January 1977
EPA-600/8-77*003a
GUIDELINES FOR INDUSTRIAL BOILER PERFORMANCE IMPROVEMENT
Boiler Adjustment Procedures to Minimize Air Pollution and to Achieve
Efficient Use of Fuel
Guidelines intended for use
- by personnel responsible (or boiler operation
to perform an efficiency and emissions tune-up
- by plant engineers to initiate maintenance and
efficiency monitoring practices
- as a supplement to manufacturers
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FEDERAL ENERGY ADMINISTRATION
ENERGY CONSERVATION AND ENVIRONMENT
NATIONAL ENERGY CONSERVATION PROGRAMS
WASHINGTON, D.C. 20461
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
RESEARCH TRIANGLE PARK, NC 27711
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CONTENTS
Section Page
I.0 INTRODUCTION 1
2.0 FUNDAMENTALS OF COMBUSTION. 5
2.1 Furnace Excess air 6
2.2 Nitrogen Oxides 9
2.3 Boiler Efficiency 11
3.0 PREPARATION FOR BOILER TESTS 20
3.1 Preliminary Boiler Inspection 20
3.1.1 Burners 21
3.1.2 Combustion Controls 22
3.1.3 Furnace 22
3.2 Stack Instruments 23
3.2.1 Excess Oxygen 23
3.2.2 Carbon Monoxide 24
3.2.3 Oxides of Nitrogen 25
3.2.4 Stack Opacity (Smoke Density) 28
3.2.5 Stack Temperature 29
3.3 Flame Appearance 30
3.4 Stack Sampling Techniques 32
3.5 Boiler Test Procedures 33
4.0 EFFICIENCY IMPROVEMENT AND NO
REDUCTION TECHNIQUES X 38
4.1 Step-by-Step Boiler Adjustment Procedure
for Low Excess O Operation 47
4.2 Evaluation of the New Low 02 Settings 50
4.3 Burner Adjustment 51
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CONTENTS (Continued)
Section Page
5.0 MAINTAINING HIGH BOILER EFFICIENCY AND
LOW NO 56
x
5.1 Combustion Efficiency Spot Check 56
5.2 Performance Monitoring (Boiler Log) 57
5.3 Performance Deficiency Costs 60
5.4 Identifying Causes of Performance
Deficiencies 61
5.4.1 Heat Transfer Related Problems 63
5.4.2 Combustion Related Problems 63
5.4.3 Miscellaneous Energy Losses 65
5.5 Efficiency Related Boiler Maintenance Items 66
5.5.1 Fuel Supply System ' 67
5.5.2 Controls and Instrumentation 68
5.5.3 Fuel Burning Equipment 69
5.5.4 Heat Transfer Equipment 71
5.5.5 Fans 72
5.5.6 Air and Gas Ducts 73
5.5.7 Insulation 73
6.0 REFERENCES . 74
APPENDICES:
A. OTHER NO REDUCTION TECHNIQUES 75
X
B. COST OF COMBUSTION MODIFICATIONS TO
CONTROL"NO 81
x
C. METHODS AND EQUIPMENT FOR EFFICIENCY
IMPROVEMENT 84
D. COMBUSTION GENERATED AIR POLLUTANTS 90.
E. CONVERSION FACTORS . 99
ii
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ACKNOWLEDGEMENTS,
The authors wish to acknowledge the assistance of Mr. Robert E.
Hall, the EPA Project Officer, and Mr. Kenneth W. Freelain, the FEA
Project Officer, for their suggestions and comments during the prepara-
tion of the guidelines.
Acknowledgement is also made to the active cooperation and advice
of Mr. W. H. Axtman of the American Boiler Manufacturers' Association and
to the ABMA members who offered a forum for discussion of the industrial
boiler guidelines and constructive criticism.
The guideline manual was prepared from several sources of informa-
tion within KVB, Inc. The principal authors were Dale E. Shore and Michael
W. McElroy.
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The contents of this manual are offered as guidance. The United States
Government, its employees, and KVB, Inc. do not assume responsibility or
liability for consequences arising from the implementation or failure to
implement the guidance contained herein. The contents of this manual
should not be construed as an endorsement by the Environmental Protection
Agency or the Federal Energy Administration of any product or manufacturer.
IV
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SECTION 1.0
INTRODUCTION
The purpose of this manual is to provide general guidelines
for use by industrial boiler operators to reduce stack emissions of
nitrogen oxides and improve boiler operating efficiency. These guide-
lines deal primarily with boiler adjustments which are typically with-
in the control of boiler operators and plant engineering personnel.
However, other techniques are also described in the Appendices which
will usually require the assistance of outside combustion specialists
due to the more critical dependence on specific boiler design, oper-
ating conditions and fuel characteristics.
Since efficiency and emissions are sensitive to many of the
same boiler operating parameters, it is essential that both of these
areas be simultaneously treated in one integrated set of guidelines.
The recommended procedures in this report are based on the results of
U.S. Environmental Protection Agency (EPA) and Federal Energy Admini-
stration (FEA) sponsored programs (Refs. 1 and 2) during which various
nitrogen oxides reduction methods were evaluated in the field and im-
provements in boiler efficiency were demonstrated.
Oxides of nitrogen are a major contributor to the total air
pollution problem existing in industrial areas. Generally referred
to as "NO ", this gaseous pollutant includes both nitric oxide (NO)
and nitrogen dioxide (NO ), although NO generally comprises only
five percent or less of the total NO emissions from boilers. These
X
compounds plus the new substances formed when they combine with other
pollutants in the air are an important element in what is commonly
referred to as "smog".
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Boilers used in industry produce a significant fraction of the
total industrial emissions of NO . In fact, industrial boilers pro-
X
duce 50 percent of the NO emitted from all stationary industrial com-
bustion sources (Ref. 3). A reduction in emissions from just this
single industrial source would obviously contribute greatly to im-
proving the national air quality.
Industrial boilers currently account for over 15 percent of
all the energy consumed in the United States, or more than 11 quad-
rillion Btu's per year (Ref. 2). An increase in industrial boiler ef-
ficiency would therefore significantly impact energy conservation na-
tionwide as well as reduce industries' fuel costs. The EPA and FEA
sponsored field test programs revealed that improvements in efficiency
of up to several percent were frequently possible by simply adjusting
the fuel/air ratio to minimize stack gas heat losses.
During the two-year EPA field test program, substantial re-
ductions in nitrogen oxides emissions were achieved through careful •
adjustment of existing boiler equipment. Usually little or no dele-
terious effects on combustion controls or boiler reliability occurred
when the optimum adjustments were established. In fact, substantial
improvements in boiler efficiency often accompany "low NO " operation.
X
However, adjustments for improved efficiency occasionally conflicted
with attempts to reduce emissions, requiring a tradeoff between emissions
and fuel usage, or preferably the application of alternate NO emission
controls.
This guide begins with a simplified discussion of the fuel
burning process to provide the boiler operator with a basic under-
standing of HO formation in the boiler and the major combustion-
related factors important to efficiency. With this background, the
techniques for reducing NO and improving boiler efficiency are
X
then discussed in detail and instructions are provided to assist
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the boiler operator in applying them to a particular boiler installation.
Emphasis is on reducing the boiler excess air to the lowest practical
level. This will require that the operator have a working knowledge
of the boiler's combustion control system and the required flue gas
analysis instrumentation necessary to perform the boiler adjustments
safely and effectively. Jt is important that this entire guide, be read
and understood before attempting any boiler adjustment or modifications.
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IMPORTANT NOTICE
To be generally applicable to all industrial boiler
installations,these guidelines could not be prepared as a self-
contained document. Due to the wide variety of combustion control
systems, burner designs and furnace geometries in use, and the
variation in operating demands, it will be necessary that these
guidelines be supplemented by other information sources available
to boiler operating personnel. These might include:
. The Plant Engineering Staff
. Boiler Operating and Maintenance Manuals
. Boiler Equipment Manufacturers and Their Service
Organizations
In addition, local and national boiler safety codes must be observed
at all times. Any apparent contradiction between these codes,
the boiler manuals, and the guidelines, must be resolved before
proceeding. It is also intended that these guidelines be used
for equipment fired with conventional fuels (i.e., hard coals,
#2 through #6 fuel oils, and natural gas.) Although many of the
concepts and recommendations will be applicable to other fuels,
these may require special considerations and procedures which have
not been addressed in these guidelines.
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SECTION 2.0
FUNDAMENTALS OF COMBUSTION
The heat energy in all fossil fuels (coals, fuel oils,
and natural gases) is released during the combustion process as the
carbon and hydrogen in the fuel react with oxygen to produce a high
temperature flame. The burning of carbon and hydrogen with oxygen
would ideally produce an exhaust gas consisting of carbon dioxide (CO_)
and water vapor (HO) which are considered harmless combustion byproducts.
Unfortunately, real combustion systems differ from this ideal situa-
tion due to the more complex make-up of the fuel itself plus the non-
ideal characteristics of the actual burning process. As a result, the
exhaust products from industrial boilers contain additional gaseous and
solid materials, some of which are identified as serious enviornmental
pollutants (see Appertdix D). Some are products of incomplete combustion
and are important from an efficiency standpoint, since they represent
a waste of available heat that is lost from the boiler stack.
Air is the convenient and non-varying source of oxygen for
nearly all industrial combustion processes. The composition of air
is roughly 21% oxygen (0 ) and 78% nitrogen (N ) by volume with traces
of other gases including argon and carbon dioxide. Under perfect com-
bustion conditions, there is a so-called "theoretical amount" of air
which will completely burn a given amount of fuel with no excess air
remaining. In practice, however, more air than the theoretical amount
must be supplied to the burner to ensure complete burning of the fuel.
The actual quantity of excess air required at a particular boiler de-
pends on many factors such as fuel type and composition, furnace de-
sign, boiler firing rate, and the design and adjustment of the burners.
If enough air is not provided, unburned fuel, smoke and other products
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of incomplete combustion such as carbon monoxide (CO) and soot are
emitted from the stack, resulting in pollution, wasted fuel energy,
and a potential for explosion. In the case of coal fired boilers,
the quantity of unburned fuel in the refuse also increase. If too
much excess air is supplied to the burner, the boiler efficiency will
be reduced because some fuel is used simply to heat the unneeded air
which is exhausted out the stack. The amount of excess air can also
influence the formation and emission of nitrogen oxides (NO ) as dis-
cussed in a later section.
2.1 FURNACE EXCESS AIR
Excess air is a primary boiler operating variable and an im-
portant element in the following discussions. It is therefore ap-
propriate to include a brief discussion of this term and the methods
available for determining the quantity of excess air at the boiler.
Accurate fuel and air flow measurements would provide a di-
rect determination of the boiler air/fuel ratio and excess air, but
these measurements are frequently not available at industrial boiler
installations. An alternate means for determining boiler excess air
utilizes measurements of specific gases in the stack and the known
relationships between their concentration and percent excess air for
a particular fuel.
Excess air in the boiler is evident from the presence of oxygen
in the flue gas. This oxygen content is customarily referred to as
excess oxygen, excess 0 or stack 0 . However, the terms "excess
^ ^
air" and "excess O " should not be confused to mean the same thing.
As the excess air is increased at the boiler, one would expect that
the oxygen concentration in the stack gases would also increase, and,
indeed, this is the case. Figure 1 shows this relationship between
excess 0 and excess air for typical natural gas, oil and high
grade coal fuels.
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£
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Some boiler operators are accumstomed to judging boiler firing
conditions based on stack C0_ measurements (as opposed to using excess
O_) and the C0_ versus excess air dependence is also shown in Figure 1.
While both approaches are equally valid for determining boiler excess
air, the use of excess 0 is preferred for the following reasons:
1. The relation between 0_ and excess air is not highly
affected by fuel composition. This is evident in Fig-
ure 1 where the 02 versus excess air curves for natural
gas, oil and coal fuels are nearly coincident. On the
other hand, CO versus excess air curves exhibit a wide
variation witn fuel type.
2. Measurement of CO- requires a much greater precision than
excess 0 measurements to obtain the same accuracy in
excess air. This is especially true when firing with
low excess air which is generally the preferred
condition for high boiler efficiencies. For example,
suppose it is desired to establish the excess air
to within +_ 2 percent excess air. If the boiler is
operating in the region of 20 percent excess air on
oil fuel, the CO would have to be measured to within
+_ 1.5% accuracy (13.0 +_ .2 percent C02> » while an 0_
measurement accuracy of only +_ S% (3.7+^.3 percent
would be required.
3. C02 is a product of combustion whereas excess ©2 is
more immediately associated with excess air. conditions
in the boiler. The excess ©2 measured in the stack
gases is the actual surplus of oxygen in the furance
available for the combustion process. As lower and
lower excess air is present in the furnace, the excess
O_ approaches zero (regardless of fuel type) while
the C02 increases, approaching some constant value which
is dependent on the fuel composition.
4. Instrumentation for excess O. measurements is generally
less expensive and more reliable as a class than C02
instrumentation. Many continuous CO instruments are
of a NDIR type which is more expensive and not very
portable .
In following sections of this manual, excess O_ will be used
exclusively as an indicator for excess air. It is strongly recommended
that the use of excess 02 be adopted by all boiler operators. However,
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for those who still prefer to think in terms of CO., it is possible
to convert 0 to CO using curves such as those in Figure 1 for the
particular fuel being fired.
One final note concerns the interpretation of boiler excess
air as it relates to excess air at the burner. For boilers with a
single burner, the percent excess air at the burner is said to be
the same as the boiler excess air (percent excess air at the stack).
For multi-burner boilers, the situation can be complicated if the fuel
and air are not equally distributed to all the burners. With equal
fuel and air distribution, the fuel/air ratio and percent excess air
at all burners is the same and equal to the percent boiler excess air.
However, when the fuel and/or air varies from burner to burner (due
to dissimilar air register settings, eroded fuel injection orifices,
coal pipe obstructions, etc.), the fuel/air ratio and burner excess
air will also vary. The use of "overfire" air or other air injection
ports away from the burner region will of course result in less excess
air at the burner than indicated by the stack 02- This situation
generally occurs only with stoker fired boilers where the concept of
burner excess air is not usually applicable due to the non-uniform
or time-dependent nature of solid fuel bed burning. In this case, stack
excess 0 is still an important measurement.
Casing or setting air leaks on induced or balanced draft units can
also distort the O readings. In these cases comparison of overfire 0
and stack O readings can verify the presence of air infiltration to the
furnace.
2.2 NITROGEN OXIDES
Combustion temperatures on the order of 3500°F are reached in the
flame zone of industrial boilers. When oxygen and nitrogen are both-
present at such high temperatures, a fraction of these will combine
to form NOx. Nitrogen oxides formed in this manner are difficult to
prevent altogether, since all three ingredients (oxygen, nitrogen and
high temperature) are integral parts of the combustion process. Nitrogen
is the major constituent in the combustion air and its elimination
would be very impractical. Most of the NOx reduction techniques
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described in following sections are generally viewed to be effective
as a result of lower peak flame temperature, reduced availability of
oxygen in the flame or a combination of both. Oxygen and temperature
are important flame parameters affecting stability, radiant heat re-
lease, combustible burnout, flame appearance and other boiler operation
related factors. Therefore, the successful application of NO reduction
techniques involve more than just reducing NO emission levels.
X
Equal consideration must be given to these other factors to
assure safe, reliable and efficient operation. This aspect of imple-
menting low NO firing will involve a certain amount of subjective inter-
pretation of flame conditions in the furnace coupled with an evaluation
of boiler efficiency, steam conditions and other boiler operational factors.
Nitrogen oxides produced by the combining of atmospheric nitro-
gen and oxygen under the influence of high flame temperatures is gener-
ally referred to as "thermal NO ". Conventional solid and liquid fuels
X
(even some natural gas fuels) contain quantities of nitrogen bearing
compounds. A fraction of this nitrogen also combines with oxygen in
the flame to produce what is called "fuel nitrogen NO " or simply "fuel
X
NO ". This "fuel NO " plus the "thermal NO " make up the total NO
X X X X
emitted from the stack. In some cases with a high nitrogen content
fuel, the "fuel NO " can contribute more than half of the total NO
x x
emissions.
The formation of "fuel NO " is not presently well understood.
There is some evidence that "fuel NO " can be reduced by lowering the
available oxygen in the flame. Switching to a fuel which contains less
nitrogen has also produced lower total NO ; however, this is not always
X
predictable for fuel variations within the same fuel type (i.e., #6
oils, bituminous coals, etc.). It should also be mentioned that measure-
ments of total NO at the stack or furnace outlet will not distinguish
between "thermal NO " and "fuel NO ". NO variations measured under
X XX
various boiler operating modes may result from combined effects on both
NO components.
Finally, while oxygen availability and flame temperature ap-
pear to be the major combustion parameters affecting NO formation, the
10
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absolute levels of NO emitted from the stack will also depend on a
x
variety of other factors. As described later on, different types of
fuels generally exhibit a different range of NO emissions. This is
X
due to differences in fuel nitrogen already mentioned plus fundamental
differences in the fuel burning characteristics, general requirements
of the associated burning equipment (stoker versus oil gun) and so on.
For a particular fuel composition, boiler-to-boiler variation in NO
X
emissions also suggest the importance of burner and furnace design and
the specific flow patterns of the flame within the furnace. At any
given boiler with a constant fuel, the NO emissions are also generally
dependent on firing rate.
2.3 BOILER EFFICIENCY
The term "boiler efficiency" as used in this manual pertains
to the thoroughness by which the boiler extracts the total available
heat energy from the fuel. Some loss of heat from the boiler is un-
avoidable and as a consequence, boiler efficiency is always less than
100%. However, some of these efficiency losses can be minimized or
eliminated by proper operating and maintenance practices.
Boiler efficiency losses arise from four major sources:
1. Heat carried away (out the stack) by the hot flue gases.
This loss is usually called "dry flue gas" loss. Hotter stack tem-
peratures and larger quantities of excess air increase this loss.
2. Latent heat of water vapor present in the flue gas.
(Water vapor results from the combustion of hydrogen contained in the
fuel and from moisture present in the fuel and combustion air.) This
loss arises from the fact that water vapor contains more heat energy
than an equal weight of liquid water. The latent heat would be re-
covered only if the water vapor were allowed to condense out before
the flue gases leave the boiler. Since this would be impractical in
conventional boiler systems, (due to corrosion problems and reduced
plume rise), the latent heat is not considered recoverable.
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3. Unburned fuel and products of incomplete combustion.
These include solid combustibles in refuse, carbon carryover from
the furnace, and all other solid and gaseous combustible material
carried away in the flue gases. This loss is usually referred to
as "combustible loss" or "unburned fuel loss." Improperly adjusted
burning equipment or an inadequate quantity of excess air can lead
to rapid increases in combustible losses.
4. Heat lost from the boiler jacket through its insulation.
This is generally termed "radiation loss" and includes heat radiated
to the boiler room and the heat picked up by the ambient air in
contact with the boiler surfaces. The quantity of heat lost in this
manner is fairly constant at different boiler firing rates and as a
result, becomes an increasingly higher percentage of the total heat
losses at the lower firing rates. Deteriorated insulation and furnace
wall refractory will also increase these losses at all loads.
Figures 2 and 3 illustrate how the various efficiency losses
are affected by changes in excess 02 and firing rate. These results
are based on actual measurements at a 13,000 Ib/hr boiler fired
with natural gas but the general trends are also representative of
many natural gas, oil and coal fired boilers. Of course, the actual
values of the various efficiency losses will be different depending
on specific fuel properties, boiler/burner design, operating con-
ditions, etc.
At each firing rate the highest boiler efficiency is achieved
by firing with the lowest practical excess 0 . For the particular
example in Figure 2, the point of maximum efficiency occurred at
about .5% excess O where the total efficiency losses were at a mini-
mum. (Excess 0 levels at peak efficiency can vary significantly from
boiler to boiler and with different fuels. These can be determined at
a boiler by a test procedure described in Sections 3.0 and 4.0.) A
further reduction in excess O caused rapid increases in carbon
12
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25
20
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Total Efficiency
Loss
Flue Moisture
Dry Flue Gas
Radiation
Combustibles (Carbon Monoxide)
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EXCESS 02/ %
Figure 2. Variation in boiler efficiency losses with changes in
excess 0-
6001/8300-461
13
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30
25
20
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15
10
Total Efficiency
Loss
Combustibles (Carbon Monoxide)
I I I
20 40 60 80
PERCENT OF RATED CAPACITY
100
Figure 3. Variation in boiler efficiency losses with changes in
boiler firing rate.
6001/8300-461
14
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monoxide and other combustibles which resulted in a very rapid deteri-
oration in efficiency.
With high excess 0 , some fuel is used to heat unneeded excess
air to the stack temperature where it is carried out the stack (result-
ing in higher "dry flue gas" losses and reduced efficiency). It might
at first seem that large quantities of excess air would mix with the
flame and cool it, resulting in a lower stack gas temperature. In prac-
tice, however, the reverse is true. High excess air does cool the flame
and cool the furnace. But, at the same time, the boiler must fire more
fuel to generate the same quantity of steam and proportionately greater
amounts of air are fed through the burner. Consequently, greater
amounts of gas pass through the boiler so quickly that they retain their
heat instead of transferring it to the tubes. This explains why stack
temperatures generally increase as the excess 0 is raised, contributing
to reduced efficiency.
r
It would be desirable to operate at .the point of peak efficiency
at each firing rate to minimize fuel wastage. However, as described
later in this manual, there are certain limitations in typical boiler
combustion controls which require that boilers be operated at some
point slightly below peak efficiency to avoid combustibles and poten-
tially unsafe conditions.
Figure 3 illustrates that there are significant changes in ef-
ficiency losses as the firing rate is varied. Especially obvious are
the "radiation loss" which increases at lower firing rates and the
"dry flue gas" loss which increases at higher firing rates. These
characteristics and the "total efficiency loss" curve shown in the
figure are very representative of many industrial boilers. Lowest
losses (highest efficiencies) occur over the range of firing rate
from approximately 50% to 80%'of capacity. Operating the boiler in
this range as much of the time as possible would therefore be de-
sirable from a fuel efficiency standpoint.
15
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300 400 500
STACK TEMPERATURE, °F
600
Figure 4. Curve showing percent efficiency improvement per every one
percent reduction in excess air. Valid for estimating
efficiency improvements on typical natural gas, #2 through
#6 oils and coal fuels.
6001/8300-461
16
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PERCENT EFFICIENCY IMPROVEMENT PER 10°F STACK TEMPERATURE REDUC
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1 0 10 20 30 40 50 60 70 80 90 ICO
BOILER EXCESS AIR, PERCENT
Figure 5. Curve showing percent efficiency improvement per every
10°F drop in stack temperature. Valid for estimating
efficiency improvements on typical natural gas, #2
through #6 oils and coal fuels.
6001/8300-461
17
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Later in this manual, the basic approach and test equipment
necessary to identify the point of maximum efficiency will be de-
scribed in detail. Once this information is available for a particular
boiler, it can be used together with NO emissions measurements to de-
termine the optimum boiler operating practice for high efficiency and
reduced NO .
x
The efficiency improvement for a boiler at each firing rate
will depend on the reductions in excess O possible and the stack tem-
peratures. To aid in determining the actual efficiency improvements,
Figure 4 gives the approximate percent efficiency improvement corres-
ponding to each 1% reduction in excess air. Since reductions in excess
0_ will be measured directly, use Figure 1 to convert excess O to ex-
cess air and then determine the efficiency improvement at the proper
stack temperature. For example, if the excess O was reduced from 6%
to 3.5%, from Figure 1 it is determined that the excess air dropped
from 40% to 20%, a 20% total change. If the stack temperature was
400°Fvthe efficiency improvement was 20 times .058 or 1.16 percent.
Reductions in stack temperature will also generally occur as
the excess O is lowered. To account for this effect, perform the
previous calculation using the initial stack temperature and add to
this improvement the efficiency improvement obtained from Figure 5.
This additional improvement from Figure 5 is the effect of reduced
temperature and is determined using the final lower excess air level.
To illustrate, if in the previous example, the stack temperature
dropped from 400°F to 370°F, as the excess 0_ was lowered from 6% to
3.5%, the effect due to the 30°F lower stack temperature would be 3
times .252 which equals .76 percent. The total improvement in ef-
ficiency is then 1.16 plus .76 for a total improvement of approxi-
mately 1.92 percent. Figures 4 and 5 can be used to estimate ef-
ficiency improvements achieved at constant firing rates on natural
gas, #2 through #6 oils and common bituminous and subbituminous coals.
18
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Some boiler operators who use these guidelines may find that
their boilers' efficiency can be improved by 1 or 2 percent which
might at first seem to be a small improvement having little effect on
total fuel costs. However, even for the smallest boilers, these seem-
ingly small improvements can lead to significant annual fuel savings
which easily justifies the time and effort spent in achieving the im-
provements. Consider, for example, a 10,000 Ib/hr boiler that is
operated year-round with an average annual loading of one-half full
capacity. If the efficiency is improved by 2 percent over the boiler
operating range, the annual fuel consumption will decrease by 2.5
percent, assuming the boiler efficiency is approximately 80 percent.
(Percent fuel reduction equals efficiency improvement times 100, divided
by the efficiency.) If the boiler is fired with #6 oil costing $2.00
per million Btu, the annual fuel savings would be nearly $2,800. For
larger boilers, this savings would increase in proportion to the size
of the boiler ($28,000 for a 100,000 Ib/hr boiler and so on).
19
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SECTION 3.0
PREPARATION FOR BOILER TESTS
To reduce NO emissions and improve boiler operating efficien-
cies, it will be necessary to determine how NO and efficiency vary as
a
boiler adjustments are made. To successfully accomplish this will re-
quire a preliminary boiler inspection to assess the existing condition
of the furnace, burner equipment and firing parameters. Completing any
necessary repairs and adjustments will insure that the subsequent ef-
ficiency and emission results are representative of the most favorable,
as-designed, condition of the boiler. In some cases, this first step
will itself directly lead to efficiency improvements and reduced NO
x
emissions.
The other essential part of the efficiency improvement/NO re-
X
duction guidelines involves the actual testing to establish the optimum
boiler adjustments. Discussion items will include boiler instrumen-
tation, visual furnace observation, stack emission measurements and
data sheets. Some of these areas involve procedures and equipment
which have not traditionally been a part of routine boiler operating
practice. Since much of this material may be new to most industrial
boiler operators, a discussion of these items before describing the
step-by-step test procedure would be helpful.
3.1 PRELIMINARY BOILER INSPECTION
Even when boiler equipment is in poor operating condition,
"best" boiler settings for improved efficiency and reduced NO em-
issions can still be found under these conditions using the test pro-
cedures in the' following section of the manual. However, it is stressed
that these efficiency and NO emission improvements obtained under a
A
deteriorated state of the boiler can be substantially less than the
improvements achieved when the boiler equipment is in proper working
order. To attain maximum fuel savings and lowest stack emissions, it
20
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is essential that the condition of the boiler be examined prior to test-
ing and that any necessary repairs or maintenance be completed.
A comprehensive list of maintenance items which can affect
boiler efficiency and NO emissions is provided in Reference 4. This
list is a useful supplement to the manufacturer's boiler operating and
maintenance manual and both should be used to ready the boiler for the
efficiency and emission tests. Prior to making extensive adjustments
and/or repairs, the manufacturers' field service department or other
combustion consultants should be consulted. Some of the more common items
to be included in the preliminary boiler inspection are summarized below.
3.1.1 Burners
For oil firing, make sure that the atomizer is the proper design
and size for the type of oil and burner geometry. (There may have been
a mix-up between boilers when oil tips were removed at the cleaning
bench.) Inspect the oil tip passages and orifices for excessive erosion
and remove any coke or gum deposits to assure a proper oil spray pat-
tern. Check to see that oil temperatures at the burner are at recom-
mended levels. (See Section 4.3.) Atomizing steam, if used, must be
at the proper pressure. Make sure that burner diffusers are not burned
off or broken and are properly located with respect to the oil gun tip.
Also check that the oil gun is positioned properly within the burner
throat. Any damaged or missing burner throat refractory should be re-
placed. Oil strainers should be in place and clean.
When firing natural gas, inspect the gas injection orifices
and verify that all passages are unobstructed. Filters and moisture
traps should be in place, clean, and operating to prevent plugging
of gas orifices. Proper location and orientation of diffusers,
spuds, gas canes, etc. should also be confirmed. Look for any burned
off or missing burner parts.
21
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Pulverized coal burner components such as pulverizers, feeders,
conveyors, and primary/tempering air ducts must all be working properly.
Coal fineness should be within recommended limits. All coal pipes should
be cleared of any coal and coke deposits. Check burner parts for any
signs of excessive erosion or burn-off. For stoker boilers, the grates
must be no excessively worn causing poor burn-out in the bed or high
carbon carryover. Make sure that spreaders are working properly and
are in the correct location. Confirm the proper positioning of all air
proportioning dampers. Proper coal sizing is also important. To mini-
mize unburned carbon losses, the cinder reinjection system must also be
operating correctly.
3.1.2 Combustion Controls
All fuel valves should be inspected to verify proper movement
and clean internal surfaces. Gas and oil valve surfaces may erode with
time. There should not be excessive "play" in control linkages or air
dampers. Fuel supply inlet pressures to all pressure regulators should
be adequate to assure constant regulator outlet pressures for all firing
rates. Atomizing steam or air systems also deliver proper flows. Cor-
rect any control elements which fail to respond smoothly to varying
steam demand. Unnecessary cycling of firing rate due to improperly
adjusted regulators or automatic master controllers can waste fuel.
All gauges should be functioning and calibrated to aid in identifying
any control problems as they occur. All safety interlocks and boiler
trip circuits must be operable.
3.1.3 Furnace
Inspect gas-side boiler tube surfaces for excessive deposits
and fouling. These lead to higher stack temperatures and lower boiler
efficiencies. Poor firing conditions may be the cause of tube deposit
problems but proper operation of sootblowing equipment should also be
checked. Periodic cleaning of tube surfaces may be a practical solu-
tion when burners and sootblowers are found to be operating as designed.
22
-------
Repair any leaks in the boiler gas passages and baffling.
Furnace refractory and insulation should also be inspected and
any casing leaks and cracked or missing refractory repaired.
Furnace inspection ports must be cleaned and operable since
visual flame observations will be an essential part of the boiler
testing. Inspection ports should provide a view of the burner
throat, furnace walls and leading convection passes.
3.2 STACK INSTRUMENTS
Boiler adjustments to improve efficiency and reduce nitrogen
oxide emissions cannot be attempted without proper stack in-
strumentation. To successfully carry out these tests in a safe
manner, it will be necessary to measure the following quantities at
the stack:
excess oxygen (or carbon dioxide)
carbon monoxide
. oxide's of nitrogen
opacity (smoke density)
stack temperature
These measurements must also be accompanied by visual furance
observations to assure acceptable flame conditions.
3.2.1 Excess Oxygen
Excess oxygen concentration in industrial boiler stacks can
vary from a fraction of one percent to 10% or more depending on
boiler design, type of fuel, burner adjustments and firing rate.
As described in Section 2.3 the lowest practical excess 0 is
usually the preferred condition for highest efficiency. It will
be shown later that NO emissions also are generally reduced by op-
J\
erating with lower excess 0_.
23
-------
Oxygen can be measured using portable analyzers when the
boiler is not already equipped with C^ meters. Reasonable accuracies
can be obtained with an Orsat analyzer by an experienced technician
using fresh chemicals. Other handheld chemical-absorbing type
analyzers and "length of stain" (color-sensitive tubes) devices are
commercially available. Portable or mounted electronic instruments
with high accuracies are also available.
Whether using a built-in 0 analyzer or a portable instru-
ment, their proper calibration is essential for accurate readings
and successful boiler adjustments. Follow the recommended calibration
procedure for the instrument and adjust the frequency of calibration
as necessary to minimize calibration "drift." By all means, start
with a fresh calibration when beginning the boiler tests. When cali-
bration gases are required, cross check newer gases, when delivered,
with older ones to catch any errors in the calibration gas itself.
For analyzers involving absorbing chemicals (such as Orsat analyzers),
make sure the absorbing chemicals are fresh and establish a routine
for renewing chemicals based on the number of samples analyzed and the
age of the chemicals. These general remarks concerning instrument
calibration also apply to the other stack measurements.
3.2.2 Carbon Monoxide
On natural gas fired boilers, carbon monoxide (CO) is the
primary indicator of incomplete combustion and will usually determine
the lowest practical excess 0 for the boiler. Carbon monoxide
concentration in the stack gases should not exceed 400 ppm once
the final boiler adjustments are made. For purposes of testing,
*Some city ordinances, industry codes and insurance organizations re-
quire that CO not exceed this value.
24
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occasional CO levels of up to 1000 or 2000 ppm can be acceptable pro-
vided adequate boiler monitoring and flame observation are possible
to assure stable conditions. Use caution at these conditions. Further
reducing the excess air will result in very rapid increases in CO and
other combustibles which can lead to smoking, flame instability, furnace
pulsation and boiler explosions.
Carbon monoxide measurements on oil and coal fired boilers are
not generally mandatory since smoking or excessive carbon carryover
will usually precede any substantial CO emissions. However, this cannot
always be anticipated. For example, high CO levels have been measured
in cases where burner equipment has deteriorated or malfunctioned (burned
off impellers, plugged oil tips, insufficient overfire air, etc.). High
CO emissions can also be encountered at high excess 0 levels where the
air flow has been increased to the point of influencing flame stability.
For this reason, it is recommended that CO measurements be included on
all boilers to assure that there ar§ nb burner equipment problems com-
plicating the efficiency and NO emission test results.
The CO analyzer should be capable of measuring up to 2000 ppm
and should also have sufficient sensitivity to measure down to the
100 ppm range. Orsat analyzers have traditionally been used for
CO determinations but difficulties in accurately reading the lower
CO concentrations (less than 1000 ppm) has spurred the use of hand-
held "length of stain" type detectors which reportedly provide the
necessary sensitivities and measurement range. Portable or mounted
electronic instruments are also available.
3.2.3 Oxides of Nitrogen
To assist in selecting NOX instrumentation with the proper range
of measurement, the following table shows the range of NOX emissions
found during field testing at industrial boilers throughout the
country (Refs. 1» 2 and 5, and other sources.) These NOX emission
25
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levels generally correspond to boiler firing rates near 80 percent
of rated load. Since NO usually increases with firing rate, these
values are close to the highest NO emissions found during normal
boiler operation. Note that higher NO emissions also generally occur
X
on boilers equipped with combustion air preheaters.
Typical Range of NOx Emissions, ppm
Without Air With Air
Fuel Type Preheaters Preheater
Coal:
Pulverized 300-600 400-800
Stoker 200-400 250-450
Cyclone 800-1100 900-1500
Fuel Oils:
#2 .50-250 100-300
#5 (PS 300) 200-400 200-600
#6 200-400 200-600
Natural Gas: 50-200 100-400
Total NO emissions from industrial boilers consist mainly
X
of nitric oxide (NO) with the remainder made up of small quantities of
nitrogen dioxide (NOo)• Since NO comprises more than 90% of total NO
X
and accurate N02 measurements are difficult, NO measurements are often
taken as representative of total NOx emissions from the boiler. There
are a number of commercially available electronic instruments capable
of measuring NO in concentrations typical of industrial boilers. They
may differ significantly in measurement method, accuracy and price.
Selection should be made with the guidance of a reliable vendor. Less
expensive hand-held "length of stain" detectors sensitive to total
NO (NO plus NO ) are also available.
A £,
26
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To properly interpret NOx emission results, the measured NO
reading obtained from the analyzer must be corrected to account for
diluting effects of excess air in the flue gas. This is important
when boiler excess air is varied and it is desired to know the
resulting effect on NO emissions. For example, as excess air is
raised, NO formation in the furnace may increase, but at the same
X
time, the additional air will dilute the flue gas and measured NO
X
readings at the stack may actually be reduced.
To illustrate this point further, suppose a large air fan is
installed at the boiler outlet to inject large quantities of outside
air into the flue gas. The operator could then adjust the fan to
dilute the stack gases and obtain any desired NOx concentration less
than the furnace outlet concentration. However, if NOx readings are
corrected to some standard excess air (or excess O ) condition, the
"corrected" NOx values will be the same regardless of how much diluting
air is added. The purpose of correcting NOx readings is not to
prevent the use of diluting air fans or other similar devices. The
primary purpose is to provide a consistent basis of comparing NO
X
emissions and to eliminate the diluting effect of excess air when
making these comparisons.
The accepted industry practice is to correct NO readings to a
• X
standard condition of 3% excess O . To do this, multiply the measured
NO reading in ppm (measured on a dry or moisture-free basis) by an
X
0 correction factor which is easily calculated. To determine the O
correction factor, divide 18 by the quantity 21 minus the percent ex-
cess O measured in the stack, as shown below:
18
O. correction factor =
For example, if the NO reading in the stack is 200 ppm and the excess
O at the same time is measured as 5.0%:
27
-------
Corrected NO equals raw NO multipled by the 02
X X
correction factor, or.
Corrected NO = (raw NO ) x (0_ correction factor)
X X ^
= 200 x 18
21 - 5.0
-200, if
= 200 x 1.125 = 225 ppm
Remember that the corrected NO will not necessarily remain constant as
boiler excess air is varied (since NO formation is not constant).
X
Raw NO readings must be obtained at each 02 level and then corrected
for the corresponding 02-
3.2.4 Stack Opacity (Smoke Density)
Smoking with oil and coal fuels is a certain indication of flue
gas combustibles or unacceptable flame conditions and should always be
avoided. Some oil and coal fired boilers (especially larger capacity
boilers) are equipped with a smoke detector which can be very useful
in providing indications of poor stack conditions when properly cali-
brated. Ultimately, acceptable stack conditions are always confirmed
by visual observation of the stack.
Accurate smoke measurements can be made on smaller boilers using
inexpensive portable hand pump, filter paper testers. These provide
spot check measurements but cannot be used for continuous stack moni-
toring. These devices use the smoke spot number or ASTM smoke scale
(ASTM D2156) and can be very helpful in setting up optimum boiler
operating conditions.
28
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3.2.5 Stack Temperature
Tube deposits and fouling on the external tube surfaces of a
watertube boiler or similar gas side conditions in the gas tubes
of a firetube boiler will inhibit the absorption of heat in the
boiler and lead to lower efficiencies. This condition will be re-
flected in high flue gas temperatures when compared to "clean"
conditions at a similar firing rate and boiler excess air. The
resulting loss in boiler efficiency can be closely estimated on the
basis that a 1% efficiency loss occurs with every 40°F increase in
stack temperature. It should be mentioned that water side deposits
resulting from inadequate water treatment would also eventually
lead to higher stack temperatures, however, tube failures due
to overheating generally occur before any substantial efficiency
losses are evident.
Stack temperature measurements are an easy and effective means
for monitoring boiler tube cleanliness conditions. Stack temperatures
should be periodically compared to values obtained during start-up
or following a boiler tube wash to determine any deviations from
"clean" baseline temperatures. Since stack temperature usually
increases with firing rate and excess air, these comparisons should
be performed at similar boiler operating conditions. In the absence
of any previous data, the stack gas temperatures will normally be
about 150 to 200°F above the steam temperature in a saturated steam
boiler at high firing rates. Naturally, this does not apply to
boilers equipped with economizers or air preheaters. The boiler
manufacturer should be able to supply a normal range of stack
temperatures for the particular boiler design. When higher stack
temperatures are measured, boiler tube cleaning may be warranted.
29
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3.3 FLAME APPEARANCE
The appearance of an industrial boiler's flame can provide a
good preliminary indication of combustion conditions. It is difficult
to generalize..the characteristics of a "good" flame since there is a
certain amount of operator preference and variations due to burner
design involved. This is especially true for stoker-fired coal boilers.
For other types of combustion equipment, flames of a definite appear-
ance have usually been sought. Short, bright, crisp, and highly turbu-
lent oil and pulverized coal flames have been desired. Blue, slightly
streaked, or nearly invisible flames have been sought for gas fuels.
(However, operation with low NO emissions at reduced excess 0 levels
X fc
may result in a different flame appearance as discussed on the next
page.) Stability of the flame at the burner and minimum furnace vibra-
tion are also universally desired. For underfed stoker boilers, an
even bed and absence of carbon streamers are important criteria.
All too often, good flame appearance is achieved by operating
with excess 0 levels higher than necessary for safe, clean firing.
Reducing the excess 0 to the lowest practical levels for the boiler
is the primary concern of these guidelines.
At the other extreme, firing with insufficient excess 0 has
also been encountered at industrial boiler installations. This con-
dition is usually limited to natural gas firing where very high
combustibles can occur with improper burner settings and inadequate
combustion quality checks. These guidelines are intended to assist in
correcting both conditions.
30
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When firing with the lowest practical excess 0 , approximately
the same amount of heat energy is released in the furnace for a given
amount of fuel heat energy input. However, this process may take a
longer period of time and utilize more furnace volume before the
fuel is completely burned. The result of low excess 0_ firing is a
flame which may have the following typical characteristics:
Flames that actually grow in volume and more
completely "fill" the furnace
Flames exhibiting a lazy "rolling" appearance.
Instead of intense, highly turbulent flames, low 0
flames may appear to flow somewhat slower through
the furnace.
The overall color of the flame may change as excess 0
is lowered. Natural gas flames become more visible or
luminous with yellow or even slightly hazy portions.
Coal and oil fires become darker yellow or orange and
may appear hazy in parts.
These characteristics are, for the most part, contrary to flame con-
ditions traditionally desired by industrial boiler operators for
clean, dependable firing. While this might seem discouraging, it is
stressed that safety, reliability, and low particulate and soot emissions
can still be achieved with low 0 firing. This is true only if the
required stack measurements are made and recommendations in these
guidelines are followed. It should be mentioned that in many cases,
firing with low excess O will not necessarily produce any drastic
changes in flame appearance.
You may find that the boiler is already being fired with the
lowest practical excess 0 . If this is the case, these guidelines
will still be of benefit by helping to assure that high efficiencies
and low NO emissions will be maintained.
x
31
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3.4 STACK SAMPLING TECHNIQUES
To obtain measurements of excess 0,, CO, NO , and smoke,
2 x
most of the analyzers previously mentioned require that a sample of
flue gas be withdrawn from the stack and delivered to the analyzer.
Some analyzers require a continuous flow of sample until^a'"steady"
reading is obtained, while others require only a small volume of
sample at one time. An exception are analyzers mounted "in-stack"
with detector elements located in the flue gas stream. Regardless
of the analysis technique, it is essential that the portion of the
stack gases analyzed be a representative sample of the bulk of the
stack gas flow.
The location of the sampling site at which the sample of flue
gas is obtained is as important as the selection of proper measurement
devices. Air leakage into the gas ducts on negative draft boilers
can dilute the flue gas, and consequently, measurements will not give
true indications of furnace conditions. Air leakage in air preheaters
poses the same problem. When selecting a sampling site, choose it
upstream of the air preheater or any known air leaks when possible.
Seal all known air leaks upstream of the sample location.
The sample site should also be removed from an area where the
flue gas is highly turbulent, such as immediately downstream of
bends, dampers, or induced draft fans. Flue gases can stratify or
form "pockets" which can lead to errors especially when samples are
withdrawn from a single point in the duct. When a single-point sample
probe is used, it is recommended that readings at several points in
the duct be compared to determine the most representative probe
location. When existing sample ports are not adequate, it is well
worthwhile to drill or cut out new ports to obtain accurate,
reliable measurements.
32
-------
Flue gas temperatures are also subject to stratification in
the ducts and a representative location of the thermometer or other
temperature sensors should be verified. The location should be close
to the boiler outlet since temperature losses can occur in the flue
gas ducting, especially in uninsulated sections.
3.5 BOILER TEST PROCEDURES
The two major aspects of the boiler testing are (1) de-
termining the optimum boiler firing conditions over the turndown
range, and (2) making the burner adjustments necessary to maintain
these optimum conditions during normal automatic operation. The
step-by-step test procedures in the following section deal mainly
with the first aspect.
The second part of the testing is very dependent on the par-
ticular design of the boiler controls. To successfully accomplish
the burner adjustments will require a working knowledge of the control
system. For example, its design will dictate to a large extent the
#
number of firing rate conditions necessary to be examined. An
adjustment at one firing rate may affect conditions at other firing
rates and these effects must be recognized and anticipated. It
would not be desirable to improve efficiency and NO emissions at
one firing rate only to create poor conditions at another. It is not
within the scope of these guidelines to supply detailed combustion con-
trol knowledge. Rather, it is intended that the boiler operation and
maintenance manual supplied with the boiler will provide the necessary
information and that any further questions can be directed to the plant
engineering staff, the boiler manufacturer or other combustion specialists.
It is also assumed in these guidelines that it will not be
necessary to elaborate on appropriate methods for varying burner
excess air. Again, this will be dependent on the design of the burner
and controls and can involve any number of air flow control devices
33
-------
such as forced draft fan inlet dampers, windbox dampers or stack
draft dampers-. Final adjustments to achieve the correct excess 0
can involve adjustments to jackshaft .control linkages, fuel valve
cam profiles, fuel/air set points, etc.
The key word in applying combustion modifications is CAUTION.
Be careful while making any adjustments and know at all times the
impact on fuel flow, air flow, or the control system. Make sure that
all boiler safety interlocks and trip circuits are functioning.
Consult plant engineering personnel or the boiler manufacturer if
you have any uncertainty about the procedures or expected outcome
of any adjustment. Flame appearance can give many clues as to
combustion conditions—observe the fires, but don't rely solely on
flame appearance. As described is Section 3.3, flame appearance
can change for low NO operation. Carefully watch boiler instrumen-
X
tation and the stack while making changes. If in doubt, always check
for combustibles (CO) in the flue gas. Conducting these tests may
require additional manpower so that controls and instrumentation,
flame appearance, and stack conditions can be monitored simultaneously
during adjustments. All personnel should be familiar with the test
objectives and fully instructed regarding their part in the test.
To obtain maximum benefit from the boiler tests, all per-
tinent test data should be recorded. The permanent record of
boiler operating conditions and stack measurements will not only
document the boiler's efficiency and emission characteristics, but also
enable future comparisons to help diagnose any efficiency or emission
problems. The test data should be recorded on prepared data sheet
forms and include the following items:
34
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1. Identification of boiler, fuel type, date of tests
and names of operating personnel involved.
2. Steam, feedwater and fuel conditions (flow rates, pressures
and temperature) to document boiler firing rate
and steam generation.
3. Combustion control position and burner settings.
4. Furnace pressures, temperatures, and damper settings.
5. Stack measurements (02/ CO , CO, NO , smoke, tempera-
ture) . Make note of sample probe position.
6. All relevant comments on flame appearance, carryover
and furnace conditions.
7. Record any new permanent changes made to combustion
controls or burner settings.
The actual boiler readings included will of course depend on
the available instrumentation. Make sure that adequate data are
obtained so that exact boiler operating conditions can be repeated
fer future comparative purposes. A sample data sheet is shown in
Figure 6, but additions or deletions will most likely be necessary
for each particular boiler. It may be worthwhile to review the final
form of the data sheet with the engineering staff and incorporate
any additional data entries that may be of mutual interest.
Readings should be recorded only after steady boiler con-
ditions are reached. This is usually indicated by steady stack "
temperature, fuel input, steam conditions (pressure and temperature
and drum level). Steady excess 02 readings in the stack are a good
indication that fuel and air flows have stablized.
It is very desirable that these tests be conducted at
normal steam pressures. This will assure that stack temperatures and
furnace temperatures are representative of normal operating conditions.
Since it will usually be necessary to control the boiler firing rate
manually during the tests to obtain stable conditions, this may pose
some problems in satisfying normal steam demands. When alternate
35
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NO REDUCTION TEST
x
PLANT
BOILER NO.
TESTS BY
FUEL
DATE
Test No.
Time
Steam Flow, Ib/hr
Steam Pressure, psi
Steam Temp. , °F
Fuel Flow, cfm, gpm, Ib/hr
Fuel Pressure, psi
Fuel Temp. , °F
Atomizing Pressure
Combustion Air Temp. , °F
Flue Gas Temp. , °F
Windbox Pressure, "H2O
Furnace Pressure, "H2O
Stack Pressure, "H2O
Fan Settings
Air Register Settings
Burner Positions
Smoke Density
o2, %
CO, ppm
NOX, ppm
Flame Appearance:
NOTES:
Figure 6. Sample data sheet.
36
6001/8300-461
-------
steam generating capacity is available, modulate the loading at
other boilers to maintain constant system pressures. When this is
not possible, it may be necessary to make provisions to dump unneeded
steam or temporarily interrupt plant processes.
37
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SECTION 4.0
EFFICIENCY IMPROVEMENT AND NO REDUCTION TECHNIQUES
The principal method described in this manual for improving
boiler efficiency and reducing NOx emissions involves operating the
boiler at the lowest practical excess 0 level. These 0_ levels will
^. fc
be at some operating margin above the absolute "minimum 0 " which is
at the threshold of smoke or combustible emissions formation. Although
peak boiler efficiency will occur close to the minimum O , it is not
practical to operate at this condition unless the boiler is equipped
with highly sophisticated combustion controls and flame quality
monitoring to prevent any small deviations into unsafe or unacceptable
combustible conditions. Since these control features are not
typical of most industrial boilers, some margin or operating "cushion"
above the minimum Q will be necessary to accommodate normal
variations in fuel properties and atmospheric conditions, repeatability
and response characteristics of the combustion control system/ and
other operational factors.
This manual provides general guidelines for determining the
lowest practical 0_ levels for a particular boiler. This will
require that the minimum O and the appropriate operating margin
above this minimum 0_ be established and evaluated with respect
to typical levels for the type of fuel and burning equipment used.
If minimum O levels are found to be excessive, then burner adjust-
ments are recommended as a possible means for reducing the burner's
minimum 0_ requirement. High minimum 0_ can also result from
improper maintenance of burner equipment (plugged orifice, broken
diffusers, etc.) but these problems will be minimized by performing
the preliminary boiler inspection (Section 3.1).
38
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The advantage of operating with low excess oxygen from the
standpoint of efficiency has previously been described in Section 2.3.
It was shown that with lower excess 0 , the "dry stack gas losses"
are minimized leading to highest efficiencies.
The advantages of low excess O. with respect to NOx emissions
are illustrated in Figure 7. The curves in the three graphs
show how NOx emissions changed as the excess 0 was varied on a
variety of gas- oil- and coal-fired boilers. It is immediately
apparent that NOx emissions can vary significantly from boiler to
boiler even when compared at the same excess 0 . For the most
part, NO emissions were reduced as the excess O_ was lowered.
X £.
Coal fired boilers had the highest NO emission levels and
X
the NO was generally found to be more sensitive to changes in
X
excess oxygen than the average oil or gas fired units. The fuel
nitrogen content of coal is the major factor in these higher emissions.
w
Industrial boilers fired with natural gas showed the lowest sensitivity
of NO to excess oxygen changes. In some cases, NO actually in-
X X
creased as excess O was lowered. When this occurs, it is still
desirable to operate at low excess O for high efficiency but
attempts should be made to reduce NO emissions by burner adjustments
X
(see Section 4.3) . Alternate NO controls are also described in Appendix A.
X
Setting up a boiler for low excess O firing will be
accomplished through a systematic, organized series of tests.
Following a test that documents "as found conditions," the lowest
possible level of excess oxygen for the boiler will be established.
The lowest level should be found at several firing rates within the
boiler's operating range. The actual number of firing rates tested
will depend on the design of the boiler control system. Enough
firing rates should be tested to assure that after the final control
adjustments are made, the optimum excess O conditions are maintained
at all the intermediate firing rates. At each firing rate tested, the
39
-------
o
df
o
JJ
13
o;
4J
o
CD
0,
a
c
.2
01
-------
excess 0 should be varied over a range from 1 or 2% above the
normal operating point down to the point where the boiler just
starts to smoke or the CO emissions rise above 400 ppm. This low
excess O condition is referred to as the smoke or CO threshold
(limit) or simply the "minimum 09." The smoke limit applies to coal
and oil firing since smoking will generally occur before CO emissions
reach significant levels. The CO limit applies to gas fuels and
is the lowest possible excess 0 level while maintaining carbon
monoxide below 400 ppm.
The smoke limit for coal or oil fuels is the lowest possible
excess O level where acceptable stack conditions can still be
maintained. In terms of the Smoke Spot Number (SSN) scale, the
maximum desirable smoke number on coal fuel for acceptable stack
conditions is SSN 4 (measured downstream of the dust collector).
For fuel oils, the maximum smoke levels are (Ref. 6):
Maximum Desirable
Fuel Grade SSN
NO. 2 less than 1
No. 4 2
No. 5 (light and heavy), 3
and low-sulfur resid
No. 6 4
When performing the boiler tests to determine minimum
excess O_ , curves such as those in Figures 8 and 9 will be
constructed. Based on measurements obtained during the tests,
these curves will show how the boiler smoke and CO levels change
as the excess O is varied. Each of the figures contain two
distinct curves to illustrate the extremes in smoke and CO behavior
which may be encountered. The curves labeled (1) exhibit a very
41
-------
C/3
D
Z
J-)
o
a
03
0
c/j
Low Air Settings
Curve (2
High Air Settings
Test Points
Curve (1
Appropriate Operating
Margin From Minimum O
Automatic Boiler
Controls Adjusted
to This Excess O_
Minimum 0
Percent 0_ in flue gas
Curve 1
Curve 2
Gradual smoke/0_ characteristic
Steep smoke/0 characteristic
Figure 8. Typical smoke-O characteristic curves for coal or oil-fired
industrial boilers.
6001/8300-461
42
-------
E
a
a*
0)
3
O
u
Low Air Settings
High Air Settings
Curve 12,
Test Points
Curve (1
CO Limit (400 pptn)
Minimum 0
Appropriate Operating
Margin From Minimum O,
Automatic Boiler
Controls Adjusted
to This CL
Percent O_ in flue gas
Curve 1
Curve 2
- Gradual CO/0 characteristic
- Steep C0/02 characteristic
Figure 9. Typical CO-0 characteristic curves for gas-fired industrial
boilers.
6001/8300-461
43
-------
gradual increase in CO or smoke as the minimum 0 condition is
reached. In contrast, the curves labled (2) are gradual at first
but as the excess 0 is reduced further and minimum 0 is approached,
the smoke or CO emission increases rapidly. In this case,
unpredictably high levels of smoke or CO or potentially unstable
conditions can occur with small changes in excess 0 and extreme
caution is required. When making O changes near the smoke or CO
limit, do so in very small steps until there are enough data to show
whether the boiler has a gradual or steep characteristic curve for
smoke and CO [curve (1) versus curve (2)] . It is important to note
that the boiler may exhibit a gradual smoke or CO behavior at one
firing rate and a steep behavior at another.
High minimum 0 may be an indication of a burner mal-
function or other fuel or equipment related problems. But it should
also be realized that different burner designs and fuels will in
general have different minimum O requirements. Many burners will
also exhibit higher minimum O at lower firing rates. »For these
reasons it is difficult to specify in these guidelines a
range of minimum 0 levels which would be considered normal.
However, based on numerous minimum O tests at industrial boiler
installations, the following table has been prepared to assist
in judging whether the minimum O levels that are measured are
typical values.
Typical Range of Minimum
Excess- ©2 At High
Fuel Type Firing Rates
Natural gas 0.5 - 3.0%
Oil fuels 2.0 - 4.0%
Pulverized coal 3.0 - 6.0%
Coal stoker 4.0 - 8.0%
44
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Boiler start-up records showing initial excess 0 conditions
can provide a valuable comparison with current minimum 0 conditions
when they are available. If it is apparent that current minimum 0_
levels are higher than the expected levels, there may be a need for
maintenance or repairs which should be completed before attempting the
followint excess 0. optimization procedure.
Once the minimum 0 is established, the next step will be to
determine the appropriate 0_ margin or operating "cushion" above the
minimum 0 where the boiler can be routinely operated. This will be
the lowest practical O for the boiler and will be the optimum setting
for high efficiency (and in most cases, lowest NO emissions). The 0
X ^
margin above the minimum 0 is necessary to account for uncontrollable
variations in the excess 0 resulting from:
1. Rapid boiler modulation which could result in smoking
or combustibles without an adequate O margin.
2. Non-repeatability or "play" in the automatic controls
(excessive "play" should be corrected).
3. Normal variations in atmospheric conditions- which
can also change excess 02 on units not equipped with
temperature and pressure-compensated combustion air
systems. This is a very important factor which is
often neglected. (Extreme variations in ambient
conditions can easily produce changes in excess 0
of 1% or more.)
4. Changes in fuel properties which may require varying
amounts of excess air.
Typical 0 margins above the minimum 0 may range from 0.5% up to 2.0%
0 , depending on the characteristics of the particular boiler control
system and fuels. If in doubt, consult the boiler manual or the manu-
facturer. When the boiler is going to be operated at a constant firing
rate for extended periods, -the lowest possible O margin should be
selected.
45
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A simple test to determine whether there is excessive "play"
(or poor repeatability) in the boiler controls can be made by simply
repeating a firing rate condition, allowing the fuel and air controls
to function in a normal manner. When performing this test, approach
the particular firing rate' from both the "high side" and "low side",
(i.e., from higher and lower firing rates). A comparison of stack
excess 0 after the boiler has stabilized indicates whether
there is excessive wear or tolerance problems in air dampers,
control shafts, valve cams, controllers, etc. Excess 0 should
repeat to within a few tenths percent excess 0 .
Atmospheric variations are reflected in excess O variations
due to changes in air density at the forced draft fan inlet as the
air pressure and temperature change. The fan will deliver a certain
volume of air to the burner, but as the air density changes, the
pounds of air supplied to the burner will vary, thus changing the
burner excess air and excess O . When combustion air is supplied
from the boiler room, maintaining constant boiler room temperatures
will minimize this problem, but atmospheric pressure effects are
unavoidable.
The boiler adjustments described below are intended for
boiler operators who will make their own NO reduction and boiler
X
efficiency improvement adjustments. For those who do not prefer to
make their own adjustments, manufacturer's service organizations
and combustion consultants perform these adjustments in what
generally is referred to as a combustion "tune-up." More information
on "tune-up" costs, what they include, and special requests to the
tune-up crew are found in Reference 4 , "Industrial Boiler Users'
Manual — Methods and Equipment for Efficiency Improvement." This
reference also describes other operating and manufacturer practices
that improve efficiency, and efficiency improvement equipment currently
available.
46
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4.1 STEP-BY-STEP^BOILER ADJUSTMENT PROCEDURE FOR LOW EXCESS
O OPERATION
1. Bring the boiler to the desired firing rate and put
combustion controls on "Manual." Make sure all safety interlocks
are still functioning. It is often convenient to use a felt tip pen
to mark the linkage setting to retrace the direction and position of
the adjustments.
2. After the boiler has stablized, observe flame conditions
and take a complete set of boiler and stack readings. This will serve
to document the existing operating conditions at the particular
firing rate. If the current excess O is found to be close to the
lower range of typical minimum O_ values in the previous table and
if CO and smoke are at acceptable levels, it is quite possible that
the boiler is already operating near the optimum excess O at this
particular firing rate. It may still be desirable to proceed through
the following steps to -determine whether lower excess C- levels are
practical. In any event, do not assume that O settings at other
firing rates are also close to the optimum.
3. Raise the excess air until the stack excess O has in-
creased by 1 or 2 percent. Take readings after the boiler has
stablized and note any changes in flame conditions.
4. Return excess air to the normal level and then begin to
slowly reduce the excess air in small steps. Watch the stack for any
signs of smoke and constantly observe the flame. Take a set of stack
readings following each change. Do not attempt to reduce the air
by throttling the burner air registers as this alters the fuel and
air mixing characteristics and complicates the tests. Watch out for
low windbox/furnace pressure emergency shutdown safety interlocks
("fuel trip" set points) at low firing rates.
5. Continue to reduce the excess air stepwise until one of
the following limitations is encountered:
47
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Unacceptable flame conditions such as flame impinge-
ment on furnace walls or burner parts, excessive
flame carryover or flame instability.
High carbon monoxide (CO) in the flue gas. The CO
limit is 400 ppm but higher levels not exceeding
1000 to 2000 parts per million are tolerable during
the tests. Use caution since CO can increase very
rapidly with small changes in excess air.
Smoking at the stack. Do not confuse smoke
with water vapor, sulfur, or dust plumes which are
usually white or gray in appearance. The smoke limit
for No. 2 oil is a Smoke Spot No. less than 1 and for
No. 6 oil or coal the smoke limit is Smoke Spot No.
4. Higher smoke might be tolerated for test purposes
but remember to observe any local air pollution
ordinances.
Incomplete burning of coal fuels leading to high
carbon carryover or increased quantities of solid
combustible matter in the refuse.
Equipment related limitations such as low windbox/
furnace pressures or built-in air flow limits.
6. Obtain as many readings of CO, excess oxygen, smoke
number and nitrogen oxides as necessary to establish curves similar
to the samples in Figures 8 and 9. Plot the data on a chart or
graph paper. Correct NOX emissions to 3% 02 (see Section 3.2.3)
and plot on the same graphs to see how NO varies with excess O .
X £
7. The lowest or minimum excess 02 requirement for the
boiler was determined in Step 6 but do not adjust the burner
controls to this value. While this may be the point of maximum
efficiency and lowest NOx, it is usually impractical to operate the
boiler right on the verge of the combustible or smoke threshold.
Compare the minimum O value to the expected value provided
by the boiler manufacturer. Typical values of minimum excess O for
various fuels are also given in a previous table (Section 4.0). If the
minimum 0 is substantially higher than the typical values, burner
48
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adjustments may be possible to improve the fuel and air mixing,
thereby allowing operation at lower 0 levels. (See Section 4.3.)
8. Establish the margin in excess 0 above the minimum 0
required for fuel variations, load changes, and atmospheric conditions.
Add this margin to the minimum excess 0 and reset the burner controls
to maintain this excess 0 when operating on automatic.
This is the lowest practical excess 0. for the boiler at
the particular firing rate. The boiler efficiency at this condition
is as close as practical to the peak efficiency which usually
occurs near the minimum excess 0 . For most boilers, NO
emissions will be reduced at the new excess O setting. However,
if NO emissions increase from previous levels, it is still desirable
x
to operate at this low excess 0 for high efficiency but attempts
should be made to lower NO by burner adjustments . Alternate
NO reduction techniques requiring special boiler modifications,
engineering design, and economic analysis should also be considered
(see Appendix A).
9. Repeat Steps 1 through 8 for each firing rate to be
tested. For some control systems it will not be possible to set
up the optimum excess ©2 at each firing rate since control adjustments
at one firing rate may also affect conditions at other firing
rates. In this case, use some judgment to choose the best settings
that give good performance for a range of firing rates. A trial-
and-error approach involving repeated tests may be necessary, if
one firing rate is predominant, the setting should be made to optimize
conditions at that rate.
10. After the control adjustments have been completed,
verify that these new settings will be acceptable during sudden
load changes which may occur in daily operation. While making rapid
load pick-ups and drops, observe the flame and stack to establish
49
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any unacceptable conditions. Utilize stack continuous monitors
(0_, CO, opacity) when available. If undesirable conditions are
detected, reset the combustion controls to provide a slightly higher
excess 0_ at the particular firing rates. Verify these new settings
in a similar fashion. Make sure that the final control settings are
documented under steady boiler operating conditions for future
reference.
11. It may be advisable not to perform any adjustments
at or near "low fire." The quantity of excess air at these
conditions is usually dictated by flame ignition characteristics
and stability which can be critical and difficult to evaluate.
If the boiler operates near "low fire" a large fraction of
the time due to sporadic steam demand, the manufacturers' service
organization or other consultants can be helpful in establishing the
best excess 0_ levels.
12. When an alternate fuel is fired, perform these tests
and adjustments for the second fuel. In some cases it may not be
possible to achieve optimum excess 0 on both fuels at all
firing rates. In these cases, use judgment to set up the best
conditions at normal firing rates.
4.2 EVALUATION OF THE NEW LOW O SETTINGS
After the boiler has been set up for low 0 operation and
returned to normal automatic firing, it is good practice to pay
extra attention to the boiler for the first month or two until
confidence is gained in the new operating mode. Watch for any
signs of unusual furnace tube fouling or flame patterns which
might be corrected by further burner adjustments. During the next
boiler shutdown, thoroughly inspect the burner and furnace sur-
faces . Be alert for any equipment or operating changes that may
50
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alter the minimum 0 , fuel flow, or air flow. These might include
changes in fuel properties, inadvertent changes in burner settings,
new boiler control set points, air control damper deterioration,
and air preheater pluggage.
To assure continuous high boiler efficiency and low NO
emissions, periodically make combustion quality spot checks. Compare
stack measurements of 0 , CO, smoke, temperature, and NO to the
£. X
readings obtained during the low 0 testing. The more often this
is done, the less likely that a poor condition will develop to the
point where large fuel wastage and increased air pollution results.
A complete boiler maintenance inspection and audit should also be
performed periodically as outlined in Section 5.2.
4.3 • BURNER ADJUSTMENT
Burner and fuel system adjustments described here are separate
from excess air or combustion control adjustments made in the previous
section. They include such items as changes in:
1. Burner air register settings (on swirl or circular
type burners)
2. Oil burner tip position with respect to the burner
throat
3. Oil gun diffuser position with respect to the
burner tip and burner throat
4. Coal spreader position
5. Fuel oil temperature
6. Fuel and atomizing pressures
7. Coal particle size
These burner adjustments, where applicable, can be useful
in reducing minimum O? requirements of the boiler (resulting in
lower operating excess O_ and improved efficiency) and can also
lead to lower NOX emissions. Lower NOX can be a result of
51
-------
operating at lower excess O-. In addition, some of these adjust-
ments can have direct effects on NO which are evident when there
x
has been no change in excess G>2 » combustibles, and smoke.
The effects of these adjustments on NOx and minimum ©2
are variable from boiler to boiler and difficult to predict. The
primary approach when making these adjustments is therefore a
trial-and-error procedure, but it must be sufficiently organized to
assure adequate stack and flame monitoring when the adjustments
are being made. Observe the general precautions given for the
excess air adjustments. These burner adjustments are best worked
into the excess air adjustment tests (Step 7) since any burner
adjustments must be completed before the final excess 0- adjustments
are made. Also the same stack measurements required when adjusting
excess air will be necessary after each burner adjustment is made
to determine whether the adjustment is producing the desired effects.
Similar to the excess air tests, make all burner adjustments slowly
to allow adequate time to evaluate each move. Be alert for any
changes in burner settings or changes in fuel properties that might
also affect the flow of air or fuel to the burner and produce
uncontrolled shifts in excess 0-.
The range of adjustment possible for the various burner
parameters listed above depends on the design of the burner and its
particular operating characteristics. For example, it may be
possible on one boiler to vary the air register settings from 50%
to 80% open while at another boiler no adjustment is possible. In
the second case, further opening the air register (reducing the
air swirl) may cause flame instability while closing off the
air register (more swirl) may widen the flame causing flame impingement
on the burner throat or furnace side walls. The boiler manual may
provide some helpful information concerning the range of adjustments
possible for the boiler.
52
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An important factor in obtaining complete combustion of
oil fuel at low excess 0 levels is to maintain the proper fuel oil
temperature. The oil firing temperature is dictated by the desired
fuel viscosity which must remain within the range recommended by
the manufacturer. The following table gives typical viscosity
ranges for various oil fuels but observe the range recommended
for each specific burner.
Usual Range of Firing Viscosity
Atomization
Method
Pressure
Steam or Air
Rotary
Saybolt Seconds
Universal
35-150 SSU
35-350 SSU
150-300 SSU
Equivalent
Kinematic
Viscosity /
centistokes
3-32 cs
3-77 cs
32-65 cs
To determine the proper oil temperature which give's the desired
viscosity, use standard viscosity-temperature curves such as in
Figure 10. When available, request viscosity characteristics of each
specific fuel from the supplier.
Coal burning equipment is also designed to give good per-
formance for particular coal particle sizes. The following table has
been compiled from several boiler industry sources (primarily
Refs. 7 and 8 ) and gives typical coal sizes for various burner
designs.
53
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ID
T3
C
o
o
0)
01
JJ
•l-l
in
0
o
ui
(3
t/1
• r-l
C
3
O
XI
(3
CO
10,000
5,000
2,000
1,000
500
400
300
200
150
100
80
60
50
40
60
3,000
2,000
1,000
500
100
50
20
10
en
a;
U)
•-i
0)
U
1/1
o
U
U]
U
•-(
4J
<3
C
100 150
Oil Temperature, °F
200
250
Figure 10. Typical viscosity-temperature relation for various grades
of fuel oil (ASTM D396-75).
6001/8300-461
54
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RECOMMENDED COAL SIZES FOR
VARIOUS BURNER DESIGNS
Underfed
Overfed
Spreader Stoker
Firing Type
Single Retort
Multiple Retort
Chain Grate
Traveling Grate
Vibrating Grate
Stationary Grate
Dumping Grate
Traveling Grate
Vibrating Grate
Pulverized Coal
Burner
Cyclone Burner
Coal Type
Coking and caking,
Free burning
Free burning
All except caking
bituminous
All except caking
bituminous
All types
All types
All types
All types
All types
All types
All types' subject
to ash properties
Sizing
1 to 1-1/2" nut
and slack (<50%
thru 1/4" screen)
2" nut and slack
(<50% thru 1/4"
screen)
1" nut and slack
1" nut and slack
will handle fine
coal
1" nut and slack
less fines pre-
ferred
3/4" nut and slack
3/4" nut and slack
3/4" nut and slack
3/4" nut and slack
Less fines pre-
ferred
70% thru 200 mesh
screen
95% thru 4-mesh
screen
6001/8300-461
55
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SECTION 5.0
MAINTAINING HIGH BOILER EFFICIENCY AND LOW N0_
•—x
Once the optimum boiler adjustments have been achieved,
there are two steps that should be taken to assure that high ef-
ficiencies and low NO emissions are maintained in day-to-day boiler
operation. The first is the combustion efficiency spot check which
can be worked into the daily or weekly operating routine. This
provides an early indication of any efficiency related problems
before large fuel wastage or extensive maintenance is required. The
second step involves periodically performing a more comprehensive
efficiency maintenance audit of the boiler equipment to identify any
necessary maintenance or repairs needs.
5.1 COMBUSTION EFFICIENCY SPOT CHECK
A spot check of combustion conditions utilizing stack
measurements of 0_, CO, smoke, and temperature is an effective
preventive tool. Perform these measurements when the boiler is
operating at steady conditions and compare the results to the measure-
ments obtained during the previous boiler adjustment tests. Keeping
a log of these data will help in identifying any deterioration
in combustion efficiency and the possible causes* Many operators
perform efficiency spot checks on a daily basis or even during each
work shift.
Shifts in boiler excess O might be attributable to
problems in the air or fuel supply or might reflect changes in fuel
properties. Other possibilities might include deterioration in
furnace baffling or setting leakage, excessive tube fouling, air
preheater pluggage or simply changes in atmospheric conditions. If
the excess O has remained constant but smoke or CO has increased,
fuel specifications may have changed or there may be a problem with
burner performance (oil tip pluggage, oil atomizing system problems,
56
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burned off or improperly adjusted burner parts, worn grate, overfire
air system, etc.). Make sure that the proper oil temperature is
being maintained. If stack temperatures have increased 20°F or
more but excess 0 , CO and smoke has remained unchanged, this may
be a preliminary indication of deteriorated furnace baffling, excessive
tube fouling or sootblower malfunction.
5.2 PERFORMANCE MONITORING (BOILER LOG)
Efficiency spot checks are valuable for identifying efficiency
degradation, but longer term performance monitoring (including docu-
mentation in a boiler log) is a more effective means of insuring peak
efficiency. The objective of performance monitoring is to document
deviations from desired performance as a function of time. This infor-
mation should be obtained on a regular basis by the operator under steady
load conditions. Data taken during load changes or under fluctuating
load conditions will be inconsistent and of little value in assessing
unit efficiency, however, control response should be noted during tran-
sient conditions.
If a widely fluctuating load is the normal condition, it may be
necessary to make special arrangements to achieve steady boiler load
for efficiency monitoring either through curtailing intermittent steam
demands or taking load swings on other boilers. If the boiler master
control is placed on manual operation, the fuel/air ratio should be as
established by the control system. The performance recorded under
these conditions will indicate deviation from desired fuel/air ratio
and other performance deviations. By manually adjusting fuel/air ratio
to the desired level, a second set of data can be obtained which repre-
sents performance deviations attributable to sources other than the
fuel/air ratio such as surface cleanliness, boiler baffles, etc.
The actual readings to be taken and the frequency are deter-
mined by the size and complexity of the equipment and the manpower
which can be justified in collecting and analyzing data. The usual
57
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practice at larger boiler houses is to record data hourly as a check on
general performance. These hourly readings are to assure that the unit
is operating normally and includes checking of safety and mechanical
devices.
Efficiency related items which should be included in the boiler
operator's log are:
1. General data to establish unit output
steam flow, pressure,
superheated steam temperature (if applicable)
feedwater temperature
2. Firing system data
fuel type (in multi-fuel boilers)
fuel flow rate
oil or gas supply pressure
pressure at burners
fuel temperature
burner damper settings
windbox-to-furnace air pressure differential
other special system data unique to particular
installation
3. Air flow indication
air preheater inlet gas O
stack gas Q-%
optional - air flow pen, forced draft fan
damper position, forced draft fan amperes
4. Flue gas and air temperature
boiler outlet gas
economizer or air heater outlet gas
air temperature to air heater
5. Unburned combustible indication
CO measurement
stack appearance
flame appearance
6. Air and flue gas pressures
forced draft fan discharge
furnace
boiler outlet
economizer differential
air heater air and gas side differential
58
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7. Unusual conditions
steam leaks
abnormal vibration or noise
equipment malfunctions
excessive makeup water
8. Slowdown operation
9. Sootblower operation
While this list may look extensive and time consuming, the
operator of a firetube or comparable-sized watertube boiler (10,000 to
24,000 Ib steam/hr) will find that the data list will reduce to:
steam pressure
feedwater temperature
steam, feedwater, or fuel flow
fuel supply temperature
boiler outlet gas temperature
boiler outlet C^
FD fan inlet temperature
stack appearance
flame appearance
windbox air. pressure
windbox-to-furnace air pressure differential
boiler outlet flue gas pressure
blowdown operation
unusual conditions or equipment malfunctions
If the unit is too small to justify a continuous O analyzer,
the excess air should be checked by Orsaf analysis weekly. If the
burner is serviced by an outside organization, the frequency should
be at least monthly, and include an excess air determination. Carbon
monoxide determination is particularly important on gas firing since
high CO levels can develop without smoke formation, unlike oil or
coal firing.
If steady load conditions are difficult to obtain, less emphasis
should be placed on the boiler operator's log for efficiency-related
maintenance items and regularly scheduled performance checks should be
made under steady conditions on a monthly basis for smaller units and
59
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on a biweekly basis for larger units. On coal-fired units, monthly
checks on ash combustible content should be made. On pulverized coal-
fired units, coal fineness should also be checked monthly.
Analysis and interpretation of performance data is discussed
in Section 5.4.
5.3 PERFORMANCE DEFICIENCY COSTS
The benefits obtained by maintaining high boiler efficiency are
readily calculated knowing boiler fuel usage (W,.) , efficiency achiev-
able (E ) , efficiency differentia.
A
formance (AE), and fuel cost, (C)
able (E ) , efficiency differential between achievable and actual per-
A
fuel $ saving = W x — x c
t EA
- The units selected must be consistent, that is, if Wf equals
million Btu/year, and C equals dollars per million Btu, the fuel saving
will be in dollars per year.
Usually, achievable efficiency and AE will vary with boiler load.
To evaluate annual fuel savings under varying load conditions, the frac-
tion of operating time spent at each load must be estimated and multiplied
by the fuel consumption rate and the ratio of AE/E for each load condi-
A
tion. The sum of the individual load calculations multiplied by fuel
cost will then equal the annual fuel dollar saving.
To provide some estimate as to the value of a one percent effi-
ciency change/ consider a boiler operating at 10,000 Ib/hr steam flow
for 6/000 hours per year. The heat required to generate one pound of
steam is approximately 1000 Btu divided by boiler efficiency as a deci-
mal fraction. If efficiency is 80%, the annual fuel consumption would be
10,000 * 6,000 x ' = 75,000 million Btu/year
0 . oO
With fuel costs at $2 per million Btu/ the annual fuel bill would be
$150,000.
60
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If efficiency decreased to 79%, the fuel bill would be $151,900,
or $1,900 higher.
If the boiler steam flow were 100,000 Ib/hr and the efficiency
decrease was 2%, the increase in annual fuel cost would be $38,000.
Obviously, more effort can be justified in maintaining efficiency as
boiler output increases and performance deterioration becomes greater.
Efficiency gains through reducing excess air or stack tempera-
ture are shown in Figures 11 and 12. A reduction in excess air is
usually accompanied by a reduction in stack temperature. The actual
temperature reduction is dependent on the initial stack temperature and
the excess air reduction. A 20% excess air reduction will produce approx-
imately a 30°F reduction if the exit gas temperature is in the 500°F to
600°F range, but only 15°F reduction if the exit gas temperature is in
the vicinity of 300°F.
The combined effect can be determined by first evaluating the
efficiency improvement for reduced excess air from Figure 11 and then
adding the efficiency improvement for reduced stack gas temperature
from Figure 12 evaluated at the lower excess air.
Solid combustible losses are of concern principally with coal
firing as discussed previously. Carbon monoxide heat losses can become
significant with gas or oil firing. Carbon monoxide in the flue gas
at a level of 1000 ppm or 0.1% represents a heat loss of approximately
0.35%. Higher CO levels will produce correspondingly higher heat
losses.
5.4 IDENTIFYING CAUSES OF PERFORMANCE DEFICIENCIES
Previous sections have dealt with establishing performance goals
and monitoring performance to determine departures from desired perfor-
mance. The specific deviations from expected performance can be of
considerable value in determining the cause of the performance deficiency,
61
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CTl
KJ
Percent Efficiency Improvement
per 1% Excess Air Reduction
o o o o c
b b b b h
o to £> cr> CD c
/
/
/
/
/
\s
/
s
/
/
/
/
Percent Efficiency Improvement per 10 °F
Stack Temperature Reduction
o o o o o c
NJ ro to u> u> £
O ib CO IU CF> C
/
/
/
\/
/
/
/
/
/
/
/
/
/
/
/
150
Figure 11.
250 350 450 550
Stack Temperature, °F
650
Percent efficiency improvement for
every one percent reduction in excess
air. Valid for estimating- efficiency
improvements on typical natural gas,
#2 through 06 oils, and coal fuels.
0 20 40 60 80 100
Boiler Excess Air, %
Figure 12. Percent efficiency improvement for
every 10°F drop in stack temperature.
Valid for estimating efficiency
improvements on typical natural gas,
#2 through #6 oils, and coal fuels.
6001/8300-461
-------
Deficiencies can be heat transfer related, combustion related, or
can result from unnecessary miscellaneous losses such as high auxiliary
power consumption, excessive blowdown, steam leaks, or defective insulation.
5.4.1 Heat Transfer Related Problems
Poor heat transfer performance is indicated by high exit gas
temperatures at normal excess air. This condition can result from a
gradual buildup of gas-side or water-side deposits. Water-side deposits
require a review of water treatment procedures and cleaning to remove
deposits. Gas-side deposits can result from normal ash accumulations on
heat transfer surfaces or may be the result of excessive carbon forma-
tion on oil-fired units. Heavy deposits may also be indicated by
increased draft loss through the boiler, economizer, or air heaters.
Soot blowers are normally installed on coal-fired units and on many heavy
oil fired units. If the blowers are operating effectively, a decrease
in exit gas temperature should be observed following blower operation.
Visual examination of deposit patterns during an outage may disclose the
need for increased blower pressure or relocation of blowers to provide
more effective cleaning. Periodic off-line cleaning of radiant furnace
surfaces, boiler tube banks, economizers, and air heaters may be necessary
to remove stubborn deposits. Washing of rotary air heaters is recommended
when draft losses increase by 1" water gage.
5.4.2 . Combustion Related Problems
High excess air will be indicated by high stack 0 readings and
increased draft and pressure losses through the unit. Exit gas tempera-
ture and fan power will also be increased. The problem is most likely
related to control system operation. Low fuel supply pressure with oil
or gas firing, -change in fuel heating value or viscosity may not be com-
pensated for in simple positioning control systems. Leaking or plugged
sensing lines in other control systems may cause errors in fuel/air ratio
settings.
63
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Low excess air will be indicated by increased CO,smoking or
solid combustible content of fly ash in addition to low 0 readings.
The cause may again be control system related or may result from
inability of fans to deliver enough air because of increased flow
resistance through heat recovery equipment, obstructed inlet screens
or dirt on air foil blades.
Unburned CO or snake with normal or high excess air indicates
burner system problems. In gas fired units, vaporized light oil
contained in the gas can condense when the gas is expanded in a pressure
reducing station. The condensed oil can carbonise in the gas burner
and cause poor fuel distribution. Unbalanced fuel/air distribution in
multi-burner furnaces can also result in high CO formation.
Poor oil fires can result from improper viscosity, worn tips,
carbonization on tips and deterioration of diffusers or spinnerplates.
Improper air register settings and deterioration of burner
throat refractory can cause increased combustible losses with all
fuels.
Stoker grata condition, fuel distributors, windbox air regulation
and overfire air systems can affect carbon loss. Low fineness on pul-
verized coal units will increase carbon loss.
Obviously, many of the firing system maintenance items will
require a boiler outage to repair. Any known problems should be placed
on a maintenance list for correction at the next scheduled outage.
Priority should be assigned on the basis of safety, reliability, and
efficiency impact.
64
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5.4.3 Miscellaneous Energy Losses
Casing leakage on balanced draft units will increase the air flow
required for satisfactory combustion since this air infiltration does not
contribute to combustion of the fuel. The excess air at the boiler outlet
will be higher than normally required to burn the fuel and the condition
may be mistakenly interpreted as poor burner performance.
The magnitude of the problem is difficult to determine
unless the unit is out of service and can be pressurized for smoke
testing. Fortunately most modern balanced draft units are constructed
in the same way as pressurized units and are therefore less likely to
have setting leakage problems than are older units.
Casing leakage on pressurized units is readily apparent and
requires repair to prevent damage to casing and insulation. Escaping
flue gas also poses a personnel hazard especially if the unit is
located indoors.
Air heater leakage on tubular air heaters is normally less than
1% however low exit gas temperature can lead to cold end corrosion and
increased leakage. Rotary air heaters (Ljungstrom type) require seals
to prevent forced draft air from entering the gas stream. Since these
seals are between stationary and moving parts, they are not perfectly
tight and'are also subject to wear. Leakage is normally 7 to 15%
depending on the size of heater and pressure differential between gas
and air. Worn seals or improperly adjusted seals can double leakage.
Since the leakage in both tubular and rotary type heaters occurs
after the gas has passed over the heating surface, there is no penalty
in heat recovery, but the additional air flow which the forced draft
fans must supply and the additional gas weight through induced draft
fans, if present, represents additional auxiliary power consumption and
could possibly influence unit capacity. Air heater leakage can be
verified by excess air measurements entering and leaving the air heaters.
Inspection of tubes or seals should be made at annual outages.
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Coal pulverizer power can be excessively high if the pulverizers
are in poor repair or if the coal is being ground too finely. Normally
pulverized coal is ground to 70% thru a 200 mesh screen. If the fineness
is increased to 80% thru a 200 mesh screen the power required will
increase by 30%. It is particularly important to check pulverizer fineness
following mill maintenance and reset for proper fineness. Monthly
checks and re-adjustments should be made to avoid low fineness and high
unburned carbon loss.
Excessive blowdown represents an unnecessary heat loss which
can be avoided by monitoring boiler water concentration and maintaining
solids level as high as permissible. Slowdown heat losses are discussed
in Reference 4.
Steam leaks are obvious heat losses which should be corrected as
quickly as possible. Small leaks inside the boiler may go undetected
unless signs are found during an outage. Larger leaks may be detected
by noise of escaping steam, increased vapor emission from stack or
increased makeup water requirements. Water or steam leaks in coal
fired boilers can cause extensive damage by fly ash cutting of nearby
tubes if allowed to continue.
Missing or loose insulation increases heat loss and should be
repaired as necessary.
Excessive soot blower operation consumes steam or air unnecessarily,
The effectiveness of each blower should be determined and blowing pressure
set at a minimum consistent with effective cleaning. The frequency should
be determined by cleaning needs and not set on an arbitrary basis
such as once per shift.
5.5 EFFICIENCY RELATED BOILER MAINTENANCE ITEMS
This section contains a review by boiler system of efficiency
related maintenance items which should be considered by a boiler owner
or operator in developing operating log and inspection requirements.
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It is again appropriate to stress that any recommendations made
in this report are not intended to replace any procedures which are
required for safety reasons or recommended by the manufacturer to extend
equipment life.
5.5.1 Fuel Supply System
Gas Firing. Since gas is a clean fuel and can be burned without
any in-plant treatment, few problems are anticipated. The gas pressure
regulator is the major component which might require attention.
Gas pressure on the downstream side of the regulator should
be entered on the hourly log. Low pressure may indicate malfunction
of regulator, plugging of upstream strainers or low pipeline pressure.
High pressure or erratic pressure would indicate regulator malfunction.
Deviation in gas pressure could influence fuel/air ratio depending on
the type of control system.
Oil firing. The fuel oil supply system consists of tanks,
pumps, strainers and a pressure regulating valve to supply oil to the
flow control valve at the proper pressure. In addition, tank heaters
are required with heavy oil firing to provide the proper viscosity for
pumping, and preheaters are required to provide the proper viscosity for
atomizing. If the oil supply is extremely variable, viscosity control
devices may also be included in the system.
With oils that do not require preheating, the components requiring
attention are the strainers and oil pressure regulators. Heavy oil
systems additionally require attention to tank heaters and preheaters.
Oil supply pressure and temperature should be entered on the
hourly log as well as flow rate if metered. Low oil pressure may be
caused by too high or too low temperature at the pump inlet, plugged
strainers, coking in the preheater, or regulator malfunction. Preheater
fouling or coking may also be indicated by inability to maintain desired
fuel oil temperature.
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Deviations in fuel oil pressure could influence fuel/air
ratio depending on the type of control system. Viscosity control is
important to providing proper fuel atomization.
Coal firing. Most of the maintenance connected with the fuel
supply system of stoker fired units is to keep the system functioning
rather than efficiency related. With pulverized coal firing, the pulverizers
and piping system performance can affect unit efficiency.
Hourly log readings should include pulverizer outlet temperature
and pressure. Visual observation of the fires should be made to de-
termine that fuel supply is reasonably uniform to all burners and that
ignition point is normal. Monthly fineness checks should be made to
determine that adequate fineness is being maintained. Annual inspection
(or as recommended by the manufacturer) should be made to determine
wear on grinding parts, classifiers and exhausters or fans. Wear on
pulverized fuel pipes or riffle dividers should also be determined.
Poor grinding can increase carbon heat losses. Excessive
grinding or worn pulverizers can increase power consumption. Low
outlet temperature may indicate low pulverizer air flow, insufficient
hot air, high moisture fuel, or wear on exhauster.
5.5.2 Controls and Instrumentation
Controls and instrumentation are £he most critical areas in an
efficiency-related maintenance program. The control function in main-
taining the proper fuel/air ratio is essential to minimizing stack gas
losses and unbumed fuel loss. Accurate and reliable maintenance of
boiler variables is also essential to monitoring boiler performance and
analyzing equipment performance problems.
A variety of control systems are described in Reference 4. The
components may be mechanical, pneumatic, or electronic, or combinations
of various devices. Each type has certain weaknesses which require
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maintenance to assure satisfactory performance. Mechanical systems
are subject to misalignment, binding, and wear which introduce
errors in repeatability of settings. Pneumatic systems are subject
to leakage or dirt in sensing and control lines. Electronic systems
are subject to dirty contacts, insulation failure or circuit problems,
and may be more sensitive to heat or vibration damage. The same
types of problems are inherent in the various types of instruments
used for performance monitoring.
The frequency of maintenance and calibration is best de-
termined by plant operating and maintenance personnel based on
records of malfunction, or drift in accuracy between calibration or
periodic maintenance periods.
5.5.3 Fuel Burning Equipment
All types of fuel burning equipment have certain features in
common: air registers or dampers, and parts subject to intense heat
which are inaccessible during operation. These parts should be
inspected annually for deformation, oxidation, or failure, or more
frequently if outages occur. Hourly observation of fires is recommended
to detect overheating of stoker, gas, oil, or pulverized coal burner
parts or unusual flame patterns which may indicate burner problems.
Gas firing. Poor flame conditions may result from plugging
of gas orifices in ring burners as a result of carbonization of light
oil fractions contained in the gas which condenses when the gas
is expanded and cooled in passing through orifices or pressure
v
reducing stations. This condition is likely to develop in the lower
burners of multiburner installations. Whenever burners are taken
out of service in a multiburner boiler, the idle burner should be
observed to determine that enough cooling air is supplied to prevent
overheating of burner parts exposed to flame.
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Oil firing. Oil gun tips will require periodic removal for
cleaning. The frequency is a function of oil type and atomization
method. The frequency is best determined by plant experience and ."nay
vary from once per shift to monthly. Tips should be checked for
wear, nicks, or cracking.
Oil pressure should be checked 'at individual burners to assure
that reasonable oil distribution is being achieved. Atomizing
steam or air pressure, if used, should conform to manufacturer's
recommendation.
Stoker firing. Mechanical condition of fuel distributers and
grates should be checked if fires are burning unevenly. Excessive
siftings through grates may indicate need for grate maintenance if
fines content of coal is not abnormally high.
If an overfire air system is installed, the condition of
nozzles should be determined during annual outages. During operation,
the performance should be checked to determine that the required
air flow is being developed.
Many stokers are equipped with cinder reinjection systems for
returning ash collected in boiler hoppers or mechanical collectors to
the furnace for returning. This system can reduce unburned carbon
heat losses by 2 to 5% and should be kept in good operating condition.
Daily checks should be made to assure that hoppers are being emptied.
Cold hopper spouts usually mean no flow. It is also usually possible
to observe the flyash stream being injected into the furnace for flow
indication. However, unless each hopper has a separate injection
nozzle, there is no assurance that flyash is being reinjected from all
hoppers.
Pulverized coal firing. The abrasive nature of pulverized
coal requires some maintenace on deflectors or distributors which
may be incorporated in the burner design. Oxidation may also occur.
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These conditions should be checked during annual outages or more fre-
quently if possible. Coke buildup on burner throats may occur with
worn burner parts. Air register adjustment may be helpful in correct-
ing coke formation conditions.
5.5.4 Heat Transfer Equipment
The principal efficiency-related maintenance aspects of heat
transfer surfaces are surface cleanliness and good flue gas flow dis-
tribution. Flue gas-side cleanliness can be maintained by soot blowers
and/or periodic water washing or mechanical cleaning. Water-side
cleanliness can be maintained by proper water treatment and periodic
chemical or mechanical cleaning.
Many older boiler designs used refractory or metal baffles
to provide cross flow of gases in boiler tube banks. These baffles
require periodic inspection and maintenance to provide the desired gas
flow pattern. Missing baffle tile or plate will result in gaS by-
passing around heat transfer surfaces and increased boiler outlet
temperature. More recent boiler designs are arranged for cross-
flow without requiring baffles. Gas distribution problems still
can occur if localized heavy ash deposits plug gas flow lanes.
The boiler operator's log will indicate the rate of increase
of exit gas temperature or draft loss which would determine the need
for boiler cleaning. A sudden increase in boiler exit gas temperature
possibly accompanied by a noticeable decrease in draft loss would
indicate damage to cross flow baffles.
Many plants which have experienced problems with internal
deposits leading to furnace tube failures have installed thermo-
couples to measure tube temperature at the failure location. If
the tubes are clean, these thermocouples will read only a few
degrees above saturation temperature. As internal deposits form,
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the thermocouple readings will become higher and indicate the need for
chemical cleaning. If the annual inspection discloses significant
internal deposits or there is evidence of tube wall overheating
(bulges or swelling) , furnace wall tube thermocouples would provide
warning of poor water side conditions in the future.
Specific efficiency-related maintenance items to look for
during an inspection outage are:
1. Soot or ash deposit formations on furnace walls which
may indicate a need for burner adjustment or repair.
2. Evidence of furnace wall overheating (bulges or
swelling of tubes)•
3. General gas side cleanliness of boiler, superheater,
economizer and air heater surfaces, and areas of heavy
deposits which are not being cleaned by sootblowers.
4. Alignment of superheater elements (misalignment could
contribute to ash plugging or increase gas flow
resistance).
5. Condition of baffles or dampers in gas passages or
air ducts.
6. Evidence of sootblcwer erosion on coal fired units
which may be caused by high blowing pressure or
excessive operation of blowers.
7. Water side inspection to establish cleanliness of
boiler and mechanical condition of drum internals.
5.5.5 Fans
Some forced draft fans with curved or air foil blades lose
considerable capacity if the blades become dirty. This type of fan
should be cleaned as required to maintain capacity. Inlet screens
should be examined frequently for blockage by rags, paper, or other
material which would restrict air entry.
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5.5.6 Air and Gas Ducts
Leakage from air ducts will increase fan requirements and may
change fuel/air ratio depending on the control system design. Inward
leakage on balanced draft units will increase induced draft fan loading
and may restrict unit capacity.
5.5.7 Insulation
Heat losses from uninsulated ducts, boiler surfaces, or steam
lines can increase heat losses significantly in addition to creating
personnel hazards and uncomfortable working conditions. Missing insu-
lation should be replaced as required.
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SECTION 6.0
REFERENCES
1. "Field Testing: Application of Combustion Modifications to Control
Pollutant Emissions from Industrial Boilers - Phase II/" U. S. EPA
Report No. EPA-600/2-76-086a, April 1976 (NTIS No. PB 253 500/AS).
2. "Assessment of the Potential for Energy Conservation through
Improved Industrial Boiler Efficiency," Final Report - Volume I,
U.S. Federal Energy Administration Contract No. C-04-50085-00,
October 1976 (available from National Technical Information Service,
Order No. PB 262-576).
3. "National Emissions Report 1973," U. S. Environmental Protection
Agency, Report No. EPA-450/2-76-007, May 1976.
4. "Industrial Boiler Users' Manual—Methods and Equipment for Effi-
ciency Improvement," U. S. Federal Energy Administration Contract
No. C-04-50085-00, October 1976 (available from National Technical
Information Service, Order No. PB 262-577).
5. "Systems Evaluation of the Use of Low-Sulfur Western Coal in
Existing Small and Intermediate Sized Boilers, Interim Report
#1," by KVB, Inc., Report No. 8800-140 under Contract No.
EPA 68-02-1863, June 1975.
6. "Guidelines for Burner Adjustments of Commerical Oil-Fired Boilers,"
U.S. EPA Report No. EPA-600/2-75-069-b.
7. Combustion Engineering Company, Inc., Combustion Engineering—
A Reference Book on Fuel Burning and Steam Generation, The
Riverside Press, Cambridge, Massachusetts, 1947.
8. Babcock and Wilcox Company, Steam, Its Generation and Use, 38th
Edition, 1972.
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APPENDIX A
OTHER NO REDUCTION TECHNIQUES
Operation of most industrial boilers with low excess air
will improve boiler efficiency as well as reduce NO stack emissions.
X
Where further NO reductions are required or when efforts to improve
efficiency lead to increases in NO , there are several NO reduc-
X X
tion techniques that may be considered. When properly applied, they
will usually involve little or no sacrifice in boiler efficiency
(except for the reduced air preheat method). These techniques include:
1. Fuel-rich ("staged") combustion
2. Flue gas recirculation
3. Low NO burners
x
4. Change of fuels
5. Reduced air preheat
In most cases, applying any of these methods will involve
modifications to existing hardware and boiler operating practices.
The selection of the appropriate method will require the assistance
of outside combustion specialists. Economic evaluations including
cost/benefit studies and long term maintenance and operating costs
will also be involved in selecting the most appropriate technique
(see Appendix B ). Whether or not a specific approach can be
successfully applied will generally depend on the design and
particular operating requirements of the boiler.
The following discussion is intended to familiarize boiler
operators and owners with the various NO reduction techniques
available. It is stressed that before any of these techniques is
considered, the reduced-NO potential of existing equipment should
X
be fully evaluated. This includes minimizing the .burner excess air
level and exploring possible burner adjustments as described in pre-
vious sections of the manual.
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A-l. FUEL RICH COMBUSTION
Fuel-rich or "staged" combustion is mainly applicable to
gas, oil and pulverized coal fired boilers with multiple burners
(four or more burners). This technique usually involves terminating
or reducing the fuel to one or more of the burners, and equally
distributing this fuel to the remaining burners to maintain the same
overall firing rate. Full air flow is maintained at the burners
with reduced or terminated fuel flow thereby causing the other burners
to operate more fuel-rich. In this manner, the fuel-rich burners
can actually be operated with less air than required for complete
combustion. This requires the flame products to be effectively mixed
with "make up" air from the out-of-service or reduced-fuel burners
to complete the combustion elsewhere in the furnace. The fuel-rich
flames provide an opportunity for a large portion of the fuel to burn
in an 0 deficient and relatively "cool" flame which reduces NOX
formation. When the flame products eventially mix with the make up
air downstream in the furnace, the combustion gas temperature is
already too low for additional NO formation but adequate to complete
the burnout of smoke and combustibles.
An alternate approach involves maintaining normal fuel flow
to all burners while directing a portion of the combustion air
through auxiliary or "over fire" air ports located away from the
burners. However, this requires redesign of the air handling parts
of the boiler and therefore can be costly.
NO emission reductions of 25% to 40% have been demonstrated
A
with fuel-rich firing (Ref. A-l) but it is seldom a straightforward
technique in terms of implementation by the boiler owner/operator. It
usually requires an extensive test program to establish the most effec-
tive fuel distribution pattern and to address potential problems such
as reduced load capacity, flame stability, furnace heat release effects,
flame impingement, and tube wastage. This work is best performed by
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combustion specialists with previous experience in fuel-rich firing
techniques. However, this approach is relatively cost effective "com-
pared to other NO reduction techniques in that little or no hardware
modifications are required with the burners out-of-service method of
fuel-rich firing.
Where this technique is applicable, it is very attractive
since it can involve little or no decrease in boiler efficiency for
large reductions in NO . Efficiency penalties mainly arise when
X
boiler excess air requirements increase to maintain acceptable
stack conditions or combustible losses. In some cases the excess 0
requirement will increase only a few tenths percent and the resulting
efficiency penalty is extremely small.
A-2. FLUE GAS RECIRCULATION
A very effective means of reducing nitrogen oxides emissions
involves recirculating a portion of the flue gas back into the com-
bustion air. These recirculated gases absorb heat energy from the
flame thereby lowering the peak flame temperature which reduces NO
X
formation. Other effects on NO may result from increased flame
x
turbulence due to higher mass flow through the burner and alteration
of flame shape and heat release.
Adding a flue gas recirculation system can conceivably be done
on most boilers but it usually requires considerable costs, engineering
design and extensive equipment modification. The point where the
flue gas is introduced into the combustion air must be carefully
chosen and designed to assure thorough mixing of flue gas and air
before it flows through the burners. Changes in burner design are
sometimes necessary to retain flame stability.
Flue gas recirculation has been demonstrated to be generally
more effective in reducing NO emissions from gas fired boilers (Ref. 1)
X
Reductions in NO of up to 73% at gas fueled industrial boilers have
X
been achieved. Reductions with fuel oil can be on the order of 30%.
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Flue gas recirculation is less effective with heavy oil and coal fuel
because they contain high levels of fuel nitrogen. The formation of
NO from fuel nitrogen is not strongly influenced by gas recirculation.
Flue gas recirculation can affect overall plant efficiency slightly
due primarily to increased auxiliary power requirements (gas recircu-
lation fans). A reduction in boiler excess 0 is sometimes possible
using flue gas recirculation but the increased auxiliary loads usually
override this beneficial effect on boiler efficiency-
A-3. LOW-NO BURNERS
X
Retrofit burners are commercially available which are
specially designed for low nitrogen oxides emissions. These "low-
NO " burners incorporate some of the principles discussed in this manual
X
to give a controlled slow burning, low-temperature flame. Some
designs involve low excess O operation which is also beneficial from
a boiler efficiency standpoint. Interpreting low-NO burner test
X
data from other boilers must be done carefully before considering
the use of the burner at another installation. Many factors such as
fuel composition, furnace geometry and combustion control precision
are influential in the success of a low-NO burner. For instance,
x
a low-NO burner design which works well on a single burner installation
may not give beneficial results when used in a multiple burner unit,
and vice versa. Careful selection by engineering personnel assisted
by competent combustion specialists is necessary in choosing a
low-NO burner best suited for any particular boiler. It is sometimes
possible that an existing burner is capable of producing NO emission
levels of a "low-NO " burner if properly maintained and adjusted.
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A-4. FUEL CHANGE
Changing fuels can be an effective method for reducing oxides
of nitrogen. This might involve changing from a higher nitrogen
fuel oil to a lower nitrogen oil (i.e., No. 6 to No. 2) or by selecting
v
oils of the same grade which have lower nitrogen content. For
example, variations in the fuel nitrogen content of No. 6 oils of more
than a factor of 3 .can occur as a result of refining processes,
blending and natural differences between oil fields.
Changing fuel types (i.e., from coal to oil or oil to gas) is
considerably more complicated and the decision is usually controlled
by other factors such as fuel availability and cost. Also it is not
always practical because of physical limitations of the boiler. A
boiler may require extensive burner modifications, new fuel handling
equipment and increased sootblowing and ash handling facilities, to
burn a different fuel. Fuels such as natural gas and light
distillate oils which potentially produce the lowest NO einissions
may be expensive or in increasingly short supply. Different fuels
characteristically exhibit modest differences in boiler efficiency
and this factor should be taken into account in addition to raw fuel
cost (on a million Btu basis) when comparing alternate fuels. These
differences result primarily from dissimilar hydrogen content in the
fuels with resulting differences in moisture content of the flue
gas (moisture losses).
A-5. REDUCED COMBUSTION AIR PREHEAT
Many larger industrial boilers operate with preheated combustion
air to increase boiler thermal efficiency and improve combustion.
Unfortunately, heated combustion air results in higher .flame
temperatures which promotes higher nitrogen oxides emissions.
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Combustion air preheaters are heat exchangers which extract heat
from the flue gas to heat the incoming combustion air. Some pre-
heaters are equipped with ducting for bypassing a portion of the air
or flue gas around the preheater to control stack temperatures for
corrosion purposes. This capability can also be used in some cases
to lower combustion air preheat and effectively reduce NO emissions.
x
The major drawback with this technique is that boiler efficiency
is reduced as reflected by higher stack temperature (higher stack
gas losses). The trade-off between efficiency and NO emissions
is the major consideration.
This technique is most effective on natural gas and light
fuel oils; however, reductions are possible with heavy oils and
coal. Potential operational problem areas include flame stability
and possible degradation in combustion conditions leading to in-
creased furnace tube fouling.
REFERENCES
A-l. "Field Testing: Application of Combustion Modifications to Control
Pollutant Emissions from Industrial Boilers - Phase II, U.S.
EPA Report No. EPA-600/2-76-086a, April 1976.
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APPENDIX B
COST OF COMBUSTION MODIFICATIONS
TO CONTROL NO
The total cost of controlling nitrogen oxides emissions from
industrial boilers by using combustion modifications is determined
by the:
1. Initial capital cost
2. Annual capital cost
3. Annual operating cost
The amount of cost information available for combustion modi-
fications on industrial boilers is very limited. Only very approxi-
mate estimates are available at this time. The most recent information
on this subject appears in References B-l, B-2, and B-3.
In Reference B-2, it was estimated that many existing small
industrial boilers could be modified to meet lower EPA new source
standard levels for nitrogen oxides for about $10,000 per boiler.
The combustion modification specified was a combination of staged
combustion and low excess air firing. The report stated that a major
portion of the expense on a multiple burner boiler would be implement-
ing fuel-rich firing by removing selected burners from burner service
and operating them with air only (see Appendix A of this manual). The
cost would include testing expenses and minor equipment modifications
such as oil burner tip enlargements. On a single burner boiler, the
cost of installing secondary air ports would be about $10,000. If,
for the $10,000 capital cost estimate, the maintenance and operational
charges are assumed to be negligible, and capital cost is annualized
to 20%, the annual charges would be $2,000.
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In Reference B-2, the minimum cost for installing a flue gas
recirculation system on a small boiler is estimated to be $30,000,
which cost will clearly dominate the fuel penalty cost which is esti-
mated to be one percent in efficiency for normal recirculation per-
centage flow. On a larger boiler (100 MMB/hr), the cost of flue gas
recirculation would be of the order of $1,000/ (MMB/hr)'. In Reference
B-l, it was estimated that secondary air capability would add 2% to
4% to the total new boiler cost for boilers in the 300,000 Ib/hr steam
flow range (approximately $1,000,000 purchase price). If another
booster air fan were required, the cost would be increased by about
an additional one percent.
Reference B-3 discusses the cost of combustion modifications
to reduce NO emissions from large electrical utility boilers. The
actual costs are not applicable to industrial boilers but the relative
expenses are. The reference states that low excess air firing per se
would incur the lowest costs, staged combustion would be the next
lowest, and flue gas recirculation would represent the highest cost.
In general, the cost of applying any of the control methods to an
existing boiler would be approximately twice that of a new unit design.
The equipment (initial) costs increase with increasing boiler size,
but the operating costs on a boiler output basis decline.
Additional cost information is given in Appendix C.
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APPENDIX B
REFERENCES
B-l. "Field Testing" Application of Combustion Modifications to Control
Pollutant Emissions from Industrial Boilers - Phase II," U.S.
EPA Report No. EPA-600/2-76-086a, April 1976.
B-2. "Control of Oxides of Nitrogen from Stationary Sources in the
South Coast Air Basin," prepared for Air Resources Board, State
of California, KVB Report No. 5800-179, September 1974.
B-3. "NO Combustion Control Methods and Costs for Stationary Sources,
Summary Study," U.S. EPA Report No. EPA-600/2-75-046, September 1975,
83
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APPENDIX C
METHODS AND EQUIPMENT FOR EFFICIENCY IMPROVEMENT
The following discussion is extracted from Federal Energy
Administration "Industrial Boiler Users' Manual" as an introduction
to that reference. This document is a manual designed for boiler
owners and plant engineers to assist them in the evaluation of effi-
ciency improvement alternatives. These include maintenance practices
and operational changes to improve boiler efficiency and boiler auxi-
liary equipment such as waste heat traps, improved combustion controls,
low excess air burners, and others. The manual includes cost infor-
mation, operating principles, performance data, and other helpful
information for evaluating the various options available and discuss-
ing equipment modifications with manufacturers and dealers. The
following excerpts summarize the topics which are discussed in detail
in the main body of the manual.
C-l. BOILER MAINTENANCE AND OPERATIONAL MODIFICATIONS FOR
EFFICIENCY IMPROVEMENT
Boiler maintenance practices are important in achieving or
maintaining efficient operation. Poor maintenance resulting in
degraded equipment operation in a manner that affects stack temperature,.
excess air level, combustibles, or other heat losses, can affect
boiler efficiency and fuel consumption.
A boiler tune-up is one of the most cost-effective means
of achieving efficient operation and saving fuel. Adjustment and
maintenance of fuel burning equipment and combustion controls permits
operation with the lowest practical excess air, thus reducing stack
losses. Annual tune-ups can be performed by boiler operating personnel,
service organizations, some local utilities, burner/boiler manufacturers,
or engineering consulting firms. A routine tune-up on a 25,000 Ib/hr
boiler can typically be conducted by a burner manufacturer in a day or
two at a cost of $300/day plus expenses.
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Boiler tube cleanliness is important for efficiency heat trans-
fer from the hot combustion gases to the water-side passages. Tube
deposits and fouling on external tube surfaces of a watertube boiler
will be reflected in high flue gas temperatures. An estimated 1%
efficiency loss occurs with every 40°F increase in stack temperature.
Some boiler operators perform their own tube washes while others rely
on commercial cleaning and repair service firms that can charge as low
as $200 or as high as $500 to clean a 10,000 lh/hr unit. The actual
cost depends on the size of the unit, fuel type, furnace design, and
extent of deposits.
Reducing the boiler steam pressure (where permissible) is an
effective means of reducing fuel consumption by as much as 1 to 2 per-
cent. Lower steam pressures give a lower saturated steam temperature,
and without stack, heat recovery, a similar reduction in final flue
gas temperature will follow. These benefits can be achieved at little
or no expense providing the process or equipment can accommodate
lower steam pressures.
Slowdown is a customary procedure to remove boiler water with
high impurity concentrations. It also represents a loss of sensible
heat energy in the waste water. Improved blowdown practices or the
use of automatic equipment-can result in a fuel savings dependent upon
current practice.
Load management is a tool in minimizing fuel consumption in
a plant with several boilers. Since boiler efficiency varies with
load, boiler design, equipment age, fuel, and other factors, there is
an advantage to distributing load to the most efficient boilers and
in operating boilers at loads where efficiency is highest. There
also is merit to shutting some boilers down in swing seasons while
operating process boilers at peak efficiency as opposed to operating
«
all boilers at reduced load and performance.
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A fuel change or fuel conversion is generally not thought of
as a common means for fuel conservation since the decision is usually
controlled by availability. However, different fuels do characteris-
tically exhibit modest differences in boiler efficiency which should
be taken into account in addition to raw fuel cost on a Btu per pound
basis.
C-2. BOILER AUXILIARY EQUIPMENT FOR EFFICIENCY IMPROVEMENT
Previous paragraphs have briefly summarized methods of effi-
ciency improvement and fuel conservation that can be accomplished
with little or no capital expenditures. Although these methods are
very cost effective, major improvements in efficiency can be accom-
plished more readily with equipment modifications that might require
several years for return on investment.
The objective of this section is to briefly review the more
commonly used efficiency improvement equipment so the potential user
r
has an overall appreciation for the range of options from- which to
choose and the relative costs and efficiency improvement that can be
expected.
The Equipment Synopsis section includes a description of the
various off-the-shelf items that can be employed to improve boiler
performance. These items can generally be divided into heat traps
that lower the temperature of the stack gases, low excess air equip-
ment that reduces stack gas flow, and other items that limit waste
heat and radiation losses. Included for each item are:
principle of operation
performance potential
cost information
physical description
It must be emphasized that the efficiency improvement potentials dis-
cussed are not cumulative; that is, a combination of a heat trap and
a low excess air modification will not result in an efficiency improve-
ment that is the sum of each individual item acting alone.
86
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The "Industrial Boiler Users' Manual" includes a brief final
section on boiler selection to assist in the purchase of a new unit
if it is shown to be more cost effective than utilizing auxiliary
equipment on the existing unit.
The reader is cautioned that new equipment is marketed periodi-
cally which advertises an improvement in efficiency where the potential
fuel savings is very dependent upon the specific boiler design and may
not be realized at all in some cases. In other cases of misapplication
or improper installation, the device may actually reduce efficiency.
(For example, turbulators are one of the most attractive efficiency
improvement devices for firetube boilers but they show little improve-
ment in four pass unit efficiency and can actually reduce boiler draft
and lead to CO formation if improperly installed.) Therefore, it is
recommended that the equipment manufacturer or a combustion specialist
be consulted before purchasing or installing such equipment.
C-2.1. Equipment Synopsis
Air preheaters are heat traps installed in the exhaust duct
that transfer heat energy from the hot flue gas to the incoming com-
bustion air supply. Unit efficiency will increase approximately 2.5%
for every 100°F decrease in flue gas temperature. Additional perfor-
mance benefits will result from improved combustion conditions in the
furnace which may enable operation with lower excess air. Applica-
tion is limited by corrosion considerations (i.e., lowest acceptable
stack temperature), existing stack temperatures, maximum acceptable
combustion air temperature, and associated increases in NO emission
levels. Initial capital equipment costs range from $1,000 to $2,000
per MBtu/hr, depending on boiler capacity.
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Economizers are heat traps that preheat boiler feed water
using heat energy from the flue gas. Again, unit efficiency will
improve 2.5% for every 100°F decrease in flue gas temperature. Corrosion
considerations are the primary limitation with some consideration
required for boiler operating pressure on low pressure boilers.
. • The choice between an air preheater and an economizer is made
on the basis of the criteria set forth in Section 4.1 of the "Industrial
Boiler Users' Manual." Economizers are generally preferred over air
preheaters on small units. A combination of air preheaters and econo-
mizers is employed on large units with operating pressure above 400 psig.
Economizer initial costs are comparable to that of air preheaters, but
other factors of installation and operating cost are a consideration.
Turbulators are baffles installed in the secondary passes of
a firetube boiler to increase turbulence and thereby convection heat
transfer to the surrounding boiler water. As with the heat traps
mentioned above, the improvement in boiler performance will be
indicated by the decrease in stack gas ^temperature and the corresponding
increase in steam generation. Turbulators cannot be used on coal
fired units. Turbulator installations range from $500 to $2000 per unit,
depending upon unit size, and are economically attractive to many
firetube boiler operators.
Improved combustion controls and instrumentation are designed
to reduce the operating excess air levels required for safe operation.
The degree to which boiler performance is improved will depend on
the previous stack gas excess air and temperature conditions and the
reduced excess air and temperature possible with new controls and
instrumentation. A changeover from the simplest jackshaft system to
a cross-limited excess oxygen system can improve boiler performance
by 2% and 5% for systems"with and without heat traps respectively.
Approximate installed costs range from $30,000 to $150,000, depending
on the degree of sophistication and capacity of the unit.
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Low excess air burners have been developed that achieve
complete combustion on oil and gas fuel with as little as 1-3% excess
air. Associated decreases in NOx and particulate emissions have also
been reported. Sustained operation at such low excess air levels
however is questionable and will require a very sophisticated
combustion control system. Initial capital costs range from $200
to $700 per MBtu/hr with increasing size of the unit.
Packaged burner assemblies that come equipped with their own
control system can reportedly operate with 2-3% excess 02 levels
and are available for retrofit replacements of the existing burner
and control system. These are generally priced between $10,000 and
$35,000 for a single burner unit.
Waste water heat recovery involves the recovery of waste heat
energy contained in drum water blowdown and expelled condensate.
This heat energy can be effectively used to preheat boiler feed
water instead of just being discarded. Approximately a 10°F
increase in feed water temperature wiil result in a 1% improvement
in efficiency. Nominal costs for automatic blowdown systems and
condensate recovery units are $1,000 and $8,000, respectively.
.Insulation is employed to reduce radiation and convective
heat losses from the boiler jacket and ductwork to the boiler
surroundings. An estimate of these energy losses can be made
based upon surface temperatures, air flow and surrounding conditions,
and should be made prior to the purchase of new insulation where
improvements appear marginal. The cost of improved insulation is
highly variable and is a function of material used, desired skin
temperature, and condition of existing insulation.
Sootblowers are employed to remove soot, slag and fly ash
deposits from the tube surfaces that would otherwise retard heat
transfer in the convective regions leading to higher stack temperatures.
Manufacturers claim that up to a 1% efficiency improvement can be
achieved by maintaining clean tube surfaces. A simple sootblower
system will cost from $15,000 to $50,000.
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APPENDIX D
COMBUSTION GENERATED AIR POLLUTANTS
The exhaust gases from all combustion devices contain a
variety of byproducts, some of which are considered environmental
pollutants. Some of these pollutants are immediately toxic in
themselves while others pose indirect health hazards by virtue of
their ability to react with other pollutants in the air to form more
hazardous compounds. Furthermore, these pollutants also differ by
the way they originate in the combustion processes. Some are more
related to the composition of the fuel itself whereas others are
dependent on the characteristics of the actual fuel burning process
and as such are sensitive to the design and operating variables of
the combustion device.
The United States Environmental Protection Agency (EPA)
has presently identified six major pollutants and has established
emission standards to protect the public health and welfare. These
six "criteria" pollutants are:
1. Particulate matter
2. Sulfur dioxide
3. Nitrogen oxides
4. Carbon monoxide
5. Hydrocarbons
6. Oxidants
Below are brief descriptions of these substances including
the principal health effects, their formation in boiler combustion
systems and methods currently used to limit their emissions from
boiler stacks. This information is included in the manual to
familiarize boiler operators and others with the major aspects of
combustion pollutants which have prompted action by the EPA and some
state and local air quality agencies to limit these emissions from
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many sources. Frequently, emission regulations or pollutant-related
operating criteria are imposed but the operators of the combustion
devices are not acquainted with the underlying health and
environmental concerns.
D-L. PARTICULATE MATTER
Particulate matter is the non-gaseous portion of the
combustion exhaust, consisting of all solid and liquid material
(except water droplets) suspended in the exhaust gases. They can be
generally defined as any material that would not pass through a very
fine filter. Particulates originating in the combustion process
can range in size from submicron in diameter (less than one millionth
of a meter) to diameters larger than a millimeter (thousandth
of a meter). The larger particulates do not carry far in the atmos-
phere and usually fall to the ground near the source. The small
particles, which may make up the bulk o.f particulate matter, can
remain in the atmosphere for long periods of time and contribute to
haze and obscured long-range visibility. These "fine particles"
are potentially the most hazardous to health since they are easily
carried into the small passages of the respiratory tract during normal
breathing.
Particulate matter can be composed of a wide variety of
materials including unburned fuel, sulfur .compounds, carbon, ash
constituents in the fuel (including many toxic metals), and even non-
combustible airborne dust that enters the combustion system with
the combustion air. Many of these materials by themselves are
identified as health hazards and when dispersed in the air in fine
particles, can be inhaled and subsequently absorbed into the body.
High concentrations of particulate matter in the inhaled air can
have more direct health effects by irritating or blocking the
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surfaces of the respiratory tract leading to temporary or permanent
breathing impairments and physical damage. Oral ingestion of
particulate matter is also possible from particulate fall-out onto
vegetation and food crops.
The quantity and composition of particulates generated in
boilers are influenced by several factors including the type of fuel
being burned, the boiler operating mode, and combustion characteristics
of the burners and furnace. Burner designs and operating modes that
tend to promote thorough, efficient combustion generally will reduce
the fraction of combustible material in the particulates. From a
boiler operating standpoint, it is desired to minimize these fuel-
derived materials since they represent wasted available fuel energy and
can lead to troublesome internal furnace deposits or objectionable
smoke at the stack. Burner air/fuel ratio is one of the more important
operating parameters that can influence the quantity of combustible
particulate material generated.
Natural gas and most oil fuels are referred to as "clean
burning" fuels primarily due to their lower tendency to form solid
combustibles (smoke, soot, carbon, etc.) and their low ash content.
By comparison, some heavy oils and most coal fuels contain substantial
quantities of ash which subsequently form the bulk of the non-
combustible particulate matter generated in the furnace. For the case
of coal, ash can compose up to 20 percent or more of the total weight
of fuel burned. Preventing its accumulation on internal boiler
surfaces is a major consideration in the design of the boiler.
In some boiler designs, most of the coal ash remains in the
exhaust gases leaving the boiler, but the use of various particulate
control devices allows low concentrations to be emitted from the
stack. Current devices employ various techniques to remove particulates
from the stack gases. These include filtration, mechanical separation
92
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and electrostatic precipitation. Many designs have proven to be
capable of removing more than 99% of the particulates and are also
applicable to oil fired boilers where particulate controls are required.
D-2. SULFUR DIOXIDE
SO is a non-flammable, colorless gas that can be "tasted"
in concentrations of less than 1 part per million in the air. In
higher concentrations, it has a pungent, irritating odor.
Sulfur dioxide (chemical symbol, SO ) is formed during the
combustion process when sulfur (S) contained in the fuel combines with
oxygen (O ) from the combustion air. Sulfur trioxide (SO ), is another
oxide of sulfur which is also formed in this manner. SO together with SO
comprise the total oxides of sulfur, generally referred to as "SOx."
SO is usually no more than 3 to 5 percent of the total SOx generated
in the bqiler.
Except for sulfur compounds present in particulate matter,
all of the sulfur initially contained in the fuel is converted
to SO and SO . Before leaving the stack, SO can combine with
moisture in the exhaust gases to form sulfuric acid which condenses
onto particulates or remains suspended in the stack gases in the
form of an acid mist. In the atmosphere, a portion of the SO
is converted to SO which similarly forms sulfuric acid by combining
with moisture in the air. The SO can also form other sulfur
compounds such as sulfates.
The sulfates and acid mists can contribute significantly
to reduced visibility in the atmosphere. Corrosion of materials
f
exposed to the air and damage to vegetation are other major environmental
effects. The health effects of sulfur oxides, sulfuric acids and
some of the sulfates are primarily related to irritation of the
respiratory tract. These effects may be temporary or permanent and
include constriction of lung passages and damage to lung surfaces.
93
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The quantity of SO generated in the boiler is primarily
J\
dependent on the amount of sulfur in the fuel and is not highly
affected by boiler operating conditions or design. Regulating the
quantity of sulfur allowed in the fuel is a primary method of
controlling SO emissions. Stack gas "scrubbers" which remove SO
A • •
from the combustion exhaust gases can also be effective where "high
sulfur" fuels are used.
D-3. NITROGEN OXIDES
Nitric oxide (NO) and nitrogen dioxide (NO ) are the two
forms of nitrogen oxides generated by boiler combustion processes.
Together, these compounds are customarily referred to as total oxides of
nitrogen or simply "NO ". NO is a colorless/ odorless gas and is not
considered a direct threat to health at concentrations found in the
atmosphere. NO is a considerably more harmful substance. Although NO
comprises typically 5% or less of the NO emitted from boiler stacks,
X
a large fraction of the NO is converted to NO in the atmosphere.
NO is a yellow-brown colored gas which can affect atmospheric
visibility. It also has a pungent, sweetish odor that can be detected
at concentrations sometimes reached in polluted air. In much higher
concentrations (100 ppm) NO can be fatal when inhaled. Prolonged
exposures at much lower concentrations can cause cumulative lung
damage and respiratory disease.
NO is formed spontaneously during the combustion process
when oxygen and nitrogen are present at high temperatures. All
three ingredients (oxygen, nitrogen and high temperature) are
essential elements of the combustion process and it would therefore
94
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be very difficult to prevent the formation of NO altogether.
X
Nitrogen is present in the combustion air and in the fuel itself.
Minimizing the fuel nitrogen content has been shown to reduce NO
but this is not currently a practical NO control approach. Most
MO reduction techniques currently applied to boilers are
3C
effective as a result of lower peak flame temperatures in the furnace,
reduced availability of oxygen in the flame or a combination of both.
These techniques include low excess air operation, fuel-rich ("staged")
firing and flue gas recirculation. While these approaches limit the
formation of NO in the furnace, future techniques may be developed
X
that "scrub" the NO from the exhaust gases before entering the
X
stack. Fuel desulfurization processes and other fuel "cleaning"
treatments may have some associated benefits in reduced fuel nitrogen
content.
D- 4 . CARBON MONOXIDE
Carbon monoxide (CO) is a product of incomplete combustion
and its concentration in boiler exhaust gas is usually sensitive to
boiler operating conditions. For example, improper burner settings,
deteriorated burner parts and insufficient air for combustion can
lead to high CO emissions. CO measurements at the stack are often
used as an indicator of poor combustion conditions.
CO is an invisible, odorless, tasteless gas. Exposure to
CO-containing exhaust gases produces a well known "CO poisoning"
which can be fatal. CO emitted from boiler stacks are dispersed in
the atmosphere and together with CO from other sources are generally
not in high enough concentrations to produce any immediate health
effects (an exception might be in the vicinity of high density
automobile traffic). However, there is concern that long-term
exposures to these concentrations may cause eventual health problems.
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D-5. HYDROCARBONS
Like carbon monoxide, hydrocarbons are indicative of in-
complete or inefficient combustion and can be essentially eliminated
from the boiler stack gases by proper operation of the fuel burning
equipment. However, this may be misleading since, strictly speaking,
hydrocarbons cannot be entirely eliminated and trace quantities of
hydrocarbon compounds will nearly always be present, regardless of
how the boiler is operated.
Due to the tremendous variety of hydrocarbon compounds
involved and the unknown health effects of some of these even in
much larger quantities, it is difficult to assess their environmental
impact. Some of these hydrocarbons resemble actual components in
the fuel and are rightfully called "unburned fuel," while others
are entirely modified forms generated in complex chemical reactions
during the combustion process.
It is known that hydrocarbon air pollutants are important
ingredients in the formation of photochemical smog. Under certain
atmospheric conditions, they can also be transformed into other
derivatives which are potentially more hazardous. Some of the
manifestations of smog such as irritation of the eyes and respiratory
tract are in part directly associated with hydrocarbons and their
derivatives.
D_6. OXIDANTS
The term "oxidant" is generally applied to oxygen-bearing
substances that take part in complex chemical reactions in polluted
atmospheres. These so-called photochemical reactions, which are
often intensified in the presence of sunlight, involve nitrogen oxides
and reactive organic substances (including hydrocarbons and their
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derivatives) as the principal chemical ingredients. These react
to form new compounds including ozone and PAN (£eroxyacyl nitrates)
which are usually considered to be the major oxidants in photo-
chemical air pollution ("smog"). The term oxidant is also sometimes
used to include the original chemical reactants NO , hydrocarbons,
and others .
While ozone and PAN are not generated directly in the boiler,
the principal ingredients (especially NO ) are supplied in part by
X
exhaust gases from the boiler. By reducing the emission of these
compounds from boilers and all the other combustion sources (auto-
mobiles, airplanes, etc.), their photochemical byproducts—the oxidants-
will be reduced.
Photochemical oxidants produce adverse effects on vegetable
matter which can affect growth, and the quantity and quality of
agricultural yields and other plant products. Deterioration of
various materials (especially rubber)' is also a well known occurrence
in polluted atmosphere which is attributed mainly to the presence
of ozone.
A major effect on humans is irritation of the eyes. In
quantities higher than typically found in polluted atmospheres,
oxidants have an irritating effect on the respiratory tract
producing coughing and choking. Headache and severe fatigue may be
other side-effects. In lower concentrations found in polluted air,
the effects appear less well defined. Aggravation of existing
respiratory ailments such as asthma has sometimes been attributed
to oxidants.
97
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APPENDIX D
REFERENCES
D-l. Research and Education Association, "Pollution Control
Technology," New York, New York, 1974.
D-2 National Tuberculosis and Respiratory Disease Association,
"Air Pollution Primer," 1969.
98
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APPENDIX E
CONVERSION FACTORS
<£>
SI Units to Metric or English Units
To Obtain
g/Mcal
106 Btu
MBII/ft2
HDII/ft3
Btu
103 lb/hr« or HBH
Ib/HOtu
ft
in
ft*
ft'
li>.
Fahrenheit
psig
psla
iwg (39.2'F)
•Ib/hr of equivalent
From Multiply By
ng/J 0.004186
GJ 0.94B
GJ'hr" -n"2 0.00806
GJ'hr" -m" 0.02684
gn cal 3.9C85 x lo"3
GJ/hr 0.948
'ng/J 0.00233
ID 3.201
cm 0.3937
m2 10.764
m3 35.314
Kg 2.205
Celaiua tr - 9/5(t 1+32
Kelvin t - 1.8K - 460
F
Pa P - (P ) (1.450X10~4)-14.7
psig pa
Pa P - (P . (1.450X10"4)
paia pa)
P* P. - (P ) (4.014X10" )
iwg pa '
saturated Btcara
To Obtain ppm
at 3% 02 of
Natural Gas Fuel
CO
HC
NO or NOx
S02 or SOx
Oil Fuel
CO
»IC
NO or NOx
so. or SOx
2
Coal Fuel
CO
IIC
NO or NOx
SO or SOx
Refinery G;ia Fuel (Location 33)
CO
IIC
NO or HOx
SO. or SOx
Refinery Go a Fuel (Location 39)
CO
IIC
NO or NOx
SO. or SOx
Multiply Concentration
in ng/J by
3.23
5.65
1.96
1.41
2.93
5.13
1.78
1.28
2.69
4.69
1.64
1.18
3.27
5.71
1.99
1.43
3.25
5.68
1.98
1.42
-------
English and Metric Units to SI Units
To Obtain
ng/J
ng/J
GJ-hr"1^"2
GJ-hr"1^'3
GJ/hr
m
cm
m
ra
Kg
M Celsius
o Kelvin
Pa
Pa
Pa
•Ib/hr of equivalent
From Multiply By
Ib/MBtu 430
g/Mcal 239
HBII/ft2 11.356
MDII/ft3 37.257
103 Ib/hr* 1.055
or 106 Btu/hr
ft 0.3048
in 2.54
ft2 0.0929
ft 0.02832
lb 0.4536
Fahrenheit tc - 5/9 (t -32)
tR - 5/9 (tp-32) + 273
palg Ppa - (Ppslg + 14.7M6.695X103)
psia Ppa«
-------
TECHNICAL REPORT DATA
(Please read laaructioni on the reverse before completing)
. REPORT NO.
EPA-600/8-77-003a
2.
3. RECIPIENT'S ACCESSION-NO.
TITLE AND SUBTITLE
Guidelines for Industrial Boiler Performance
Improvement
5. REPORT DATE
January 1977
6. PERFORMING ORGANIZATION COOE
. AUTHOHtS)
Michael W. McElroy and Dale E. Shore
8. PERFORMING ORGANIZATION REPORT NO.
6001/8300-461
. PERFORMING ORGANIZATION NAME AND ADDRESS
KVB, Inc.
17332 Irvine Boulevard
Tustin, California 92680
10. PROGRAM ELEMENT NO.
1AB014; ROAP 21BCC-046
11. CONTRACT/GRANT NO.
68-02-1074
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Guidelines
14. SPONSORING AGENCY COOE
EPA/600/13 and FEA
15. SUPPLEMENTARY NOTES (*)Tne FEA (K. W. Freelain, project officer, 202/254-9690) cospon-
sored this document. IERL-RTP project officer is R.E.Hall, 919/549-8411 Ext 2477.
This document is available through the National Technical Information Service.
16. ABSTRACT
The document contains recommended procedures for improving industrial
boiler performance to minimize air pollution and to achieve efficient use of fuel. It is
intended for use by industrial boiler operators to perform an efficiency and emissions
tune-up on boilers firing gas, oil, or coal. Portions of the guidelines are also inten-
ded for plant engineers interested in initiating preventive maintenance and boiler
efficiency monitoring practices to maintain peakboijer operating efficiency. Several
appendices to the guidelines contain background material on nitrogen oxides reduction
techniques, the cost of combustion modifications, methods and equipment for efficiency-
improvement, and a discussion of combustion generated air pollutants. Earlier
documents in this series are: EPA-600/2-75-069a (residential oil burners) and
EPA-600/2-76-088 (commercial oil-fired boilers).
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Air Pollution, Efficiency, Combustion
Nitrogen Oxides, Nitrogen Oxide (NO)
Nitrogen Dioxide, Smoke
Carbon Monoxide, Energy, Conservation
Fuel Oil, Natural Gas, Coal
Burners, Boilers
Air Pollution Control
Stationary Sources
Combustion Modification
Energy Conservation
Excess Air
Boiler Tune-Up
Fuel Use
13B,14A,21B
07B
21D
13A
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
105
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
101
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