-4
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Some retorts use grates that move up and down to break up the coke that forms
as coal burns and to also provide good air distribution through the burning fuel bed.
Most modern underfeed stokers use overfire-air jets, also called secondary airports, to
mix the volatile gases with air and burn them.
In underfeed stokers using feed rams, the ram forces coal from a hopper into the
retort. During normal operation, green, or raw, coal is continually pushed out over
the grate tuyeres. The burning coal slowly moves from the retort over grates toward
the sides of the furnace. After combustion is completed, ashes are dumped into an
ash pit located at the bottom of the furnace.
Larger underfeed stokers use multiple retorts, sometimes as many as twelve. To
aid in moving the coal and ash through the furnace, these retorts are inclined 25° to
30° from the rams toward the ash-discharge end of the furnace. The multiple-retort
stoker consists of single retorts placed side by side with tuyeres between each of
them. Each retort is equipped with a primary ram to feed coal from a hopper. The
fuel is moved slowly toward the furnace rear and at the same time forced up over
the tuyeres by secondary (distribution) pushers or by moving the bottom of the
retort. Most of the combustion air comes in through tuyeres. However, some overfire
air is used to ensure that the fuel is completely burned. Ash is discharged at the rear
of the furnace by dump grates, or plates. Dump grates are operated by air or steam
cylinders. Ash falls from the dump grates into an ash pit where water sprays are
used to cool the ash. Figure 3-3 shows a multiple-retort underfeed stoker. These
units are used in boilers that produce 20,000 to 500,000 pounds of steam per hour.
Boiler tubes
rimary feeding
ram
Ash dump
place
Distributing pushers
Figure 3-3. Multiple-retort underfeed stoker.
3-5
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Underfeed stokers can suitably burn both anthracite and bituminous coals and are
especially good for burning high-volatile coals. Burning low-ash coal may result in
excessive temperatures on the grate and consequently high maintenance. In addition,
if the ash in the coal fuses at a low temperature clinkers can form and clog the
openings in the tuyeres. Underfeed stokers are very responsive to changes in steam
demand because the fuel bed on the grate is very thick. An increase in airflow
through the bed quickly increases the heat in the furnace when the need for steam
increases. Conversely, if the steam demand drops, the airflow through the bed can
be decreased resulting in a lower amount of heat in the furnace.
Overfeed Stokers
In overfeed stokers, coal is fed onto a grate from hoppers. Three overfeed stokers are
called the chain grate, traveling grate, and vibrating grate.
The chain-grate stoker uses a continuously moving grate constructed of closely
fitted links of steel and chrome-cast iron. Coal is deposited onto one end of the grate
from a coal hopper. The coal depth, regulated by a gate, ranges from 4 to 12 inches
thick. Coal is burned as the grate moves through the furnace at less than 30 ft/hr.
Ash is continuously dumped into an ash pit located at the rear of the furnace.
Figure 3-4 shows a typical chain-grate stoker.
Coal hopper
Continuously
moving chain grate
Figure 3-4. Chain-grate stoker.
3-6
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The traveling-grate stoker differs from the chain-grate stoker only in the type of
grate used. The traveling grate is made of steel bars, or links attached to separate
carrier chains. Generally, two carrier chains support and drive each grate. Figure 3-5
shows a traveling-grate stoker.
Coal hopper
Ash pit
Figure 3-5. Traveling-grate stoker.
In both traveling-grate and chain-grate stokers, air enters the furnace through
openings in the grates. The amount of air is manually controlled by the stoker
operator. These units also use overfire-air jets located in the front wall of the furnace
to mix the volatile gases with air for more complete combustion. Chain-grate and
traveling-grate stokers are used on boilers that can produce as much as 200,000
pounds of steam per hour.
The vibrating-grate stoker, shown in Figure 3-6, uses vibration and gravity to
move coal through the furnace. The grate is made of cast-iron blocks attached to
water-cooled tubes. The water-cooled grate is tied into the boiler-circulating system.
Cooling the grate allows the burning of low ash coals without overheating the grate.
As with traveling-grate and chain-grate stokers, coal is fed from a hopper and the
fuel bed depth is regulated by a gate. The vibrating force is provided by a generator
located at the front of the stoker underneath the coal hopper. The grate is vibrated
for approximately 5 seconds every 2 minutes. The interval and duration of the vibra-
tion is automatically controlled. Ash is discharged into an ash pit located in the rear
of the furnace. The vibrating stoker has individually controlled air sections
3-7
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underneath the grate to supply air for the varying changes in the boiler output. The
boiler often has a rear arch to direct any volatile gases in the burnout zone back into
the active combustion zone. These units also have overfire-air jets located in the
front wall.
Overfire-air jets
Cast iron grate
tuyere blocks
(water-cooled)
^.^ . 7 Air control dampers
Ash pit • ~~~r^"--''
Figure 3-6. Vibrating-grate stoker.
These three stokers are used to burn different coals. Chain-grate stokers are used
for noncaking high-volatile, high-ash coals. Traveling-grate stokers are used for
lignite, and small-sized pieces of anthracite coal and coke breeze. Vibrating-grate
stokers are used for medium- and high-volatile bituminous coals, low-volatile
bituminous and subbituminous coals, and lignite at reduced burning rates. Overfeed
stokers are not as suitable for burning high-coking coals than are underfeed stokers.
Spreader Stokers
In a spreader stoker, coal is spread over a grate by mechanical feeders located in the
front of the furnace. Fine particles of coal and volatile gases bum while suspended
above the grate. The remainder of the coal fed into the furnace falls onto the grate
forming a thin bed of burning fuel. A forced-draft fan blows air through openings
in the grate. Some of this air is used to burn the thin bed of coal on the grate, the
remainder passes up through the furnace to bum the fine particles of coal in suspen-
sion and the volatile gases. Overfire-air jets on the front wall of the furnace supply
additional air for suspension burning and produce turbulence. Many spreader stokers
use overfire-air jets on the front and back walls of the furnace to help provide tur-
bulence for mixing volatile gases, to prevent the flames from scorching the furnace
walls and to keep them out of the coal-feeder throat.
A number of different mechanical feeders are used on spreader stokers. Most of
the feeders use adjustable rotor speeds, a feed plate, and a deflector to distribute the
3-8
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coal evenly on the grate. Coal is fed from hoppers on the front wall of the furnace to
a revolving motor with protruding blades. By varying the speed of the rotor and the
place for coal to fall on the rotor blades, the operator can distribute the coal to
various locations in the furnace. One mechanical feeder for a spreader stoker is
shown in Figure 3-7.
Deflector plate
with tuyeres
Reciprocating
feed plate
Revolving
rotor
Figure 3-7. Mechanical feeder on a spreader stoker.
Spreader stokers use a wide variety of grates and ash removal methods. Simple
units use stationary grates similar to those used hi hand-fired boilers. These units use
at least two feeders that deposit coal onto the grate. When the ash deposits fill a
grate, its feeder taken out of service, the fuel bed burns down, and the ash is raked
through the furnace door.
Dumping grates can also be used to remove ash from the grate. One feeder is
taken out of service, the flow of air through the grate is stopped, and the ash is
dumped into ash pits located below the furnace (Figure 3-8). The dumping grates
can be operated by hand or by steam- and air-powered cylinders. During the dump-
ing cycle, the coal feed to other furnace sections is increased to prevent a drop in
steam pressure in the boiler. Dumping grates have been used on spreader stokers
that can produce 15,000 to 75,000 pounds of steam per hour.
3-9
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Coal hopper
Dumping graces
Ash pit
Figure 3-8. Spreader stoker with a dumping grate.
Large spreader stokers use a continuous ash removal system. Vibrating grates have
been used, but the most popular are traveling grates. These operate similarly to
those used in overfeed stokers. A traveling grate ash removal system used on a
spreader stoker is shown in Figure 3-9. Coal is thrown onto the grate, and is burned
while the grate slowly moves through the furnace. The ash is dumped into an ash pit
located below the grate. Most traveling grates dump ash into ash pits located in the
front wall beneath the stoker. However, some have been designed to use ash pits
located hi the furnace rear. Spreader stokers can produce as high as 400,000 pounds
of steam per hour.
In many spreader stokers, collected fly ash, cinders, and bottom ash are reinjected
into the furnace. Because a portion of the coal is burned in suspension, some of it is
carried out of the furnace as cinders by the flue gas before it is completely burned.
Cinders are collected in hoppers located beneath the convection section of the boiler.
Fly ash is usually collected in cyclones or electrostatic precipitators. Some unburned
carbon is also deposited in the ash pit. These collected cinders, fly ash, and bottom
ash are occasionally reinjected into the furnace through openings in the rear wall
improving stoker efficiency by as much as 3 to 5%. However, maintenance increases
because reinjection piping may become plugged and dust collectors, ducting, and
fans may be subject to abrasion.
3-10
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Mechanical
feeders
Continuously moving
traveling grate
Ash pit
Figure 3-9. Spreader stoker with a traveling grate.
In the spreader stoker, the fuel 'bed is thiri and a portion of the coal bums in
suspension. As a result, the spreader stoker can respond rapidly to changes in steam
demand. It will bum a variety of coals ranging from lignite to semianthracite. Coals
that tend to form clinkers on the grate can be burned because of the spreading
action in the furnace. The spreader stoker can also bum municipal solid waste,
bark, bagasse, woodchips, sawdust, and coffee grounds.
Pulverized-Fired
Some large industrial boilers and most electric utility boilers use pulverized-coal (PC)
firing. Pulverizing the coal creates a large surface area to be exposed to oxygen, thus
accelerating combustion. Each boiler uses one or more pulverizing units where coal is
pulverized into a powder before it passes to the burners in the furnace. Coal is fed to
the pulverizers to meet the steam demand to the boiler. Warm air from the air
preheater dries the coal in the pulverizer. This preheated air also carries the
pulverized coal from the pulverizers to the burners. Combustion occurs as the fuel
and primary air leave the burner tip. Secondary combustion air passes through
openings in the burner, where it mixes with coal and primary air to create the
necessary turbulence to burn the coal in suspension.
Pulverizers
Three types of pulverizers are used —contact mills, ball mills, and impact mills. Each
of these is designed to pulverize bituminous coal so that approximately 65 to 70%
will pass through a 200-mesh sieve and 99% will pass through a 40-mesh sieve.
A contact mill contains stationary and power-driven grinding elements. Coal
passes between the elements where a rolling action pulverizes it into fine powder.
3-11
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The grinding elements can be balls rolling in rings, or races; or they can be rings
that move around stationary rollers. Figure 3-10 shows a contact mill using a ball
and race arrangement. The balls are located between the two grinding elements, or
races —an upper race that is stationary and a lower race that is power driven. Coal is
fed through a hopper into the contact mill. The coal is pulverized between the balls
and the lower race. This pulverized coal is blown up into a rotary classifier where
oversized pieces are sent back to the balls and races and are repulverized. The fines
are blown to the burners. A forced-draft fan supplies hot air to dry the coal, and to
move it through the mill to the burners. The mill is therefore slightly pressurized
and if the casing leaks, pulverized coal may be blown into the room where the mill is
located.
Pulverized coal
to burners
Raw coal
feed
Hot air from
forceoL-draft fan f
Grinding elements,
or races
Figure 3-10. Contact mill using balls and races
used to pulverize coal.
3-12
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The contact mill shown in Figure 3-11 uses rollers and a ring as grinding
elements. The ring is power driven and revolves around two or three stationary
rollers, or tines. The rollers rotate as the ring revolves and the coal is ground
between the two surfaces. The ground coal is carried by primary air through a
classifier where oversized pieces are separated and reground. Pulverized fines are sent
to the burners.
Pulverized
coal to burners
Raw coal
inlet
Classifier
Stationary tire
Segmented
grinding ring
Figure 3-11. Contact mill using a revolving ring and roller
(stationary tires) used to pulverize coal.
3-13
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A typical ball mill, shown in Figure 3-12, consists of a drum partly filled with steel
balls of varying sizes. The drum slowly rotates as coal is fed into it. Coal is crushed
as the balls rub against each other. Hot air is blown into the drum to dry the coal
during the pulverizing step. Pulverized coal passes through classifiers, then to the
burners. Oversized pieces from the classifier are returned to the drum for additional
grinding.
• Pulverized coal
'••'• to burners
Coal feed
Hot air
Hot air
\
«•• / • • •
• /• • • •
/
1
Drum with steel balls
Figure 3-12. Ball mill used to pulverize coal.
3-14
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In an impact mill, shown in Figure 3-13, the coal remains in suspension during
the entire pulverizing process. The grinding elements and the primary air fan are
connected to the same shaft. An induced-draft fan pulls heated air and coal (in
suspension) through the mill. Coal is ground to a granular state by hammers in the
primary grinding stages. In the final grinding stages, rotating disks move between
stationary pegs. The coal moves toward the center of the pulverizer where rotating
scoop-shaped rejector arms throw large coal particles back into the grinding sections.
The fines are passed through the fan and discharged into the burners. These mills
can adjust very rapidly to changes in steam demand. Impact pulverizers are also
called Atrita pulverizers.
Primary air
and coal to burners
Coal feeder
Primary
grinding stage
Final grinding stage
Figure 3-13. Impact mill used to pulverize coal.
Burners
Burners are designed to efficiently mix air with fuel to promote complete combus-
tion. Coal and heated primary air usually move through the center part of the
burner. Secondary combustion air is supplied from the windbox to the burner by a
forced-draft fan. The amount of secondary air coming in through the burner is con-
trolled by dampers. Occasionally, tertiary air will be brought into the furnace
through openings, or ports, on the furnace wall or through openings around the out-
side wall of the burner. Coal is ignited by inserting a burning gas, oil, or kerosene
torch into the burner.
Many different burner designs are used in pulverized coal-fired boilers. Figure
3-14 shows a typical wall-mounted burner. In this burner, fuel and air are mixed by
impellar vanes. The boiler is usually equipped with a number of these burners
mounted on the walls of the furnace.
3-15
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Impeller
vanes XSoftP^
Figure 3-14. Typical burner used for pulverized coal firing—
circular register burner.
The intervane burner, shown in Figure 3-15, imparts a rotary motion to the coal
and primary air mixture in a central nozzle. This rotary motion provides good air
and fuel mixing (turbulence). Secondary air flows into the furnace from a register
that surrounds the nozzle. Coal is ignited by using an oil igniter.
Oil igniter
Coal nozzle
Figure 3-15. Intervane burner used for pulverized coal firing.
3-16
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In the horizontal burner, shown in Figure 3-16, coal is fed through a central nozzle
with internal ribs. The nozzle is surrounded by a housing containing adjustable vanes
to control air turbulence and flame shape. Coal is ignited by inserting an ignition
torch through the central tube.
The shape of the flame in the furnace depends on the type of burner used and
location or firing pattern shown hi Figure 3-17. In vertical firing, burners placed at
the top of the furnace produce a long U-shaped flame. In horizontal firing, burners
extend through the furnace wall producing a turbulent cone-shaped flame. Burners
can be mounted on one side or on opposite sides of the furnace. In tangential firing,
the furnace has one or more burners in each corner. The flames move toward the
furnace center forming a large swirling ball of flames.
Coal
nozzle
Figure 3-16. Horizontal burner used
for pulverized coal firing.
Horizontal firing
\\
Tangential firing
(top view)
Figure 3-17. Various firing patterns of
pulverized coal-fired boilers.
3-17
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Advantages and Disadvantages
The ash in the coal can present operating and maintenance problems that must be
considered when designing the furnace. Small- and medium-sized furnaces have ash
removed in the dry state, and are called dry bottom units. The temperature of the
furnace must be maintained below the ash-fusion temperature of the coal being
burned. If this precaution is not taken, large quantities of slag can form, fouling the
boiler surfaces. In some larger furnaces, the furnace temperature is maintained
above the ash-fusion temperature of the coal. In this case the bottom ash is in the
molten state, called slag. The slag is tapped from the furnace and then chilled by
water. The rapid change hi temperature causes the molten slag to shatter into small
pieces of ash. These pulverized units are referred to as wet bottom.
Pulverized coal-fired boilers have the following advantages and disadvantages
(Woodruff and Lammers, 1977):
Advantages
• Can adjust very quickly to varying steam demands.
• Requires low amount of excess air.
• Reduces or eliminates heat losses due to furnace banking.*
• Can be repaired without cooling down the furnace because most of the equip-
ment is located outside the furnace.
• Can burn a variety of coals.
• Can use high-temperature preheated air successfully—thus increasing furnace
efficiency.
• Easily adapted to automatic combustion control.
Disadvantages
• Costly to install.
• Requires skilled personnel to operate because of explosion possibilities.
• Has high fly ash carryover —requiring the use of electrostatic precipitators or
baghouses to meet emission regulations.
• Requires multiple mills and burners to obtain satisfactory operating ranges.
• Slag deposits may form on lower boiler tubes.
• Requires extra power to pulverize coal.
Fluidized-Bed
Fluidized-bed boilers have recently been used in some industrial and electric utility
steam generators. These boilers are frequently referred to as atmospheric fluidized-
bed (AFB) combustion units. The technology of fluidized-bed boilers evolved in oil
refineries and chemical plants where they were used in many, processes and also to
destroy gaseous, liquid, and solid wastes.
In a fluidized-bed boiler, coal and an inert material such as sand, alumina, ash
(from the fuel), or limestone, are suspended in a combustion chamber by air blow-
ing up through the bed. Fluidizing the fuel bed provides turbulent mixing required
*The furnaces of stoker-fired boilers are banked with coal that is burned very slowly during periods
when there is a low demand for steam. A banked furnace can quickly be returned to full service by
adding more coal and combustion air.
3-18
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for good combustion. The amount of fluidization that occurs depends on the size of
coal and inert material and the velocity of the air moving through the bed. The
fluidized-fuel bed essentially behaves as a liquid. The resulting improvement in fuel
mixing allows the fuel to bum at lower temperatures, approximately 1500 to
1600°F, compared to other coal-fired boilers. Thus, the combustion chamber of a
fluidized-bed releases heat at an equivalent level to that of a conventional boiler, but
at lower temperatures without any theoretical loss in efficiency.
Fluidized-bed boilers offer some advantages over conventional designs in terms of
reducing air pollutants. Because the operating temperatures are relatively lower,
nitrogen oxide emissions will be lower. In fluidized-beds using limestone in the fuel
bed, sulfur oxides, formed as the sulfur in the coal oxidizes, combine with the
limestone to form calcium sulfate and sulfite particles that can be collected in an
electrostatic pretipitator or a baghouse.
Figure 3-18 shows a typical fluidized-bed boiler. Some fluidized-bed boilers use
underbed feed systems, where coal is fed underneath the fluidized-bed. Others use
overbed feed systems, and/or a combination of underbed and overbed feed systems.
Overbed feed systems consisting of gravity-feed pipes or conventional spreader-stoker
mechanisms have been successfully used. Many systems use perforated plates with
equally-spaced holes that distribute air evenly through the fuel bed providing
uniform fluidization. Some systems use steam tubes placed directly in the fluidized
bed, while others use separate combustion chambers followed by convection sections,
superheaters, and economizers.
TD —*• Flue gas
'..'."..."..''. 1—^- Steam
Overbed
coal feed
Underbed
coal feed
Limestone
• Underbed coal feed
' Feedwater
Figure 3-18. Schematic of a fluidized-bed boiler.
Fluidized-bed boilers can be designed to bum many different grades of coal, wood
chips, solid wastes, and shredded tires. Fluidized-bed boilers are capable of pro-
ducing 10,000 to 600,000 pounds of steam per hour.
3-19
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Summary
Boiler designs affect the application of air pollution control and the response time to
generate steam. Underfeed and overfeed stokers usually have lower fly ash carryover
than do spreader stokers or pulverized-coal-fired boilers. Fine powdery fly ash is
more readily carried with the flue gas. Data available on the fluidized-bed indicate
that the fly ash carryover from these units are less than from pulverized-coal boilers.
In terms of response time, in other words, the unit's ability to start up and change
for various steam demands, pulverized-fired boilers are the quickest. These units are
followed in order by fluidized beds, spreader stokers, overfeed stokers, and underfeed
stokers.
Oil-Fired Boilers
Oil is used as fuel in many commercial and industrial boilers and in some utility
boilers. The design of the combustion system depends on the grade of fuel oil
burned and on the size of the boiler. As stated in Lesson 2, fuel oils are graded
according to gravity and viscosity, the lightest being No. 1 and the heaviest being
No. 6. Light distillate oils, such as No. 1 (kerosene), will readily vaporize in simple
burners. Heavy fuel oils such as No. 6 must be heated to be adequately pumped to
and burned in the burners.
Boiler Sizes
Boilers generate steam or heat for many commercial establishments. Commercial-
sized boilers typically burn Nos. 4, 5, and 6 fuel oil at a rate of 3 to 100 gallons per
hour (gph) (EPA, 1980). Electric heat is often used to decrease the viscosity of
heavier fuel oils so that they will vaporize at the burner tip. Steam can also be used
to heat heavy fuel oils. If distillate oils, Nos. 1 and 2, are burned, they do not need
to be heated. Commercial-sized units are designed to use approximately 20 to 30%
excess air. Fire-tube and water-tube (packaged) boilers are used for commercial
establishments.
Industrial-sized boilers usually burn Nos. 4, 5, and 6 fuel oil at a rate of 70 to
3500 gph (EPA, 1980). Steam heaters are often used to heat these heavy fuel oils.
Industrial boilers are shipped as packaged units or fabricated at the plant site. These
boilers are designed to operate with approximately 10 to 15% excess air.
Utility boilers firing fuel oil burn No. 6, Bunker C, at rates of 3500 to 60,000 gph
(EPA, 1980). These boiler systems usually include steam or electric heaters, insulated
and/or heat traced piping, suction strainers for removing sludge, meters, and
regulating and safety valves. Utility boilers are usually erected in the field and are
designed to operate with approximately 2 to 4% excess air.
Burners
Steam-, air-, or pressure-atomizing burners are most frequently used for firing oil.
Oil is atomized into very fine particles by the burner before it is burned. A steam-
atomizing burner (internal mix) is shown in Figure 3-19. The oil is atomized as the
3-20
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steam contacts it, before reaching the burner tip, forming a short, bushy flame.
These burners are used on commercial, industrial, and utility boilers at firing rates
up to 1100 gph. An air-atomizing burner is shown in Figure 3-20. This burner uses
low-pressure air to atomize the oil. Oil enters the rear of the burner and flows
through a central tube. Oil combines with primary and secondary air at the end of
the tube. Primary air moves through tangential vanes causing air to swirl as it passes
around the stream of oil. This mixture combines with secondary air at the burner
tip. These burners can bum No. 2 fuel oil or Nos. 4 and 5 fuel oil when used on
commercial-sized boilers. A mechanical pressure-atomizing burner is shown in Figure
3-21. Oil flows at high pressure through a center tube and is discharged through
tangential slots in a swirling chamber. The swirling oil passes through a sprayer-plate
into an orifice where some of the oil moves through an orifice plate while a portion
is returned to the suction pump. The amount of oil returned is determined by the
position of the return-line control valve. Oil leaving the burner tip forms a conical
spray.
Steam supply
Oil supply -
Steam supply
Figure 3-19. Internal mix steam atomizing burner
used for oil firing.
Low pressure
air inlet
Oil inlet
Figure 3-20. Air atomizing burner used for oil firing.
3-21
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Sprayer plate
Oil return and orifice
Figure 3-21. Mechanical pressure-atomizing burner
used for oil firing.
Summary
Fuel oil burned in boilers to generate steam has the following advantages over coal
(Woodruff and Lammers, 1977):
• Oil can be stored without deteriorating or combusting spontaneously.
• Plants can be operated with less labor than coal-burning steam plants, because
of ease in operating oil transporting and burning equipment and because less
ash is produced when oil is burned.
• Combustion processes can be automatically controlled.
• Initial plant costs are less than for coal-burning plants because coal- and ash-
handling equipment are not necessary.
• Plants are easier to keep clean.
• Plants produce lower amounts of air pollutants than coal-burning plants.
(However, the amount of SO2 and NOr emissions can still be significant).
Gas-Fired Boilers
Gaseous fuels burned in boilers are natural gas, by-product coke oven gas, blast fur-
nace gas, refinery gas, and manufactured gas. Natural gas is readily available
because of the vast network of gas pipelines. Other gases are used in the plants
where they are produced or in neighboring plants. Natural gas is burned in smaller
boilers, usually for residential or commercial establishments. Gas is occasionally used
as a back-up fuel for industrial and utility boilers. It is also used for igniting
pulverized coal-fired boilers.
Burners
Gas burners vary in the way they mix air and fuel. A simple premix burner is shown
in Figure 3-22. Gas and primary air are mixed upstream of the burner tip.
Secondary air is brought in at the burner tip. These burners are used on small
residential- and commercial-sized boilers. Industries that have a large supply of
blast-furnace or coke-oven gas readily available occasionally use them in boilers to
produce steam or electricity.
3-22
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Air and gas mixture Burner tip
>J
Figure 3-22. Premix burner used for gas firing.
A burner that can be used to fire gas and/or oil is shown in Figure 3-23. Gas enters
through a large circular ring at the burner throat. Air from a windbox enters at the back
end of the burner tube. Curved vanes impart a whirling motion to the air. Air mixes
with the gas in the burner tube. The oil tube runs through the center of the burner.
Air inlet
Curved air
vanes "^s,
Tangential blast furnace gas inlet.
Figure 3-23. Combined blast furnace gas and oil burner.
3-23
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Summary
The maintenance of gas-fired boilers is visually less than either oil-fired or coal-fired
boilers. However, gas burners must be maintained because burners can become
dogged. Air register mechanisms must be in good operating conditions and the
boiler settings must be frequently checked to reduce air inleakage. Burning gas pro-
duces less air pollutants than do either oil or coal, because gas contains very little
sulfur and virtually no ash.
Review Exercise
1. In a
system, a fan located after the boiler
pulls air through the boiler and out the stack.
a. natural-draft
b. forced-draft
induced-draft
c.
fans are frequently used for induced-draft
systems, especially if the flue gas contains a high concen-
tration of dust.
a. Radial
b. Backward-curved
c. Forward-curved
1. c. induced-draft
3. In a(an)
coal is fed into the furnace through
2. a. Radial
long troughs called retorts.
a. overfeed stoker
b. underfeed stoker
c. traveling-grate stoker
d. spreader stoker
4. In an underfeed stoker, a
forces coal
through the length of the retort and upward.
a. mechanical spreader
b. chain grate
c. screw feeder
d. mechanical ram or screw feeder
3. b. underfeed
stoker
5. True or False? Multiple retort underfeed stokers are
inclined slightly to aid in moving the coal and ash
through the retorts.
4. d. mechanical
ram or screw
feeder
5. True
3-24
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In underfeed stokers, combustion air conies through
openings in the grate called
a. tuyeres.
b. windboxes.
c. over-fire air jets.
7. Chain-grate and traveling-grate stokers are
a. underfeed stokers.
b. overfeed stokers.
c. spreader stokers.
6. a. tuyeres.
8. stokers use grates constructed of closely
fitted links of steel and cast iron while
stokers use grates made of steel bars attached to a
separate chain.
a. Spreader, chain-grate
b. Chain-grate, traveling-grate
c. Traveling-grate, chain-grate
d. Chain-grate, vibrating-grate
7. b. overfeed
stokers.
9. In both traveling-grate and chain-grate stokers, com-
bustion air enters the furnace through openings in the
, and through located on the
front wall.
a. tuyeres, grates
b. grates, tuyeres
c. grates, overfire-air jets
8. b. Chain-grate,
traveling-grate
10. In vibrating-grate stokers, the grate is made of
a. cast-iron blocks attached to water-cooled tubes.
b. closely fitted bars attached to a separate chain.
c. steel bars that continuously move from the front to
the back of the furnace.
9. c. grates,
overfire-air jets
11. In a
fine particles of coal and volatile
gases burn while suspended above the grate.
a. single-retort underfeed stoker
b. spreader stoker
c. overfeed stoker
d. vibrating-grate stoker
10. a. cast-iron
blocks attached
to water-cooled
tubes.
12. Spreader stokers use _
furnace.
a. shovels
b. traveling grates
c. pulverizers
d. mechanical feeders
to feed coal into the
11. b. spreader
stoker
12. d. mechanical
feeders
3-25
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13. In most spreader stokers, ash is removed from grates by
or
a. traveling grates, dumping grates
b. vibrating grates, mechanical rams
c. screw conveyors, tuyeres
14. True or False? In pulverized-coal firing, coal is heated
by hot air from the air preheater.
13. a. traveling
grates, dumping
grates
15. Coal can be pulverized into a very fine powder by using
a. ball mills.
b. contact mills.
c. impact mills.
d. all of the above
14. True.
16. In a contact mill, coal is crushed as it moves
between grinding elements. These elements are
a. balls rolling in rings, or races.
b. rings that move around stationary rollers.
c. a drum filled with steel balls.
d. a. and b. above
e. all of the above
15. d. all of the
above
17. True or False? In burners used for pulverized-coal
firing, coal is ignited by inserting a burning-gas, oil, or
kerosene torch.
16. a. and b. above
18. In most burners used for pulverized-coal firing,
move(s) through the center part of the
burner.
a. secondary air
b. primary air
c. coal and primary air
d. none of the above
17. True.
19. A pulverized-coal-fired boiler using a tangential-firing
pattern has
a. six burners mounted on the front and back walls of
the furnace.
b. one or more burners in each corner of the furnace.
c. two rows of burners in both the top and bottom of
the furnace.
18. c. coal and
primary air
19. b. one or more
burners in each
corner of the
furnace.
3-26
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20.
21.
22.
23.
24.
25.
In pulverized-coal boilers, if the bottom ash is removed
from the furnace while it is in a molten state, these
units are referred to as
a. dry bottom.
b. slag spreaders.
c. wet bottom.
d. none of the above
In fluidized-bed boilers, coal and inert materials are
suspended hi the combustion chamber by
a. a chain grate.
b. mechanical rams and screw feeders.
c. electrical fluidizers and bar grates.
d. air blowing down through the bed.
e. air blowing up through the bed.
True or False? Fluidized-bed boilers are capable of
reducing both SO2 and NOX emissions. This is because
limestone in the fuel bed combines with NO* to form
calcium nitrate. Because the furnace temperature is
relatively low, SO2 formation is also reduced.
Which of the following has the highest fly ash carryover
from a boiler furnace.
a. underfeed stoker
b. traveling-grate stoker
c. spreader-stoker
d. pulverized-coal-fired boiler
e. fluidized-bed boiler
Which of the following fuel oils is(are) usually heated
before being pumped to and burned in burners?
a. No. 1 and No. 2
b. kerosene
c. No. 5 and No. 6
True or False? Fuel oils are atomized in the burner
by using steam, air, or mechanical pressure.
20. c. wet bottom.
21. e. air blowing
up through the
bed.
22. False.
SO2 combines
with limestone
to form calcium
sulfate and NO*
emissions are
reduced because
of the low
furnace
temperatures.
23. d. pulverized-
coal-fired boiler
24. c. No. 5 and
No. 6
25. True.
3-27
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References
Babcock and Wilcox Company. 1978. Steam Its Generation and Use. New York:
Babcock and Wilcox Company.
Environmental Protection Agency (EPA). 1981. A Guide to Clean and Efficient
Operation of Coal-Stoker-Fired Boilers. EPA 600/8-81-016.
Environmental Protection Agency (EPA). 1980. APTI Course 427, Combustion
Evaluation—Student Manual. EPA 450/2-80-063.
Joseph, G. T. and Beachler, D. S. 1981. Control of Gaseous Emissions. APTI
Course 415, EPA 450/2-81-005. U.S. Environmental Protection Agency.
Makansi, J. and Schwreger, B. 1982. Fluidized-Bed Boilers. Power, August, 1982.
Power. Controlling Combustion and Pollution in Industrial Plants New York:
McGraw Hill.
Woodruff, E. B. and Lammers, H. B. 1977. Steam-Plant Operation, fourth
edition. New York: McGraw-Hill Book Company.
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Lesson 4
Operation and Maintenance
Lesson Goal and Objectives
Goal
To familiarize you with normal boiler operation and maintenance, including system
controls and safety practices.
Objectives
Upon completing this lesson, you should be able to —
1. recognize the use of water columns, fusible plugs, and steam gauges in a boiler,
2. briefly describe the operation of a boiler feedwater regulator,
3. recognize soot blowers and describe their operation,
4. recognize two safety devices used to control the flow of water and steam in a
boiler and to detect the presence of flames in burners, and
5. briefly describe the reason for and use of blowdown in a boiler.
Introduction
The automatic controls used on boilers will depend on the size of the boiler, the fuel
that is fired, the operating pressures, and the steam requirements from the boiler.
Because the operating and maintenance procedures will be unique for each boiler, it
is essential that it be operated accordingly to assure continuous, safe, and efficient
operation.
Controls and Instruments
Controls used on a boiler will provide for safe and efficient operation. A number of
variables are measured including steam pressure and flow, furnace pressure and
draft, feedwater flow, air flow, fuel supply and feed rate, and flue gas composition
(CO, O2, and CO2). Many of these variables are also automatically controlled to
keep the boiler operating. Most controls consist of a few basic components (TPC
Training Systems, 1975):
• primary element that senses and responds to cycle changes, such as a drop in
steam pressure or too low water level.
• error detector that measures and compares an output signal to a set point. This
is usually considered to be the actual controller.
4-1
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• relaying element that converts the controller's signal and transmits the signal to
control points.
• power units that receive the control impulses and then activate a device such as
a damper, or close or open a valve, or feed more fuel to the boiler.
Water Glasses and Columns
Maintaining the proper water level of a boiler protects it from overheating and
allows it to be adjusted for varying changes in steam demands. Some small boilers
have gauge glass, or water gauges, mounted directly on the front of the boiler shell
that visually show the water level. Most boilers use water columns to indicate water
level. Water columns are small vessels, or tubes, connected to the boiler drum, to
which gauge glasses are attached (Figure 4-1). Water columns can be located on the
boiler so that they can be easily inspected and maintained. Water columns have a
blowdown valve and line. Water is drained during blowdown to remove the scale
and dirt that accumulate on the viewing glass. Scale and dirt could cause the water
level readings to be off.
Water column
Figure 4-1. Water column on a horizontal return-tube boiler.
A simple gauge glass is suitable for boilers operating at pressures below 400 psi. It
is a small glass tube fitted with valves at the top and bottom, so that steam and
water flows will be shut off if the glass breaks. The gauge glass used on boilers with
pressures from 400 to 2000 psi consists of flat glass strips backed with pieces of mica.
The mica separate the glass from high-temperature steam and water. A bicolor glass
gauge is used on boilers operating with high pressures, 1000 psi to 3000 psi. It
operates on the optical principle that light beams bend differently when they pass
through water or steam. The illuminated gauge contains a green glass and a red
4-2
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glass sandwiched together., The green glass detects water and the red glass detects
steam. The water level is where the two colors appear to meet. If water is in the
glass gauge, red light will be bent out of the field of vision and green light will
appear. If steam is in the glass gauge, green light will be bent out of the field of
vision and red light will appear.
In a fire-tube boiler, the water level must be at least 3 inches above the top row of
tubes. In a water-tube boiler, it must be adequate enough to assure that all of the
tubes contain water or steam to prevent them from overheating. Overheating in both
fire-tube and water-tube boilers could burst the tubes and cause a possible explosion.
Many boilers use alarms to signal when the water level is not adequate. High
water alarms signal when the water level is too high and low level alarms signal
when the water level is too low.
Fusible Plugs
Fusible plugs are used to sound alarms when the water level in a boiler is low. These
are brass or bronze and contain a tapered hole. In an ordinary plug, the hole is
filled with tin which has a melting temperature of approximately 450 °F. One side of
the fuse plug is exposed to hot gases, the other side to water. The water carries the
heat away from the plug side exposed to the hot gases. If the water level drops below
the plug, the heat will melt the tin and blow it out of the core. This causes a
pressure-activated alarm to sound, warning the boiler operator that the water level is
low.
Once set off, fusible plugs must be replaced. This can be done by taking the
boiler out of service. However, many boilers use fusible plugs installed in a pipe con-
nected to a valve (Figure 4-2). When the fuse blows, the valve can be shut and
another fuse inserted without taking the boiler out of service. Fusible plugs should be
inspected frequently to check for scale and din buildup on the water side and soot
deposits on the fire side. These deposits will cause the plug to malfunction.
Fuse
Inside type Outside type Fuse alarm
Figure 4-2. Fusible plugs and fuse alarm.
4-3
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Pressure Gauges
Pressure gauges are used to measure steam and water pressure in steam drums, feed-
water heaters, steam headers, and other boiler equipment. Pressure gauges are the
Bourdon tube, manometer, diaphram, and bellows.
The Bourdon tube is the most common gauge used on a boiler. It consists of a
curved tube that is sealed at one end (Figure 4-3). The sealed end is connected to a
pointer by linkage. The open end of the gauge is the pressure connection. As
pressure increases in the tube, the tube straightens out, moving the pointer. As the
pressure decreases the tube returns to the normal curved position. Bourdon pressure
gauges can measure pressures of steam, air, oil, water, or other fluids. These gauges
require careful handling and proper maintenance to keep them operating accurately.
They should be removed from their mountings, disassembled and cleaned with a
suitable solution regularly.
Tube
Open end ' Exterior
Bourdon tube and linkage
Figure 4-3. Typical Bourdon pressure gauge.
Steam gauges for a small boiler are usually mounted on top of the water column.
The gauge will directly read the pressure of the boiler. In many boilers, gauges will
be mounted on pipes that run from the steam dram to ground level, so that they
can easily be read by the operator. At this level, the gauge reads the steam pressure
plus the hydraulic head of water in the line. The true steam pressure is the value
read on the gauge minus the hydraulic head. For each foot of vertical distance
between the connection at the drum and the ground level, the gauge reading must
be corrected by subtracting a value of 0.433 psi per foot of head. Gauges can also be
mounted above the point of pressure measurement. In this case the pressure due to
the hydraulic head must be added to the gauge reading.
Manometers are commonly used to measure low air pressures and pressure dif-
ferences between two points. Two manometers are the single leg and U-tube. A
single leg manometer is a glass tube filled with water or mercury. The top of the
tube is open to the atmosphere and the pressure that is measured enters an opening
in the well (Figure 4-4a). If the pressure is greater than atmospheric, the fluid in the
4-4
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tube will rise. If the pressure is below atmospheric, the fluid in the tube falls. A
U-tube manometer, shown in Figure 4-4b, has two legs filled with water or mercury.
When both legs of the manometer are exposed to the same pressure, the manometer
shows a zero reading. If there is a difference in pressure in the legs, the liquid level
will rise in one leg and fall in the other. A scale beside the tube for either a single
leg or a U-tube manometer indicates pressure in inches of mercury or water,
depending on the type of fluid used.
Atmospheric
pressure
Pressure
Pressure
Unknown
pressure
a. Single leg
b. U-tube
Figure 4-4. Manometers.
Manometers are useful in determining if the boiler is operating efficiently. Occa-
sionally, tube sections become coated with heavy deposits of soot or slag that can
cause a resistance to the flue gas flow. By using manometers, pressure drops across
various boiler components can be detected and appropriate maintenance initiated.
Manometers must be checked regularly to ensure they are free of din and dust
and that they have the correct amount of liquid in the tubes. All connections should
be tight.
Feedwater Regulators
Feedwater regulators automatically control the water supply. Feedwater regulators
reduce the risk of low or high water levels, increasing the safety of boiler operation.
Three basic designs for feedwater regulators are the single-element, two-element,
and three-element (Figure 4-5).
Small boilers, having infrequent changes in boiler load use single-element
regulators (Figure 4-5a). These respond only to a change in water level. If the level
of water is inadequate, the sensor sends a signal to the controller. The controller
then opens or closes a valve to increase or decrease waterflow. Single-element
regulators cannot compensate for water "swells" or shrinkage that occur as the firing
rate in the boiler changes. When the firing rate increases, the water in the drum
swells because steam bubbles form below the water surface. When the firing rate
4-5
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decreases, the water volume in the drum decreases because the number of steam
bubbles and their size decreases. Thus, these regulators are not used on boilers that
have rapid changes in firing rates.
A rwo-element regulator is shown in Figure 4-5b. This regulator responds to
changes in water level in the steam drum and to the steam flow from the boiler. A
steam flow sensor measures the flow of steam, sending a signal to the controller as
the flow of steam changes. The controller then changes the position of the feedwater
valve to increase or decrease water flow to the drum. If the water level changes after
the drum pressure becomes stable, the controller changes the feedwater valve to
restore the proper water level. This regulator thus uses the steam flow to prevent
underfeeding and overfeeding of water to the boiler drum and uses the water level
sensor to finally adjust the correct water level.
A three-element regulator (Figure 4-5c) responds to changes in the water level,
steam flow, and water flow. The three-element regulator maintains the correct water
level in the drum by adjusting the feedwater flow to correspond to the changes of
steam flow from the boiler. When the boiler load varies, the steam and water flows
change immediately. Three-element regulators handle swells and shrinkage better
than do two-element regulators and are used on boilers with wide and sudden load
changes.
Level sensor
Steam flow
Valve
Controller
r-CJ
Pump
Water flow
Valve !
a. Single-element regulator
* Steam drum
Steam flow sensor
| Level LJ~[J b. Two-element regulator
Controller I sensor JL c" *^i
j , j —*m\ Steam flow
n—F=——
Pump
Water flow
Steam flow sensor
! Level
c. Three-element regulator
Valve
Controller j sensor
r
Steam flow
Water flow sensor
Pump
Water flow
Source: TPC Training Systems.
Figure 4-5. Feedwater regulators.
4-6
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Steam Headers
Steam is transported to processes or turbines through pipes or headers. Headers are
cylindrical vessels from which steam is withdrawn as the demand changes. Headers
are constructed to withstand internal shock and pressure because high velocity steam
passes through them. Headers can also be used in superheaters and in water walls to
allow steam or water to move through the boiler circulatory system.
Steam headers are insulated and provided with drains and traps to remove any
water that condenses in and to prevent condensing water from entering pumps,
engines, or turbines. Main steam headers are connected to branch steam lines from
each boiler. This system makes it possible to use one boiler or a combination of
boilers to supply steam for various industrial processes and/or turbines.
Safety Devices
Valves
Boilers are designed to operate at certain maximum pressures. If the operating
pressure is exceeded, the boiler may explode. Therefore, all boilers are equipped
with at least one or more safety valves. Safety valves will open, releasing steam if the
pressure in the drum becomes too high.
In a safety valve, a compressed spring holds a disc snuggly against a seat (Figure
4-6). When the pressure against the disk exceeds a preset limit, the safety valve pops
open—causing the disk to move away from the seat. The pressure at which the valve
opens can be changed by adjusting the compression spring. When a safety valve
opens, it discharges, or blows, steam until the pressure of the boiler decreases to a
preset amount. The valve then shuts back into its normal seating arrangement. The
pressure difference between the popping pressure and the closing pressure is called
blowback. The valve must be properly adjusted for sufficient blowback or the valve
will leak slightly after popping. Blowback can be adjusted by raising or lowering a
ring around the valve seat. Safety valves can also be popped manually by using hand
levers. For large boilers, each superheater and reheater will have one or more safety
valves. The safety valves are located near the outlets of these tube sections.
If a boiler has several valves, they are set to pop at different pressures. The first
valve should open when the pressure exceeds a value approximately 3 to 5% above
the boiler operating pressure. The other valves will open at pressures slightly above
the first valve, usually 10 to 15 psi (TPC Training Systems).
Safety valves should be checked on a regular basis to make sure that they operate
properly. They should be maintained to prevent an accumulation of scale or dirt
that would interfere with safe operation.
4-7
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Spring
Figure 4-6. Safety valve.
Flame Detectors
Flame detectors, or scanners, monitor burner flames on all boilers and ignitors on
coal- and oil-fired boilers. If the flame in a burner or ignitor goes out, a flame
detector sends a signal to the fuel feed controls that automatically stop the flow of
fuel into the boiler. Thus, the boiler is prevented from operating or igniting while
explosive conditions in the furnace exist.
Three flame detectors used on boilers are photocell, ultraviolet, and infrared
detectors. Photocells detect visible light, ultraviolet sensors detect ultraviolet light,
and infrared sensors detect infrared light in the burner flame or ignitor. These
devices are installed in the furnace wall as shown in Figure 4-7.
4-8
-------
Main burner detector
\
Ignition burner
detector
Main burner
\
Ignition burner
Figure 4-7. Location of flame detectors.
Combustion Controls
Combustion controls are used to adjust the amount of air and fuel supplied to the
furnace to respond to the changes in boiler steam pressure. Three combustion con-
trols are on-off, positioning, and metering.
On-off controls, the simplest, are used on fire-tube and small water-tube boilers.
A change in steam pressure activates a pressurestat or mercury switch to start the
stoker, the oil burner, or gas burner and the forced-draft fan. The on-off control
system supplies a pre-determined amount of fuel and air. The air and fuel ratio can
be altered, if necessary, by manually adjusting fuel and air settings on the controls.
When the steam pressure builds up again, the controls shut down the fuel and air
supplies. On-off controls cannot supply a steady steam pressure because they work
on a cyclic basis. The pressure points are set far enough apart to prevent the on-off
sequence from being constantly activated. Combustion efficiency is low because the
control system can only vary the length of the on and off cycles.
Positioning controls, used on many boilers, are more flexible and can provide
better combustion efficiency than can on-off controls. These controls operate on a
continuous basis, providing smoother changes in fuel and air feed, allowing the
boiler to maintain a more uniform steam pressure. The control system has a master
pressure controller that responds to a change in steam pressure. When the steam
pressure changes, power units actuate the damper on the forced-draft fan to control
air flow and position the fuel valve to regulate the fuel feed. Furnace-draft con-
trollers operate independently of the positioning controls to maintain the furnace
draft. Positioning controls operate effectively on boilers having relatively stable steam
demands. The amount of air and fuel feed can be adjusted manually to change the
4-9
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air-to-fuel ratio. These adjustments are required to compensate for boiler load
changes, dirty tube surfaces, slagging of fuel on furnace walls, or changes in
barometric pressure.
Metering controls are a refinement of positioning controls. As with positioning
controls, metering controls also have a master pressure controller that responds to a
change in steam pressure. However, the metering control system measures the actual
flow of fuel and air. The flow of steam or water is measured to correspond to the
amount of fuel fed into the furnace. This can be accomplished by measuring the
pressure drop across an orifice, flow nozzle, or venturi. The draft loss across the
clean-air side of the combustion air preheater is measured to indicate the air flow
through the boiler. The metering controls change the damper and fuel valve posi-
tions to maintain the correct air-to-fuel ratio. Metering controls are generally located
in a remote station where they can be operated automatically or manually. These
control systems allow the boiler to be operated efficiently for wide changes in boiler
loads. They can also compensate for changes in the fuel supply and for dirt buildup
on the tube surfaces.
Operation
The procedure for operating a boiler will depend on the boiler size, the type of com-
bustion equipment used, the operating pressure of the unit, and the steam
requirements. The boiler manufacturer should supply the operator with specific
instructions as to how to bring the unit on line, general operating practices,
emergencies, and caring for idle boilers.
Bringing the Boiler on Line
A specific startup procedure should be followed to prevent the boiler from being
damaged. The boiler should be inspected thoroughly after it is installed to make sure
that all manhole and access covers have been replaced and that all scaffolding,
ladders, tools, and other equipment have been removed from the inside and outside
of the boiler. Fans, dampers, and combustion equipment should be checked for
proper operation.
New boilers and those that have accumulated oil and grease must be cleaned with
an alkaline solution. The solution is first prepared and then pumped into all boiler
tube sections. The boiler is slowly brought on line to approximately one-third of its
normal working pressure and left on line for one to three days. In addition to being
cleaned with an alkaline solution, large boilers are also cleaned out with an acid
solution. After the cleaning cycle is finished, the boilers are flushed out with water.
New boilers are then given a hydrostatic test before placing them into service. This
test consists of filling the boiler with water and slowly building up to 1 V£ times the
normal working pressure. During the test, all safety valves are removed or blocked
off so they will not open.
All boiler valves, vents, drains, and the feedwater regulators should then be
checked according to the manufacturers operating procedures. The boiler is then
4-10
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slowly brought on line while the draft gauges are checked and the fans and dampers
are adjusted to establish the correct air flow to and from the boiler. The feedwater
regulator is operated and the water level and feedwater-supply pressure are carefully
checked. The furnace is slowly fired to prevent excessive temperature differences and
resulting unequal expansion of boiler components. Combustion is regulated to bring
the boiler up to full operating pressure, usually in approximately 45 minutes for
small- and medium-sized boilers and approximately two to three hours for large
boilers. Even longer periods may be required for boilers that operate at very high
temperatures.
Normal Operation
Operating a boiler is a continuous process. Fuel and air are supplied to produce
steam, while waste products of ash and flue gas are discharged. The boiler operator
must adjust the flow of these materials to maintain the correct steam pressure. On
boilers that do not have automatic controls, the operator must watch the steam
gauge and adjust the fuel as is necessary. On automatically-controlled boilers, the
change in steam pressure will adjust the fuel feed. However, the operator will still
have to check the bed thickness in a coal-fired stoker, and monitor the shape of the
flame when pulverized coal, gas, or oil is burned. He will also have to check draft
gauges, flue gas analyzers, pressure gauges, thermocouples, damper settings, and ash
removal systems and make any necessary adjustments. Instruments and controls
should be checked, adjusted, calibrated, and kept in good operating condition.
High combustion efficiency can be achieved by monitoring the flue gas with con-
tinuous emission monitors. By measuring the oxygen or carbon dioxide in the flue
gas, adjustments for the correct amount of excess air can be made. Too much excess
air wastes heat out through the stack. Too little excess air causes a high concentra-
tion of combustibles to remain in the ash and smoke and unburned fuel to be
discharged from the stack. (Note: operator safety concerns are the overriding factors
at low excess air conditions). The operator can use analyzers and draft gauge
readings to help keep combustion efficiency high.
The operator will also have to perform certain maintenance functions to keep the
boiler operating smoothly. Some of these, such as blowdown and sootblowing, must
be done on a regular eight-hour shift basis. Others must be done on a regularly-
scheduled basis. Boiler maintenance will be discussed later in the lesson.
Emergencies
Occasionally, emergencies occur and the boiler must be taken off line. An emer-
gency shut-down procedure must be established and all operators should be familiar
with it to ensure a safe shut down.
Many boilers are equipped with automatic controls that activate in the event of
burner flame out or low water level. Fuel valves automatically close and the boiler is
shut down until the difficulty has been corrected. In many large boilers, alarms
sound for high and low water levels and the operator must then decide on the
appropriate action to be taken.
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If the water level becomes low, the operator should make sure that feedwater is
added to the boiler. If for some reason the feedwater regulator does not work, the
fuel and air feed to the boiler should be stopped. The procedure will depend on the
combustion equipment used on the boiler.
Failure in fuel supply, too much primary air, or a disturbance because of
improper sootblowing, may cause the flame to blow out in a pulverized-coal-, gas-,
or oil-fired boiler. The flame detector will stop the fuel flow to the burner. Fans
should be operated to remove combustible fuel and gases from the furnace. Once
the corrective action has been completed, fans should be operated for a short time to
ensure that no combustibles are present. Natural draft fans have an advantage in
that they will operate if a power outage occurs.
Forced-draft and induced-draft fans can fail, safety valves become stuck, and
occasionally fires in pulverizers can occur making an emergency shut down
imperative. The boiler must be shut down to prevent an explosion from occurring.
All plant operators must be ready to initiate safe emergency operating procedures.
Care for Idle Boilers
Boilers must be taken off line for occasional inspection and repairs. Some boilers are
only used on a periodic basis to provide heat or steam during colder seasons. When
a coal-fired boiler is taken out of service for extended time periods, the coal in the
bunkers should be used up before shutting the boiler down. Coal stored for long
rime periods can be a fire hazard.
The normal procedure for removing boilers from service involves reducing the fuel
feed and slowly decreasing the steam pressure. All drain connections should be
opened and the feedwater valve should be closed. The boiler should be allowed to
cool down slowly to prevent injury because of rapid contraction of metal and refrac-
tory materials. All tube sections should be washed out to remove any sludge deposits.
Boilers that will be out of service for short time periods can be filled up with an
alkaline solution and deaerated water. This will allow the boiler to be ready to be
brought back on line, after it is quickly drained and filled with water. Boilers taken
out of service for extended time periods should be flushed with water and permitted
to thoroughly dry. Containers of unslaked lime or dessicant are then placed in the
boiler to absorb any moisture from the air in the confined space. Boilers prepared
for storage in these two ways can be returned to service by restoring the water level
and bringing the unit on line by the normal startup procedure.
Maintenance
All boilers operate more efficiently when they are properly maintained. Maintenance
schedules vary depending on the boiler component and its location. Boiler tube sec-
tions, boiler drums, and heat recovery equipment must be kept free of soot and scale
to provide good heat transfer and adequate cooling to tube surfaces. Boiler auxiliary
systems such as pumps, fans, valves, and motors must be maintained to operate
4-12
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properly. Boiler manufacturers should provide guidelines to the suggested
maintenance schedules and procedures.
Sootblowing
Sootblowing removes soot and ash from the fire-side of boiler tubes and heat
recovery equipment. These deposits insulate tube surfaces reducing boiler efficiency.
They can also erode and corrode metal surfaces, particularly if fly ash is sharp and
contains sulfates and acids. The amount of soot and ash deposited on tube surfaces
depends on the content and fusion temperature of the ash in the coal burned, and
the combustion efficiency in the furnace. A large amount of ash is produced from
burning coal; burning oil produces less, while burning gas produces almost no ash.
Hand lances and sootblowers remove soot and ash (slag) from tube surfaces by
blasting jets of air or steam against the tubes, while the furnace is on-line. Most
large boilers use sootblowers, the two common types being rotary and retractable.
In a rotary sootblower, air or steam flows through a tube, or arm, and discharges
at a very high speed through nozzles. The nozzles are spaced to blow steam or air
directly into each boiler tube as the arm rotates. In a retractable sootblower, the
blower is located outside the furnace. The blower moves in and out of the furnace
and can reach far inside a boiler to clean superheaters, reheaters, and economizers.
Sootblowing is done at least once a day and occasionally more often. The time
between sootblowings depends on the type of fuel burned and how quickly the tube
sections become dirty. An increase in the flue gas temperature exiting the boiler or
an increase in pressure drop across the tube sections are good indicators that tubes
are dirty. If tubes quickly become dirty again after sootblowing, the operator should
check the air-to-fuel ratio. There may be too little air to burn the fuel completely,
thus forming soot.
When a boiler is down for service, boiler tubes can be cleaned by washing them
with water. Hard slag deposits can be removed by carefully chipping them off with a
chisel.
Water Treatment
Boiler feedwater must be treated before it can be used. Suspended solids, dissolved
minerals, and dissolved gases can cause corrosion and scale in boiler tubes and affect
the quality of steam produced.
Minerals dissolve in water as ions that carry an electrical charge. The ions increase
the electrical conductivity and hardness of the water, both of which can damage
boiler tubes. Increased electrical conductivity rapidly corrodes metal surfaces. High
levels of hardness in the water cause scale and sludge to form on tube surfaces.
Boiler feedwater can be treated by softening methods.
Water hardness results when mineral salts of magnesium and calcium dissolve in
water. These salts can be removed by using chemical softeners or ion exchangers.
Chemical softeners are vessels where soda ash or lime react with dissolved salts to
form solid precipitates. The solids settle in the bottom of the vessel while softened
water passes through a filter to remove only remaining solids. Ion exchangers are
vessels containing a thick bed of grainy material called resins. Hard water flows
4-13
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through the bed where the resin absorbs the hard ions and replaces them with
harmless ions. When the resin bed no longer absorbs hardness ions, the bed is
regenerated with a strong salt solution to replenish its supply of harmless ions.
Another ion exchange process, called demineralization, uses two ion exchange beds,
one containing acid, the other containing a caustic soda solution. These systems are
designed to produce very pure water.
The measure of the concentration of hydrogen ions in water is called pH. It has a
numerical value on a scale of 0 to 14. A pH of less than 7 indicates acidic water and
a pH of greater than 7 indicates alkaline water. Boiler feedwater should have a pH
of 8.5 to 11.5. Water with low pH values can corrode boiler tubes. Water from lakes
and streams that is used in many boilers has a pH ranging from 6.0 to 8.0. The pH
of this water may be raised by adding chemicals such as ammonia, phosphates, or
caustic soda to boiler feedwater.
Dissolved oxygen in feedwater eats away at the metal, weakening boiler tubes,
drums, and piping. One way to remove dissolved oxygen is by using a deaerating
heater. Many deaerating heaters consist of trays stacked inside a vessel. Water enters
the top of the vessel and flows down through the trays. Steam heats the water as it
flows through the vessel causing most of the dissolved oxygen to leave the heater with
the steam. Heated, deaerated water is sent to a storage tank where chemicals such as
sodium sulfite or hydrazine are added to remove any oxygen still remaining in the
water.
Evaporators are also used to remove dissolved impurities from water. An
evaporator consists of a steam coil in a tank. Water is fed into the tank and heat,
supplied by the steam coil, causes the water to boil. Water leaves the evaporator as a
vapor leaving the impurities behind. The vapor enters a heat exchanger where it
condenses as pure, distilled water. The sludge left in the evaporator is removed from
the bottom.
Boiler feedwater is constantly tested to determine its purity. Impurity tests include
checks on dissolved oxygen, silica content, hardness, pH, and conductivity. These
tests can be done manually or by using automatic monitoring devices. Even small
amounts of impurities in the water can damage boiler equipment and reduce
efficiency.
Slowdown
As a boiler generates steam, any impurities in the water become concentrated in the
boiler water. As these concentrations increase, they can cause corrosion, scale, or
possibly boiler tube failure. A procedure called blowdown reduces the impurity levels
(solids) in boiler or cooling water. Blowdown consists of removing water containing a
high level of impurities and replacing it with high quality water. Blowdown can be
done on a periodic or continuous basis.
In periodic blowdown, a main blowdown, or blowoff, valve is opened allowing
water to drain out of the system. This is usually done when the steam demand is
low. Most boilers have the blowoff valve connected to the lower, or mud, drum, In
cooling towers, blowdown involves opening a blowoff valve that is located in the
basin on the tower.
4-14
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In continuous blowdown, a small amount of water from a boiler or cooling tower
is constantly removed. Continuous blowdown valves are usually located in the steam
drum. Makeup water that replaces the blowdown water is fed to the drum by the
feedwater regulator. Blowdown water is sent to heat exchangers to extract useful
heat before disposing of it. Heat, from the blowdown water in a heat exchanger, is
transferred to makeup water before it enters the economizer.
Water is tested regularly to determine the level of dissolved solids and, thus, the
frequency of blowdown. Conductivity meters that measure the electrical conductivity
of the boiler water are used to determine blowdown frequency.
Scale Removal
Scale forms on the inside of tubes in a water-tube boiler and on the outside of tubes
in fire-tube boilers. Scale insulates tubes, reducing heat transfer and thus efficiency.
As the heat transfer decreases, the metal tubes become hotter. If the temperature
becomes too high, the tubes can overheat and eventually rupture, or burst.
Scale formation can be reduced by using water softeners, demineralizers, and
evaporators. These devices remove most of the materials that cause scale. However,
not all of the minerals are always removed and scale deposits will form in boiler
tubes. Scale deposits should be removed as soon as possible. Scale can be removed by
internal cleaning while the boiler is on line or by mechanical or acid cleaning when
the boiler is down.
For internal cleaning, chemicals such as phosphates are added to boiler water.
Phosphate salts react with scale to form sludge. Sludge is removed during blowdown.
Mechanical cleaners remove scale from boiler tubes when the boiler is shut down.
Mechanical cleaners are power-driven units that contain a cleaning head, a hose,
and a motor driven by steam, air, or water. The cleaning head for removing scale
from a fire-tube boiler is called a knocker and is shown in Figure 4-8a. The knocker
head has lobes that tap the inside of the tube as the cleaner moves through the tube.
Mechanical cleaner heads used on water-tube boilers are called cutter heads. The
cutter head has several cutting elements made of hard steel (Figure 4-8b). The head
is rotated at high speed, pressing the cutter against the tube to remove the scale.
Acid cleaning can also remove scale from boiler tubes and drums. The cleaning
solutions consist of acids, such as hydrochloric acid, and other materials called
inhibitors to reduce the attack of acid on the metal. The cleaning solutions circulate
or soak in the boiler for a few hours. When the cleaning cycle is complete, the boiler
is flushed with alkaline and water solutions to remove any traces of acid. Acid clean-
ing has some advantages over mechanical cleaning in that it requires much less down
time to clean the boiler, and it can clean areas and tubes where mechanical cleaners
are difficult to reach.
4-15
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Scale
a. Tube cleaner for
fire-tube boiler
b. Tube cleaner for
water-tube boiler
Cutter heads
Figure 4-8. Cleaning heads for fire-tube
and water-tube boilers.
Boiler Auxiliaries
Pumps, valves, safety valves, controls, compressors, and fans are among the many
boiler auxiliaries that must be maintained regularly. Pumps require lubrication to
keep the bearings from overheating, rusting, or corroding. Pumps can leak around
the packing gland. The packing can be tightened somewhat to help stop leaks.
Valves should be checked for correct operation and leaks. Valves tend to leak
around the valve stems and packing and may need to be repacked occasionally. All
moving parts on a valve should be lubricated. Compressors must be lubricated to
protect cylinders from heat and wear. If the compressor has its own lubricating
system, the oil level should be checked daily, and the oil changed when dirty. Intake
filters must be checked and replaced when they become filled with dust. Water
jackets and intercoolers should be inspected to make sure they do not become
plugged. Fan blades need to be inspected for excessive wear when they are out of
service. Dust deposits in the fan housing and ducts should be removed. Dampers
should be moved manually to make sure they move freely and close completely. The
bearing oil resevoir level should be checked and oil added if necessary.
These are a few of the maintenance functions that must be performed to keep the
boiler operating smoothly. The maintenance crew should have a checklist and
logsheet for each boiler component. Inspection frequencies and preventive
maintenance practices should be established for all boiler equipment by the vendors.
Summary
This lesson briefly reviewed boiler operation and maintenance. Boilers can be com-
plicated systems and operators and maintenance persons should be properly trained
on all aspects of the boiler equipment that they will be operating or maintaining.
4-16
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Review Exercise
1.
2.
3.
4.
5.
6.
7.
8.
Most boilers use to indicate the water level.
are used to sound alarms when the wafer
level in a boiler is low.
a. Gauge glasses
b. Water columns
c. Fusible plugs
True or False? Bourdon pressure gauges can measure
pressures of steam, air, oil, and water.
. are rommonly used rn measure air flow
pressures and pressure differences between two points.
a. Bourdon gauges
b. Manometers
c. Fusible water columns
Feedwater regulators are automatic controls that
a. regulate the amount of water that is sent to the cool-
ing tower.
b. adjust the water level in the boiler.
c. adjust the water level in the condenser.
A three-element feedwater regulator responds to
changes in
a. water level, water flow, and steam flow.
b. air flow, water flow, and water level.
c. steam level, water flow, and air flow.
In a boiler, headers are used to
a. collect condensed steam.
b. release steam if the pressure becomes too high.
c. transport water and steam.
All boilers are equipped with , that are used
ro release steam if the ., in the boiler becomes
too high.
a. blowdown valves, water temperature
b. safety valves, pressure
c. steam traps, pressure
d. all of the above
1. water columns
2. c. Fusible plugs
3. True
4. b. Manometers
5. b. adjust the
water level in
the boiler.
6. a. water level,
water flow, and
steam flow.
7. c. transport
water and
steam.
8. b. safety valves,
pressure
4-17
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9. In a safety valve, the pressure difference between the
popping pressure and closing pressure is called
a. blowdown
b. pressure drop
c. blowback
10. Most boilers use flame detectors to
a. detect and adjust the length of the flame.
b. detect the presence of a flame and thus prevent the
boiler from operating or igniting while explosive con-
ditions in the furnace exist.
c. measure and adjust the flame profile, thus ensuring
complete combustion conditions.
9. c. blowback
11. Boilers are cleaned with
to remove
accumulated oil and grease before bringing them
on-line.
a. alkaline solutions
b. alkaline solutions and acid solutions
c. alkaline solutions, acid solutions, and water
10. b. detect the
presence of a
flame and thus
prevent the
boiler from
operating or
igniting while
explosive
conditions in
the furnace
exist.
12. Ash and dust that deposit on the outside surface of
boiler tubes can be removed while the boiler is
on-line by
a. sootblowing
b. blowdown
c. knocker heads
d. all of the above
11. c. alkaline solu-
tions, acid
solutions, and
water
13. Sootblowers remove ash and soot from boiler tube
surfaces by
a. scraping boiler tubes with wire brushes.
b. blasting jets of alkaline solution against the tubes.
c. blasting jets of air or steam against the tubes.
12. a. sootblowing
13. c. blasting jets
of air or steam
against the
tubes.
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14.
If the flue gas temperature at the stack exit
or the pressure drop across tube sections
it is likely that boiler tubes are dirty and sootblowing
should be initiated.
a. decreases, increases
b. increases, decreases
c. decreases, decreases
d. increases, increases
15. True or False? Water hardness results when mineral
salts of magnesium and calcium dissolve in water.
14. d. increases,
increases
16. What should be the pH of boiler feedwater?
a. 5.0 to 7.0
b. 8.5 to 11.5
c. 11.5 to 14.0
15. True.
17. Hardness can be removed from water by
a. adding lime or soda ash to the water.
b. using ion exchangers.
c. using demineralizers.
d. all of the above
16. b. 8.5 to 11.5
18. True or False? Boiler feedwater should contain a high
concentration of dissolved oxygen.
17. d. all of the
above
19. A procedure called
reduces the impurity
18. False.
levels (solids) in boiler water and cooling water by
periodically removing water from the boiler or cooling
tower.
a. sootblowing
b. deaerating
c. blowdown
20. Scale can be removed from boiler tubes by using
mechanical cleaners. are used for cleaning
fire tubes, while are used for cleaning water
tubes.
a. Blowdown valves, retractable sootblowers
b. Cutter heads, knocker heads
c. Knocker heads, cutter heads
19. c. blowdown
20. c. Knocker
heads, cutter
heads
4-19
-------
References
Babcock and Wilcox. 1978. Steam—Its Generation and Use. New York: The
Babcock and Wilcox Company.
TPC Training Systems. 1975. Generating Steam in the Power Plant. Barrington,
Illinois: Technical Publishing Company.
TPC Training Systems. 1975. Using Steam in the Power Plant. Barrington,
Illinois: Technical Publishing Company.
Woodruff, E. B. and Lammers, H. B. 1977. Steam-Plant Operation. New York:
McGraw-Hill Book Company.
4-20
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Lesson 5
Steam Turbines, Condensers,
and Cooling Towers
Lesson Goal and Objectives
Goal
To familiarize you with the operation of a turbine used to produce electricity and
with the operation of auxiliary equipment in a power plant.
Objectives
Upon completing this lesson, you should be able to —
1. describe the operation of a turbine in producing electricity,
2. recall the location of condensers in a power plant and the reason they
are used,
3. recognize two types of cooling towers and the difference in their operation,
and
4. recall the locations of steam turbines, condensers, cooling towers,
feedwater heaters, and reheaters in a complete steam generation system.
Introduction
Boilers produce steam for many different purposes. Some industries design their
facilities to use steam in the processes, to heat the facility during colder months, and
occasionally to generate electricity for in-plant use. Utilities use steam to drive large
turbines that generate electricity. The design and complexity of a boiler system will
vary depending on the size and ultimate use of the steam produced by the boiler.
Steam Turbines
Steam contains a tremendous amount of heat energy. Heat energy is transformed
into mechanical energy to drive a steam turbine. The turbine in turn rotates a
generator which changes the mechanical energy into electrical energy, or electricity.
A steam turbine has two main parts —the cylinder and the rotor. The cylinder, or
stator, is made of steel or cast iron and contains the fixed blades, vanes, or nozzles
that direct steam into the movable blades. The rotor is a shaft that carries the
5-1
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movable blades. High-temperature, high-pressure steam enters one end of the tur-
bine through an inlet valve into the steam chest. The steam chest contains control
valves that regulate the flow of steam into the turbine. Steam flows through a set of
stationary blades, or nozzles. As the steam passes through the nozzles, it expands in
volume, and its velocity increases. The steam moving at high velocity strikes the first
set of moving blades, causing the shaft to rotate (Figure 5-1). The steam enters the
next set of fixed blades and then into the set of moving blades, continually causing
the shaft to rotate.
Shaft
Steam intake
Steam exhaust
Figure 5-1. Typical steam turbine.
As the steam moves through the turbine its pressure and temperature decrease,
while its volume increases. A pound of steam will expand over 800 times its original
volume as it moves from the steam header through the turbine. The turbine,
therefore, increases in diameter from the inlet to the outlet. This allows the volume
of steam to increase as it moves through the turbine without reducing the efficiency
of the system.
A turbine that uses the impact force of a steam jet on the blades to turn the shaft
is called an impulse turbine. Its action is analogous to that occurring with a wind-
mill. As the wind strikes the blades, the impact force causes the windmill to turn.
The harder the wind blows, the faster the windmill blades will turn. The steam flow
through the blades in an impulse turbine is shown in Figure 5-2. Steam expands as it
passes through the nozzles where its pressure decreases and its velocity increases. As
steam flows through the moving blades, its pressure remains the same and its velocity
decreases because the steam does not expand here. The nozzles, or fixed blades,
expand the steam again as the steam moves into the next stage. The pressure
decreases in each stage as the steam expands through the fixed blades.
5-2
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Moving blades
A
v
Fixed blades
Figure 5-2. Steam flow through the blades
of an impulse turbine.
In a reaction turbine, the pressure decreases and the velocity increases while the
steam flows through both the fixed and moving blades. The action is analogous to
the kickback that an individual receives when shooting a shot gun. The reaction
turbine uses the kickback force from the steam as it leaves the moving blades to
rotate the shaft. All of the blades are the same shape and therefore act like nozzles
(Figure 5-3).
Many utilities use turbines that have both impulse and reaction blade
arrangements. These turbines usually have impulse blades at the high-pressure end
and reaction blades at the low-pressure end of the turbine. The length and size of
the blades increase from front to back to use the expanding steam efficiently.
5-3
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Stationary blades
V
Moving blades
Figure 5-3. Steam flow through the blades
of a reaction turbine.
Large steam turbines usually have high-pressure, intermediate-pressure, and low-
pressure sections (Rgure 5-4). Steam, from the superheater, goes to the main steam
header. It flows into the high-pressure section of the turbine, rotates the shaft, and
looses some of its pressure and temperature. The steam then goes back to the boiler
where it is heated in the reheater. Steam flows from the reheater to the
intermediate-pressure turbine where it turns the rotor. Part of the steam is extracted
from the intermediate-pressure turbine and is used to heat water in the boiler feed-
water heaters. The rest of the steam flows through a crossover pipe to the low-
pressure turbine and continues to turn the rotor. In the low-pressure turbine, the last
bit of work is extracted from the steam. Some steam from the high-pressure and low-
pressure turbines is also extracted to heat boiler feedwater. The spent steam from
the low-pressure turbine is sent to the condenser.
5-4
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To boiler reheater
-<
Main steam
header
/-*>. Main stop
(/*-"~~ valve
Hot reheat steam from boiler
Reheat stop valve
_ Intercept valve
Crossover
„. ,
High-pressure
u-
turbine
Control
valves
Intermediate-
pressure
r , .
turbine
n
J I
T
Low-pressure
r. .
turbine
V U
J L
"X Shaft
Feedwater heaters
Low-pressure
exhaust
to condenser
Figure 5-4. Steam flow through high-pressure, intermediate-pressure,
and low-pressure turbines.
5-5
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The shaft arrangements can be single, tandem-compound, and cross-compound as
shown in Figure 5-5. A single turbine consists of one steam turbine coupled to a
generator. In a tandem-compound turbine, a high-pressure turbine and a low-
pressure turbine are joined to a common shaft that is coupled to a single generator.
In a cross-compound turbine, a high-pressure and an intermediate-pressure turbine
are joined to a common shaft and a low-pressure turbine is on a separate shaft. Each
shaft drives its own generator.
Turbine Generator
a. Single turbine
High-pressure Low-pressure
turbine
turbine
Generator
b. Tandem-compound turbine
... , Intermediate-
Hiim-pressure „
0 V- pressure Generator
turbine r , .
turbine
Low-pressure ,-,
r. . Generator
turbine
c. Cross-compound turbine
Figure 5-5. Turbine and generator shaft arrangements.
Condensers
Condensers are used in connection with steam turbines for two reasons: (1) to pro-
duce a vacuum at the turbine exhaust and (2) to recover the condensate, condensed
steam, so it can be used again. Because condensed steam is pure distilled water, it is
very suitable for use as boiler feedwater. Condensed steam, at the turbine exhaust,
produces a vacuum to remove the back pressure that would otherwise hinder the
flow of steam from the turbine. Because the condensed steam is at a lower
temperature than the exhausted steam, the overall efficiency is increased.
5-6
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Two types of condensers are the direct contact and indirect contact. In a direct
contact condenser, steam is mixed with sprays of cooling water (Figure 5-6). The
cooling water condenses the steam and both are collected at the bottom of the vessel,
called the hotwell. Few power plants use direct contact condensers because the cool-
ing water, usually pumped from nearby lakes, rivers, or ponds, contaminates the
pure condensed steam. Thus, the condensate is unsuitable to be used as boiler feed-
water without first being treated extensively.
Steam inlet
Cooling water
Hotwell
Figure 5-6. Direct-contact condenser.
Most power plants use indirect, or surface, condensers, commonly called shell-and-
tube heat exchangers. The surface condenser is a closed vessel containing many
small-diameter tubes (Figure 5-7). Cooling water passes through individual tubes
while steam flows over and around tube bundles. Condensed steam collects at the
condenser bottom or hotwell. The condensate is pumped from the hotwell, through
the feedwater heaters, into the economizer, and finally back into the boiler steam
drum where the cycle begins again. Depending on the design, the cooling water can
make one or more passes through the tubes before being discharged. Warmed cool-
ing water is returned to the rivers or lakes or is sent to a cooling tower. Because the
5-7
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cooling water does not actually come in contact with the steam, the pure condensed
steam is not contaminated as it is in the direct contact condenser.
Cooling water
tubes
Hotwell
Water inlet
Figure 5-7. Surface condenser.
Condensers require large quantities of cooling water. A condenser uses approx-
imately 9 to 12 gallons of water (75 to 100 Ib) to condense each pound of steam
(TPC, 1975).
The water pumped from nearby rivers, lakes, and streams passes through intake
screens located at the water source to remove sticks, leaves, and other suspended
solids from it. Screens can become plugged, and therefore, must be periodically
checked and maintained to remove collected debris. Otherwise, waterflow to the
condenser may be restricted.
Condenser tubes become dirty after continual use. Tube fouling occurs when
scale, slime, and algae collect on the inside of the tubes. These deposits can reduce
both heat transfer and water flow through the condenser. Tubes can be cleaned by
using a hydraulic gun, chemicals, or backwashing. In the hydraulic gun technique,
rubber plugs are shot by water jets through the condenser tubes. The rubber plugs
rub against the tube walls to remove slime and soft scale. In chemical cleaning,
chlorine or chlorine compounds are added regularly to the water supply. The
chlorine dissolves algae and reduces slime buildup. In backwashing, the water flow
through the condenser is reversed, flushing out the tubes.
Cooling Water Systems
The cooling water system through the condenser can be a once-through or a recir-
culating system. Water is pumped from the source and flows through large pipes or
channels. The intake of the pipe has a screen or a set of closely-spaced bars to pre-
vent solids from entering the pipe. Water is pumped through the condenser and is
5-8
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returned to the source with an increased temperature occasionally as high as 20 °F
above the water source's temperature. This can cause thermal pollution to the water
source, possibly injuring fish and other organisms.
Power plants having limited water supplies or those with high-temperature return
water from the condenser use a recirculating cooling water system. This system uses
one or more cooling towers to remove heat from the warmed cooling water and
returns the water to the condenser. A recirculating system only requires a small
amount of additional cooling water (approximately 5 to 10%) to replace any losses
that occur during the cooling operation.
One type of cooling tower, a mechanical draft tower, uses either a forced-draft
fan that is located at the bottom of the tower or an induced-draft fan that is located
at the top of the tower. In a tower using a forced-draft fan, air is blown up through
the tower while the warm water from the condenser is sprayed at the top of the
tower. Water descends over wood, ceramic, or fiberglass slats and collects in a basin
at the tower bottom. In an induced-draft cooling tower, air enters louvers in the side
of the tower and is pulled upward by the fan (Figure 5-8). In both of these towers,
the water temperature decreases as water evaporates and heat is transferred to the
air. A pump in the basin returns cooled water back to the condenser.
Fan
Water inlet
Air inlet
Water outlet
Figure 5-8. Induced-draft cooling tower.
A hyperbolic natural-draft cooling tower is shown in Figure 5-9. Water is sprayed
at the tower top and falls over slats of wood, ceramic, or fiberglass contained in the
5-9
-------
tower. Air enters the bottom of the tower and rises up through the tower because of
the natural draft. Cooled water collects in a concrete basin and is returned to the
condenser.
Water flow
Air inlet
Figure 5-9. Hyperbolic natural-draft
cooling tower.
In cooling towers, the dissolved solids concentration increases as the cooling water
evaporates. Buildups of minerals in the water can cause scale, corrosion, and
plugging in the condensers, pumps, and piping. Scale formation can be reduced by
adding phosphates to the water. Phosphates react with scale-forming impurities
precipitating them into a sludge. The sludge settles in the tower basin and is
removed during blowdown. Phosphates can cause algae to grow, but the algae
growth can be controlled by adding chlorine. The pH of the cooling water can be
adjusted by adding either sulfuric acid or lime. Dissolved oxygen in the cooling water
can be reduced by adding corrosion inhibitors.
Summary
This lesson briefly covered steam turbines, condensers, and cooling towers. A com-
plete steam generation system that generates electricity contains a boiler, turbine,
generator, and auxiliary equipment. Figure 5-10 shows the schematic diagram of a
coal-fired boiler system.
Pulverized coal is fed into the burners of the boiler by a forced-draft fan. Steam
produced in the boiler tubes collects in steam drums where moisture is removed by
separators. Steam is then sent to the superheater where it is further heated. High-
pressure, high-temperature steam leaves the superheater through steam headers.
Steam enters the steam chest in the turbine where control valves regulate the flow
through the turbine. The high-pressure turbine, containing fixed and moving vanes,
is turned as the high-pressure steam strikes the blades. Steam is exhausted from the
5-10
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high-pressure turbine and piped back to the reheat section of the boiler to be heated
again. Reheated steam flows through the intermediate-pressure turbine and/or the
low-pressure turbine. Some steam is extracted from the turbines to heat boiler feed-
water in the feedwater heaters. Boiler feedwater is further heated in the economizer
before it flows to the steam drum as makeup water. Steam is exhausted from the
low-pressure turbine into the condenser to create a vacuum and to condense steam
into high quality water to be used again in the boiler. Condenser cooling water is
cooled by using cooling towers. Fresh makeup water for the boiler is treated by
chemicals and by an evaporator or demineralizer before it goes to the feedwater
heaters. Flue gas produced in the boiler goes through the boiler tube sections, the
economizer, air preheater, and finally through air pollution control devices to
remove pollutants before it enters the atmosphere.
Induced draft
fan
Air preheater
Low-pressure
turbine
Superheater
Air pollution control device
High
turbine
Main steam. /.
Cooling
tower
Circulating
water pump
Condensate
pump
Low-pressure
feedwater heaters
Makeup water
Evaporator or
Chemical feedwater demineralizer
treatment
Figure 5-10. Layout of a steam generation system.
5-11
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Review Exercise
High-temperature, high-pressure steam enters a turbine
through an inlet valve into the
a. steam chest.
b. reheater.
c. condenser.
2. In a turbine, fixed or stationary blades are called
a. stators.
b. nozzles.
c. rotors.
1. a. steam chest.
3. As steam moves through a turbine and is exhausted, its
pressure , its volume , and its
2. b. nozzles.
temperature
a. increases, decreases, decreases
b. decreases, decreases, decreases
c. decreases, increases, decreases
4. A
uses the kickback force from steam as
it leaves the moving blades to rotate the shaft.
a. impulse turbine
b. impact turbine
c. reaction turbine
3. c. decreases,
increases,
decreases
5. In a steam turbine, steam is sent from the high-
pressure turbine to the before it enters the
low-pressure turbine.
a. economizer
b. reheater
c. superheater
d. condenser
4. c. reaction
turbine
Condensers are used in connection with steam
turbines to
a. cool water before it is returned to rivers or lakes.
b. produce a vacuum at the turbine exhaust.
c. recover condensed steam.
d. b. and c. above
e. all of the above
5. b. reheater
6. b. and c. above
5-12
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Power plants generally use _
water is not contaminated.
a. direct contact condensers
b. spray ponds
c. surface condensers
so that cooling
8. Cooling towers that use fans located in the top of the
tower are called
a. hyperbolic natural-draft towers.
b. induced-draft towers.
c. forced-draft towers.
7. c. surface
condensers
9. In cooling towers, the water temperature decreases as
the water , thus transferring heat to the air.
a. condenses
b. evaporates
c. diffuses
8. b. induced-draft
towers
10. In cooling towers, dissolved solids can be removed by
a. blowdown
b. blowback
deaerators
9. b. evaporates
c.
10. a. blowdown
References
Babcock and Wilcox. 1978. Steam—Its Generation and Use. New York: The
Babcock and Wilcox Company.
TPC Training Systems. 1975. Generating Steam in the Power Plant. Barrington,
Illinois: Technical Publishing Company.
TPC Training Systems. 1975. Using Steam in the Power Plant. Barrington, Illinois:
Technical Publishing Company.
Woodruff, E. B. and Lammers, H. B. 1977. Steam-Plant Operation. New York:
McGraw-Hill Book Company.
5-13
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Lesson 6
Air Pollution Emissions, Regulations,
and Control Techniques for Industrial
and Utility Boilers
Lesson Goal and Objectives
Goal
To familiarize you with the air pollution emissions generated in a boiler, the air
pollution regulations that limit the amount of pollution that can be emitted from a
boiler, and the control techniques used to reduce these emissions.
Objectives
Upon completing this lesson, you should be able to —
1. name three air pollutants emitted from a boiler,
2. recognize two regulations that have been adopted to limit the amount of air
pollution that can be emitted from a boiler, and
3. recognize at least three control techniques and equipment used to reduce
paniculate, SO2, and NOX emissions from a boiler.
Air Pollution Emissions
Air pollution emissions generated from burning fossil fuels in a boiler are paniculate
matter, sulfur dioxide (SO2), nitrogen oxides (NO*), and carbon monoxide (CO).
These are emitted in varying amounts depending on the fuel burned and the boiler's
operating conditions. A complete listing of emission factors for particulates, SO2,
and NO* emitted from boilers is given in the EPA publication AP-42.
Particulate Matter
Paniculate matter is emitted from a boiler stack when fossil fuel is burned in the
furnace. Since coal usually contains a higher content of ash than does fuel oil or gas,
the paniculate emissions from coal-fired boilers are usually greater than those from
oil-or gas-fired boilers. In fact, when natural gas is burned in a boiler, paniculate
emissions are almost nil. Coal-fired boilers produce different amounts of paniculate
emissions depending on ash content of the coal and the way the fuel is burned in the
furnace. For instance, when coal is pulverized and burned in a pulverized coal-fired
6-1
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boiler, the paniculate emissions are higher than those from an underfeed, overfeed,
or spreader stoker boiler. Underfeed, overfeed, and spreader stoker boilers burn a
coarser coal than do pulverized coal-fired boilers, resulting in coarser fly ash in the
exhaust gas. Emission factors used to estimate paniculate emissions from coal-fired
boilers are listed hi Appendix A.
For fuel-oil combustion, paniculate emissions vary depending on the grade and
composition of the fuel burned, the type and size of the boiler, and the firing and
loading practices. Loading practice refers to the percent capacity—such as 50%,
75%, or 100% of the boiler's rated capacity—at which the boiler is operated. The
amount of paniculate emissions resulting from burning fuel oil depends mostly on
the grade of the fuel burned. Fly ash emissions are greater when burning heavy
residual oils (Nos. 5 and 6 grades) than when burning lighter distillate oils (No. 2
grade). Paniculate emissions are also a function of the sulfur content when burning
residual oil. The higher the sulfur content for residual oil, the higher the paniculate
emissions generated. This is because high sulfur residual oil contains more ash,
sulfur, and heavy organic compounds that are difficult to bum cleanly. Emission
factors used to estimate paniculate emissions from oil- and gas-fired boilers are listed
in Appendix A.
Sulfur Dioxide
Sulfur dioxide emissions occur when the sulfur contained in the fuel is oxidized to
SO2. Therefore, the lower the amount of sulfur contained in the fuel, the lower the
resulting emissions will be when the fuel is burned. Natural gas contains very little
sulfur and, consequently, a very small amount of SO2 is emitted from a gas-fired
boiler. Fuel oils contain varying amounts of sulfur in the oil. The heavier oils usually
contain more sulfur than do the lighter oils. SO2 emissions resulting from burning coal
will depend on the amount of sulfur contained in the coal. Low sulfur western coal
usually has a sulfur content of less than 1 % whereas some high sulfur eastern coals
contain between 3 and 6% sulfur. The higher the sulfur content in the coal, the
larger the amount of SO2 emitted. Emission factors used to estimate SO2 emissions
from boilers are listed hi Appendix A.
Nitrogen Oxide
When fossil fuels are burned in a furnace, nitrogen oxides (NO*) are formed by two
processes. In the first, the nitrogen and oxygen contained in the combustion air react
at the high temperatures hi the furnace to form nitrogen oxide (NO). In the second,
the nitrogen compounds contained in the fuel are oxidized to form NO. The impor-
tant factors that affect the formation of nitrogen oxides are: flame and furnace
temperature, residence time that the combustion products are at the flame
temperature, the nitrogen and oxygen content of the combustion air, and the
nitrogen content of the fuel that is burned. In large boilers, approximately 95% of
the NO* is in the form of NO, the remainder is nitrogen dioxide (NO2).
In boilers, nitrogen oxide emissions will vary depending on the fuel burned. If
coal is burned, NO* emissions will be high because coal has a high percentage of
6-2
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nitrogen and the temperature of the flame is high. For fuel oil, the NOr emissions
will vary depending on how much nitrogen is contained in the fuel oil and also on
the conditions in the furnace. NO* emissions from gas-fired boilers occur mainly
because of the high temperatures in the furnace since natural gas contains very little
nitrogen. Emission factors used to estimate nitrogen oxide emissions from boilers are
listed in Appendix A.
Carbon Monoxide
Carbon monoxide (CO) is formed as a result of the incomplete combustion of the
fuel (see Lesson 2). If the boiler is operated properly, the CO emissions will be
relatively low regardless of the fuel that is burned.
Emission Regulations*
The Federal government has set standards for pollutant levels in the ambient air.
These standards, known as the National Ambient Air Quality Standards (NAAQS),
are specified for the following pollutants: sulfur dioxide (SO2), carbon monoxide
(CO), ozone (O3), nitrogen dioxide (NO*), paniculate matter, and lead. In order
that these ambient standards can be attained, industrial source emission standards
have also been set. State and local air pollution control agencies have adopted
regulations to limit the pollutant concentration that can be emitted. The Federal
government has set New Source Performance Standards (NSPS) for industrial
sources. Two NSPS for boilers have been promulgated, and a third should be
promulgated in late 1985.
New Source Performance Standards
for Fossil Fuel-Fired Steam Generators
EPA has promulgated NSPS for fossil fuel-fired steam generators (FFFSG) with heat
input greater than 73 MW (250 x 106 Btu/hr). These standards establish paniculate,
sulfur dioxide, and nitrogen oxide emission limits for steam generators whose "con-
struction commenced" after August 17, 1971 (Table 6-1). This standard is covered
under Subpart D, Pan 60, Code of Federal Regulations. The Code of Federal
Regulations defines a fossil fuel-fired steam generator as a furnace or boiler used in
the process of burning fossil fuel (natural gas, oil, coal, or wood) for the purpose of
producing steam by heat transfer. This NSPS covers both utility and industrial
boilers rated greater than 73 MW (250 x 10s Btu/hr heat input). The term "con-
struction commenced" is defined in the Clean Air Act and does not necessarily mean
that actual physical construction was initiated. It may be interpreted as the date that
a permit is initiated at the air pollution control agency.
'The majority of the following sections are adapted from Beachler and Joseph, February, 1984.
6-3
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Emission monitoring requirements are also given in Table 6-1. Continuous emis-
sion monitors for monitoring opacity, SO2, and NOr emissions are required for all
fossil fuel-fired steam generators rated greater than 73 MW (250 X 106 Btu/hr heat
input) installed after August 17, 1971. EPA has proposed an amendment to Subpart
D to allow fuel sampling or manual stack sampling (modified EPA Method 6) to be
used in place of continuous SO2 emission monitors.
Table 6-1. New Source Performance Standards for fossil fuel-fired steam
generators rated greater than 73 MW (250 x 1Q* Btu/hr heat
input). Subpart D, new sources installed after August 17, 1971.
Emissions
Paniculate*
SO,
NO,
Metric units
(ng/J)
43
340
520
86
130
300
English units
(lb/10§ Btu)
0.1
0.8
1.2
0.2
0.3
0.7
Fuel
Gas, liquid, solid
Liquid (oil)
Solid (coal)
Gas
Liquid (oil)
Solid (except lignite)
'Opacity is not to exceed 20% for periods over six minutes in one
hour, and opacity is never to exceed 27% (for burning all fuels).
Emission
monitoring
requirement
—
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Note: For utility boilers, this standard applies to boilers installed after August 17,
1971 but before September 18, 1978.
New Source Performance Standards
for Electric Utility Steam Generators
EPA promulgated NSPS for electric utility steam generators with heat input greater
than 73 MW (250 X 10s Btu/hr) for which construction commenced after September
18, 1978 (Table 6-2). This standard is covered under Subpart Da, Part 60, Code of
Federal Regulations. The Code of Federal Regulations defines electric utility steam
generating unit as any steam generator that is constructed for the purpose of supply-
ing more than one-third potential electric capacity and more than 25 MW electrical
output to any utility power distribution system for sale. This standard is more strin-
gent than Subpart D and applies only to utility steam generators.
6-4
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Table 6-2. New Source Performance Standards for fossil fuel-fired steam generators
rated greater than 73 MW (250 x 10* Btu/hr heat input). Subpart
Da, new sources installed after September 18, 1978.
Emissions
Paniculate*
SO,
NO,
Metric units
250x 106 Btu/hr) cannot have SO2 emissions
exceeding 1.2 lb/106 Btu. In addition, the plant is required to reduce the SO2 emis-
6-5
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sions by 90%. If the plant's emissions are less than 0.6 lb/106 Btu, then only 70%
scrubbing is required. It is possible that the SO2 emissions will fall between 0.6 and
1.2 lb/106 Btu. In this case, 90% scrubbing is required. It is also possible to meet
the NSPS standard by scrubbing 85% if, and only if, the plant's emissions do not
exceed 0.6 lb/106 Btu. A useful graphical representation of the 1978 NSPS for sulfur
dioxide emission limitations from fossil fuel-fired steam generators (utility boilers) is
shown in Figure 6-1.
_o
**
u
•a
O
S/5
w
U
u
I
90
80
70
1.2 Ibs SO,/108 Btu
0.6 Ibs SOi/10" Btu
I I I
t L 1 t
0
2 4 6 8 10 12 14 16
18 20
Uncontrolled SOj emissions (Ib SOj/lO" Btu)
I |
0
i t i I i i
2
i t i I 1 i 1 I I i i I
468
i 1 1
10
Sulfur content of fuel (Ibs/10" Btu)
Source: Beachler and Joseph, 1984.
Fisrure 6-1. 1978 NSPS for utility boilers—required
SOt reduction.
A number of economic and energy impacts were considered when EPA decided to
set this NSPS standard. One factor that made the variable 70 to 90% control rule
attractive was the encouragement to use control technology such as dry FGD
scrubbing that can easily remove 70% of SO2 emissions from flue gas. Another fac-
tor was that the rule would encourage the use of locally-available coal and would not
create an economic incentive for burning low-sulfur western coal (Costle, 1977).
Emission monitoring requirements were also given in Table 6-2. Continuous emis-
sion monitors for monitoring opacity, SO2, and NO* emissions are required for all
fossil fuel-fired steam generators rated greater than 73 MW (250 x 106 Btu/hr)
installed after September 18, 1978.
6-6
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Proposed New Source Performance Standards
for Industrial Boilers
Proposed New Source Performance Standards for industrial boilers were published in
the Federal Register on June 19, 1984. The proposed NSPS affects boilers with a
heat input capacity of greater than 29 MW (100 X 106 Btu/hr). The draft was
published as Subpart Db, Part 60, Code of Federal Regulations. The proposed
regulations establish limits for paniculate and NO* emissions from industrial boilers
firing coal, oil, natural gas, wood, or solid waste. The proposed emission limits
supersede the paniculate and NO* standards given hi Subpart D for industrial
boilers greater than 73 MW (250 x 106 Btu/hr) heat input. The changes to Subpart
D would not be retroactive, and these changes would only apply to new industrial
boilers that are "constructed" after June 19, 1984.
There are no SO2 emission limits included in the proposed standard. The pro-
posed standard does not revise the SO2 emission limits given in Subpart D for
industrial boilers greater than 73 MW (250 X 106 Btu/hr). SO2 emission limits given
hi Subpart D still apply. A proposed standard for limiting SO2 emissions from
industrial boilers is being worked on by the EPA staff, with a projected proposal
date of 1985.
Air Pollution Control Equipment
Particulate Emissions Control
Paniculate emissions are controlled by using cyclones, wet scrubbers, electrostatic
precipitators (ESPs), and fabric filters (baghouses). Cyclones are generally used to
remove particles larger than 10 /on in diameter. These devices are occasionally used
before wet scrubbers, ESPs, or baghouses to remove large particles. Wet scrubbers
are generally used when both participate and SO2 emission reduction is desired.
Electrostatic precipitators have been used to reduce particulate emissions from
boiler flue gas for over 50 years. ESPs have been designed to remove particles with at
least 99.5% efficiency. ESPs used on boiler exhaust generally contain discharge elec-
trodes and collection plates. The discharge electrodes are either long thin wires or
wires attached together in rigid frames. Discharge electrodes create a strong electric
field that ionizes flue gas as it passes through the ESP. This ionization charges the
particles in the flue gas. Charged particles migrate to and are collected on oppositely
charged collection plates. Cold-side ESPs are located behind the combustion air
preheaters where the flue gas temperatures are approximately 400 °F or less. Hot-side
ESPs are located in front of air preheaters and are used to clean flue gas having
temperatures greater than 572 °F. One problem in using ESPs occurs when low-sulfur
coal is burned in a boiler. The resulting fly ash has high resistivity and is difficult to
collect. Hot-side ESPs were popular in the early 1970's for removing fly ash having
high resistivity. However, many of these hot-side ESPs did not operate reliably, and
vendors recently favor the use of cold-side ESPs and conditioning agents. Some of
6-7
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these conditioning agents include sulfur trioxide, sulfuric acid, ammonia, sodium
chloride, or soda ash. ESPs are covered in detail in APTI Course 412B Electrostatic
Precipitator Plan Review (EPA 450/2-82-019).
Baghouses have been used to remove fly ash from flue gas at over 100 industrial
and utility boiler installations in the U.S. Reports have shown that baghouses used
on pulverized-coal-fired utility boilers are routinely capable of achieving collection
efficiencies of 99.9%, stack opacities well below 5%, and outlet concentrations of
0.005 lb/106 Btu (Carr and Smith, 1984). The collection efficiency for baghouses
used on industrial coal-fired boilers has been equally high.
Baghouses are located downstream of air preheaters where the flue gas
temperatures are typically 300 to 350 °F. Baghouses contain long cylindrical bags
made with fabric material. Bags hang vertically in the baghouse and filter dust on
the outside or inside of the bag, depending on the baghouse design and purpose.
The flue gas temperature in the baghouse must be carefully controlled and must be
high enough to prevent water or acid from condensing in the baghouse. However,
the temperature must be low enough (< 500 °F) to keep the fabric material from
deteriorating. Many baghouses use bags made of fiberglass that are coated with
Teflon®, silicone, or graphite either singly or in combination. Other materials such
as Teflon®, Ryton®, and acrylics have been used. Utility-boiler baghouses almost
always contain fiberglass bags and use reverse air cleaning or shake and deflate
cleaning. Industrial-boiler baghouses contain bags made with fiberglass, Teflon®,
Nomex®, and Ryton®, and they clean dirty bags by reverse air, shaking, and pulse
jet techniques. Baghouses are covered in detail in APTI Course 412B Baghouse Plan
Review (EPA 450/2-82-005).
The required emission reduction efficiencies for meeting the various NSPS emis-
sion levels for paniculate matter are given in Table 6-3. Baghouses and electrostatic
precipitators are the most popular paniculate emission control devices used to meet
the NSPS (for paniculate matter) on coal-fired boilers because they are generally the
only devices that can consistently meet the 0.03 lb/106 Btu emission limitations. Wet
scrubbers are also used, but usually only when SO2 emission control (FGD systems) is
required. A summary of paniculate matter control devices used to develop the pro-
posed industrial boiler NSPS emission limits is given in Table 6-4.
6-8
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Table 6-3. Required efficiencies to achieve NSPS control levels
for paniculate emissions.
Boiler type
and fuel
Pulverized coal'*
Spreader stoker*
Chain grate stoker*
Underfeed stoker*
Residual oil"
Distillate oil*
Natural gasc
Fuel
analysis
% ash
5 to 11
5 to 11
5 to 11
5 to 11
3% sulfur
1% ash
0.5% sulfur
—
Uncontrolled
emissions
ng/J
db/10' Btu)
1522 to 3350
(3.54 to 7.79)
1165 to 2563
(2.71 to 5.96)
447 to 985
(1.04 to 2.29)
224 to 490
(0.52 to 1.14)
96
(0.223)
6.3
(0.0146)
0.34 to 6.45
(0.0008 to 0.015)
Efficiency required at the given emission limit (%)
43 ng/J
(0.1 lb/10' Btu)
97.18 to 98.72
96.31 to 98.32
90.38 to 95.63
80.77 to 91.23
55.16
—
—
21.5 ng/J
(0.05 lb/10' Btu)
98.59 to 99.34
98.16 to 99.16
95.19 to 97.82
90.38 to 95.61
77.58
—
—
13 ng/J
(0.03 lb/10« Btu)
99.15 to 99.62
98.89 to 99.50
97.12 to 98.69
94.23 to 97.37
86.55
—
—
•*Reference AP-42 expresses emissions on a kg/MT (Ib/ton) of fuel burned basis. A conversion factor of
kj/kg (12,000 Btu/lb) was used.
"Reference AP-42 expresses emissions on a kg/1000 t (lb/1000 gal) of fuel burned basis. Conversion factors
of 43,043 kj/kg (18,500 Btu/lb) and 45,345 kj/kg (19,500 Btu/lb) were used to convert factors to a
heat input basis for residual and distillate oil respectively. Densities of 0.96 kg/? (8.0 Ib/gal) and
0.84 kg/f (7.0 Ib/gal) were also used.
cReference AP-42 expresses emissions on a kg/10* m1 (lb/10* ft3) of fuel burned basis. A conversion
factor of 50,707 kj/kg (21,800 Btu/lb) and a density of 0.722 kg/ms (0.0451 lb/ft3) were used.
Table 6-4. Summary of paniculate matter control devices to meet the
proposed NSPS emission limits.
Fuel
Coal
Coal equipped with wet
scrubbing FGD systems
Wood
Solid waste
Fuel mixtures containing
above fuels
Basis of
proposed standard
Fabric filter/ESP
Wet scrubber
ESP/wet scrubber
ESP
ESP/ wet scrubber
Proposed emission limits
ng/J (Ib/million Btu) heat input
ng/J
21.5
43
43
43
43
lb/106 Btu
0.05
0.10
0.10
0.10
0.10
Opacity
20%
20%
20%
20%
20%
6-9
-------
Sulfur Dioxide Control
Sulfur dioxides (SO2) are emitted from coal-fired and oil-fired boilers burning fuels
that contain sulfur. SO2 emissions have been controlled by both wet and dry
scrubbing. These are usually called flue gas desulfurization (FGD) processes. The two
most popular wet scrubbing methods are lime and limestone scrubbing. Approx-
imately 75% of all installed FGD systems use a lime or limestone slurry as the
scrubbing liquor. Here SO2 reacts with the lime or limestone slurry to form calcium
sulfite and calcium sulfate sludge. The sludge must be disposed of in a pond or
landfill. Other wet scrubbing systems include the Dual Alkali, Wellman-Lord, and
Magnesium Oxide processes. Most wet scrubbing FGD systems are capable of reduc-
ing SO2 emissions by 90%. Therefore, these wet FGD systems can usually be used to
meet the SO2 emission reduction requirements for the NSPS (Subpart Da).
In dry FGD scrubbing, an alkaline slurry is injected in a spray dryer with dry par-
ticle collection in a baghouse or electrostatic precipitator. Spray dryers are vessels
where hot flue gases are contacted with a fine, wet, alkaline spray. SO2 emissions are
sorbed by the alkaline spray. The high temperature of the flue gas, 250 to 400 °F,
evaporates the moisture from the alkaline spray, leaving a dry product. The dry
product is collected in a baghouse or ESP. Dry scrubbing FGD systems can remove
approximately 75 to 90% of the SO2 emissions.
EPA-AEERL is currently working on a promising technology called Limestone
Injection Multistage Burner (LIMB). In this process, limestone is injected with
pulverized coal and burned in a multistage low NO* burner. Current studies indicate
an SO2 reduction of 50% is possible with a limestone stoichiometric ratio of 2.0.
Sulfur oxides can also be reduced by coal cleaning or by using synthetic fuels.
Coal can be cleaned by using physical and chemical coal cleaning methods. Mineral
sulfur can be removed by physical methods in which coal is crushed, washed, and
then separated by settling processes using cyclones, air classifiers, or magnetic
separators. Organic-bound sulfur can be removed by chemical methods such as
microwave desulfurization and hydrothermal desulfurization. The Air and Energy
Engineering Research Laboratory (AEERL), formerly the Industrial Environmental
Research Laboratory (IERL), of the EPA is currently involved in research of these
technologies. Coal can also be gasified or liquefied into "cleaner" synthetic fuels.
Commercial operation of synthetic fuel facilities is expected in the mid 1980's or
early 1990's. Sulfur dioxide emission reduction is covered in detail in APTI Course
412C, Wet Scrubber Plan Review (EPA 450/2-82-020).
Nitrogen Oxide Control
Nitrogen oxides are emitted from gas-, oil-, and coal-fired boilers. These emissions
can be reduced by two control methods: combustion modifications and flue gas
treatment. Combustion modifications are changes made in the operation and design
of the furnace. Some of the more widely used combustion modification techniques
include the use of low excess air, staged combustion, flue gas recirculation, and low-
NOX burners. These combustion modifications are done to alter the combustion con-
ditions in the furnace. This can be accomplished by:
6-10
-------
• reducing the peak flame temperature,
• reducing the residence time the combustion products remain in the chamber,
• diverting approximately 15% of the fuel further downstream in the combustion
chamber to achieve "reburning,"
• changing the mixing rate of the fuel and air, or
• increasing the temperature and residence time in precombustor chamber.
NO* emissions can be reduced from 10 to 40% depending on the fuel burned and
the combustion conditions in the furnace. Combustion modification techniques can
usually be used to meet all of the NSPS NO* emission limits (Subparts D, Da,
and Db).
Nitrogen oxide emissions can also be reduced by treating the flue gas after it
leaves the combustion zone. This technique can be used when there is a need to
reduce NO, emissions to very low levels, such as the NOX emission reduction from
utility boilers now required by the South Coast Air Quality Management District in
California. However, flue gas treatment is not required to meet any of the NSPS
standards for industrial or utility boilers.
Flue gas treatment methods include the Exxon Thermal De-NOT, Selective
Catalytic Reduction (SCR), and the Shell UOP processes. These processes have been
used in Japan to reduce NOZ emissions from utility boilers. Pilot projects are cur-
rently being tested hi the United States at a number of utilities. Full scale units are
expected to be installed in the next few years. The Exxon process has reduced NO*
emissions by 60%, and the SCR and Shell UOP processes have reduced NO* emis-
sions by 90%. Nitrogen oxide emission reduction techniques are covered in detail in
APTI Course 415, Control of Gaseous Emissions (EPA 450/2-81-005).
Summary
Industrial and utility boilers can emit significant amounts of air pollutants into the
atmosphere. Air pollution regulations have been developed to limit the amount of
pollution that can be emitted. Regulations such as the NSPS have been one tool
used to help improve and maintain air quality. Major efforts by industry to develop
and install air pollution control devices to meet air pollution regulations will help
our society in its continual struggle for protecting the quality of air we breathe.
6-11
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Review Exercise
1. True or False? The amount of paniculate emissions from
coal-fired boilers depend on the way the coal is burned in
the furnace.
2. In a boiler,
is emitted when the
1. True
in the fuel is oxidized; while
the in the fuel is oxidized and the
in the air is burned.
is emitted when
3. The 1971 NSPS was promulgated to regulate emissions
from
a. electric utility boilers greater than 73 MW.
b. industrial boilers greater than 73 MW.
c. electric utility and industrial boilers greater than
73 MW.
d. electric utility and industrial boilers less than 73 MW.
sulfur dioxide,
sulfur,
nitrogen oxide,
nitrogen,
nitrogen
4. The 1978 NSPS was promulgated to regulate emissions
from
a. electric utility and industrial boilers greater than
73 MW.
b. industrial boilers greater than 29 MW.
c. electric utility boilers greater than 73 MW.
d. electric utility boilers greater than 29 MW.
3. c. electric utility
and industrial
boilers greater
than 73 MW.
5. The 1978 NSPS for electric utility boilers requires
a. 90% SO2 emission reduction and SO2 emissions less
than 1.2 lb/106 Btu.
b. 70% SO2 emission reduction and SO2 emissions less
0.6 lb/106 Btu.
c. a sliding scale of from 70% to 90% as long as SO2
emissions after control are less than 0.6 lb/106 Btu.
d. all of the above
e. a. and b. only
4. c. electric utility
boilers greater
than 73 MW.
6. Boilers burning low-sulfur coal produce fly ash having
high resistivity which is difficult to collect using a
a. baghouse.
b. electrostatic precipitator.
c. wet scrubber.
d. dry scrubber.
5. d. all of the
above
6. b. electrostatic
precipitator.
6-12
-------
7. Because of high temperature flue gas from utility
boilers, baghouses used on them contain
a. coated wool bags.
b. uncoated cotton bags.
c. coated fiberglass bags.
d. all of the above
8. Most FGD installations use
emissions.
to reduce SO2
a. dual alkali and magnesium oxide scrubbing
b. lime and limestone scrubbing
c. the Wellman-Lord process
d. dry scrubbing
7. c. coated
fiberglass bags.
Combustion modification techniques are used to reduce
nitrogen oxide emissions from boilers. These include
a. low excess air.
b. staged combustion.
c. flue gas recirculation.
d. low NO* burners.
e. all of the above
f. none of the above
8.
b. lime and
limestone
scrubbing
9. e. all of the
above
References
Beachler, D. S. and Joseph, G. T. 1984. Emission Regulations and Air Pollution
Control Equipment for Industrial and Utility Boilers. Environmental Progress
(Vol. 3, No. 1).
Beachler, D. S. 1983. Electrostatic Precipitator Plan Review—Self-instructional
Guidebook. APTI Course SI:412B, EPA 450/2-82-019.
Beachler, D. S.; Jahnke, J. A.; Joseph, G. T.; and Peterson, M. M. 1983. Air Pollu-
tion Control Systems for Selected Industries—Self-instructional Guidebook. APTI
Course SI:431, 450/2-82-006.
Beachler, D. S. and Peterson, M. M. 1982. Baghouse Plan Review—Student
Guidebook. APTI Course SI:412A, EPA 450/2-82-005.
Beachler, D. S. and Jahnke, J. A. 1981. Control of Particulate Emissions—Student
Manual. APTI Course 413, EPA 450/2-80-066.
6-13
-------
Buroff, J. et al. Technology Assessment Report for Industrial Boiler Applications:
Coal Cleaning and Low Sulfur Coal. Environmental Protection Agency (EPA).
EPA 600/7-79-178c.
Carr, R. C. and Smith, W. B. January, 1984. Fabric Filter Technology for Utility
Coal-Fired Power Plants. Part I: Utility Baghouse Design and Operation. Journal
of Air Pollution Control Association. 34:79-89.
Carr, R. C. and Smith, W. B. February, 1984. Fabric Filter Technology for Utility
Coal-Fired Power Plants. Part II: Application of Baghouse Technology in the
Electric Utility Industry. Journal of the Air Pollution Control Association.
34:178-184.
Costle, D. M. New Source Performance Standards for Coal-Fired Power Plants.
Journal of the Air Pollution Control Association. 29:690-692.
Environmental Protection Agency (EPA). August, 1980. Controlling Sulfur Oxides.
EPA 600/8-80-029.
Environmental Protection Agency (EPA). July, 1978. Electric Utility Steam Genera-
ting Units. Background Information for Proposed Particulate Matter Emission
Standards. EPA 450/2-78-006a.
Environmental Protection Agency (EPA). February, 1980. Controlling Nitrogen
Oxides. EPA 600/8-80-004.
Environmental Protection Agency (EPA). Compilation of Air Pollution Emission
Factors. AP-42.
Environmental Protection Agency (EPA). April 23, 1982. Draft—Proposed Rule
and Notice of Public Hearing for Standards of Performance for New Stationary
Sources—Industrial Boilers.
Joseph, G. T. and Beachler, D. S. 1984. Wet Scrubber Plan Review—Self-instruc-
tional Guidebook. APTI Course SI:412C, EPA 450/2-82-020.
Joseph, G. T. and Beachler, D. S. 1982. Control of Gaseous Emissions—Student
Manual. APTI Course 415, EPA 450/2-81-005.
Roeck, D. R. and Dennis, R. December, 1979. Technology Assessment Report for
Industrial Boiler Applications: Particulate Collection. Environmental Protection
Agency (EPA). EPA 600/7-79-178h.
U.S. Code of Federal Regulations. 40 Protection of Environment. Parts 53 to 80.
Revised as of July 1, 1981.
6-14
-------
Appendix A
(The following pages are excerpts from AP-42
which relate to combustion sources)
COMPILATION
OF
AIR POLLUTANT EMISSION FACTORS
Third Edition
(Including Supplements 1-7)
U.S. Environmental Protection Agency
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1977
A-l
-------
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, cur-
rent 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
A-2
-------
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 an 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 10* MT) of coal, 623 million barrels (99 x 10' liters) of distillate fuel oil, 715 million barrels (114 x
10* liters) of residual fuel oil, and 22 trillion cubic feet (623 x 1012 liters) of natural_gas were, consumed in the
United States.'
Power generation, process heating, and space heating are some of the largest fuel-combustion sources of sulfur
oxides, nitrogen oxides, and paniculate 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. Adcerson, 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 puiverized-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
1.1.2.1 Particulates1 • Particulates emitted from coal combustion consist primarily of carbon, silica, alumina, and
iron oxide in the fly-ash. The quantity of atmospheric paniculate 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
A-3
-------
Table 1.1-1 gives the range of collection efficiencies for common types of fly-ash control equipment. Particulate
emission factors expressed as pounds of paniculate 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 WeUman-Lord process. Detailed discussion of various
flue-gas desulfurization processes may be found in the literature.12-13
1.1.13. Nitrogen Oxides1*3 • Emissions of oxides of nitrogen result not only from the high temperature reaction
of atmospheric nitrogen and oxygen in the combustion zone, but also from the partial combustion of nitrogenous
compounds contained in the fuel The important factors that affect NOX production are: flame and furnace
temperature, residence time of combustion gases at the flame temperature, rate of cooling of the gases, and
amount of excess air present in the flame. Discussions of the mechanisms involved are contained in the indicated
references.
1.1.14 Other Gases • The efficiency of combustion primarily determines the carbon monoxide and hydrocarbon
content of the gases emitted from bituminous coal combustion. Successful combustion that results in a low level
of carbon monoxide and organic emissions requires a high degree of turbulence, a high temperature, and
sufficient time for the combustion reaction to take place. Thus, careful control of excess air rates, the use of high
combustion temperature, and provision for intimate fuel-air contact will minimize these emissions.
Factors for these gaseous emissions are also presented in Table 1.1-2. The size range in.Btu per hour for the
various types of furnaces as shown in Table 1.1-2 is only provided as a guide in selecting the proper factor and is
not meant to distinguish clearly between furnace applications.
TABLE 1.1-1. RANGE OF COLLECTION EFFICIENCIES FOR COMMON TYPES
OF FLY-ASH CONTROL EQUIPMENT"
Type of
furnaca
Cyclone furnaca
Pulverized unit
Spreader stoker
Other stokers
Range of collection efficiencies, %
Electrostatic
precipitator
65 to 99.5s
80 to 99.5s '
99.5"
99.5*
High-
efficiency
cyclone
30 to 40
65 to 75
as to so
90 to 95
Low-
resJstanca
cyclone
20 to 30
40 to 60
70 to 80
75 to 85
Settling
chamber ax-
panded chimney
bases
10"
20"
20 to 30
25 to 50
1 and 2.
maximum «ff ic»ncy to b« «xp«etnj for ths collection dwiot applied to thii rypa jourc*.
EMISSION FACTORS
4/73
A-4
-------
Table 1.1-2. EMISSION FACTORS FOR BITUMINOUS COAL COMBUSTION WITHOUT CONTROL EQUIPMENT
EMISSION FACTOR RATING: A
>
c!n
Furnace sue,
106 Btu/hr
heat input*
Greater than 100*
(Utility and large
industrial boilers)
Pulverized
General
Wet bottom
Dry bottom
Cyclone
10 to 100" (large
commercial and
general industrial
boilers)
Spreader stoker1*
Less than 10'
(commercial and
domestic furnaces)
Underfeed stoker
Hand-fired units
Paniculate**1
Ib/ton
coal
burned
I6A
13A1
17A
2A
13A4
2A
20
kg/MT
coal
burned
8A
6.5A
B.5A
1A
6.5A
1A
10
Sulfur
oxides6
Ib/ton
coal
burned
38S
38S
38S
3 8S
38S
38S
38S
kg/MT
coal
burned
IBS
IBS
IBS
IBS
IBS
IBS
IBS
Carbon
monoxide
Ib/ton
coal
burned
1
1
1
1
2
10
BO
kg/MT
coal
burned
0.5
0.5
0.6
0.6
1
6
45
Hydro-
carbons'1
Ib/ton
coal
burned
0.3
0.3
0.3
0.3
1
3
20
kg/MT
coal
burned
0.15
0.16
0.15
0.16
0.5
1.6
10
Nitrogen
oxides
Ib/ton
coal
burned
18
30
18
65
15
6
3
kg/MT
coal
burned
B
16
fi
27.6
7.6
3
1.6
Aldehydes
Ib/lon
coal
burned
0.005
0.005
0.005
0.005
0.005
0.005
0.005
kg/MT
coal
burned
0.0025
0.0025
0.0025
0.0025
0.0025
0.0025
0.0025
•t Blu/hr- 0.262 kcal/hr.
"Tha letter A on all unit* other then hand-fired equipment indicaiai that the weight percentage ol ash in the coal ihould be multiplied by the value giuen.
Example: II lha factor It 16 and the aih content it 10 percent, the paniculate emission! before the control equipment would be 10 limet 16. or 160
poundi ol paniculate per lonol coal (10 timaiB. or 80 kg ol paniculate* per MT of coal).
CS equalt the tulfur content (Me footnote b above).
"ExpJMjed at methane.
*Ral«rencet 1 and 3 through 7.
'without lly-ath reinjection.
ORelerencei 1,4. and 7 through 9.
f'For all other itokert uta 6A for paniculate emistion (actor.
| Without fly-ath reinjaclion. With fly-ath reinfection uta 20 A. Thu value it not en emiuion factor but reprcwnu loading reaching tha control equipment'
!Referencai7.fl, and 10.
-------
References for Section 1.1
1. Smith. W. S. Atmospheric Emissions from Coal Combustion. U.S. DHEW. PHS. National Center tor Air
Pollution Control. Cincinnati, Ohio. PHS Publication Number 999-AP-24. April 1966.
2. Control Techniques for Paniculate Air Pollutants. U.S. DHEW, PHS, EHS, National Air Pollution Control
Administration Washington. D.C. Publication Number AP-51. January 1969.
3. Perry, H. and J. H. Field Air Pollution and the Coal Industry. Transactions of the Society of Mining
Engineers. 238:337-345, December 1967.
4. Heller, A, W. and D. F. Walters. Impact of Changing Patterns of Energy Use on Community Air Quality. J.
Air Poi. 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 Poilution 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. 14:267-219,
July 1964.
S. Hovey, H. H., A. Risman, and J. F. Cunnan. The Development of Air Contaminant Emission Tables for
Nonprocess Emissions. J. Air Pol. Control Assoc. 7<5:362-366, July 1966.
9. Anderson, D. M., J. Lieben, and V. H, Sussman. Pure Air for Pennsylvania. Pennsylvania Department of
Health. Hanisburg, Pi November 1961. p. 91-95.
10. Communication with National Coal Association. Washington, D. C. September 1969.
11. Private communication with RJD. Stem, Control Systems Division, Environmental Protection Agency.
Research Triangle Park, N.C June 21, 1972.
11 Control Techniques for Sulfur Oxide Air PoQutants. U.S. DHEW, PHS, EHS, National Air Pollution Control
Administration. Washington, D.C. Publication Number AP-52. January 1969. p. xviii and xxii.
13. Air Pollution Aspects of Emission Sources: Electric Power Production. Environmental Protection Agency,
Office of Air Programs. Research Triangle Park, N.C. Publication Number AP-96. May 1971.
EMISSION FACTORS 4/76
A-6
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1.2 ANTHRACITE COAL COMBUSTION revised by Turn Uhre
1.2.1 General1^
Anthracite i> a high-rank coal having a high fixed-carbon content and low volatile-matter content
relative to bituminoua coal and lignite. It is also characterized by higher ignition and ash fusion tem-
perature*. Because of its low volatile-matter content and non-clinkering characteristics, anthracite is
most commonly fired in medium-sized traveling-grate stokers and small hand-fired units. Some an-
thracite (occasionally along with petroleum coke) is fired in pulverized-coal-fired boilers. None is fired
in spreader stokers. Because of its low sulfur content (typically lesa than 0.3 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 Emission* and Controls3-4
Particulate emissions from anthracite combustion are a function of furnace-firing configuration,
firing practices (boiler load, quantity and location of underfire air, soot fa lowing, flyash reinjection,
etc.), as well as of the ash content of the coaL Pulverized-coal-fired boilers emit the highest quantity of
particulate per unit of fuel because they fire the anthracite in suspension, which results in a high per-
centage of ash carryover into the exhaust gases. Traveling-grate stokers and hand-fired units, on the
other hand, produce much lesa particulate per unit of fuel fired. This is because combustion takes
place in a quiescent fuel .bed and does not cesult 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 bituminoua 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 lesa than that of bituminoua 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 gaa 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 itack. Cyclone collectors have been employed on traveling-grate stokers;
4/77 External Combustion Sources
A-7
-------
limited information «uggesti these devices may be up to 75 percent efficient on particuiate. Flyash rein-
jectioo, frequently employed in traveling-grate ftokers to enhance fuel-use efficiency, tends to in-
cre**« particulate emiasionj per unit of fuel combusted.
Emiuion factors for anthracite combuition are presented in Table 1.2-1.
EMISSION FACTORS 4/77
A-8
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Table 1.2-1. EMISSION FACTORS FOR ANTHRACITE COMBUSTION. BEFORE CONTROLS
EMISSION FACTOR RATING: B
M
X
r+
n
3
n
o
tr
c
o
0
tfl
o
e
n
u
Type of furnace
Pulverized coal
Traveling grata
Hand-fired
Emissions'
Paniculate
Ib/ton
17 A1
1AO
toh
kg/MT
8.6A*
O.BAfl
Bh
Sulfur oxides'*
Ib/ton
3BS
38S
38S
kg/MT
19S
ies
IBS
Hydrocarbons0
Ib/lon
Neg
Meg
2.6
kg/MT
Neg
Neg
1.25
Carbon
monoxide"
Ib/ton
1
1
90
kg/MT
0.6
0.6
46
Nitrogen
oxides6
Ib/ton
18
10
3
kg/MT
9
6
1.5
*AII emlwion factor* are per unit of anthracite fired.
Uciori u e beied on the assumption thil, 11 with biluminoui coal combustion. moil of the fuel lulfur it emitted ai tulfur oxide*. Limited data in
Refer *nc* 6 verify ihli assumption for pulvariied-anlhracita-fired boiler*. Generally moil of Ihete eminioni are tullur dioxide; however, approximately
1 to 3 percent are tullur irioxide.
'Hydrocarbon emission! from anthracite combuition ere auumed to be lower than from bilumlnou* coal combuilion becauM of anthracite'* much lower
volatile-mailer content. No emiuioni dale are available lo verify Ihi* auumpllon.
'•The carbon monoxide f acton for pulverized-anlhracite-fired boilart and hand-tired uniti are from Table 1.1-2.and are bated on the similarity between
anthracite and biluminoui coal combuilion. The pulverixed-coal-fired boileri factor It tubiiantiaiad by additional data in Reference 10. The factor
for irevellng-grala noken it bated on limited information In Reference 8. Carbon monoxide emiwioni may increate by teveral orders of magnitude it
e boiler ii not properly operated or well maintained.
*The nitrogen oxide tactori for pulveriied-anlhracite-fired boilers and hand-fired unili are aiiumed to be limilar to thote for biluminoui coal combui-
lion given in Table 1.1-2. The laclori for traveling-iiraie ilpkeri are baled on Reference 8.
Th«te laciort are bated on the timilarity between enihracite and biluminoui coal combuilion and on limited data in Reference 6. Note that all pulveriied-
anihraciie-fimd boileri operate in the dry lap or dry bottom mode due to anlhracile'i characieritiically high ath-lution temperature. The letter A on unili
other than hand-lired equipment indicate! that the weight percentage of aih in the coal thould be multiplied by the value given.
BBatad on in'ornrmlion in Reference! 2.4.8. and 8. Thute taciori account for limited fallout that may occur in fallout chamber* end Hack bi ettching.
Emiuion laciort lor Individual boileri may vary from 0.6A Ib/lon (0.26A kg/MT) to 3A Ib/lon (1.5A kg/MTl. and a* high us 6A Ib/lon 12.6A kg/MTI
during tool blowing.
Bated on limited inlormallon in Ruference 2.
-------
References for Section 1.2
1. Coal—Pennsylvania Anthracite in 1974. Mineral Industry Surveys. U.S. Department of the In-
terior. Bureau of Mines. Washington, D.C
2. Air Pollutant Emission Factors. Resources Research, Inc., TRW Systems Group. Reston. Virginia.
Prepared for the National Air Pollution Control Administration, U.S. Department of Health, Ed-
ucation, and Welfare, Washington, D.C, under Contract No. CPA 22-69-119. April 1970. p. 2-2
through 2-19.
3. Steam—Its Generation and Use. 37th Edition. The Babcock & Wilcox Company. New York, N.Y.
1963. p. 16-1 through 16-10.
4. Information Supplied By J.K. Hambright, Bureau of Air Quality and Noise Control. Pennsyl-
vania Department of Environmental Resources. Harris burg, Pennsylvania. July 9, 1976.
5. CAM, R.W. and R.M. Broadway. Fractional Efficiency of a Utility Boiler Baghouse: Sunbury
Steam-Electric Station—OCA 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. Baghouae Dust Collectors On A Low Sulfur Coal Fired Utility Boiler. Present-
ed at the 67th Annual Meeting ot 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
-------
1.3 FUEL OIL COMBUSTION by Turn Lah
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 typ« and size
of the boiler, the firing and loading practices used, and the level of equipment maintenance. Table 1.3-1 presents
emission factors for fuel oil combustion in units without control equipment. Note that the emission factors for
industrial and commercial boilers are divided into distillate and residual oil categories because the combustion of
each produces significantly different emissions of particulates, SOX, and NOX. The reader is urged to consult the
references cited for a detailed discussion of all of the parameters that affect emissions from oil combustion.
1.3.2.1 Particulates^ - Paniculate emissions are most dependent on the grade of fuel fired. The lighter
distillate oils result in significantly lower paniculate formation than do the heavier residual oils. Among residual
oils, grades 4 and 5 usually result in less paniculate than does the heavier grade 6.
In boilers firing grade 6, paniculate 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), paniculate 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 paniculate emissions in units firing grade 6 oil. At low load conditions, paniculate
emissions may be lowered by 30 to 40 percent from utility boilers and by as much as 60 percent from small
industrial and commercial units. No significant particulate reductions have been noted at low loads from boilers
firing any of the lighter grades, however. At too low a load condition, proper combustion conditions cannot be
maintained and particulate emissions may increase drastically. It should be noted, in this regard, that any
condition that prevents proper boiler operation can result in excessive particulate formation.
1.3.2.2 Sulfur Oxides (SOX) - Total sulfur oxide emissions are almost entirely dependent on the sulfur
content of the fuel and are not affected by boiler size, burner design, or grade of fuel being fired. On the average,
more than 95 percent of the fuel sulfur is converted to SOs, with about 1 to 3 percent further oxidized to $03.
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
A-ll
-------
Table 1.3-1. EMISSION FACTORS FOR FUEL OIL COMBUSTION
EMISSION FACTOR RATING: A
Polluunl
Parliculateb
Sulfur dioxide*1
Sulfur trioxide*1
Carbon monoxide*
Hydrocarbons
(toial. as CH4)f
Niliogen oxides
(total, as NO^fl
Type of boiler*
Power plant
Residual oil
lb/103gal
c
167S
2S
6
1
105(50)h''
kg/103 liter
c
19S
0.2BS
0.63
0.12
12.6|625)h-'
Industrial and commercial
Residual oil
lb/103gal
c
167S
2S
6
1
60l
kg/103 liter
c
IBS
0.25S
063
0.12
7.61
Distillate oil
lb/103gal
2
142S
2S
6
1
22
kg/103 liter
0.26
I7S
0.26S
0.63
0.12
28
Domestic
Distillate oil
lb/103 gal
2.5
142S
2S
5
1
IB
kg/103 liter
0.31
17S
0.25S
0.63
012
2.3
M
n
I
n
o
G
OB
p»
M*
O
a
in
o
'Boilers can be classified, roughly, according to their grots (higher) heal input rat*.
as shown below.
Power plant (ulilityl boiler*: >260 * 106 Blu/hr
(>63x 10bkg<»l/hr)
Induilrlal boiler*: >16x to6 but <260x I06 Blu/hr
l>3.7 * to", but <63 x 10^ kg^al/hr|
Commercial boiler*: >0.6x 106. but 0.l3x 106. but <37x I06kg-cal/hrk
Oomctlic (rttidtnliel) boiUri: <0.6 x 10® Blu/hr
«O.I3x lO^kg^al/hrl
bBaied on Ralarancei 3 through 6. Pariiculal* it defined in Ihil lection at that
malarial collected by EPA Method 6 (front half catch)?.
cPaniculat* emiuion Itclori for reiidual oil combutlion n» best d«*cribad. on
Ih* average, ai a function of fuel oil grade and sulfur content, a* ihown below.
Grade 6 oil: lb/1()3 oal - 10 IS) + 3
I kg/10^ liter- 1.26 IS) + 0.381
Where: S ii the percentage, by weight, of tulfur In Ihe oil
Grade 6 oil: 10 lb/l()3 gal (I 25 kg/103 liter)
Grade 4 oil: 7 Ib/tu3 gal (0 88 kg/IO^ liter)
Bated on References 1 through 6. S it the percentage, by weight, of tullur in
Ihe oil.
eBated on Reference! 3 through 6 and 8 through 10. Carbon monoxide emiuions
may increuta by a factor of 10 to 100 it a unit It improperly operated or not well
maintained.
'Bated on Reference* t. 3 through 6, end 10. Hydrocarbon emiisiont are gener-
ally negligible unleti unit it Improperly operated or not wejl maintained, in
which cate emiuiont may increase by leveral order* of magnitude.
flCated on Reference* I through 6 and 8 through It.
hUse 60 Ib/lfl3 gal (6.26 kg/103 Inert lor langentially fired boiler* end 105
Ib/I03 gal (12.6 kg/10^ liter) for all other*, at full load, and normal (>I6
percent) exceu air. At reduced loadt. NOH emittioni are reduced by 05 to
1 percent, on thu average, for every percentage reduction in boiler load.
Several combutllon modification* can be employed for NOM reduction: (1)
limited excett air firing can reduce NOH amitiion* by S to 30 percent, (21 tiaged
combutiion can reduce NOH emittion* by 20 to 45 percent, and (31 flue gat
recirculation can reduce NOM amitiioni by 10 to 46 percent. Combinations of
the modification* have been employed to reduce NOM emittiont by at much at
60 percent in certain boiler*. See lection 1.4 for a riitcuuion of ihete NO,,-
reducing technique*.
'Nitrogen oxide* emittion* from residual oil combutlion in industrial and com-
mercial boiler* are ttrongly dependent on the fuel nitrogen content and can be
estimated more accurately by the following empirical relationship:
Ib NO2/I03 gal "22 + 400 0 5%. by weight) nitrogen conientt. one should use 120 Ib •
NO2/I03 gal (16 kg NO^/IO3 liter) at en amitiion factor.
-------
1.3.13 Nitrogen Oxides (NO*)1"6' 8"11' 14 -Two mechanisms form nitrogen oxides: oxidation of fuel-bound
nitrogen and thermal fixation of the nitrogen present in combustion air. Fuel NOX are primarily a function of the
nitrogen content of the fuel and the available oxygen (on the average, about 45 percent of the fuel nitrogen is
converted to NOX, but this may vary from 20 to 70 percent). Thermal NOX, on the other hand, are largely a
function of peak flame temperature and available oxygen - factors which are dependent on boiler size, firing
configuration, and operating practices.
Fuel nitrogen conversion is the more important N0x-forming mechanism in boilers firing residual oil. Except
in certain large units having unusually high peak flame temperatures, or in units firing a low-nitrogen residual oil,
fuel NOX will generally account for over 50 percent of the total NOX generated. Thermal fixation, on the other
hand, is the predominant NOX -forming mechanism in units firing distillate oils, primarily because of the negligible
nitrogen content in these lighter oils. Because distillate-oil-fired boilers usually have low heat release rates,
however, the quantity of thermal NOX formed in them is less than in larger units.
A number of variables influence how much NOX is formed by these two mechanisms. One important variable
is firing configuration. Nitrogen oxides emissions from tangentially (corner) fired boilers are, on the average, only
half those of horizontally opposed units. Also important are the firing practices employed during boiler operation.
The use of limited excess air firing, flue gas recirculation, staged combustion, or some combination thereof, may
remit 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 lf 3"5' 8"10' 14 - As a rule, only minor amounts of hydrocarbons and carbon monoxide
will be produced during fuel oil combustion. If a unit is operated improperly or not maintained, however, the
resulting concentrations of these pollutants may increase by several orders of magnitude. This is most likely to be
the case with small, often unattended units.
1.3.3 Controls
Various control devices and/or techniques may be employed on oil-fired boilers depending on the type of
boiler and the pollutant being controlled. All such controls may be classified into three categories: boiler
modification, fuel substitution, and flue gas cleaning.
1J.3.1 Boiler Modification1"*1 8% 9> 13'l4 - 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 unbumed 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 U-l 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 SO* 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
A-13
-------
1.3.3.3 Rue Gas Geaning6' 15"21 - Flue gas cleaning equipment is generally only employed 00 large oil-fired
boiler*. Mechanical collectors, a prevalent type of control device, are primarily useful in controlling particulars
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 flyash provide only 40 to 60 percent control of oil-fired paniculate. 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
paniculate. These systems can achieve SO? removal efficiencies of up to 90 to 95 percent and provide paniculate
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.
1 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. Paniculate Emission Control Systems For Oil-Fired Boilers. CCA Corporation. Bedford, Mass. Prepared foi
Environmental Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-1316.
Publication No. EPA^50/3-74-063. 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. J<5(247): 24S88-:>4890
December 23, 1971.
8. Banok, 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 ai. Field Testing: Application of Combustion Modifications to Control NOX Emissions
From Utility Boilers. Exxon Research and "Engineering Company. Linden, N.J. Prepared for Environmental
Protection Agency, Research Triangle Park, N.C., under Contract No. 68-02-0227. Publication No.
EPA-650/2-74-066. June 1974. p.l 13-145.
10. Deffner, J.F. et al. Evaluation of Gulf Econoject Equipment with Respect to Air Conservation. Gulf
Research and Development Company. Pittsburgh, Pa. Report No. 731RC044. December 18, 1972.
EMISSION FACTORS 4/76
A-14
-------
11. Blakesiee, C.E. and H.E. Burbach. Controlling NOX Emissions from Steam Generators. J. Air Pol. Control
Assoc. 23:3142, January 1973.
12. Siegmund, C.W. Will Desulfurized Fuel Oils Help? ASHRAE Journal. 11:29-33, April 1969.
13. Govan, F.A. et al. Relationship of Paniculate 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. 424^36.
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. Fry Ash Collection From Oil-Fired Boilers. (Presented at 10th Annual Technical Meeting of
New England Section of APCA, Hartford, April 21, 1966.)
17. Bagwell, F.A, and R.G. Velte. New Developments in Dust Collecting Equipment for Electric Utilities. J. Air
Pol. Control Assoc. 21:781-782, December 1971.
18. Internal memorandum from Mark Hooper to EPA files referencing discussion with the Northeast Utilities
Company. January 13, 1971.
19. Pinheiro, G. Precipitaton for Oil-Fired Boilers. Power Engineering. 75:52-54, April 1971.
20. Flue Gas Deaulfurization: Installations and Operations. Environmental Protection Agency. Washington, D.C.
September 1974.
21. Proceedings: Flue Gas Desulfurization Symposium - 1973. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-650/2-73-038. December 1973.
4/76 External Combustion Sources
A-15
-------
1.4 NATURAL GAS COMBUSTION Revised by Thomas Lahre
1.4.1 General 1.2
Natural gas has become one of the major fuels used throughout the country. It is used mainly for power gen-
eration, for industrial process steam and heat production, and for domestic and commercial space heating. The
primary component of natural gas is methane, although varying amounts of ethane and smaller amounts of nitro-
gen. helium, and carbon dioxide are also present. The average gross heating value of natural gas is approximately
1050 Btu/stdft3 (935Q kcal/Nm3), varying generally between 1000 and 1100 Btu/stdft3 (8900 to 9800 kcal/
Because natural gas in its original state is a gaseous, homogenous fluid, its combustion is simple and can be pre-
cisely controlled. Common excess air rates range from 10 to 15 percent; however, some large units operate at
excess air rates as low as 5 percent to maximize efficiency and minimize nitrogen oxide (NOX) emissions.
1.4.2 Emissions and Controls 3-16
Even though natural gas is considered to be a relatively clean fuel, some emissions can occur from the com-
bustion reaction. For example, improper operating conditions, including poor mixing, insufficient air, etc., may
cause large amounts of smoke, carbon monoxide, and hydrocarbons to be produced. Moreover, because a sulfur-
containing mercaptan is added to natural gas for detection purposes, small amounts of sulfur oxides will also be
produced in the combustion process.
Nitrogen oxides are the major pollutants of concern when burning natural gas. Nitrogen oxide emissions are
a function of the temperature in the combustion chamber and the rate of cooling of the combustion products.
Emission levels generally vary considerably with the type and size of unit and are also a function of loading.
In some large boilers, several operating modifications have been employed for NOX control. Staged combus-
tion, for example, including off-stoichiometric filing and/or two-stage combustion, can reduce NOX emissions
by 30 to 70 percent. In off-stoichiometric firing, also called "biased firing," some burners are operated fuel-
rich, some fuel-lean, while others may supply air only. In two-staged combustion, the burners are operated fuel-
rich (by introducing only 80 to 95 percent stoichiometric air) with combustion being completed by air injected
above the flame zone through second-stage "NO-ports." In staged combustion, NOX emissions are reduced be-
cause the bulk of combustion occurs under fuel-rich, reducing conditions.
Other N0x-reducing modifications include low excess air firing and flue gas recirculation. In low excess air
firing, excess air levels are kept as low as possible without producing unacceptable levels of unbumed combus-
tibles (carbon monoxide, hydrocarbons, and smoke) and/or other operational problems. This technique can re-
duce NOX emissions by 10 to 30 percent primarily because of the lack of availability of oxygen during
combustion. Flue gas recirculation into the primary combustion zone, because the flue gas is relatively cool and
oxygen deficient, can also lower NO, emissions by 20 to 60 percent depending on the amount of gas recircu-
lated. At present only a few systems have this capability, however.
Combinations of the above combustion modifications may also be employed to further reduce N0% emissions.
In some boilers, for instance, NOX reductions as high as 70 to 90 percent have been produced as a result of em-
ploying several of these techniques simultaneously. In general, however, because the net effect of any of these
combinations varies greatly, it is difficult to predict what the overall reductions will be in any given unit.
Emission factors for natural gas combustion are presented in Table 1.4-1. Flue gas cleaning equipment has
not been utilized to control emissions from natural gas combustion equipment.
External Combustion Sojirces
A-16
-------
Tabi« 1.4-1. EMISSION FACTORS FOR NATURAL-GAS COMBUSTION
EMISSION FACTOR RATING: A
Pollutant
Participates*
Sulfur oxides (SO2>b
Carbon monoxide*:
Hydrocarbons
(as CH4)d
Nitrogen oxides
100 MMBtu/hr) use the NOX factors pre-
sented for power plantx
i Use 80 (1280) for domestic heating units and 120 (1920) for commercial units.
o
u
o
i
UJ
0.6
0.4
40
60
80
LOAD, percent
100
110
Figure 1.4-1. Load reduction coefficient as function of boiler
load. (Used to determine NOX reductions at reduced loads in
large boilers.)
EMISSION FACTORS
5/74
A-17
-------
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. 9-3.
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. Raman, 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 J.
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. ("hast, R. L and R. E. George. Contaminant Emissions from the Combustion of Fuels, J. Air Pollution Control
Assoc. ;0:34-*3, February 1960.
8. Hangebrauck, R. P., D. S. Von Lehmden, and J. E. Meeker. Emissions of Polynudear 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.
Battelle-Columbus Laboratories, Columbus, Ohio. Prepared for U.S. Environmental Protection Agency,
Research Triangle Park, N.C. under Contract No. 68-02-0251. Publication No. EPA-R2-73-084. June 1973.
13. Blakeslee, C. E. and H. E. Burbock. Controlling NOX Emissions from Steam Generators. J. Air Pollution
Control Assoc. 25:37^2, January 1973.
14. Jain, L. K. et aL "State of the Art" for Controlling NOX Emissions. Part 1. Utility Boilers. Catalytic, Inc.,
Charlotte, N. C. Prepared for U.S. Environmental Protection Agency under Contract No. 68-02-0241 (Task
No. 2). September 1972.
15. Bradstreet, J. W. and 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 NO* 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.
External Combustion Sources
A-18
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1.5 LIQUEFIED PETROLEUM GAS COMBUSTION Revised by Thorruis 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.3 Improper design, blocking and dogging of the
flue vent, and lade 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. Rest on, Va. Prepared for National
Air Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119. April 1970.
2. Clifford, EJL A Practical Guide to Liquified Petroleum Gas Utilization. New York, Moore Publishing Co.
1962.
4/77 External Combustion Sources
A-19
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Tabla 1.6-1. EMISSION FACTORS FOR LPG COMBUSTION*
EMISSION FACTOR RATING: C
Pollutant
Particulatas
Sulfur oxide*5
Carbon monoxida
Hydrocarbons
Nitrogen oxides6.
lndu»tr|a| process furnace;
Butana
Ib/tO3 gal
1.8
0.09S
1.6
0.3
12.1
kg/103 liters
0.22
aois
0.19
0.036
1.45
Propane
lb/103 gal
1.7
0.09S
1.6
0.3
11.2
kg/ 103 liters
0.20
Q.01S
0.18
0.033
1.35
Domestic and commercial furnaces
Butana
lb/103 gal
1.9
0.09S
2.0
0.8
(8 to 12)d
kfl/103 liters
0.23
0.01S
0.24
0.096
(1.0to1.6)d
Propane
lb/103 gal
1.8
0.09S
1.9
0.7
(7 to 11|d
kg/103 liters
0.22
0.01S
0.23
0.084
(0.8 to 1.3»d
in
c/i
»-H
o
•z
Q
o
K>
O
*LPG aminlon factori calculated aMuming amialoni (excluding tulfur oxidet) art lha t»m». on • hMI input b»»i». »f for nilural ga* combuilioa.
bS nqutli lulfur content •xpfMted in aroint par 100 It3 g*i vapor; «.g.. if the tullur coniant U O.I6grain par 100 ll (0.366g/tOO m ) vapor, Ihe SO} amittion (actor would be
0.09 N 016 or 0.014 Ib SO2 par 1000 gallon! 10.01 M 0.366 or 0.0018 kg SO^/IO3 litart) buiana burnad.
£E xprassed at NOj.
d(JM lower valua for domettlc unlu and highar valua for commarcial uniu.
-------
1.6 WOOD/BARK WASTE COMBUSTION IN BOILERS Revised by Thomas Lite
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 3000 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 Practices 1-3
A variety of boiler firing configurations are utilized for burning wood/bark waste. One common type in
smaller operations' is the Dutch Oven, or extension type of furnace with a flat grate. In this unit the fuel is fed
through the furnace roof and burned in a cone-shaped pile on the grate. In many other, generally larger, opera-
tions, more conventional boilers have been modified to burn wood/bark waste. These units may include spreader
stokers with traveling grates, vibrating grate stokers, etc., as well as tangentially fired or cyclone fired boilers.
Generally, an auxiliary fuel is burned in these units to maintain constant steam when the waste fuel supply fluctu-
ates and/or to provide more steam than is possible from the waste supply alone.
1.63 Emissions 1.2.4-3
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 fry-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-cnmbustibles can be successfully separated from the fly-ash before reinjection to the furnace.
Furnace design and operating conditions are particularly important when burning wood and bark waste. For
example, because of the high moisture content in this waste, a larger area of refractory surface should be provided
to dry the fuel prior to combustion. In addition, sufficient secondary air must be supplied over the fuel bed to
burn the volatiles that account for most of the combustible material in the waste. When proper drying conditions
5/74 External Combustion Sources
A-21
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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 paniculate, 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.
Tabfct 1.6-1. EMISSION FACTORS FOR WOOD AND BARK WASTE COMBUSTION IN BOILERS
EMISSION FACTOR RATING: B
Pollutant
Particuiates*
With fly-ash reinjectiond
Without fly-ash reinjection
Wood/bark mixture**-*
With fly-ash njinjectiond
Without fly-ash reinjection
Wooota
Sulfur oxides (SO2)".'
Carbon monoxidei
Hydrocarbonsk
Nitrogen oxides (NOj)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
Theae emission factors were determined for boiler* burning gas or oil as an auxiliary fuel, and it wa» assumed all paniculate*
resulted from tha waste fuel alone. When ao*i i* burned a* an auxiliary fuel, the appropriate emission factor from Table 1.1-2
should be used in addition to the above factor.
&These factors based on an aspired moisture contant at 50 percent.
^References 2, 4, 9.
^This factor represents a typical dust loading reaching tha control equipmant for bailers tmployinq fly-ash rainj action. Tha value
in parenthesis repmems areiisions after the control equipment assuming an average «ff Iciancy of 30 percent.
•References 7, 10.
f This waste includes clean, dry (S to 50 percent moisture) awidust, jhavings. ends, «tc., 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.
^References 11-13.
'This factor is calculated by material balance assuming a maximum tulfur content of 0.1 percent in the waste. When auxiliary
fuels are burned, the appropriate factors from Table* 1.1-2.1.3-1, or 1.4-1 ihould be used in addition to determine sulfur oxide
•missions.
'Reference* 1.5,7.
iThis factor is based on tngineering judgment and limited data from references 11 through 13. Use lower values for well designed
and operated boilers,
"This factor is based on limited data from reference* 13 through 15. Use lower values for well designed and operated boilers.
1 Reference 1 &
References for Section 1.6
1. Steam, Its Generation and Use, 37th Ed. New York, Babcock and Wflcox Co., 1963. p. 19-7 to 19-10 and
3-A4.
1 Atmospheric Emissiora 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
A-22
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3. C-E Bark Burning Boilers. Combustion Engineering, Inc., Windsor, Connecticut. 1973.
4. Barron, Jr., AJvah. Studies on the Collection of Bark Char Throughout the Industry. TAPPI. JJ(8): 1441-144S,
August 1970.
5. Kreisinger, Henry. Combustion of Wood-Waste Fuels. Mechanical Engineering. 62: \ 15-120, February 1939.
6. Magill,P,L.etal. (eds.). Air Pollution Handbook. New York, McGraw-Hill Book Co., 1956. p. 1-15 and 1-16.
7. Air Pollutant Emission Factors. Final Report. Resources Research, Inc., Reston, Virginia. Prepared for U.S.
Environmental Protection Agency, Durham, N.C. under Contract-No. CPA-22-69-119. April 1970. p. 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, Georgia.
May 1973.
10. Effenberger, H. K. et al. Control of Hogged-Fuel Boiler Emissions: A Case History. TAPPI. J
-------
1.7 LIGNITE COMBUSTION by Thomas Lalire
1.7.1 General1-*
Lignite is a geologically young coal whose properties are intermediate to those of bituminous coal and peat. It
has a high moisture content (35 to 40 percent, by weight) and a low heating value (6000 to 7500 Btu/lb, wet
basis) and is generally only burned close to where it ir mined, that is, in the midwestem States centered about
North Dakota and in Texas. Although a small amount is used in industrial and domestic situations, lignite is
mainly used for steam-electric production in power plants. In the past, lignite was mainly burned in small stokers;
today the trend is toward use in much larger pulverized-coal-fired or cyclone-fired boilers.
The major advantage to firing lignite is that, in certain geographical areas, it is plentiful, relatively low in cost,
and low in sulfur content (0.4 to 1 percent by weight, wet basis). Disadvantages are chat more fuel and larger
facilities are necessary to generate each megawatt of power than is the case with bituminous coal. There are
several reasons for this. First, the higher moisture content of lignite means that more energy is lost in the gaseous
products of combustion, which reduces boiler efficiency. Second, more energy is required to grind lignite to the
specified size needed for combustion, especially in pulverized coal-fired units. Third, greater rube spacing and
additional soot blowing are required because of the higher ash-fouling tendencies of lignite. Fourth, because of its
lower heating value, more fuel must be handled to produce a given amount of power because lignite is not
generally cleaned or dried prior to combustion (except for some drying that may occur in the crusher or
pulverizer and during subsequent transfer to the burner). Generally, no major problems exist with the handling or
combustion of lignite when its unique characteristics are taken into account.
1.7.2 Emissions and Controls 2~*
The major pollutants of concern when firing lignite, as with any coal, are participates, sulfur oxides, and
nitrogen oxides. Hydrocarbon and carbon monoxide emissions are usually quite low under normal operating
conditions.
Particulate emissions appear most dependent on the firing configuration in the boiler. Pulverized-coal-fired
units and spreader stokers, which fire all or much of the lignite in suspension, emit the greatest quantity of flyash
per unit of fuel burned. Both cyclones, which collect much of the ash as molten slag in the furnace itself, and
stokers (other than spreader stokers), which retain a large fraction of the ash in the fuel bed, emit less paniculate
matter. In general, the higher sodium content of lignite, relative to other coals, lowers paniculate emissions by
causing much of the resulting flyash to deposit on the boiler tubes. This is especially the case in
pulverized-coal-fired units wherein a high fraction of the ash is suspended in the combustion gases and can readily
come into contact with the boiler surfaces.
Nitrogen oxides emissions are mainly a function of the boiler firing configuration and excess air. Cyclones
produce the highest NOX levels, primarily because of the high heat-release rates and temperatures reached in the
small furnace sections of the boiler. Pulverized-coal-fired boilers produce less NOX than cyclones because
combustion occurs over a larger volume, which results in lower peak flame temperatures. Tangennally fired
boilers produce the lowest NO levels in this category. Stokers produce the lowest NO 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 NO emissions.
Sulfur oxide emissions are a function of the alkali (especially sodium) content of the lignite ash. Unlike most
fossil fuel combustion, in which over 90 percent of the fuel sulfur is emitted as SO?, a significant fraction of
the sulfur in lignite reacts with the ash components during combustion and is retained in the boiler ash deposits and
flyash. Tests have shown that less than 50 percent of the available sulfur may be emitted as SOi when a
high-sodium lignite is burned, whereas, more than 90 percent may be emitted with low-sodium lignite. As a rough
average, about 75 percent of the fuel sulfur will be emitted as S0?, with the remainder being converted to various
sulfate salts.
12/75 External Combustion Sources
A-24
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Air pollution controls on lignite-fired boilers in the United States have mairuy been limited to cyclone
collectors, which typically achieve 60 to 75 percent collection efficiency on lignite flyash. Electrostatic
precipitaton, which are widely utilized in Europe on lignitic coals and can effect 99+ percent particulate control,
have seen only limited application in the United States to date although their use wdl 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.
Tabta 1.7-1. EMISSIONS FROM LIGNITE COMBUSTION WITHOUT CONTROL EQUIPMENT9
EMISSION FACTOR RATING: 3
Pollutant
Particulate*3
Sulfur oxides8
Nitrogen
oxides'
Hydrocarbons'
Carbon
monoxide'
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."
<0.5
0.5
Cyclone
Ib/ton
6A
30S
17
<1.0
1.0
kg/MT
3A
15S
3.5
<0.5
0.5
Spreaker stoker
Ib/ton
7.0Ad
30S
6
1.0
2
kg/MT
3.5Ad
155
3
0.5
1
Other stokers
Ib/ton
3.0A
30S
6
1.0
2
kg/MT
1.5A
1SS
3
0.5
1
'All •minion facton are expressed in terms of pounds of pollutant p*r ton (kilogram of pollutant per rmtric ton) of lignita burned,
wet basis (35 to 40 percent moisture, by weight).
bA is the **h conttnt of the lignite by weight, wet basis. Facton based on References 5 and 6.
CThit factor is basad on data 'or dry-bottom, pulverizad-coaMired units only. It is expected that this factor would be lower for wet-
bortom unirj.
<*Limited data preclude any determination of the effect of flyasn reinjection. It is expected that particulate emissions would be
greater when reinjection is employed.
*S is the sulfur content of the lignite by weight, wet basis. For a high sodium-ash lignite (Na-jO > 3 percent) use 17S Ib/ton (8-5S
kg/MT); for a low sodium-esh lignite (N»]O < 2 percent), use 3SS Ib/ton (17.5S kg/MT}. For intermediate todium-ash lignite, or
when the *odiurrvash content is unknown, use 30S Ib/ton (1SS kg/MT)). Factors based on References 2. S. and 6.
'Expressed as NO7. Facton based on References 2. 3. 5, 7, and 9.
9Use 14 Ib/ton (7 kg/MT) for front-walMired and horizontally opposed wall-fired units and 3 Ib/ton (4 kg/MT) for tangentially
fired units.
hNitrogen oxide emissions may be reduced by 20 to 40 percent with low excess air firing and/or ttaged combustion in front-fired
and opposed-wall-fired units and cyclones.
'These factors are basad 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. 381-413.
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
A-25
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4. 1965 Keystone Coal Buyen 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, NJD. December 1973.
6. Gronhovd, G-H. et aL Comparison of Ash Fouling Tendencies of High and Low-Sodium Lignite from a North
Dakota Mine. In: Proceedings of the American Power Conference. Vol. XXVIII. 1966. p. 632-642.
7. Crawford, A. R. et aL Field Testing: Application of Combustion Modifications to Control NOX Emissions
from Utility Boilers. Exxon Research and Engineering Co., Linden, NJ. Prepared for U.S. Environmental
Protection Agency, Research Triangle Park, N.C. under Contract No. 68-02-0227. Publication Number
EPA-650/2-74-066. June 1974.
8. Engelbrecht, H. L. Electrostatic Precipitators in Thermal Power Stations Using Low Grade Coal. (Presented at
28th Annual Meeting of the American Power Conference. April 26-28, 1966.)
9. Source test data from U.S. Environmental Protection Agency, Office of Air (Duality Planning and Standards,
Research Triangle Park, N.C. 1974.
External Combustion Sources
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1.8 BAGASSE COMBUSTION IN SUGAR MILLS by Tom Lahre
1.8.1 General1
Bagasse is the fib rout residue from sugar cane that has been processed in a sugar mill. (See Section
6.12 for a brief general description of sugar cane processing.) It is fired in boilers to eliminate a large
solid waste disposal problem and to produce steam and electricity to meet the mill's power require-
ments. Bagasse represents about 30 percent of the weight of the raw sugar cane. Because of the high
moisture content (usually at least 50 percent, by weight) a typical heating value of wet bagasse will
range from 3000 to 4000 Btu/lb (1660 to 2220 kcal/kg). Fuel oil may be fired with bagasae when the
mill's power requirements cannot be met by burning only bagasae or when bagasse is too wet to support
combustion.
The United States sugar industry is located in Florida, Louisiana, Hawaii, Texas, and Puerto Rico.
Except in Hawaii, where raw sugar production takes place year round, sugar mills operate seasonally,
from 2 to 5 months per year.
Bagasse is commonly fired in boilers employing either a solid hearth or traveling grate. In the for*
mer, bagasse is gravity fed through chutes and forms a pile of burning fibers. The burning occurs on
the surface of the pile with combustion air supplied through primary and secondary ports located in
the furnace walla. This kind of boiler is common in older mills in the sugar cane industry. Newer boil-
ers, on the other hand, may employ traveling-grate stokers. Underfire air is used to suspend the ba-
gasse, and overfired air is supplied to complete combustion. This kind of boiler requires bagasse with a
higher percentage of fines, a moisture content not over 30 percent, and more experienced operating
personnel.
1.3.2 Emissions and Control*1
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.
Paniculate emissions are reduced by the use of multi-cyclones and wet scrubbers. Multi-cyclones
are reportedly 20 to 60 percent efficient on paniculate from bagasae 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 bagasae fired boilers are shown in Table 1.3-1.
4/77 External Combustion Sources
A-27
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Table 1.8-1. EMISSION FACTORS FOR UNCONTROLLED BAGASSE BOILERS
EMISSION FACTOR RATING: C
Paniculate0
Sulfur oxides
Nitrogen oxides8
Emission factors
lb/103 Ib steam3
4
d
0.3
gAg steam3
4
d
OJ
Ib/ton bagasse'3
16
d
1.2
kg/MT bagasse5
8
d
0.6
Emission factors are expressed in terms of the (mount of steam product, as most mills do not monitor the
amount of bagasse find. These factors should be applied only to that fraction of ttaam resulting from bagasse
combustion. If a significant amount (> 25% of total 8tu input) of fuel oil is fired with th« bagasse, th« appropriate
•mission factors from Table 1.3-1 should ba used to estimate the emission contributions from th« fuel oil.
b Emissions ara expressed in farms of wet bagassa, containing approximataiy 50 parcant moistura, by waight.
As a rule of thumb., about 2 pounds (2 kg) of iteam ara produced from 1 pound (1 kg) of w«t baoacaa.
evhilti-cydonas ara rvportadly 20 to 60 parcant afficiant on particulata from bagasse boilers. Wat scrubbers
ara csoatte of «ffacting 90 or more percent particuUta control. Based on Reference 1.
dSutfur 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 oti is fired with bagasse, the appropriate facton from
Table 1-3-1 should be used to estimate sulfur oxide emissions.
•Based on Reference 1.
Reference for Section 1.3
L Background Document: Bagaue Combustion in Sugar Mill*. Prepared by Environmental Science
and Engineering, Inc., Gainesville, Fla., for Environmental Protection Agency under Contract
No. 68-02-1402, Taak Order No. 13. Document No. EPA-450/3-77-007. Research Triangle Park, N.C
October 1976.
EMISSION FACTORS
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1.9 RESIDENTIAL FIREPLACES by Tom Latin
1.9.1 General'.*
Fireplaces are utilized mainly in homes, lodges, eta, 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 ia 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
ia supplied by natural draft, and may be controlled, to tome extent, by a damper located in the chim-
ney directly above the firebox. It ia common practice for dampen to be left completely open during
the fire, affording little control of the amount of air drawn up the chimney.
Moat 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 ia that fireplaces are extremely inefficient heating devices. Indeed, in cases where com-
bustion is poor, where the outside air ia cold, or where the fire ia 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!3
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 ia 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 fuela 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
A-29
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Table 1.9-1. EMISSION FACTORS FOR RESIDENTIAL FIREPLACES
EMISSION FACTOR RATING: C
Pollutant
Paniculate
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Carbon monoxide
Wood
Ib/ton
20°
Qd
1*
59
120"
kg/MT
10b
Qd
0.5'
2.53
60"
Coal3
Ib/ton
3QC
36S«
3
20
90
kg/MT
15C
36S<
1.5
10
45
*AII cod amisMon factors, txcaot oarticulata, ara based on data in Tabla 1.1-2
of Section 1.1 for hand-firad units.
"This includes condansabla Darticulata. Only about 30 parcarrt of tftu is filter-
abla particulatt a* daterminad by EPA Mwtriod 5 (front-half catch).4 Basad
on limitad dau from Rafaranca 1.
eThis includes condensable parciculata. About 50 paream of this is flltarabla
particulata at datarminad by EPA Method 5 (front-half catch).4 Sasad on
limitad data from Rafarenca 1.
Batad on n«giigibla sulfur contant in mon w
-------
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 disposal1 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 uncoflected 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 bumed, using a wide variety of combustion methods with both enclosed and open
burning3. Atmospheric emissions, both gaseous and paniculate, 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 Wfll Not Co Away. League of Women Voters of the United States. Publication Number 675.
April 1971.
2. Black, RJ., H.L. Hickman, Jr., AJ. Klee, AJ. Muchick, and JLD. 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
A-31
-------
2.1 REFUSE INCINERATION Revised by Robert Rosensteel
2.1.1 Process Description1-4
The meat 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 modem 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. Indusaialjcommercial incinerators — The capacities of these units cover a wide range, generally between
50 and 4,000 pounds (22.7 and 1,300 kilograms) per hour. Of either single- or multiple-chamber design,
these units are often manually charged and intermittently operated. Some industrial incinerators are
similar to municipal incinerators in size and design. Better designed emission control systems include
gas-fired afterburners or scrubbing, or both.
3. Trench Incinerators — A trench incinerator is designed for the combustion of wastes having relatively high
heat content and low ash content. The design of the unit is simple: a U-shaped combustion chamber is
formed by the sides and bottom of the pit and air is supplied from nozzles along the top of the pit. The
nozzles are directed at an angle below the horizontal to provide a curtain of air across the top of the pit
and to provide air for combustion in the pit. The trench incinerator is not as efficient for burning wastes
as the municipal multiple-chamber unit, except where careful precautions are taken to use it for disposal
of low-ash, high-heat-content refuse, and where special attention is paid to proper operation. Low
construction and operating costs have resulted in the use of this incinerator to dispose of materials other
than those for which it was originally designed. Emission factors for trench incinerators used to bum
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
A-32
-------
TabU 2.1 1. EMISSION FACTORS FOR REFUSE INCINERATORS WITHOUT CONTROLS*
EMISSION FACTOR RATING: A
Incinerator type
Municipal*
Multiple chamber, uncontrolled
With settling chamber and
water spray system'
1 ndust rial/commercial
Multiple chamber?
Single chamber'
Trench'
Wood
Rubber tires
Municipal refuse
Controlled airm
Flue-fed single chamber"
Flue fed (modified)0-?
Domestic single chamber
Without primary burner4*
With primary burner'
Pathological*
Particulates
Ib/ton
30
14
7
16
13
138
37
1.4
30
6
36
7
8
kg/MT
16
7
3.6
7.6
6.6
69
18.6
0.7
15
3
17.6
3.6
4
Sulfur oxides6
ilb/ton
2.6
2.6
2.5"
2.6h
0.1k
NA
2.5h
1.6
0.6
0.6
0.6
0.6
Neg
kg/MT
1.26
1.26
1.26
1.26
0.05
NA
1.25
0.76
0.26
0.25
0.26
0.26
Neg
Carbon monoxide
Ib/ton
35
36
10
20
NA1
NA
NA
Neg
20
10
300
Neg
Neg
kg/MT
17.6
17.6
6
10
NA
NA
NA
Neg
10
6
150
Neg
Neg
Hydrocarbons0
Ib/ton
1.6
1.5
3
16
NA
NA
NA
Neg
15
3
100
2
Neg
kg/MT
0.75
0.76
1.6
7.6
NA
NA
NA
Neg
7.5
• 1.6
50
1
Neg
Nitrogen oxidesd
Ib/lon
3
3
3
2
4
NA
NA
10
3
10
1
2
3
kg/MT
1.5
1.6
1.5
1
2
NA
NA
5
1.5
6
05
1
1.5
c?
E
I
a
f
t
O3
00
•Average lectori given bated on EPA procedural for Incinerator Hack UHing.
b£xpret»ed at tullur dioxide.
cExpra»i«d •• methane.
dExpraited *i nitrogen dioxide.
*Ralarancai 6 and 8 through 14.
' Moil municipal Incinaraiori ara aqulppad with al lean thli much control: taa Table
21 -1 lor appropriata efliclenciai lor olhar conlrolt.
OReferancei 3. 6, 10. 13. and 16
^Baied on municipal Inclnaraior data.
1 Reference* 3. 6. 10. and 16.
'Reference?.
Baled on data tor wood combuitlon In conical burner*.
Not available.
•"Reference 0.
"Reference* 3.10. 11.13. 16. and 16.
°With allerburnari and drall contioli.
PRal.rencei 3.11. and IB.
iRelerencm & and 10.
'Reference 6.
'Reference! 3 and 9.
-------
S 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 paniculate emissions. Air may be introduced from beneath the
chamber, from the side, or from the top of the combustion area. As underfire air is increased, an increase in
fly-ash emissions occurs. Erratic refuse charging causes a disruption of the combustion bed and a subsequent
release of large quantities of particulates. Large quantities of uncombusted particulate matter and carbon
monoxide are also emitted for an extended period after charging of batch-fed units because of interruptions in
the combustion process. In continuously fed units, furnace particulate emissions are strongly dependent upon
grate type. The use of rotary kiln and reciprocating grates results in higher particulate emissions than the use of
rocking or traveling grates.14 Emissions of oxides of sulfur are dependent on the sulfur content of the refuse.
Carbon monoxide and unburned hydrocarbon emissions may be significant and are caused by poor combustion
resulting from improper incinerator design or operating conditions. Nitrogen oxide emissions increase with an
increase in the temperature of the combustion zone, an increase in the residence time in the combustion zone
before quenching, and an increase in the excess air rates to the point where dilution cooling overcomes the effect
of increased oxygen concentration.14
Table 2.1-2 lists the relative collection efficiencies of particulate control equipment used for municipal
incinerators. This control equipment has little effect on gaseous emissions. Table 2.1-1 summarizes the
uncontrolled emission factors for the various types of incinerators previously discussed.
Table 2.1-2. COLLECTION EFFICIENCIES FOR VARIOUS TYPES OF
MUNICIPAL INCINERATION PARTICULATE CONTROL SYSTEMS"
Typ« of system
Settling chamber
Settling chamber and water spray
Wetted baffles
Mechanical collector
Scrubber
Electrostatic precipitator
Fabric filter
Efficiency.
Oto30
30 to 60
60
30 to 80
80 to 95
90 to 96
97 to 99
•fl«f»r«nc»»3,5,6. «nd 17 through 21.
EMISSION FACTORS
A-34
-------
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. D« 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 AJ>. Fururich. Techniques for Testing for Air Contaminants from
Combustion Sources. J. Air Pol. Control Assoc. 6(4): 191-199. February 1957.
6. Jens. W. and F.R. Rehm. Municipal Incineration and Air Pollution Control 1966 National Incinerator
Conference, American Society of Mechnical Engineers. New York, May 1966.
7. Burkle, J.O., J. A. Dorsey, and B. T. Riley. The Effects of Operating Variables and Refuse Types on
Emissions frd'm a Pilot-Scale Trench Incinerator. Proceedings of the 1968 Incinerator Conference, American
Society of Mechanical Engineers. New York. May 1968. p. 34-41.
8. Femandes, 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.
4/73 Solid Waste Disposal
A-35
-------
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. 5:199-204. 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. 12:83-89. February 1962.
19. Smauder, E.E. Problems of Municipal Incineration. (Presented at Pint Meeting of Air Pollution Control
Association, West Coast Section, Los Angeles, California. Match 1957.)
20. Gentle, 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. 1%7.
21. A Field Study of Performance of Three Municipal Incinerators. University of California, Berkeley, Technical
Bulletin. 5:41, November 1957.
EMISSION FACTORS
A-36
-------
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 bum two bodies
simultaneously.2 As many as 50 can 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 can 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 12009F (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 UM 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. Afterbumen and low-voltage electrostatic precipitators have been
used to reduce paniculate emissions;- the former also reduces some of the gaseous emissions.3-4 When
afterburnen 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 facton for auto body incinerators
are presented in Table 2.2-1.
TabU 2.2-1. EMISSION FACTORS FOR AUTO BODY INCINERATION*
EMISSION FACTOR RATING: B
Pollutants
Particulates"
Cartoon monoxide*
Hydrocarbons (CH4)C
Nitrogen oxides (NOj)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
'Saiad on 250 Ib (113 kg) of combustible material on stripped car body.
kRsferences 2 and 4.
C8as«d on data for open Burning and References 2 and 5.
^Reference 3.
4/73
Solid Waste Disposal
A-37
-------
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. 12:64-13,
February 1961
3. Alpiser, F.M. Air Pollution from Disposal of Junked Autos. Air Engineering. 10:18-22, November 1968.
4. Private communication with D.F. Walters, U.S. DHEW, PHS, Division of Air Pollution..Cincinnati, Ohio. July
19, 1963.
5. Gentle, R.W. and D.A. Kemnitz. Atmospheric Emissions from Open Burning. J. Air Pol. Control Assoc.
/7:324-327. May 1967.
EMISSION FACTORS
A-38
-------
2.3 CONICAL BURNERS
2.3.1 Process Descrip rionl
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
13-1.
4/73 Solid Waste Disposal
A-39
-------
>
o
in
in
N^
O
25
O
70
in
Tabla 2.3 1. EMISSION FACTORS FOR WASTE INCINERATION IN CONICAL BURNERS
WITHOUT CONTROLS'
EMISSION FACTOR RATING: B
Type of
waste
Municipal
'refuse*1
Wood refuse*
Participates
Ib/ton
20(10 to 60ie-d
1'
7«
20"
kg/MT
10 '
06
3.6
10
Sulfur oxides
Ib/ton
2
0.1
kg/MT
1
0.05
Carbon monoxide
Ib/ton
60
130
kg/MT
30
65
Hydrocarbons
Ib/ton
20
11
kg/MT
10
6.5
Nitrogen oxides
Ib/ton
5
1
kg/MT
2.5
0.5
'Molilure content ai fired li approximately 60 percent lor wood waste.
Except lor particulate*. lectori tit besad on comparison with other watt* disposal practical.
cUte high iid« ol rang* lor Intarmiltanl oparalloni charged with a bulldozer.
dBaiad on Reference 3.
'Reference* 4 through 0.
' Saliilactory operation: properly maintained burner with ad|ustabla underfir* air tupply and adjutlabla. tangential ovartir* air Inleli. approximately 600 percent
exceii air and 70O°f 1370%) axil gat temperature.
DUntalislactory operation: properly maintained burner with radial overllre air tupply near bottom of (hall, approximately 1200 percent excaM air and 400°F (204°C)
exit gai temperature.
"Vary unialiilactory operation: Improperly maintained burner with radial overtire air supply near bottom of ihell and many gaping holei in ihell. approximately 1500
percent axceii air and 40O°f (204"C) axil ga> temperature.
-------
References for Section 2.3
1. Air Pollutant Emission Factors. Final Report. Resources Research Inc. Reston, Va. Prepared for National Air
Pollution Control Administration, Durham, N.C., under Contract Number CPA-22-69-119. April 1970.
2. Kj-eichelt, I.E. Air Pollution Aspects of Teepee Burners. U.S. DHEW, PHS, Division of Air Pollution.
Cincinnati, Ohio. PHS Publication Number 999-AP-28. September 1966.
3. Magill, P.L. and R.W. Benoiiei. Air Pollution in Los Angeles County: Contribution of Industrial Products.
Ind.Eng.Chem. 44:1347-1352, June 1952.
4. Private communication with Public Health Service, Bureau of Solid Waste Management, Cincinnati, Ohio.
October 31, 1969.
5. Anderson, D.M., J. Lieben, and V.H. Sussman. Pure Air for Pennsylvania. Pennsylvania State Department of
Health, Harrisburg. November 1961. p.98.
6. Boubel, R.W. et al. Wood Waste Disposal and Utilization. Engineering Experiment Station, Oregon State
University, Corvallis. Bulletin Number 39. June 1958. p.57.
7. Netzley, A.B. and J.E. Williamson. Multiple Chamber Incinerators for Burning Wood Waste. In: Air Pollution
Engineering Manual Danielson, J.A. (ed.). U.S. DHEW, PHS, National Center for Air Pollution Control.
Cincinnati. Ohio. PHS Publication Number 999-AP40. 1967. p.436-445.
8. Droege, H. and G. Lee. The Use of Gas Sampling and Analysis for the Evaluation of Teepee Burners. Bureau
of Air Sanitation. California Department of Public Health. (Presented at the 7th Conference on Methods in
Aii Pollution Studies, Los Angeles. January 1965.)
9. Boubel R.W. Particulate Emissions from Sawmill Waste Burners. Engineering Experiment Station, Oregon
State University, Corvallis. Bulletin Number 42. August 1968. p.7,8.
4/73 Solid Waste Disposal
A-41
-------
2.4 OPEN BURNING
2.4.1 General1
revued by Tom Lahre
and Pom Canova
Open burning can be done in open drums or basket*, in fields and yard*, and in large open dumps
or pits. Materials commonly disposed of in this manner are municipal waste, auto body component*.
landscape refuse, agricultural field refuse, wood refuse, bulky industrial refuse, and leaves.
2.4.2 Emissions1-19
.Ground-level open burning is affected by many variables including wind, ambient temperature,
composition and moisture content of the debris burned, and compactness of the pile. In general, the
relatively low temperatures associated with open burning increase the emission of particulates, car-
bon monoxide, and hydrocarbons and suppress the emission of nitrogen oxide*. Sulfur oxide emissions
are a direct function of the sulfur content of the refuse. Emission factors are presented in Table 2.4-1
for the open burning of municipal refuse and automobile components.
Table 2.4-1. EMISSION FACTORS FOR OPEN BURNING OF NONAGRICULTURAL MATERIAL
EMISSION FACTOR RATING: B
Municipal refuse3
Ib/ton
kg/MT
Automobile
components 'c
Ib/ton
kg/MT
Particulates
16
3
100
50
Sulfur
oxides
1
0.5
Neg.
Neg.
Carbon
monoxide
85
42
12S
62
Hydrocarbons
(CH4)
30
15
30
15
Nitrogen oxides
6
3
4
2
aflt
-------
Table 2.4-2. EMISSION FACTORS AND FUEL LOADING FACTORS FOR OPEN BURNING
OF AGRICULTURAL MATERIALS3
EMISSION FACTOR RATING: 8
Refuse category
Field cropsc
Unspecified
Burning technique
not significant^
Asparagus8
Barley
Corn
Cotton
Grasses
Pineapple
Rice9
Safflower
Sorghum
Sugar cane*1
Headfire burning'
Alfalfa
Bean (red)
Hav (wild)
Oats
Pea
Wheat
Backfire burning'
Alfalfa
Bean (red), pea
Hay (wild)
Oats
Wheat
Vine crops
Weeds
Unspecified
Russian thistle
(tumbleweed)
Tules (wild reeds)
Orchard cropsc>k-'
Unspecified
Almond
Apple
Apricot
Avocado
Cherry
Citrus (orange.
lemon)
Date palm
Fig
Emission factors
Paniculate'3
Ib/ton
21
40
kg/MT
11
20
22 11
14 | 7
3
16
g
4
8
4
9 4
18
18
7
45
43
32
44
31
22
29
14
17
21
13
5
15
22
5
6
6
4
6
21
8
6
10
7
9
9
4
23
22
16
22
16
11
14
7
8
11
6
3
8
11
3
3
3
2
3
10
4
3
5
4
Carbon
monoxide
Ib/ton
117
150
157
108
176
101
112
83
144
77
71
106
186
139
137
147
128
119
148
150
136
108
51
. 85
309
34
52
46
42
49
116
44
31
56
57
kg/MT
53
75
78
54
88
50
56
41
72
38
35
53
93
70
68
74
64
60
72
75
68
54
26
42
154
17
26
23
21
24
58
22
40
28
28
Hydrocarbons
(asC6H14)
Ib/ton
- 23
85
19
16
6
19
8
10
26
9
10
36
46
22
33
38
17
37
25
17
18
11
7
12
2
27
10
8
4
3
32
10
12
7
10
kg/MT
12
42
10
3
3
10
4
5
13
4
5
18
23
11
16
19
9
- 18
12
8
9
6
4
6
1
14
5
4
2
4
16
5
6
4
5
Fuel loading factors
(waste production)
ton/acre
2.0
1.5
1.7
4.2
1.7
3.0
1.3
2.9
11.0
0.8
2.5
1.0
1.6
2.5
1.9
0.8
2.5
1.0
1.6
1.9
2.5
3.2
0.1
1.6
1.6
2.3
1.8
1.5
1.0
1.0
1.0
2.2
MT/hectare
4.5
3.4
3.3
9.4
3.8
5.7
2.3
6.5
24.0
1.8
5.5
2.2
3.6
5.6
4.3
1.8
5.6
2.2
3.6
4.3
5.6
7.2
0.2
3.6
3.6
5.2
4.0
3.4
2.2
2.2
2.2
4.9
EMISSION FACTORS
A-43
-------
TabU 2.4-2 (continued). EMISSION FACTORS AND FUEL LOADING FACTORS FOR OPEN BURNING
OF AGRICULTURAL MATERIALS1
EMISSION"FACTOR RATING: B
Refuse category
Orchard crops0'*'1
(continued)
Nectarine
Olive
Peach
P«ar
Prune
Walnut
Forest residues
Unspecified"1
Hemlock, Douglas
fir, cedar" .
Ponderosa pine0
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
!b/ton
33
114
42
57
42
47
140
90
. 195
kg/MT
16
57
21
28
21
24
70
45
98
Hydrocarbons
(asC6H14)
Ib/ton
4
18
5
9
3
8
24
5
14
kg/MT
2
9
2
4
2
4
12
2
7
Fuel loading factors
(waste production)
ton/acre
2.0
1.2
15
2.6
1.2
1.2
70
MT/hectare
4.5
2.7
5.6
5.8
2.7
2.7
157
'Factors expresaed as weight of pollutant emitted par weight of refuse material burned,
OpwTicuUn matter from mo*t agricultural refuse burning hat been found to be in the submicromater tixe ring*.'2
Cfleferences 12 and 13 for emission factors: Reference 14 for fuel loading factors.
dFor these refuse materials, no »gnificant difference exists between emissions faulting from heedflring or backfiring.
Thaw factor* raprnant emissions undar typical high moisture condition*. If farm am driad to laai than 15 percent
moisture, particulata emissions will ba raducad by 30 percent. CO minion by 23 percent, and HC by 74 percent.
'Whan pineapple i* allowad to dry to (act than 20 percent moinura. as it usually is. tha firing technique i* not important.
Whan haadfirad abova 20 parcant moisture, paniculate emiasion will incraaaa to 23 Ib/ton (11.5 kg/MT) and HC will
incraaaa to 12 Ib/ton (6 kg/MTl. Saa Reference 11.
9Thit factor ia for dry «15 parcant moisture) riea maw». If rica nr«w w burned at highar moatura lavalt, particulata
amiaHon will incraaaa to 29 Ib/ton (14.5 kg/MT), CO amisvon to 161 Ib/ton (80.5 kg/Mil, and HC amiasion to 21
Ib/ton (10.5 kg/MTI.
^Saa Saction 6.12 for ditcuntcn of wgar eana burning.
'Saa accompanying taut for definition of haadfiring.
'Saa accompanying taxt for definition of backfiring. This category, for amiaaion animation purooaaa. indudaa anothar
tachnioua u*ad occasionally for limiting amisaiona. callad into-
-------
TabU 2.4-3. EMISSION FACTORS FOR LEAF BURNING18'19
EMISSION FACTOR RATING: 8
Leaf species
Black Ash
Modesto Ash
White Ajh
Catalpa
Horse Chestnut
Cottonwood
American Elm
Eucalyptus
Sweet Gum
Stack 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
39
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'*-
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
3
.17
13.5
13
'These factors are an arithmetic average of the results obtained by burning high- and low moisture content conical piles ignited
lither at the top or around the periphery of the bottom. The windrowarrangemem VMS only tested on Modeno A*h, Catalpa,
American Hm, Sweet Gum, Silver Maple, and Tulip, and the results are included in the average* for the*e species.
t>The majority of particulaies ire submicron in size,
indicate hydrocarbons consist, on the avenge, of 42% otefina, 33% methane, 3% acetylene, and 1 3% other uturatei.
References for Section 2.4
1. Air Pollutant Emission Factor*. Final Report. Resources Research, Inc., Reston, Va, Prepared for
National Air Pollution Control Administration, Durham, N.G, under Contract Number CPA-22-
69-119. April 1970.
2. Gerrtle, R.'W. and D.A. Kemnitx. Atmospheric Emissions from Open Burning. J. Air PoL Control
Aasoe. 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
Emiaaiona from a Pilot-Scale Trench Incinerator. In: Proceedings of 1968 Incinerator Confer-
ence, American Society of Mechanical Engineer*. New York. May 1968. p. 34-41.
4. Weisburd. M.L and S.S. Griawold (eds,). Air Pollution Control Field Operations Guide: A Guide
for Inspection and Control. U.S. DHEV, PHS, Division of Air Pollution, Washington, D.C PHS
Publication No. 937. 1962.
EMISSION FACTORS
A-45
-------
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. 26:685-690, 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. 23:542-545, 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. 29:497-500, July 1969.
9. Waste Problems of Agriculture and Forestry. Environ. ScL 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.)
1L 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-L April 1974.
13. Darley, E°F. Progress Report on Emissions from Agricultural Burning. California Air Resources
Board Project 4-011. University of California, Riverside, Calif. Private communication with per-
mission of Air Resources Board, June 1975.
14. Private communication on estimated waste production from agricultural burning activities. Cal-
ifornia Air Resources Board, Sacramento, Calif. September 1975.
15. Fritschen, L. et aL Flash Fire Atmospheric Pollution. U.S. Department of Agriculture, Washing-
ton, D.C Service Research Paper PNW-97. 1970.
16. Sandberg, D. V., S.G. Pickford, and E.F. Darley. Emissions from Slash Burning and the Influence
of Flame Retardant Chemicals. J. Air PoL Control Assoc. 25:278, 1975.
17. Wayne, L.G. and M.L. McQueary. Calculation of Emission Factors for Agricultural Burning
Activities. Pacific Environmental Services, Inc., Santa Monica, Calif. Prepared for Environ-
mental Protection Agency, Research Triangle Park, N.C, under Contract No. 68-02-1004, Task
Order No. 4. Publication No. EPA-450/3-75-087. November 1975.
18. Darley, E.F. Emission Factor Development for Leaf Burning. University of California, Riverside,
Calif. Prepared for Environmental Protection Agency, Research Triangle Park, N.C, under Pur-
chase Order No. 5-02-6876-L September 1976.
19. Darley, E.F. Evaluation of the Impact of Leaf Burning - Phase I: Emission Factors for Illinois
Leaves. University of California, Riverside, Calif. Prepared for State of Illinois, Institute for En-
vironmental Quality. August 1975,
4/77 Solid Waste Disposal
A-46
-------
15 SEWAGE SLUDGE INCINERATION By Thomas lahre
2-S.I Process Description W
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 enten the top of the furnace where it is first dried by contact with the hot, rising, combustion
gjiev and then burned as it moves slowly down through the lower hearths. At the bottom hearth any residual
j-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
(J20°C) in the lower, ash cooling hearth; 1400 to 2000°F (760 to 1100°C) in the central combustion hearths,
ami 1000 to 1200°F (540 to 650°C) in the upper, drying hearths. Temperatures in a fluidized bed reactor are
f lirly uniform, from 1250 to 1500aF (680 to 820*C). In both types of furnace an auxiliary fuel may be required
Mher during startup or when the moisture content of the sludge is too high to support combustion.
15.2 Emissions and Controls
Because of the violent upwards movement of combustion gases with respect to the burning sludge, partial-
htes are the major emissions problem in both multiple hearth and fluidked 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 (S20°C) in fluidlzed bed reactors or
1600 to 2000°F (870 to 1100°C) in multiple hearth units, a«-e not formed in great amounts.
Odors can be a problem in multiple hearth systems as unburned volatile* are given off in the upper, drying
liearths. but are readily removed when afterburners are employed. Odors are not generally a problem in fluid-
•ted 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 unices tlw 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
A-47
-------
Table 2.5-1. EMISSION FACTORS FOR SEWAGE SLUDGE INCINERATORS
EMISSION FACTOR RATING: B
Pollutant
Paniculate*
Sulfur dioxide^
Carbon monoxide4
Nitrogen oxides<* (as NOj)
Hydrocarbons^
Hydrogen chloride gas<*
Emissions •
Uncontrolled41
Ib/ton
100
1
Neg
6
1.5
1.5
F kg/MT
50
0.5
Neg
3
0.75
0.75
After scrubber
Ib/ton
3
0.3
Neg
5
1
0.3
kg/MT
1.5
0.4
Neg
2.5
0,5
0.15
•Unit vMighti in ttrrm of *i«d riudo*.
b&timrad from •minion factor* after jo-utotwrt.
3.
References for Section 2.5
1. Caiaceto, R. R. Advances in Fly Ash Removal with Gas-Scrubbing Devices. Filtration Engineering. 7(7): 12-15,
March 1970.
1 Balakrishnam, S. et ai. State of the Art Review on Sludge Incineration Practices. U.S. Department of the
Interior, Federal Water Quality Administration, Washington, D.C. FWQA-WPC Research Series.
3. Canada's Largest Sludge Incinerators Fired Up and Running. Water and Pollution Control 707(1 ):20-21, 24,
January 1969.
4. Caiaceto, 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. 103(2):55-57,
February 1972.
6. Liao.P. Design Method for Fluidized Bed Sewage Sludge Incinerators. PhD. Thesis. University of Washington,
Seattle, Washington, 1972.
7. Source test data supplied by the Detroit Metropolitan Water Department, Detroit, Michigan. 1973.
8. Source test data from Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, N.C. 1972.
9. Source test data from Dorr-Oliver, Inc., Stamford, Connecticut. 1973.
EMISSION FACTORS
A-48
-------
Appendix B
Conversion Factors
Length
1 inch= 2.54 cm
1 m=3.048 ft
1 ft = 0.305 m
Mass
1 lb = 453.6 g
1 kg=2.2 Ib
Pressure
1 atm=101,325 Pa
= 760 mm Hg (0°C)
= 14.7 psia
Force
1 N=l kg-rn/s2
Energy
1 cal = 4.184j
1 J=9.48x 10'4 Ecu
1 Btu=252.2 cal
Kinematic viscosity
1 nWs= 10* stokes
Power
1 w= 1 J/s
1 hp= 33,479 Btu/hr
Area
1 cm2 = 0.155 in2
1 mz=10.764ftz
Volume
1 cm3 = 0.061 in3
1 m3=35.31 ft3
1 barrel (oil) = 42 gal
1 ft3 = 7.48 gal
1 ft3 = 28.317 liters
Density
1 kg/m3 = 0.0624 lb/ft3
Dynamic viscosity
1 Pa«s= 1 N»m/s= 1000 centipoise
1 cp = 0.000672 lb/ft-sec
Volume flow
1 m3/s=35.3 ftVsec
1 m3/min=35.3 ftVmin
1 scfm= 1.7 m3/h
1 gpm = 0.227 mVh
Velocity
1 m/s=3.048 ft/sec
1 mi/hr = 0.447 m/s
Geometry
area of circle = TTZ
circumference of circle = 2 TTT
surface area of sphere = 4 Trr2
volume of sphere = 4/3 Trr3
area of cylinder = 2 Trrh
B-l
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
EPA 450/2-84-010
3. RECIPIENT'S ACC£SSIOf*NO.
4. TITLE AND SUBTITLE
APTI Course SI:428A
Introduction to Boiler Operation
Self-Instructional Guidebook
5. REPORT DATE
December, 1984
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
David S. Beachler
, PERFORMING ORGANIZATION
9. PERFORMING ORGANIZATION NAME AND ADDRESS
ETS, Inc.
Suite C-103
3140 Chaparral Drive
Roanoke, VA 24018
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3573
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Manpower and Technical Information Branch
Research Triangle Park, NC 27711
13. TYP6 OF REPORT AND PERIOD COVERED
Self-Instructional Course
14. SPONSORING AGENCY CODE
13. SUPPLEMENTARY NOTES
EPA Project Officer for this report is R. E. Townsend, EPA-ERC, MD-20,
Research Triangle Park, NC 27711
16. ABSTRACT
This self-instructional guidebook is a self-instructional course, APTI
Course SI:428A, "Introduction to Boiler Operation." This course is designed
for engineers and other technical persons responsible for inspecting boilers
and issuing operating permits. The course focuses on the major components
of boilers and how boilers operate to produce steam for processes, heating,
or generating electricity. Major topics include: fire-tube and water-tube
designs, combustion efficiency, supplying air and fuel for gas-fired,
oil-fired, and coal-fired boilers (underfeed, overfeed, and spreader stokers,
pulverized coal-fired units, and fluidized-bed units), boiler operation and
maintenance, steam turbines, condensers, cooling towers, air pollutants
emitted from boilers, and air pollution control techniques.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIEHS/OPEN ENDED TERMS
c. COSATI Fieid/Group
Boiler Operation
Coal-, Oil-, and Gas-Fired Boilers
Air Pollution Control Equipment for
Boilers
Self-Training Manual
Self-Instructional
Guidebook
DISTRIBUTION STATEMENT unlimited
National Audio-Visual Center
National Archives and Records Service
GSA Order Service HH
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
172
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
2220-1 (9-73)
B-2
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