United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Washington, DC 20460
EPA-340/1-92-004a
November 1991
Final Draft
Stationary Source Compliance Training Series
COMBUSTION SOURCE
INSPECTION
Student Reference Manual
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EPA 340/1-92-004a
FINAL DRAFT
COMBUSTION SOURCE INSPECTION
STUDENT REFERENCE MANUAL
by
International Technology Corporation
Air Quality Services
3710 University Drive, Suite 201
Durham, North Carolina 27707-6208
Contract No. 68-02-4468
Work Assignment No. 57
PN 3770-57
Ms. Joyce Chandler, Work Assignment Manager
Aaron R. Martin, Project Officer
U.S. ENVIRONMENTAL PROTECTION AGENCY
STATIONARY SOURCE COMPLIANCE DIVISION
OFFICE OF AIR QUALITY PLANNING AND STANDARDS
WASHINGTON, D.C. 20460
November 1991
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DISCLAIMER
This report was prepared for the U.S. Environmental Protection Agency by PEI
Associates, Inc., Durham, North Carolina, under Contract No. 68-02-4466, Work
Assignment No. 57. The contents of this report are reproduced herein as received
from the contractor. The opinions, findings, and conclusions expressed are those of
the author and not necessarily those of the U.S. Environmental Protection Agency.
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CONTENTS
Figures v
Tables x
Acknowledgment xi
1. Section 1 - Introduction 1
2. Section 2 - Fundamentals of Combustion 5
Introduction 5
Principles of combustion 5
Stoichiometric reactions 9
F-Factors 20
Adiabatic flame temperature 28
Thermal efficiency of boilers 29
Summary 40
References 41
3. Section 3 - Combustion Equipment 41
Oil and gas combustion 43
Coal combustion 58
Wood-fired combustion 94
Municipal wastes and refuse derived fuels 104
Combustion in cupolas and blast furnaces 110
References 115
4. Section 4 - Boiler Equipment and Steam Cycles 117
Introduction 117
Heat transfer concepts 117
Steam characteristics 119
Boiler components 121
Steam cycle 129
References 135
HI
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CONTENTS (Continued)
5. Section 5 - Inspection Procedures for Combustion Processes 137
Determination of compliance with operating limits „ 139
Determination of gas volume and gas conditions . 140
Determination of gas volume from boilers 148
Conclusions 152
6. Section 6 - Air Pollution Control For Combustion Applications 155
General 155
Paniculate control 157
Sulfur dioxide control 188
Control of nitrogen oxides 197
Control of other pollutants 204
References 205
7. Section 7 - Emissions and Process Monitoring 207
Continuous emissions monitoring 207
Control equipment 246
Process rates 274
References ~. 278
8. Section 8 - Combustion Problems 279
Introduction 279
Excess air problems 279
Fuel characteristics 287
Boiler operation and maintenance 290
Case examples 293
Appendices
A. New Source Performance Standards Subparts Da and Db A-1
B. Sample Inspection Checklists B-1
C. Sample Combustion Calculation Forms C-1
IV
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FIGURES
Number Page
2-1 Rshtail and bunsen burner for combustion of methane 8
2-2 CO2 versus excess air for different fuel types 24
2-3 Graphical method for determination of adiabatic flame temperature 30
2-4 ABMA radiation chart 39
3-1 Circular register burner with water-cooled throat for oil
and gas-firing 45
3-2 Typical gun burner high pressure nozzle 51
3-3 Typical return-flow pressure atomizer 53
3-4 Typical rotary-cup burner 53
. *
3-5 Steam atomizer tip 54
3-6 Low excess air burner 56
3-7 End view of low excess air burner 57
3-8 Water-cooled stationary grate 68
3-9 Two views of a dumping grate 68
3-10 Vibrating grate 69
3-11 Reciprocating grate 69
3-12 Oscillating grate 70
3-13 Traveling grate 71
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FIGURES (Continued)
Number Page
3-14 Belt, reciprocating, types of coal feeders for spreader-stokers 73
3-15 Pneumatic distributor used for burning refuse with coal in a
spreader-stoker 74
3-16 Grate-clip overlap used on a traveling grate stoker 75
3-17 Schematic of a traveling grate showing air zones 76
3-18 Schematic of a traveling grate stoker showing the air
supply system 77
3-19 Guidelines for coal sizes for a spreader-stoker 79
3-20 Photograph and cutaway diagram of single-retort underfeed
stoker with reciprocating ram 81
3-21 Single retort underfeed stoker with undulating grate 82
3-22 Diagram of an underfeed stoker showing air supply 82
3-23 Horizontal burner 90
3-24 Circular register burner 90
3-25 Intervene burner • 91
3-26 Directional burner 91
3-27 A CFB design 93
3-28 Wood hogger 95
3-29 Small spreader-stoker furnace 100
3-30 Material and energy balances for a representative
bagasse-fired boiler 103
3-31 Mass burn combustor 106
VI
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FIGURES (Continued)
Number Page
3-32 Basic design of water-cooled cupola 111
3-33 Location of cupola zones 113
4-1 Example of water tube boiler showing heat transfer sections 123
4-2 Radiant boiler for pulverized coal 125
4-3 Detail of a steam drum 126
4-4 Illustration of a rotary regenerative air heater 129
4-5 Rankine cycle 131
4-6 Double reheat cycle 133
5-1 Simplified fan curve 145
5-2 Radiation loss in percent of gross heat input 153
6-1 Muto'cydone cross section 159
6-2 Cyclone tube detail 160
6-3 General relationship between penetration and particle size for
wet scrubbers 164
6-4 Venturi scrubber 166
6-5 Orifice scrubber 167
6-6 Rod scrubber 167
6-7 Simple moving bed scrubber 169
6-8 Preformed spray scrubbers 170
6-9 Initial capture mechanisms of fabric filtration 173
VII
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FIGURES (Continued)
Number Page
6-10 Shaker-type fabric filter 177
6-11 Reverse-air fabric fitter 178
6-12 Pulse-jet fabric filter 180
6-13 Basic processes of electrostatic precipitation 183
6-14 Typical wire-weight ESP 185
6-15 Limestone wet scrubbing system 190
6-16 Typical dry scrubbing system 192
6-17 LNB for pulverized coal-fired boiler 198
6-18 General SCR system 203
7-1 Simplified schematic diagram of a nondispersive infrared analyzer 212
7-2 The ultraviolet-visible spectrum of SO2 and NO2 213
7-3 Operation of a differential absorption NDUV analyzer 215
7-4 Operation of the SO2 fluorescence analyzer 217
7-5 Operation of a chemiluminescence analyzer 219
7-6 Operation of a flame photometric analyzer 220
7-7 Operation of an electrochemical transducer 222
7-8 Operation of an electrocatalytic oxygen analyzer 224
7-9 Operation of a 'magnetic wind" paramagnetic oxygen analyzer 226
7-10 name ionization detector 228
VIII
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FIGURES (Continued)
Number Page
7-11 Types of in-situ monitors 229
7-12 Operation of in-situ differential absorption analyzer 231
7-13 Operation of a cross-stack gas-filter correlation spectrometer 231
7-14 Absorption principles of a gas-filter correlation analyzer 233
7-15 Operation of the second derivative in-stack monitor 235
7-16 Ultraviolet light wavelengths scanned by spectrometer moving mask 236
7-17 Scanning a broad band absorption 237
7-18 Scanning an absorption peak 238
7-19 Single-pass transmissometer system 241
7-20 Double-pass transmissometer system 241
7-21 Transmissometer siting 244
7-22 Typical plot plan layout for recording ESP operating data 253
7-23 Comparison of T-R set trip patterns for two different days 255
7-24 Graphical display of plate area of service over a 30-day period 256
7-25 Graphical plot of secondary current versus field for a
3-chamber ESP 257
7-26 Example of graphical displays of secondary current and voltage
versus day of operation 258
7-27 Typical air-load test V-l curve for an ESP on a recovery
boiler with normal dust layer 260
7-28 Comparison of typical air load and gas load V-l curves 262
7-29 Typical bag replacement record 267
ix
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TABLES
Number Page
3-1 Viscosity of Fuel Oils 47
3-2 Pour Points for Various Grades of Fuel Oil 49
3-3 API Gravity of Fuel Oils 50
3-4 Boiler Turndown Ratios for Various Types of Burners 57
3-5 ASTM Specifications for Classifying Coals According to Rank 59
3-6 Operating Characteristics of Various Types of Stokers 65
3-7 Approximate Range in Size and Moisture Content of Typical
Components of Hogged Fuel 97
3-8 Typical Proximate Analyses of Moisture-Free Wood 97
3-9 Air Requirements (STP) for Combustion 114
7-1 Infrared Band Centers of Some Common Gases 211
7-6 Opacity Monitor Performance Specifications 245
7-7 Control Equipment Monitoring Requirements for NSPS Sources 247
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ACKNOWLEDGMENT
This report was prepared for the U.S. Environmental Protection Agency,
Stationary Source Compliance Division, by PEI Associates, Inc., Durham, North
Carolina. The project was directed by Mr. David R. Dunbar and managed by Mr. Gary
Saunders. The principal authors were Mr. Gary Saunders, Mr. Craig Mann, Mr. Roy
Paul, Mr. John Carroll, and Mr. Darrell Hollowed. We would like to acknowledge Ms.
Joyce Chandler, the U.S. Environmental Protection Agency Work Assignment
Manager, and Mr. Kirk Foster for their overall guidance and direction on this work
assignment.
XI
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SECTION 1
INTRODUCTION
The stationary source combustion process is one of the most prevalent
processes that Federal, State, and local agencies have the responsibility of regulating
and inspecting. Estimates indicate that there are more than 10,000 industrial boilers
permitted and operating in the United States. In addition, there are over 1000
electrical utility boilers. These operations represent the largest use of the combustion
process for the generation of steam and electricity.
The combustion process is not limited to the generation of steam and electricity.
The combustion of fuel to produce heat is necessary for other processes. In the
operation of cement and lime kilns. The performance of the kilns is influenced directly
by the combustion process and the efficient use of fuel. In the pulp and paper
industry, combustion of black liquor in recovery boilers is an essential process and
recycle loop in the economic production of paper. Many of the operations in the
metals processing industries also requires proper and efficient combustion of fuel.
The oil refining operations generate waste by-products that may be used as internal
fuel for heat and steam production in the refining process. Each of the industries have
their unique characteristics associated with the use of the combustion process.
However, each also shares a common process operation; the efficient combination of
fuel and air to produce heat for use by a process.
The prevalence of combustion processes in the industrial environment make it
essential that those responsible for the inspection and permitting of these processes
have a solid understanding the fundamentals involved in the combustion process. The
impact from emissions associated with combustion processes is very significant. Large
quantities of paniculate matter, sulfur dioxide (SO2), nitrogen oxides (NOJ, carbon
monoxide (CO) and a large number of noncrrteria pollutants are released from the
combustion process even when it is operated efficiently. The potential to emit some
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pollutants increases substantially when a combustion process is operated poorly or
inefficiently. In many cases, the combustion process may be overlooked because the
product (heat or steam) of the combustion process is considered secondary to a
facility's main product (e.g., paper or cement). A poorly or inefficiently operated
combustion process generally, however, requires an increase in fuel consumption to
compensate for the inefficiencies with a corresponding increase in the cost of
production and emissions. Examples exist to illustrate where the inefficient operation
of several boilers at a facility have resulted in the substantial contribution to a
nonattainment area for SO2. The excessive consumption of fuel to produce the steam
required for process operations resulted in excessive SO2 production, which ultimately
resulted in the designation of an SO2 nonattainment area (see Section 8 for details of
this case example). This type of problem could have been revealed and resolved by
an understanding of the combustion process and some relatively simple inspection
and evaluation procedures. There are many such examples where the poor or
inefficient operation of a combustion process has resulted in excessive emissions.
Many of these problems can be discovered through an effective evaluation of the
combustion process and some relatively simple calculations.
This manual has been developed to be used as a basic reference to the
Combustion Workshop developed for the U. S. Environmental Protection Agency
(EPA). It will provide the reader with fundamental information for evaluating
combustion processes. Although the manual cannot be the definitive reference
document to cover ail situations, it does provide the reader with the basic and most
important aspects of the combustion process. It also serves as a bibliography to
identify additional references that may be used to obtain more detailed information.
The manual is organized into sections or lessons to provide the reader with
information on the fundamentals of combustion, the types and design features of
equipment, important inspection points, and the relationship between combustion
efficiency and performance and emissions and/or control equipment performance.
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The manual begins with fundamentals of the combustion process and relationships
that are universal in all combustion processes (Section 2). These basic equations will
be used in the evaluation of all combustion sources and a solid understanding of
these principles is necessary for any evaluation of combustion equipment. The
concepts of fuel analysis, combustion products, excess air, and combustion efficiency
are discussed in this chapter. Section 3 discusses differences in equipment design for
different fuel types including gas, oil, coal, wood, and refuse derived fuel (RDF).
Although combustion processes share the same basic chemical reactions, the process
equipment that is used to carry out the combustion process and to use the energy
varies according to the fuel properties as well as the process. The importance of
these differences is discussed.
Section 4 addresses the characteristics of steam cycle and steam generation
because many of the combustion applications are used to generate steam. Concepts
such as enthalpy, saturated steam, steam superheat, and thermal efficiency of steam
cycles will be discussed.
Section 5 addresses the procedures that may be used for inspecting and
evaluating combustion processes. These procedures include gathering of process
and fuel analysis data, measurement of flue gas composition and temperature, and
calculation of flue gas volume from the combustion process. These data and
calculations will also indicate thermal efficiency of steam generation processes, the
percent excess air, and whether the gas volumes are consistent with design values.
Section 6 discusses the various control equipment options for pollutants
generated from the combustion process. The categories for control include paniculate
matter, SO2, NOX> and noncriteria (air toxic) pollutants. Within each category is a
discussion of control equipment type, basic principles of operation, and the
identification of key parameters that should be examined during an inspection.
Section 7 addresses the subject of process and emissions monitoring. Process
monitoring includes such items as fuel firing rate, steam
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generation rate, steam temperature and pressure, and gas temperature. Emissions
monitoring may be required for many processes and for pollutants such as paniculate
(as opacity), SO2, NOX, and CO. Oxygen (O2) monitors are also required for the
determination of emission rates and for combustion control. The basic operating
principles of these monitors as well as the practical evaluation of the monitoring data is
discussed.
Section 8 addresses the integral relationship between the combustion process
and the generation of pollutants and control equipment performance. Examples are
provided to illustrate this relationship between the combustion process and the
resulting emissions. In general, it has been observed that combustion problems
adversely affect control equipment performance. Very often the excess emissions that
are observed with combustion sources are the result of combustion problems that
must be addressed to correct the problem. This occurs most often with paniculate
matter emissions but may also affect the emissions of other pollutants as well. This
section summarizes the most common problems and some of the solutions that are
available.
The user of this manual is encouraged to explore the combustion process and
all its aspects by obtaining and reviewing other references. This manual attempts to
condense a large body of information into a convenient reference for the evaluation of
combustion sources and was developed as a supplement to a three-day workshop on
the evalaution of combustion sources, processes, and control equipment. Most of the
major considerations in the design, operation, and evaluation of combustion sources
have been included. To the extent possible, the manual presents the latest concepts
and techniques that are important to the overall evaluation of combustion processes.
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SECTION 2
FUNDAMENTALS OF COMBUSTION
2.1 Introduction
The presence of O2 in the atmosphere leads to oxidation of various materials.
Iron oxidizes to form rust, copper oxidizes to produce a green tarnished color, and
silver oxidizes to a tarnish that we remove from jewelry and other silver items. These
examples of oxidation are representative of a slow oxidation process. Combustion is
also an oxidation process but it is relatively rapid and produces heat. The industrial
applications of combustion involve the use of a fuel to produce heat that can be used
for purposes such as heating water to steam, generating electrical energy, or melting
or refining raw materials. The efficient and cost effective use of combustion processes
requires a basic understanding of combustion steps and combustion theory that apply
almost universally to all fuel types and applications.
2.2 Principles of Combustion
: Most of the major combustion operations of commercial importance rely on the
combustion of mixtures of carbon (C) and hydrogen (H2) known as hydrocarbons.
Fuels such as natural gas, fuel oil, coal, and wood are mixtures of simple and complex
arrangements of C and H^ Other elements may be included in the molecular
structure such as sulfur (S) and nitrogen (NJ, which also release heat when they are
oxidized but are generally considered undesirable contaminants and contribute very
little to the total heat generated. A small quantity of O2 may also be included in the
molecular structure of some of the hydrocarbons and is included as a source of O2
when the combustion process occurs.
The combustion of fuel to produce useful heat is a complex chemical reaction.
There are many different hydrocarbon structures that participate in the combustion
process. The basic chemical reactions of combustion can be simplified and
summarized by the equations:
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C + O2 •» C02 (1)
and
H2 + 14O2 •» H2O. (2)
The actual chemical reactions that occur during the combustion of fuel are more
complicated than these two simple chemical reactions. Every type of fuel that is used
in the combustion process involves these two reactions to form the combustion
products of carbon dioxide (COJ and water. These two chemical reactions form the
basis of combustion calculations and the analysis of boiler performance.
Normally, fuel does not spontaneously combust because several other
conditions must be satisfied to start and maintain combustion. Rrst, all fuels bum as a
gas. Even solid and liquid fuels must be gasified for combustion. Once in gaseous
form the fuel can then be intimately mixed with the O2 in the air. A fuel such as natural
gas requires no gasification because it already exists as a gas. Fuels such as oil,
coal, and wood, however, generally require heat to break down and gasify the
components so that combustion can take place. A wax candle serves as a useful
illustration of this gasification and combustion process.
The candle wick contributes little to the heat generated by combustion and is
eventually consumed as the candle is burned. The wick may be burned initially but
the heat from this burning (or from a match) serves to melt a small pool of wax that is
drawn up the wick toward the flame. The liquid wax is gasified as it approaches the
heat of the flame, combines with O2, and combusts to release heat, which continues
the melting, wicking, gasification, and combustion process. Without the wick to
promote this process, the candle would not bum. The candle also illustrates the need
for the heat release to be high enough to continue the combustion process. Any
contact of the flame with a cold surface stops the combustion process and produces
soot and smoke due to unbumed C.
The volatilization of hydrocarbons in solid fuels follows an analogous path to the
example provided by the candle. The volatile components are driven off by additional
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heat and combusted to provide heat for the process to continue. The reaction of 02
with the remaining C also relies on the very high heat release to raise the temperature
to C incandescence so that 02 can penetrate the C surface and react with the C to
form CO2.
The reaction of hydrocarbons can follow many different paths to the eventual
formation of water vapor and CO^ The reaction of the simplest hydrocarbon,
methane, illustrates the different paths that are available for combustion. Two
examples of burning methane are a laboratory bunsen burner and the burner tips of
gas lanterns used prior to the introduction of the electric light bulb (Figure 2-1). The
gas lantern produces a yellow, highly luminous flame and the bunsen burner produces
a very hot, but nonluminous flame. The difference in the two types of flame are
related to the combustion path that is followed. The gas lantern flame does not mix
O2 with the methane until the gas leaves the tip of the burner. The heat from the flame
(once established) raises the temperature of the methane gas stream. At the same
time gas and O2 from the air are mixing to reach the proper ratio for combustion.
Suddenly, the mixture reaches the proper proportion and begins to bum rapidly. The
sudden increase in temperature thermally decomposes or cracks the hydrocarbon
structure to its constituents of H2 and C. The H2 bums to form water and the C
reaches incandescence and burns to give the flame its yellow color. The bunsen
burner premixes a portion of O2 to the methane at the base of the burner tube. The
quantity of air introduced is less than that required for combustion, but the premixing
and heating lead to the formation of hydroxylated compounds in the flame. The
addition of more air at the burner tip to the proper burning ratio results in a near
colorless, nonluminous flame. Although the reaction produces the same combustion
. \
products of water vapor and CO2 and releases the same quantity of heat, the reaction
path is completely different as there is no thermal cracking in the bunsen burner flame.
With natural gas (or any gaseous fuel), the mixing of air and fuel to produce
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Ml cordon A/mft/
of edge of flame
releases coroan
Air mixes here- —
not, et heated
ahead of burner
Fish-tail burner tip
Illuminating gas
2. Thermal decomposition of gas supplied
to a fishtail burner yields yellow flame
"Non-Juminous*
flame"'
Secondary air
enters here ~'
'Hottest part
of flame
Illuminating gas
3. Gas and air mix before reaching flame
in Bunsen burner, producing a blue color
Figure 2-1. Fishtail and bunsen burner for combustion of methane.1
8
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nonluminous flame is relatively simple. It is much more difficult to achieve this effect
with liquid of solid fuels and in practical burning situations both thermal cracking and
hydroxylation processes occur simultaneously in the flame.
Efficient combustion of any fuel requires a combination of three factors as
illustrated above. These three factors are time, temperature, and turbulence and are
known as the Three-Ts of Combustion." Combustion requires the time for the
reaction to be initiated and completed, at a sufficiently high temperature, with adequate
mixing between O2 and the fuel. In general, as one of the factors is decreased the
others must be increased to compensate for the decrease. Although the combustion
process is primarily a chemical reaction, most of the important factors that contribute
to the efficient combustion of fuel are related to mechanical actions. Consequently,
most of the problems that occur in the combustion process are mechanically related.
It is important to understand these principles of combustion. The equations and
calculations used in evaluating the combustion process reveal only part of the picture.
The evaluation of any combustion process requires both the use of the calculation
procedures and an understanding of how combustion occurs.
2.3 Stolenjometric Reactions
As noted previously, all fuels bum as a gas and fuels that start as a gas are
generally the easiest to bum because all that has to be done is to add O2 and a
.source of heat to start the combustion process. The heat of reaction should then
sustain the combustion process as long as there is adequate fuel and O2. There is a
limited range of air/fuel mixtures, however, where the combustion process will occur.
If the air/fuel mixture falls outside of this range then the combustion process will not
occur. These are the flammabilrty limits of a fuel. The upper flammability limit of a fuel
is the minimum air/fuel (fuel-rich) mixture that will support combustion. The lower
flammability limit is the maximum air/fuel (fuel-lean) mixture that can support
combustion. As long as the air/fuel mixture is between these limits, combustion can
occur.
9
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For each fuel, within these flammability limits, there is one ideal or perfect
quantity of O2 (air) that will provide just enough O2 to completely combust the C and
H2 as shown in Equations 1 and 2. This is known as the stoichiometric quantity or
ratio for the reaction to occur. Under ideal conditions, combustion of any fuel with a
stoichiometric quantity of air results in a reaction where the combustion products are
only a mixture of CO2, water vapor, and N2 from the initial quantity of air that did not
participate in the reaction. If the quantity of air used was greater than the
stoichiometric ratio, then the resulting flue gas would also contain the extra, unused O2
and N2. If the quantity of combustion air was less than the stoichiometric ratio, then
insufficient O2 would be available for complete oxidation of the hydrocarbons in the
fuel. The result is incomplete combustion producing CO, unbumed C, and partially
cracked hydrocarbons.
2.3.1 Fuel Analysis
An analysis of the fuel to be burned is required to determine the stoichiometric
ratio of fuel that will be required. Generally this is in the form of a fuel ultimate
analysis, which presents the weight percentage of chemical elements in the fuel. The
ultimate analysis can be presented in several formats, particularly for solid fuels.
Examples are as-fired, moisture-free, and moisture and ash-free. The most useful
value is the as-fired value because it represents the analysis of the fuel as it enters the
combustion process. The as-fired ultimate analysis generally provides the weight
ratios of C, H2, N2, S, ash, moisture, and O2 in the fuel. Sometimes other elements
such as chlorine may be included as part of the ultimate analysis. In addition the
ultimate analysis also provides a heat value for the fuel typically expressed in Btu/lb
although it may be expressed as Btu/gal for liquid fuels or Btu/ft3 for gaseous fuels. It
should be noted that for solid fuels a proximate analysis may be conducted. This
provides an indication of volatile matter, fixed C, moisture, and ash content. Although
the proximate analysis is useful in evaluating the burning properties of solid fuels, it
does not assist in the calculation of combustion air requirements. A proximate
analysis, however, can be mathematically converted to an ultimate analysis.
10
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The combustion air requirements can be determined from the as-fired fuel
analysis. The reactions in Equations 1 and 2 represent chemical reactions as mole
quantities (a mole is defined as the quantity of atoms or molecules required to equal
the molecular weight of a substance). A mole of one substance contains the same
number of atoms or molecules as a mole of another different substance although their
masses differ. Or viewed more simply, the combustion air requirement is the ratio of
molecules that are needed to perform the chemical reaction. In Equation 1 the
reaction specifies one O2 molecule for each C atom to form a molecule of CO2 .
Equation 2 specifies one-half of an O2 molecule for each H2 molecule. The weight
requirements for each of the compounds can be determined by the molecular weights
of each of the compounds. The molecular weights of the compounds involved in
Equations 1 and 2 are listed below:
C 12.01 Ib/lb-mole
O2 32.00 Ib/lb-mole
H2 2.016 Ib/lb-mole
CO2 44.01 Ib/lb-mole
Water (H2O) 18.016 Ib/lb-mole
The reaction between C and 02, therefore, could be stated as follows:
12.01 Ib C + 32 Ib O2 -> 44.01 Ib CO2, or (3)
combustion of 1 Ib of C requires 2.66 Ib of O2 to produce 3.66 Ib of CO2. This
reaction produces 14093 Btu/lb C combusted as heat release. A similar weight
equation could, be written for the reaction of H,, with O2:
2.016 Ib H2 + 16 Ib O2 -> 18.016 Ib H2O, or (4)
combustion of 1 Ib of H2 requires 7.94 Ib of O2 to produce 8.94 Ib of water vapor.
This reaction between H2 and 02 produces 61100 Btu/lb H2 combusted as heat
release. Before leaving these fundamental reactions, several fundamental laws that
are used in combustion calculations should be stated.
11
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2.3.2 Conservation of Mass and Energy
The first law is the conservation of matter that states that matter is neither
created nor destroyed. This is illustrated in Equations 3 and 4 where the total mass
on the left side of the equation is equal to that one the right. The sum of the quantity
entering the process is equal to that leaving the process. The second law is the
conservation of energy that states energy is neither created nor destroyed. The sum
of the energy entering the process must equal the sum of the energy leaving the
process. In the combustion process, the energy enters as chemical energy and on
reaction leaves as heat. (Note: these first two laws are adequate for the combustion
calculations. Matter and energy are generally thought of as being interchangeable at
the atomic level and the combustion reaction does result in the conversion of a small
quantity of matter into energy. This quantity, however, is too small to be measured in
practical combustion applications and is generally ignored.) The third law is the law of
combining weights, which states that all substances combine in accordance to simple
weight relationships. As shown in Equations 3 and 4, compounds combine in
accordance to their molecular weights. This law is related to the law of conservation
of mass.
2.3.3 Ideal Gas Law
There are also several laws related to the behavior of gases that are important
in combustion calculations and are used to convert between mass and volume
occupied by combustion gases. For gases, a mole also is related to the volume of
space occupied by the gas at specific temperature and pressure conditions. Under
most combustion situations the gases behave according to the ideal gas law. The
ideal gas law relates volume, temperature, and pressure and states that for all ideal
gases these factor together to a constant value. The traditional ideal gas law equation
is:
12
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pV = nRT (5)
where:
p = Absolute pressure, Ib/ft2
V = Volume, ft3
n = Number of moles of gas
T = Absolute temperature, degrees Rankine (degrees F+460)
R = Ideal gas constant, 1545 ft Ib/mole degree R.
A consequence of the ideal gas law is that equal volumes of different gases contain
the same number of molecules. The ideal gas law allows for the calculation of the
volume of any ideal gas at atmospheric pressure for any temperature. Reference
temperatures vary according to application (boiler applications typically reference 80
°F) and one must be careful to know the reference temperature when converting from
one condition to another. In addition, Amagat's law states that the total volume of a
mixture of gases at any temperature and pressure is equivalent to the sum of the
individual volumes of each of the gases at the same temperature and pressure. This
law is particularly useful in determining flue gas composition from combustion
calculations. Extending Amagat's law further it is possible to show that the mole
fraction of any gas will also be equivalent to the volume fraction of any gas, where the
mole fraction is calculated by the equation:
Mole fraction (component i) = moles i/totaJ moles all components (6)
and
Volume fraction (component i) = mole fraction (component i). (7)
The combustion calculations thus far have involved only C and H2. In most fuel
combustion situations the reaction between S and O2 is also considered according to
the reaction:
S + O2 -, SO2 (8)
or 1.00 Ib of O2/lb of S to produce 2.0 Ib of SO2/lb S combusted.
13
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The total O2 requirement for a given fuel is determined by summing the O2
requirement for combustion of each of the three components listed (C, H2, and S) and
deducting the quantity of O2 found in the fuel because it is presumed to participate in
the combustion process. Thus, the theoretical O2 requirement can be found from an
ultimate analysis by summing the following factors:
% C/100 x 2.66
% H2/100 x 7.94
% S/100 x 1.00.
and subtracting the amount of O2 contained in the fuel (% O2/100). The resulting total
represents the O2 requirement under stoichiometric conditions to provide complete
combustion of the fuel. An example to illustrate the procedure is provided below.
i
Example 1
Determine the O2 requirement for the given ultimate coal analysis:
Ultimate' analysis • Required for combustion
Ib/lb fuel as-fired Ib/lb fuel as-fired
C 0.7279 x 2.66 1.9362
H, 0.0483 x 7.94 0.3835
0* 0.0657
N* 0.0136
S 0.0091 x 1.00 0.0091
H,0 0.0542
Ash 0.0801
Cl, 0.0011
Sum 1.0000 2.3288
Less 02 in fuel 0.0657
Required 0 ' 2.2631
2.3.4 Excess Air
Thus far the discussion of combustion requirements has only included
stoichiometric conditions and has involved only O2. Stoichiometric conditions
14
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represent the ideal situation with perfect mixing and complete reaction between the
fuel components and the O2. Unfortunately, the practical applications of combustion
principles are not ideal although, in some cases very close approximation of the ideal
are possible. To compensate for the less-than-ideal situation, excess O2 is usually
introduced to help assure that adequate 02 is available for complete combustion? The
excess O2 is also present in the combustion products gas, whereas in the
stoichiometric condition none would be present The quantity of excess O2 present or
specified in a combustion system design would depend on the fuel type and the
combustion method (combustion methods are more fully discussed in Section 3). In
general, more excess O2 is made available as the fuel becomes more difficult to bum,>
although there are other trade-offs that must be considered.
Although there are operations that use pure 02 for combustion, most use air as
their source of O2 in combustion. Air is a mixture of N2 (78.03 percent by volume), O2
(20.99 percent by volume), water vapor, and inert gases such as argon (inert gases
account for 0.98 percent by volume). These values are typically converted to weight
percents for use in combustion calculations although they are usually measured as
volume percentages. Inert gases are usually included with N2 in the weight
percentages yielding values of 76.85 percent and 23.15 percent by weight for N2 and
O2, respectively. The N2 and inerts occupy volume and must be accounted for in the
design of combustion equipment The procedure outlined previously to determine the
O2 requirements can be used to determine the total quantity of air required and the
quantity of combustion products produced because the weight ratio of the O2 and N2
in air are constant values.
The weight ratio of 02 required to combust with C, H2, and S were shown
previously (2.66, 7.94, and 1.00, respectively). Because the quantity of air per pound
of O2 is also a fixed ratio, then the quantity of air required to combust C, H2, and S
should be the O2 requirement multiplied by a factor. The multiplication factor is 4.32
(derived from 100 Ib dry air/23.15 Ib OJ. Thus, to stoichiometrically combust C, H2,
and S requires 11.53, 34.34, and 4.29 Ib dry air/lb, respectively.
15
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Excess air and excess O2 are terms that are often used interchangeably. For
design purposes they are calculated in an identical manner but refer to different
elements of the same combustion calculation. The purpose of excess air is the same
as discussed for excess O2, to compensate for the nonideal combustion
characteristics of actual equipment and fuels. When evaluating operating combustion
equipment, the measurement of excess O2 and the determination of the quantity of
excess air are important parameters. They have a direct influence on the combustion
and heat transfer efficiency of steam generators and the quantity of flue gas that must
be handled by gas moving equipment and air pollution control equipment. The
evaluation of combustion equipment will be discussed in Section 5 of this manual. An
example is provided below for the calculation of the air requirement, including excess
air, for a fuel with a known fuel analysis.
Example 2
Determine the air requirement for combustion with 30 percent excess air for the
given coal ultimate analysis:
Ultimate analysis Required for combustion
Ib/lb fuel as-fired Ib/lb fuel as-fired
C 0.7279 x 11.53 8.3927
H, 0.0483 x 34.34 1.6586
0, 0.0657
N2 0.0136
S 0.0091 x 4.29 0.0390
H,0 0.0542
Ash 0.0801
C12 0.0011
Sum 1.0000 10.0903
Less 0, in fuel (as equivalent air) 0.2838
Stolchiometrlc air requirement 9.8075
Excess air (30 percent) 2.9422
Total Air Requirement 12.7497
16
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The air requirement for any fuel with a known fuel analysis can be calculated
using the method above. One of the principal advantages to the weight method of
calculating air requirement is that it does not require conversion of the weight
percentages obtained from the ultimate analysis into mole units. It should be noted
that the O2 contained in the fuel was converted into equivalent air using the same
weight ratio factor between O2 and air as discussed previously and subtracting that
value from the other air requirements. The excess air may be calculated once this
adjustment is made.
2.3.5 Estimation Combustion Products
The air and O2 requirements that are calculated give only values for combustion
requirements for a given fuel. The calculations cannot predict whether the combustion
process will be efficient. There are no parameters available in the combustion
calculations to calculate the amount of unbumed C that may remain or to predict how
efficient the fuel/air mixing will be. In practical applications this presents a problem
because the measurement of operating conditions may indicate that an adequate
amount of excess air may be present but combustion efficiency may be poor due to
inadequate mixing of the fuel with air, low temperatures due to low firing rates, etc.
Another extremely useful combustion calculation is the estimation of the quantity
of combustion products that result from a given fuel and excess air level. The same
material balance and use of the fundamental laws will allow the calculation of the
quantity of the combustion products generated. The numerical factors have been
derived previously in Equations 3, 4, and 8 and are only summarized here. These
factors are applied to the fuel ultimate analysis to calculate the quantity of combustion
gas produced:
% C/100 x 3.66 = Ib CCyib
% H2/100 x 8.94 = Ib H2O/lb
% S/100 x 2.00 = Ib SCyib
17
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In addition to these combustion products, the combustion calculations must take into
account the N2 remaining from the combustion of O2 from the air, the excess O2
remaining after combustion, the moisture from the fuel that is evaporated, and the
moisture in the air that enters into the combustion process. The values used to
calculate the air requirements are based on dry air. The moisture in the air is typically
estimated as a standard air at a fixed relative humidity. This standard air is 80 °F with
a relative humidity of 60 percent to yield a moisture content of 0.013 Ib H2O/lb dry air.
The example below illustrates the combustion calculations that are used to calculate
the quantity of combustion products from a fuel analysis.
Example 3
Determination of combustion products from given coal ultimate analysis and 30
percent excess air:
Ultimate analysis Combustion product
Ib/lb fuel as-fired Ib/lb fuel as-fired
C 0.7279 x 3.66 - 2.6641 (CO,)
H, 0.0505 x 8.94 - 0.4318 (H20)
H,0 0.0657 + (12.7497 X 0.013} - 0.2314 (H*0)
S 0.0091 x 2.00 - 0.0182 (S02)
Excess air
02 (excess) (2.2631 x 0.30) - 0.6789 (0,)
N2 0.0136 + (12.7497 x 0.7685)- 9.8117 (N2)
Total weight, wet 13.8130
Total weight, dry 13.1498
The calculation of the combustion products from the example fuel analysis
illustrates several items. First, the contribution of fuel moisture and moisture from the
air represent a smaller fraction of the moisture in the flue gas than that from the
reaction of H2 in the fuel. This is generally true for fuels, except for those with
inherently high moisture (such as wet wood). Second, the major portion of the flue
gas is composed of N2 that is brought into the reaction with the combustion air but
18
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does not participate in the reaction itself (in actuality a small proportion of the N2 from
the air or the fuel does react to form NO2 but is not considered here). Small increases
in excess air can result not only in a substantial increase in the combustion air
admitted to the process but also results in a substantial increase in the quantity of
combustion products. Die combustion of fuel releases heat that ultimately results in
heating the combustion gases. The greater the quantity of flue gas to be heated
means that the gas temperature must necessarily be lower since the heat content is a
"fixed" value with respect to the fuel being burned. This will be more fully discussed in
later sections with respect to boiler efficiency.
2.3.6 Summary of Calculations for Theoretical Air and Combustion Products
The procedures for calculation of the combustion air requirements and the
quantity of combustion products that were outlined in examples 1, 2, and 3 can be
summarized by two equations. The theoretical air requirements can be determined by
the equation:
11.53 C + 34.34 (H2 - CyS) + 4.29 S (9)
where C, H2, O2, and S are the fractional percentage, by weight, of these components
in the fuel. The additional air requirement for a given excess air can be determined by
adding the excess air value to the minimum value determined for stoichiorrietric
conditions. The quantity of the products of combustion can be determined from the
combination of the ultimate analysis and the air requirements. The theoretical quantity
of combustion products can be determined by the following equations:
CO2 = 3.66 C
H2O = 8.94 H2 + H2O
SO2 = 2.00 S
N2 = 8.86 C + 26.41 (H2 - (y8) + 3.29 S + N2 (10)
The values for H2O and N2 on the right-hand side of the equation represent the
fractional percentage as determined from the coal analysis. The values on the left-
hand side of the equation are in units of Ib/lb fuel as-fired. It should be noted that this
19
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second set of equations represent stoichiometric conditions only using dry air. Further
adjustments are necessary as shown in example 3 to correct for moisture in the
combustion air in addition to excess air.
2.4 F-Factors
F-factors describe the relationship between the heat input and the quantity of
combustion gas produced. Hie F-factors are based on the relationships described
previously for the stoichiometric reactions between fossil fuels and O2 in the air. The
F-factor concept was developed to assist in the evaluation of emission rates from
combustion sources. Many regulatory limits are based on a heat input limit (i.e.,
lb/106 Btu) and during testing it may be difficult to determine the heat input rate into a
process because fuel feed rate may not be measured. During testing, however, the
volumetric flow rate is usually measured as are the combustion gas composition and
temperature. When combined with an ultimate analysis of the fuel, the heat input rate
and fuel feed rate can be determined. If an ultimate analysis is not available, then one
can use published values for the F-factors for the fuel(s) of interest (Appendix A).
F-factors can be very useful in the evaluation of operating combustion sources. The
flue gas produced by combustion can be estimated directly if the fuel firing rate is
known and if flue gas composition and temperature are measured. The volume of flue
gas is usually important to the operation of any air pollution equipment. If fuel feed
rate is not known then other methods of estimating the flue gas volume must be used.
Another method using F-factors exists for estimating flue gas volume from boiler
operation providing other operating data are available. This will be discussed further
under the concepts of boiler efficiency.
The basic F-factor equations can be divided into two categories: wet basis and
dry basis F-factors. The dry basis F-factors for fuels relate the volume of dry flue gas
produced per unit of heat input. If the ultimate analysis of a fuel is known then the
quantity of dry flue gas produced under stoichiometric conditions can be calculated
using the equation:
20
-------
10* I 3.64 %// + 1.53 %C + 0.57 %5 + 0.14 %/V - 0.46 %O ]
GCV
where the values for each of the components are the percentages of the fuel weight
and the gross caloric value (GCV) is the gross calorific value in Btu/lb of fuel. The
value of Fd is the volume of flue gas per unit heat input as dry standard cubic feet
(dscf)/106 Btu. Standard conditions are defined as an atmospheric pressure of 29.92
in Hg and a temperature of 68 °F.
The wet F-factor Fw accounts for the extra volume of gas produced by moisture
from H2 burning and moisture in the fuel. The wet F-factor is also based on
stoichiometric relationships defined previously, and the conversion of the elemental
composition of the fuel into an equivalent gas volume on combustion. The form of the
wet F-factor equation is similar to the dry F-factor form and is described by the
equation:
m 10* [ 5.56 (%H) * 1.53 (%C) * 0.57 (%S) * 0.14 (%/V) - 0.46 (%O) + 0.21 (HyO) ] /12)
GCV
Values for Fw are only published for fuels that do not typically exhibit wide variations in
fuel moisture content Those fuels that do exhibit wide variations will not have a
published value and will require separate calculation of the value of Fw based on fuel
ultimate analysis and the specific moisture content of the fuel.
These two forms of the F-factor equations, and the values that may be
calculated using them, provide a method of estimating the gas volume produced from
the combustion of a specific fuel that differs from the weight basis previously
discussed. Other corrections to these calculated values are required to the determine
actual cubic feet per minute (acfm) produced by combustion because both predict gas
volume at stoichiometric standard conditions. These corrections are the excess air,
fuel moisture, and temperature correction factors that are discussed below.
21
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2.4.1 Excess Air Correction Factor
The excess air correction factor is applied to the dry gas volume estimate to
account for the increased gas volume associated with excess combustion air. As
noted in the calculations for the weight of gases associated with combustion,
presence of excess air can substantially increase the quantity of gases that are
generated during the combustion process. Determination of the quantity of excess air
is usually necessary to evaluate the combustion process. The excess air value is
typically determined using a portable gas analyzer to determine combustion gas
composition, although onsite instruments may also be used.
The quantity of CO2 and O2 are usually determined as a percentage, by volume,
of the combustion gases. CO may also be measured if suitable instrumentation is
available. Hand-held instruments may be used which include Fyrrte and Orsat
analyzers use as well as electronic analyzers. The Fyrite and Orsat analyzers use a
wet chemical absorption method to determine the combustion gas composition. The
volume displaced by the absorption solution is calibrated to correspond to the volume
percentage in the combustion gas. Electronic instruments expose a cell to the
combustion gas and the cell reacts to the presence of the constituent(s) of interest to
produce an electric signal that is translated to an equivalent volume percentage in the
combustion gas. Orsat analyzers are familiar instruments to those associated with
stack testing procedures. Orsat analyzers are capable of measuring CO2, O2, and CO
while the Fyrite is only capable of measuring O2 and CO2. The Orsat analyzer
provides better accuracy and precision than a Fyrite analyzer but most Orsat analyzers
are not suitably designed for easy field transport for field inspections to evaluate
combustion sources. The Fyrite analyzer or an electronic analyzer may provide a
better choice and should provide suitable accuracy in the ranges of combustion gas
compositions that should be encountered at most combustion sources. If CO
concentrations are low (less than 100 ppm, volume basis) then the concentration of
CO is ignored from a basis of volume determination.
22
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The quantity or percentage of excess air can be calculated from either the CO2
or the O2 concentration in the combustion gases. The O2 concentration is preferred
because the relationship between the quantity of 02 in the combustion gases and the
excess air does not vary significantly with fuel type and can be determined by one
formula. The relationship between excess air and CO2 concentration in the
combustion gases varies depending on fuel type because of the differences in the
C/H2 ratio. These differences are illustrated in Figure 2-2 for different fuel types.
The percent excess air can be calculated by the following equation by
substituting the measured O2 content into the equation:
%O9
Percent excess air = ——-— x 100 (13)
( 20.9 - %O2 )
The equation takes into account the addition of excess N2 and its dilution effect on the
combustion gas composition as the quantity of excess air increases. It can be seen
that at the point where no excess air would be present there would be no O2
measured in the combustion gas stream. Conversely, if ambient air conditions were
measured there would be an "infinite" amount of excess air meaning that no
combustion was occurring.
A different but related equation known as the excess air (E. A.) correction factor
is used to convert the dry gas volume produced at stoichiometric conditions to the dry
gas volume produced at the measured excess air conditions. This equation produces
a multiplication factor to be applied to the Fd value for the measured O2 level in the
combustion gases. The excess air correction factor should not be confused with the
excess air calculation. One equation produces a multiplication factor while the other
produces a percentage value. The excess air correction factor is calculated by the
equation:
23
-------
0 10 20 SO 40 50 60 70 80 90 100
% excess air
Os (natural gas)
Ot (#2-06 oils)
Os (bituminous coals)
COt (bituminous coals)
CO, (#2-#6 oils)
COt (natural oils)
Figure 2-2. C02 versus excess air for different fuel types.2
24
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E A Correction Factor = — (14)
( 20.9 - %O2 )
The difference between the excess air calculation and the excess air correction factor
can be remembered by substituting the value of zero into the percent O2 value. The
excess air calculation will produce a value of zero while the excess air correction factor
will produce a value of 1.00.
The excess air correction factor is applicable only to the dry gas volume
calculation and is applied to the value of Fd to determine the increase in combustion
volume due to excess air. It should also be noted that the O2 measurement must be
on a dry basis (the Fyrite and Orsat analyzers both determine the Combustion
composition on a dry basis). If an instrument is used that indicates the O2 content on
a wet basis then the excess air correction factor will be based low because the
moisture in the gas stream acts as a diluent.
The result of multiplying of the value of Fd by the excess air correction factor
produces a value for the dry gas produced by combustion at a measured O2 (excess
air) content. The units of this value are still dscf/106 Btu.
2.4.2 Fuel Moisture Correction
The evaporation of fuel moisture and the production of moisture from the
combustion of H2 add to the volume produced during the combustion of fuel. The
correction for this additional gas volume takes place separately from the excess air
correction because the excess air correction factor must be applied to a dry gas
value. Generally, the value for the fuel moisture correction can be determined by
simply subtracting the value of the dry F-factor from the value of the wet F-factor to
produce the fuel moisture correction factor (Fw - Fd). If no published value for the wet
F-factor exists then it must be calculated from the as-fired ultimate analysis. The value
of the fuel moisture correction factor is then added to the dry gas F-factor corrected
25
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for excess air to obtain wet standard cubic feet (wscf)/106 Btu. This value will always
be a positive value because Fw is always greater than Fd. (Note: At standard
conditions the moisture from the combustion process may not actually remain in a
vapor state but may condense to form liquid water with a substantial decrease in
actual volume. The moisture, however, is treated as if it remains as a gas at all
conditions since for the majority of combustion applications the gas temperature
remains high enough to keep the moisture in a vapor phase.)
2.4.3 Temperature Correction Factor
The temperature correction factor is applied to account for the expansion of gas
due to heating, assuming that the air pressure remains unchanged. This factor is
merely an extension of the ideal gas law and corrects from the standard conditions to
actual measured conditions. The temperature correction factor is a multiplier applied
to the wet and dry standard cubic foot/106 Btu values to match the actual temperature
conditions of the combustion gas stream. The temperature correction factor is
calculated according to the equation:
Temperature Correction Factor = <°F) * 46° or (°g) * 273 (15)
528 293
with the temperature in the denominator representing the reference temperature at
standard conditions.
2.4.4 Pressure Correction Factor
A pressure correction factor is necessary if operating pressures are
substantially different from normal atmospheric pressure or if due to the elevation of
the process being evaluated. The difference between normal sea level pressure and
the atmospheric pressure at elevations below 1000 feet are normally ignored. At
higher elevations, however, the difference in gas density between sea level and the
26
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site elevation start to become significant and the volume should be corrected for this
difference. The are two methods of producing a pressure correction factor. The
actual atmospheric pressure at the site can be measured and the density correction
factor determined by the equation:
Pressure Correction Factor = 29.92 in. Hg (16)
local barometric pressure (in. Hg)
or the attitude correction factor can be found from standard atmospheric pressure
tables. One of the advantages to working with gas weights instead of gas volumes is
the combustion air and combustion products calculations are unaffected by density
changes due to temperature or altitude.
2.4.5 Factor Summary
The F-factor method allows a quick method of determining the volume of
combustion gas produced based on a fuel ultimate analysis and measurement of
actual gas composition and temperature. The F-factor method is based on the
fundamental combustion principles discussed previously. The F-factor method of
determining gas volume is most useful in the evaluation of actual operating conditions
at combustion sources as will be discussed in Section 5 on inspection techniques.
The gas volume produced by a combustion process can be determined if the fuel
analysis is available (or if the fuel is one of the fuels that has a published F-factor) and
if the heat input rate is known. In summary, the actual gas volume can be determined
from the following equation:
ff / CA rnm**inn\ 1 Temperature Pressure ]
\\\Fd* %ZZr^ + ( F, ~ Fd ) * Correction x Correction \
Gas Votume -\[[ *** > J «" Factor) (17)
x Heat Input Rate ( 10*£&// mln )
27
-------
where the gas volume is the acfm and the values of the F-factors and the correction
factors are determined as outlined previously.
2.5 Adiabatic Rame Temperature
The adiabatic flame temperature is the theoretical maximum temperature that
can be reached by the combustion of a specific fuel and air. The adiabatic flame
temperature assumes complete combustion, no loss of heat to the surrounding
volume around the flame, and no disassociation of the combustion products due to
high temperature. The adiabatic flame temperature may also be considered the
average flame temperature. This value is sometimes useful in examining combustion
processes where there is a combustion problem due to high excess air or excessive
fuel moisture because it calculates a maximum temperature that could be achieved.
Temperature is one of the three important parameters in combustion.
In practical applications, the adiabatic flame temperature and the actual average
temperature may differ significantly. There are several reasons for this. First, it is
difficult to achieve the degree of mixing necessary to allow for the complete transfer of
heat from the combustion to the combustion products. The combustion process
would have to be nearly instantaneous which, in reality, it is not. The combustion of
natural gas and oil and some coal combustion systems approach this ideal mixing
condition. Second, some heat from the combustion process is lost to the
surroundings. The term adiabatic is defined as no heat gain or loss from a process.
In actual combustion conditions, some heat is lost as radiation and some as
convection heat losses. This will act to decrease the flame temperature. Finally, the
reaction to form CO2 and H2O are limited by high temperatures. Above temperatures
of 3000 °F, some of the CO2 and H2O disassociate to form CO, H2, and O2 and absorb
the heat of reaction (4345 Btu/lb of CO formed and 61,100 Btu/lb of H2 formed,
respectively). This heat is not lost but is recovered as the flame temperature
decreases due to heat transfer and the CO and H2 recombine with O2. The delay in
the completion of the reaction, however, acts to lower the flame temperature.
28
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The maximum adiabatic flame temperature is reached when there is no excess
air in combustion. In addition, the adiabatic flame temperature can be increased by
increasing the temperature of the fuel and/or the combustion air. Finally, the adiabatic
flame temperature can be increased by decreasing the moisture content of the
combustion gas stream. The fuel moisture can only be lowered by changing fuels so
that there is a lower percentage of H2 in the fuel or by the reduction of fuel moisture.
Generally the fuel moisture may be altered but the H2 cannot be altered significantly.
The adiabatic flame temperature is calculated in two steps. The first step is to
calculate the adiabatic enthalpy of the combustion gas. This is calculated by
determining the weights of the combustion products and enthalpy associated with the
combustion process, fuel, and combustion air (at a reference temperature of 80 °F):
f heat of } (sensible heat] {sensible heat]
h B {combustion) + ( in fuel )*\ in air } (18)
8 . weight of products of combustion
where hg is the adiabatic enthalpy in Btu/lb of combustion gas. The second step is to
determine the weight percentage of moisture in the combustion gas from the
combustion calculations and calculate the adiabatic flame temperature. This may be
most easily accomplished by graphical methods (Rgure 2-3) although it can be
calculated using the heat capacities of the combustion gases involved.
2.6 Thermal Efficiency of Boilers
The combustion of fuel in steam generation equipment relies on the efficient
transfer of heat from one medium (combustion gases) to another (water and steam) to
provide useful energy for process operation. Unfortunately, it is not possible to
recover all of the heat from the combustion process and some quantity of heat loss
occurs from all processes. This can be translated into thermal transfer efficiency in
steam generators. The measurement of combustion gas temperature and
29
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/
DO 301
sTempen
/
y
>
/
7 ~~*
/
/
/
/
/
/
/
M
rtu
/
•
;
/
i
/
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/
4
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y
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31
re.F
/
f
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/
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f
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00. 321
/
/
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y
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» 3301
/
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/
3000 3100 3200 3300 3400 3SOO 3600
3400 3500 3600 3700 3800 3900 4000
Flu* QM lemperatm. F
Figure 2-3. Graphical method for determination of adiabatic flame temperature. (Continued)
31
-------
composition when combined with a fuel ultimate analysis allows for the estimation of
the efficiency of thermal transfer for steam generation equipment. These calculations
rely on the same fundamental principles used to calculate combustion air requirements
and the quantity of combustion products produced.
Thermal efficiency of boilers can be determined by two methods. The first
method is the Input/Output method in which all energy streams into the boiler (fuel,
feed water, etc.) and out of the boiler (steam, blowdown, etc.) are measured. The
ratio of the output to the input defines the thermal transfer efficiency. This
methodology requires accurate measurement of all flow rates and conditions of each
stream entering or leaving the boiler. As a practical matter, it is difficult to obtain
closure on the material balances and heat balances around the boiler even when the
equipment is new and within calibration specifications. The second method of
determining thermal efficiency from steam generators is the Heat Loss method. The
heat loss method does not require the measurement of all flow rates through the
boiler. Instead, the heat loss method relies on several simple measurements to
determine the energy losses from the boiler and relates them to the percentage of the
original heat content of the fuel. The heat loss method is a much easier method to
use for determination of the thermal efficiency of any boiler and is the method
generally used in the evaluation of boiler performance.
The heat loss method divides the heat losses into several distinct categories.
These are: the heat loss associated with the dry combustion gas leaving the boiler, the
sensible heat associated with the moisture from H2 combustion and fuel moisture, the
latent heat associated with the moisture, C loss from unbumed fuel, C loss due to
formation of CO instead of CO2, and radiation losses from the boiler. The latent heat
associated with moisture is the heat that is not recoverable because of the phase
change between the liquid phase and gas phase of water. A substantial quantity of
energy is associated with this phase change (970 Btu/lb of water). The sensible heat
is "recoverable" above the phase change if enough heat exchange area is provided for
heat transfer. The dry gas losses are all sensible heat losses. The C loss due to C in
32
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the ash requires an estimate or measurement of the percent combustibles contained in
the ash (usually expressed as a loss on ignition). It is generally assumed that the loss
on ignition (LOI) is equivalent to pure C and not a mixture of heavy hydrocarbons to
determine the Btu/lb ash value. The C loss associated with CO formation accounts
for the loss of energy due to incomplete reaction of C with O2.
The calculations for the heat loss method are summarized in the American
Society of Mechanical Engineers (ASME) Power Test Codes. Simplified equations for
calculating the heat loss are presented here. The first steps are calculated
sequentially to determine the actual dry gas production rate. These equations differ
slightly from the stoichiometric combustion equation in that they account for C loss as
both combustible loss in the ash and as CO in the combustion gas. Once the quantity
of dry gas is determined the heat loss for each category is calculated. All values for
the fuel are based on an as-fired basis.
The first step is the determination of the dry refuse rate per Ib as-fired fuel. This
is calculated by the equation:
Dry refuse (Ibllb )= % ash in fuel (19)
. 100 - % combustible in ash
The second step is the determination of the quantity of C burned per Ib as-fired fuel.
This is calculated by the equation:
burned (Ibflb \ - % caft>on ** **&*' ( dry /p/i/$e///> fwl * gft//fl> mfus* }
l ' ' 100 I 14500 J
If the combustible content of boiler ash and fly ash are substantially different,
procedures are outlined in the American Boiler Manufacturers Association (ASME)
Power Test Codes to provide a weighted average combustible content. The third step
is the determination of the quantity of dry gas produced per Ib of as-fired fuel. This
33
-------
step accounts for the C losses due to the combustibles in the ash and CO in the gas
stream. The values for CO, CO2, and O2 are the percent, by volume, of each of the
components in the combustion gas stream. The value for N2 is obtained by difference
from the composition of the combustion products. The value for S in the equation is
the Ib/lb as-fired fuel, not percentage. The equation for calculating dry gas volume is:
Dry gas ( tollb) - x (Ib cvbon bumedllb fuel+3/BS) (21)
+ CO)
The heat loss from each category can be determined once these values for dry gas
are calculated.
2.6.7 Dry Gas Loss
The dry gas loss accounts for the loss due to sensible heat being carried out in
dry combustion gases. The combustion gas temperature and gas composition are
both measured after the last heat exchange surfaces in the boiler. In general, the dry
gas losses account for the largest proportion of the energy losses from the boiler and
become more substantial as the excess air and combustion gas temperature
increases. Unfortunately, an increase in excess air usually results in an increase in the
exit gas temperature because heat transfer between the combustion gases and the
steam is reduced. Heat loss from too much excess air results in not only more gas
mass to carry the sensible heat out of the boiler but also carries it at a higher
temperature as well. The equation for dry gas loss is:
Dry gas loss ( Btujlb fuel ) = dry gas x 0.24 ( f. - f, ) (22)
34
-------
where: 0.24 = specific heat of the combustion gas, Btu/lb-°F
tg = temperature of gas leaving unit, °F
ta = temperature of air entering unit, °F
2.6.2 Fuel Moisture Loss
The loss due to fuel moisture accounts for the loss due to sensible and latent
heat remaining with the moisture in the combustion gas, which is not recovered to
generate steam. For most fossil fuels, the losses associated with fuel moisture are
relatively small compared with the losses due to H2 burning and dry gas losses. The
exception to this is high moisture fuels such as wet woods and barks that may contain
fifty to seventy percent, by weight, water in the as-fired condition. In these cases, the
energy losses associated with fuel moisture can be substantial. The presence of water
requires the energy of combustion to be used to evaporate the water from the fuel
prior to burning and to elevate this gas volume up to flame temperature. The
presence of water also lowers the adiabatic flame temperature and in actual
combustion equipment may result in a low temperature flame that promotes poor
combustion. In general, each pound of water brought in with the fuel results in a loss
of one pound of steam generation capacity. Although it is desirable to provide a fuel
that has a low moisture content there may be economic considerations in the cost of
fuels at different moisture contents that need to be considered.
The fuel moisture loss is calculated by the equation:
Fuel moisture toss - -- x ( enthalpy of vapor 6 tg & 1 psla - enthalpy of liquid 9 tt ) (23)
where: H2O = % moisture in the fuel.
The values for the enthalpy (heat content) of water vapor and liquid water may
be obtained from any standard engineering reference under "Steam Tables." There
35
-------
are equations that derive the enthalpy for steam at many observable conditions but
they are better suited for calculations by a computer and are beyond the scope of this
document. The values of ta and ^ are the same as the values used in the dry gas
loss calculation.
2.6.3 H2 Combustion Loss
The heat loss due to H2 combustion is generally the second greatest loss from
the boiler, except for high moisture fuels. Although fuel drying may be an option for
some solid fuels to decrease the energy loss associated with fuel moisture, there is
little that can be done to decrease the loss from H2 combustion, except to change
fuel. For example, the combustion of natural gas can be carried out at very low
excess air levels because natural gas is easily burned. It is not uncommon to find
well-adjusted burners operating with excess air levels of 10 to 15 percent excess air.
The loss due to H2, however, is substantial because H2 accounts for approximately 25
percent of the fuel weight of natural gas and produces a large quantity of combustion
gas moisture. There is little that can be done to recover this lost heat in conventional
boiler designs except to change fuel. The heat loss due to H2 is calculated using the
equation:
Hydrogen g u
combustion = —£ x ( enthalpy of vapor 9 L & 1 psta - enthalpy of liquid 9 t. ) (24)
loss 10°
2.6.4 CO LOSS
The CO loss is included here for completeness. The quantity of energy lost
due to CO is usually quite small and for levels less than 100 ppm (volume) may be
ignored as other losses are substantially greater than the CO losses. The equation for
the CO loss is:
36
-------
CO loss = °° x 10160 x carbon burned (Ibflb) (25)
C/C?
2.6.5 Unbumed Combustible Loss
The unbumed combustible loss represents the unbumed C in the ash. The
range of C loss is quite varied depending on the fuel type and the combustion process
used. The C losses from oil fired boilers are usually ignored. Grate firing of coal or
wood may result in relatively low C losses if fuel and air characteristics are properly
maintained. Carbon losses as low as 10 percent can be achieved. Lower C losses
are possible when firing pulverized coal. The C content can reach as high as 60
percent when improper combustion techniques are applied. In many cases, this will
be evident from elevated CO levels but such elevated levels are not guaranteed to be
observed.
the C loss may be calculated by the equation:
Carbon loss = dry refuse x Btu/lb refuse (26)
The dry refuse should represent a weighted average between bottom ash and fly ash
if the ash losses are substantially different
2.6.6 Total Losses
The losses from each of the above losses are in units of Btu/lb as-fired fuel.
The sum of these losses represent the total calculated losses by the heat loss method.
To determine the percentage loss, the total loss is divided by the heat content of the
fuel and multiplied by 100 to obtain percent loss. The equation is:
Z Btu loss x 10o = % fcss (27)
Btu/lb as-fired fuel
37
-------
2.6.7 Other Losses
There are other losses that are not measured but may be included in the overall
boiler efficiency calculation. These include radiation losses, sensible heat in the ash,
and heat pick-up in cooling water. The radiation loss can be determined as a
percentage of the total heat input using an ABMA standard radiation loss chart (Rgure
2-4). The other losses are typically assigned a total value of between 1 and 1.5
percent
2.6.8 Uses of Thermal Efficiency
The thermal efficiency value allows for an instantaneous assessment of boiler
performance using easily measured parameters. The evaluation of other equipment,
such as air pollution control equipment, requires the knowledge of the approximate
gas flow through the equipment. This may be obtained by determining the net heat
output from the steam flow and steam conditions and the feed water flow and feed
water conditions. The net enthalpy increase, as determined from the steam tables,
provides a relative indication of the heat output of the boiler. The heat input can be
estimated from the knowledge of the boiler efficiency and calculated by the equation:
Heat input = ^eat output (28)
boiler efficiency
Once the heat input is determined, the gas volume produced by the combustion
process may be calculated using the F-factor method, which requires knowledge of
the heat input rate. This procedure is used in Section 5 under the discussion of
inspection procedures.
38
-------
No. of Cooled Furnace Walls
zoo420
10.0 •
8.0 >'
"5
9 a , E
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S -6 '
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2.
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r
' Use factor below fi
I air-cooled walls
|
1
r
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te
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v— N
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^
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\
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ie radiation toss values obtained from this curve are
r a differential of 50 F between surface and ambient
mperatures and for an air velocity of 100 feet per
\.
\
N
\
^^
»- •«- >
«^^^
^•^
d It Ions should be made In accordance with Fig. 3 page 170
In the 1957 Manual of ASTM Standards on Refractory
Materials.
i i i i i i i iii ii
s
\
V
"\
\
^^"N,
V
^
^
\
^
\^
^^*N.
A furnace wall must have at least one third its
projected surface covered by water cooled surface
before reduction in radiation loss Is permitted.
Air thru cooled walls must be used for combustion -
if reduction in radiation loss Is to be made. ~
Example: Unit guaranteed for maximum continuous ~
output of 400 million Btu/hr with three ~
water cooled walls. -
Loss et 400 = 0.33%
Loss at 200 " 0.68% ~
xl \l .
\
\
lv
\
*-•*.
s
^N,
s
ON.
N
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k Y^
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X >
X
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. \
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on Loss at
%^
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\
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Max.
X
X
>
k
^ X
\ XN
VS. 9 3 568 hO 2030406080 200 400600 1000 2000 6000 10.000 20.000
Y\ 79 50 100 300 800 4000
) .94 1.0 Water Wall Factor Actual Output Million Btu/hr
3 .97 1.0 Alr-Cooled Wall Factor
Figure 2-4. ABMA radiation chart.3
-------
2.7 Summary
The fundamentals of combustion apply to all combustion sources. The
fundamental concepts of material and energy balances are used to further define and
refine combustion air requirements, products of combustion, F-factor methods and
thermal efficiency calculations for boilers. The reaction of fuel and air is .a chemical
process that requires mechanical activities to perform the three-Ts" of combustion. It
is usually a related mechanical action that is at fault when combustion proceeds
poorly. The results of calculations outlined in this section do not ensure that proper
combustion conditions will exist in the combustion zone for complete and efficient
combustion. The combustion calculations, however, provide a starting point to screen
out gross operating problems. These methodologies will be outlined in Section 5 and
some of the combustion problems will be highlighted in Section 8 of this manual.
40
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2.8 References
1. Power from Coal: Part II, Coal Combustion. Power, March 1974.
2. Beachler, D.S. U.S. Environmental Protection Agency, Air Pollution Training
Institute (AFTI). APT) Course SI:428A, Introduction to Boiler Operation, Self
Instructional Guidebook, December 1984.
3. Babcock and Wilcox. Steam/Its Generation and Use. New York, 1978.
41
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42
-------
SECTION 3
COMBUSTION EQUIPMENT
This section discusses various types of fuels and fuel combustion equipment.
The fuel characteristics often define the design parameters associated with combustion
equipment. Where possible, design values for such items as heat release rates and
typical fuel characteristics required for proper combustion are provided.
3.1 Oil and Gas Combustion
Petroleum (crude oil) is the most important source of hydrocarbons. It provides
many combinations of hydrogen and carbon in arrangements and proportions ranging
from a gas [methane (CHJ] through a variety of liquids to heavy waxes and asphalts
that are solids at room temperature.1 Refining of crude oil yields a number of
products having many different applications. Fuels include gasoline, distillate fuel,
residual fuel, jet fuels, still gas, liquified gases, kerosene, and petroleum coke. The
types of fuels used for industrial and utility boilers are primarily No. 2 distillate and No.
6 residual oils and natural gas.
Because natural gas almost always accompanies petroleum, it may well be
considered petroleum type fuel. Much of the natural gas produced is suitable for use
without further preparation. Natural gas containing excessive amounts of hydrogen
sulfide is commonly known as "sour" gas. In most cases, the sulfur is generally
removed before distribution. Natural gas is usually sold with a standard Btu/ft3
content (typically at or near 1000 Btu/scf). Natural gas is usually sold by the therm
rather than by the ft3. The therm is a standard unit of measure representing 100,000
Btu of energy.
Distillate oils and natural gas are considered somewhat interchangeable. Most
industrial boilers that are designed for natural gas can usually bum distillate oil. Some
43
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furnaces, including burners, can accommodate fuel switching by simply turning valves.
Different burners may be required for burning residual oil, but it too may usually be
accommodated by natural gas-fired systems.
The choice of fuel for a particular plant is based primarily on fuel cost. When
fuel costs change rapidly, the capability to bum multiple fuels is important. In addition,
curtailments in natural gas supplies from regional distributors require the ability to
change rapidly from one fuel to another.
3.1.1 Gas Burning Equipment
Natural gas burning, equipment may be used in a wide range of industrial
applications. Natural gas advantages are its relatively low cost, it is easy to bum and
generally easy to control for efficient combustion. Boilers burning natural gas can be
much more compact than boilers burning solid fuel with the same steam output,
resulting in an initial capital cost savings.
Natural Gas Burners
Gas burners are considerably simpler than those used for oil or solid fuels
because natural gas can be mixed easily with air. Natural gas is usually mixed with a
fraction of the air necessary for complete combustion before being fed to the
combustion zone. The air mixed with the gas at this stage is called primary air. The
gas mixture enters the burner either through nozzles or through perforated rings.
Upon entering the burner, the gas mixture is ignited and mixes with secondary air,
which makes up the remainder of the air necessary for complete combustion.
The variable-mix multispud gas element (Rgure 3-1) was developed for use with
circular type burners. It obtains good ignition stability under most conditions, such as
the two-stage combustion technique. With the proper selection of control equipment,
a multifuel-fired burner with a variable-mix multispud type gas element is capable of
changing from one fuel to another without a drop in load or boiler pressure.
Simultaneous firing of natural gas and oil in the same burner is acceptable on burners
equipped with variable-mix multispud type gas elements.1
44
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Scanner and Observation Ports Air Register
Main Oil
Burner
Windbox
Water
/Cooled
L^ Throat
Gas
Spuds
Stabilizer
Figure 3-1. Circular register burner with water-cooled throat for oil and gas-firing.1
45
-------
In many respects natural gas is an ideal fuel because it requires no preparation
for rapid and intimate mixing with the combustion air flowing through the burner throat.
This characteristic of easy ignition under most operating conditions has, in some
cases, led to operator carelessness and damaging explosions. To provide safe
operation, gas burner ignition should remain dose to the burner wall, and it should
remain close to the wall throughout the full range of allowable gas pressures, not only
with normal air flows, but also with much more air flow through the burner than is
theoretically required. Ideally, it should be possible at the minimum load to pass full-
load air flow through the burner, and at full load as much as 25 percent in excess of
theoretical air without loss of ignition. With this latitude in air flow it is not likely that
ignition can be lost, even momentarily, during some upset in air flow due to improper
operation or error.
Burner Pulsation
One of the problems associated with gas burners and, to a much less degree
with oil burners, is that of burner pulsation. It appears to result from certain
combinations of combustion chamber size and configuration coupled with some
characteristic of the burners, perhaps too perfect mixing of fuel and air at the burner.
When one or more burners on a large unit start to pulsate, it may become alarmingly
violent, at times shaking the whole boiler. Making an adjustment of only one burner
may start or stop pulsation. At times only minor burner adjustments eliminate the
pulsation. In other instances, it is necessary to alter the burner configuration. This
may involve modifying the gas ports, impinging gas streams on one another, or using
some other device that effectively alters the mixing of the gas with the air. Burner and
boiler manufacturers incorporate the latest information available into the designs of
burners and furnaces to avoid pulsation.1
46
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3.1.2 Fuel Oil Characteristics
Fuel oil is produced by refining crude oils using two basic techniques: thermal
and catalytic cracking. The refining process breaks down heavy hydrocarbons into
lighter fractions that can be blended to provide the desired properties. Note that any
oil is a blend of many different molecules, each with its own characteristics. For
example, No. 2 oil is not a uniform product in terms of chemical composition; it has
been blended to meet certain criteria concerned with physical properties and heat
content. The important physical properties of fuel oil for combustion are viscosity,
flash point, pour point, carbon residue, sulfur content, bottom settlings, and gravity.
Viscosity
Viscosity is a measure of the resistance of an oil in flowing through a line. It is
measured by the amount of time it takes for a measured quantity of oil to flow through
the orifice of a viscosity measurement instrument. The units of viscosity are either in
Saybolt Seconds Universal (SSU) or Saybolt Seconds Furol (SSF), depending on the
type of instrument that is used. Most chemical and mechanical handbooks have a
table relating these two measures.
Fuel oils are blended to have various viscosities at 100°F. For example, a
supplier may specify a fuel oil as No. 5-800, which is Number 5 oil with an SSU
reading of 800. Table 3-1 shows the range of viscosity for various oils.
TABLE 3-1. VISCOSITY OF FUEL OILS2
Grade
No
No
No
No
of oil
. 2
. 4
. 5
. 6
Viscosity,
Minimum
34
45
150
900
SSU at 100' F
Maximum
40
125
800
8500
47
-------
The viscosity of an oil is decreased by heating. Most No. 5 and 6 oils must be
heated to atomize properly for combustion. Burners are designed to atomize oil with a
viscosity ranging between 100 and 200 SSU. Therefore, it is necessary to preheat the
oil to a temperature that produces this viscosity before atomization. For example, a
No. 5 oil with a viscosity of 800 would require heating to 160°F to achieve a viscosity
of 170 SSU.
Flash Point
The flash point is a measure of the lowest temperature at which a flash flame
can be produced. The flash is caused by combustion of lightweight hydrocarbons.
Thus, an oil with a low flash point will bum more easily than one with a higher flash
point. The flash point is measured with either an open or closed cup. The closed-cup
method gives the lowest reading.
From a safety standpoint, it is necessary to maintain the flash point above 100°
to 150°F. Oils should never be preheated to a temperature greater than the flash point
because preignition of the burner results. A low flash point can also cause flashback-
a condition in which the flame ignites but is unable to maintain combustion of the
heavier hydrocarbons. In contrast, a high flash point makes it difficult to start a flame
in cold furnaces.
Pour Point
The pour point is the lowest temperature at which the oil can be poured. This
property is important because it indicates the lowest temperature at which oil can be
pumped. Table 3-2 gives the approximate ranges for pour points of fuel oils.
48
-------
TABLE 3-2. POUR POINTS FOR VARIOUS GRADES OF FUEL OIL2
Grade Pour point, *F
No. 2 Below zero to 15
No. 4 Below zero to 25
No. 5 10 to 75
No. 6 20 to 75
Carbon Residue
After fuel oil has been completely vaporized, a fraction of carbon remains (the
carbon residue). This residue is undesirable because it encourages sludge formation
in the burner. The amount of carbon residue in oils varies widely, generally increasing
with the heavier oils. The amount of residue that can be handled depends on burner
design. It is important to note that incomplete combustion can cause formation of a
substance similar to carbon residue. The possibility of incomplete combustion should
be checked thoroughly before blaming a carbon problem on carbon residue.
Sulfur Content
Sulfur is the most undesirable impurity in oils because it produces harmful
emissions and highly acidic compounds that attack steel boiler parts. The amount of
sulfur in fuel oil can be determined with a liquid gas chromatograph. The amount
present depends primarily on the sulfur content of the crude oil and varies widely,
even for the same grade of oil. Any oil with a sulfur content over 1 percent is
generally considered a high-sulfur oil. The use of high sulfur may be limited by
regulatory limits on SO2 generation.
Bottom Settlings and Water (BS&W)
This term refers to the amount of residue and water contained in the oil and can
range up to 2 percent for No. 6 oil. Any greater amount is usually due to external
49
-------
sources. This material can plug burners, burner tips, and screens, and cause erratic
combustion such as sparking and flashback. The BS&W are not the same as sludge
because sludge is an organic material resulting from oxidation of hydrocarbons,
whereas BS&W are water and inorganic materials such as dirt and rust. The
combination of sludge and BS&W will eventually cause trouble unless preventive
maintenance addresses these factors.
Gravity
Specific gravity is usually measured in terms of the American Petroleum Institute
(API) scale. It indicates the density of oil compared to water at standard conditions
(60°F). In this scale, an oil with an increasing density has a smaller API value. It is
important to realize that, due to refining, similar gravities can be obtained that have
radically different chemical properties. Table 3-3 provides a breakdown of typical
ranges of API gravity for various oils.
The major significance of gravity is that the burner apparatus is designed to use
oils within a definite gravity range. Operators must ensure that the fuel oil gravity is
within the design range for their boiler.2
TABLE 3-3. API GRAVITY OF FUEL OILS2
Type API gravity range
No. 2 29* to 39*
No. 4 24* to 28*
No. 5 16* to 22'
No. 6 6' to 15 •
50
-------
3.1.3 Oil Burning Equipment
There are several different types of fuel oil burners used. The operation and
characteristics of these burners are described below.
Simple Pressure Atomizing Burner
These burners are often called "gun type" or mechanical atomizing burners and
are illustrated in Rgure 3-2. They produce a fine spray of fuel oil operating under a
pressure between 75 and 200 psi. The oil is discharged through a small hole and
often is given a swirling motion by a slotted disk. This type of burner can be operated
only as an on/off device. By providing multiple nozzles in the same configuration,
however, high-low-off firing is possible. These burners are usually found on equipment
of less than 5 million Btu/h rating.
Plug
Oil Flow
Atomizing Slots
Figure 3-2. Typical gun burner high pressure nozzle.3
51
-------
Return-Flow Atomizing Burners
These nozzles work on the same principle as the gun type, but at a higher
pressure (above 300 psi). They permit modulated firing by returning part of the flow
as shown in Figure 3-3, or by using a control rod to change the nozzle area. A partial
turndown ratio (maximum firing rate/minimum firing rate) of 4:1 can be obtained.
Rotary-Cup Burning
Oil is fed through a stationary tube and is discharged into a cup, rotating at
about 3500 rpm (Rgure 3-4). Centrifugal force flings the oil from the edge of the cup.
Primary air is supplied by a blower fixed to the shaft, to which the cup is attached.
These burners can operate with a turndown ratio of 3:1. They can operate well, but
require precision machining. Therefore, rotary-cup burners cost more than other
systems and currently are declining in popularity. Some states outlaw rotary cup
burners because of their high paniculate output
Steam-Atomizing Burners
This burner system intersects jets of steam and oil either just inside or outside
the burner through concentric annular channels. Rgure 3-5 shows a typical system.
Pressures used are 75 to 150 psi for oil and 15 to 150 psi for steam. A high turndown
ratio of 7:1 is possible. This burner, however, has some drawbacks. Steam must be
available at the correct pressure. A falling steam pressure results in poor fuel
atomization which, in turn, decreases the steam pressure further. Another drawback
to this system, compared with the air atomization type explained below, is that it
typically is 1 percent less efficient than air-atomized firing with all factors considered in
both systems.
Air-Atomizing Burner
This system operates on the same principle as steam atomization, with air
replacing steam. The air pressure used ranges from below 30 psi to more than 100
psi, depending on the design. Turndown ratios of 7:1 are also possible at air
pressures of 40 psi or greater.
52
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Barrel
Coupling
EEEE3-
ip Cop
SECTION A-A
Ferrule •
-Gasket
Figure 3-3. Typical return-flow pressure atomizer.3
(Courtesy of the Peabody Engineering Corporation)
OIL
DISTRIBUTOR
HEAD
PRIMARY AIR
COMPRESSOR
BLADES
-ROTARY
ATOMIZING
CUP
SECONDARY
AIR
PRIMARY
AIR
Figure 3-4. Typical rotary-cup burner.3
(Courtesy of the Space Conditioning Corporation)
53
-------
y////////////////////
Oil
\\\\\\\\\\\\\\\\v
Steam
.
7///////////////7
Figure 3-5. Steam atomizer tip.3
(Courtesy of Babcock & Wlleox Company)
54
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Low Excess Air Burner
A new type of burner designed specifically to bum with low-excess air has been
introduced into the United States in the past few years. These burners can burn gas
or oil with excess air levels less than 2 percent. Typically, they cost about 25 percent
. .w^
more than conventional burners and are generally found in sizes above 30,000,000
Btu/h.
Figure 3-6 shows a COEN low excess air burner. These high-efficiency burners
provide a means for thoroughly mixing oil or gaseous fuels with combustion air to
obtain maximum combustion efficiency. They are available in a wide variety of types
and sizes, but all use the principle of controlling the swirl of combustion air flow to
maximize mixing of the fuel with the combustion air. This allows for a stable, wide
turndown over a large firing range. Other advantages of these burners are their ability
to reduce NOX emissions through flue gas recirculation or fuel/air staging techniques
and their ability to bum more than one type of fuel (Figure 3-7).
Turndown Ratio
A measure of the practical range over which a burner will operate is called the
"turndown ratio.' It is defined as the maximum practical firing rate divided by the
minimum practical firing rate. This ratio is very important because boilers are usually
oversized and operate at low loads. Table 3-4 shows the turndown ratio for various
types of burners. 3
55
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Co en Gas 'Electric
Pilot •
Optional Intcrzonc Type
Gas Burner for Low
BTU low Pressure CM
Core Air Zone
Lower Assembly
Heavy Duty Gear Drive
Aimulus Air Zone
Lower AssemMy
Ring Type Gas Burner
Coen Preformed Refractory
Throat Tiles ore Shaped Co Fit the
Specific Furnace Geometry
Figure 3-6. Low excess air burner.3
(Courtesy of COEN Company, Inc.)
56
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VENTURI
DISCHARGE
SECTION
AIR STABILIZER
GAS NOZZLE
OIL GUN TIP
GAS SPUDS
Figure 3-7. End view of low excess air burner.3
TABLE 3-4. BOILER TURNDOWN RATIOS FOR VARIOUS TYPES OF BURNERS
Burner type
Turndown ratio
Pressure atomizing
Fixed
High-low-off
Modulating
Rotary cup
Fluid atomizing
Low excess air
1:1
1:1 or 4:1 (typical)
4:1
3:1
7:1
8:1
57
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3.2 Coal Combustion
The type of equipment used for the combustion of coal is highly dependent on
the classification and qualities of coal available to the plant. Boiler design and
equipment specifications are directly related to the type of coal to be burned.
Significant variations in the types of coal received at the plant represent the most
common reason for equipment malfunctions and a common underlying cause of air
emission violations. Thus, the first step in understanding coal combustion equipment
is to understand the coal itself.
3.2.1 Properties of Coal
Although coals can be grouped or classified in many different ways according
to specific chemical and physical properties, the classification system most frequently
used is the one that was developed by the American Society for Testing & Materials
(ASTM). Table 3-5 illustrates the ASTM rankings for various coal categories. Volatile
matter, fixed carbon, bed moisture, and oxygen are all indicative of rank, but no one
item completely defines it. In ASTM classification, the basic criteria are the fixed
carbon and the calorific values calculated on a mineral-matter-free basis.
Various tests and methods of analysis express coal qualities. An ultimate
analysis shows the exact chemical composition of a fuel; this type of analysis provides
data needed for combustion calculations. The principal characteristics of coal are
derived from a proximate analysis. The proximate analysis provides a good picture of
a coal's behavior in a furnace. It is a relatively simple procedure, which involves
determining the percentage of 1) moisture, 2) ash, and 3) volatile matter, in
accordance with prescribed ASTM test methods, and calculating the percentage of
fixed carbon. Coal analyses can be made on several bases. The coal is usually
analyzed as-received, air-dried or moisture-free. As the name implies, the as-received
analysis reports the condition of coal as delivered to the laboratory. This comes
closest to the conditions as-shipped or as-fired, the values desired in practical work. It
58
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TABLE 3-5. ASTM SPECIFICATIONS FOR CLASSIFYING COALS ACCORDING TO RANK
Class
I Anthradtlc
II Bituminous
III Subbl luminous
IV Llgnltlc
Group
s
1 Meta-anthraclte
2 Anthracite
3 Semi -anthracite6
1 Low volatile
bituminous coal
2 Medium volatile
bituminous coal
3 High volatile A
bituminous coal
4 High volatile B
bituminous coal
5 High volatile C
bituminous coal
1 Subbl luminous A
coal
2 Subbl luminous B
coal
3 Subbl luminous C
coal
1 Lignite A
2 Lignite B
Fixed carbon
limits, X (Dry,
mlneral-matler-
. free basis)
Equal or
greater
than
98
92
86
78
69
Less
than
982
928
86
78
69
Volatile matter
limits, % (Dry,
mineral -mailer- free
basis)
Grealer
lhan
2
8
14
14
22
31
Equal or
less
lhan
22
31
Calorific value
limits, Btu/lb
(Moist, mineral-
matter free basis)
Equal or
greater
than
14,000d
13,000d
11,500
10,500
10,500
9,500
8,300
6,300
Less
than
•
14,000
13,000
11,500
11,500
10,500
9,500
8,300
6,300
Agglomerating
character
Nonagglom-
erallng
Commonly
agglomerating"
Agglomerating
Nonagglom-
erallng
Nonagglom-
erallng
•The ASTM classification Index set forth In "Specification for classification of coals by rank" [ASTM D 388-66 (1972)]
does not Include a few coals, principally nonbanded varieties, which have usual physical and chemical properties and
which come within the limits of fixed carbon or calorific value .of the high-volatile bituminous and subbltumlnous
ranks. All of these coals either contain less than 48 percent dry, mineral-mailer-free fixed carbon or have more lhan
15,500 Btu/lb on a moist, mineral-matter-free basis.
Tlolst refers to coal containing Its natural Inherent moisture but not Including visible water on the surface of the
coal.
'If agglomerating, classify In the low volatile group of the bituminous class.
"foals having 69 percent or more fixed carbon on the dry, mineral-mailer-free basis shall be classified according lo
fixed carbon, regardless of calorific value.
*It 1s recognized that there may be nonagglomeratlng varieties In these groups of the bituminous class, and there are
notable exceptions In the high volatile C bituminous group.
-------
is also customary to determine separately the total amount of sulfur contained in the
coal, the ash-fusibility (fusion) temperature, and the fuel's heating value. These
properties are discussed briefly below.
Moisture
All coal contains some natural moisture, from 1 to 5 percent in most eastern
coals, and up to 45 percent in some lignites. This moisture lies in the pores and forms
a true part of the coal, being retained when the coal is air dried. Surface moisture, on
the other hand, depends on conditions in the mine, and the weather during transit
Moisture generally is determined quantitatively in two steps: air drying and
oven drying. The air-dried component of the total moisture value should be reported
separately, because this information is required in the design and selection of coal-
handling and coal preparation equipment It is the surface moisture that must be
evaporated from anthracite and bituminous coal before pulverization to maintain high
grinding efficiencies.
Ash
Ash is the incombustible mineral matter left behind when coal bums completely.
The amount and character of ash are directly related to fuel-bed and furnace problems
such as clinkering and slagging and also have an effect on air pollution equipment for
removal of particulate matter.
Volatile matter
Volatile matter is that portion of the coal that is driven off in gaseous form when
the fuel is subjected to a standardized temperature test It consists of combustible
gases, such as CH4 and other hydrocarbons, hydrogen and CO, and noncombustible
gases. Because the quality of volatile matter indicates the amount of gaseous fuel
present, it affects firing mechanics. It also influences furnace volume and the
arrangement of heating surfaces.
60
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Fixed carbon
Fixed carbon is the combustible residue left after the volatile matter distills off. It
consists mainly of carbon, but contains some H2, O2, S, and N2 not driven off with the
gases. The form and hardness of this residue are an indication of the caking
properties of a fuel and are, therefore, a guide in the selection of combustion
equipment.
Sutfur
Sulfur is present in raw coal in amounts ranging from trace quantities to as
much as 8 percent or more. When coal is burned, sulfur oxides are emitted from the
stack unless some type of sulfur-removal system is employed. Regulatory limitations
may restrict the sulfur content of the fuel.
Three forms of sulfur are found in coal: 1) pyritic sulfur, which is sulfur
combined with iron in. the form of mineral pyrite or marcasite, 2) organic sulfur, or
sulfur combined with the coal substance, and 3) sulfate sulfur, in the form of calcium
or iron sulfate. Of these, the finely divided pyrites and organic sulfur are considered
nonremovable impurities on the basis of current technology and economics. Sulfate
sulfur, generally not over 0.1 percent by weight is as-mined coal, is not too important.
In some pulverizer designs pyritic sulfur may be rejected during pulverizing, lowering
the as-fired sulfur content
Ash-fusibility temperature
Ash-fusibility temperature is measured by heating cones of ash in a furnace
generally arranged to produce a reducing atmosphere. The temperature at which the
cone fuses down into a round lump is called the softening temperature. Other
temperatures sometimes observed include that at which 1) the cone tip starts to
deform (the initial-deformation temperature), and 2) the melted cone spreads out into a
flat layer (the fluid temperature). The softening temperature (or sometimes the spread
61
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between the initial-deformation and softening, or the softening and fluid temperatures)
serves as the best single indicator of clinkering and slagging tendencies under given
fuel-bed and furnace conditions.
Heating value
Heating value is used in judging fuel values. When a coal sample is burned in a
bomb-type calorimeter filled with oxygen under pressure, the fuel's higher heating
value is measured. It assumes that the latent heat of water vapor contained in the
combustion products is absorbed in the boiler. Because water vapor in the flue gas is
not cooled below its dewpoint during normal boiler operation, this latent heat is not
available for making steam. Hence, it sometimes is subtracted from the higher-heating
value to give the net or lower-heating value.
Caking, Coking
Confusion often exists with respect to the proper use of these two terms. When
coal is heated in the absence of air or in an atmosphere very deficient in oxygen,
volatile matter is driven off, leaving behind a residue of carbon. This is coke. It may
take the form of small powdery particles, or it may fuse into lumps of varying size and
strength. Swelling may occur. In commercial coke-making, the term "coke" refers to
lumps of marketable size and quality; coking coals are used to produce them in a
coke oven.
Coke formation, in one shape or another, represents an intermediate
combustion stage in any fuel bed. In a boiler furnace, for example, some coals
become plastic and form lumps or masses of coke. (This type of coke usually is not
of metallurgical quality, and often is referred to as semicoke.) These are called caking
or agglomerating coals. Those coals that show little or no fusing action are called
free-burning.
Although both caking and free-burning coals can be burned without difficulty in
boilers fired with pulverized coal, this is not the case with all types of stoker firing. In
62
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general, caking coals are burned on underfeed stokers, which have moving rams or
other means for breaking the masses of semicoke formed in the fuel bed. Free-
burning coals usually are burned on traveling-grate or spreader stokers because there
is no agitation of the fuel bed.
Grindability
Grindability is a term used to measure the ease of pulverizing a coal, in
comparison with coals chosen as standards. In the Hardgrove test, the industry
standard, a prepared sample of coal receives a definite amount of grinding energy in a
laboratory pulverizer, results are measured by weighing the amount passing through a
200-mesh sieve. Multiplying the weight passing the sieve by 6.93 and adding 13 to
the product gives the Hardgrove grindability.
Sizing of coal .
The ability of a coal to resist breakage is known as size stability; the tendency
to break or crumble into smaller pieces is called friability. ASTM has two tests to
assess these properties: 1) the drop-shatter test indicates resistance to breakage
from ordinary handling; 2) the tumbler test gives the effect of rougher handling in
mechanical conveyors, feeders, and other equipment. This property is generally more
important to stoker-fired systems.4
3.2.2 Stoker-Fired Combustion Equipment
Fuel beds provide the most economical method for burning coal in almost all
industrial boilers rated less than about 200,000 Ib/h of steam. In fuel-bed firing, coal is
pushed, dropped or thrown onto a grate by a mechanical device called a stoker. Part
of the fuel is distilled off as a combustible gas (mostly hydrocarbons and CO), which
bums above the bed just like gaseous fuels. Coke, remaining on the bed after
distillation, is burned in the presence of the air that flows up through the grate and the
fuel. Ash left after combustion usually is removed from the furnace on more or less a
continuous basis by movement of the grate.
63
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Stokers can be divided into two general classes, depending on the direction
from which raw coal reaches the fuel bed: 1) overfeeds, in which the fuel comes from
above, and 2) underfeeds, in which it comes from below. The overfeed group
includes spreader and mass-burning stokers. The latter, sometimes called crossfeed
stokers, are more commonly referred to by specific design: chain-grate, traveling-
grate or water-cooled vibrating-grate. Types of underfeed stokers are single-retort and
multiple-retort Multiple retort stokers are relatively rare in today's boiler applications.
Underfeed stokers are commonly applied to small steam systems. The various types
of stokers have different operating characteristics which are summarized in Table 3-6.
The grate area required for a given stoker design and boiler capacity
determined from the allowable heat-released rates established by experience. These
rates (in Btu/ft2 per h) are based on using coals suited to the particular stoker: For a
spreader stoker with stationary or dumping grate, 450,000; with water-cooled vibrating
grate, 400,000; for a single-retort underfeed stoker, 425,000; and multiple-retort,
600,000.
As boiler size is increased, practical considerations limit the grate size and,
consequently, the maximum rate of steam generation with fuel-bed firing. To illustrate:
spreader stokers are specified in boilers with capacities from 5,000 to 400,000 Ib/h
with stationary grates being used at the low end of the range and traveling grates at
the high end. Mass-burning stokers usually are employed in sizes from approximately
15,000 to 250,000 Ib/h while single-retort underfeed units serve between 5,000 and
35,000 Ib/h.
Spreader stokers are extremely popular in industry today. One reason is that
they are capable of burning a wide range of coals, from high-rank eastern bituminous
to lignite or brown coal, as well as many byproduct waste fuels.
Spreaders take raw coal and distribute it within the furnace. Rnes in the
incoming coal stream bum in suspension; larger lumps fall to the grate, forming a fuel
bed. Since 25 to 50 percent of the coal is burned in suspension and fuel-bed
inventory is minimal, spreader-stoker firing has a very fast response to load swings.
The load range generally extends from 20 percent of full load to maximum capacity.
64
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TABLE 3-6. OPERATING CHARACTERISTICS OF VARIOUS TYPES OF STOKERS*
Operating characteristic
Increase load rapidly
Minimize carbon loss
Overcome coal segregation
Accept a wide variety of coals
Burn extremely fine coal
Permit smokeless combustion at
all loads
Minimize fly ash discharge to
stack
Maintain steam load under poor
operating conditions
Minimize maintenance ,
Minimize power consumption
(stoker and boiler auxiliaries)
Handle ash and cinders easily
Spreader
stoker
Excel 1 ent
Fair
Fair
a
Poor
Poor
Poor
Good
Good
Good
Excel 1 ent
Chain and
traveling grate
Fair
Fair
Poor
Poor
Poor
Good
Good
Poor
Good . -
Good
Good
Underfeed
stoker
Fair
Fair
Poor
Poor
Poor
Good
Good
Poor
Fair
Good
Fair
"Traveling-grate type is rated excellent, agitating-grate type is rated fair.
65
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Beneath the active fuel bed is a layer of ash. This bed, together with the flow of
air through the grate, serves to keep metal parts at allowable operating temperatures.
In fact, this method of grate insulation and cooling is so effective that combustion air
usually can be preheated to 300° to 350°F without creating a maintenance problem.
The thin bed of coal and ash also offers relatively low resistance to underfire
(primary) air flow. By keeping grate resistance high and by holding windbox pressure
low, large fluctuations in draft can be avoided as fuel-bed thickness changes. This is
an important point because excessive underfire draft causes heavy cinder carryover
and, in extreme cases, blowholes in the fuel bed. Low excess air is maintained in the
furnace by minimizing leakage of underfire air, using seals at grate joints and at the
sides and rear of the grate.
In addition to underfire air, overfire (secondary) air also is required. In all fuel
beds, the composition of the gas released during distillation varies somewhat from
point to point There is a tendency for the gas and stagnant air over the bed to take
the most direct path to the furnace exit unless high velocity overfire air jets are
installed. The turbulence they create improves mixing, increases the time for
combustion, and also helps to reduce ash carryover. The overfire air jets must
provide enough pressure so that the air penetrates all the way across the fuel bed.
The suspension-burning characteristic of spreader stokers has disadvantages too. For
example, it causes greater paniculate carryover in the flue gas than occurs with other
stoker types. Because much of this carryover is unbumed combustibles, installation of
a cinder-reinjection system is necessary to conserve fuel. Some experts estimate that
reinjection of fly ash from both boiler and dust-collector hoppers typically increases
boiler efficiency by 2 to 3 percent
*
Grafe arrangements
A variety of grate types are available for spreader stokers. Generally, plant
operating conditions determine the most suitable design for any given installation. The
simplest and least expensive arrangement is the stationary grate, which is cleaned
66
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manually. It may or may not have water cooling (Rgure 3-8). Water-cooled stationary
grates sometimes are specified for small coal-fired units. They are more apt, however,
to be found in refuse-firing applications. Ash is either blown off the grate by steam or
air, or is raked off if no nozzles are provided. Uncooled grates accommodate boilers
rated from 5000 to 30,000 Ib/h, but they are not specified today because of air
pollution control restrictions. (The boiler is so small that the required flue-gas cleanup
equipment cannot be justified economically.)
As with the stationary grates, air pollution codes have dramatically curtailed the
use of dumping grates (Figure 3-9). Here the grate is designed in segments, with
each section having its own spreader stoker and underfire air damper. When ash
builds up to a predetermined level on a particular grate section, the fuel supply is
discontinued temporarily to that section, and the thin bed burns out quickly. Underfire
air is then shut off, and ashes are discharged while the boiler load is carried on the
section or sections remaining under fire. With the restoration of fuel and air supply,
ignition is almost instantaneous.
Dumping grates are used to bum low-grade bituminous and subbituminous
coals efficiently, and with a minimum of operating attention, in boilers with capacities
ranging from approximately 5,000 to 60,000 Ib/h of steam. In larger boilers, ash is
removed from the grate continuously. If combustion controls are not carefully
monitored during grate dumping, the dumping grate boiler can be a very "smoky*
design.
Stationary and dumping grates have been replaced in many plants by
continuous-cleaning grates of the reciprocating (Rgure 3-10), vibrating (Rgure 3-11)
and oscillating (Figure 3-12) types. Boilers using these beds are assured optimum
combustion conditions without interruption. This offers a substantial increase in overall
efficiency and minimizes air pollution problems. Discharge of ash from a reciprocating
grate is accomplished by controlled reciprocation of lateral rows of overlapping grates,
which causes the fuel bed to move forward, dumping ash into a pit at the front of the
boiler. The frequency of the reciprocating cycle is synchronized with fuel and air
67
-------
Figure 3-8. Water-cooled stationary grate.4
Figure 3-9. Two views of a dumping grate.4
-------
Overfire air parts •
-Fu»l hopper
Figure 3-10. Vibrating grate.4
Figure 3-11. Reciprocating grate.4
-------
Figure 3-12. Oscillating grate.4
supply. The grate, which can be used on boilers from 500 to 75,000 Ib/h,
accommodates a wide range of bituminous coals or lignite without preparation other
than sizing. Another benefit of this design is that shallow pits can be used to remove
ash at the operating floor level.
The vibrating grate is similar to the reciprocating grate except that the fuel is
moved forward through the furnace by vibration rather than reciprocation. The grate
surface is vibrated intermittently, as a unit, by an electrically operated eccentric-drive
assembly mounted at the front end of the boiler. A timer automatically controls the
frequency and duration of vibration cycles in response to boiler load.
70
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Oscillating grates can be adapted to boilers with capacities up to approximately
150,000 Ib/h. The frame of each grate section is a rigid component that forms the
upper portion of the plenum chamber. Free-moving, cross-tee grid assemblies carry
the grate surface, which is inclined toward the discharge end of the unit to insure
positive travel of the fuel bed. The cross-tee members are supported within the top
portion of the frame by a series of flexure-plate assemblies, attached to longitudinal
base members at the bottom of each side plate comprising the frame. Flexure plates
impart the amplitude of motion that causes the grate to oscillate.
Traveling grates are the most popular grate configuration for spreader-stoker-
fired boilers rated more than approximately 75,000 Ib/h (Figure 3-13). Traveling-grate
spreader stokers, which can bum a wide variety of coals and waste fuels, generally
are the choice in industrial boilers rated 100,000 to 400,000 Ib/h. The endless grates
move at speeds between 4 and 20 ft/h, depending on the steam demand, toward the
front end of the boiler, discharging ash continuously. They are designed to handle a
wide range of coals, as well as process wastes and municipal refuse.
Figure 3-13. Traveling grate.4
71
-------
Spreader-stoker details
Coal usually is withdrawn from the stoker hopper by a mechanical feeder, which
provides an even, uninterrupted supply of fuel to a distribution device. A variety of
feeder types can be used: belt feeder (Figure 3-14, left), reciprocating (center), and
rotary drum (right), for example. These feeders transfer coal from hopper to bladed
rotor, which spreads fuel in the furnace. Overthrow rotation of rotor, rather than
underthrow, provides the best fuel distribution and minimizes maintenance.
Spreader drives can be of the mechanical or hydraulic type. The variable-speed
»
mechanical drives use electric-motors or steam turbines as prime movers operating
through reducing units-such as gear or pulley systems. These same prime movers
actuate a pump and reservoir set for hydraulic drives.
Burning wastes. Where process and/or municipal wastes can be burned in
conjunction with coal, pneumatic fuel distributors generally are added in the front of
the furnace-above the spreader stokers handling coal. In one such refuse distributor
(figure 3-15), air under pressure enters the inlet, passes the air-control damper, and
flows into the distributor nozzle. High-velocity air emerges from the nozzle at the
distributor tray. Trajectory of the refuse, which flows by gravity down the angled
chute, is controlled by raising or lowering the tray with a regulating handwheel. Like
coal fines, small particles of refuse are consumed while in suspension; larger pieces
bum on the grate.
Refuse burning offers advantages in eliminating industrial solid-waste problems
and in minimizing fossil-fuel consumption. Its combustion, in conjunction with coal-
firing, invariably requires a separate fuel-preparation and handling system. The
addition of refuse-firing capability demands a more complex combustion-control
system than would be used for coal firing alone.
72
-------
Coal hepftr
Coal
Rgure 3-14. Belt, reciprocating, and rotary drum types of coal feeders for spreader-stokers.4
-------
Figure 3-15. Pneumatic distributor u*ed for burning refuse wtth coal
in • spreader-stoker.4
Mass-burning stokers
The grate-in-chain and traveling-grate stokers resemble a wide belt conveyor,
moving slowly from the feed end of the furnace to the ash-discharge end. Coal is fed
from a hopper under control of a gate, which establishes fuel-bed thickness. Furnace
heat ignites the coal, and distillation begins. As the fuel bed moves slowly, the coke
formed is burned, and the bed gets progressively thinner. By the time the far end is
reached, nothing remains but ash, which falls off the grate as it goes around the end
sprocket to begin the return trip underneath. Chan grates were originally developed
for bituminous coal, and traveling grates for small sizes of anthracite. As the name
implies, the chain grate is really a wide chain, with grate bars forming the links. The
links are staggered (Figure 3-16), and connected by rods extending across the stoker
width. The traveling grate has a chain drive at the side of the grate, with crossbars at
intervals. Fingers, keys, or dips that form the grate surface are attached to these
crossbars. They overlap to prevent ash from sifting through. An advantage of the
traveling grate is that the easily removed dips simplify maintenance.
74
-------
Figure 3-16. Grate-clip overlap used on a traveling grate stoker.4
Ignition
On a moving fuel bed, the rate of ignition tends to control grate speed and fuel-
bed thickness. Otherwise, time within the furnace may be too short for complete
combustion, or too long to permit full use of the grate. It is mainly radiation that
ignites the incoming fuel. Once the surface layer begins to bum, it warms coal
beneath by contact If the air-flow rate through this part of the fuel bed is correct,
surrounding coal ignites rapidly. If it is excessive, the bed cools and ignition is much
slower.
For good combustion, air flow must vary along the bed. This can be
accomplished in several ways. In a typical chain-grate installation, for example, the
space between the upper and lower strands of grate forms a common air chamber,
which allows equalization of air pressure under the entire grate. The grate surface,
75
-------
i ii II11IIII mm ii mwH
Figure 3-17. Schematic of a traveling grate showing air zones.4
however, is divided into a series of zones, each with individual dampers for close
control of air flow. Most traveling grates have from four to nine active air zones,
depending on size. These units (such as the one shown in Rgure 3-17) differ from
chain grates in that they have two types of active air zones: high-pressure and low-
pressure.
Another air-supply system commonly used with traveling-grate stokers is
illustrated in Rgure 3-18. In it, underfire air is supplied through individual air ducts
leading to each compartment or section of the grate. Row can be adjusted manually
for each duct. Air leakage between compartments is prevented by air seals.
Air seals also are used to control leakage around chain and traveling grates.
Note that if leakage occurs at the combustion-chamber level, it reduces the pressure
differential across the fuel bed. The effect of this is to lower the ignition rate, and
place a heavier load on forced- and induced-draft fans.
76
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WffitT feTT'ivi^^]-^^
Figure 3-18. Schematic of a traveling grate stoker
•bowing the air supply system.4
Fuel flexibility
Chain- and traveling-grate designs accommodate steam capacities from as low
as 6000 Ib/h to over 200,000 Ib/h. As a class, these stokers are well suited for a wide
variety of fuels. Almost any solid fuel of suitable size such as peat, lignite,
subbrtuminous, free-burning bituminous, anthracite, or coke breeze, can be burned on
them. Generally, 11/4 in. screenings and smaller are used.
Strongly caking bituminous coals may have a tendency to mat and prevent
proper passage of air through the fuel bed, causing unbumed carbon to be
discharged to the ash pit Also, a fuel bed of strongly caking coals may not be very
responsive to a rapidly changing load. Experience has shown, however, that the bed
can be made more porous by tempering the coal (i.e., by adding moisture in the form
of either water or wet steam). Weathering can also help, because it reduces the
swelling or caking power of a coal. The trouble with both these solutions is that a
significant percentage of the coal's heating value is lost. Tempering of caking coals is
77
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not required by the other type of mass-burning stoker: a water-cooled, vibrating-grate
unit. It can bum a wide variety of bituminous coals, from free-burning to high-coking
grades, high or low volatile, lignites, and even some semianthracrties.
The size consistency (proper mixture of sizes) of coal fed to a spreader stoker
has a direct bearing on boiler efficiency, and on the tendency of the boiler to
discharge paniculate. The reason is that spreader-stoker operation is based on both
stationary combustion (on a grate) and burning coal in suspension. Thus, the quantity
of paniculate entrained in the gases tends to increase as the percentage of fines in the
fuel increases.
The extreme sensitivity of a spreader stoker to load variations is one of the
principal advantages of this type of firing. This sensitivity calls for rapid ignition of the
finer fuel particles. Hence, some fines must be provided in the coal.
The chart (Rgure 3-19) provides a guideline for coal sizes for a spreader-stoker.
The recommended limits of coal sizing are defined by the tinted area. It should not be
inferred that spreader stokers cannot be operated with coals outside this size range.
Care must be taken, however, that coal characteristics remain in this nominal range.
Operation outside this range can lead to poor combustion characteristics and as
illustrated in Section 8, excessive costs for operation.
Note that the recommended limits apply to the sizes of coal actually delivered to
the stoker hopper. Depending on the friability of the coal, the mode of shipment, and
the number of times the coal is handled between unloading and transfer to the stoker
hopper, there may be a wide difference between the coal as shipped from the mine
and the fuel that finally reaches the stoker.
Reinjection of fly ash containing unbumed carbon is another boiler design
feature that minimizes the pollution problem and increases overall efficiency, however,
it must be done on a selective basis. Only the coarse carryover, which contains a
significant amount of carbon, should be reinjected into the furnace. The fine fly ash,
which has little or no combustion value, only adds to the dust loading of the gas, and
should be discarded.
78
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Fuel to be Delivered Across Stoker Hopper Without Size Segregation '
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Underfeed Stokers
In underfeed stokers, raw coal is fed into the fuel bed from below. It is pushed
in a feed trough, or retort, and, under the pressure of fresh coal from behind, it rises in
the retort and spills over onto the bed at either side of the trough. No air is supplied
in the retort proper; it comes through openings, called tuyeres, in the grate sections
adjoining the trough. At the top of the retort, raw coal is exposed to some drying
action from both the incoming air and furnace heat. Ignition occurs and distillation
begins as the coal moves from the retort to the active burning area around it. Either
under the pressure of incoming coal, or as the result of grate motion, burning coal
moves slowly to the dumping grates over the ash-discharge area.
There are two types of underfeed stokers: single-retort and multiple-retort.
Single-retort units differ in the method of feeding coal and in the grate design. For
example, one unit has a reciprocating ram and pusher-block arrangement. The ram
transfers coal from the hopper to the retort, where pusher blocks help distribute it to
the fuel bed (Rgure 3-20). Another type has a retort with a sliding bottom on which
auxiliary pusher blocks for advancing coal in the retort are mounted.
Many single-retort units have moving grates to provide fuel-bed agitation and to
assist movement of the coal to the dump grates at the sides. The single-retort stoker
illustrated in Rgure 3-21 has undulating grates that produce a wave-like motion. This
particular model handles highly caking coals well. Undulation grate action breaks up
the coke formations and keeps the fuel bed porous and free-burning. The stationary
grate is used in boilers with capacities up to approximately 20,000 Ib/h of steam; the
undulating grate usually handles up to 25,000 Ib/h, occasionally as much as 35,000
Ib/h.
Air distribution
Side grates and dumping grates usually are provided with air holes to insure
complete carbon burnout In a typical unit (Figure 3-22) air is supplied by a blower or
fan connected by a duct to the stoker's main air chamber-located directly below the
80
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Figure 3-20. Photograph and cutaway diagram of single-retort
underfeed stoker with reciprocating ram.4
81
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Figure 3-21. Single retort underfeed stoker with undulating grate.4
Figure 3-22. Diagram of an underfeed stoker showing air supply.4
82
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retort. Rising through this chamber, air enters the hollow grate bars at the retort end
through penetrations in the underside of each bar. Tuyere openings in the grate bars
admit some of this air over the retort The remainder is forced through the bars and is
discharged into the auxiliary air chamber. From there, it passes up between the grate
bars into the fuel bed. Note that in traveling through the bars, air absorbs heat,
prolonging bar life and providing some preheating.
The air distribution system is designed to proportion the amount and pressure
of primary or underfire air, as required by various sections of the fuel bed for proper
combustion. Secondary or overfire air flow is controlled by a damper operated from
the front of the stoker. Air can also be admitted under the dump grates, when
necessary to complete burning, by opening .dampers in the auxiliary air chamber.
Coal characteristics
Single-retort stokers burn most bituminous coals as well as anthracite. Size is
not too critical, but top size usually is limited to a range from 3/4 in. to 1 1/4 inches.
Allowable caking properties generally are specified too.4
3.2.3 Pulverized Coal Combustion Equipment
Coal may be pulverized to the fineness of talc and blown through pipes into
burners. When handled in this manner, the combustion of coal becomes similar to the
combustion of oil. The advantages of burning coal in this manner are the high surface
area of the pulverized coal, make it possible to burn a wide variety of coals, the
response to heat input demands are relatively fast, and a high combustion efficiency is
often realized because the excess air requirements and combustible losses are lower
than a comparable stoker-fired system. These advantages must be weighed against
the higher cost of the pulverizer equipment and energy costs associated with
pulverized coal firing. Although smaller units exist, pulverized coal firing generally
becomes cost competitive for boilers operating above the 100,(XX) Ib steam/h range.
Nearly all pulverized coal systems used today are direct-fired systems. The
coal is fed to the pulverizer and is discharged directly to the burner system. This
83
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provides a certain degree of safety as a relative small inventory of coal is in the
pulverizer and the coal burner pipes at any given time. Pulverizer and burner pipe
fires are sometimes a problem with pulverizer systems. The limited inventory generally
restricts the damage due to fires.
The pulverized coal system can be divided into several major areas. These are
the coal feeder, the pulverizer, the conveying air fan, and the burner. There are
numerous variations on the pulverizer design, burner design, and conveying air
system. Most systems, however, share these common components.
The coal is fed to the pulverizer by a coal feeder. The coal feeder controls the
rate that the coal enters the pulverizer and is controlled by the boiler control system.
The coal enters the pulverizer where it is dried and pulverized. The drying air is
usually provided from the combustion air preheater. This hot gas dries the coal and
provides the transport air for the pulverized coal to leave the pulverizer. The
pulverized coal passes through a particle size classifier. Oversized coal particles are
returned to the pulverizer mill for more size reduction while the remaining coal particles
leave the pulverizer and enter the burner pipe. The burner pipe is usually refractory
lined to protect the pipe from abrasion as it conveys the coal to the burner. The
typical coal fineness is 70 percent by weight through a 200 mesh screen, though this
varies depending on coal characteristics and the percent of full load operation.
The coal enters the burner with the conveying air which is the primary
combustion air. The primary combustion air typically composes only 15 to 25 percent
of the total air required for the combustion of coal with approximately 1.0 to 2.5 Ib
air/lb coal. Within a fraction of a second of entering the burner, the coal particles are
exposed to the heat of the burner and the combustion zone, the temperature of the
particle rises and the volatile matter distills off. The primary air begins the combustion
process but the secondary air and the mixing of the primary and secondary air
provided the remaining air and turbulence for the complete combustion of the coal
particles. The secondary air, also brought from the air preheater, is much hotter than
84
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the primary air because it has not been used to dry the coal and this also helps in the
combustion process. As in oil firing the ratio of primary and secondary air and the
degree of turbulence affect the flame shape and the rate of carbon burnout.
The pulverized coal burner must be started up with another fuel. Usually the
fuel is any easy burning one that maintains flame stability in the presence of cold
burner and furnace surfaces. This is usually natural gas to start and , perhaps, a
switch to oil once warming begins. The use of other fuels to start the operation of
pulverized coal burning is standard practice.
An individual pulverizer has a limited turndown range. Typically this turndown
ratio is only approximately 3:1. Below 50 percent of full rated pulverizer load control of
primary air to the primary/secondary levels becomes more difficult and flame stability
becomes a problem. The pulverizer compensates for this somewhat by its design
because the lower air flow through the pulverizer means that the particle size leaving
the pulverizer gets smaller as the load decreases. The finer coal particle enhances the
flame stability by providing more combustion surface area. Boilers using more than
one pulverizer and equipped with multiple burners achieving greater turndown ratios
by taking burners and pulverizers out of service. Those pulverizers that are
operational at low steam loads typically are operating near there maximum design rate.
There are numerous coal pulverizer designs but they generally fall into three
categories: ball mills, tube or rod mills, and bowl mills. The bowl mill class is the most
common application of coal pulverizer used today. Each boiler manufacturer has its
preference for specific design features and the difference in design features sometimes
makes a difference in the performance of the boiler and the control equipment. An
example of these differences may be seen in the Raymond Mill used by Combustion
Engineering in many of their boiler designs and the MPS pulverizer used by Babcock
and Wilcox. Although both mills are capable of delivering the coal to the burner pipe
with the desired size specification, it has been generally observed that the Raymond
Mill tends to reject more material than the MPS mill. This is felt to be caused by the
mill design and the fact that the mill rejects material that is harder to grind. This may
85
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include rock that may not have been separated from the coal during coal preparation
at the coal mine and iron pyrites that are included in the coal structure. In some
cases, the quantity of rejects from this mill type have been so significant that the
quantity of sulfur in the fuel that enters the burner is substantially different from the
sulfur analysis that is arrived at during the coal ultimate analysis. This can cause
operating problems for an ESP that may require a certain level of SO2/sutfur trioxide
(SOg) to avoid high resistivity problems. The lower quantity of sulfur burned results in
a smaller quantity, of sulfur that is converted to SO3 and may produce a higher
resistivity ash in the ESP.
The boiler size for pulverized coal combustion is governed by the coal
properties and the allowable heat release rates. A boiler designed for coal firing will
be substantially larger than the comparably sized oil or natural gas boiler. The heat
release rate must be lower to avoid the problems of ash slagging and fouling and the
solid fuel takes a longer time to bum. This results in a much larger furnace volume
than that for oil or natural gas. In addition the presence of ash in the gas stream
requires an increase in the tube spacing in the heat transfer zone to minimize buildup
between the tubes. To provide the equivalent heat transfer area of a natural gas or
oil-fired boiler, the volume of the heat transfer areas is increased. Lastly the velocity of
the gas through the heat transfer area cannot be as high as that allowed for the
combustion of natural gas or oil because of abrasive effects of the ash. Gas velocities
through the tubes are usually 50 to 75 ft/s through the tubes for coal-fired boilers
compared with 100 ft/s for natural gas or oil-fired boilers.
Substantial differences exist among boiler designs even within the category of
pulverized coal combustion. In addition to the choices of discrete burners versus
tangential (or comer) firing, the size of the furnace zone is determined by the coal
characteristics. Western subbituminous coals that have lower heating values and
higher moisture levels may require larger furnace volumes to allow for complete
combustion without slagging or fouling of the tube surfaces. Eastern bituminous coals
tend to have less slagging characteristics. The heat release rates for pulverized coal
86
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combustion typically ranges between 25,000 to 50,000 Btu/h per ft3 of furnace volume.
The heat release rates may also be expressed as the heat release for the plan area
(the cross sectional area of the boiler) and the heat release per ft2 of effective
projected radiant surface (EPRS) area The plan area heat release rates for coals with
high slagging potential are typically around 1.4 x 106 Btu/ft2 per h up to 2.4 x 106
Btu/ft2 per h for coals with low slagging potential. In addition, the radiant heat release
is typically between 70,000 and 120,000 Btu/ft2 (EPRS)-h with the lower range of
values used for coals with higher slagging potential. As can be seen from these
parameters, a boiler burning a coal with high slagging potential can be 50 to 75
percent larger than the boiler burning a coal with low slagging potential.
The tangential fired systems (typical of Combustion Engineering boilers) and
those using discrete burners differ in the method in which coal and secondary air are
introduced into the boiler. In theory the discrete burner approach provides the
opportunity to control the combustion process for each burner. This is fine for a small
number of burners but may become more difficult in the boiler with many burners and
pulverizers. The tangential fired system, however, introduces coal into a swirling mass
(fireball) in the furnace where secondary air is introduced above and below the coal
burner pipes. Most of these tangential fired systems have tillable burners for
placement of the combustion zone within the furnace for the desired
radiant/convective heat transfer pattern in the furnace. The tangentially-fired system is
usually thought to be a lower inherent NOX producer because the combustion process
tends to reduce peak flame temperature. Control of the air ratio, however, is as
important to the tangential-fired system as it is to the discrete burner arrangement.
Suspension firing of the coal causes most of the ash produced from the
combustion to be suspended in the gas stream and to leave the boiler as fly ash that
must be collected by some air pollution control device. Typically, 70 to 90 percent of
the ash leaves the boiler as fly ash with the remainder as bottom ash. The particle
size distribution leaving the boiler appears to be influenced by boiler design and
pulverizer operation with some designs producing a much finer particle size fractions
87
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than others. The precise cause of this phenomenon is not known but it is suspected
that the overall particle size generated by certain pulverizers is generally smaller then
that generated by other designs although they may all meet the criteria of 70 percent
through a 200 mesh screen. These factors along with ash chemistry, combustion gas
conditions, and carbon loss all affect the design and operation of air pollution control
equipment A direct-firing system is typically used and the pulverizers feed the burners
directly. Since there is no storage bin, pulverizer operation fluctuates with steam
demand. This system is not only simple, i.e., involving less equipment, but it also
avoids a potential fire hazard. The quantity of pulverized coal in the mill never exceeds
a minimal amount, and the length of piping between the mill and the burners is short.
These systems have the flexibility to handle a wide range of load and coal conditions.
Burners
After pulverization, coal is pneumatically transported to the burners in pipes.
These components supply air and fuel to the furnace in a manner that permits 1)
stable ignition, 2) effective control of flame shape and travel, and 3) complete mixing of
fuel and air.
Air used to transport coal to the burner is the primary air; secondary air is
generally introduced around or near the burner. The burners described below impart
a rotary motion to 1) the coal/air mixture emanating from a central nozzle, and 2) the
secondary air issuing from a chamber around that nozzle within the burner. This gives
some premixing for coal and air, plus turbulence.
Many industrial burners fire into the furnace horizontally, usually from one wall.
These burners generally are arranged in a manner to promote turbulence. The
horizontal burner shown in Figure 3-23 has a central coal nozzle with internal ribs in
the form of rifling. The nozzle is surrounded by a housing, which is provided with
adjustable vanes for controlling air turbulence and the resulting flame shape. A central
tube allows for the insertion of an ignition torch. In opposed firing, burners in opposite
walls of the furnace throw their flames against each other to increase turbulence.
Tangential or comer firing, which is inherently turbulent, is also is used in industry.
88
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A circular register burner (Figure 3-24) can be equipped to fire any combination
of the three principal fuels-coal, oil, or gas. But combination pulverized-coal/oil firing
(in the same burner) is not recommended because coke may form on the pulverized-
coal element, reducing burner performance.
An intervene burner (Figure 3-25) imparts a rotary motion to the coal/primary-
air mixture in a central nozzle. This provides fuel/air premixing and considerable
turbulence, which are required for efficient combustion. Secondary air flows into the
furnace from a chamber that surrounds the nozzle.
A directional burner (Rgure 3-26) introduces air and fuel into the furnace
through vertical slots formed by water-cooled openings between tubes in the furnace
walls. Each slot has directional vanes, which can be adjusted to obtain the desired
placement of flame and to minimize the formation of NOX.4
Fluidized-Bed Boilers
Fluidized bed combustors (FBCs) appear to be the new growth area in
combustion technology. The technology is not yet widely used in either the industrial
or the electric utility combustion areas. New construction of coal-fired boilers for
industrial uses, however, has seen a significant percentage of these boilers being
permitted over other designs. As operating experience is gained and designs refined,
FBCs will probably dominate new industrial boiler construction for sizes once
dominated by pulverized coal systems.
The FBCs operate by suspending fuel and inert material such as sand, alumina,
silica, and limestone in an air stream from underneath the bed of material. The
velocity of air through the bed of material is high enough to provide controlled
entrapment of the material in the furnace without total suspension of the fuel out of the
boiler exit, as in pulverized coal firing.
89
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Figure 3-23. Horizontal burner.4
Figure 3-24. Circular register burner.4
90
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Figure 3-25. Intervene burner.4
Figure 3-26. Directional burner.4
91
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There are several design factors that make FBCs attractive when compared to
other designs. First, they are capable of burning a wide range of fuel. This should not
be interpreted as being capable of burning any fuel or being able to radically switch
fuels on short notice. With proper preparation, however, the operation of FBCs can
tolerate a wide range of fuels with only limited side effects. Second, the high degree
of turbulence in the bed promotes mixing and evenly distributed temperatures within
the bed. The higher degree of turbulence means that lower operating temperatures
may be used to provide complete combustion. The lower operating temperatures
should promote combustion with less likelihood of thermal NOX formation. The lower
operating temperature also means that the problems associated with the ash
characteristics such as ash fusion temperature and boiler slagging and fouling should
be minimized. Finally, the fluidized bed provides for the control of S02 during the
combustion process by the use of limestone injection into the bed material. The
reaction between limestone and SO2 depends on the available surface area of the
limestone, the amount of limestone available, and the temperature of the reaction
between SO2 and the limestone (which is controlled by the bed temperature).
There are numerous FBC designs available from several boiler manufacturers.
The designs may be categorized into two different groups. The two designs are the
bubbling bed and the circulating fluidized bed (CFB) designs (Rgure 3-27). The
differences between the two designs are related to the operating velocity in the
fluidized bed and the recycle, or return, rate of material entrained out of the
•
combustor. Bubbling bed designs are generally classified as having design velocities
of 4 to 12 ft/s. The entrapment loss (mass loading) of particles leaving the combustor
is relatively low and material has to be siphoned off the fluid bed to remove ash and
spent limestone sorbent. The particles that leave the bubbling bed reactor are usually
captured by a cyclone or multicydone arrangement. A portion of the material
captured by the separator is recycled to the combustor to enhance combustion
efficiency.
The CFB combustors generally operate at velocities of 12 to 30 ft/s. The
degree of entrainment is much higher than that of the bubbling bed design.
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Convection
Figure 3-27. A CFB design.5
-------
The entrained particles are captured by high volume mechanical separators with high
recycle rates. As the material is recycled a small portion of the recycled material is
siphoned off, otherwise particles escape the process in the combustion gases leaving
the mechanical separators. The gases leaving the mechanical separators in both
designs then pass through conventional corrective heat transfer equipment, as would
be used in other solid fuels designs.
Both bubbling bed and CFB designs may incorporate in-bed boiler tubes to
help control bed temperature and to improve thermal efficiency. In general, however,
the volume of the furnace zone of either type of FBC is much smaller than the
comparably sized stoker or pulverized coal boiler. The design variations are
numerous at this time as the technology is relatively new and many of the design
details are proprietary. There are many variations in the amount of heat transfer area,
recirculation, amount of mass per unit heat release rate for a given steam production
rate, fuel feed techniques, and ash removal techniques from the fluidized bed. As
more experience is gained, a consensus in boiler design may begin to emerge.
3.3 Wood-Fired Combustion
Wood is typically used to fire boilers in the paper and allied products industry,
the forest products industry, and the furniture industry. Within these industries, the
types of wood burned ranges from sawdust and sander dust to wood slats, wood
chips, and wood bark. Other sources of wood for fuel include: discarded packing
crates, wood pallets, and wood waste from construction/demolition activities. There
are approximately 1600 wood-fired boilers in operation in the United States with a total
capacity of 30.5 GW (1.04 x 1011 Btu/h) thermal input. These range in size from 0.44
MW (1.5 x 106 Btu/h) to 420 MW (1.43 x 109 Btu/h) thermal input The largest
numbers of wood-fired boilers are in the States with the most forest-related industries -
Oregon, Washington, Georgia, Florida, and Arkansas.
Bagasse is an agricultural waste which, like wood, is frequently burned as a
fuel. It consists of the fibrous residue left after processing sugar cane. Approximately
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185 boilers that bum bagasse are currently in operation in Florida, Louisiana, Texas,
Hawaii, and Puerto Rico. Bagasse boilers range in capacity from 3.8 MW (13 x 106
Btu/h) to 236 MW (805 x 106 Btu/h) thermal input.
3.3.7 Characteristics of Fuels From Wood and Bark Residues
Wood and bark prepared for firing a boiler are commonly referred to as hog
fuel. The term stems from the machine used to reduce the size of residues called a
hog (Figure 3-28). Hog fuel can be classified or characterized by species, size,
moisture content, ultimate analyses, proximate analyses, and heating value.
DOUBLE
BREAKING
PLATE
COVER DIVIDES HERE
METAL TRAP
Figure 3-28. Wood hogger.
95
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The size of hog fuel depends on the material that makes up the fuel. A typical
sample of hog fuel might include a combination of bark, coarse wood residues (slabs,
trimmings, and end pieces), planer shavings, sawdust, sander dust, and reject "mat
furnish." Each of these component parts has recognizable size characteristics (Table
3-7).
There are two ways to describe the moisture content of fuel; the wet or "as is"
basis, and the dry basis. The wet basis is more commonly used. For wet basis
determinations, the weight of moisture in fuel is divided by the total weight of fuel plus
moisture, and the answer is expressed as a percentage on either a wet or dry basis.
Moisture content is significant for two reasons. First, it varies over a wide range
of values and, therefore, makes control of the combustion process difficult. For
example, consider moisture content of the different components of hog fuel. Bark,
coarse wood residue, and sawdust normally have a moisture range from 30 to 65
percent. The average value is around 45 percent This is dependent, however, on the
time of year, the type of wood (species), and the process used at a particular mill. On
the other hand, kiln-dried planer shavings, sander dust, and some rejected mat-furnish
materials usually have low moisture content from 4 to 16 percent. Table 3-7
summarizes typical moisture content for the normal components of hog fuel The
second significant feature of moisture content is that it has negative heating value; that
is, heat is needed to evaporate it
Proximate analysis of wood fuel determines the percentage of volatile material,
fixed carbon, and ash. Some typical proximate analyses of wood fuels are shown in
Table 3-8. Note the consistent difference in volatile content of bark compared to that
of sawdust, regardless of species (except for cedar). In general, volatile content of
wood is 10 percent higher than that of bark.
The ash content of wood residue is generally low, but still significant where
large quantities are burned. The ash content of bark usually is greater than that of
wood because handling and harvesting of logs frequently causes dirt and sand to
ding to the bark. Saltwater storage and transport of logs also can add to the ash
content of fuel by depositing sea salt in the wood or bark.
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TABLE 3-7. APPROXIMATE RANGE IN
COMPONENTS
Component
Bark
Coarse wood residues
Planer shavings
Sawdust
Sander dust
Reject "Mat Furnish"
"From kiln dried to green
Size
1/32 -
1/32 -
1/32 -
1/32 -
2fj-
1QU-
1 umber.
SIZE AND MOISTURE CONTENT OF TYPICAL
OF HOGGED FUEL
range
4 Inches
4 Inches
1/2 Inch
3/8 inch
1/32 Inch
1/4 Inch
Moisture
25
30
16
25
2
4
content, %
- 75
- 60
- 40°
- 40
- 8
- 8
TABLE 3-8. TYPICAL PROXIMATE ANALYSES OF MOISTURE-FREE WOOD
Species Volatile matter, % Charcoal, % Ash, %
Bark
Hemlock 74.3 24.0 1.7
Douglas fir, old growth 70.6 27.2 2.2
Douglas fir, young growth 73.0 25.8 1.2
Grand fir 74.9 22.6 2.5
White fir 73.4 24.0 2.6
Ponderosa pine 73.4 25.9 0.7
Alder 74.3 23.3 2.4
Redwood 71.3 27.9 0.8
Cedar bark 86.7 13.1 0.2
Sawdust
Hemlock
Douglas fir
White fir
Ponderosa pine
Redwood
Cedar
84.8
86.2
84.4
87.0
83.5
77.0
15.0
13.7
15.1
12.8
16,1
21.0
0.2
0.1
0.5
0.2
0.4
2.0
97
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Characteristics of hog fuel, such as size, moisture content, ultimate analysis,
proximate analysis, and heating value influences the combustion process. The
combustion process is a gaseous-phase reaction. Approximately 75 to 85 percent of
wood fuel is volatile and must bum in the gaseous state. This requires proper
conditions for vaporization of the fuel. The size of fuel particles directly affects their
ability to vaporize. The smaller the pieces, the more rapidly their volatile components
will vaporize and bum.
Moisture content of fuel also affects the rate at which fuel can vaporize to the
gaseous state. Some fuel-related variations in moisture are shown in Table 3-7.
Variations in moisture content over time may make control of the combustion process
difficult.
3.3.2 Furnace Designs
Three classes of furnace design are commonly used for wood-firing: Dutch
ovens, spreader stokers, and suspension burners.
Dutch Oven
The Dutch oven design was the standard until the early 1950's. It is primarily a
large, rectangular box, lined on the sides and top with firebrick (refractory). Heat is
stored in the refractory and radiated to the conical fuel pile in the center of the
furnace. This aids in driving moisture from the fuel and evaporating organic materials.
The refractory may be water cooled to minimize the damage to the furnace from high
temperatures.
The fuel pile rests on a grate. Underfire air is fed through the grate and overfire
air is injected around the sides of the fuel pile. By design, incomplete combustion is
intended to occur in the Dutch oven or primary furnace. Combustion products pass
between the bridge wall and the drop-nose arch into the secondary furnace chamber,
where combustion is completed. Then gases enter the heat exchange section.
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Tliis furnace design has a large mass of refractory, which helps to maintain
uniform temperatures in the furnace region. This uniform temperature aids in
stabilizing combustion rates, but causes slow response to fluctuating demands for
steam. The system works well with this design, however, the underfire airflow rate
depends on height and density of the fuel pile on the grates. When the fuel pile is wet
and deep, the underfire airflow is low. Thus, the fire may be deficient in oxygen. As
the fuel dries, the pile bums down, the flow rate increases, and the pressure drop
through the fuel pile decreases. This brings about an excess of air in the furnace. For
fluctuating steam loads, the result is continuous change from insufficient air to excess
air. This feature, coupled with slow response, high cost of construction, and high
costs of refractory maintenance, resulted in phasing out Dutch oven designs.
Spreader Stokers
The most common method of firing a wood-fired boiler larger than 100,000 Ib/h
is the spreader stoker. In spreader stoker furnaces (Rgure 3-29), fuel is spread
pneumatically or mechanically across the furnace. Part of it burns in suspension, but
large pieces fall onto a grate. The feed system is designed to spread an even, thin
bed of fuel on the grates. The flame over the grates radiates heat back to the fuel to
aid combustion. Underfire air can be controlled, because the pressure drop through
the fuel mat is fairly constant
Spreader stoker furnace walls normally are lined with heat exchange tubes
(water walls)! As there is little refractory, construction and maintenance costs are low.
For a given steam-generation capacity, spreader stokers are substantially smaller than
Dutch ovens. Also, they can respond to load variations quickly and with less upset in
the combustion process. With little or no refractory to reflect heat back to the fuel,
heated combustion air is normally used.
Within the categories of spreader stokers, the grate systems may vary
substantially. They may be categorized as fixed or dumping grates; air-cooled or
water-cooled grates; flat or inclined grates; stationary grates, continuously moving
99
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STEAM OUT C
STACK
CVERFIRE
AIR—i
SPREADER
MULTIPLE
CYCLONE
COLLECTOR
STEAM DRUM
AIR HEATER
WATER WALL FURNACE
Figure 3-29. Small spreader-stoker furnace.
100
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chain grates, reciprocating grates; or grates with large area for gas passage, such as
"herringbone" rather than pinhole designs. Design of a particular grate system takes
into account such factors as fuel size, moisture content, available heat, maximum rate
of steam generation of the boiler, and acceptable level of maintenance. Many of the
differences, however, reflect the product line of particular manufacturers. Variations in
these designs are shown in Section 3.3.1 where spreader stokers are used for coal
burning.
Suspension Burning Systems
Fuel in small sizes can be burned in suspension, that is, supported by air rather
than by fixed metal grates. Sander dust usually is burned in this manner. With
adequate reduction in size, wood and bark residues also can be burned in
suspension. The advantages of suspension burning include low capital costs for
combustion equipment because grates are not required, and ease of operation, as
grate cleaning is not necessary. The ash goes into suspension as paniculate matter in
the exhaust stream or falls to the furnace bottom for removal, and rapid changes in
rate of combustion are possible.
Suspension burning has disadvantages because most of the ash escapes with
the exhaust gases, control of fly ash may be difficult Temperature control in the
furnace zone is critical. If the ash-fusion temperature is exceeded, the ash may form
large pieces, which can plug or damage the system. Fuel preparation must be
extensive to assure fuel size small enough for suspension burning. Moisture content
also must be controlled within reasonable limits. This can be costly for systems
burning wood and bark fuels. For sander dust fuel, the processing already is done.
Residence time is critical; the nature of suspension burning involves a short residence
time in the combustion chamber. At high combustion rates, there may be insufficient
time for the process to go to completion.
101
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3.3.3 Bagasse-Fired Boilers
Bagasse-fired boilers are located at sugar mills, and the steam output is used to
power the sugar cane processing equipment. The methods used for firing bagasse to
generate steam in existing boilers are pile burning designs (fuel cell, horseshoe) and
the spreader stoker. The pile burning designs are considered to be the most reliable,
flexible, and most simple firing methods available for bagasse. Because these designs
are less efficient and require more operating labor, spreader stokers have been
typically used in recent years.
The design of bagasse spreader stoker boilers is the same as that of wood-
fired boilers except that cinder reinjection is not normally used. The general
description of wood-fired boiler operation is also applicable to typical bagasse-fired
spreader stoker boilers.
Rgure 3-30 shows a schematic of a representative bagasse-fired spreader
stoker boiler with a heat input capacity of 58.6 MW (200 x 106 Btu/h). This figure
shows material balances for the representative bagasse-fired boiler. Bagasse entering
the boiler usually contains approximately 52 percent moisture (wet basis) by weight.
Rgure 3-30 also shows the energy balance for a bagasse-fired boiler. This balance is
based on 1) fuel energy input from the bagasse and 2) steam output and various heat
losses. All heat losses are shown as heat loss out of the stack. Because a spreader
stoker boiler has an average of 60 percent efficiency overall when firing bagasse, total
heat loss is 40 percent of the heat input, or 23.4 MW (80 x 106 Btu/h). Available
energy input is 3920 Btu/lb of bagasse. This low available energy in the bagasse
partly results from the high moisture content (52%) of the fuel.
Bagasse combustion causes ash accumulation in the boiler ash pit and
paniculate matter discharge with flue gas from the stack. Ash accumulation and flue
gas discharge rates for a representative bagasse-fired boiler are shown in Rgure 3-30.
102
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Steam Output
35.2.MW
(120 x 10° Btu/hr)
Combustion Air
97,100 kg/hr
(214,000 Ib/hr)
Flue Gas
120,000 kg/hr
264,000 Ib/hr
PM: 458 kg/hr
(1010 Ib/hr)
NOX: 18.1 kg/hr
(40.0 Ib/hr)
Radiative, Convective
and Stack Losses
23,4 MW
(80 x 10& Btu/hr)
Mass Flow Stream
Bagasse Fuel
Mass Input
23,100 kg/hr
(51,000 Ib/hr)
Bagasse Fuel
Heat Input
»— 58.6,MW
(200 x 10° Btu/hr)
Cntt
Bottom Ash
145 kg/hr
|319 Ib/hr
Energy Flow Stream
Figure 3-30. Material and energy balances for a representative bagasse-fired boiler.
103
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3.4 Municipal Wastes and Refuse Derived Fuels
As of 1987, approximately 160 municipal waste combustors (MWCs) were
operating in the United States. Combustion of municipal waste is an attractive waste
management option because it reduces the volume of the waste by 70 to 90 percent.
Because of shrinking landfill availability, municipal waste combustion capacity in the
United States is expected to grow rapidly, faster than the growth rate for municipal
refuse generation. From the current combined U.S. capacity of 45,000 tons/day,
combustion capacity has been projected to reach 117,000 to 252,000 tons/day by the
year 2000 with the addition of nearly 200 new facilities.6
Three main types of combustors are used: mass bum, modular, and refuse-
derived fuel (RDF) fired. The first type is called "mass bum" because the waste is
burned without any preprocessing, other than the removal of large noncombustible
items. In a typical mass bum combustor, refuse is placed on a grate system that
moves the waste through the combustor (Rgure 3-31). Combustion air in excess of
stoichiometric amounts is supplied both below (underfire air) and above (overfire air)
the grate to ensure complete burnout of combustibles in untreated garbage. Mass
bum combustors are usually field-erected and range in size from 50 to 1000 tons/day
of refuse throughput per unit The majority of mass bum facilities have two or more
combustors and many have site capacities of greater than 1000 tons/day.
The mass bum category can be further divided into waterwall and refractory-
wall designs. Waterwall combustors are designed to recover energy in the form of
steam. Refractory-Wall combustors are used for waste volume reduction and do not
recover energy. Most refractory-wall combustors were built prior to the early 1970's;
newer units are waterwall combustors.
Modular combustors, like the large mass bum combustors, bum waste without
preprocessing. Unlike the large units, they are typically shop-fabricated and range in
size from 5 to 100 tons/day of refuse feed per unit. In a typical modular combustor
the primary chamber is fed using a hopper and ram feed system. Air is supplied to
104
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the primary chamber at substoichiometric levels. The incomplete combustion products
pass into a secondary combustion chamber where excess air is added and
combustion is completed. The resulting hot gases may be passed through a heat
recovery boiler for energy recovery.
A third major class of MWC bums RDF. The types of boilers used to bum RDF
-<•
can include suspension, stoker, and fluidized bed designs. RDF may be co-fired with
a fossil fuel (usually coal), but co-firing is not prevalent at the present time. The
degree of processing of refuse to yield RDF can vary from simple removal of bulky
items accompanied by shredding to extensive processing to produce finery divided fuel
suitable for co-firing in pulverized coal-fired boilers. Processed municipal waste,
regardless of the degree of processing performed, is broadly referred to as RDF.
The combustion of municipal waste involves many more operating problems
than combustion of coal. This is due primarily to the fluctuating, inconsistent nature of
municipal waste itself. One problem is that noncombustibles are mixed with
combustibles. For example, wastes high in moisture, such as grass clippings, leaves,
and other yard waste, quench the flame in the combustor. Ferrous, aluminum, and
glass components do nothing but remove heat, reduce operating efficiency, and
change the chemical species that may be generated. Other noncombustible material
that enters with the waste often does nothing but further increase the quantity of
material discharged that still must be disposed.
Material that does not bum well inevitably leads to higher maintenance of the
combustor. For example, chlorine, found in corrugated boxes and plastic products,
corrodes boiler and superheater tubes. Glass and aluminum, on the other hand,
account for much of the slagging and fouling. Glass melts at around 2000° F, a
temperature routinely found in the lower furnace sections. Instances have been noted
of slag building to the size of a small car, then falling on and breaking the grate,
shutting down the plant Aluminum melts at 1200° F, lower than typical waste-
combustor temperatures. Molten aluminum dogs air-entry holes in the grate, causing
uneven burning and lower efficiency.
105
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Figure 3-31. Mass bum combustor.7
Another problem is that municipal waste combustion byproducts may be more
hazardous that coal-burning byproducts. For example, dead batteries in the waste
stream are the principal source of heavy metals in the combustion-gas stream.
Button-type batteries in watches and calculators and alkaline, zinc, nickel, and
cadmium batteries also contribute to heavy-metal content in the discharge. These
metals carry over to fly ash and bottom ash that must be disposed in a landfill.
MWCs generate a large amount of ash. If these metal-containing ashes are
disposed into a landfill along with decomposing waste, weak acids can leach out the
metals. Environmental concerns have been raised concerning both solid residues and
106
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pollutants emitted to the air from MWCs. In particular, concern was raised in
Congress about the presence of chlorinated dibenzo-p-dioxins (ODD) and chlorinated
dibenzofurans (CDF) in emissions to the air and solid residues.6
Air pollutants of interest emitted from MWCs include metals, acid gases
(primarily HCI), organics (including COO and CDF), and, in some localities, NOX as
well. Options for control include combustion optimization to minimize organic
emissions; scrubbing for acid gas control; flue gas cooling for condensation of metals
and organics; high efficiency particulate matter collection; and NOX control where
necessary.
3.4.1 Types of Equipment
Nearly all municipal solid waste (MSW) incinerators in use are grate-fired
systems. There are several rotary kiln designs in operation and there has been limited
operating experience with FBCs burning RDF. The majority of new systems currently
being constructed or recently installed have waterwall construction with other standard
boiler components. Many of the components discussed in the stoker designs of coal-
fired boilers are applicable to the MSW incinerator design.
The components used in the MSW incinerator may be similar or even identical
but many of the design parameters are quite different. First, the heat release rates in
MSW incinerators are much lower than in comparable coal-fired units. The grate heat
release rates are typically 200,000 to 350,000 Btu/h per ft2 of grate area. This is
required in part by the nature of the waste which has a low heat content and has the
potential for low ash fusion temperatures. The grate heat release rate also depends
on the grate type. Second, the volume associated with the furnace zone is much
larger than that associated with coal combustion. The composition of MSW is typically
very wet and contains a substantial fraction of volatile matter. The lower combustion
temperatures require the furnace volume to be larger to provide the time for
combustion to be completed. The furnace heat release rate is typically 13,000 to
25,000 Btu/h per ft3. Finally, the gas velocity through the heat transfer zones of the
107
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boiler are typically lower because the fly ash tends to be very abrasive and "glassy*.
High gas velocities tend to cause excessive abrasion of the tube surfaces and may
cause thinning of the tubes.
The use of underfire and overfire air in MSW incinerators is similar to that for
coal-fired boilers. Temperature monitoring equipment may be installed above the
overfire air ports to help achieve the desired combustion gas temperature. In most
typical application, this temperature is approximately 1500° to 1600 °F. The ratio of
underfire and overfire air is typically evenly divided (50/50 percent). Short term
temperature control is achieved by varying the overfire/underfire air ratio. The
introduction of underfire air may be zoned. A typical arrangement is to divide the
grate area into four equal zones. The MSW proceeds from the first zone where it
introduced into the furnace and exits after the fourth zone. The fuel entering the first
zone enters the furnace under a refractory lined arch. No underfire air is provided and
radiant heat from the combustion zone heats, dries, and begins to volatilize from the
fuel bed. As the gas passes up through the overfire air ports, it is ignited. The MSW
continues to volatilize and the heat from the furnace ignites the fuel bed. When the
MSW passes into the second and third grate zones the fuel bed begins to bum
vigorously with the addition of underfire air as the remaining volatiles are driven off.
The last zone has a limited supply of underfire air to complete carbon bum out on the
grate and the remaining material is discharged from the grate into an ash disposal
system.
The operating requirements of MSW incinerators to provide steam are different
from those of other fossil fuel-fired boilers. The corrosive potential of the gases from
such elements as chlorine require that oxidizing conditions are maintained throughout
the boiler. Excess air levels to provide complete combustion and reduce the
probability of localized reducing zones in the furnace require the excess air to be
approximately 80 to 100 percent of theoretical requirements. The loss of efficiency
that occurs because of the high excess air levels is usually offset by the reduction of
corrosion related failures and maintenance that would be required if lower excess air
levels were used.
108
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Several steps can be taken to improve or maintain combustion efficiency. The
most important is to reduce the fluctuation in fuel characteristics to the extent possible.
This includes removal of large, noncombustible materials and the mixing of the waste
as it enters the facility and is stored prior to combustion. Large, noncombustible items
tend to take up space and may cause underfire air to bypass the fuel bed through the
path of least resistance. Consistent fuel bed properties and depth are essential to
proper operation. In addition, combustion air may be preheated to improve the
combustion efficiency and the adiabatic flame temperature. Although preheating the
combustion air supplied to the underfire air supply would improve the rate of drying
and volatilization of material from the fuel bed, it generally would cause problems with
clinker formation and possibly cause damage to the grates due to high heat release
rates on the grates. Combustion air preheating can be used but it is usually used only
on the overfire air to improve combustion efficiency while the underfire air is usually at
ambient temperature.
The combustion gas exit temperature must also be maintained at a level
sufficiently high to minimize corrosion of the boiler heat transfer surfaces and the
ductwork and other equipment that follows the boiler. The principal problem
compounds are HCI and HP emissions whose acid dewpoint can be very high. This
loss of heat due to potential corrosion problems is again one of the tradeoffs
associated with burning MSW.
Emissions of particulate matter have historically been controlled using ESPs.
Fabric filters had been used infrequently due to concerns over poor combustion,
carbon carryover, sticky particulate, and fires. In recent years, with the additional
requirements for acid gas scrubbing, spray dryers equipped with fabric filters have
become the control method of choice. The spray dryer allows the reaction between
lime and the acid gases to control their emissions while cooling the gas stream. The
presence of the reacted lime in the gas stream as a dry particulate also tends to
protect the bags from the effects of sticky particulate matter as long as there is no
water droplet carryover from the spray dryer.
109
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3.5 Combustion In Cupolas and Blast Furnaces
Combustion in cupolas and blast furnaces is different than combustion in
conventional furnaces. Because of these differences, the methods used for
conventional combustion analysis cannot be applied. The following sections describes
the physical and thermal operation of cupola systems.
3.5.1 Physical Arrangement
A cupola is a vertical cylindrical shaft in which a product is heated and melted
using a solid fuel charged with the product. Cupola and/or blast furnaces are used to
melt a number of ores and slags including iron ore, secondary lead, secondary
copper, grey iron, ductile iron, and mineral wool. All these processes have the
common need to melt the ore and reduce the metal oxides to elemental forms.
Rgure 3-32 is a cross section of a typical gray iron cupola. Scrap iron, coke,
and fluxing agents are charged at the top and the material moves downward through
the shaft as fuel is consumed and molten materials are discharged from the bottom.
As ban be seen fuel is burned using forced air (heat or unheated) in the lower
section of the shaft. The air ports are referred to as tuyeres and can be located at
multiple levels (split air) and may be introduced at preselected angles. The number
and diameter of the tuyeres are determined by the cupola diameter, melt rate, use of
oxygen enrichment, use of heat combustion air, and material properties.
Flux (silica, limestone, etc.) is added to the charge to provide fluidity to the
impurities that are separated from the ores of scrap during melting. Flux acts as a pH
control in the slag, which floats on top of the melt. Slags are defined as basic or
acidic depending on the relative ratio of (CaO + MgO)/(SiO2 + M2OJ. When this
ratio exceeds one, the slag is basic. Slag chemistry is controlled to provide proper
metal/slag separation and slag fluidity for tapping from the cupola.
Rue gases are discharged at the top of the shaft and preheated charge material
is tapped as the charge moves downward through the shaft The charge dome
(chute) is sealed by the charge and the trap doors to reduce air inleakage and
maintain cupola draft.
110
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WATCMOOtB
NOTRVMIM
Figure 3-32. Basic design of water-cooled cupola.8
111
-------
3.5.2 Combustion Theory
Solid high carbon fuels (coke) are the primary fuel used in cupolas. Although
some experiments have been used in burning liquid and gaseous fuels, they have not
been highly successful. Solid fuels provide high adiabatic flame temperatures that are
required for melting and do not require a cavity (opening) to complete oxidation.
Because of the size of solid fuel used, voids between lumps provide area for
combustion and flue gas/oxygen exchange. Also the solid fuels provide sufficient
structural integrity to support the charge weight above the burning zone in the shaft.
The cupola is divided into three well defined zones; the well, oxidation
(combustion), and reducing zone (Figure 3-33). Both physical and chemical reactions
occur in each zone that affect the final flue gas composition and cupola thermal
efficiency.
The well zone is the area that receives the molten slag and metal. Coke in this
area is surrounded by melt and floats on top of the melt. Slag and metal separate,
which form two distinct layers below the tuyeres. Reactions in this zone are reducing
and the conditions in this zone control the amounts of carbon, sulfur, and other metal
species in both the melt and the slag.
The oxidizing or combustion zone is the level in the cupola in which air injected
through the tuyeres reacts with coke to form CO and CO2. Water in the combustion
air is reduced to hydrogen in this zone. Combustion temperatures in this zone are
between 1700° and 2100° C. The oxidation zone is defined as the area in which
oxygen in the gases is greater than 2 percent or the area in which CO2 is a maximum.
The function of the combustion zone is to provide heat to superheat molten metal (i.e.,
melting zone is above oxidation and reducing zone), and provide hot gases to melt
and preheat the charge. The oxidizing zone is the area in which thermal energy is
released in the cupola
The reducing zone in the cupola is above the oxidizing zone and below the
melting zone. In this zone the coke is heated to iridescence by the flue gas from the
112
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oxidation
ion*
, *F (*C)
zono*
Figure 3-33. Location of cupola zones.6
113
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combustion zone. The CO2 is reduced in the lower section of this zone by contact
with the coke. The reaction is endothermic and the reaction consumes a portion of
the coke and reduces the combustion gas temperature. The final relative ratio of CO2
and CO in the flue gases exiting the system is varied and depends on coke reactivity,
size, preheated combustion air temperature, and whether oxygen enrichment is used.
Table 3-9 summarizes the combustion variables that may be expected for
various percentages of CO2 found in cupola flue gases at oxygen free conditions.
This table is applicable only when oxygen enrichment is not used. A typical cupola
may operate at a thermal efficiency of 65 percent, which yields a CO content of 8.3
percent in the flue gas.
TABLE 3-9. AIR REQUIREMENTS (STP) FOR COMBUSTION8
BnuWltOMO
VolUMM
CO, CO N,
0.0 34.7 65.3
1.0 33.1 65.9
2.0 31.4 66.6
3.0 29.8 67.2
4.0 28.1 67.9
5.0 26.5 66.5
6.0 24.8 69.2
7.0 23.2 69.6
8.0 21.5 70.S
9.0 19.9 71.1
10.0 18.2 71.6
11.0 16.5 72.5
12.0 14.9 73.1
13.0 13.2 73.8
14.0 11.6 74.4
15.0 9.9 75.1
16.0 8.3 75.7
17.0 6.6 76.4
18.0 5.0 77.0
19.0 3.3 77.7
20.0 1.7 78.3
21.0 0.0 79.0
Ca*mi
CO, CO
0.000 1.000
0.029 0.971
0.060 0.940
0.092 0.908
0.12S 0.875
0.150 0.841
0.1 95 0.805
0.232 0.768
0271 0.729
0.312 0.688
0.355 0.645
0.399 0.601
0.446 0.554
0.495 0.505
0.547 0.453
0.601 0.399
0.659 0.341
0.719 0.281
0.783 0.217
0.851 0.149
0.933 0.078
1.000 0.000
fUdo
0.00
2.94
5.99
9.16
12.46
15.89
19.48
2321
27.11
31.19
35.46
39.93
44.62
49.54
64.70
60.14
65.88
71.92
78.32
85.08
92.25
100.00
MVkaol
o, N. row
0.93 3.51 4.44
0.96 3.61 4.57
0.99 3.72 4.71
1.02 8.83 4.85
1.05 3.96 5.00
1.08 4.07 S.15
1.11 4.19 5.31
1.15 4.32 5.47
1.19 4.46 5.65
122 4.60 5.83
126 4.75 6.02
1.31 4.91 622
1.35 5.08 6.42
1.40 525 6.64
1.44 5.43 6.87
1.49 S.62 7.11
1.S5 5.82 7.37
1.60 6.03 7.64
1.68 6.26 7.92
1.73 6.50 622
1.79 6.75 8.54
1.86 7.01 8.88
OWMftMUMtf
CO, CO N, ToW
0.00 .67 3.57 5.38
0.05 .61 3.61 5.48
0.11 .76 3.72 5.59
0.17 .70 3.83 5.70
023 .63 3.95 5.81
0.30 .57 4.07 5.93
0.36 .50 4.19 6.06
0.43 .43 4.32 6.19
0.51 .36 4.46 6.33
0.58 .28 4.60 6.47
0.66 .21 4.75 6.62
0.75 .12 4.91 6.76
0.63 1.03 5.08 6.94
0.92 0.94 5.25 7.12
1.02 0.85 5.43 7.30
1.12 0.74 5.62 7.49
123 0.64 S.82 7.69
1.34 0.52 6.03 7.90
1.46 0.40 6.26 8.13
1.59 0.28 6.50 8.36
1.72 0.14 6.75 8.62
1.87 0.00 7.01 8.88
MotfDontopod
KteVkgof
CO, CO ToW
0.00 2.20 220
0.23 2.14 2.37
0.47 2.07 2.54
0.72 2.00 2.72
0.98 1.93 2.90
1.25 1.85 3.10
1.53 1.77 3.30
1.82 1.69 3.51
2.12 1.60 3.73
2.44 1.51 3.96
2.78 1.42 420
3.13 1.32 4.45
3.50 122 4.71
3.68 1.11 4.99
4.29 1.00 528
4.71 0.68 5.59
5.16 0.75 5.91
5.64 0.62 625
6.14 0.48 6.61
6.67 0.33 7.00
7.23 0.17 7.40
7.83 0.00 7.83
Thorn*]
COMD.IIL
(%)
28.1
30.2
32.4
34.7
37.0
39.5
42.1
44.8
47.6
50.5
53.6
56.8
602
63.7
67.4
71.3
75.4
79.8
64.4
89.3
94.4
100.0
KOVkaofCokt
CO, CO ToW
0.00 2.43 2.43
0.24 2,36 2.60
0.48 2.29 2.77
0.74 2.21 2.95
0.01 2.13 3.14
1.28 2.06 3.33
1.57 1.96 3.53
1.87 1.87 3.74
2.19 1.77 3.96
2.52 1.68 4.19
2.86 1.57 4.43
3.22 1.46 4.68
3.60 1.35 4.95
4.00 123 523
4.41 1.10 5.52
4.85 0.97 5.82
5.32 0.63 6.15
5.80 0.68 6.49
6.32 0.53 6.85
6.87 0.36 723
7.45 0.19 7.63
8.06 0.00 8.06
IIMNM!
CM*, en.
r*>
30.2
32.2
34.4
36.6
38.9
41.3
43.6
46.4
49.1
51.9
54.9
58.0
61.3
64.6
68.4
72.2
76.2
80.4
84.9
89.6
94.6
100.0
Conversion Factors:
IMVkg-16ft.»/Ib.
IKCal/kg - 1800 BTUJIb.
Combustion Efficiency Ratio - (%C
-------
3.6 References
1. Babcock & Wilcox. Steam/Its Generation and Use. New York, 1978.
2. Savoie, M. J., G. Maples, and D. F. Dyer. U.S. Air Force Central Heating Plant
Tuneup Workshop, Volume IV: Fuel Oil Qualify. U.S. ACERL Special Report E-
90/03, Vol. IV, January 1990.
3. Savoie, M. J., G. Maples, and D. F. Dyer. U.S. Air Force Central Heating Plant
Tuneup Workshop, Volume III: Description of Burners. U.S. ACERL Special
Report E-90/03, Vol. Ill, January 1990.
4. Power From Coal: Part II, Coal Combustion. Power, March 1974.
5. Special Report: Fluidized-Bed Boiler Achieve Commercial Status Worldwide,
Schueugen, Bob. Power, February 1985.
6. Radian Corporation Municipal Waste Combustion Study: Report to Congress.
EPA/530-5W-87-021A. June 1987.
7. Bretz, E. Energy From Wastes. Power, March 1989.
8. American Foundrymens Society. Cupola Handbook, 5th ed. Des Plaines,
Illinois, 1984.
115
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116
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SECTION 4
BOILER EQUIPMENT AND STEAM CYCLES
4.1 Introduction
As stated in the introduction to this manual, the combustion process has its
widest application in the production of steam for a wide variety of processes. These
range from small boilers to produce low pressure steam for heating, ventilation, and air
conditioning (HVAC) systems, to steam energy for process heat, to large utility boilers
driving 1200-1300 MW turbine/generators with high pressure steam for electrical
power generation. There are hybrid systems that are cogeneration units designed to
produce electrical power and steam heat for other purposes. Another example of a
hybrid system is the gas turbine/generator with a heat recovery steam generator
(HRSG) system to recover the heat not recoverable by the turbine.
The problem for many people new to the combustion process and specifically
to the steam generation cycle is the development of an understanding of the
terminology and the equipment associated with steam generation. The purpose of this
chapter is to provide an explanation of the basic equipment and concepts involved in
*
the production of steam. This goes beyond the basic combustion process and
involves heat transfer concepts and fluid flow characteristics around the boiler. It is
not, however, all inclusive of all possible equipment configurations or steam cycles.
The major components should be inclusive of many designs. Those familiar with the
steam generation process may wish to proceed to other portions of this manual for
information that may be more pertinent to their needs.
4.2 Heat Transfer Concepts
The combustion process releases heat to be captured for some other useful
purpose. In the combustion zone where the fuel and air are being introduced and the
combustion sustained, the release of heat and the temperature that theoretically could
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be attained in the flame are described by the adiabatic flame temperature (discussed
in Section 2). The generation of steam, however, from liquid water requires this heat
released by combustion to be transferred to the water and heat it sufficiently to
produce steam. Since heat will only flow from an area of higher temperature to an
area of lower temperature, the heat will flow from the combustion gas to the water or
steam only as long as the temperature of the combustion gas is higher than the
temperature of the water or steam.
The forms of heat flow can be divided into three categories: conduction,
convection and radiation. The heat transfer by conduction requires direct contact
between a warm surface and a cooler one. An example of the conduction process is
the boiler tubes themselves. Heat is transferred from the hot combustion gases
through the tube wall to the cooler water or steam flowing on the inside of the tube.
Heat transfer by convection occurs on both sides of the tubes due to density changes
and mixing of the fluids. Heat transfer by radiation requires no direct contact between
mediums and occurs primarily in the zone of fuel combustion.
During actual operation all three heat transfer mechanisms are at work in the
boiler. The design and operation of the boiler will dictate which heat transfer
mechanism dominates and where in the boiler. In general, most boilers can be
divided into zones where radiation heat transfer predominates and zones where
convection is the dominant heat transfer mechanism. The area around the
combustion zone where the flame is generated is dominated by radiant heat transfer.
The temperature difference between the flame and the boiler water is greatest at this
point enhancing the radiant transfer of energy. The amount of radiant energy
transferred in this zone can be significantly influenced by the quantity of excess air
introduced to the combustion zone. Lower excess air means higher flame
temperatures, provided complete combustion is occurring. Increased levels of excess
air will result in lower flame temperatures, less radiant transfer and more gas volume to
pass out of the boiler. As the heat from combustion is transferred to the boiler water
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the temperature of the gas decreases and reduces the amount of radiation heat
transfer that occurs. The heat exchange eventually is dominated by convection in the
lower temperature zones of the boiler. The combustion gases must pass between
boiler tubes to transfer the heat from the combustion gas to the boiler water/steam.
As the combustion gases pass through the boiler transferring heat to the boiler tubes
the gas temperature gradually decreases until the gas exits the boiler and has no
other surfaces to transfer useful heat to.
4.3 Steam Characteristics
While the gas is losing heat and decreasing in temperature, the boiler feedwater
is generally flowing in an opposite direction (counterflow) to the combustion gases.
The boiler feedwater gains heat and increases in temperature until the boiling
temperature is reached. At this point no further temperature increase is immediately
possible because the energy being supplied to the feedwater is used to change from
the liquid to the gaseous state. Most of the heat released by the combustion process
goes toward the phase change of water. At standard atmospheric conditions the
boiling temperature of water is 212 °F. The temperature of water just at the boiling
point (saturated water) and steam at the boiling point (saturated steam) is the same.
The energy content (enthalpy) of the two states, however, is very different. The
enthalpy of the saturated liquid is 180.17 Btu/lb. The enthalpy of the saturated steam
at the same temperature and pressure is 1150.5 Btu/lb, or a difference of 970.3
Btu/lb. Once the liquid has changed to the vapor phase it may continue to accept
available heat and the steam will increase in temperature. This increase in
temperature and enthalpy above the saturated steam conditions is called superheat.
Superheat may be added to provide additional energy for useful work or to prevent
condensation of saturated steam back to liquid phase due to heat loss. In a turbine
application, superheat is necessary for both reasons. (As a reference note, air is
composed of superheated gas compounds as the mixture of nitrogen and oxygen that
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we breathe is well above the saturation vaporization temperatures of -320 °F and -297
°F, respectively.) The enthalpy of steam at different pressure and temperature
conditions may be found in most engineering reference books that include the ASME
Steam Tables. Some interpolation may be necessary to obtain the enthalpy value
between the published points. Equations suitable for computer application are also
available but are beyond the scope of this manual.
All boilers operate at a pressure above atmospheric pressure because the
boiling of water occurs within a closed system and the evaporation and expansion of
the water into steam will cause the pressure to increase. An increase in pressure also
raises the boiling temperature above 212 °F. The elevation in operating pressure
above atmospheric pressure is used to move steam through pipes to the point of use.
Small boilers used for only HVAC systems may operate at a pressure of 50-75 pounds
per square inch gauge (psig) and a superheat of only 25-50 °F. Most industrial
boilers, however, operate above 125 psig. In industrial applications where the steam
is used for process heat only, operating steam pressures are typically less than 350
psig with a superheat of 100 °F or less. The operating pressures and superheat are
substantially higher when the steam is used to turn a turbine/generator for generation
of electrical power. For industrial boilers where the steam is first used to generate
t
electrical power before being used to provide process heat (cogeneration), the
operating pressures are typically between 600 and 1600 psig. Boilers operated to
produce steam used only for electrical power generation are typically designed to
operate from a range of 2000 to 3000 psig. There are also boilers designed to
operate in the range of 3500 to 4000 psig. These boilers are known as supercritical
boilers because they operate at conditions above the critical point of water (3208.2
psia and 705.47 °F). The critical temperature is the temperature where no amount of
pressure can be applied to change the gaseous form of a substance back to liquid
phase. There is no distinct phase change from liquid to gas in supercritical boilers
and hence they have a somewhat different design from a boiler operating below the
critical point.
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Most boilers are designed to operate within a distinct range of temperature and
pressure. The boiler components are rated to a specified pressure and temperature
with a margin of safety to minimize the damage potential of catastrophic failure if the
boiler is operated above its design limits for a short period of time. The process of
boiler design must optimize a number of design limitations including rate of heat . -
transfer through boiler tubes. This is one reason why the highest steam operating
temperatures observed will seldom exceed 1000 °F. Higher operating pressures,
however, do provide some thermal efficiency advantages over lower pressures
particularly for processes using turbine/generators. The higher operating pressure
provides the opportunity to perform more pressure-volume related work in the turbine.
In addition, the higher operating pressure results in a lower thermal energy
requirement to raise the steam temperature to the design level. This results in a lower
fuel requirement (assuming no other changes in boiler operation).
4.4 Boiler Components
Thus far the combustion characteristics, fuel characteristics, and boiler types
have been discussed with little or no mention of the boiler components. The design of
the boiler components are important to the overall boiler performance and its thermal
efficiency. The major components that are seen on many boiler designs are discussed
here (combustion systems and types were discussed in the previous chapter). There
may be individual design differences from those discussed here. It is assumed that
the steam cycle used is a dosed cycle (i. e., the steam produced in the boiler is
•used" and condensed and returned to the boiler to begin the cycle again.
4.4.1 Feedwater Pump
The feedwater pump returns the water to the boiler and pressurizes the water to
a pressure approximately 100 to 200 psig above the steam outlet temperature. The
feedwater may arrive at the boiler at a somewhat elevated temperature and pressure
due to feedwater heating with steam. When evaluating thermal efficiency by
conducting a heat and material balance around the boiler, care must be taken to
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define feedwater conditions in the determination of net enthalpy increase. There are
so many variations in boiler design that site specific evaluation is necessary.
4.4.2 Economizer
An economizer may be used on a boiler to pass the pressurized water through
a heat exchange surface to extract heat from the combustion gas stream. The
economizer is sometimes termed a "water preheater". The heat transfer from the
combustion gas to the economizer is usually dominated by convection. If present, the
economizer is usually the first piece of heat transfer equipment associated with the
boiler that the feedwater passes through. The economizer generally elevates the
water temperature to within 100 °F of the boiling temperature. The operating
temperature and gas temperatures entering the economizer are strictly a function of
the operating conditions of the boiler.
4.4.3 Boiler Tubes
The boiler may be equipped with a separate boiler bank as is illustrated in
Figure 4-1. In this case, the preheated water enters the steam drum and the liquid is
distributed from the drum into the boiler tube bank that is in the gas passage at the
top of the boiler. In addition, water is also distributed from both the upper and lower
drums into the distributor system for the furnace zone (water wall) boiler tubes (not
shown). The purpose of these sections is to provide the heat transfer area to convert
liquid water into steam. The water/steam mixture rises in the tubes either by natural4
convection or through forced circulation back to the steam drum. The heat transfer
mechanism in the furnace zone is primarily radiant transfer while the boiler bank may
be a mixture of both radiant and convective heat transfer. The exit temperature from
the boiler section depends upon the operating pressure of the boiler and the
temperature of the steam. Some boiler designs incorporate only a single drum and no
boiler tube bank in the convective heat transfer gas passages. These boilers are
designed to have all the phase change from liquid to gas occur in the furnace zone
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.
stack
Source: Babcock and Wilooz. 1978.
Water wall
tubes
Figure 4-1. Example of water tube boiler showing heat transfer sections.1
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tubes. These boilers are sometimes known as "radiant" boilers because all the steam
generation occurs in the radiant heat transfer zone of the furnace. The radiant design
is usually seen in the larger industrial boilers and electric utility applications (Rgure
4-2).
4.4.4 Steam Drum
The steam drum serves several purposes. First, it contains equipment in the
drum internals to separate saturated steam from water that is carried out of the boiler
tubes. The internals may include cyclone and/or mesh type eliminators to separate
the water droplets from the steam (Figure 4-3). Second, the steam drum provides for
short-term surge capacity to accommodate variations in steam demand. This is
accomplished by controlling water level in the steam drum. If, for example, there was
a sudden increase in the steam demand the water level in the steam drum would rise
to maintain steam pressure. The boiler controls would also react to increase the fuel
feedrate to the boiler to increase the steam production and restore the drum level
back to its set point. Finally, the steam drum provides control over the boiler
operating pressure particularly during transient periods of increased or decreased
steam demand.
As mentioned in the section on boiler tubes, there are different boiler designs
that may incorporate one, two, or more drums. The upper drum(s) are always used
to separate steam from water. The lower drum(s) are usually known as "mud drums"
and 'are full of heated water. These mud drums provide another distribution point for
boiler water and a settling point for solids that may be carried into the boiler. Today's
water treatment, however, has substantially reduced the quantity of "mud" produced
and recovered from these drums. The higher operating pressures characteristic of
today's boilers as well as turbine applications require water quality with very low solids
content.
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Penthouse
Pendant
Reheater
Primary
Superheater
Economfzar
Steam Drum
Secondary
Superheater
Steam Coil
Air Heater
Forad Drift Fan
Figure 4-2. Radiant boiler for pulverized coal."
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Chevron blades
Cyclone separator
Risen
Dow
Figure 4-3. Detail of a steam drum.1
4.4.5 Superheaters
As discussed previously, superheat is the additional energy that is added to the
steam after the phase change from the liquid to the gaseous state. Superheat is
important to the operation of any boiler whose steam is used to operate a steam
turbine. The work done by steam in a turbine results in the loss of energy from the
steam to the turbine. If saturated steam were used, this loss in energy would result in
the condensation of saturated steam into water droplets. The quantity of
condensation that may be tolerated in a turbine is limited by the amount of acceptable
wear and damage to the turbine blades. In practical applications, this condensation
limit is around 10 percent. The turbine, however, is able to convert much of the
energy available from superheat directly into work without condensing moisture. While
the proportion of energy input recoverable from saturated steam is limited, the energy
available to the turbine from superheat is essentially all recoverable. In addition, the
amount of heat input required to develop steam superheat is small compared to the
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heat requirement to raise the water temperature from feedwater conditions to
saturated steam conditions. Thus, the addition of superheat provides an economical
efficiency increase for turbine operation. Electric utilities and large industrial boilers
with turbine/generators may be equipped with more than one superheater for efficient
heat recovery from the boiler combustion gases. For non-turbine applications
superheat may be added to provide temperature control for process operation or to
prevent or minimize the condensation potential as steam is transported to the point of
use.
Superheaters may be located in the boiler so that the heat transfer is by
radiation, convection, or both. There is a limit to the amount of superheat that can be
added to steam. This is more a function of tube metallurgy and economics than a
limitation of the steam itself. In general, steam temperatures will be limited to 1000 °F
and in a few cases up to 1050 °F. Above this temperature, heat transfer rates are
limited by the tube metallurgy of high temperature and pressure operation.
4.4.6 Reheaters
Reheaters are a form of superheater that are used primarily in electric utility
boilers. Their operating principle is the same as the superheater, i. e., to add energy
to steam above the saturation temperature. Reheaters are used to extract energy
from the combustion gases to provide additional superheat to the steam after it has
passed through the high pressure turbine stages. Generally only a single reheat is
used as part of the steam cycle although there are a few "double reheat* boilers in
existence. The temperature limits that applied to the steam exiting the superheater
also apply to the reheater for the same reasons. After leaving the reheater the steam
does not return to the boiler until it has been condensed and is returned as boiler
feedwater.
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4.4.7 Air preheater
As the name implies, the air preheaters transfer heat from the combustion gas
to the combustion air to improve combustion and thermal efficiency. The increase in
air temperature means that less energy is required to raise combustion air (and
combustion products) temperature and that a higher adiabatic flame temperature is
possible. In small natural gas and oil fired boilers there may be an economic trade off
between using an economizer or an air heater as the last heat exchange surface. For
larger boilers the presence of both an air preheater and Economizer is necessary for
fuel efficiency reasons. An air heater is essential to the operation of any pulverized
coal fired boiler because the heated air is necessary to dry the coal in the pulverizer
while it is being ground. The air preheater is also necessary in many grate fired solid
fuel boilers for the drying effects on wet fuel and to provide higher combustion
temperatures for more complete combustion.
Air preheaters can generally be divided into two types: tubular and regenerative.
Tubular air heaters are heat exchangers where combustion air flows around the
outside of the tubes while combustion gases flow through the insides of the tubes.
The heat transfer is through the tube walls and there are a variety of ways the
combustion air may flow through the heat exchanger. Tubular air preheaters are
generally applied to smaller boilers and to natural gas and oil-fired boilers where the
combustion gas is relatively clean. The regenerative air heater is generally applied to
larger boilers. The most common regenerative design uses a rotating plate assembly
that alternately passes through the combustion gas stream and then through the
combustion air stream. As the heater elements (sometimes called "baskets") come
into contact with the combustion gases they are heated, thus lowering the combustion
gas temperature. The elements then rotate into contact with the combustion air where
they give up their heat and the cycle is repeated. An example of a regenerative rotary
air preheater is shown in Rgure 4-4. An important maintenance issue with this design
is the seal between the air and the combustion gas sectors. Air leakage can decrease
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Plate
Groups
\
\ /
Plate
Groups
/ \
Gastn
Air Out
Figure 4-4. Illustration of a rotary regenerative air heater.2
thermal efficiency and increase gas handling requirements. In both designs, while it is
desirable to extract as much useful heat as possible, care must be taken that
temperatures are not taken so low that acid dewpoint temperatures are reached. The
resulting corrosion of the air heater and other downstream components may prove to
be more expensive to maintain than the cost of a slight efficiency loss due to
somewhat higher operating temperatures.
4.5 Steam Cycle
Thus far, the combustion principles, combustion equipment types, and boiler
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components have been discussed with occasional references to the uses of steam.
Since many combustion sources are associated with the production of steam, it is
appropriate to discuss steam cycles.
Steam production can be divide into two general uses. One use is for the heat
content of the steam including the energy associated with the phase change from
liquid to gas. When water is converted to steam it absorbs heat as is measured by its
enthalpy. When the steam condenses, the energy contained by the steam is given up
as it condenses. As discussed previously in this section, the heat of vaporization is
substantial and the ability to control a wide range of temperatures at which this energy
release occurs, by controlling pressure, is a substantial advantage for steam use in
industrial processes. The other use of steam is for the work that can be done by the
steam pressure and volume using mechanical devices such as a turbine/generator.
These devices rely upon the energy contained in the superheat and the steam
pressure to convert thermal energy into mechanical energy. Much of the thermal
energy required for the phase change from liquid to gas, however, is wasted by these
processes. A third category uses both the work potential of superheated steam and
the energy available due to phase change to provide the most efficient use of the
combustion energy. These are the cogenerators that generate electrical power with
turbine generators and then provide the energy remaining with the steam leaving the
turbine as a heating medium to recover the enthalpy available from the phase change
from steam to water.
The typical steam cycle is a closed cycle. This means that the steam, or at least
a substantial portion of it, is recovered as a liquid to be recycled back to the boiler.
This reduces the make-up requirements for boiler water and provides an economical
water cycle. Water treatment requirements become quite rigid as steam pressures
and temperatures being supplied to a turbine increase. The cost of boiler water
treatment can be reduced if boiler water losses are kept to a minimum.
The steam cycle that is used in electrical power production is the Rankine cycle.
An example of the Rankine cycle is illustrated in Figure 4-5. Starting at point a, liquid
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672
560
Open (NoivCondensing) Cycle 100F Feed
Entropy, s
I
.560
Closed (Condensing] Cycle
100F, 0.95 psia Condensing Conditions
Entropy,
Figure 4-5. Ranklne cycle.2
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water is compressed to the operating pressure at point b. This compression is
exaggerated in the figure for clarity. The actual increase in enthalpy from compression
of liquid water is quite small. From point b to c, heat added to the compressed liquid
increases the temperature until the boiling temperature is reached (water passing
through the economizer and then through either the boiler tube bank or the water
walls of the furnace). At this point the temperature rise is halted and the energy is
absorbed to change from compressed water to steam. The saturated liquid is
separated from the saturated steam at point c. The saturated steam then enters the
superheaters) to increase the energy content of the steam prior to discharge into a
turbine (point d). Steam expands in the turbine converting the enthalpy contained in
the steam to work turning the shaft This expansion causes a decrease in enthalpy
until the saturation vapor point is reached and some of the steam begins to condense
to form liquid droplets (point d to point e). The steam is discharged from the turbine
and into a condenser to convert the saturated steam back to water. The heat given
up by the condensing steam is absorbed by cooling water circulating through the
condenser and rejected to the environment through cooling towers, cooling ponds, or
back into a water body. The condensed water is recycled back to the boiler
feedpump to be repressurized (point a).
The efficiency of the Rankine cycle can be increased in several ways. First,
extraction of the steam from the turbine to be reheated and returned to the turbine will
increase the energy extracted from the combustion process and converted to useful
energy by the turbine. This is illustrated in Figure 4-6 where the second temperature
peak represents the steam reheated and returned to the turbine. Another method of
increase the efficiency is to lower the temperature at which the steam will condense in
the turbine. This is accomplished by placing the condenser and last stage of the
turbine under a vacuum using vacuum pumps or ejectors. The lowest condensation
temperature is limited both by the vacuum that can be achieved and by the
temperature of the cooling water available. The steam cycle can also be made more
efficient by extracting a quantity of steam from the turbine in using it to preheat the
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1000
1.5 1.72
Figure 4-6. Double reheat cycle.
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water returning from the condenser to the boiler (feedwater heaters, including the
deaerator). This recovers a portion of the heat that would otherwise be lost to the
cooling water rather than using the combustion gases to heat the water from the
condenser exit temperature to the eventual superheated steam temperature. These
practices are common to electric utility generating systems. Industrial operations may
use only feedwater heaters and reheat to improve the Rankine cycle efficiency
because the steam may be used for other purposes after it passes through the
turbine. Such operations use noncondensing turbines (also known as backpressure
turbines).
These design and operation practices improve the Rankine cycle efficiency but
they still do not eliminate the loss in energy that occurs because of the limitation in
turbine operation. In the most efficient operations only about 40 percent of the energy
that is transferred to the steam can be used and recovered by the turbine generator.
The remaining 60 percent is lost as rejected heat in the cooling water. Cogeneration
improves this situation somewhat. The use of a noncondensing turbine, or the
extraction of a significant proportion of the steam at a temperature and pressure that
is well above atmospheric pressure (e.g., 250 psig), means that a significant portion of
the enthalpy that might otherwise be recovered for electrical generation is not used in
the turbine. This loss is more than offset by the use of steam for its heat content
when the heat from condensation can be used. This is one reason for the recent
increase in the construction and use of Degeneration facilities. Assuming the demand
for new electrical generating capacity exists or can be used by the industrial facility,
the use of Degeneration to supply both electrical demand and steam demand results in
a more efficient use if fuel than having two separate facilities to separately and
independently supply steam and electrical power. The economics of cogeneration are
not automatically favorable and require considerable planning and design for different
operating contingencies, but it is likely that the construction of new cogeneration
facilities will continue in the foreseeable future.
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4.6 References
1. Beachler, D.S. U.S. Environmental Protection Agency, Air Pollution Training
Institute (APT)). APT! Course 428A: Introduction to Boiler Operation, Self-
Instructional Guidebook. 1984.
2. Babcock and Wilcox. Steam/Its Generation and Use. New York, 1978.
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SECTION 5
INSPECTION PROCEDURES FOR COMBUSTION PROCESSES
The purpose of this section is to demonstrate practical methodologies for
determining the compliance status of combustion sources with applicable regulatory
limits and/or permit conditions. Many times, compliance with mass emission limits
may be verified in the field through continuous emission monitor (OEM) data. In cases
were OEMs are not required or are inoperable, and for mass emission limits of
paniculate matter, these inspection methodologies can be used to make engineering
judgments as to the probable compliance status of the source. That is, these
methodologies are used to evaluate the operating conditions of the combustion source
as they relate to established stack test conditions (baseline) or to good engineering
principles. By determining operating conditions during an inspection, an estimate of
flue gas volume and composition can be made and their effects on the operation of
any associated air pollution control (ARC) systems can be evaluated. From these
data, the inspector can make engineering judgments as to the likelihood of compliance
or noncompliance of the source. In addition, these data can be used to specify stack
test operating conditions for any subsequent compliance testing that may be required.
Regulatory limits and/or permit conditions that affect a source can be divided
into four main categories: 1) combustion source operating limits, 2) mass emission
limits, 3) opacity, and 4) pollution control equipment operating conditions.
Combustion source operating limits include, but are not limited to, fuel-firing
rates, input or output process rates, fuel type or constituent limits (e.g., fuel oil sulfur
content), and for boilers, maximum steam generation rates. These types of operating
limits are usually accompanied by recordkeeping and reporting requirements through
which compliance can be readily determined.
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Opacity limits are enforced by using either CEM (i.e., transmissometer) data or
by application of EPA Method 9 opacity determinations. Again, compliance with
opacity limits can be determined in a straight forward fashion by direct methods.
On the otherhand, compliance with mass emission limits (e.g., Ib/h of SO2,
ppmv NOX, lb/106 Btu paniculate matter, etc.) may or may not involve-onsite
instantaneous methods of determination. In the absence of CEM data, stack testing is
the only way to determine the true compliance status of a source with regards to mass
emission limits. By the application of sound engineering principals during a source
inspection, however, logical judgments can be made as to whether inspection
operating conditions warrant subsequent compliance testing under similar operating
conditions.
Finally, pollution control equipment operating limits defined by regulation or
source operating permit usually involve APC operating data that can be measured at
the site. Such limits may include ESP power levels, scrubber pressure drop and liquid
flow rates, and fabric filter pressure drop and cleaning cycle frequency. As important
as these operating parameters are, the flue gas volume that passes through the
control device is the single most important factor in the removal efficiency of the APC
system.
The removal efficiency of most APC systems is, to one degree or another, gas
volume dependent. Most control devices are designed to operate at maximum
«.
removal efficiency within a rather narrow range of gas volume, grain loading, excess
air, gas temperature, gas moisture, etc. Although APC system instrumentation such
as pressure drop indicators, thermocouples, and liquid flow meters will be affected by
gas volume and gas conditions, they are only indicators of proper APC operating
conditions, hi some cases, data from these equipment can be contradictory to actual
operating conditions. For example, high gas volumes in excess of venturi scrubber
design values may cause complete penetration of the gas through the water turbulent
zone in the scrubber throat (doughnut hole). In such an event, pressure drop would
actually decrease, which would falsely indicate reduced gas volume.
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Because control device efficiency is so dependent on gas volume, the inspector
should calculate the gas volume seen by the APC system and compare this estimated
gas volume to that of the control device design range. Gas volumes excessively
outside of the design range indicate potential noncompliance with the mass emission
limits. This is especially true if the baseline compliance test indicates that the average
emission rate is close to permitted limits at control device design gas volume.
The following inspection techniques will allow the inspector to determine the
compliance status of a combustion process source or help the inspector determine if a
compliance test is warranted under the operating conditions recorded during the
inspection.
5.1 Determination of Compliance With Operating Limits
Before the inspection, operating conditions of the combustion source and any
associated APC systems during the baseline or last compliance test should be
reviewed and recorded on the field inspection checklist or in the inspector's field
notebook. In addition, the applicable regulations and/or permits should be reviewed
and specific limitations-likewise transcribed.
During the inspection, raw material or finished product throughput of the source
(gal/min, tons/h etc.) should be recorded and compared with any permit or regulatory
limits as well as with previous compliance tests. The inspector should also note any
changes in process configuration since the last compliance test that might have a
significant impact on potential uncontrolled emission rates. For example, this might
include a significant increase or decrease in the solids content or in the water content
of liquid or semi-solid material processed in a direct contact dryer. Increased solids
content may increase flue gas grain loading while increased water content may
increase gas volume, decrease stack temperature, and may result in higher fuel-firing
rates to compensate for the heat required to vaporize the additional water.
Fuel-firing rates typical of previous stack tests as well as firing rates at or below
permitted limits must also be verified by the inspector. Long-term records should be
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reviewed to determine average or typical firing rates. It should be noted that the
records should also be detailed enough for the inspector to identify short-term or
instantaneous peak firing rates if permitted maximum firing rates are applicable.
Verification of fuel specifications may also be required if permitted limits have
been imposed. Typically, this involves the percent sulfur content of fuel oil. On
occasion, sulfur content may also be specified for coal as well as ash content. Ash
content may also be specified in the permit for No. 6 or residual oil. Again, the
inspector should examine long-term records to verify compliance. In the case of ash
content, this will require ultimate or proximite analysis of the fuel.
5.2 Determination of Gas Volume and Gas Conditions
For all combustion devices, flue gas volume may be either determined from the
fuel-firing rate or from calculating the volume of flue gas handled by the fan. With a
fuel-firing rate, a dry F-factor (Fd) is employed to calculate the dry standard cfm
produced per unit of fuel fired. The corrected wet standard cfm is further corrected for
the amount of oxygen in excess of stoichiometric conditions (excess air) and for the
temperature of the gas to yield the actual cfm at the APC system. This volume is also
corrected for the amount of water produced from combustion using a wet F-factor (FJ
as well as any additional water added in the case of wet fuels (e.g., wood, bark, etc.).
Alternatively, a fan curve or fan table correlating gas volume moved by the fan
with gas temperature, static pressure across the fan, and brake horsepower of the fan
motor, can be used to derive the actual cfm at the APC system.
5.2.1 Determination of Gas Volume from Fuel-Firing Rate
To determine the gas volume at the APC system from the fuel-firing rate, the
following data are necessary:
0 Instantaneous fuel-firing rate (e.g., gal/min, Ib/h, scfm-NG)
0 Gas temperature immediately after each control device (except for
scrubbers)
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0 Flue gas percent oxygen - location is the same as for temperature
0 Ultimate analysis of fuel or accurate F-factors (Fd and FJ.
When acquiring the fuel-firing rate, an instantaneous rate is required which
correlates with the time that the flue gas temperature and percent oxygen are
empirically measured. If the combustion device is operating in a consistently smooth
manner (i.e., little if any sudden changes in firing rate, excess air, steam demand,
etc.), gas oxygen and temperature measurements may be taken first and the
instantaneous fuel firing rate corresponding to the time that the temperature and
oxygen measurements were taken can be later retrieved. If instantaneous firing rates
are not continually recorded or the combustion device is operating in an irregular
mode, fuel-firing rate and gas measurements must be recorded simultaneously. This
may involve the need for at least two people measuring and/or recording data at the
same time.
The inspector should be equipped with a portable temperature-measuring
device (e.g., a thermometer or thermocouple) capable of accurate measurements
within the expected temperature range and a portable oxygen-measuring device (e.g.,
a fyrite oxygen analyzer or Orsat). To measure flue gas temperature and oxygen, it
should be noted that oxygen measurements are made on a dry basis. Plant oxygen
indicators are useful if they are accurate, read on a dry basis, and are located at or
near the APC equipment Plant oxygen sensors within the combustion device are not
appropriate to determine gas volume at the APC equipment, especially if duct integrity
is questionable (i.e., when air inleakage is possible).
To calculate gas volume, it is also necessary to have either accurate F-factors
(Fd and FJ for the fuel as-fired, or an ultimate analysis of the fuel with which to
calculate fuel-specific F-factors.
From the fuel ultimate analysis, F-factors are calculated using the as-fired gross
caloric value (GCV) of the fuel as follows:
141
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Btu) = 1oa(a64% H * 1.53% C * 0.57% 5 * 0.14% N - 0.46% O)
«^ . 10e(5.56% W + 1.53% C + 0.57% S * 0.14% N - 0.46% O2 * 0.21%
Btu) 5 — S -
With the fuel-firing rate, F-factors, and flue gas oxygen and temperature, the flue
gas volume is calculated as follows:
HI
20.9
d 20.9 -
'/»
460
528
where Q = Gas volume in actual ftVmin, acfrn
HI = Heat input, 106 Btu/min
Fd = Dry F-factor for fuel, dscf/106 Btu
Fw = Wet F-factor fuel, wscf/106 Btu
%O2 = Percent oxygen if flue gas
Tm = Measured flue gas temperature, °F.
This equation assumes complete combustion of the fuel fired. The heat input
(HI) can be calculated from the fuel-firing rate and the GCV of the fuel. For example,
for coal:
106 Btu/min = Ib/min x 106 Btu/lb-coal
or oil: .
10s Btu/min = gal/min-oil x 106 Btu/gal.
For fuels with high free moisture content (e.g., wood, bark, bagasse, etc.), the
equation is more complex because the contribution of the moisture from evaporation
to the flue gas is significantly higher than that produced by combustion. For high
moisture fuels, the equation is as follows:
142
-------
= HI
20.9
"120.9 - %O2
(MoistureCorrectiori)
(Tm - 460)
528
This equation should be used when the values have the same definitions as
previously and the moisture correction is:
fractional % HJO in fuel by weight x 21.41
Moisture correction =
(1 - fractional % H2O In fuel) x 10s Btu lib of dry fuel
This equation requires the dry GCV of the fuel. The value 21.41 is the conversion
factor (minus units) to convert 1 Ib of water to 1 Ib of water vapor (i.e., 1 Ib H20 vapor
occupies 21.41 scf of volume).
It should be noted that gas volume for wet scrubbers is calculated as the
saturated outlet gas volume at the scrubber stack. Although some scrubber
manufacturers include inlet design gas volume values, outlet saturated gas volume
values are the most common. To calculate outlet saturated gas volume, the-inspector
should first measure gas temperature and oxygen content immediately before the
scrubber to calculate inlet gas volume. From the gas volume equation, inlet gas
percent moisture may also be calculated. With inlet gas volume, gas temperature, and
gas moisture, outlet saturated gas volume may be determined from an adiabatic
saturation table.
Finally, gas volumes for some combustion devices such as lime kilns where flue
gases are in direct contact with process material, cannot be calculated using the
standard F-factor and firing rate equation. In the case of lime kilns, CO2 is released as
a by-product of calcination of the raw material. When calculating gas volumes for
processes that release gases from the process material, the added gas volume must
be included in the calculations.
143
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5.2.2 Determination of Gas Volume From Fan Conditions
Independent of firing rate and F-factor calculations, flue gas volume may also
be determined from fan conditions. This methodology involves the use of a fan curve
or fan table correlating gas volume delivered by the fan with pressure drop across the
fan or with brake horsepower of the fan motor along with gas temperature, density,
and fan rotation speed. A fan curve is a graphical representation of these correlations
while a fan table is the tabular form. Use of this methodology presupposes that an
accurate fan curve or fan table is available from the source or from the fan
manufacturer.
The fan curve or fan table is calculated for specific gas conditions and fan type.
If the fan has been changed in any significant way (e.g., different fan blade size, shell
diameter, etc.), the original fan curve or table must be recalculated. Figure 5-1 shows
a simplified typical fan curve for a straight radial blade fan. To determine gas volume
from a fan curve, either static pressure across the fan or fan motor brake horsepower
must be determined along with fan rotation speed and gas temperature.
Equipment needed to measure these data include:
0 Tachometer
0 Differential pressure gauge
0 Inductance ammeter
Temperature sensor.
o
If static pressure is to be used to enter the fan curve, static pressure taps must
be available immediately before and after the fan. In addition, temperature must be
measured immediately before the fan and fan rotation speed measured with a
tachometer. Measured differential pressure across the fan must first be corrected to
the gas temperature at which the fan curve was calculated. This temperature
correction is as follows:
144
-------
UJ CC.
cc uj
§2
UJ UJ
QC (/)
Q- CC.
OO
STATIC PRESSURE
STRAIGHT RADIAL
BLADES
GAS VOLUME
Figure 5-1. Simplified fan curve.
145
-------
where AP, = Differential pressure corrected for temperature, in. H2O
APm = Measured differential pressure, in. H2O
Tm = Measured gas temperature,°F
Tf = Temperature at which fan curve was calculated, °F.
In addition to temperature, the differential pressure must also be corrected for
fan rotation speed if the measured rotation speed is different from that used to
calculate the fan curve. The rotation speed correction is as follows:
where AP* = Corrected differential pressure, in. H2O
AP, = Differential pressure corrected for temperature, in. H2O
RPM, = Fan rotation speed at which fan curve was calculated, rpm
RRMm = Measured fan rotation speed, rpm.
With the corrected differential pressure (AP*), gas volume at the APC system can be
derived directly from the fan curve or fan table.
If fan motor brake horsepower is used to enter the fan curve, fan motor current
must be measured (inductance ammeter) along with gas temperature and fan rotation
speed. To correctly calculate fan motor brake horsepower, measured motor current
must be corrected to the gas temperature at which the fan curve was calculated. The
temperature correction factor is as follows:
146
-------
where I, = Motor current corrected for temperature, °F
Tm = Measure gas temperature, °F
TF = Temperature at which fan curve was calculated, °F
lm Average measured fan motor current, amperes.
With the corrected fan motor current, brake horsepower corrected for
temperature is calculated as follows:
(V)(/,)(1.73)(PF)(ME)
55
where BMP, = Brake horsepower corrected for gas temperature, BMP
V = Fan motor rated voltage, volts-AC
It = Motor current corrected for temperature, amperes
1.73 = Wave form factor for 3 phase system (=1 for single phase)
SF = Fan motor power factor, dimensionless
ME = Fan motor fractional efficiency, dimensionless.
The fan motor brake horsepower corrected for temperature must also be
corrected for fan rotation speed if different from that used to calculate the fan curve.
The correction for fan rotation speed is as follows:
BHP*
where BHP* = Corrected brake horsepower, BHP
RPM, = Fan rotation speed at which fan curve was calculated,
rpm
RPMm = Measured fan rotation speed, rpm
BHP, = Brake horsepower corrected for gas temperature,
BHP.
147
-------
With the corrected fan motor brake horsepower, gas volume at the ARC system
can be derived directly from the fan curve or fan table. Finally, as with the F-factor
method of determining gas volume, sources that yield off-gases from process material
such as lime kilns may require an additional correction of static pressure or brake
horsepower due to gas density if not originally included in the fan curve or fan table
calculations. If gas density corrections are indicated by significant differences between
actual and design density values, the corrections are made by a simple ratio of the
gas densities.
5.3 Determination of Gas Volume From Boilers
Many times the inspector will discover that instrumentation at the plant does not
exist to determine an instantaneous fuel-firing rate or that fuel consumed is not
measured at all. For fuel oil, gal/min fuel usage rates often include total fuel oil to the
burners but does not account for fuel that is not burned but returned to storage. If
instantaneous fuel-firing data are available, they must be accurate and truly reflect that
quantity of fuel that is actually burned.
The lack of accurate instantaneous fuel-firing data is common for boilers. Many
times, the only firing data consist of fuel usage integrator readings that usually
measure long-term usage rates (e.g., tons/h, scf/h-NG, gal/h x 1000, etc.) or total
usage rates for multiple sources.' In such cases, calculation of gas volume from fuel-
firing rates which correlate to instantaneously measured gas temperature and oxygen
content is not possible.
The same two options for calculating flue gas volume (fan curve and F-factor),
however, are nonetheless still available to the inspector. Although fuel-firing rates are
not available for the F-factor methodology, heat input (HI) to the boiler may be derived
from boiler heat output (HO) and an estimation of boiler efficiency (E):
148
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To calculate boiler heat output, the following data are required that is
representative of the time that flue gas measurements are recorded:
0 Steam generation rate, Ib-steam/h
0 Steam drum pressure, psia
0 Steam temperature, °F
0 Feedwater temperature, °F
0 Whether superheated or saturated steam.
Heat output of the boiler is calculated as follows:
HO (Btu Ih) = Steam generation rate (Ibfh) x [Steam enthalpy (Btuflb)
Feedwater enthalpy
Steam and feedwater enthalpy are derived from steam tables for superheated or
saturated steam and for saturated water.
Boiler efficiency is estimated using a methodology based on the ASME Test
Form for Abbreviated Efficiency Test (discussed in Section 2). This methodology
accounts for the total heat losses in steam generating units. As with the F-factor
method for calculating gas volume, the ASME method requires an ultimate analysis of
the as-fired fuel and an estimation of the percent combustibles in the boiler fly ash and
bottom ash (dry refuse). If an accurate estimation of the percent combustibles in the
dry refuse is not available from the source, representative samples should be
subjected to loss-on-ignition (LOI) laboratory testing.
The following steps are performed using the ASME methodology to estimate
boiler efficiency:
149
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STEP 1. Calculate Dry Refuse per Ib of As-Fired Fuel. Ib/lb
% ash in as-fired fuel
Dry Refuse, Ib lib
100 - % combustion in refuse sample
Ash content of the as-fired fuel (%) is found in the fuel ultimate analysis, percent
combustibles is estimated or derived from LOI tests.
STEP 2. Calculate Carbon Burned er Ib of As-fired Fuel. Ib/lb
dry mfuse llb offmlxBtu
Carbon burned Ib lib - f % cart)on ** welght ln iuel\ x (
( 100 ) (
14,500
Percent carbon by weight in fuel and dry refuse/lb of fuel are found in the fuel ultimate
analysis. Btu/lb of refuse is derived from LOI tests or source estimates. If fly ash and
bottom ash differ materially in the combustible content they should be estimated
separately.
STEP 3. Calculate Dry Gas per Ib of As-fired Fuel Burned. Ib/lb
M1CCU + 8CU * 7(/VL •«• CO)^
Dry gas, Ib lib - «/xJT—5;^ ^ * (^ carfwn burned lib as-fired fuel + 3/8 S)
Ib lib - f11C*^ **^ * ^ * °° *
\ 3(O^ + CO)
CO2, O2, and CO are the percent by volume of carbon dioxide, oxygen and carbon
monoxide, respectively in the flue gas. For most situations, CO can be ignored as it
normally constitutes less than one percent of the flue gas. N2 is the percent by
volume of nitrogen, by difference, in the flue gas (i.e., 100 - %O2 + %CO^). S is the
pound of sulfur per Ib of as-fired fuel from the ultimate analysis, or the fractional
percent sulfur. CO2 and O2 measurements of the flue gas should be taken
immediately after the last heat exchange surface of the boiler (normally the economizer
or air heater). Both CO2 and O2 measurements can be made with a fyrrte apparatus
or an Orsat.
150
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STEP 4. Calculate the Percent Heat Loss Due to Dry Gas
= Ib dry gasflb as-fired fuel burned x 0.24 (t -
where 0.24 = Specific heat of gas
tp = Rue gas temperature leaving unit, °F
t, = Combustion air temperature, °F.
Rue gas temperature (y should be measured at the same location as CO2 and O2
content. Combustion air temperature is ambient air temperature entering the boiler
prior to the use of any air preheater.
STEP 5. Calculate the Percent Heat Loss Due to Moisture in Fuel (HLJ
HLm - (% 1mo mo^m ln **0 x (enthalpy of vapor at 1 psla and at tg - enthalpy of liquid at
Percent free moisture in fuel is found in the ultimate analysis or from source estimates.
Enthalpy of vapor and liquid are derived from steam and saturated water tables.
STEPS. Calculate the Percent Heat Loss Due to Hydrogen in Fuel (HLJ
9H,
HLH = — -2 x (enthalpy of vapor at 1 psia and at tg - enthalpy of liquid at tj
H2 is the percent hydrogen in the fuel from the ultimate analysis.
STEP 7. Calculate the Percent Heat Loss Due to Unbumed Combustibles (HL^J
= Dry refuse (bottom ash + fly ash) per Ib as-fired fuel x Btullb of refuse
151
-------
Btu/lb of refuse is derived by LOI tests. Heat loss from unbumed combustibles may
range from near zero to as high as 50 percent. Refer to the ASME Power Codes to
determine dry refuse per Ib of as-fired fuel.
STEP 8. Determine the Percent Heat Loss Due to Radiation (HLr)
From Figure 5-2, determine the percent heat loss due to radiation. Boiler design
maximum continuous heat output (106 Btu/h) must be known as well as the number of
water or air-cooled furnace walls.
STEP 9. Total AH Heat Losses and Subtract From 100
Boiler efficiency (%) = 100 -
(HL+ - HLm + HLh + HL^
Btujlb as-fired fuel
NOTE: Heat loss due to unburned CO in the flue gas is normally negligible (<1%).
With heat output of the boiler and an estimate of boiler efficiency, true heat input
to the boiler can be calculated. With heat input, gas volume can be calculated using
the F-factor method at both the boiler outlet (immediately after the last heat exchange
surface), and at the APC systems. Increases in measured flue gas oxygen content
and decreases in gas temperature between these locations indicates infiltration of
tramp air, increasing the gas volume handled by the APC equipment and the
possibility of condensation of acid gases (H2SO4) from sulfur bearing fuels.
Excessively increased gas volume above baseline stack test conditions and/or above
manufacturer's design specifications, along with possible acid corrosion, are two of the
most common boiler APC system problems.
5.4 Conclusions
The methodologies and procedures presented in this section are designed to
aid the inspector reviewing the compliance status of combustion sources. A properly
152
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No. of Cooled Furnace Walls
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ie radiation loss values obtained from this curve are
r a differential of SO F between surface and ambient
mperatures and for an air velocity of 100 feet per
inute over the surface. Any correction for other con-
tions should be made hi accordance with Fig. 3 page 17i
the 1957 Manual of ASTM Standards on Refractory
aterials.
i i i i i i i ii ii
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A furnace wall must have at least one mini its
projected surface covered by water cooled surface
before reduction in radiation loss is permitted.
Air thru cooled walls must be used for combustion —
if reduction in radiation loss is to be made. ~
Example: Unit guaranteed for maximum continuous ~
output of 400 million Btu/hr with three ~
water cooled walls. —
Loss at 400 = 033%
Loss at 200 => 0.68% ~
IN \l
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0 2030406080 200 400600 1000 2000 6000 10.000 20.000
\\ 79 50 100 300 800 4000
3 .94 1.0 Water Wall Factor Actual Output Million Btu/hr
3 .97 1.0 Air-Cooled Wall Factor
Rgure 5-2. Radiation loss in percent of gross heat input.
(American Boiler Manufacturers Association)
153
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conducted inspection not only verifies records and recordkeeping practices, but also
attempts to determine the compliance or likely compliance of the source with mass
emission limits and with opacity limits.
In many cases, mass emission limits may be verified by reviewing OEM data.
When OEM data are unavailable, the inspector must analyze the operating conditions
of not only the APC equipment but also the combustion source and compare his or
her analysis to benchmarks such as baseline or most recent stack test data. This
analysis helps the inspector decide the likelihood of noncompliance of the source and
aids in documenting inspection operating conditions to serve as the operating protocol
for any subsequent compliance testing.
154
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SECTIONS
AIR POLLUTION CONTROL FOR
COMBUSTION APPLICATIONS
6.1 General
Effective control of air pollutant emissions from combustion sources requires
knowledge of the combustion products of the fuel being burned and of the
characteristics of the combustion equipment. During complete combustion under ideal
conditions, carbon bums with oxygen to produce carbon dioxide, and hydrogen burns
with oxygen to produce water vapor. If the combustion process is not properly
controlled, carbon monoxide may form from the incomplete burning of carbon.
Because most commercial fuels contain sulfur, sulfur dioxide is produced as a
combustion product. This product is generally unwanted because it corrodes metals
and is a suspected precursor to acid rain.1 Nitrogen from the air and fuel may
produce varying quantities of nitrogen oxides depending on the conditions of
combustion such as temperature and excess air.2 This product is also an unwanted
air pollutant that is a suspected precursor to acid rain.1 Incombustible solids, or ash,
in the fuel are released with the flue gas and become particulate emissions along with
any unbumed carbon particles. When burning solid or hazardous waste fuels, other
fuel constituents such as chlorine, organics, and metals may produce unwanted
combustion products in the flue gas.
Particulate emissions are controlled by collection devices designed to remove
solid particles from the flue gas. Gaseous emissions may be controlled by various
processes including the use of scrubbing equipment, combustion control techniques,
and/or reduction processes. This chapter presents the various control equipment and
control techniques organized by type of pollutant to be controlled. This is not
intended to be a comprehensive discussion on inspection of air pollution control
equipment Rather, concepts of emissions control as related to the combustion
process will be stressed, and common problems associated with control systems that
155
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are affected by combustion processes will be discussed. Control of the products of
combustion will be stressed as opposed to control of process emissions such as
cement kiln dust. It is essential that characteristics of the combustion equipment, fuel,
flue gas, and any process variations be considered in an analysis of the air pollution
control system.
In many cases a preverrtative approach has been taken to air pollution control
in order to eliminate unwanted products of combustion before they are produced or at
least released in the flue gas. Fuel switching to low-ash or low-sulfur fuels,
modification of equipment to increase combustion efficiency, and use of special
burners to reduce formation of nitrogen oxides are some examples of these
techniques. More frequently these kinds of techniques are playing a larger role in air
pollution control for industrial and utility combustion sources, although traditional air
pollution control equipment is still essential in reducing unwanted emissions to
acceptable levels.
Inspection of combustion sources includes comparison of air emissions with
regulated Federal, State, and/or local emission levels. Regulations may be based on
visible emissions (opacity), mass emission limits, and/or fuel content or operational
restriction incorporated in the source permit. Emissions monitoring requirements are
discussed in Section 7. Applicable Federal regulations depend on the type of source,
whether it is new or existing, and whether it is located in an attainment or a
nonattainment area for criteria pollutants. Requirements on the use of specific types of
control equipment also depend on these factors. New and modified combustion
sources are subject to the New Source Performance Standards (NSPS) (Appendix A).
Requirements for control equipment for new sources are generally determined on an
individual basis, and requirements may change based on the current state of
technology.
156
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6.2 Participate Control
The four basic types of equipment used to control paniculate emissions from
combustion sources are the multicyclone, wet scrubber, fabric filter, and electrostatic
precipitator (ESP). The theory of particle collection, general configuration, and
inspection guidelines for each type of equipment are briefly discussed in the following
sections.
Collection efficiency is an important measure of the effectiveness of air pollution
control equipment. "Penetration" is a term frequently used in assessing performance
of particulate control devices. Penetration is a measure of the quantity of emissions
leaving a control device as compared to the inlet loading. Penetration is directly
related to the collection efficiency by the following equation:
where X = Penetration (dimensionless)
E = Collection efficiency (percent).
It can be seen that if the collection efficiency of a control device is 99 percent then the
penetration equals 0.01. The use of penetration instead of efficiency sometimes
makes comparisons of performance easier (e.g., the difference between 99.9 and 99.5
percent efficiency does not seem great, but the difference between 0.001 and 0.005
means that the 99.5 percent device emits 5 times more than the 99.9 percent efficient
device). These terms will be used later in the discussion of specific types of control
equipment.
6.2.1 Mutticyclones
The multicyclone is a mechanical collector consisting of a number of individual
tubes, or cyclones, acting in parallel to remove particulate from the gas stream. This
device is also known as a multiple cyclone, multicyclone, muttitube collector, or
157
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mechanical dust collector. A cross-section of a typical multicyclone is shown in Figure
6-1. Multicyclones are generally used where control of larger particles (>5 micron) is
desired. The device may be used alone, but is frequently used for primary control
before a secondary collector such as a fabric filter or ESP.
Theory of Operation
All multicyclones operate under the principle of inertia! separation in removing
paniculate from the flue gas. The dirty gas enters the collector between tube sheets
and is distributed to the inlets of individual cyclones. As the gas enters the cyclone
tube through the inlet vanes, a vortex or spiral path is created (Figure 6-2). The gas
and suspended particles move in a downward circular motion and the particles are
separated from the gas stream by the resulting centrifugal force and move to the walls
of the cyclone. As the gas nears the bottom of the cyclone body, the vertical
component of the vortex causes it to reverse direction and move upward. The clean
gas moves upward in an inner vortex and exits through an outlet tube, while the
paniculate is discharged to a hopper beneath the cyclone.
Important parameters in the design of multicyclones are gas volume, inlet grain
loading, particle size and specific gravity, pressure drop, and required collection
efficiency. The collection efficiency is often expressed as 'X % efficiency at Y %
particles < 10 microns." Efficiency curves are available from the manufacturer or the
efficiency may be calculated.3 Efficiency generally increases as the pressure drop,
particle size, and specific gravity of the particles increase. The centrifugal force which
separates paniculate from the gas stream is expressed by:
where M = Particle mass
V = Gas velocity
r = tube radius.
158
-------
CLEAN-GAS TUBE
DIRTY-GAS INLET
COLLECTOR SHELL
OUST PARTICLES
DROPPING INTO HOPPER
CLEAN-GAS
OUTLET
CLEAN-GAS
/TUBE SHEET
DIRTY-GAS
BE SHEET
CAST IRON
COLLECTING TUBE
FLY ASH
ASH HANDLING
VALVE
Figure 6-1. Multicyclone cross section.
159
-------
INLET TURNING
VANES
INNER VORTEX
GAS OUTLET TUBE
CYCLONE BODY
OUTER VORTEX
DUST OUTLET
Figure 6-2. Cyclone tube detail.
160
-------
Increasing the velocity of the gas or decreasing the tube size within practical limits will
increase the centrifugal force and the collection efficiency. Typical efficiencies of
mutticyclones used with coal-fired boilers range from 70 to 90 percent. Pressure drop
generally ranges from 2 to 6 inches of water.3
Use With Combustion Equipment
The most common application of the multicyclone is as the primary collector of
fly ash from coal-fired boilers, although this device is used in a wide variety of
industrial processes. Multicyclones may be used alone for paniculate control for small
boilers. For utility boilers and larger industrial boilers, the multicyclone is often used to
remove larger particulate and/or to reduce paniculate load on a fabric filter, scrubber,
or ESP. Multicyclones may be used to increase combustion efficiency of equipment
such as stoker-fired boilers by recirculating unburned carbon panicles to the furnace.
One advantage of the multicyclone is that it can withstand flue gas temperatures up to
750° F for carbon steel, whereas a fabric filter is limited to a maximum of 200° to 500°
F depending on the type of bag fabric used.
Use of mutticyclones with swing-load boilers poses problems because efficiency
drops sharply when gas velocity falls below the design range necessary to sustain
inertia! separation. To correct this situation a portion of the gas may be recirculated
from the clean side of the device to the dirty side as boiler load is decreased. In this
way a constant velocity and pressure drop is maintained to improve efficiency.
Another method used to improve efficiency is sidestream separation, also
known as hopper evacuation or fractionating. In this method a portion of the gas
(typically 20%) from the multicyclone is drawn away from the area between the
discharge tubes and the hopper and ducted to a small high-efficiency baghouse.
Efficiency is improved because particulate reentrainment from the hopper is eliminated
and finer particles that would normally exit the multicyclone are collected by the
baghouse.
161
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Inspection Guidelines
Detailed procedures for performing Levels 2 and 3 inspections for multicyclones
and other particulate control devices are found in the Air Compliance Inspection
Manual4 and the Air Pollution Source Reid Inspection Notebook.5 Common problems
associated with multicyclones are discussed below. Consideration of these potential
problems will be useful in evaluating any apparent performance deficiencies.
The major causes of mutticydone problems result from leaks, turbulence,
pluggage from particulate deposits, and deviation from design operating parameters.3
Particulate abrasion can wear holes in critical areas of the mutticyclone and can
destroy seals or gaskets around the discharge valves and tube sheet. External leaks
may develop around access doors and welded seams due to poor seals and welds.
Turbulence within the cyclone tubes can disturb or destroy the vortex which separates
particulate from the gas. Turbulence may be created by leaks, dents, particulate
deposits, worn vanes or discharge openings, and excessive gas flow. Buildup of
particulate deposits and pluggage become potential problems whenever the gas
temperature falls near its dew point or the gas flow is reduced below design limits.
When inlet vanes of a cyclone tube become plugged, entrained particles from the
hopper area may flow up through the normal discharge opening of this tube to the
outlet.
Monitoring differential pressure is probably the best method to determine
effectiveness of the mutticyclone during compliance inspections.3 Boiler load should
always be recorded with this data. Readings should be compared to baseline data
and/or previous inspections. Of course, exhaust plume opacity is the primary
measure of effectiveness if the mutticydone is the only particulate control device used.
The usefulness of opacity may be limited, however, because multicyclones usually do
not collect particles below 2 microns. Unless changes in inlet particle size occur,
opacity may provide little indication in operating problems. When internal inspections
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are performed, signs of collector bypass, leaks, tube wear, pluggage, and flow
maldistribution should be examined. Air inleakage may be checked by measuring O2
levels at the inlet and outlet of the multicyclone unit.
6.2.2 Wet Scrubbers
The purpose of wet scrubbing systems in use on combustion sources today
may be for paniculate control, S02 control, or a combination of both. This section
discusses the collection mechanisms and types of scrubbers used for paniculate
control.
Collection Mechanisms
Wet scrubbers remove dust from a gas stream by providing favorable
conditions for transfer of suspended paniculate from the gas to a scrubbing liquid in
the form of droplets, sheets, or jets. The fundamental particle capture mechanisms
involved are inertial impaction and to a lesser extent, Brownian diffusion.6 The
effectiveness of inertial impaction is related to the particle size, gas velocity, and liquid
droplet size. Increasing the size of the particle and velocity increases impaction
effectiveness. Impaction effectiveness also improves if smaller droplets are formed.
The effects of Brownian diffusion are seen with smaller particles (<0.2 micron). These
particles move randomly across gas streamlines due to collisions with gas molecules,
resulting in capture by liquid droplets or sheets. This captive mechanism increases in
proportion to smaller particle size and higher gas temperatures. The relative effects of
impaction and diffusion as related to particle size are shown in Rgure 6-3. It can be
seen that peak penetration or minimum collection efficiency occurs in the O.2 to 0.5
micron particle size range.
Types of Wet Scrubbers
The major categories of wet scrubbers used for paniculate control for
combustion sources include gas-atomized spray scrubbers, moving bed scrubbers,
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1.0
DIFFUSION
MORE
EFFECTIVE
I I I i i 11it I I I i i 11
o
0.10
0.01
IMR&CTION MORE
EFFECTIVE
i i i i i i 111
O.I 0.2 Q5 1.0 234 5678910
PARTICLE DIAMETER, JimA
Figure 6-3. General relationship between penetration and particle size for wet scrubbers.6
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and preformed spray scrubbers. Packed-bed scrubbers and impingement plate
scrubbers may be used for incinerator applications. Other types of wet scrubbers are
also used in industries such as metals processing and material handling.
Gas-atomized scrubber types include the venturi scrubber, orifice scrubber, and
rod scrubber. Rgure 6-4 shows a venturi scrubber. The collection process mainly
relies upon acceleration of the gas stream through a throat-type constriction to provide
impaction and intimate contact between the particulate and the fine liquid droplets
generated as a result of gas atomization. This is a high-energy-consuming device
designed for high-efficiency particulate collection. Typically, the pressure drop in
electric utility use is on the order of 20 inches of water or more. Collection efficiency
increases with pressure drop and liquid to gas ratio (L/G). There is, however, an
optimum L/G value above which additional liquid rate is not effective at a given
pressure drop. In this device the pressure drop can be increased by increasing the
gas velocity. The high gas velocities can also cause a high rate of wear. A cyclonic
separator, or demister, is provided to remove entrained water droplets from the gas
leaving the venturi. Some venturi designs include adjustable throat mechanisms so
that gas velocity can be varied. Figure 6-5 shows an example of an orifice scrubber.
With this type of scrubber the gas stream is forced through a narrow area underneath
a partition and just above the liquid surface. The turning gas stream entrains some of
the liquor in a pool beneath the gas inlet. The atomized droplets serve as impaction
targets for the particles. Maintaining the proper liquid level is important with this type
of scrubber. These units are generally smaller than venturi scrubbers. Both vertically
and horizontally oriented designs exist. Rgure 6-6 shows a rod scrubber. The spaces
between the rods comprise the area of gas stream acceleration and droplet
atomization. Spray nozzles for liquor distribution are located above the rod deck. In
some cases several rod decks may be used, the advantage being in improved gas
absorption rather than particulate control. Potential rod erosion and corrosion are
concerns with rod scrubbers.
165
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QernafM
Water tprmjt
Figure 6-4. Venturi scrubber.4
166
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CkmafBi
Dirty g*f
.' Dirty f*>
Figure 6-5. Orifice scrubber.4
Figure6-6. Rod scrubber.4
167
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Moving bed scrubber types are illustrated by the simplified design shown in
Rgure 6-7. In principle, dusty gas passes upward through a bed of spheres, which
may go into a fiuidized state of random motion depending upon the gas velocity and
the density of the spheres. Scrubbing liquid is sprayed from above the spheres,
resulting in formation of a turbulent zone around the spheres. Dust enters the
scrubber at the bottom counter-currently, contacts the main liquor, and bubbles with
the liquor upward through the turbulent layer. Inertia! impaction and interception are
the primary collection mechanisms. The solid particles that are captured by the liquid
are drained out the bottom of the scrubber. Energy consumption of this device is
relatively low, with a typical pressure drop of 4 inches of water per stage and L/G ratio
approximately 20 to 25 gal/min per 1000 cfm. Although the device is not as efficient,
for participate removal as the venturi scrubber, it has better gas absorption
characteristics. The scrubber is well-suited for sticky material or high paniculate
loadings since there are no restricted passages that can plug. The turbulent action of
the spheres also has a self-cleaning effect. Packed-bed scrubbers are similar to
moving-bed scrubbers but are used primarily for gas absorption. Most commercial
units have several beds in series rather than the single stage unit shown in the figure.
Preformed spray scrubber types include variations of spray towers and cyclonic
towers. These are illustrated in Rgure 6-8. The preformed spray scrubber unit is the
simplest type of wet scrubber and has the lowest overall paniculate collection
capability. It is a vertical tower with one or more sets of spray nozzles. The gas
stream moves directly upward through the tower or, alternately in a cyclonic motion
upward. Demisters are used in the top of the scrubber unit. Effectiveness of the
spray nozzles, L/G ratio, and particle size distribution are important parameters.
Removal capabilities for small particles are generally very limited. Spray nozzle
erosion and/or pluggage are common problems. In many applications gas absorption
is the primary function of preformed spray scrubbers.
168
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Mist eliminator
Spray nozzle*
Mobile packing
Dirty gu
Figure 6-7. Simple moving bed scrubber.4
169
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Dirrjgm
a. Simple Spray Tower
b. Cyclone Spray Tower
Figure 6-8. Preformed spray scrubbers.4
170
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Wet Scrubbing Systems
Wet scrubber units are generally not isolated pieces of equipment. Some of the
other components in the system may include a gas cooler/humidifier, liquor and solids
treatment equipment, gas stream demister, liquor recirculation tanks and pumps,
alkaline addition equipment, fans, dampers, and bypass stacks. Wet scrubbers used
on coal-fired boilers are generally found in conjunction with SO2 absorption systems.
In the case of large utilities, several scrubbing trains may be used in series so that
changes in boiler load can be accommodated.
Inspection Guidelines
Detailed procedures for inspection of wet scrubbing systems are available in the
Wet Scrubber Inspection and Evaluation Manual6 and other previously mentioned
inspection manuals.415 Important performance parameters to consider are the
pressure drop, gas velocity, L/G ratio, particle size distribution, gas temperature, and
inlet grain loading. The pH of the liquor is also important because pH levels below 6
can lead to severe corrosion of carbon steel components, and pH levels of 9 and
above can lead to scaling and buildup of calcium and magnesium compound
deposits. Other equipment parameters to check are the condition of the scrubber
shell, any erosion or pluggage of spray nozzles, and general conditions of the system
fan, pumps, piping, valves and ducts.
Observation of visible emissions is the initial step in any scrubber inspection. It
should be remembered, however, that opacity observations from wet scrubbers may
be affected by steam plume interference. Heavy mist, droplet reentrainment, and/or
rain-out of droplets from the plume indicates a significant demister problem.
6.2.3 Fabric Filters
Fabric filters are dry paniculate control devices that use a fabric media, in the
form of multiple bags, to block the passage of dust as the dirty gas flows through the
filtration media. The buildup of dust on the surface of the bags actually aids in the
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filtration process. Bags must be cleaned at regular intervals to prevent excessive dust
buildup and to collect this material in hoppers underneath the bags for removal and
subsequent disposal. Fabric filter units are sometimes referred to as " bag houses. "
Particle Capture Mechanisms
A single fiber can be used to illustrate the various capture mechanisms of a
fabric filter. As shown in Figure 6-9, the five basic mechanisms by which particulate
can be collected by a single clean fiber are 1) inertial impaction, 2) Brownian diffusion,
3) direct interception, 4) electrostatic attraction, and 5) gravitational settling. These
collection mechanisms, plus sieving, also apply to a fabric with a dust cake, such as
would be encountered under typical operating conditions. Inertial impaction is the
dominant collection mechanism within the dust cake. The forward motion of the
particles results in impaction on fibers or on already deposited particles. Although
impaction increases with higher gas velocities, these higher velocities reduce the
effectiveness of Brownian diffusion. Use of a less dense fabric or more frequent
cleaning also reduces diffusional deposition. Except at low gas velocities, the effect of
gravity settling is negligible. Electrostatic forces may have an affect on collection
because of the difference in electrical charge between the particles and the filter.
Sieving occurs when the particle is too large to pass through the fabric matrix. The
combination of all these particle collection mechanisms results in high-efficiency
removal efficiency for all particle sizes.
The fabric filtration process or the accumulation of particulate on a new fabric
surface occurs in three phases: 1) early dust bridging of the fabric substrate, 2)
subsurface dust cake development, and 3) surface dust cake development. The fabric
used in a fabric filter is typically a woven or felted material, which forms the base on
which particulate emissions are collected. In the first phase, particles entering a new
fabric initially contact the individual fibers and are collected by the filtration
mechanisms. These deposited particles, which are essentially lodged within the fabric
structure, promote the capture of additional particles. As these particles build up
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DIRECT
INTERCEPTION
DIFFUSION ^
INERTIAL
IMPACTION
ELEaROSTATIC
ATTRACTION
_— GRAVITATIONAL
SETTLING
Figure 6-9. Initial capture mechanisms of fabric filtration.7
-------
during the second phase, particle aggregates form, bridging of open fabric spaces
occurs, and a more or less continuous deposit is formed. In the third phase, particles
continue to collect on the previous deposit, and the surface dust cake is developed.
The cleaning cycle (via shaking, reverse air, or pulse jet) removes some of the
surface cake. After a few cleaning cycles, theoretically, a steady-state dust cake
should be formed, which will remain until the bag is damaged, replaced, or washed.
Actually, however, the dust cake can vary significantly from cycle to cycle, particularly
in severe applications such as utility boilers or metallurgical processes. This remaining
cake forms a base for the collection of particles when the bag is put back on line after
cleaning.
Gas Stream Factors That Affect Fabric Filter Design and Operation
Characterization of the gas stream is very important in the design, operation, or
evaluation of a fabric filter system. It should include the gas flow rate; minimum and
maximum gas temperatures; acid dew point; moisture content; presence of large
paniculate matter; presence of sticky paniculate matter; paniculate mass loading;
chemical, adhesion, and abrasion properties of the paniculate; and presence of
potentially explosive gases or paniculate matter. These data can be used to design a
collector with the required degree of control or to optimize the operation of an existing
fabric filter, as illustrated by the following examples:
1. The required size of a fabric filter system is determined by the gas
volume to be filtered, the air-to-cloth (A/C) ratio, and the pressure drop
at which the filter can be operated given the fabric type, dust cake
properties, and cleaning method. The area of fabric surface is
determined by multiplying the total gas flow by the selected A/C ratio.
2. Penetration is related to the effective A/C ratio in the system, particularly
if the A/C ratio is outside the optimum range for the specific application
and type of fabric filter. Therefore, the lowest feasible face velocity is
desirable for fabric filter design. This parameter should also be
considered in the operation of an existing fabric filter if process flow rates
increase significantly or additional sources are added.
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3. Variations in gas stream temperature over time affect the operation and
design of a fabric filter. The temperature of gases emitted from industrial
processes may vary more than several hundred degrees within short
periods of time. They may fall below the gas moisture and acid dew
points or they may exceed the maximum that the fabric will tolerate. The
temperature extremes must be determined before the filter fabric is
selected and during evaluation of fabric filter performance.
4. The particle size distribution of the dust must be considered in the design
and operation of the collector. Particle size distribution affects both the
porosity of the dust cake and abrasion of the fabric. The presence of
fine particles in the gas stream can create a very compact dust cake and
increase the static pressure drop through the cake. These fine particles
can also cause fabric bleeding if pulled through the fabric. The presence
of large abrasive particles can reduce bag life and may necessitate the
use of a precleaner or gas distribution devices in the collection system.
5. Moisture content and acid dew point are important gas composition
factors. Operating a fabric filter at dose to the acid dew point introduces
substantial risk of corrosion of the fabric filter housing and internal
framework. Also, allowing the temperature to drop below the water
and/or acid dew point, either during startup or at normal operation, will
usually cause blinding of the bags. Acids or alkali materials can also
weaken the fabric and shorten their useful life. Trace components, such
as fluorine, also can attack certain fabrics.
nitration media selection is an important aspect of effective fabric filter design
and operation. Woven fiberglass bags have been used for most utility combustion
applications, but many types of fabrics are available today. Acrylics and many other
synthetic fabrics are less costly, but have lower temperature limitations. Laminated
fabrics and fabric coatings are also available that provide improvements such as
resistance to acid gases or superior dust cake initiation. Other details of specific
fabrics are discussed in the Operation and Maintenance Manual for Fabric Fitters 7 and
in manufacturer's literature.
Types of Fabric Filters
Fabric filter types are generally classified by their cleaning mechanism. The
most common types are the shaker (shake/deflate), reverse-air, and pulse-jet units.
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Shaker-Type Fabric Filters. A conventional shaker-type fabric filter is shown in
Figure 6-10. Particulate-laden gas enters below the tube sheet and passes from the
inside bag surface to the outside surface. At regular intervals a portion of the dust
cake is removed by mechanical shaking (manual shaking for small systems). The
shaking is normally accomplished by rapid horizontal motion induced by a mechanical
shaker bar attached at the top of the bag. This creates a standing wave in the bag
and causes flexing of the fabric. The flexing causes the dust cake to crack, and
portions are released from the fabric surface. The cleaning intensity is controlled by
bag tension and by the amplitude, frequency, and duration of the shaking. Woven
fabrics are generally used in shaker-type collectors; and because of the low cleaning
intensity, the gas flow is stopped before cleaning begins to eliminate particle
reentrainment. The cleaning may be done by bag, row, section, or compartment.
Gas flow through shaker-type fabric filters is usually limited to a low superficial
velocity or A/C ratio of less than 3 ft/min and a typical range of from 1 to 2 ft/min.
High A/C values can lead to excessive particle penetration or blinding, which reduces
fabric life and results in high pressure drop.
Mechanical shaker-type units differ with regard to the shaker assembly design,
bag length and arrangement, and type of fabric. All sizes of control systems can use
the shaker design.
Reverse-Air Fabric Filters. In fabric filters with reverse-air cleaning, particles can
be collected on a dust cake on either the inside or outside of the bag. Fabrics may
be either woven or felt, but felts are normally restricted to external surface collection.
A typical reverse air filter is shown in Rgure 6-11. Smaller units are sometimes
cylindrical in shape. Cleaning is accomplished by reversal of the gas flow through the
filter media. The change in direction causes the surface contour of the filter surface to
change (relax) and promotes dust-cake cracking. The flow of gas through the fabric
assists in removal of the cake. The reverse flow may be supplied by cleaned exhaust
gases or by ambient air introduced by a secondary fan.
176
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OVERMOUNTED
EXHAUSTER
MOTOR
DOOR
DOOR
INLET- -
DISCHARGE GATE
Figure 6-10. Shaker-type fabric fllter.7
177
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Figure 6-11. Reverse-air fabric filter.7
178
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In filters with inside bag collection, cleaning is done with compartments isolated.
The filter bags may require anticollapse rings to prevent closure of the tube and dust
bridging.
Reverse-air filters are usually limited to A/C ratios of less than 3 ft/min, with a
typical range of about 1 to 2.5 ft/min. In general, the appropriate A/C ratio for a
reverse-air unit is slightly lower than for a similar shaker-type unit application.
Pulse-Jet Fabric Filters. In pulse-jet fabric filters, filtering takes place on exterior
bag surfaces. A small pulse-jet fabric filter is illustrated in Rgure 6-12. The bags,
supported by inner retainers (usually called cages), are suspended from a tube sheet.
Compressed air for cleaning is supplied through a manifold-solenoid assembly into
blow pipes. Venturi's are mounted in the bag entry area to improve the pulse-jet effect
and to protect the top part of the bag. The diffuser is placed at the gas inlet to
prevent large particles from abrading lower portions of the bag.
During cleaning, a brief pulse of compressed air injected into the top of the bag
creates a traveling wave in the fabric, which shatters the cake and throws it from the
surface of the fabric. The dominant cleaning mechanism in a pulse-jet unit is fabric
flexing. Felted fabrics are normally used, and the cleaning intensity (energy) is high.
The cleaning usually proceeds by rows, and all bags in a row are cleaned
simultaneously. Pulse-jet units can operate at substantially higher A/C ratios than the
previously discussed fabric filters because of their higher cleaning intensity. Typical
ratios range from 5 to 10 ft/min.
Use With Combustion Equipment
Fabric filters and ESPs are the two primary particulate control devices used for
industrial and utility boilers. Fabric filters have been successfully used in combination
with dry scrubbing systems for SO2 control (Section 6.3.2) as well as for particulate
control. Fabric filters may have an advantage over ESPs in controlling emissions from
boilers using low sulfur coal because of particle resistivity problems (Section 6.2.4).
179
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CtCAM AM PUMUM
Figure 6-12. Pulse-Jet fabric filter.7
180
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Although all three classifications of fabric filters are used on combustion
sources, reverse-air units have been used for most large-scale utility applications,
while pulse-jet units are generally preferred for industrial boilers.8 Many industrial
applications such as kilns, cupolas, and electric are furnaces use fabric filters for
paniculate control. Fabric filters have also been installed on RDF plants. Fabric filters
are generally not used on wood-fired boilers because of the fire hazard from glowing
char particles that are carried out of the combustin process or from poor combustion
characteristics with wet fuels.
Inspection Guidelines
Details of procedures for compliance inspections of fabric filters are available in
the inspection manuals previously mentioned.4'5 Diagnostic type inspections and
cause-and-effect relationships are discussed in the Operation and Maintenance Manual
for Fabric niters.7
The basic parameters for evaluation include visible emissions, gas temperature,
pressure drop, bag conditions, gas volume, and A/C ratio. Process conditions and
records of bag failure are also important. Signs of abrasion, corrosion, high
temperature (above bag limit), low temperature (below acid dewpoint), bag blinding,
etc. may be apparent by internal inspection.
6.2.4 ESPS
ESPs are high efficiency paniculate control devices that electrically charge
particles in an enclosed chamber in order to remove them from the gas stream.
Particles are typically collected on grounded vertical plates. In the dry precipitation
process that is used for most combustion sources, particles are removed from the
plates by rapping the plates and dropping the dust into a hopper. Wet ESPs remove
collected paniculate by water flushing. The wet ESPs are used for specialized
industrial applications such as for basic oxygen furnaces and sutfuric acid plants. Wet
ESPs have been applied to some wood-fired boilers firing wet, salt laden woodwaste.
All other discussions of ESPs in this document refer to the dry type.
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Operating Principles
The basic principles of the electrostatic precipitation process are 1)
development of a high-voltage direct current that is used to electrically charge particles
in the gas stream (almost all commercial ESP's have negative polarity), 2)
development of an electric field in the space between the discharge electrode and the
positively charged collection electrode that propels the negatively charged ions and
paniculate matter toward the collection electrode, and 3) removal of the collected
paniculate by use of a rapping mechanism. These basic principles are illustrated in
Rgure 6-13.
The electrostatic precipitation process occurs within an enclosed chamber; a
high-voltage transformer (to step up the line voltage) and a rectifier (to convert AC
voltage to DC) provide the power input. The precipitation chamber has a shell that is
usually made of steel. Suspended within this shell are the grounded collecting
electrodes (usually plates), which are connected to the grounded steel framework of
the supporting structure and to an earth-driven ground. Suspended between the
collection plates are the discharge electrodes (usually wires) which are insulated from
ground and negatively charged with voltages ranging from 20 kV to 100 kV. The large
difference in voltage between the negatively charged discharge electrode and
positively charged collection electrode creates the electric field that drives the
negatively charged ions and particles toward the collection electrode. The particles
may travel some distance through the ESP before they are collected or they may be
collected more than one time. Some particles lose their charge rapidly after being
collected and are lost through reentrainment in the gas stream.
The last segment of the process covers the removal of the dust from the
collection electrodes. This is accomplished by periodic striking of the collection and
discharge electrode with a rapping device which can be activated by a solenoid, air
pressure, or gravity after release of a magnetic field, or mechanically through a series
of rotating cams, hammers, or vibrators. The paniculate is collected in hoppers and
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EARTHED COLLECTOR
ELECTRODE AT
POSITIVE POLARITY
ELECTRICAL CHARGED
FIELD PARTICLE
DISCHARGE ELECTRODE
AT NEGATIVE POLARITY
1 HIGH VOLTAGE
J CURRENT SUPPLY
UNCHARGED
PARTICLES
PARTICLES ATTRACTED
TO COLLECTOR ELECTRODE
AND FORMING DUST LAYER
Figure 6-13. Basic processes of electrostatic precipitation.9
-------
then conveyed to storage or disposal. Figure 6-14 shows a typical wire-weight ESP.
Other types such as rigid-frame and rigid electrode units are also in use.
Gas Stream Factors Affecting Electrostatic Precipitation
Several important gas stream and paniculate properties determine how well an
ESP will collect a given paniculate matter. They include particle size distribution, flow
rate, and resistivity which is influenced by the chemical composition, density of the
paniculate, and process temperature. These factors can also affect the corrosiveness
of the dust and the ability to remove the dust from the plates and wires. Following are
brief discussions of some of these properties.
Particle Size Distribution. In general, the larger the size of a particle, the easier
it is for an ESP to collect it Particles in the 0.2 to 0.4 micron diameter range are the
most difficult to collect because in this size range, the fundamental field charging
mechanism is less effective and gives way to diffusion charging for very small particles.
A large percentage of small particles (<1 micron) in the gas stream can suppress the
generation of the charging corona in the inlet field of an ESP, and thus reduce the
number of particles collected.
Resistivity. This parameter is a measure of how easy or difficult it is for a given
particle to conduct electrical charge. The higher the measured resistivity (the value
being expressed in ohm-cm), the harder it is for the particle to transfer the charge.
Resistivity is influenced by the chemical composition of the gas stream and paniculate,
the moisture content of the gas stream, and the temperature. Resistivity must be kept
within reasonable limits for the ESP to perform as designed. The preferred range is
108 to 1010 ohm-cm. Low resistivity generally results in collected particles loosing their
charge to the collection plate and being reentrained in the gas stream. High resistivity
results in increased electrical force in the collected dust layer which leads to excessive
dust buildup, reduced operating voltage, and increased sparking.
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BUS DUCT ASST
INSULATOR
COMPARTMENT
VENTILATION SYSTEM
HIGH VOLTAGE
SYSTEM RAPPER
INSULATOR
COMPARTMENT
RAILING
NIGH VOLTAGE
SYSTEM UPPER -
SUPPORT FRAME
24 In.
MANHOLE
RANSFORMER/RECTIFIEt
REACTOR
RIMARY LOAD
RAPPER
ROL PANEL
ELECTRICAL
EQUIPMENT
PLATFORM
HIGH VOLTAGE
ELECTRODES
WITH WEIGHT
COLLECTING
SURFACE
RAPPERS
HOPPER
Figure 6-14. Typical wire-weight ESP.9
185
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Temperature. In some applications the effect of temperature on resistivity and
(ultimately on ESP collection efficiency) can be significant. Resistivity may increase or
decrease with increasing temperature, depending on whether the ESP is operating on
the "cold-side" or the "hot-side" of the temperature range (cold side and hot side ESPs
in boiler applications usually refer to their location relative to the air preheater). Most
units in use today are cold-side applications.
Gas Volume/Velocity. An ESP will operate best when the gas volume keeps the
velocity within a typical range of 3.5 to 5.5 ft/s. Units are generally designed based on
an average gas velocity assuming uniform gas distribution across the cross section of
the ESP. Because uniform gas distribution is rarely achieved, there are localized
variances within the ESP. Above some critical velocity, rapping and reentrainment
losses tend to increase rapidly because of the aerodynamic forces on the particles.
This critical velocity is a function of gas flow, plate configuration, precipitator size, and
other factors, such as resistivity. Excessive air inleakage can also cause higher-than-
expected gas volumes, but this problem can be remedied by proper design and
maintenance of seals and expansion joints.
A final consideration is that of low gas volumes. If velocity is allowed to drop
below 2 to 3 ft/s, performance problems can occur as a result of maldistribution of
gas flow and dropout of dust in the ducts leading to the ESP.
Fuel-Related Parameters. A decrease in the sulfur content of coal will generally
result in an increase in resistivity and a reduction in the collection efficiency of the
ESP. Certain chemical constituents in the paniculate (e.g., sodium and iron oxide) can
reduce resistivity and improve performance provided they exist in sufficient quantities.
An analysis of the ash or process dust should be used to design the ESP based on
the worst fuel or process dust expected. Because of its low resistivity, carbon is
another constituent that can reduce ESP performance. Hie carbon particle is
conductive, but it loses its charge quickly and becomes reentrained from the collection
plates. This is aggravated by the fact that carbon is lighter than other constituents in
186
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the flue gas. This is a problem on coal-fired stoker boilers, wood-fired boilers, and
coke oven underfire applications, for example, where the combustible content of the
ash may range from 25 to 50 percent. The ESP's for these units are larger and have
lower face velocity than those for applications where resistivity levels are normal.
ESP Applications
ESP's are used with many basic combustion sources and in some specialized
applications. The electric utility industry is the biggest user of ESPs, but other users
include the cement industry (rotary kilns), the pulp and paper industry (kraft recovery
boilers, coal, and hogged fuel boilers), municipal incinerators, metallurgical
applications, the petroleum industry, and industrial boilers of all types. Paniculate
matter from these sources can generally acquire an electrical charge quite well, and an
ESP can be designed to treat large gas volumes.
ESPs can be used with low-sulfur coal (or other high resistivity problem
applications) by using a conditioning system to introduce moisture or chemical
substances to increase the conductivity of the paniculate.
Moisture not only reduces the resistivity of most dusts and fumes at
temperatures below 250° to 300° F, but also greatly enhances the effect of chemical
conditioning agents. Moisture conditioning is performed by steam injection or water
sprays; the lower the gas stream temperature, the better the conditioning effect.
Proper spray nozzle design, adequate chamber space, and proper temperature
control are imperative; otherwise, too much water can be provided and the paniculate
matter will cake on the interior of the ESP.
Chemical conditioning agents that are in use include sulfur trioxide, sulfuric acid,
ammonia, and sodium compounds. Sulfur trioxide (SOg) and sulfuric acid have been
widely used on coal-fired utility boilers. The primary mechanism is condensation or
adsorption on ash. The handling of both of these highly corrosive and toxic liquids is
different because they must be vaporized before they are injected into the flue gas.
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Although flue gas conditioning often improves ESP performance by reducing
dust resistivity, conditioning agents cannot correct problems associated with a poorly
designed ESP, poor gas distribution, misaligned plates and wires, or inadequate
rapping. Thus, any existing installation should be carefully evaluated to determine that
poor ESP performance is due entirely to resistivity problems.
Inspection Guidelines
Details of procedures for compliance inspections of ESPs are available in the
inspection manuals previously mentioned.4'5 Diagnostic type inspections and trouble-
shooting evaluations are discussed in the Operation and Maintenance Manual for
Electrostatic Precipitators.9
The basic parameters for evaluation include visible emissions/opacity, electrical
data (primary and secondary voltages and currents, and spark rate), general physical
conditions, gas stream parameters, and process conditions. The most common
operating problems include resistivity difficulties, plate-discharge electrode
misalignment, rapping problems, insulator failure, air infiltration, hopper overflow, and
poor gas flow distribution. It should be remembered that many of these problems are
interrelated and several may exist at one time.
6.3 Sulfur Dioxide Control
Sulfur dioxide is produced in significant quantities in the combustion of most
coals and fuel oil. The two general approaches to controlling SO2 are to remove sulfur
from the fuel prior to its use, or to remove SO2 from the flue gases before release to
the atmosphere. Low sulfur fuels are used in the first approach. The second
approach involves the use of flue gas desulfurization (FGD) equipment or in-fumace
sorbent injection processes. This section discusses the major SO2 control techniques,
including wet scrubbing, dry scrubbing, and sorbent injection/combustion processes.
188
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6.3.1 Wet Scrubbing Techniques
Wet FGD systems have been widely used by utilities and industrial applications
for SO2 control by gaseous absorption. The scrubber vessel is a major component of
the larger FGD system. Many scrubbers used for paniculate control such as the
venturi scrubber (Section 6.2.2), may also be used for SO2 control or a combination of
both. The major categories of scrubber vessels were previously discussed.
Most wet FGD systems use a lime or limestone slurry as the scrubbing liquor.
As SO2 contacts the liquor, it reacts with the lime or limestone to form calcium suffite
and calcium sulfate sludge, which must be further treated and/or disposed of as a
waste product. A few systems, such as those using magnesium oxide or citric acid,
have been used to recover sulfur or sulfuric acid as by-products. Wet FGD systems
are typically capable of 90 percent SO2 removal efficiencies. An example of a
limestone wet scrubbing system is shown in Rgure 6-15.
Spray tower scrubbers (Section 6.2.2) and packed-bed scrubbers are units
primarily used for gaseous absorption. The packed-bed scrubber is similar to the
moving bed scrubber shown in Figure 6-7 except that the packing material has special
shapes and is not mobile. The large liquor surface area created as the liquor
gradually passes over the packing material favors gas absorption and diffusion. One
potential problem with this unit is the accumulation of solids in the bed.
In addition to control of SO2 emissions from coal- and oil-fired boilers, wet
scrubbing systems are also used for incinerator applications. Wet collection devices
are the major control technology used for hazardous waste incinerators. These
systems may consist of several different wet scrubbing processes in the same system
to control emissions of paniculate matter, SO2, and acid gases such as HCL and HF.
Inspection guidelines for wet scrubbers were previously discussed. Monitoring
of suspended and dissolved solids in the liquor, and liquor pH are important
parameters for scrubbers used in wet FGD systems.
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Limestone
Reciftulition Tanks
Figure 6-15. Limestone wet scrubbing system.54
190
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6.3.2 Dry Scrubbing Techniques
Dry scrubbing is a FGD process that uses absorption to remove SO2 from the
combustion gases. The dry scrubbing systems incorporate two major pieces of
equipment; spray dryers, which have been used for many years in manufacturing
processes such as for detergents and powdered milk, and a paniculate control device
(fabric filter or ESP). These systems are capable of greater than 90 percent SO2
removal efficiency. Dry scrubbing has been used successfully with coal-fired boilers
and municipal waste incinerators.
Lime is typically the reagent used in the dry scrubbing process. The addition of
chlorine or ammonia has also been found to increase the removal efficiency under
certain process conditions.1 Most dry scrubbing systems are "wet/dry" processes in
which a lime slurry is created and injected into the spray dryer for reaction with the
SO2 in the flue gas. The paniculate control device removes the resulting solids, and a
small amount of direct S02 removal continues in the fabric filter or ESP.
Description of Typical Dry Scrubbing System
In the dry scrubbing system shown in Figure 6-16, high-calcium pebble lime
with greater than 90 percent available CaO is used as the sorbent. This pebble lime is
stored in a silo and is fed through a weigh-bert feeder into a paste slaker. In the
slaker, the CaO is converted into a 22 percent solids milk-of-lime [Ca(OH)2] slurry.
This slurry is sent through a rotary screen for grit removal and then to a milk-of-lime
storage tank.
From the storage tank, lime slurry is pumped to a slurry mix tank. Here fresh
lime slurry is combined with recycled dry wastes from the system and dilution water to
produce a 35 percent solids slurry. The ratio of fresh lime and recycled material
depends on the outlet SO2 concentration in the stack and the slurry density. If the
outlet SO2 concentration increases, the ratio of fresh lime to recycled product is
increased. This has the effect of increasing the internal stoichiometry (available
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CO
ro
Rue
Gas >
Boiler
, 1
* *
* spray
Dryer
V
^ Baghouse
Fabric
Rlter
x s
\
ToAtn
Stack
Waste ^
Disposal ^
nos
i
^Mi
phere
1
1
-
Rec
Silo
Dilu
Wa
} •
Slaking
Water
««
Slaker and
tlon Milk of
er Lime System
i i
' ^ ' r™
Slurry GrU
M\x Tank Bin
Pebble
Lime
Silo
i —
'
s
Figure 6-16. Typical dry scrubbing system.
-------
alkali/inlet SOJ of the system. A density controller adjusts the relative amounts of
dilution water and recycled material to ensure that the slurry is maintained at the
desired concentration. This slurry is then injected into the spray dryer for reaction with
the sulfur in the flue gas. Injection is accomplished using either pressure nozzles or
high-speed rotary atomizers.
In the spray dryer, the finery divided droplets are brought into contact with the
the flue gas, some carbonation of the lime also occurs. Several factors control the
extent to which the S02 is removed from the gas stream in the spray dryer. The first
of these are the drying time of the droplets and the approach to dewpoint, or adiabatic
saturation. The droplet size and the total amount of slurry control both the drying time
and the approach temperature. It has been found by researchers that an "optimum"
droplet size (50 to 75 micron diameter) is necessary for good removal. Oversize
droplets will dry slowly, and the gas will still be wet by the time it reaches the exit of
the spray dryer. Conversely, if most of the droplets are well below the optimum
diameter, then even though they will have dried by the time they reach the wall, the
drying time will have been so short resulting in insufficient removal of SO2.
The approach temperature of the exit gas to the adiabatic saturation
temperature (dewpoint) is controlled by the total amount of water evaporated in the
dryer itself. Clearly, with a fixed amount of solids (per unit of time) what is being
controlled is not only the outlet gas temperature from the spray dryer, but also the hot
flue gas at temperatures in the range of 250° to 350° F. Two events occur due to the
contact of the droplets with the hot flue gas: 1) the droplets begin to evaporate,
lowering the flue gas temperature, and 2) S02 in the flue gas contacts the droplets
and is absorbed, and a portion reacts with the calcium hydroxide to form calcium
sulfite and water. Some of the calcium sulfite thus formed reacts with oxygen (while
the particle is drying) to form calcium sulfate. The more water injected (in the slurry)
into the sprayer dryer, the closer the approach will be to the dewpoint temperature
and the longer the drying time of the individual droplets. A longer drying time means
that more time is available for the SO2 to be absorbed and reacted with the calcium
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hydroxide. The minimum outlet temperature from the spray dryer is normally
controlled at approximately 20° F above the dewpoint to prevent condensation
problems in the fabric filter or ESP.1
One disadvantage of dry scrubbing systems is that more solid waste is
produced than with wet scrubbing systems. This waste material is not fully oxidized
and must be disposed of properly. Also, there are limitations with the use of ESPs in
some cases that require resistivity modifications to correct ESP performance.
The percentage of sulfur in coal along with the stoichiometry (calcium to sulfur
ratio) affects the performance of these systems. Lower sulfur content of fuel and
higher stoichiometry generally mean a higher S02 removal efficiency.
Inspection Guidelines
Procedures for inspection of dry scrubbing systems are discussed in a
previously mentioned inspection manual.5 Parameters for investigation include visible
emissions, continuous monitors for opacity, S02, HCL, and/or NOX, gas temperatures,
make-up reagent feed rates and recycle rates, paniculate control device conditions,
and process conditions. Potential problems include pluggage and scaling in the feed
system, and general corrosion problems.
6.3.3 Sorbent Injection/Combustion Techniques
Another form of dry FGO involves injection of dry limestone or another sorbent
directly into the burning zone of a boiler or in the air heater or flue gas duct just
downstream of the combustion device. The combustion technique is referred to as
limestone injection into a multistage burner (UMB). The injection of a dry sorbent
downstream of the combustion device is referred to as dry injection.
UMB
The UMB system is a simple retrofit technology for coal-fired boilers of varied
size and is low in cost compared to available FGD alternatives. It has been shown
that limestone calcination conditions that enhance the effective surface area of the
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calcine will, at the same time, improve capture of SO2. In so doing, it is possible to
create momentarily a large surface area (6100 ft2 or more) per ounce of limestone.
Maximizing the presence of high-surface-area lime by using an optimized limestone-
feed grind (particle size), is vital in optimizing UMB performance.
Also, favorable temperature conditions for up to approximately 1 s after
calcination must be provided for sulfation reaction, that is, 1560° to 2370° F, through
appropriate choice of limestone feed location. This selection may be made from
several of the combustion air injection locations, e.g., auxiliary air and overfire air, or
the coal injection location.
Early use of dry-limestone injection into utility boilers gave unsatisfactory results
because of poor SO2 removal and substantial loss of feed caused by dead-burning
and nonuniform distribution. As applied, it also caused other major operational
problems, such as tube fouling and impairment of precipitator performance. More
recent use of low NOX burners, with reduced peak-flame temperature and enlarged
fuel-rich furnace zones, provides an improved means for overcoming these limitations
and successfully applying dry-limestone FGD by injecting the sorbent with either the
staged air or the pulverized coal.
New UMB applications are generally combined with low NOX burners to provide
combined SOj/NO,, control for pulverized coal-fired power plants. Coal is fired in low
NOX burners to minimize NOX emissions. SOX emissions are reduced by a
combination of in-fumace capture and downstream cleanup. The sorbent can be 1)
mixed with the coal prior to the pulverizer, or mixed with the coal after grinding and fed
to the furnace through the burner, or 2) mixed with one of the combustion airstreams
(secondary or tertiary staged air) and then injected into the furnace.
The addition of sorbent may increase the total solids loading in the furnace and
may also cause problems from slagging and fouling. A dust collector downstream of
the air heater removes the sorbent, which may then be sent to a wet or dry contactor
to reduce flue-gas SO2 content further.
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A major advantage of UMB is its low capital cost, which makes it feasible and
attractive for retrofit to existing sources and provides a means for substantial reduction
of SO2 emissions from utility boilers having limited remaining lifetimes. The
disadvantages of UMB include uncertainties as to its feasibility for continuous high-
efficiency SO2 removal because of limited operating experience, and concerns about
its possible impact on boiler reliability.11
Dry Injection
Dry injection in usually associated with combustion of low-sulfur coal requiring
only 70 percent SO2 removal. A calcium- or sodium-based dry sorbent such as
nahcolrte (NaHCO-j) is injected in the air heater or directly into the flue-gas duct
upstream of paniculate collection equipment. The dry sorbent reacts with flue-gas S02
in the duct and in the paniculate collection equipment.
Dry injection has been demonstrated on pulverized-coal-fired boilers equipped
with fabric filters for low-sulfur service using the NaHCO3 sorbent. SO2 removal of 70
percent has been achieved with over 90 percent alkali utilization, with no adverse
impacts on the performance of the fabric filter because of NaHCO3 injection.
However, at low-load conditions with the flue-gas temperature less than 275° F at the
fabric filter, SO2 removal is impaired unless provision is made to predecompose the
bicarbonate by subjecting the NaHCO3 to an intermediate temperature of 450° to
500° F.
The cost of dry injection is substantially less than for wet- or dry-scrubbing
systems, but SO2 removal is also lower. Use of sodium-based compounds may also
enhance NOX reduction. A disadvantage with the sodium-based .compounds is the
need for disposal of solid waste that exhibits greater leaching characteristics than the
calcium-based solid waste.
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6.4 Control of Nitrogen Oxides
As previously discussed, NOX is formed in the combustion process by reaction
of nitrogen from both the fuel and the combustion air with available oxygen. The
important factors affecting NOX formation are: flame and furnace temperature,
residence time in the flame zone, nitrogen and oxygen content of the combustion air,
and the nitrogen content of the fuel. NOX emissions may be controlled (reduced) by
in-fumace combustion modifications and/or flue gas treatment. These methods
include use of low NOX burners, flue gas recirculation, selective noncatalytic reduction
and, selective catalytic reduction. Conversion of an older pulverized coal or stoker-
fired boiler to a fluidized-bed combustor can also be considered a NOX control option.
Inspection of NOX control equipment generally involves monitoring of
combustion process parameters, feed rates, and NOX levels from continuous monitors
or stack tests.
6.4.1 Law NOX Burners
Low NOX burners (LNB) and related in-fumace combustion modifications reduce
the formation of NOX by reducing the excess air, reducing the peak flame temperature,
and/or reducing the residence time of the combustion products. A LNB retrofit can be
expected to reduce NOX emissions by 40 to 60 percent from uncontrolled baseline
levels. LNBs incorporate several combustion techniques, notably low excess air firing
and staged combustion, which may also be used alone as combustion modifications
to reduce NOX formation.
Description of LNB Technology
LNBs employ a variety of mechanical configurations for controlling the mixing of
fuel and air to reduce NOX formation. Designs are available for retrofit modifications
and for new installations. A generalized drawing of an LNB for a pulverized coal-fired
boiler is shown in Rgure 6-17. As fuel-bound nitrogen is released from the coal during
the early stages of combustion, fuel-rich conditions retard conversion to NOX as well
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SPLIT MR
FLOW
THROAT
Figure 6-17. LNB for pulverized coal-fired boiler.12
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as inhibiting NOX formation from nitrogen in the combustion air. Lower temperatures
in the secondary burnout zone also minimize NOX formation from residual nitrogen
contained in the char particles.12 The mixing of fuel and air in a pattern keeps the
flame temperature down and dissipates heat quickly. Whereas conventional burners
mix secondary air with the primary fuel-air stream as soon as they are injected into the
furnace, creating a high-intensity combustion process, LNBs establish distinctly
separate primary and secondary combustion zones, thereby staging the flame at the
burner.
Two basic types of LNBs in use with coal-fired boilers are dual-register burners
and distributed mixing burners. Dual-register burners produce a limited-turbulence,
controlled-diffusion flame through various design details for the mixing device and
flame pattern formation. Distributed mixing burners introduce a portion of the
combustion air through tertiary air ports around the burner periphery to induce staged
combustion. The distributed mixing burners are generally simpler in design than the
dual-register burners. Other LNB designs exist for industrial oil- and gas-fired units
such as those employing gas recirculation and two-stage combustion within the burner
itself.11
Related Combustion Modifications
The same techniques employed in the burners for NOX reduction also can be
used in the furnace, usually as retrofit modifications of older units. Low excess air
(LEA) is a combustion modification technique that seeks to reduce the generation of
thermal-NIC),, and, where applicable, fuel-NOx. This combustion technique reduces the
flame zone concentration of oxygen by limiting the amount of combustion air used in
the system. By reducing the amount of excess air (i.e., excess oxygen), the
concentration of free N2 is proportionally lowered. LEA finds wide application in boiler
NOX control situations.
Staged combustion is a combustion modification technique that seeks to
reduce the generation of thermal NO, by adjusting the fuel/air ratios in dual staged
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combustion systems. In the primary zone the fuel is fired with less than the
stoichiometric amount of oxygen. This creates a fuel-rich situation in the primary flame
zone. This reduces the potential for NOX formation by limiting the amount of available
oxygen and by limiting the flame temperature. The secondary combustion zone is
operated air-rich, where the remainder of the combustion air is introduced. Creation
of NOX in the secondary zone is limited by a reduction in the peak flame temperature
in that zone because of the excess air present Staged combustion is typically
employed in large fossil-fuel-fired boiler applications. The fuel-rich zone is located at
the lower portions of the boiler furnace. The air-rich zone is located in the upper
convection and radiant portions of the boiler. Air-rich conditions are generally
achieved by using overfire air (OFA) ports in this boiler region.
OFA involves the addition of air injection ports above the uppermost burners in
the furnace. In operation, a portion of combustion air, typically less than 25 percent, is
diverted to the ports, creating a slightly fuel-rich primary burning zone and an air
blanket where combustion is completed. This assumes that ample space is available
above the burners for combustion to be completed. NOX reduction potential with OFA
alone ranges up to 30 percent When OFA is properly combined with LNB, NOX
reduction of up to 75 percent is possible.
6.4.2 Flue Gas RecJrculation
Flue gas retirculation (FGR) is a combustion modification technique that
reduces the generation of thermal-NOx. This technique has found applications on
large fossil-fuel-fired boilers and municipal refuse incinerators. In FGR, a portion
(typically 10 to 30 percent) of the flue gas exhaust stream is routed back into the main
combustion chamber. The recirculated flue gas is injected directly into the primary
combustion zone. The recirculation gas stream dilutes the oxygen concentration at
the primary zone and lowers the flame temperature. The combination of these events
reduces the creation of thermal-No,.
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An FGR system retrieves flue gas exiting the combustion chamber and reinjects
it into the zone near the primary burner. The flue gas that is recirculated back is
essentially inert as most of the available oxygen is consumed during the initial fuel
combustion. FGR generally reduces the residence time in the combustion zone.
There is also a potential for reduced flame stability that could result in incomplete
combustion in the primary zone. Property designed systems can improve combustion
efficiency as well as reduce NOX formation. FGR may be used alone or in combination
with LNB for improved NOX reduction. FGR has been especially effective in improving
the operating efficiency of older stoker-fired boilers.
6.4.3 Selective Noncatalytic Reduction
Thermal or selective noncatalytic reduction (SNR) is a post-combustion process
in which ammonia, urea, or another nitrogen based compound is injected into the flue
gas at a temperature range of 1600° to 2000° F to reduce NOX to nitrogen and water.
The reducing agent along with a carrier gas (steam or compressed air) is injected into
the flue gases at a location that will provide for intimate mixing of gases at temperature
and for a sufficient residence time. The effective temperature range may be lowered
to 1300° F by injecting hydrogen along with ammonia. Above 2000° F, a competing
reaction will begin to dominate the process. The competing reaction will oxidize
ammonia to NOX and will create more NOX than was originally present in the flue gas
stream. Below the effective temperature range, ammonia will proceed through the
system unreacted and escape from the exhaust stack; this is referred to as ammonia
slip. Properly designed SNR systems are capable of removing between 40 and 70
percent of the NOX present Advantages in using urea as the reducing agent are that
it is not dangerous to handle and it is less costly to inject as a liquid than ammonia is
as a gas. Adequate mixing of the reducing agent with the flue gas is extremely
important; injection is usually performed in the upper furnace by one or more injection
grids.13
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SNR has been applied to utility and industrial boilers including demonstrations
on several large oil- and coal-fired boilers. SNR is also being used in various
incinerator applications. The process has been less widely used than the selective
catalytic reduction process discussed in the next section.
Several disadvantages exist with SNR including byproduct salt formation, which
is increased with high SO3 levels, as with high-sulfur-coal firing. The effects of ash
content, changing fuel properties, and boiler turn down on SNR have not been fully
addressed. CO emissions have also shown a tendency to rise when using SNR. This
may be controlled by operation in the correct temperature range.
6.4.4 Selective Catalytic Reduction
The selective catalytic reduction (SCR) process is similar to SNR except that a
catalyst is used to make the reactions proceed at a lower temperature range
(approximately 550° - 800° F). Catalysts in use include vanadium, platinum, or titanium
compounds impregnated in a metallic or ceramic substrate. Ammonia is usually
injected at about 5 percent concentration through an injection grid in the flue gas path.
Adequate mixing and control of the ammonia injection rate based on the inlet NOX
concentration are critical. The basic SCR system is shown in Rgure 6-18.
Catalysts lose activity over time, and must be replaced periodically. This
replacement life is anywhere from one to five years and is the main component of SCR
operating costs. Performance of a catalyst degrades because of sintering (reduction
or prot volume, blinding of pores by solid deposits, poisoning by alkali compounds
(potassium, and heavy metals) poisoning by SO3, and/or erosion by fly ash.
Ammonia slip will always occur to a small degree, but this tends to increase
over time. Several unwanted reactions occur when ammonia slip is high. One is that
the catalyst tends to convert SO2 to SO3 in the presence of oxygen. The SO3 then
reacts with residual ammonia to form ammonium bisulfate and ammonium sulfate.
These solids can plug or foul downstream components or create a nuisance blue haze
emission from the stack. Also, it is difficult to accurately measure ammonia
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AMMONIA INJECTION GRID
SCR REACTOR
COMBUSTION
FLUE GASES
CATALYST BED
\
AMMONIA /AIR
MIXER
I &4
LIQUID AMMONIA
STORAGE TANK
DILUTION AIR
Figure 6-18. General SCR system.
DOWNSTREAM
EQUIPMENT
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concentrations in the flue gas with current instrumentation. If not properly controlled,
ammonia slip could be higher than the NOX reduction.13
SCR technology offers the highest potential for NOX reduction at 80 to 90
percent. SCR has been successfully used with oil-, gas-, and coal-fired boilers and
with gas-fired turbines. Use has generally been limited to combustion with low-sulfur
fuels.
6.5 Control of Other Pollutants
For any combustion process, the potential for emissions of other pollutants
besides the paniculate, SO2, and NOX should also be considered. The sources of
other pollutants are from the constituents of the fuel, or in some cases, additives to
the flue gas for control of the primary pollutants. In most cases the level of other
pollutants will be small, and existing control equipment will handle these emissions. In
the case of incinerators and refuse-fired steam generators, characterization of the
waste to be combusted is extremely important in the control of other pollutants.
Pollutants of concern may include products of incomplete combustion (PIC) and
other trace organic compounds, metals such as vanadium, mercury, lead, and 4
cadmium, acid gases such as hydrogen chloride (HCL) and hydrogen fluoride (HF),
and many others depending on the application.
Proper combustion control is critical in control of PICs and organic emissions.
Wet scrubbing techniques provide control of acid gases and other pollutants.
Paniculate control equipment provides control of trace metals attached to fly ash.
Fabric filters may have an advantage over ESPs in control of submicron particles
which may absorb a higher fraction of the heavy metals and organics.14 Condensation
of pollutants at lower temperatures may be advantageous in some cases, and this
favors the use of wet scrubbers, or wet ESPs for extreme cases.
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6.6 References
1. Makansi, J. Acid-Rain Control Systems. Power, February 1990.
2. Power From Coal: Part III, Combustion, Pollution Controls. Power, April 1974.
3. Izant, P., and T. Shiran. Multiple Cyclone Guidelines. Georgia Department of
Natural Resources, September 1985.
4. U.S. EPA. Air Compliance Inspection Manual. EPA-340/1-85-020. September
1985.
5. Richards Engineering. Air Pollution Source Reid Inspection Notebook.
Prepared for U.S. EPA. June 16, 1988.
6. Engineering Science. Wet Scrubber Inspection and Evaluation Manual. EPA-
340/1-83-022. September 1983.
7. PEI Associates, Inc. Operation and Maintenance Manual for Fabric Fitters.
EPA-625/1-86/020. June 1986.
8. Makansi, J. Paniculate Control: Optimizing Precipitators and Fabric Filters for
Today's Power Plants. Power, December 1986.
9. PEI Associates, Inc. Operation and Maintenance Manual for Electrostatic
Precipitators. EPA-625/1-85/017. September 1984.
10. Farber, P. S. Emissions Control Through Dry Scrubbing. Environmental
Progress, August 1986.
11. Elliott, T. C. Standard Handbook of Power Plant Engineering. McGraw-Hill,
Inc., New York, N.Y., 1989.
12. Maulbetsch, J. S., et al. Retrofit NOX Control Options for Coal-Fired Electric
Utility Power Plants. JAPCA, November 1986.
13. Makansi, J. Reducing NOX Emissions. Power, September 1988.
14. Makansi, J. Traditional Control Processes Handle New Pollutants. Power,
October 1987.
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SECTION 7
EMISSIONS AND PROCESS MONITORING
7.1 Continuous Emissions Monitoring
7.1.1 Continuous Emissions Monitoring Requirements
New Sources
Continuous emissions monitoring (CEM) is required for fossil-fuel-fired steam
generators whose construction commenced after August 17, 1971. Various other
source categories are required to install continuous monitoring for either gaseous
pollutants or opacity as specified in Part 60 of Title 40 Code of Federal Regulations
(CFR).
Subparts Da and Db of Part 60 of Title 40 CFR established the new source
performance standards (NSPS) for electric utility and industrial/commercial/institutional
steam generating units, respectively. These performance standards set the emission
limits for nitrogen oxides (NOJ, sulfur dioxide (SOg), and participate matter.
The NSPS regulations also establish the requirements for continuous emissions
monitoring. Certain categories of new sources are required to monitor and record
SO2, NOX, and opacity emissions, plus the oxygen (OJ or carbon dioxide (COg)
concentration of the flue gases where SO2 or NOX emissions are monitored.
Existing Sources
The Clean Air Act of 1970 provides for the regulation of existing sources by the
States. The State's regulations must meet minimum requirements established by the
EPA. Once a State's regulations are approved by the EPA they become part of the
State Implementation Plan (SIP). The SIP establishes the procedures through which a
State plans to meet ambient air quality standards set by the EPA. States must draft
continuous monitoring regulations for fossil-fueled-fired steam generators.
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Only sources that have an emission standard for SO2, NOX, or opacity are
required to have continuous emission monitoring. Existing fossil-fuel-fired plants are
required to be monitored for SO2 emissions only if SO2 pollution control equipment has
been installed and if they have a heat input rate of greater than 250 million Btu/h. A
source must have NOX emissions monitoring if it is within an Air Quality Control Region
(AQCR) that has a control strategy for NOX, has a heat input rate greater than 1000 x
106 Btu/h, and if the source emits NOX at levels greater than 70 percent of the State's
NOX standard. Opacity is required to be monitored only if the source has a heat input
rate of greater than 250 million Btu/h.
7.1.2 CEM Performance Specifications
Performance specifications for the OEMs are included in the NSPS. The
performance specifications give the general characteristics expected of a monitoring
system and provides installation requirements, performance expectations during the
one week (168 h) test period, and statistical methods for the analyzation of the test
period data. Design characteristics that opacity monitors must possess are given in
the specifications. Design characteristics are not given for gaseous emission
monitors. The performance specifications for continuous emissions monitors are given
in Appendix B of Part 60 of the CFR.
7.1.3 Purpose of Emissions Monitoring
The intent of the continuous monitoring regulations is to insure that a source
operator will utilize some type of instrumentation system to monitor the performance of
air pollution control devices. EPA has ruled that compliance monitoring based on the
use of excess emission reports (ERRs) is a alternative to onsite inspections. The
information supplied by OEMs may be used for determining compliance with either 1)
operation and maintenance requirements or 2) emission standards.
The instrumentation systems can decrease control equipment operating costs
while increasing process efficiency. Oxygen, COg, and other combustible monitors
208
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can be used for the determination of the completeness of combustion. The analysis of
O2, CO, and other combustibles along with process rates (steam temperatures, flow
rates and pressure) and general fuel characteristics can be used to determine fuel
load rates and efficiencies of boilers. While both 02 and CO content of flue gases are
indicators of boiler efficiency, CO content can be a direct measure of the
completeness of combustion. Oxygen content is affected by leakage in the boiler's
ductwork; high inleakage could provide a false measure of boiler efficiency.
7.1.4 Gaseous Emissions Monitoring Systems
Continuous monitoring equipment for gaseous emissions consists of two major
categories; extractive systems and in-situ systems. The type of system used often
depends on the emissions being monitored and features of the plant design.
The selection of a monitor also is dependent on EPA criteria for the
Performance Specification Test. A gaseous-emissions monitoring instrument must
meet the following specifications after it is installed on the source:
SO., and NOX O. or COg
Accuracy 20%
Calibration error 5%
Zero drift (2 h and 24 h) 2% of span <0.4% and <0.5% O2 or CO2
Calibration drift (2 h and
24 h) 2.5% of span <0.4% and <0.5% O2 or CO2
Response time 15 min (max.) 10 min (max.)
Operational period 168 h 168 h
Extraction systems draw a sample of gas from the duct or stack by the use of a
pump. The sample is then conditioned for the removal of paniculate matter and water
vapor, and in some cases, removal of specific gases that interfere in the analytical
methods used for the monitored emission. After conditioning, the sample is passed to
the analyzer, which can be located near, or remotely from, the sampling site.
Extraction systems require good maintenance due to the tendency of the sampling
equipment's vulnerability to plugging.
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In-situ systems are monitors that measure gaseous emissions in the stack. The
in-situ systems do not require the modification of the flue gas composition and can
detect gas concentrations in the presence of particulates.
Extractive Analyzers for Gaseous Emissions Monitors
Extractive systems for gaseous emissions can be grouped into three major
categories based on the principles of chemical physics used. The three categories
are absorption spectrometers, luminescence analyzers, and electroanalytical analyzers.
There are a few monitors which do not use absorption spectrometry, luminescence or
electroanalytical methods. There are oxygen analyzers that use paramagnetism,
hydrocarbon monitors that use flame ionization detectors, and SO2 monitors that use
thermal conductivity.
Extractive Analyzers - Absorption Spectrometry. Absorption spectrometers are
based on the principle that molecules of different components of a gas vibrate at
specific frequencies which cancel out equivalent light frequencies in the visible,
ultraviolet and infrared portions of the optical spectrum. Identification of the
components and their concentrations are made by the analysis of the absorbed
frequencies in the spectrum.
Nondispersive Infrared Analyzers
Nondispersive infrared (NDIR) analyzers have been developed to monitor SO2,
NOX, CO, CO2, and other gases that absorb in the infrared, including hydrocarbons.
NDIR instruments utilize a broad band of light that is centered at an absorption peak
of the pollutant molecule of interest This broad band is usually selected from all the
light frequencies emitted by the infrared source, by using a bandpass filter. Table 7-1
gives the band centers for several of the gases found in source emissions.
In a typical NDIR analyzer, such as that shown in Figure 7-1, infrared light from
a lamp passes through two gas cells - a reference cell and a sample cell. The
reference cell generally contains dry nitrogen gas, which does not absorb light at the
210
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TABLE 7-1. INFRARED BAND CENTERS OF SOME COMMON GASES"1
Location of Band
Gas Centers, m
NO 5.0 - 5.5
N02 5.5-20
S02 8 - 14
H20 3.1
5.0 - 5.5
7.1 - 10
CO 2.3
4.6
C02 2.7
5.2
NH3 8-12
CH4 10.5
3.3
7.7
Aldehydes 3.4 - 3.9
Have number, cm"1
1800 - 2000
500 - 1800
700 - 1250
1000 - 1400
1800 - 2000
3200
2200
4300
850 - 1250
1900
3700
950
1300
3000
2550 - 2950
"Table from LBL-1, "Instrumentation for Environmental Monitoring.1
211
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DETECTOR
REFERENCE CELL
Figure 7-1. Simplified schematic diagram of a nondlsperelve infrared analyzer.1
wavelength used in the instrument As the light passes through the sample cell,
pollutant molecules will absorb some of the infrared light. As a result, when the light
emerges from the end of the sample cell, it will have less energy than when it entered.
It also will have less energy than the light emerging from the reference cell. Trie
energy difference is then sensed by some type of detector, such as a thermistor, a
thermocouple, or microphone arrangement
A common problem with analyzers that use a detecting arrangement is that
gases that absorb light in the same spectral region as the pollutant molecule will cause
a positive interference in the measurement For example, water vapor and CO2 will
interfere in the measurement of CO using this arrangement (Table 7-1). These gases
must be removed by some scrubbing system before the sample gas enters the
analyzer.
212
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The advantages of the NDIR-type analyzers are their relatively low cost and the
ability to apply the method to many types of gases. Generally, a separate instrument
is required for each gas, although several instruments have interchangeable cells and
filters to provide more versatility. Problems associated with the method are those that
arise from interfering species, the degradation of the optical system caused by
corrosive atmospheres, and in some cases, limited sensitivity. The microphone type
detectors are sensitive to vibration and often require both electronic and mechanical
damping.
Nondispersive Ultraviolet Analyzers (NDUV) - Differential Absorption
Several available nondispersive systems use light in the ultraviolet and visible
regions of the spectrum rather than in the infrared. To analyze for SO2, these
instruments utilize one of the narrow absorption bands of the ultraviolet absorption
spectrum (Figure 7-2).
2.0
1.8
1.6
8 1.4
1 1.2
GO
§ 1.0
^0.8
<
0.6
0.4
0.2
0.0
NO,
250 300 350 400 450 500
WAVELENGTH (cm)
550 600
Figure 7-2. The ultraviolet-visible spectrum of SO2 and NO2.n
213
-------
NO2 may be determined by taking advantage of its absorption spectrum in the
visible region. The instruments that are designed to work within these regions do so
in a manner somewhat different from the NDIR method discussed previously.
Essentially, the analyzers measure the degree of absorption at a wavelength in the
absorption band of the molecule of interest (280 nm for SO2 and 436 nm for NO2, for
example). This is similar to the NDIR method, but the major differences is that a
reference cell is not used. Instead, a reference wavelength, in a region where SO2 or
NO2 has minimal absorption, is utilized.
This method of analysis is often termed differential absorption, since
measurements are performed at two different frequencies. This method is not limited
to extractive monitoring systems, but it also is used in both in-situ analyzers and
remote sensors.
Figure 7-3 shows a schematic of one of the more typical NDUV monitors.
Instead of using a reference cell (as in the NDIR systems), the instrument uses a
reference wavelength at 578 nm. Light from the mercury discharge lamp passes
through the sample cell to a beam splitter. The beam splitter, actually a
semitransparent mirror, directs the light to two separate photomultiplier tubes. Narrow
bandpass filters allow light of only the specified wavelengths to reach each of the
photomultipliers. The reflected beam passes through a 578 nm filter and is used to
generate the reference signal in the detector. Since the pollutant molecules will
absorb light (SO2 at 280 nm, NO2 at 436 nm), the amount of light or energy reaching
the phototube from the transmitted beam will be less than that reaching the reference
phototube. The resultant photomultiplier signals are amplified and processed to give a
reading for the pollutant concentration. When NO2 concentrations are being analyzed
the transmitted beam passes through a 280 nm filter before it reaches the phototube.
Nitric oxide (NO) does not absorb in the spectral region covered by the instrument
and first must be quantitatively converted to NO2 for subsequent analysis. This is
done sequentially by stopping the flow in the NO2 sample cell, pressurizing it with O2,
214
-------
MEASURING
PHOTOTUBE
SEMITRANSPARENT MIRROR
(BEAM SPUTTER)
SAMPLE CELL
SO2/NOX
CALIBRATION FILTER
I
SAMPLE CELL
S02/NOX
IN OUT
REFERENCE
PHOTOTUBE
LAMP
ELECTRONICS
RECORDER
Figure 7-3. Operation of a differential absorption NDUV analyzer.1
and waiting approximately 5 minutes for the NO to be converted to NO2 by the excess
oxygen. Trie NO is then determined from the difference in the NO2 readings before
and after the reaction with oxygen.
The extractive analyzers using differential absorption have proven to be reliable
in monitoring source emissions. Trie differential absorption SO2 analyzers are
somewhat more sensitive than are the NDIR counterparts. The sequential nature of
the NOX analysis may limit the utility of the method in some cases. As with all
extractive monitoring systems, particulate matter should be removed before entering
the analyzer. It is not necessary, however, to remove water vapor in some of these
215
-------
systems. A heated sample line and heated cell prevent condensation in the analyzer.
Since water does not absorb light in this region of the ultraviolet spectrum, no
interference occurs.
Extractive Analyzers - Luminescence Methods of Analysis.
General
Luminescence is the emission of light from a molecule that has been excited in
some manner. Photoluminescence is the release of light after a molecule has been
excited by ultraviolet, visible, or infrared radiation. The emission of light from an
excited molecule created in a chemical reaction is known as chemiluminescence. The
atoms of a molecule can even be excited to luminescence in a hydrogen flame. Three
types of luminescent processes are used in source monitoring applications. Monitors
utilizing the effects of luminescence can be very specific for given pollutant species
and can have greater sensitivity than some of the absorption or electrochemical
methods. Monitors that use each of these luminescent processes will be discussed in
this section.
Fluorescence Analyzers for SO=
Fluorescence is a photoluminescent process in which light energy of a given
wavelength is absorbed and light energy of a different wavelength is emitted. In this
process, the molecule that is excited by the light energy will remain excited for about
10"8 to 10"4 second. This period of time will be sufficient for the molecule to dissipate
some of this energy in the form of vibrational and rotational motions. When the
remaining energy is reemitted as light, the energy of the light will be lower, meaning
light of a longer wavelength (shorter frequency) will be observed.
Commercially available instruments contain either a continuous or a pulsed
ultraviolet light source (Rgure 7-4). The light from the source is filtered to a narrow
region that is centered near 210 nm in the near ultraviolet range where the SO2
molecule will be excited. The fluorescent radiation is measured at right angles to the
216
-------
210 nm BANDPASS
FILTER
SAMPLE OUT
350 nm BANDPASS FILTER
ELECTRONICS
PHOTOMULTIPUER
TUBE
/
/
Tim ice
1
M*
"•I*
>
^
{•RECORDER
Figure 7-4. Operation of the SO2 fluorescence analyzer.1
sample chamber with a photomultiplier tube. Another filter is used to select only a
portion of the fluorescent radiation for measurement, since interferences can occur
over the range of the fluorescence emission spectrum.
Particulates and water must be completely removed from the sampling stream
before entering the sampling chamber or the instrument will be easily fouled.
Permeation tube dryers generally are used in the instrument itself to eliminate any
remaining water vapor that is not removed by the extractive system.
Chemiluminescence Analyzers for NOK and NO,.
Chemiluminescence is the emission of light energy that results from a chemical
reaction. It was found in the late 1960's that the reaction of NO and ozone (Og), will
217
-------
produce infrared radiation from about 500 to 3000 nm. Monitors that measure NO
concentrations by observing the chemiluminescent radiation select only a narrow
region of the total emission; a fitter is used to select light in the region from about 600
to 900 nm.
NO2 does not undergo this reaction and must be reduced to NO before it can
be measured by this method. Most commercial analyzers contain a converter that
catalytically reduces NO2 to NO. The NO produced is then reacted with the ozone
and the chemiluminescence measured to give a total NO + NO2 (NOX) reading.
Rgure 7-5 shows a schematic typical of this class of instruments.
Ozone is generated by the ultraviolet irradiation of oxygen in a quartz tube. The
ozone is provided in excess to the reaction chamber to ensure complete reaction and
to avoid quenching effects. Since the photomultiplier signal is proportional to the
number of NO molecules, not to the NO concentration, the sample flow rate must be
carefully controlled. The NO2 to NO converter chamber is generally made of stainless
steel or molybdenum to effect the catalytic decomposition. A few monitors on the
market will switch the sample gas automatically in and out of the converter to give
almost continuous readings for both NO and NO2.
Rame Photometric Analyzers for Sulfur Compounds
Another luminescence technique used to detect gaseous pollutants is that of
flame photometry. Rame photometric analyzers are primarily used in ambient air
sampling, but have been applied to stationary source sampling by using sample
dilution systems.
Rame photometry is a branch of spectrochemical analysis in which a sample is
excited to luminescence by introduction into a flame. Instead of using an ultraviolet or
visible light source to excite the SO2 molecule, as in photoluminescence, a hydrogen
flame is used in the flame photometric method to excite the sulfur atom. The excited
atom will in turn emit light in a band of wavelengths centered at about 394 nm, which
is then detected by a photomultiplier tube, as shown in Rgure 7-6. The method is
specific to sulfur, not to SO2. Compounds, such as H2S, SO3, and mercaptans, will
218
-------
NO
2 HEAT
NO + ViO2
FLOW CONTROL
STEP1
NO + NO2
STEP 2
NO +
NO (CONVERTED
FROM NO2)
N02 TO NO
CONVERTER
•SAMPLE IN
03 GENERATOR
SOURCE
DETECTOR
CONTROL
I REACTION CHAMBER
PHOTOMULTIPLIER!
TUBE
SAMPLE EXHAUST
Figure 7-5. Operation of a chemilumlnescence analyzer.1
SIGNAL
219
-------
EXHAUST
i > ' _
PHOTOMULTIPUER
TUBE
Figure 7-6. Operation of a flame photometric analyzer.1
contribute to the ultraviolet emission to give a measure of the total sulfur content of the
sample stream. With the use of scrubbers or chromatographic techniques, selective
determinations can be made of each of these compounds.
Extractive Analyzers - Electroanatytical Methods.
General
Bectroanalytical methods of measurement has found great utility in source
monitoring applications. There are four distinct types of electroanalytical methods
used in source monitoring. These are polarography, electrocatalysis, amperometric
analysis, and conductivity.
A number of monitors based on polarographic and electrocatalytic methods are
available for source monitoring applications. Polargraphic analyzers have been
220
-------
developed for a number of gases and can be inexpensive and portable, ideal for
inspection work. Complete continuous source-monitoring systems also are available
from manufacturers of these instruments. The electrocatalytic or high temperature
fuel-cell method, as it is often called, is used to monitor oxygen only. Both extractive
and in-stack monitors are available using this technique. The methods of
amperometric analysis and conductivity are less widely used and are subject to a
number of interferences. Descriptions of these methods are given here, since a few
instruments employing them are still marketed.
Polarographic Analyzers
Polarographic analyzers have been called voftametric analyzers or
electrochemical transducers. With the proper choice of electrodes and electrolytes,
instruments have been developed utilizing the principles of polarography to monitor
SO2, NO2> CO, O2, H2S, and other gases.
The tranducer in these instruments is generally a self-contained electrochemical
cell in which a chemical reaction takes place involving the pollutant molecule. Two
basic techniques are used in the transducer: 1) the utilization of a selective
semipermeable membrane that allows the pollutant molecule to diffuse to an
electrolytic solution, and 2) the measurement of the current change produced at an
electrode by the oxidation or reduction of the dissolved gas at the electrode. Rgure
7-7 shows a schematic of a typical electrochemical transducer. The generation of
electrons at the sensing electrode produces an electric current that can be measured.
The operation of a polarographic system involves 1) diffusion of the pollutant
gas through the semipermeable membrane, 2) dissolving of the gas molecules in the
thin liquid film, 3) diffusion of the gas through the thin liquid film to the sensing
electrode, 4) oxidation-reduction at the electrode, 5) transfer of the charge to the
counterelectrode, and 6) reaction at the counterelectrode. The electron current
through the resistor then can be measured as a voltage.
221
-------
SAMPLE IN
SEMIPERMEABLE
MEMBRANE
THIN FILM
ELECTROLYTE
SENSING ELECTRODE
BULK ELECTROLYTE
REFERENCE
ELECTRODE
SAMPLE OUT
OUTPUT
Figure 7-7. Operation of an electrochemical transducer.1
222
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Electrocatalytic Analyzers for Oxygen
A method for the determination of oxygen has developed as an outgrowth of
fuel-cell technology. These so-called fuel-cell oxygen analyzers are not actually fuel
cells, but simple electrolytic concentration cells that use a special solid catalytic
electrolyte to aid the flow of electrons. These analyzers are available in both extractive
and in-srtu (in-stack) configurations. This versatility of design is making them popular
for monitoring diluent oxygen concentrations in combustion sources.
The instruments designed to continuously monitor oxygen concentrations utilize,
instead, different concentrations of oxygen gas expressed in terms of partial
pressures. A special porous material, zirconium oxide, serves both as an electrolyte
and as a high temperature catalyst to produce oxygen ions. A schematic of the
electrocatalytic sensing system is shown in Figure 7-8.
When sampling combustion gases, the partial pressure of the oxygen in the
sample side will be lower than the partial pressure of oxygen in the reference side,
which is generally that of air. When such a cell is kept at a temperature of about 850°
C, oxygen molecules on the reference side will pick up electrons at the electrode-
electrolyte interface. The porous ceramic material of ZrO2 has the special property of
high conductivity for oxygen ions. This occurs because the metal ions form a perfect
crystal lattice in the material, whereas the oxygen ions do not, resulting in vacancies.
Heating the zirconium oxide causes the vacancies and oxygen ions to move about.
The oxygen ions migrate to the electrode on the sample side of the cell, release
electrons to the electrode, and emerge as oxygen molecules. If the temperature is
well stabilized and the partial pressure of the oxygen on the reference side is known,
the percentage of oxygen in the sample can be easily obtained.
Amperometric Analyzers
Amperometric analysis is a technique used in a few instruments developed for
both ambient and source monitoring. These analyzers (also called coulometric
analyzers) measure the number of coulombs required to produce a chemical reaction.
223
-------
POROUS
ELECTRODE
t
2r02 POROUS ELECTROLYTE | ELECTRON CURRENT
PREF{02) > PSAMPLE (02)
e
Figure 7-8. Operation of an electrocatalytic oxygen analyzer.1
Typically, amperometric analyzers measure the current in an electrochemical reaction,
such as, 2Br -> Br2 + 2e~. SO2 will affect this reaction in the following manner:
SO2 + 2H2O + Br2 -> H2SO4 + 2HBr.
The instrument measures the change of current flow caused by the change in
the rate of Br2 generation caused by the presence of SO2. However, amperometric
instruments are susceptible to interferences from compounds other than those of
interest. Problems with the necessary chemicals and associated plumbing also have
made the application of these systems somewhat limited in terms of continuous
source monitoring. The technique, however, is useful for the measurement of SO2,
H2S, and mercaptans.
224
-------
Conductimetric Analyzers
Conductimetric analyzers sense the change in the electrical conductivity in
water when a soluble substance is dissolved in it. This change of conductivity is
proportional to the concentration of the substance added and can be measured easily.
The method, however, is not entirely specific, since both SO2, NOX, and acid gases will
change the conductivity of water. Interfering gases, therefore, have to be removed
before analysis.
Extractive Analyzers - Miscellaneous Methods.
Paramagnetic Analyzers for Oxygen
When an oxygen molecule is placed near a magnetic field, the molecule is
drawn to the field and the magnetic moments of the electrons becoming aligned with
it. This striking phenomenon was first discovered by Faraday and forms the basis of
the paramagnetic method for measuring oxygen concentrations.
There are two methods of applying the paramagnetic properties of oxygen in
the commercial analyzers. These are the magnetic wind or thermomagnetic methods
and the magnetodynamic methods:
0 Magnetic Wind Instruments (Thermomagnetic) - The magnetic wind
instruments are based on the principle that paramagnetic attraction of the
oxygen molecule decreases as the temperature increases. A typical
analyzer utilizes a cross-tube world with filament wire heated to 200° C
(Rgure 7-9).
A strong magnetic field covers one half of the coil. Oxygen contained in
the sample gas will be attracted to the applied field and enter the cross-
tube. The oxygen then heats up and its paramagnetic susceptibility is
reduced. This heated oxygen will then be pushed out by the colder gas
just entering the cross-tube. A wind or flow of gas will therefore
continuously pass through the cross-tube. This gas flow will, however,
effectively cool the heated filament coil and change its resistance. The
change in resistance detected in the Wheatstone bridge circuit can be
related to the oxygen concentration.
225
-------
MAGNETIC RELD
OUT
CROSS TUBE
AS
Figure 7-9. Operation of a 'magnetic wind' paramagnetic oxygen analyzer.1
Several problems can arise in the thermomagnetic method. The cross-
tube filament temperature can be affected by changes in the thermal
conductivity of the carrier gas. The gas composition should be relatively
stable if consistent results are desired. Also, unbumed hydrocarbons or
other combustible materials may react on the heated filaments and
change their resistance.
Magneto-dynamic Instruments - The magneto-dynamic method utilizes
the paramagnetic property of the oxygen molecule by suspending a
specially constructed torsion balance in a magnetic field. Here, a
dumbbell-shaped platinum ribbon is used. Since platinum is
diamagnetic, the dumbbell will be slightly repelled from the magnetic field.
When a sample containing oxygen is added, the magnet attracts the
oxygen and field lines surrounding the dumbbell are changed. The
dumbbell then will swing to realign itself with the new field. Light
reflected from a small mirror placed on the dumbbell then can be used to
indicate the degree of swing of the dumbbell, and hence, the oxygen
concentration.
226
-------
All of the commercial paramagnetic analyzers are extractive systems. Water
and paniculate matter have to be removed before the sample enters the monitoring
system. It should be noted that NO and NO2 are also paramagnetic and may cause
some interference in the monitoring method if high concentrations are present.
Thermal Conductivity Analyzers
Thermal conductivity analyzers operate on the principle that different gases will
conduct heat differently. When a sample gas flows over a heated wire, the wire will be
cooled and the resistance of the wire will change accordingly. If the composition of
the sample gas changes, the cooling rate and the resistance of the wire will change to
give an indication of the gas composition. A Wheatstone bridge circuit is generally
used to detect the resistance changes in the heated wire.
Thermal conductivity analyzers have been used to monitor CO2, SO2, and other
gases in process gas streams. A disadvantage to the method is that a flow of
reference gas must always be maintained. Changes in the composition of the gas
stream other than those due to changes in the pollutant level will interfere in the
measurement. Scrubbing systems or some other methods are necessary in such
cases for accurate measurements.
Flame lonization Detectors
The monitoring of hydrocarbons in flue gases is usually accomplished by the
use of flame ionization detectors (FID). The FID measures the ion current increase
resulting from the combustion of hydrocarbon compounds in a hydrogen flame. The
FID can be used to measure methane or total hydrocarbons. The analyzer reports the
hydrocarbons as methane equivalent A schematic diagram of a FID is shown in
Rgure 7-10.
227
-------
VHT
,CUINOIIICAI coiuaon
ELECTRODE (FIO)
COUM IH man
AJB> HYOWitt
Figure 7-10. Flame ionhation detector.2
In-Situ Analyzers for Gaseous Emissions Monitors
Terminology. In-situ gaseous emissions monitors measure gas concentrations
in the stack. In-situ systems are comprised of two major categories of systems:
Cross-stack and In-stack. Rgure 7-11 shows the types of in-situ monitors. Cross-
stack in-situ monitors measure a pollutant level across the complete diameter or a
major portion of the diameter of a stack or duct. Stratification effects are lessened by
the use of cross-stack instruments, since an average reading is taken over a relatively
long sample path. There are two types of cross-stack monitors: single pass and
double pass.
0 Single-pass systems locate the light transmitter and the detector on
opposite ends of the optical sample path. Since the light beam travels
through the flue gas only once, these systems are termed single pass.
0 Double-pass systems locate the light transmitter and the detector on one
end of the optical sample path. To do this.the light beam must fold back
on itself by the use of a retroreflector. The light beam will traverse the
sample path twice in going from the instrument housing to the
retroreflector and back to the instrument Double-pass systems are
easier to service than single-pass systems, since all of the active
components are in one location.
In-stack, in-situ systems monitor emission levels by using a probe that
measures over a limited sample pathlength. All of the commercial optical in-stack
monitors are double-pass systems (the in-stack electrocatalytic oxygen monitor
228
-------
CROSS-STACK
IN-STACK
SINGLE-PASS
DOUBLE-PASS DOUBLE-PASS
POINT. OR SHORT PATH SYSTEMS
Figure 7-11. Types of in-sftu monitors.1
discussed earlier is not an optical system). The pathlength may vary from 5 cm to a
meter. A retroreflector, usually made of quartz, is located at the end of the probe.
The in-stack systems are also termed short-path monitors. The siting of such systems
should follow the same guidelines as those given for extractive systems. The location
should be Chosen carefully so that consistent levels of emissions can be accurately
monitored.
Since particulate matter causes a reduction in light transmission, in-sttu systems
utilize electro-optical techniques to eliminate this effect when monitoring gases. The
electro-optical techniques used are: differential absorption, gas-filter correlation, and
second derivative spectroscopy. The use of the electro-optical techniques in cross-
stack and in-stack monitors is discussed in the following sections.
229
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In-Situ Cross-Stack Analyzers.
Differential Absorption Spectroscopy
The technique of differential absorption spectroscopy used in cross-stack gas
monitor is similar to that used in the NDUV extractive analyzers discussed previously.
A diffraction grating is used in this analyzer to obtain a narrow band of radiation over
which the pollutant molecule will absorb energy. A grating disperses light from an
ultraviolet lamp and light of the appropriate wavelength is detected: one wavelength
for monitoring the pollutant level, another to serve as a reference wavelength (Rgure
7-12).
The ratio of the intensities of the lights of measuring wavelength to the
reference wavelength produces a signal that is related to the pollutant concentration.
Obtaining a ratio of intensities is important in the case of differential absorption
technique in-stack monitors. Particulates in the flue gas will attenuate the amount of
light energy passing through the optical path. This is the principle of measurement in
the opacity monitors. If the light attenuation is the same for the light energy at the
measuring wavelength and at the reference wavelength, each intensity would be
reduced by a constant factor. This satisfies the requirement demanded of all in-situ
monitors that particulates not interfere in the analytical method. Interference caused
by broad-band absorption of water vapor or other molecular species should similarly
cancel out if the measuring and reference wavelengths do not differ too greatly.
A cross-stack monitor set up to measure pollutants on a stack of a given
diameter will give different readings if moved to another stack of a different diameter
and a correction is not made for the new diameter.
Gas-Fitter Correlation Spectroscopy
The gas-filter correlation (GFC) system method is used to monitor CO2, CO,
SO2, and NO. There are a number of optical configurations that can be designed into
a GFC system. The essential feature of such a system, however, is the gas-filter cell
(Figure 7-13).
230
-------
LIGHT
SOURCE
BLOWER
MONOCHROMETER
SYSTEM
DIFFRACTION GRATING
PHOTODETECTOR
CHOPPER
Figure 7-12. Operation of in-srtu differential absorption analyzer.1
LIGHT
SOURCE
BEAM
ALTERNATOR
\ NEUTRAL FILTER
DETECTOR
GAS-FILTER
CORRELATION
CELL
Figure 7-13. Operation of a cross-clack gas-filter correlation spectrometer.1
231
-------
First, consider "zero" condition where there is no pollutant gas in the stack.
Light, generally in the infrared, is emitted from a lamp and passes through the empty
stack to an analyzer where it is split into two separate beams. One beam passes
through a neutral filter and the other through the gas-fitter correlation cell. This cell
contains enough of the gas being analyzed so that most of the energy contained in
the individual absorption lines of the gas will be removed. Light of wavelengths not
absorbed by the specified gas is not removed and passes on to the detector. This
results in a reduction in light energy after the beam traverses the correlation cell.
In most GFC instruments, a neutral density filter is chosen to reduce the
amount of light energy in the other beam by an equal amount. The neutral density
filter reduces the energy from all of the wavelengths in the beam before it reaches the
detector. The gas-filter cell only cuts out energy at the absorption wavelengths. With
the proper choice of a neutral density filter and gas concentration in the correlation
cell, the amount of energy reaching the detector from each beam is the same, and the
system is said to be balanced [Figure 7-14(a)].
Next, consider the condition where pollutant gas is in the stack. The beam
again traverses the stack, but in this case pollutant molecules are present and absorb
light energy at wavelengths corresponding to their absorption spectra. Since the gas-
filter correlation cell was chosen to absorb energy at the same wavelengths, the
absorption is already complete in the correlation cell beam, and the detector will see
the same signal as it did when the stack was dean. The beam passing through the
neutral density filter, however, will have less energy than previously, since light was
selectively absorbed by the pollutant gas in the stack. The difference in energy
between the two beams can be related to the pollutant concentration and is monitored
at the detector [Rgure 7-14(b)].
Particulates will reduce the intensity equally in each of the beams. If the two
signals are ratioed, the effect of particulate matter will cancel out. Note that paniculate
interference is equal in both graphs of part (c) of Rgure 7-14. Molecules with spectral
232
-------
NEUTRAL BEAM
(a)
(b)
oc
O
W
CD
(c)
GAS-f ILTER CELL BEAM
100- —
NOS02
IN STACK
S02 IN STACK
PARTICULARS
IN STACK
WAVELENGTH
WAVELENGTH
Figure 7-14. Absorption principles of a gas-filter correlation analyzer.
patterns near that of the pollutant molecule being measured will not affect the
measurement if they do not "correlate" or overlap with the pollutant spectral pattern. If
there is some overlap, some interference will result.
The GFC method has been found to be a very sensitive and specific method in
the infrared. The ability to monitor a large number of absorption lines provides greater
sensitivity, in some cases, than can be obtained with the differential absorption
technique using only filters. The GFC method is an NDIR method; the light is not
dispersed.
233
-------
In-Situ, In-Stack Analyzers
Second-Derivative Spectroscopy
This monitor analyzes the gas for SO2 and NO in-situ; the gas is not extracted,
but is monitored as it exists in the flue gas stream. The tip of the probe contains the
measuring chamber, which senses across a distance of 10 cm. The instrument
therefore does not measure cross-stack. It is an in-stack point monitor or short-path
monitor. Care should be taken when siting such a system, since a representative
location is required to be monitored by the EPA. The guidelines given for siting of the
probe of an extractive system could be followed in choosing the location of an in-stack
monitor. EPA has not published any specific siting criteria for this technique outside of
the general criteria for representative measuring.
The probe of this system consists of a ceramic thimble surrounding the
measuring chamber. The thimble and a metal V bar in front of the thimble prevent
particulates from entering the chamber. The filtering action of the thimble prevents
particulate matter from fouling the optical surface of the retroreflector shown in Rgure
7-15. Gas diffuses into the measuring cavity and the pollutant can be monitored.
Ultraviolet light is sent from the analyzer section, down the length of the probe,
through the measuring cavity to the retroreflector. A quartz corner cube reflector is
used in this case, and the light is bounced back to the analyzer section. The pollutant
gas only occupies the small measuring cavity and not the entire length of the probe
assembly.
The technique of second-derivative Spectroscopy (SDS) utilizes the spectral
absorption features of a molecule in a manner somewhat different from the methods
discussed for the cross-stack monitors. A diffraction grating selects the specific
absorption wavelengths, but instead of just sitting on a specific wavelength as is done
in differential absorption techniques, a scanner or moving slit scans back and forth
across the central wavelength. In this instrument, light at 218.5 nm, corresponding to
234
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UV UGHT MODULATED
BY GAS ABSORPTION
MIRRORS
NO CHANNEL
SCANNER
ENTRANCE
SUT
STACK
RETROREFLECTOR
RETURNED i!
UGHT .
S02
CHANNEL
SEQUENTIAL
SHUTTERS
DUAL EXIT SLITS
• ULTRAVIOLET
UGHT SOURCE
GRATING
DETECTOR
POROUS
[WINDOW / FILTER
STACK
GAS
DIFFUSION
ABSORPTION
CHAMBER
Figure 7*15. Operation of the second derivative In-slack monitor.
the maximum of an SO2 absorption peak in the ultraviolet, is utilized. The scanner
modulates the light at wavelengths from 217.8 to 219.2 nm, across the width of the
absorption peak (Rgure 7-16).
The results of this scanning are seen at the detector of the instrument. Before
looking at the signal that such a scan of the absorption peak would produce on a
detector, consider the detector signal produced by a scan of a broad band absorption
(Rgure 7-16). Here, there is no strong absorption peak, but a gradual decrease in
transmission (increased absorption) as the light varies from the lowest scanned
wavelength to the highest scanned wavelength.
235
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%
ABSORPTION
100
217.8 run-*- 218.5-
FREQUENCY
219.2nm
Figure 7-16. Ultraviolet light wavelengths scanned by spectrometer moving mask.1
The moving mask scans over the wavelengths of light separated by the
diffraction grating and then goes back over the same wavelengths. One cycle, back
and forth, will take 0.09 second (a period of 0.09 = 11 cycles per second). The
resultant signal seen at the detector will b e in the form of a sine wave or an
alternating current, with a period t = 0.09 second and frequency of 11 cps.
In the following case there is no broad band absorption, but instead, a sharp
absorption peak caused by the presence of an SO2 molecule (Rgure 7-17). Following
the same argument, where the slit moves back and forth in a time period of 0.045
second there is an extra hump in the detector signal (Rgure 7-18). Although the mask
scans the wavelengths at a frequency of 11 cycles per second, maxima will appear at
the detector signal at double the frequency, or 22 cycles per second. Since the
amplitude of the peaks seen at the detector are related to the amount of light
absorption, the amplitude is related to the amount of pollutant gas in the optical path.
236
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RELATIVE
ABSORPTION
SPECTRUM
BROAD BAND ABSORPTION
(NO ABSORPTION PEAKS)
lat-x
MOVING MASK
SCANNING WAVELENGTHS
A-xTOA+x.
BACK AND FORTH
lat-x
lat-x
at+x
at+x
SIGNAL I
DETECTOR
INTENSITY
AT
DETECTOR
I
lat+x
'at-x
TIME
t
at+x
RESULTANT SIGNAL
AT THE DETECTOR
lat-x
Figure 7-17. Scanning a broad band absorption.
-------
RELATIVE
ABSORPTION
SHARP ABSORPTION
(NO BROAD BAND ABSORPTION)
MOVING MASK
SCANNING WAVELENGTHS
A-xTOA+x
BACK AND FORTH
INTENSE
AT
DETECTOR
I
RESULTANT SIGNAL
AT THE DETECTOR
'at+x
TIME !at+x
lat-x
Figure 7-18. Scanning an absorption peak.
-------
Electronically, the concentration of a pollutant is determined by tuning in on the
frequency which is double that of the frequency of movement of the scanner, much
like tuning a radio. A radio station produces a signal at a given frequency and a dial is
adjusted to receive that station, A station with a strong transmitter will produce a
louder signal than a weaker station. In the second-derivative method, the instrument
is tuned to a frequency of 2f, where f is the scanning frequency of the mask. A strong
signal from the detector indicates strong absorption and a high concentration of SO2.
A weak signal at this frequency indicates a lower concentration of S02.
The second-derivative in-stack monitor is limited to monitoring one stack at a
time. Vibration also can be a problem, since extreme cases can affect the optical
system. One of the most common problems in this and similar electro-optical systems
is the failure of electronic components. The complicated circuitry of such systems in
some cases may lead to a high probability of component failure.1
7.1.5 Particular Emissions Monitoring Systems
Opacity and Transmittance
When light passes through a plume or flue some of the light-will be scattered
and adsorbed by particulate matter in the plume. The transmission of the light
through is decreased. A transmissometer is a meter that gives a quantitative value of
the decrease in light transmission.
If light is not able to penetrate through a plume, the plume is said to be opaque
• the opacity of the plume is 100 percent Transmittance and opacity can be related in
the following manner:
Percent Transmittance = 100 - Percent Opacity.
Therefore, if a plume or object is 100 percent opaque, the transmittance of light
through it is zero. If it is not opaque (zero percent opacity), the transmittance of light
will be 100 percent. A plume from a stationary source rarely will have either zero or
100 percent opacity.
239
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The Transmissometer
A transmissometer may be constructed using either a single-pass system
(Rgure 7-19) or a double-pass system (Rgure 7-20). In the single-pass system, a
lamp projects a beam of light across the stack or duct leading to the stack, and the
amount of light transmitted through the flue gas is sensed by a detector. Such
instruments can be made rather inexpensively; however, they often do not satisfy
specific EPA criteria for system zero and calibration checks. The double-pass system
shown in Rgure 4-2 houses both the fight source and light detector in one unit. By
reflecting the projected light from a mirror on the opposite side of the stack, systems
can be easily designed to check all of the electronic circuitry, including the lamp and
photodetector as part of the operating procedure. Most transmissometer systems
include some type of air purging system or blower to keep the optical windows clean.
In the case of stacks with a positive static pressure, the purging system must be
efficient or the windows will become dirty, leading to spuriously high readings. The
development of fiber optics has allowed for the improvement of transmissometers.
The installation of a fiber optic cable between the light source and receiver of a single-
pass system allows the system to measure the zero calibration and dust
accumulations continuously, removing the need for manual adjustments to the system.
Design Specifications
There are essentially seven design criteria that must be met by an opacity
monitor:
1. Spectral Response - The system must project a beam of light with the
wavelength of maximum sensitivity lying between 500 and 600 nm. Also,
no more than 10 percent of this peak response can be outside of the
range of 400 to 700 nm.
240
-------
LIGHT SOURCE
COLUMATING LENS
DETECTOR
==(( RmnwiuiimiiiiiiiiiiipifMiiiHiiiiimiiiimiiiiiiiiiiiiiiiii
COLUMATING
LENS
ROTARY
BLOWER
Figure 7-19. Single-pass transmissometer system.1
LIGHT
BEAM
SPUTTER
ROTARY
BLOWER
Figure 7-20. Double-pass transmissometer system.1
241
-------
2. Angle of Projection - The angle of the light cone emitted from the system
is limited to 5 degrees.
3. Angle of View - The angle of the cone of observation of the
photodetector assembly is limited to 5 degrees.
4. Calibration Error - Using neutral density calibration filters, the instrument
is limited to an error of 3 percent opacity.
5. Response Time - The transmissometer system must detect and identify
95 percent of the value of a step change in opacity within 10 seconds.
6. Sampling - The monitoring system is required to complete a minimum of
one measuring cycle every 10 seconds and one data recording cycle
every 6 minutes.
7. System Operation Check - The monitor system is to include a means of
checking the "active" elements of the system in the zero and calibration
procedures.
Installation Specifications
After an approved transmissometer has been selected by the source operator,
the instrument must be installed and checked for proper operation on the source itself.
There are several points that must be considered when installing a transmissometer:
0 It must be located across a section of duct or stack that will provide a
representative measurement of the actual flue gas opacity.
0 It must be downstream from the paniculate control equipment and as far
away as possible from bends and obstructions.
0 It must be installed in the plane of the bend if located in a duct or stack
following a bend.
0 It should be installed in an accessible location.
0 It may be required to demonstrate that it is obtaining representative
opacity values at its installed location.
242
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These installation specifications are designed so that the transmissometer will
measure the actual flue gas opacity or "an optical volume which is representative of
the particulate matter flowing through the duct or stack." Figure 7-21 shows some of
the problems in particulate matter flow distribution occurring in an exhaust system.
Particulate matter may settle in ducts or stratify in the flue gas stream
depending upon the construction of the exhaust system. In Figure 7-21, the plane of
the bend is formed by the stack and the duct (in this case, the plane of the paper).
If a transmissometer were located perpendicular to this plane, such as at point
A, Rgure 7-21, a large portion of the particulate matter would not be seen. A
transmissometer located at B is in the plane of the bend and will be sensing a cross-
section of the total particulate flow. Location C would not be appropriate for an
opacity monitor, since the monitor would not be in the plane formed by the horizontal
duct and the breeching duct. A monitor at location C also would not satisfy criterion 1
or 2, since settling of particulate matter might not provide a representative sample, and
the location is close to two bends in the exhaust system. Location D would be one of
the most ideal points for monitoring, since the transmissometer would be more
accessible and might be more carefully maintained than if it was in location B.
Location D comes after the control device and does not follow a bend. The only
problem that might arise is the settling of particulate matter in the duct and possible
reentrainment to give unrepresentative opacity readings. An examination of the
opacity profile over the depth of the duct might be necessary to place the monitor at
this point.
The Performance Specification Test
For the Performance Specification Test, the opacity monitors must undergo a 1-
week conditioning period and a 1-week operational test period. In the conditioning
period, the monitor is merely turned on and is run in a normal manner. This is
essentially a bum-in period for the new instrument to eliminate those problems that
one might expect for a new device. In the operational test period, the monitor is run
243
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CONTROL
DEVICE
*Z*:^¥®(
••SP"""'?-fe
•&8ftv I •••••
STACK •.
Figure 7-21. Transmissometer siting.1
for 1 week without any corrective maintenance, repair, or replacement of parts other
than that required as normal operating procedure. During this period, 24-hour zero
and calibration drift characteristics are determined. If the instrument is poorly
designed or if it is poorly mounted, these problems will become evident from the drift
data, and corrective action must be taken. Only zero, calibration drift, and response
time data are necessary for the performance test. The acceptable limits for these
parameters are given in Table 7-2.
244
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TABLE 7-2. OPACITY MONITOR PERFORMANCE SPECIFICATIONS1
Conditioning period - I week
Operational period - 1 week
Zero Drift (24 h) < 2% opacity
Calibration drift (24 h) - < 2% opacity
Response time - 10 seconds
Data Reporting Requirements
After an opacity monitoring system has passed the Performance Specification
Test, it may be used to monitor the source emissions. New sources required to
monitor opacity are required to report excess emissions on a quarterly basis. Since
opacity standards are based on the opacity of the plume at the stack exit, the in-stack
transmissometer data must be corrected to the pathlength at the stack exit.
To satisfy the NSPS continuous monitoring regulations, the opacity must be
measured every 10 seconds. The data must be averaged and recorded every 6
minutes, with a minimum of 24 equally spaced data points being used in the average.
Dividing 24 into 6 minutes gives a measuring time of 15 seconds. This does not
correspond to the minimum required measuring time of 10 seconds. The discrepancy
arises because a visible emissions observer performing EPA Method 9 is required to
average 24 plume opacity observations at 15-second intervals, and the continuous
opacity monitoring reporting requirements were made to correspond to EPA Method
9.
The transmissometer system must be able to record the average of at least 24
equally spaced opacity readings taken over a 6-minute period. Any readings in
excess of the applicable standard (e.g., 20 percent opacity for a coal-fired boiler) must
245
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be reported. Also, a report of equipment malfunctions or modifications must be made.
Although the recorded data do not have to be reported to EPA unless excessive
emissions occurred, the data must be retained for a minimum of 2 years.1
7.2 Control Equipment
7.2.1 Parameter Monitoring
The recordkeeping requirements for NSPS sources are given in 40 CFR Part 60,
Subpart A, §60.7(b),(d). The owner or operator is required to maintain records on any
malfunction of the air pollution control equipment for at least two years. The records
must include the duration of the malfunction. A summary of the parameters to be
monitored for each type of control equipment is given in Table 7-3. While it would
appear that certain types-of control equipment require little or no recordkeeping,
Subpart A, §60.11(d) states that "...owners and operators shall, to the extent
practicable, maintain and operate any affected facility including associated air pollution
control equipment in a manner consistent with good air pollution control practice for
minimizing emissions." To satisfy this provision, monitoring and recording key
parameters not explicitly listed should be performed.
Parameter monitoring usually plays a key role in an overall operation and
maintenance plan, particularly one that stresses preventive maintenance. Such
monitoring also forms the basis for a recordkeeping program that places emphasis on
diagnostics. Typically, daily operating data are reduced to the data on a few key
parameters that are monitored. Acceptable ranges may be established for various
parameters (by use of baseline test data) that require further data analysis or perhaps
some other action if the values fall outside a given range. Care must be taken not to
rely on just one parameter as an indicator, as other factors, both design- and
operation-related, usually must be considered.
246
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TABLE 7-3. CONTROL EQUIPMENT MONITORING REQUIREMENTS FOR NSPS SOURCES3
Control
technique
Parameter
Subparts
requiring monitoring
Wet Scrubber
Incinerator
Afterburner
Pressure drop
Water pressure
Inlet gas temperature
Liquid flow rate
Thermal incinerator
exhaust temperature
Catalytic incinerator
upstream
Combustion zone
temperature
N, T, U, V, W, X, Y, BB, KK, LL, NN
N, Y, BB, NN
Y
LL
BB, EE, MM, RR, SS, TT, WW, FFF
EE, MM, RR, SS, TT, WW, FFF
UU
Electrostatic
precipitator
High velocity
air filter
Fabric filter
Solvent recovery
system
Emission control
system
Inlet gas temperature
Inlet gas temperature
None
Total volume of VOC
solvent recovered
Estimated emission
percentage
VOC concentration of
exhaust
Pressure drop
UU
UU
EE, QQ, RR
QQ
FFF
PP
247
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Recordkeeping Practices and Procedures
Recordkeeping practices for control equipment range from none to maintaining
extensive logs of operating data and maintenance activities and storing them on
computer disks. The data obtained by parameter monitoring is a basis for
recordkeeping, as this type of data usually indicates equipment performance.
Recordkeeping allows plant personnel to track equipment performance, evaluate
trends, identify potential problem areas, and arrive at appropriate solutions. The
magnitude of the recordkeeping activity will depend on a combination of factors, such
as personnel availability, size of the control equipment, and the level of maintenance
required. For moderately sized, well-designed, and well-operated control equipment,
maintaining both daily operating records and maintenance records should not be too
cumbersome; however, only records of key operating parameters should be
maintained to avoid accumulating a mountain of unnecessary information.
Recordkeeping practices can be separated into two major areas, operating
records and maintenance records, each of which can be further divided into
subcategories. When setting up a recordkeeping program, one should give attention
to both areas because they are required to provide a complete operating history of the
control equipment. This operating history is useful in an evaluation of future
performance, maintenance trends, and operating characteristics that may increase the
life of the unit and minimize emissions. Even though recordkeeping programs are site-
specific, they should be set up to provide diagnostic and troubleshooting information,
rather than merely for the sake of recordkeeping. This approach makes the effort
both worthwhile and cost-effective.
Other supplementary records that should be maintained as part of the
permanent file for operation and maintenance include data from air-load tests
conducted on the unit, all baseline assessments that include both process and control
equipment operating data, and data from emission tests. A spare parts inventory
listing should also be maintained, with periodic updates so that parts may be obtained
and installed in a timely manner.
248
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Operating Records
As mentioned previously, the specifics on what parameters will be monitored
and recorded, and at what frequency, will be largely control equipment and site-
specific. Nonetheless, the factors that are generally important in parameter monitoring
will also be the ones recorded as part of a recordkeeping program. These data
probably should be gathered at least once per shift. The greater the frequency of
data gathering, the more sensitive the operators will be to process or control
equipment operational problems, but the amount of data to manipulate also increases.
The optimal frequency may be every 4 hours (twice per shift). If sudden and dramatic
changes in performance occur, if the source is highly variable, if the control equipment
operation is extremely sensitive, or if required by regulatory requirements, shorter
monitoring intervals are required.
In addition to the numerical values of the operating parameters, a check list
should be included to confirm operation of control equipment components and general
physical considerations that can adversely influence control equipment performance.
Maintenance Records
Maintenance records provide an operating history of control equipment. They
can indicate what has failed, where, and how often; what kind of problems are typical;
and what has been done about them. These records can be used in conjunction with
a spare parts inventory to maintain and update a current list of available parts and the
costs of these parts.
The work order system provides one of the better ways to keep maintenance
records. When properly designed and used, this system can provide information on
the suspected problem, the problem actually found, the corrective action taken, time
and parts required, and any additional pertinent information. The system may involve
the use of triplicate carbon forms or it may be computerized. As long as a centralized
system is provided for each maintenance activity, the work order approach usually
works out well.
249
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Another approach is to use a log book in which a summary of maintenance
activities is recorded. Although not as flexible as a work order system (e.g., copies of
individual work orders can be sent to various appropriate departments), it does
provide a centralized record and is probably better suited for a small facility.
In addition to these centralized records, a record should be maintained of all
periodic checks or inspections. These should include the periodic weekly, monthly,
semiannual, and annual checks of the control equipment that make up part of a
preventive maintenance program. Specific maintenance items identified by these
periodic inspections should be included in the recordkeeping process. The items to
be checked are discussed in more details in the following sections concerning specific
control equipment.
Retrieval of Records
A computerized storage and retrieval system is ideal for recordkeeping. A
computer can manipulate and retrieve data in a variety of forms (depending on the
software) and also may be useful in identifying trends. A computerized system,
however, is not for everyone. The larger the data set to be handled, the more likely it
is that a computer can help to analyze and sort data. For a small source with control
equipment that presents few problems and that has a manageable set of operating
parameters to be monitored, a computer system could be very wasteful (unless
computing capability is already available). Also, it is sometimes easier to pull the
pages from a file manually, do a little arithmetic, and come up with the answer than to
find the appropriate disks and files, load the software, and execute the program to
display the answer."
Retention time is also a site-specific variable. If records are maintained only to
meet a regulatory requirement and are not used or evaluated, they can probably be
disposed of at the end of the statutory limitation (typically 2 years). It can be argued
that these records should not be destroyed because if the control equipment (or
process) should fail prematurely, the data preserved in the records could be used as
250
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an example of what not to do. In addition, adequate records may be used to
determine if operating or maintenance problems are design or process related. On
some control equipment in service today, records going back 10 to 12 years have
been kept to track the performance, cost, and system response to various situations
and the most effective ways to accomplish things. These records serve as a learning
tool to optimize performance and minimize emissions, which is the underlying purpose
of recordkeeping. Some of these records may very well be kept throughout the life of
the equipment. After several years, however, summaries of operation and
maintenance activities are more desirable than the actual records themselves. These
can be created concurrently with the daily operating and maintenance records for
future use. If needed, actual data can then be retrieved for further evaluation.
7.2.2 ESP's
Baseline Assessment
Two considerations are necessary in any performance audit or evaluation of an
operating ESP. The first concerns the design factors that are built into the ESP.
These include such parameters as the specific collection area (SCA), number of fields,
number of T-R's, electrical sectionalization, T-R set capacity, design superficial velocity
and treatment time, aspect ratio, and particulate characteristics. This background
information permits the auditor or evaluator to determine what the ESP was designed
to do and whether operating parameters have changed significantly from design. The
second consideration concerns the use of baseline data to establish normal or good
operating conditions. The baseline serves as a reference point, and the types and
magnitude of shifts from baseline conditions are important in evaluating ESP
performance.
Most of the effort expended during the collection of baseline performance
readings is in the area of process and ESP operating data. Process data may include
production weight, raw material and product feed characteristics, operating
temperatures and pressures, combustion air settings, and cycle times (for cyclic
251
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processes). The ESP data will include electrical readings (usually several readings per
run), temperature, gas flow rate, opacity, rapping cycle, and excess air levels.
Baseline data may also include generation of air load and/or gas load V-l curves as
part of the equipment performance record.
Although accurate predictions cannot be made of the exact effect a change in
most of these parameters will have on performance, a qualitative evaluation can often
be made when values deviate from baseline conditions. These deviation values are
useful in parameter monitoring.
Data Collection
Recording T-R Set Data. The primary indicators of performance are the
electrical operating conditions monitored at the T-R control cabinet. These conditions
are reflected in the primary voltage, primary current, secondary voltage, and
secondary current. Even if all these are not monitored (on older ESP's secondary
voltage often is not monitored, and on some newer ones primary voltage and current
are not monitored), the values provided should be recorded.
The level of effort required for this task depends on the size of the ESP and on
the number of parameters monitored. For relatively small ESP's equipped with two to
five T-R sets, very little time is required to record the data. The time required for the
larger and more sectionalized ESP's, however, can be substantial. Computerized data
loggers are becoming more common for the larger ESPs.
The T-R data may be recorded in tabular form with the appropriate data for
each T-R set to track inlet, center, and outlet field performance. Plant personnel will
be looking for certain patterns that are indicators of ESP performance levels.
When the tabular form is less than satisfactory, a more graphical approach can
be taken. Several graphical approaches are available for obtaining these data in a
more useful form. The simplest of these is to draw the ESP plot plan with the relative
position of the plate area of each T-R blocked out and to place the electrical data for
each T-R in the appropriate box (Rgure 7-22). This is useful for evaluating the
252
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3
3
3
3
3
3
3
3
H
G
F
:E
•
;D
•
jc
•
•
i
}B
|A
2
2
2
2
2
2
2
2
H
G
IF
i
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|
»
ID
i
|c
i
B
e
A
i
1
1
1
i
1
1
1
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G
F
E
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C
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A
P
WiE W1E W A E
Figure 7-22. Typical plot plan layout for recording ESP operating data.4
253
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performance of large ESP's and those having fields of different dimensions. When the
data gathering is completed, a look at the values for each field will quickly indicate if
the desired pattern is there. This graphical representation will also show how many
fields are out of service and how severe the problem may be (Rgure 7-23). Total plate
area of out-service for the entire ESP can then be observed over a number of days, as
shown in Rgure 7-24.
Another graphical method is to plot the electrical data on a graph for each field
from inlet to outlet (one for each chamber or grouping of T-R's, if necessary). This
also allows a visual evaluation of the data for characteristic patterns (Rgure 7-25).
Usually, all electrical parameters do not have to be plotted, as secondary current and
voltage are good first indicators. For ESP's with different plate areas per T-R, it may
be useful to normalize the data by dividing the values by the square feet of plate for
each T-R. The resulting current densities should reflect the desired pattern of
increasing current from inlet to outlet. (Note: In some cases, the same ESP will have
T-R sets with energized fields varying from 1.5 to 12 feet in depth. These ESP's may
have been designed this way, or they may have changed over time. In either case,
the non-normalized values may reveal strange electrical characteristics.)
Although both of these graphical techniques are good for collecting and
visualizing electrical characteristics, they have the shortcoming of only depicting ESP
performance during the period when the values are taken; they cannot reflect trends in
performance over time.
Another graphical method that can be used to evaluate long-term changes in
ESP performance involves plotting the values of interest on a time chart (time on x-
axis, voltage/current on y-axis). Two examples of this technique are shown in Rgure
7-26. This chart allows maintenance personnel to note any changes that are occurring
and the rate of change. Although this system of data compilation provides an
excellent visual analysis of operating trends, it does not provide a good means of
comparing voltages and currents directly to see if the desired patterns exist. This
presents a real problem on larger ESP's with many fields, but a relatively minor one on
254
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No. T/R SETS: 24
No. CHAMBERS: 3
No. FIELDS: B
ELECTRICAL FIELDS: 48
DATE: 3/30/81
No. SECTIONS OUT: 5
•A PLATE OUT: 10
-No. T/R SETS: 24
No. CHAMBERS: 3 DATE: 6/ta/8i
No. FIELDS: 8 No. SECTIONS OUT: 17
ELECTRICAL FIELDS: 48 % PLATE OUT: 35
3
3
3
3
3
3
3
3
H
O
r
E
0
c
B
A
2
2
•
2
2
2
2
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W | E W
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i
1
1
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i
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0
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h E
DAILY T/R SET TRIP PATTERN
•
•
•
•
3
3
3
H
0
F
E
D
C
B
3 A
2
2
2
2
2
2
2
2
H
a
F
E
D
C
B
A
1
1
•'
1
1
•'
1
1
W | E W | E W ;
DAILY T/R SET TRIP PATT
H
0
F
E
O
C
B
A
f E
ERN
Figure 7-23. Comparison of T-R set trip patterns for two different days.4
-------
TO
M
2 40
S
<2
jy 20
c
-J 10 —
BOILER R1 10/80
10
ts
DAYS
Figure 7-24. Graphical display of plate area of service over a 30-day period.4
256
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1200
1000 -
2
CO
O NORTH
CENTER
D SOUTH
200 -
FIELD NUMBER
Figure 7-25. Graphical plot of secondary current versus field for a 3-chamber ESP.4
257
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40
35
>30
25
20
mA
.800
600
400
200
40
35
>30
25
20
FIELD 1A
FIELD 2A
FIELD 3A
FIELD 4A
10
15 DAYS 2°
25
30
KV
35 '
30
25
1000
800
600 <
400
200
KV
35
30
25 .
1000
800
600 <
E
400
200
Figure 7-26. Example of graphical displays of secondary current and
voltage versus day of operation.4
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ESP's that have only three or four fields. Another advantage of this graphical method
is that it permits the plotting of other parameters such as gas temperature, O2 content,
process load, opacity, and important feed characteristics. This capacity may provide
correlating data to help diagnose the source of any problems that occur.
Other data that should be collected from the T-R cabinets include spark rate, .
evaluation of abnormal or severe sparking conditions, controller status (auto or
manual), and identification of bus sections out of service. This additional information
helps in the evaluation of ESP performance.
Air Load/Gas Load V-l Curves
In addition to the routine panel meter readings, other electrical tests of interest
include the air load and gas load V-l (voltage-current) tests, which may be conducted
on virtually all ESP's. Air load tests are generally conducted on cool, inoperative
ESP's through which no gas is flowing. This test should be conducted when the ESP
is new, after the first shutdown, and every time offline maintenance is performed on
the ESP. These airload V-l curves serve as the basis for comparison in the evaluation
of ESP maintenance and performance. A typical air load curve is shown in Figure 7-
27. Gas load V-l curves are generated when the ESP is operating. They can be used
to diagnose operating problems within the precipitator.
Generating a V-l curve, a simple procedure, can be done with either primary or
secondary meters. A deenergized T-R set on manual control is energized (but with
zero voltage and current), and the power to the T-R set increased manually. At
corona initiation the meters should move suddenly and the voltage and near zero
current level should be recorded. (It is sometimes difficult to identify this point
precisely, so the lowest practical value should be recorded.) After corona initiation is
achieved, the power should be increased at predetermined increments, (e.g., every 50
or 100 milliamps of secondary current or every 10 volts of AC primary voltage; the
increment is discretionary), and the values recorded. This procedure should be
continued until either sparking occurs, the current limit is achieved, or the voltage limit
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1400
1200
< 1000
w
o
I
o
O
UJ
W
800
600
400
200
SPARKOVER
I
20 30 40 50
SECONDARY VOLTAGE. kV
60
Figure 7-27. Typical air-load test V-i curve for an ESP on a recovery
boiler with normal dust layer.4
260
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is achieved. This procedure is then applied to each T-R. One difficulty that
sometimes arises is activation of the under-voltage trip circuit in the control cabinet.
Either increasing the time for response or decreasing the activation voltage will prevent
the T-R from tripping out during the test. This problem is worse with some T-R
cabinet designs than with others. When conducting gas V-l curve tests the procedure
should be started at the ESP outlet fields and move sequentially to the inlet fields.
The use of the air-load curves enables plant personnel to identify which field(s)
may be experiences difficulty. Comparison with an air-load test run just before a unit
is serviced will confirm whether the maintenance work corrected the problems(s).
Because air-load tests are performed under near identical conditions each time,
curves from different tests can be compared. One of the disadvantages is that the
internal conditions are not always the same as during normal operation. For example,
misalignment may appear or disappear when the ESP is cooled
(expansion/contraction), and dust buildup may be removed by rapping during ESP
shutdown.
The gas load V-l curve, on the other hand, is generated during the normal
operation of the process while the ESP is energized. The procedure for generating
the V-l curve is the same except that gas-load V-l curves are always generated from
the outlet fields first and move toward the inlet. This prevents the upstream flow that is
being checked from disturbing the V-l curve of the downstream field readings.
Although such disturbances would be short-lived (usually 2 minutes, but sometimes up
to 20 minutes), working from outlet to inlet also speeds up the process.
The curves generated under gas load will be similar to air-load curves. They
will generally be shifted to the left under gas load conditions, however, and the shape
of the curve will be different for each field depending on the presence of paniculate in
the gas stream (Rgure 7-28).
The pattern in the V-l curves under gas load conditions is similar to what is
shown in Rgure 7-28. As shown, the gas-load curve is to the left of the air-load curve.
Both curves shift to the left from inlet to outlet (characteristic of most ESP's operating
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GAS-LOAD
Figure 7-28. Comparison of typical air load and gas load V-l curves.4
under moderate resistivity). Hie end point of each curve is the sparking voltage/
current level, or maximum attainable by the T-R. These points represent the
characteristic rise in current from inlet to outlet that is normally seen on the ESP panel
meters. Problems characterized by the air load curves will normally also be reflected
in the gas-load curve, but some problems may show up in one set of curves and not
in the other (e.g., high resistivity and some misalignment problems).
Other possible data that could aid in the evaluation of trends and long-term
performance include a plot of wire failures within the ESP and their frequency,
frequency of hopper pluggage, and a plot of the percent of the ESP deenergized on a
daily basis. This last item can be used in combination with opacity and electrical data
to define when maintenance work is needed and whether it is addressing the
problems encountered, and to aid in the scheduling of routine and preventive
maintenance.
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It is evident that obtaining good operating data and maintaining good records
help in the maintenance of ESP performance by providing a historical data base that
can be used to evaluate daily operating performance. Recordkeeping alone, however,
will not guarantee satisfactory long-term performance. Analysis of the data and an
understanding of the fundamental design features and limitations and the operating
characteristics of the ESP are necessary to correct minor problems before they
become major.
7.2.3 Fabric Filters
Baseline Assessment
Fabric filter baseline conditions generally can be established during the unit's
initial performance test. The following key parameters should be examined during the
baseline assessment:
1. Gas volume - If too high, it can blind the bags; if too low, it can cause
dust dropout in the ducts.
2. Temperature - If too high, it can destroy the bags and/or gasketing; if
too low, it might cause excursions below the dewpoint.
3. Pressure drop - A pressure drop that is too high indicates potential bag
blinding or high gas flow; one that is too low indicates bag failure.
4. Dust load - If too high, it may exceed the unit's capacity to convey the
dust from the baghouse; if too low, it may cause excessive emissions
after each cleaning cycle.
5. Particle size - Particles that are too fine can cause blinding of the bags or
excessive emissions.
Baseline conditions should also be established for the process that the
fabric filter controls. Process data may include production weight, raw material and
product feed characteristics, operating temperatures and pressures, combustion air
settings, and cycle times (for cyclic processes).
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Date Collection
For most fabric filter applications at combustion sources the most useful
operating parameters are the opacity, the pressure drop across the filter material, and
the temperature data which is important for evaluation of the impact of high
temperature excursions or condensation. The frequency for collection of these data
will depend on several factors, but as a general rule, these data should be checked
once a day. Continuous strip-chart recorders for opacity, pressure drop, and
temperature can be very useful for indicating daily trends. The use of continuous
strip-chart recorders is often limited to larger sources. Most small sources that use
fabric filters have no opacity monitors. Temperature at the fabric filter inlet should be
monitored and recorded continuously.
In the absence of continuous monitors/recorders, visible emission
characteristics and onsite instrumentation must be observed periodically and the
results evaluated. Opacity observations are very useful at most applications because
opacity plumes at a properly operated and maintained fabric filter are generally very
low, except when a condensible plume is present. A relatively continuous elevated
opacity level can be indicative of the presence of major leaks and tears in the filter
bags. Pinhole leaks are also usually discernible by an increase in opacity after
cleaning of the bag(s). These kinds of plume characteristics are generally discovered
by continuous observation of the plume as opposed to once every 15 seconds as
required by EPA Reference Method 9. Whereas the use of Method 9 for determining
average opacity is sufficient for enforcement purposes, changes in opacity that result
from minor leaks may be missed when this method is used. In general, continuous
observation of the plume to note any changes is better suited for evaluating
maintenance requirements, as problems in certain rows or modules can be identified
by this method.
The pressure drop across the fabric filter gives an indication of the resistance to
gas flow and cleaning effectiveness. The pressure drop usually varies with the square
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of the gas volume flow through the fabric, but it will also vary with the thickness of the
dust cake and the amount of material permanently retained by the fabric filter. This
value will depend on various factors. The pressure drop of a fabric filter generally falls
within a "typical" range, and it is this range that is important. The recorded value
should fall within the general operating range for the unit. Any changes in the
pressure drop, whether gradual or sudden, may indicate the need for maintenance. If
the cleaning cycle is initiated by a specified pressure drop the pressure drop will not
change, but the time between cleaning cycles will be shortened. When a large
number of fabric filters must be evaluated, forms may be printed that include the
typical or baseline values so that an immediate comparison can be made. For large,
multicompartmented filter systems, recording the pressure drop across individual
modules may not be necessary because pressure drop tends to equalize across all
the modules.
For all combustion units, operating temperature is of particular concern and the
use of continuous strip-chart monitors is highly recommended. Sometimes bag
damage is not evident until days or weeks after a temperature-related incident. This
can be troublesome to maintenance personnel because failure to detect the cause of
deteriorating bags can result in unusually high maintenance costs. Although both inlet
and outlet monitors are recommended, measurement of only the inlet gas temperature
is usually sufficient. Temperature readings recorded during the acquisition of other
data (opacity, pressure drop, production rate, etc.) are usually of little use by
themselves, since they are not made continuously.
Maintenance records are also useful in evaluating fabric filter performance. A
record of bag failures and/or bag replacement can be especially helpful. In a typical
application with newly installed bags, random bag failures shortly after startup is not
uncommon. These are usually caused by an occasional defective bag and by
installation problems. After these failures occur during the shakedown period, bag
replacement requirements are expected to be minimal until the bags near the end of
their useful lives. Records of bag replacement location may reveal the presence of
265
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failure patterns resulting from design or operating practices. These patterns may
suggest a possible cause and solution that will improve performance and reduce
maintenance cost in the long run. An example of a bag replacement record is shown
in Rgure 7-29.
Another characteristic that bears examination is the physical property of the
dust and any associated changes that may have occurred. Although site-specific
factors control the characteristics of the dust to be controlled, two general
characteristics that can influence fabric filter performance are particle size distribution
and the adhesive characteristics of dusts. Changes in particle size distribution may
increase abrasive wear if the particles increase in size. On the other hand, a shift to a
smaller particle size range may increase penetration (bleed-through) and blinding.
Changes in process operating characteristics pan sometimes cause significant shifts in
particle size. Changes in adhesive characteristics can also result from variations in
process operation conditions (e.g., some combustion sources can produce "sticky"
carbon particles if combustion characteristics are poor) or fluctuations in temperature
that produce dewpoint problems. Where such changes are possible, routine
monitoring of dust characteristics may be prudent to prevent excessive or unexpected
maintenance problems. High carbon ashes can also lead to fires in the fabric filter
which will destroy the bag integrity.5
7.2.4 Wei Scrubbers
Baseline Assessment
Wet scrubbers should be evaluated for baseline data by the examination of the
following key parameters:
1. Pressure drop
2. Gas temperature
3. Liquid flow rate
4. Gas flow rate
5. Gas velocity
6. Opacity
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111
17
14
12
11
10
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ooo
ooo
ooo
ooo
ooo
ooo
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c B A
OOOO'
•OOO"
OOOO'5
OOOO"
OOOO"
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00*0°
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18
17
16
13
13
12
11
10
9
8
7
6
5
4
3
2
1
Key: B •
No
C
ABC
• Broken/Hole
Letter - Ring
- Collapse
Figure 7-29. Typical bag replacement record.
267
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Baseline data for the process served by the wet scrubber should also be established.
Operating factors can affect particle size distribution, vapor concentration and gas flow
rates at the scrubber inlet and, thus, the efficiency of the scrubber.
Data Collection
The static pressure drop through a wet scrubber is used extensively to evaluate
performance. In order to properly define the pressure drop, a sketch of the scrubber
system is helpful in showing where the inlet and outlet static pressures are measured.
The gas stream temperatures should be measured at the same locations where
the inlet and outlet static pressures are measured. The gas stream temperatures are
used to convert the static pressures back to a standard gas density.
A low pressure drop across a scrubber, relative to baseline levels at the same
process operating conditions, is usually a function of the liquid to gas ratio at any
given gas velocity. The gas velocity, through a scrubber, may be a function of the gas
flow rate only, as in the case of tray-type, spray tower, or simple Venturis, or it may be
a function of the gas flow rate and the position of a throat mechanism (damper, vanes,
or plumb bob). A movement of the throat mechanism can cause a decreased gas
velocity, which will cause a linear decrease in the pressure drop.
The monitoring of liquid flow rates allows the operator to insure that the liquid
distribution system is working properly. The maintenance of the proper liquid to gas
ratio insures that the scrubber performs as designed.
The quality of the scrubber liquid should also be monitored for pH, solids
content and surface tension. The quantities of antifoaming agents, surfactants, and
flocculants or pH modifiers added to the liquid should also be recorded.
7.2.5 Mutticyclones
Baseline Assessment
Baseline data for murticydones should be taken when the collector is in good
physical condition. The following parameters should be examined and recorded
during the baseline assessment:
268
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1. Inlet and outlet static pressures
2. Inlet and outlet gas temperatures
3. Inlet and outlet oxygen concentrations
4. Stack opacity.
The baseline data should be taken at various boiler loads since the gas flow rate
affects all of the parameters above.
Data Collection
The most important operating parameter for multicyclones is the pressure drop
across the collector. The pressure drop across the collector provides an indication of
the gas volume being handled. It may also serve as an indicator of the overall
collection efficiency. As mentioned in Section 6.2.1 the efficiency of a multicyclone
generally increases as the pressure drop increases. The accumulation of solids
around the inlet turning vanes of the multicyclone will cause a rise in pressure drop
that is noticeably above the normal range. If the outlet tubes experience erosion, the
pressure drop at a given boiler load will be substantially below the normal range. Low
pressure drops can also occur due to weld or seal problems around the clean-side
tube sheet. The gaps provide a direct short circuit through the collector.
The measurement of gas temperatures and oxygen before and after the
collector can provide an indication of air inleakage into the system. An increase in
oxygen content with a simultaneous decrease in gas stream temperature is indicative
of ambient air infiltration. Normally, the gas temperature drops are in the range of 10°
to 30° F and oxygen increases are in the 0.5 to 1.0 percent range. Gas temperature
drops and oxygen increases outside of these ranges can indicate worsening air
infiltration problems. .
The measurement of temperature also can allow the operator to determine if
acid dew point condensation is occurring within the collector. Acid condensation can
cause corrosion in the collector or create the development of material buildup within
the collector.
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The collection of maintenance records for multicyclones is not quite as useful as
with other control equipment Tube sheet location failure records should be
maintained to determine if repeat failures are occurring at the same locations. Report
failures could be indicative of particle stratification and/or gas maldistribution.119
Another characteristic that bears examination is the physical property of the
dust and any associated changes that may have occurred. Although site-specific
factors control the characteristics of the dust to be controlled, two general
characteristics that can influence performance are particle size distribution and the
adhesive characteristics of dusts. Changes in particle size distribution may increase
abrasive wear if the particles increase in size. On the other hand, a shift to a smaller
particle size range may decrease collector efficiency since multicyclones are relatively
ineffective for particles in the 0.5 to 2 micron size. Changes in process operating
characteristics can sometimes cause significant shifts in particle size. Changes in
adhesive characteristics can also result from variation in process operation conditions
(e.g., some combustion sources can produce "stick" carbon particles if combustion
characteristics are poor) or fluctuations in temperature that produce dewpoint
problems. Where such changes are possible, routine monitoring of dust
characteristics may be prudent to prevent excessive or unexpected maintenance
problems.
7.2.6 Dry Scrubbers
Baseline Assessment
The baseline data for a dry scrubber should be included in the following
parameters:
1. Absorber exit gas temperatures
2. Gas flow rate
3. Feed rate of lime into slaker
4. Row rate of the slurry to the absorber atomizer
5. Row rate of the solids recycled.
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The operation of a dry scrubber is dependent on the sulfur dioxide concentration of
the gas stream. Baseline data should reflect fuel loading rates and fuel sulfur content
that would be experienced during normal operation.
Data Collection
The efficiency of a dry scrubber is dependent on the stoichiometric proportions
of alkali to sulfur dioxide. Therefore, the flow rate of slurry to the absorber and the
gas flow rate should be monitored to insure that SO2 removal is satisfactory. The
amount of alkali in the slurry available for reaction with the S02 is dependent on the
amount of lime feed into the slaker as well as the amount of calcium hydroxide and
calcium sulfite in the recycled slurry. Monitoring of these parameters allows the
operator to insure that absorber efficiency is maintained while controlling the purchase
costs for lime.
.The exit gas from the absorber is monitored to insure that the temperature is
being held at a controlled point above the adiabatic saturation temperature.6 This
requires the recording of the wet bulb and dry bulb temperatures of the exit gas.
7.2.7 Limestone Injection/Combustion Techniques
Baseline Assessment
The key parameters to be monitored for the baseline assessment of a limestone
injection into a multistage burner (UMB) are:
1. ' The loading rate of coal
2. The loading rate of limestone
3. Opacity.
Since UMB is a direct combustion technology, baseline data should be collected for
various process rates.
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Data Collection
The introduction of limestone into the furnace with pulverized coal increases the
total solids loading of the furnace. This will increase paniculate emissions in the exit
gas stream. This increase can result in the overloading of any existing participate
control equipment. Opacity monitoring will insure that paniculate control equipment is
functioning as intended. The loading rates of coal and limestone should be
stoichiometrically related. Monitoring of the loading rates of coal and limestone will
insure that the SO2 removal efficiency is maintained.
7.2.8 Low-NOx Burners
Baseline Assessment
Since the control of NOX is directly related to fuel loading rates, baseline data
for low-NOx burners should be collected under varying process rates. The parameters
which should be monitored are:
1. Fuel loading rate
2. Primary air flow
3. Secondary air flow
4. Tertiary air flow.
Data Collection
The monitoring of primary, secondary, and where applicable, tertiary air flows
will permit an assessment of the proper operation of the burner and thus, low-NOx
formation. Excess primary flow will reduce the effectiveness of the burner.
7.2.9 Flue Gas Recirculation
Baseline Assessment
The key parameters to be monitored during the baseline assessment of flue gas
recirculation systems are:
1. Fan curves
2. Gas temperatures
3. Damper settings.
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The baseline data should be gathered for all expected process rates that will
encountered during normal operation of the system.
Data Collection
The flow rate of gas recirculated back to the furnace is dependent upon the
systems fan. Monitoring of the fan settings and measurement of the pressure drop
through the fan will allow for the determination of the gas flow rate. The gas flow rate
will have to be corrected for gas density by measurement of the gas temperature. The
damper setting of the furnace will determine the oxygen flow rate into the furnace.
Recording of the settings, along with the gas recirculation rate, will permit the
determination of combustion conditions inside the furnace.
7.2.10 Selective Noncataiytic Reduction
Baseline Assessment
The key parameters to be monitored in the collection of baseline data are:
1. Gas temperature
2. Injection rate of ammonia.
The use of a SNR process requires the attainment of good baseline data for the
determination of the flue gas NOX concentration. Data should be collected for varying
process and fuel loading rates.
Data Collection
The SNR process requires the flue gas temperature to be in the 1600° to 2400°F
range to reduce NOX to nitrogen and water.7 Gas temperature should be monitored to
insure the proper operation of the system.
The reduction of NOX is a stoichiometric process with the injection rate of
ammonia being dependent on the NOx concentration of the flue gas. Monitoring of
the injection rate will insure that maximum reduction of NOX is achieved while
preventing emission of ammonia from the stack.
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7.2.11 Selective Catalytic Reduction
Baseline Assessment
Data collected for the baseline assessment of a selective catalytic reduction
(SCR) process should include:
1. Injection rate of ammonia
2. Temperature of flue gas.
The use of a SCR process requires the attainment of good baseline data for the
determination of flue gas NOX concentration. Data should be collected for varying
process and fuel loading rates.
Data Collection
The reduction of NOX in a SCR process occurs at temperatures around 600° to
750° F.7 Gas stream temperature should be monitored to insure that process
temperatures are maintained.
The reduction of NOX is a stoichiometric process with the injection rate of
ammonia being dependent on the NOX concentration of the flue gas. The monitoring
of the injection rate will insure that maximum reduction is achieved while preventing
emissions of ammonia out of the stack or into other control equipment where it can
present problems.
7.3 Process Rates
Process data provides useful information concerning operating rates and
characteristics that may be used to evaluate performance of a combustion source or
equipment. The type of process data will vary with the industrial source category that
is utilizing the combustion process. For example, cement clinker production only has
meaning in the context of a cement kiln, whereas black liquor firing rate only applies in
the kraft recovery boiler operation. Process data provides information on how the
combustion process is operating in the present as well as providing a historical
perspective on the performance of the combustion source in the past.
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Procedures to gather and record process data are varied. They range from a
manual recording of a few key parameters on an hourly or semi-hourly basis to a full-
scale data logging computer with routine, systematic storage of information and event
interrupt capability to record data if certain events or alarms are triggered all
automatically. Continuous strip charts may be used to record data. In reviewing strip
charts it is necessary to have them properly time synchronized so that meaningful
interpretation of the data is possible. This usually requires daily time stamping of the
strip charts. The recordkeeping practices are very site specific. There may regulatory
requirements for minimum data gathering and reporting but seldom are the
procedures that will be used to gather the data specified.
Operating data that should be recorded are the same general values that are
used in evaluating combustion process performance. 'Data that should be collected
from non-steam generating combustion sources (e.g., cement kilns or blast furnaces)
include the raw material feed rate and/or production rate of the product, fuel feed rate,
temperature conditions of the exit gas stream at the inlet of air pollution control
equipment, and combustion gas composition at the same point. The composition of
the feed and product material may also be of use in certain applications such as
cement manufacturing. Fuel, feed and product characteristics should be obtained
periodically so that these parameters may be related to other operating parameters. It
is very important to determine the fuel feed rate and fuel conditions in most of these
processes that do not produce steam as a result of combustion.
Steam producing operations have another set of operating parameters that
should be measured and recorded. The fuel feed rate is also an important parameter
to obtain for these processes. The fuel feed rate can be determined by estimating the
thermal efficiency of the combustion process and estimating the heat output of the
steam generation cycle as outlined in Section 2 and 5. The steam flow rate and steam
conditions are necessary, as is the feedwater flow rate and the feedwater conditions.
The steam and feedwater conditions are defined by their respective temperatures and
pressures to determine the enthalpy from steam tables. The net heat increase from
275
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the feedwater to steam conditions, plus any reheat energy added, represents the heat
output of the boiler. Heat input can be determined from the heat output and the
thermal efficiency. As discussed in Sections 2 and 5 heat input is useful in
determining gas volume to the equipment as well as determining other boiler related
parameters.
Different techniques are used to measure and report process operating
parameters. Most techniques convert the measurement method to an electrical signal
that is transmitted to the control room display panels, where they may be displayed on
instruments and or strip chart recorders calibrated. The methods used to determine
the operating parameters that are converted in to electrical signals are varied
depending upon the material being measured and its physical characteristics. Solid
materials may be weighed by a weigh belt or weighing feeder that converts deflection
of a belt or beam or into a weight equivalent electrical signal. Temperatures are
typically measured by thermocouples that produce an electrical voltage. Pressure
readings are usually obtained by the deflection of a diaphragm/spring arrangement.
Row rates of liquids may be obtained from flow meters that generate a pressure
differential which is related to the volumetric or mass flow rate (e.g., venturi or orifice
meters). The pressure differential can then be converted to an electrical signal
corresponding to a volumetric or mass flow rate. The volumetric flow rate may also be
determined from noncontact methods such as Doppler flow meters, where the
frequency shift due to the flowing fluid can be related to the velocity of the fluid
through the pipe (analogous to radar).
These instruments and there converters should be checked periodically for
proper operation and calibration. It is usually possible to check the display
instrumentation for proper range response by providing known voltage or current to
the input line. Signal conversion equipment can also be checked periodically. Some
equipment can only be checked visually to ascertain that the physical condition of the
measuring equipment is within nominal design specifications. For example, it is
extremely difficult to calibrate large steam flow meters through physical measurement
276
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of the steam flow rate, because equipment are usually not available to contain and
measure the quantity of material that passes through the flow meter. The meter can
be precisely measured, however, for diameter and relative location of pressure
measurement taps. These measurements are then related to operating characteristics
developed for smaller meters whose operation can be calibrated.
The need for process instrumentation for proper operation of combustion
equipment cannot be stressed enough. Furthermore, equipment that has been
installed requires a maintenance plan to assure reliable data gathering. As will be
discussed in Section 8, the lack of instrumentation or the failure to maintain the
equipment installed can result in costly operating conditions.
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7.4 REFERENCES
1. U.S. Environmental Protection Agency. Continuous Air Pollution Source
Monitoring Systems. EPA-625/6-79-005. June 1979.
2. Lodge, J. P. Jr., ed. Methods of Air Sampling and Analysis (3rd ed), Lewis
Publishers, Inc. Chelsea, Michigan, 1989.
3. U.S. Environmental Protection Agency. Air Compliance Inspection Manual.
EPA-340/1 -85-020. September 1985.
4. PEI Associates, Inc. Operation and Maintenance Manual for Electrostatic
Precipitators. EPA-625/1-85/017. September 1984.
5. PEI Associates, Inc. Operation and Maintenance Manual for Fabric Fitters.
EPA-625/1-86/020. June 1986.
6. Farber, P. S. Emissions Control Through Dry Scrubbing. Environmental
Progress, August 1986.
7. Makansi, J. Acid-Rain Control Systems. Power, February 1990.
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SECTION 8
COMBUSTION PROBLEMS
8.1 Introduction
This section discusses the most common problems encountered with
combustion sources. These problems affect not only the efficiency of the combustion
process but may detrimentally affect any air pollution control equipment that follows .
the combustion process. Even when equipment is not affected in a detrimental
manner, a poorly operated combustion process can have significant, if unexpected,
impacts.
Combustion related problems can be divided into three broad categories, 1)
problems with excess air, 2) problems due to fuel and/or ash characteristics, and 3)
boiler maintenance problems. Some of the specific problems which, will be discussed
can be placed in more than one category. Although the calculations for combustion
gases and efficiency will help in many cases, these values are .only indicators and
must be considered along with other information that is available to determine what
combustion problem(s) exist and the corrective action to be taken. This listing of
problems cannot be all inclusive as the number of problems can be as numerous as
the number of combustion sources and fuels used at each one. The most common
problems, however, have been highlighted in this section.
8.2 Excess Air Problems
One of the most common problems associated with poor or less than optimum
.combustion performance is associated with excess air. Problems in maintaining
excess air at proper levels are easy to overlook because it is often necessary to
provide a limited amount of excess air and most often too much air is provided. For
some combustion processes sufficient fan capacity, pollution control removal
efficiency, and in the case of boilers, steam capacity may mask any problems.
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Problems with low excess air are seen much more infrequently because excess
carbon loss becomes apparent in the form of carbon particles, increased carbon loss,
and increased CO levels in the combustion gas products. In some cases the air
related problem is due to improper distribution or mixing of combustion air even
though the flue gas composition indicates that the proper excess air level is being fed
to the combustion process.
8.2.1 Low Excess Air
Low excess air is usually desirable because it can result in the most efficient
combustion with the least quantity of combustion products generated and it produces
the highest thermal efficiency in boiler applications. Low excess air conditions require
much more careful attention to the combustion process, particularly for solid fuels.
Low excess air conditions below design limits (or air-starved conditions) can exist
because the combustion controls do not respond fast enough to fuel conditions when
the combustion process is being controlled to very low excess air levels. The
combustion process does require time to bum to completiion particularly under low
excess air conditions. The flames formed under low excess air conditions can be very
long and "lazy" rather than short and crisp. These conditions may allow flames to
impinge onto cool surfaces and stop the combustion process resulting in
carbon/combustible losses. Carbon loss can result in a paniculate that is high in
carbon content, is sticky, or is very fine. Due to low excess air levels these particle
characteristics can make the products of incomplete combustion extremely difficult to
capture, or worse, may cause severe damage to the air pollution control equipment.
Another problem with low excess air combustion is related to ash
characteristics. This is primarily related to solid fuels firing but problems may be seen
with some ashes produced by combustion of residual oils. The heat release rate in a
boiler is related to fuel characteristics. With the exception of boilers designed to
produce a liquid slag from the ash, the heat release rate and furnace volume should
be designed to prevent the ash from becoming molten in the radiant zones of the
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furnace. The temperature at which this occurs is generally the ash fusion temperature
which is dependent upon the ash composition. By designing for an expected range of
ash characteristics, the local heat release rates per unit area and per unit furnace
volume are intended to limit the problem with slagging. For most ashes the ash fusion
temperature for reducing conditions (oxygen limited or deficient) is generally lower
than that for oxidizing conditions. Sometimes this difference is as much as 250° F
between the oxidizing and reducing conditions. In suspension firing of fuel this can
produce a liquid or a partially liquified ash particle that, when it contacts a cooler
surface such as a furnace wall tube or superheater tube, cools and sticks to the
surface. This situation, can make it very difficult to remove ash deposits from heat
transfer surfaces and reduces thermal efficiency. It may also cause localized heat or
corrosion damage to the tubes and eventually lead to tube failure. This is one lesson
that has been learned by experience in the operation of MSW incinerators that are
recovering the heat of combustion through steam generation. The combination of acid
gases (i.e., chlorine), low ash fusion temperature of the ash, and reducing gas •
conditions due to low excess air combustion, has proved disastrous in some of these
applications. In addition to the difficulty in achieving complete combustion of MSW,
the tube failure rate and the cost for downtime, maintenance, and repairs may offset
any thermal efficiency gained by operating at low excess air.
The problems associated with low excess air and ash fusion temperature under
reducing conditions is not limited to suspension firing or combustion of MSW. Grate-
fired system are also susceptible to changes in ash fusion temperatures due to the
presence of reducing combustion gas conditions. The guidelines provided for heat
release rate per unit grate area (Section 3) are intended to provide protection of grate
components from the heat release from the fuel but also to limit the formation of a
fused mass of material on the grate. Low excess air, particularly from the under-grate
air supply can promote the formation of clinkers in the ash bed on the grate. This in
turn, reduces air flow through the grate and fuel bed which further promotes reducing
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conditions in the fuel bed. It is possible to turn the entire fuel bed into a fused mass
that requires the boiler to be shutdown and the clinker to be removed from the grates
(sometimes with a jackhammer).
Although it is desirable from a combustion efficiency standpoint to operate at as
low an excess air level as is possible, it is necessary to avoid the problems of poor
combustion and ash fusion problems associated with low excess air. Operation of a
combustion source at low excess air levels requires good monitoring equipment and
controls responsive to variations in process demands. In many ways it may be more
difficult to operate on this lower limit than under some less efficient (higher excess air)
operating mode. For most combustion processes a balance between the cost of
efficiency and the cost of control to achieve that efficiency level must be established.
8.2.2 High Excess Air
Of all the problems observed at combustion sources, high excess air is
probably the most common problem. There are many causes of high excess air
problems, ranging from inadequate controls available to monitor and control the air
flow, to poor maintenance of boiler components allowing excessive air inleakage to
occur. The most obvious problem with high excess air is the high gas volumes that is
associated with the combustion process. The thermal efficiency of boilers may be
severely limited by too much excess air.
The oxygen content in the combustion gases that may constitute a high excess
air level differs depending upon fuel type and combustion method. For example, an
excess oxygen level of 3-5 percent may represent a very efficient range of excess
oxygen in the combustion gas for pulverized coal burning, whereas with natural gas
this might be considered a high excess air level. The firing of wet fuels on a grate
(e.g., wet wood, bark, or MSW) typically requires an excess oxygen level of between 8
and 12 percent depending on site specific design and conditions. Under no
circumstances should oxygen levels of 15 percent or higher be present in the
combustion gases. Justification for operating at these levels can seldom be provided
for combustion sources.
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The combustion problems associated with high excess air are all associated
with excessive air volume. The thermal efficiency of a boiler is most strongly affected
by the quantity of dry gas and gas temperature leaving the boiler (see Section 2 on
the discussion of boiler efficiency calculations). High excess air levels lower the flame
temperature achievable because additional gas volume must be heated by the
combustion process. The lower flame temperature reduces the amount of heat that
can be transferred by radiation in those sections of the boiler where radiant heat
transfer is important To maintain thermal efficiency the boiler must increase its rate of
heat transfer in the corrective heat transfer zones of the furnace. There is a fixed
amount of heat transfer area in the boiler. Even though the increased gas volume
increases the velocity of combustion gas through the tubes (thereby increasing the
rate of convective heat transfer) the increased heat transfer rate cannot make up for
the increased gas quantity and the lower flame temperature. Thus, the thermal
efficiency of the boiler decreases.
A decrease in flame temperature may cause an increase in combustible losses.
The decrease in temperature may require an increase in the time available for
combustion and/or an increase in the mixing (turbulence). Unfortunately, the furnace
volume is a fixed value and the increased volume of combustion gases means that
furnace velocities are increased while retention time is decreased. Thus, complete
burn-out of the fuel may not be possible and excessive carbon loss can detrimentally
affect air pollution control equipment performance. In extreme cases, fuel has been
found to be leaving the boiler and entering air pollution control equipment still burning.
With the exception of a wet scrubber, this can lead to a fire in the air pollution control
equipment that may cause severe damage. The wet scrubber may quench the
burning material but it may also be unable to capture the fine carbon particles
generated by the incomplete combustion conditions.
High excess air conditions may also have two other effects even in the absence
of high combustible losses. First, process operation rates may be limited because the
fan capacity to move the gases through the process have been reached. Once the
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fan capacity has been reached the process must be limited to that operating level or
excess gas volume will escape the process as fugitive emissions. Most gas handling
systems are designed with a margin of extra capacity at expected maximum operating
levels. This extra capacity can be easily exceeded by high excess air levels. The
second effect is to increase the quantity of fuel combusted to produce the necessary
heat in the process. This increase, due to reduced efficiency, may result in the
combustion of substantially greater quantities of fuel with the generation of more
paniculate matter, S02, NOX, and other pollutants. Although the emission rate in
lb/106 Btu may comply with emission limits it is possible to exceed any heat input
limitations specified by a permit as well as a Ib/hr limitation. In addition, high excess
air levels may promote an increase in the formation in SO3 from SO2 emissions and
increase the possibility of acid dewpoint problems from sulfuric acid in the combustion
and air pollution control equipment.
8.2.3 Improper Air Balance
If the air and the fuel are not mixed properly the presence of the proper level of
excess air does not assure the complete and efficient combustion of fuel. In solid fuel
suspension firing systems and oil and gas burners this means that primary and
secondary air mixtures must be within specified ranges for good combustion
characteristics. For grate-firing systems, proper air balance can be interpreted as
meaning the proper underfire and overfire air quantities as well as effective overfire air
turbulence.
In oil and natural gas combustion, primary and secondary air are introduced to
begin combustion and control the flame shape. Often a high degree of mixing is
achieved with the fuel and primary air to begin the combustion process. The mixing of
secondary air to complete combustion controls flame shape. The rate of fuel bum-out
depend upon the ratio of primary and secondary air and the amount of turbulence
used to mix the combustion air with the fuel. The same quantity of air can be used to
produce short, wide, crisp flames with high peak flame temperatures or much longer
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flame with a lower peak flame temperature just by controlling the primary/secondary
air ratio and the amount of turbulence in the burner. The short, intense flame may
produce a slightly lower carbon loss than the longer flame but the high peak flame
temperature will tend to promote high NOX emissions. A similar situation exists for
pulverized coal firing. The primary air is also used as the transport air to bring the
pulverized coal from the pulverizer to the burner. The primary air is generally 15 to 25
percent of the required combustion air. The vigorous combustion of the coal begins
at the primary/secondary air interface where the mixture of coal and air become
"combustible". The shape and length of the flame can be controlled by the
primary/secondary air ratio and the turbulence in mixing the air into the fuel.
When the primary/secondary air ratio settings get out of the proper range, poor
combustion can occur causing excessive carbon carryover. This* may not be
detectable through excess air measurements. In fact, an air balance problem may
cause boiler controls to cut back on air because of the "unused" oxygen present in the
combustion gas and create a low excess air condition. When excess air appears to
be adequate and coal properties are within normal limits, a burner imbalance may be
suspected if high combustible levels are found in the fly ash. This type of imbalance
may occur in only one burner or multiple burners in a boiler.
An imbalanced air supply problem may also occur in grate-fired combustion
systems. In these systems it is necessary to have the proper ratio of overfire and
underfire air. In general, the underfire air will make up approximately half of the
combustion air (including excess air) supplied to bum the fuel on the bed, although
the underfire air may range from 35 to 60 percent of the total air supplied to the grater.
Too little underfire air may result in poor air distribution through the fuel bed, clinkering
and fusing of the ash in the fuel bed due to reducing conditions, high residual
combustible content in the ash from the grates, generation of excessive quantities of
unburned carbon and hydrocarbons from the fuel bed, and damage to the grates
because insufficient air was provided to carry heat away from the grates. Overfire air
must provide adequate mixing and penetration of the zone over the fuel bed to
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complete the combustion of hydrocarbons and carbon that are generated by the fuel
bed.
Having too much underfire air can be as detrimental to boiler performance as
too little. Excess underfire air may result in fuel being carried off the grates into the
furnace volume to be combusted. In addition, large quantities of underfire air may
cause very high heat release rates in the fuel bed because much of the total air
requirement may be met by the underfire air requirement This high heat release rate
in the fuel bed may cause the generation of very fine paniculate matter as alkaline
compounds are vaporized from the ash. This may be more of a problem with
biomass fuels (wood, bark, etc.) because they tend to have rather high percentages of
the compounds in the residual ash. Once the gases cool these compounds tend to
condense to form submicron particles that may be difficult for some control equipment
to capture.
8.3 Fuel Characteristics
Most often fuel characteristics are of interest from the perspective of how they
affect emissions of SO2 or paniculate matter. Thus, the characteristics that may be
checked are the sulfur and/or ash content of a fuel. These are important parameters
but so are the fuel characteristics that the combustion process "sees'. The fuel
characteristics that will be discussed are applicable mostly to solid fuel, and to a
limited extent, residual oil combustion.
Combustion of residual fuel oil in a burner requires the atomization of the oil
into finely divided droplets for proper mixing and combustion. This atomization of the
oil from nozzles may be assisted by pressurized air or steam. Each system has its
advantages and disadvantages but generally result in comparable performance. If the
nozzles become plugged, partially plugged, or are of the wrong size for the oil
characteristics, droplets that are too large combustion are produced, as a result
performance will suffer in the form of combustible losses. This may be compensated
for by slightly increasing excess air and turbulence in the burner zone. The best
policy, however, is to maintain the burner tips for proper atomization of the oil.
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An analogous situation exists for pulverized coal combustion. The combustion
characteristics of pulverized coal are not dissimilar to that of oil firing. The coal must
be pulverized .to a sufficient fineness to provide a large surface area for heating and
combustion when it enters the burner and furnace zone. The general requirement for
eastern bituminous coal is to be pulverized so that 70 percent passes through a 200
mesh screen (a 200 mesh screen has openings of 74 microns or approximately 0.0029
inches). For western subbrtuminous coals the pulverization requirement is somewhat
lower with 60 to 65 percent passing through a 200 mesh screen. The higher the
percentage passing through the 200 mesh screen the finer the coal distribution and
the higher the energy requirement for pulverization. This fine coal powder has the
consistency of talc when it enter the furnace. If the particle size increases (i.e., the
percentage passing through the 200 mesh screen decreases) due to wear or
misadjustment of the pulverizers, the potential for combustible loss due to unbumed
carbon increases.
The difference between bituminous and subbrtuminous coal pulverizing
requirements lies in a characteristic of the coals themselves. Many bituminous coals
are caking or agglomerating coals. This means that when the fine coal particles enter
the burner and furnace zone and are exposed to heat, the coal particles tend to stick
together. This reduces the surface area for burning and makes the particles effectively
larger. Subbrtuminous coals tend to be nonagglomerating. Although the ashes that
some of these coals produce have very low ash fusion temperatures, the ash fusion
characteristics should not be confused with the agglomerating characteristics of the
coal. In addition to being nonagglomerating, many subbrtuminous coals tend to
contain high levels of inherent moisture and high oxygen contents. Although the high
moisture content may make the coal difficult to pulverize, the combined effect of the
moisture and oxygen give the coal a 'popcorn' effect when it enters the heat of the
burner and furnace zones. This exposes more burning surface and reduces the
required fineness of the coal leaving the pulverizer. The requirements for pulverization
depend upon the coal being burned. The coal fineness should checked periodically to
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determine if pulverizer adjustments or rebuilding is required. Most often pulverizer
problems are discovered as a result of increased combustible loss in the fly ash.
Insufficient coal fineness may not result in a detectable increase in emissions of CO.
Fuel size characteristics are very important to grate-fired systems, particularly
spreader stoker boilers. The grate-fired system relies upon the coal size distribution to
be within a range of values that allows the penetration of underfire air through the fuel
bed. If the fuel is too large there will be too little resistance to flow and air distribution
problems may occur causing excessive carryover. . If too many fines are present it is
difficult to force the air through the fuel bed and again incomplete combustion is the
results. In the spreader stoker excessive fines in the coal can result in excessive
carbon carryover because the fines may be carried out of the boiler instead of being
burned in suspension as the boiler is designed to do. Extremely high carbon losses
are possible from these boilers if care is not taken to insure proper coal size
distribution.
Ash fusion temperature is a fuel characteristic that should be considered in
boiler operation. As briefly discussed under the section on low excess air conditions,
many ashes have ash fusion temperatures that vary depending upon whether the
conditions are oxidizing or reducing. An ash that is satisfactory under oxidizing
conditions may become a liquid slag under high heat release rates and low excess air
conditions.
The ash fusion temperature is an essential element to boiler design and
guidelines for the heat release rates and ash fusion temperatures exist for both grate-
fired and suspension fired systems. Problems with ash fusion temperatures will
generally be limited if these guidelines are followed and the fuels combusted meet the
specifications. One problem that may not be foreseen is a the change in ash
characteristics that may occur due to fuel blending or the presence of other materials
along with the ash. Examples of these problems are relatively common.
Ash from wood combustion typically has an inherently high ash fusion
temperature that is above 3000° F. In general, it is difficult to exceed this temperature
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in most combustion systems and ash fusion and clinker formation are generally not a
problem. The addition of soil or silt from logging operations can change that and
produce an ash mixture that has a much lower ash fusion temperature than the "pure"
wood ash itself. This can be a difficult problem when the quantity of sand, soil and silt
are quite variable in the fuel feed.
The presence of an additional substance and its affect on ash characteristics is
not limited to wood combustion. In some boiler applications, high-temperature, "hot-
side" ESPs have been installed to overcome the problems of high resistivity associated
with the combustion of low sulfur coal. Unfortunately, many of these precipitators
experience another resistivity phenomenon known as sodium depletion which is just as
detrimental to ESP performance. In some locations an attempt to overcome the
sodium depletion problems has involved the addition of sodium, in the form of sodium
carbonate, to the fuel. The sodium is incorporated into the ash as the fuel bums and
raises the sodium content of the ash to overcome the sodium depletion problem. The
addition of sodium to the fuel rather than the gas stream after combustion appears
necessary to achieve any positive results. Unfortunately, the addition of sodium to
most coals has an undesirable side-effect The additional sodium reduces the ash
fusion temperature substantially and can cause severe slagging problems in the boiler.
Unless the boiler was previously designed to accommodate a slagging type coal ash
(by incorporating a large furnace volume and large cross-sectional area to reduce the
effective heat release rate per ft3 furnace volume and per ft2 of projected radiant
transfer surface area in the furnace) the operating rate of the boiler may have to be
substantially reduced. In some cases, the reduction in boiler heat release rate is so
great that approximately one-third of the boiler capacity is lost, while in other cases
there is little appreciable loss in operating load and a substantial improvement in ESP
performance. The trade-off between the loss in performance due to sodium depletion
resistivity problems and that lost due to sodium addition to the fuel is dependent upon
site specific factors.
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A much more common problem occurs with fuel blending. Two coals may be
checked for their respective coal and ash characteristics and meet specifications.
When blended, however, the coal ashes may create an ash slag or clinker problem.
This is due to the formation of a eutectic ash. A eutectic is a mixture of one or more
compounds whose melting point is lower than any of the individual compounds. The
eutectic may result from a very specific blend of coals or may occur over wide range
of mixtures. Only experimentation can determine where these eutectics form and what
mixtures to avoid. It must be noted that fuel blending does not automatically mean
that a problem with eutectics will occur. Some facilities use and blend a large number
of coals from a variety of sources without encountering problems. However, if
blending is used the potential for problems should be understood.
Problems with fuel characteristics are nearly as common as problems with
excess air. A combination of problems with excess air and fuel characteristics almost
always results in poor performance from the combustion and air pollution control
perspective. Some combustion sources are more sensitive to fuel characteristics than
others and require diligence on the part of the operators to maintain performance
within the design parameters of the unit This is particularly true of spreader stoker
boilers whose operation is most sensitive to coal size distribution.
8.4 Boiler Operation and Maintenance '
The last general area of combustion problems is related to boiler operation and
maintenance. Some of the problems described here overlap with other problems
listed previously. However, all act to reduce the operational efficiency of the
combustion process and may adversely affect air pollution control equipment
operation.
The problems associated with excess air have been discussed previously from
a combustion and thermal efficiency standpoint Air inleakage can contribute a large
part of the excess oxygen that is measured in the boiler combustion gas. Air
inleakage can occur from many sources but the most common are access doors, air
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heaters and ductwork. Poor maintenance of the boiler itself can also contribute to the
quantity of excess air that is drawn in the combustion gas if the boiler structural
components are not well maintained.
Most boilers are maintained under a slight negative pressure around and in the
combustion zone. A fan typically draws the combustion gases out of the combustion
zone. As the combustion gases pass through the equipment and towards the fan the
static pressure of the gas becomes increasingly more negative compared to
atmospheric pressure. The greater the difference between the combustion gas
pressure and the atmosphere the greater the potential for inleakage. The fan will
simply pull gas through the ductwork and any openings that provide the path of least
resistance. If the inleakage is severe and near the fan (e.g., an opening in the
ductwork or an open access door) then it is possible that so much air will be drawn in
at that point (the path of least resistance) that all of the combustion gases cannot be
drawn out of the combustion zone and the combustion rate must be reduced to
reduce the rate of generation of combustion gases. This is primarily a maintenance
issue and should not be overlooked in periodic inspection of the operation of a
•
combustion source.
Air inleakage into boilers reduces the gas temperature, reduces the heat
transfer rate and increases the gas volume that must be handled. In addition, air
inleakage can cause and promote zones of localized cooling that may cause acid
dewpoint corrosion problems. One of the largest sources of boiler air inleakage is the
air preheater. For boilers that are used in cyclic service and are equipped with a
tubular air heater, the expansion and contraction of the air heater can cause leakage
around the ends of the tubes where they meet the tubesheet. Regenerative air
heaters are also prone to leakage and require periodic maintenance to maintain the
integrity of the sector-seals between the combustion gases and the combustion air. It
is not unusual to find that the amount of oxygen in the combustion gases increases
after passing through the air heater by 1 to 2 percent (e.g., the combustion gas enters
the air heater at 4.5 percent oxygen and leaves at 6.0 percent oxygen). The result is
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an increased gas volume that must be moved by the fan(s) and treated by the air
pollution control equipment
A problem associated with boiler operating practices is one of fuel distribution.
Grate-fired systems, particularly spreader stoker boilers require even fuel distribution
across the grate from front-to-rear and side-to-side. Holes and piles in the fuel bed on
the grate do not allow even air flow through the fuel bed and the air will preferentially
pass through the thin spots (at higher velocity clearing the grate) and leave other
portions of the grate with little or no air for combustion. Grate-fired systems are most
susceptible to this problem. During operation, operators must periodically check the
fuel bed to make sure that even coverage is being maintained and to make
adjustments as necessary.
Pulverized coal combustion is not immune to fuel distribution problems. Coal
feeders must feed coal to pulverizers to match fuel firing demands. Occasional
problems with coal feeders due to coal bridging above the feeders have been known
to cause unstable flame conditions and are suspected in a number of ESP explosions.
The short-term disruption of coal feed to a pulverizer causes the controls to decrease
the amount of air being fed to the pulverizer. If the coal feed is suddenly reestablished
•
there may be insufficient air to complete combustion even though the coal is entering
a hot combustion zone. In the reducing conditions the coal is pyrolized and broken
down to simpler hydrocarbons such as methane and hydrogen. If these gases are
then combined with sufficient oxygen (from inleakage for example) and provided an
ignition source (a spark in the ESP) the mixture becomes explosive and can do severe
damage to equipment. The potential exists for injuring any personnel unfortunate
enough to be in the area. Pulverizer feeder problems tend to occur whenever there is
an excessive amount of moisture or fines in the coal.
Finally, the operation of boilers provides the potential for introducing large
quantities of water into the gas stream due to tube leaks. Often a severe tube leak
due to a ruptured tube(s) requires the shutdown of the boiler and the repair of the
tube(s) involved. Minor leakage may be tolerable for a period of time provided the
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leakage is not damaging other equipment or surrounding tubes. A leak represents an
energy loss in the form of energy already expended and absorbed by the steam
and/or as an addition of water that reduces the overall thermal efficiency. The
presence of a tube leak may have varied effects on air pollution control equipment.
Minor leakage from superheaters and reheater generally has little observable effect on
air pollution control equipment such as ESPs or fabric filters. .Tube leaks from boiler
water walls and economizers tend to have a more pronounced effect. In some cases,
the additional moisture improves the control equipment efficiency. For example, an
ESP suffering a slight high resistivity problem may improve performance because the
additional performance modifies resistivity into a more favorable range. However,
when enough water is added to form "mud" due to high moisture levels then
performance suffers and the boiler must be shut down and repaired.
8.5 Case Examples
Several illustrative examples of boiler problems and their effects on boiler and
control equipment performance are provided to illustrate the cause and effect
relationships often associated with boiler operating problems. These problems are not
intended to be all inclusive but represent a number of the more common problems
discussed previously in this section.
8.5.1 Excess Air
In this example several oil-fired boilers at an industrial facility were evaluated for
their thermal efficiency. These were relatively old boilers and over time some of the
structural components had deteriorated and were allowing a substantial quantity of
inleakage into the boilers. The boilers were not equipped with economizers but were
equipped with tubular air heaters to preheat the combustion air entering the burners.
In addition, much of the boiler instrumentation had deteriorated and either did not
provide reliable readings or had failed altogether. There was limited information
available to the boiler operator beyond the steam and drum pressures and the water
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level in the steam drum. The steam flow meters were considered unreliable and the
heat output of the boilers could not be readily determined. Thermal efficiency was
determined by measuring combustion gas conditions.
The combustion gas measurements were taken after the air heaters in the boiler
stacks. The average temperature for most of the boilers was 625° F at an oxygen
content ranging from 15.5 to 17.5 percent. An analysis of the fuel oil being burned
was obtained from the industrial facility. Computation of thermal efficiency indicated
that the boilers were operating in a thermal efficiency range of between 51 and 57
percent. Since the boilers were not equipped with economizers, the expected thermal
efficiency was between 80 and 85 percent since the boiler were not equipped with
economizers. Discussions with plant personnel indicated that they were aware of the
high cost of fuel consumption for the facility. Since there were other consumption
points of fuel oil within the facility and equipment to determine the quantity used at
each point was not in operational condition, plant personnel and boiler operators were
oblivious to the high rate of fuel use by the boilers.
These boilers had been recently stack tested. The emission limits that had to
be met were in units of lb/106 Btu and these emission limits were being met for
paniculate and SO2 (the only two pollutants regulated for these existing sources). No
evaluation was conducted during the stack tests to determine the amount of heat input
to these boilers or their thermal efficiency. In fact, thermal efficiency had dropped to
the point where these boilers were unable to meet steam demand and steam demand
was being met by a new package boiler recently installed at the facility, as well as by
several older boilers that had been converted from standby service to continuous
service.
The situation was further complicated by the presence of an ambient monitor
near the site that showed periodic violations of the 3-hr ambient standard for SO2.
The boilers had short stacks protruding from the roof of a long, low building. The
potential for building downwash was substantial. When downwash was considered
the point of maximum impact from the boiler stacks could be shown to be in the area
of the ambient monitor.
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The cost of the thermal efficiency loss was estimated to be worth approximately
two million dollars per year at the prices that were being paid for fuel oil. The plant
personnel were surprised by this number. In addition, the quantity of SO2 being
generated was substantially greater from these boilers stacks than anyone had
considered. The cost of the energy losses and the cost of repairing the old boilers
were substantially greater in the long term than constructing a new high efficiency
boiler. Ultimately, all the boilers, except the package boiler, were replaced. The
estimated time for the return on investment was approximately seven years. In
addition, the operation of the new boiler resulted in a substantial reduction in SO2
emissions. A new taller stack eliminated downwash and SO2 concentrations above the
ambient standard were eliminated.
If control equipment had been applied in this case the gas volumes that would
have been treated would have been substantially higher than the design values.
Similar situations have been observed for solid fuel fired boilers with high excess air.
Usually this situation results in an inability to meet particulate matter emission
standards (both opacity and mass limits) because of the high gas volumes.
8.5.2 Improper Fuel Characteristics
An example of improper fuel characteristics in solid fuel firing are useful in
illustrating the range of problems that can occur. In the example the fuel is
combusted on a grate-fired combustion system.
In the first example, three coal-fired boilers were used to provide process steam
to a facility. All the boilers were spreader stoker designs and the particulate matter
emissions were controlled using a single fabric filter unit for all three boilers. In
general, only two of the three boilers would be required to satisfy the steam demand
at the facility except in winter. The fabric filter was designed to operate with all three
boilers on-line. Therefore, it was felt that the fabric filter had an adequate margin of
performance built into the design. The fabric filter replaced three mutticyclones that
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had previously been used to unsuccessfully control emissions from the boilers. During
the time the fabric filter was being installed the coal supplier was changed.
The first several weeks of operation with the new system seemed to indicate
that things were going as well as could be expected. There were the usual start-up
problems but nothing out of the ordinary. It was noted that the boilers were having
the steam demand could not be met with two boilers and as a result all three were
being operated. Over a period of approximately 60 days the pressure drop across the
fabric filter continued to rise to a pressure drop of about 12 inches. The fan reached
its capacity at this point and began to limit boiler capacity. Eventually the pressure
drop across the fabric filter decreased but not because of adjustments made to the
fabric filter cleaning system. The bags developed holes that relieved the pressure and
the opacity then went from 5 to 10 percent up to 40 to 60 percent. The boilers were
shut down and 840 bags were replaced. This cycle of 60 to 90 days between bag
replacement was repeated several more times with much discussion between the
fabric filter manufacturer and the facility operators.
Eventually, the performance of the boiler was examined as a potential source of
the operating problems. The combustion gas oxygen levels and temperature were
measured. The oxygen was found to be approximately 10 percent. This was slightly
higher than what would be expected but not exceptionally high. The temperature was
also slightly higher than what was expected (375° F) but again was not exceptionally
high. The values normally expected for these boilers were about 8 percent oxygen
and 345° F. The difference clearly indicated that some improvement was possible. An
ash sample and coal sample were obtained for analysis. It became immediately
obvious that the coal being burned was much too fine for the spreader stoker boiler
design. Looking through the boiler inspection ports indicated that there was a very
thin fuel bed on the grates and most of the fine coal was being burned in suspension
rather than approximately equal quantities in suspension and on the graces. No
measurement of CO was available during the operation of the boiler.
296
-------
The coal analysis indicated that the as-fired heat content of the coal was
relatively high. The heat content was approximately 12,500 Btu/lb with an ash content
of 8 to 10 percent. It was the ash analysis that confirmed the finding that the coal was
too fine. The ash combustible content indicated a heat content of between 6500 and
7800 Btu/lb. An internal inspection of the fabric filter indicated that the bags were
being blinded by fine carbon particles. An analysis of the energy losses indicated that
the boiler thermal efficiency was approximately 70 percent Over half of the energy
loss was from the carbon loss found in the fly ash. The analysis also showed that the
thermal efficiency that could be achieved was approximately 87 percent if the coal was
changed to the proper size distribution. There was an increase cost of $5/ton for coal
with the proper size distribution. The increased coal cost was initially felt to be an
unjustified expense by the facility operators. When the cost of the lost efficiency (as
lost fuel value) was factored in, the use of the less expensive coal resulted in an
increased cost to the facility of approximately $171,500/yr. Bag replacement was
valued at approximately $250,000/yr and other energy costs rounded out the total
costs to approximately $450,000/yr. Clearly the choice to continue to purchase the
less expensive coal was not the correct one. The costs did not include any penalties
or fines associated with noncompliance with regulatory limits. The only practical
choice was to either convert the boilers to fire pulverized coal or to purchase the more
expensive coal. The latter option was chosen and the performance of the boilers and
the fabric filters improved dramatically. Bag life was extended to more than two years.
In this case, what seemed to be a more expensive alternative was actually the least
expensive alternative and the correct one.
Numerous cases very similar to this one have been found for both coal and/or
wood combustion. In the previous example the operator was fortunate that a severe
fire had not occurred although there were indication of small fires in the hoppers of the
fabric filter. In another similar application using an ESP, the operators were not as
fortunate and the carbon carry over resulted in a fire that required a substantial
rebuilding of the ESP and a major expense in addition to the loss of operating capacity
and thermal efficiency.
297
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8.5.3 Summary
These examples cannot be all inclusive of every problem that may occur in
combustion systems. They do, however, illustrate the need for proper monitoring of
the process, proper maintenance of equipment, good excess air characteristics, and
proper fuel characteristics. The effects of a poorly operating combustion process can
result in poor control equipment performance due to unsatisfactory particle
characteristics and/or excessive gas volumes. The combustion process and the
control equipment can be evaluated separately but they should also be examined as
whole because the performance of one may affect the other.
298
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APPENDIX A
NEW SOURCE PERFORMANCE STANDARDS
SUBPARTS Da AND Db
A-1
-------
M.4
* a
FIGURE I
CONTINOUOUS BUBBLER (SOj/CO,) SAMPLING TRAIN
•1-8
Ion
•|Nm- s.. 5,eti.» c.)mein
C» ti.ln 4urln| tht
IKLfT
OPTIONAL:
HEATED
PROBE AKD
IN-STACK
FILTER
10*
2-PROPANOL
(OPTIONAL)
OUTLtT
Subpart Do—Standards of Perform-
ance for Electric Utility Steam
Generating OnHt far Which Con-
ttrwctlan It Commenced After
September 18, 1978
Sooner 44 PR SS613. June 11.1979. unless
otherwise noted.
860.40s Applicability and designation of
affected facility.
(a) The affected facility to which
this subpart applies Is each electric
utility steam generating unit:
(1) That Is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat Input of fossil fuel
(either alone or In combination with
any other fuel): and
262
Iron
Ion
(2) For which construction or modi-
fication Is commenced after Septem-
ber 18.1978.
(b) This subpart applies to electric
utility combined cycle gas turbines
that are capable of combusting more
than 73 megawatts (250 million Btu/
hour) heat Input of fossil fuel In the
steam generator. Only emissions re-
sulting from combustion of fuels In
the steam generating unit are subject
to this subpart. (The gas turbine emis-
sions are subject to Subpart OO.)
(c) Any change to an existing fossll-
fuel-flred steam generating unit to ac-
commodate the use of combustible ma-
terials, other than fossil fuels, shall
not bring that unit under the applica-
bility of this subpart.
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to ac-
commodate the use of any other fuel
(fossil or nonfossll) shall not bring
that unit under the applicability of
this subpart.*
960.41* Definitions.
As used hi this subpart, all terms not
defined herein shall have the meaning
given them In the Act and In Subpart
A of this part.
"Steam generating unit" means any
furnace, boiler, or other device used
for combusting fuel for the purpose of
producing steam (Including fossll-fuel-
flred steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not Included).
'"Electric utility steam generating
unit" means any steam electric gener-
ating unit that Is constructed for the
purpose of supplying more than one-
third of Its potential electric output
capacity and more than 25 MW electri-
cal output to any utility power distri-
bution system for sale. Any steam sup-
plied to a steam distribution system
for the purpose of providing steam to
a steam-electric generator that would
produce electrical energy for sale is
also considered In determining the
electrical energy output capacity of
the affected facility.
"Fossil fuel" means natural gas. pe-
troleum, coal, and any form of solid.
liquid, or gaseous fuel derived from
such material for the purpose of creat-
ing useful heat.
"Subbitumlnoua coal" means coal
that Is classified as subbltumlnous A,
B, or C according to the American So-
ciety of Testing and Materials (ASTM)
Standard Specification for Classifica-
tion of Coals by Rank D388-77 (Incor-
porated by reference—see 860.17).
"Lignite" means coal that la classi-
fied as lignite A or B according to the
American Society of Testing and Ma-
terials' (ASTM) Standard Specifica-
tion for Classification of Coals by
Rank D388-77 (Incorporated by refer-
ence—see 860.17).
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
material, clay, and other organic and
Inorganic material.
"Potential combustion concentra-
tion" means the theoretical emissions
(ng/J, Ib/mllllon Btu heat Input) that
would result from combustion of a fuel
In an uncleaned state without emission
control systems) and:
(a) For partlculate matter Is:
(1) 3.000 ng/J (7.0 Ib/million Btu)
heat Input for solid fuel; and
(2) 75 ng/J (0.17 Ib/milllon Btu)
heat Input for liquid fuels.
(b) For sulfur dioxide Is determined
under 8 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/J (0.67 Ib/milllon Btu)
heat Input for gaseous fuels:
(2) 310 ng/J (0.72 Ib/mllllon Btu)
heat Input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/mllllon Btu)
heat Input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion
system where heat from the turbine
exhaust gases Is recovered by a steam
generating unit.
"Interconnected" means that two or
more electric generating units are elec-
trically tied together by a network of
power transmission lines, and other
power transmission equipment.
"Electric utility company" means
the largest Interconnected organiza-
tion, business, or governmental entity
that generates electric power for sale
(e.g.. a holding company with operat-
ing subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
263
-------
560.41o
"Neighboring company" means any
one of those electric utility companies
with one or more electric power Inter-
connections to the principal company
and which have geographically adjoin-
ing service areas.
"Net system capacity" means the
sum of the net electric generating ca-
pability (not necessarily equal to rated
capacity) of all electric generating
equipment owned by an electric utility
company (Including steam generating
units. Internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contractual pur-
chases that are Interconnected to the
affected facility that has the malfunc-
tioning flue gas desulfurizatlon
system. The electric generating capa-
bility of equipment under multiple
ownership Is prorated based on owner-
ship unless the proportional entitle-
ment to electric output Is otherwise es-
tablished by contractual arrangement.
"System load" means the entire elec-
tric demand of an electric utility com-
pany's service area Interconnected
with the affected facility that has the
malfunctioning flue gas • desulfuriza-
tlon system plus firm contractual sales
to other electric utility companies.
Sales to other electric utility compa-
nies (e.g., emergency power) not on a
firm contractual basis may also be In-
cluded In the system load when no
available system capacity exists In the
electric utility company to which the
power Is supplied for sale.
"System emergency reserves" means
an amount of electric generating ca-
pacity equivalent to the rated capacity
of the single largest electric generat-
ing unit In the electric utility company
(Including steam generating units. In-
ternal combustion engines, gas tur-
bines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which Is Interconnected
with the affected facility that has the
malfunctioning flue gas desulfuriza-
tlon system. The electric generating
capability of equipment under multi-
ple ownership Is prorated based on
ownership unless the proportional en-
titlement to electric output Is other-
wise established by contractual ar-
rangement.
40 CFR Ch. I (7.1*88 Edition)
"Available system capacity" means
the capacity determined by subtract-
ing the system load and the system
emergency reserves from the net
system capacity.
"Spinning reserve" means the sum
of the unutilized net generating capa-
bility of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of Immediately accepting addi-
tional load. The electric generating ca-
pability of equipment under multiple
ownership is prorated based on owner-
ship unless the proportional entitle-
ment to electric output Is otherwise es-
tablished by contractual arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system ca-
pacity in all neighboring companies.
(b) The sum of the rated capacities
of the power Interconnection devices
between the principal company and all
neighboring companies, minus the
sum of the electric power load on
these interconnections.
(c) The rated capacity of the power
transmission lines between the power
interconnection devices and the elec-
tric generating units (the unit In the
principal company that has the mal-
functioning flue gas desulfurizatlon
system and the unlUs) in the neigh-
boring company supplying replace-
ment electrical power) less the electric
power load on these transmission
lines.
"Spare flue gas desuVurteation
system module" means a separate
system of sulfur dioxide emission con-
trol equipment capable of treating an
amount of flue gas equal to the total
amount of flue gas generated by an af-
fected facility when operated at maxi-
mum capacity divided by the total
number of nonspare flue gas desulfuri-
zatlon modules in the system.
"Emergency condition" means that
period of time when:
(a) The electric generation output of
an affected facility with a malfunc-
tioning flue gas desulfurizatlon system
cannot be reduced or electrical output
must be Increased because:
(1) All available system capacity In
the principal company Interconnected
with the affected facility is being oper-
ated, and
264
Environmental Protection Agtncy
(2) All available purchase power
Interconnected with the affected facil-
ity .Is being obtained, or
(b) The electric generation demand
is being shifted as quickly as possible
from an affected facility with a mal-
functioning flue gas desulfurizatlon
system to one or more electrical gener-
ating units held in reserve by the prin-
cipal company or by a neighboring
company, or
(c) An affected facility with a mal-
functioning flue gas desulfurizatlon
system becomes the only available
unit to maintain a part or all of the
principal company's system emergency
reserves and the unit Is operated In
spinning reserve at the lowest practi-
cal electric generation load consistent
with not causing significant physical
damage to the unit. If the unit is oper-
ated at a higher load to meet load
demand, an emergency condition
would not exist unless the conditions
under (a) of this definition apply.
"Electric utility combined cycle pas
turbine" means any combined cycle
gas turbine used for electric genera-
tion that Is constructed for the pur-
pose of supplying more than one-third
of Its potential electric output capac-
ity and more than 25 MW electrical
output to any utility power distribu-
tion system for sale. Any steam distri-
bution system that Is constructed for
the purpose of providing steam to a
steam electric generator that would
produce electrical power for sale Is
also considered In determining the
electrical energy output capacity of
the affected facility.
"Potential electrical output capac-
ity" Is defined as 33 percent of the
maximum design heat Input capacity
of the steam generating unit (e.g., a
steam generating unit with a 100-MW
(340 million Btu/hr) fossil-fuel heat
Input capacity would have a 33-MW
potential electrical output capacity).
For electric utility combined cycle gas
turbines the potential electrical
output capacity Is determined on the
basis of the fossil-fuel firing capacity
of the steam generator exclusive of
the heat input and electrical power
contribution by the gas turbine.
"Anthracite" means coal that Is clas-
sified as anthracite according to the
American Society of Testing and Ma-
§ 60.42o
terlals' (ASTM) Standard Specifica-
tion for Classification of Coals by
Rank D388-77 (Incorporated by refer-
ence—see |60.17).
"Solid-derived fuel" means any solid
liquid, or gaseous fuel derived from
solid fuel for the purpose of creating
useful heat and Includes, but Is not
limited to, solvent refined coal, liqui-
fied coal, and gasified coal.
"24-hour period" means the period
of time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a fa-
cility that combusts more than 76 per-
cent non-fossil fuel on a quarterly (cal-
endar) heat Input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Com-
monwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit
for the entire 24 hours.
(44 PR 33613. June 11, 1970. as amended at
48 PR 3737. Jan. 27.1983)
0 60.42a Standard for partleulate matter.
(a) On and after the date on which
the performance test required to be
conducted under 8 60.8 Is completed,
no owner or operator subject to the
provisions of this subpart shall cause
to be discharged Into the atmosphere
from any affected facility any gases
which contain particulate matter In
excess of:
(1) 13 ng/J (0.03 Ib/mllllon Btu)
heat Input derived from the combus-
tion of solid, liquid, or gaseous fuel;
(2) 1 percent of the potential com-
bustion concentration (99 percent re-
duction) when combusting solid fuel;
and
(3) 30 percent of potential combus-
tion concentration (70 percent reduc-
tion) when combusting liquid fuel.
(b) On and after the date the partic-
ulate matter performance test re-
quired to be conducted under f 60.8 is
completed, no owner or operator sub-
ject to the provisions of this subpart
shall cause to be discharged Into the
atmosphere from any affected facility
any gases which exhibit greater than
20 percent opacity (6-mlnute average),
-------
« foi 9-i • p „ pei
hour of not more than 27 percent
opacity.
I «0.49a Standard for rolfor dioxide.
(a) On and after the date on which
the initial performance test required
. to be conducted under |60.8 la com-
pleted. no owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the atmos-
phere from any affected facility which
combusts solid fuel or solid-derived
fuel, except as provided under para-
graphs (c), (d). (f) or (h) of this sec-
tion, any gases which contain sulfur
dioxide in excess of:
(1) 820 ng/J (1.20 Ib/mllllon Btu)
heat input and 10 percent of the po-
tential combustion concentration (90
percent reduction), or
(2) 30 percent of the potential com-
bustion concentration (70 percent re-
duction), when emissions are less than
260 ng/J (0.60 Ib/mllllon Btu) heat
input
(b) On and after the date on which
the Initial performance test required
to be conducted under 160.8 Is com*
pleted. no owner or operator subject to
the provisions of this subpart shall
cause to be discharged Into the atmos-
phere from any affected facility which
combusts liquid or gaseous fuels
(except for liquid or gaseous fuels de-
rived from solid fuels and as provided
under paragraphs (e) or (h) of this sec-
tion), any gases which contain sulfur
dioxide in excess of:
.(1) 340 ng/J (0.80 Ib/mllllon Btu)
heat Input and 10 percent of the po-
tential combustion concentration (90
percent reduction), or
(2) 100 percent of the potential com-
bustion concentration (eero percent re-
duction) when emissions, are less than
86 ng/J (0.20 Ib/mllllon Btu) heat
Input
(c) On and after the date on which
the Initial performance test required
to be conducted under 160.8 is com-
plete, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged Into the atmos-
phere from any affected facility which
combusts solid solvent refined coal
(SRC-I) any gases which contain
sulfur dioxide in excess of 820 ng/J
(1.20 Ib/mllllon Btu) heat input and 18
40 CFt Ch | (7-« — Ed[
percent or the potential combustion
concentration (86 percent reduction)
except as provided under paragraph
(f) of this section; compliance with the
emission limitation Is determined on a
30-day rolling average basis and com-
pliance with the percent reduction re-
quirement Is determined on a 24-hour
basis.
(d) Sulfur dioxide emissions are lim-
ited to 620 ng/J (1.20 Ib/mllllon Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recov-
ery facility, or
(3) Is located in a noncontlnental
area and combusts solid fuel or solid-
derived fuel.
(e) Sulfur dioxide emissions are lim-
ited to 340 ng/J (0.60 Ib/mlllion Btu)
heat input from any affected facility
which Is located In a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction require-
ments under this section do not apply
to any affected facility that is operat-
ed under an SOt commercial demon-
stration permit Issued by the Adminis-
trator In accordance with the provi-
sions of 160.45a.
(g) Compliance- with the emission
limitation and percent reduction re-
quirements under this section are both
determined on a 30-day rolling average
basis except as provided under para-
graph (c) of this section.
(h) When different fuels are com-
busted simultaneously, the applicable
standard is determined by proration
using the following formula:
(1) If emissions of sulfur dioxide to
the atmosphere are greater than 260
ng/J (0.60 Ib/mllllon Btu) heat input
E*» - 1340 x + 820 yl/100 and
P.O. - 10 percent
(2) If emissions of sulfur dioxide to
the atmosphere are equal to or less
than 260 ng/J (0.60 Ib/mllllon Btu)
heat input*
En. - (340 x -f- 520 y)/100 and
P.O.- (90 x + 70 y)/100
where: '
En. Is the prorated sulfur dioxide emission
limit (ng/J heat Input).
266
'Iroi
all
Ion
«y
..-.SO
Pm la the percentage of potential sulfur di-
oxide emission allowed (percent reduc-
tion required - 100-?„„),
x la the percentage of total heat Input de-
rived from the combustion of liquid or
gaseous fuels (excluding solid-derived
fuels)
r Is the percentage of total heat Input de-
rived from the combustion of solid fuel
(Including solid-derived fuels)
S 60.44s Standard for nitrogen oxides.
(a) On and after the date on which
the Initial performance test required
to be conducted under ( 60.8 Is com-
pleted, no owner or operator subject to
the provisions of this subpart shall
cause to be discharged Into the atmos-
phere from any affected facility,
except as provided under paragraph
(b) of this section, any gases which
contain nitrogen oxides In excess of
the following emission limits, based on
a 30-day rolling average.
(1) NO, emission limits.
Fuairypa
OMaout hute
CoaMarimd MM
All ottwr fu«t»....._ -
UquUfurts:
CoaMertrad furtt
Shato oi __...„.-..._
AS otnaf (ue(8.«.«..-.«..- ....
SoUluete
CMl-dwtved fuels ......;
. Any fuH containing fncra tfian
25%. by wtfflM. coal
rahita „.-..:.
Any fuel eontlMng more than
25%. by wrtgM. IgnKt N
OM R0nit9 to fnlnoQ In Nwtn
Dakota. Sou* Dakota, or
• Montana, and la combusted
In a elag tap furnace
Ugnlta not aubjact to tha 340
ng/J haat Input amltalon
ImH ..._M.«.W.._ .
Subbtturrinoua coal—..—
Bttumtaeua eoal _..—.. —
Afiff»aclte coal __» -,..
M«tftww kflrfft
UUHJI n^^v»»ww«.«...»~...w<
Emfaston tanA tor haat
Input
ng/J
210
M
2tO
2tO
130
210
«')
f
340
MO
210
260
260
280
(tVmmon
Btu)
0.50
0.20
0.50
0.50
0.30
0.50
{•I
OK
0.60
0.50
0.60
0.60
0.60
1 Eicwnpt from NO* ftsmtertft And NO, ftionftortng
(2) NO, reduction requirement.
Fuattypa
OtMout hitta..
raduc&on of
comtouctfon
concentration
25
90
65
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which Is
combusting coal-derived liquid fuel
and Is operating under a commercial
demonstration permit Issued by the
Administrator In accordance with the
provisions of 1 60.45a.
(c) When two or more fuels are com-
busted simultaneously, the applicable
standard Is determined by proration
using the following formula:
- (86 W+130x + 310y + 280 si/100
where:5
the applicable standard for nitrogen
oxides when multiple fuels are combust-
ed simultaneously (ng/J heat Input);
w Is the percentage of total heat Input de-
. rived from the combustion of fuels sub-
• Ject to the 88 ng/J heat Input standard;
x Is the percentage of total heat Input de-
rived from the combustion of fuels sub-
ject to the 130 ng/J heat Input standard:
y Is the percentage of total heat Input de-
rived from the combustion of fuels sub-
ject to the 210 ng/J heat Input standard:
and
e la the percentage of total heat Input de-
rived from the combustion of fuels sub-
ject to the 280 ng/J heat Input standard.
0(0.45a Commercial , demonstration
permit
(a) An owner or operator of an af-
fected facility proposing to demon-
strate an emerging technology may
apply to the Administrator for a com-
mercial demonstration permit. The
Administrator will Issue a commercial
demonstration permit In accordance
with paragraph (e) of this section.
Commercial demonstration permits
may be Issued only by the Administra-
tor. and this authority will not be dele-
gated.
(b) An owner or operator of an af-
fected facility that combusts solid sol-
vent refined coal (SRC-I) and who is
Issued a commercial demonstration
permit by the Administrator Is not
subject to the SOt emission reduction
267
-------
requirement* under |60.43a(c) but
must, as a minimum, reduce 8O» emis-
sions to 20 percent of the potential
combustion concentration (80 percent
reduction) for each 24-hour period of
steam generator operation and'to less
than 520 ng/J (1.20 Ib/mlllion Btu)
heat Input on a 30-day rolling average
basis.
(c) An owner or operator of a fluid-
teed bed combustion electric utility
steam generator (atmospheric or pres-
surized) who is Issued a commercial
demonstration permit by the Adminis-
trator IB not subject to the 8Ot emis-
sion reduction requirements under
|60.43a(a) but must, as a minimum,
reduce 8O» emissions to 15 percent of
the potential combustion concentra-
tion (85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/mllllon Btu) heat
Input on a 30-day rolling average basis.
(d) The owner or operator of an af-
fected facility that combusts coal-de-
rived liquid fuel and who Is Issued a
commercial demonstration permit by
the Administrator Is not subject to the
applicable NO. emission limitation and
percent reduction under 160.44a(a)
but must, as a minimum, reduce emis-
sions to less than 300 ng/J (0.70 Ib/
million Btu) heat Input on a 30-day
rolling average basis.
(e) Commercial demonstration per-
mits may not exceed the following
equivalent MW electrical generation
capacity for any one technology cate-
gory, and the total equivalent MW
electrical generation, capacity for all
commercial demonstration plants may
not exceed 16,000 MW.
—.;
SoM «otv»m rvftwd oori (SBC
i)
nuktad tod eomburton (it-
FunDVo EMM GonwuMon yjflMH
fBftnrfl
ToW ttomMt tor M Men-
PglUMI
SO.
SO,
so.
NO.
OApMlty (MW 1
outpuq E
1
1
•.000-10.000 t
400-1.000 *
o
400-1.200 d
750-10.000 Q
a
1SOOO D
268
•HI tPl Gh. \ (7-1-88 Edition)
160.46s Compliance prorlilonB.
(a) Compliance with the partlculate
matter emission limitation under
|60.42a(aXl) constitutes compliance
with the percent reduction require-
ments for partlculate matter under
I 60.42a(a)(2> and (3).
Compliance with the nitrogen
oxides emission limitation under
160.44a(a) constitutes compliance
with the percent reduction require-
ments under 160.44a(a)(2).
(c) The partlculate matter emission
standards under |60.42a and the ni-
trogen oxides emission standards
under 160.44s. apply at all times
except during periods of startup, shut-
down, or malfunction. The sulfur diox-
ide emission standards under | 60.43a
apply at all times except during peri-
ods of startup, shutdown, or when
both emergency conditions exist and
the procedures under paragraph (d) of
this section are Implemented.
(d) During emergency conditions In
the principal company, an affected fa-
cility with a malfunctioning Hue gas
desulfurlzation system may be operat-
ed If sulfur dioxide emissions are mini-
mized by.
. (1) Operating all operable flue gas
desulfurlzatton system modules, and
bringing back Into operation any mal-
functioned module as soon as repairs
are completed,
(2) Bypassing Hue gases around only
those flue gas desulfurlzation system
modules that have been taken out of
operation because they were Incapable
of any sulfur dioxide emission reduc-
tion or which would have suffered sig-
nificant physical damage if they had
remained In operation, and
(3) Designing, constructing, and op-
erating a spare flue gas desulf urtzatlon
system module for an affected facility
larger than 365 MW (1.250 million
Btu/hr) heat input (approximately
125 MW electrical output capacity).
The Administrator may at his discre-
tion require the owner or operator
within 60 days of notification to dem-
onstrate spare module capability. To
demonstrate this capability, the owner
or operator must demonstrate compli-
ance with the appropriate require-
ments under paragraph (a), (b), (d),
(e), and (1) under 160.43ft for any
Environmental Protection Agtncy
period of operation lasting from 24
hours to 30 days when:
(I) Any one flue gas desulfurlzation
module Is not operated,
(II) The affected facility Is operating
at the maximum heat Input rate,
(III) The fuel fired during the 24-
hour to 30-day period Is representative
of the type and average sulfur content
of fuel used over a typical 30-day
period, and
(iv) The owner or operator has given
the Administrator at least 30 days
notice of the date and period of time
over which the demonstration will be
performed.
(e) After the Initial performance test
required under 160.8. compliance with
the sulfur dioxide emission limitations
and percentage reduction require-
ments under 160.43a and the nitrogen
oxides emission limitations under
160.44a is based on the average emis-
sion rate for 30 successive boiler oper-
ating days. A separate performance
test Is completed at the end of each
boiler operating day after the Initial
performance test, and a new 30 day av-
erage emission rate for both sulfur di-
oxide and nitrogen oxides and a new
percent reduction for sulfur dioxide
are calculated to show compliance
with the standards.
(f) For the Initial performance test
required under 8 60.8, compliance with
the sulfur dioxide emission limitations
and percent reduction requirements
under 5 60.43a and the nitrogen oxides
emission limitation under § 60.44a is
based on the average emission rates
for sulfur dioxide, nitrogen oxides, and
percent reduction for sulfur dioxide
for the first 30 successive boiler oper-
ating days. The initial performance
test Is the only test In which at least
30 days prior notice Is required unless
otherwise specified by the Administra-
tor. The Initial performance test Is to
be scheduled so that the first boiler
operating day of the 30 successive
boiler operating days Is completed
within 60 days after achieving the
maximum production rate at which
the affected facility will be operated.
but not later than 180 days after ini-
tial startup of the facility.
(g) Compliance Is determined by cal-
culating the arithmetic average of all
hourly emission rates for SO, and NO.
§ «0.47a
for the 30 successive boiler operating
days, except for data obtained during
startup, shutdown, malfunction (NO,
only), or emergency conditions (SOi
only). Compliance with the percentage
reduction requirement for SO> Is de-
termined based on the average Inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under
( 80.47& of this subpart, compliance of
the affected facility with the emission
requirements under 8}60.43a and
60.44a of this subpart for the day on
which the 30-day period ends may be
determined by the Administrator by
following the applicable procedures In
sections 6.0 and 7.0 of Reference
Method 19 (Appendix A).
0 60.47a Emission monitoring.
(a) The owner or operator of an af-
fected facility shall Install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
the opacity of emissions discharged to
the atmosphere, except where gaseous
fuel is the only fuel combusted. If
opacity Interference due to water
droplets exists In the stack (for exam-
ple, from the use of an POD system).
the opacity Is monitored upstream of
the Interference (at the Inlet to the
PGD system). If opacity Interference
Is experienced at all locations (both at
the Inlet and outlet of the sulfur diox-
ide control system), alternate param-
eters Indicative of the particulate
matter control system's performance
are monitored (subject to the approval
of the Administrator).
(b) The 'owner or operator of an af-
fected facility shall Install, calibrate.
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas Is the only fuel combusted.
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet
of the sulfur dioxide control device.
(2) For a facility which qualifies
under the provisions of {60.43a(d),
269
-------
ill xid «Ioi_ _. onl, ...v.i-
Itored as discharged to the atmos-
phere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirements of Method
10 (Appendix A) may be used to deter-
mine potential sulfur dioxide emis-
sions in place of a continuous sulfur
dioxide emission monitor at the Inlet
to the sulfur dioxide control device as
required under paragraph (bXl) of
this section.
(c) The owner or operator of an af-
fected facility shall Install, calibrate,
mft'n**'", and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged
to the atmosphere.
(d) The owner or operator of an af-
fected facility shall Install, calibrate.
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
the oxygen or carbon dioxide content
of the flue gases at each location
where sulfur dioxide or nitrogen
oxides emissions are monitored.
(e) The continuous monitoring sys-
tems under paragraphs (b), (c), and (d)
of this section are operated and data
recorded during all periods of oper-
ation of the affected facility including
periods of startup, shutdown, malfunc-
tion or emergency conditions, except
for continuous monitoring system
breakdowns, repairs, calibration
checks, and zero and span adjust-
ments.
(f) When emission data are not ob-
tained because of continuous monitor-
Ing system breakdowns, repairs, cali-
bration checks and zero and span ad-
justments, emission data will be ob-
tained by using other monitoring sys-
tems as approved by the Administra-
tor or the reference methods as de-
scribed in paragraph (h) of this sec-
tion to provide emission data for a
mlptmnm of 18 hours in at least 22 out
of 30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph |60.13(h) are ex-
pressed in ng/J (Ibs/mllllon Btu) heat
Input and used to calculate the aver-
age emission rates under 160.46a. The
1-hour averages are calculated using
the data points required under
40 CFR Ch. I (7.1.88 Edition!
, ««.*3(b/. rtv least two data points
must be used to calculate the 1-hour
averages.
(h) Methods used to supplement
continuous emission monitoring
system data to meet the minimum
data requirements In 160.47a(f) will be
used as specified below or as otherwise
approved by the Administrator.
(1) Methods 3 or 3A. 6 or 6C and 7.
7A. 7C. 7D or 7E as applicable, are
used. Method 6A or 6B may be used
whenever Methods 6 and 3 data are re-
quired to determine the SOi emission
rate in ng/J. Methods 3A. 6C. and 7E
are used only at the sole discretion of
the source owner or operator. The
sampling locatlon(s) are the same as
those specified for the continuous
emission monitoring system.
(2) For Method 6 or 6A. the mini-
mum sampling is 20 minutes and the
fnininMim sampling volume is 0.02
dsin' (0.71 dscf) for each sample. Sam-
ples are collected at approximately 60-
minute Intervals. Each sample repre-
sents a 1-hour average. Method 6B
shall be operated for 24 hours per
sample, and the minimum sample
volume Is 0.02 dam1 (0.71 dscf) for each
sample. Each Method 6b sample repre-
sents 24 1-hour averages. •
(3) For Method 7 or 7A. samples are
taken at approximately 30-mlnute in-
tervals. The arithmetic average of
these two connective samples represent
a 1-hour average. For Method 1C or
7D, each run shall consist of a 1-hour
sample.
(4) For Method 3, the oxygen or
carbon dioxide sample Is to be taken
for each hour when continuous SO,
and NO, data are taken or when
Methods 6 or 6C and 7. 7A. 7C. 7D. or
7E are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the Integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (lb/mll-
lion Btu) heat input are determined
and used as needed to achieve the min-
imum data requirements of paragraph
(f) of this section.
(I) The following procedures are
used to conduct' monitoring system
performance evaluations under
270
'in
160.13(0) and calibration checks under
160.13(d).
(1) Methods 3 or 3A, 6, 6A. 6B or 6C,
and 7, 7A, 7C. 7D or 7E, as applicable,
are used for conducting relative accu-
racy evaluations of sulfur dioxide and
nitrogen oxides continuous emission
monitoring systems. Methods 3A, 6C,
and 7E are used only at the sole dis-
cretion of the source owner or opera-
tor.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under per-
formance specification 2 of appendix
B to this part.
(3) For affected facilities burning
only fossil fuel, the span value for a
continuous monitoring system for
measuring opacity Is between 60 and
80 percent and for a continuous moni-
toring system measuring nitrogen
oxides Is determined as follows:
BpinvtlMfer
500
600
1.000
800 (B-tyt-f 1.000:
where:
x la the fraction of total heat Input derived
from gaseous fossil fuel.
y ls the fraction of total heat Input derived
from liquid fossil fuel, and
8 Is the fraction of total heat Input derived
from solid fossil fuel.
. (4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels
are rounded to the nearest 600 ppm.
(5) For affected facilities burning
fossil fuel, alone or in combination
with non-fossil fuel, the span value of
the sulfur dioxide continuous monitor-
Ing system at the inlet to the sulfur di-
oxide control device Is 125 percent of
the maximum estimated hourly poten-
tial emissions of the fuel fired, and the
outlet of the sulfur dioxide control
device Is 60 percent of maximum esti-
mated hourly potential emissions of
the fuel fired.
[44 FR 33613. June 11. 1679. as amended at
47 FR 54079, Dee. 1. 1982; 51 FR 21166. June
11,1086; 52 PR 31007, June 4,1987]
060.48s Compliance determination proce-
dure* and methods.
(a) The following procedures and
reference methods are used to deter-
mine compliance with the standards
for partlculate matter under 9 60.42a.
(1) Method 3 is used for gas analysis
when applying Method 5, 6B, or 17.
(2) Method 5, 6B. or 17 is used for
determining partlculate matter emis-
sions and associated moisture content
as follows: Method 6 is to be used at
affected facilities without wet POD
systems; Method SB Is to be used only
after wet FOO systems; and Method
17 may be used at facilities with or
without wet POD systems provided
that the stack gas temperature at the
sampling location does not exceed a
temperature of 160 *C (320 T). The
procedures of sections 2.1 and 2.3 of
Method 6B may be used In Method 17
only If It is used after wet POD sys-
tems. Do not use Method 17 after wet
POD systems if the effluent Is saturat-
ed or laden with water droplets.
(3) For Method 6, 6B, or 17. Method
1 is Used to select the sampling site
and the number of traverse sampling
points. The sampling tune for each
run is at least 120 minutes and the
minimum sampling volume Is 1.7 dscm
(60 dscf) except that smaller sampling
times or volumes, when necessitated
by.process variables or other factors.
may be approved by the Administra-
tor.
(4) For Method 6 or 6B the probe
and filter holder heating system In the
sampling train is set to provide an av-
erage gas temperature of 160 *C (320
*F>.
(6) For determination of partlculate
emissions, the oxygen or carbon diox-
ide sample is obtained simultaneously
with each run of Method 5. SB. or 17
by traversing the duct at the same
sampling location. Method 1 Is used
for selection of the number of oxygen
or carbon dioxide traverse points
except that no more than 12 sample
points are required.
(6) For each run using Method 6, SB.
or 17. the emission rate expressed In
ng/J heat input is determined using
the oxygen or carbon-dioxide measure-
ments and partlculate matter meas-
urements obtained under this 'section,
271
-------
560.49o
the dry basis Fe-factor »nd the dry
basis emission rate calculation proce-
dure contained In Method 19 (Appen-
dix A).
(b) The following procedures and
methods are used to determine compli-
ance with the sulfur dioxide standards
under 160.43s.
(1) Determine the percent of poten-
tial combustion concentration (percent
FCC) emitted to the atmosphere as
follows:
(I) Fuel pretreatment (% Rf): Deter-
mine the percent reduction achieved
by any fuel pretreatment using the
procedures In Method 19 (Appendix
A). Calculate the average percent re-
duction for fuel pretreatment on a
quarterly basis using fuel analysis
data. The determination of percent R,
to calculate the percent of potential
combustion concentration emitted to
the atmosphere Is optional. For pur-
poses of determining compliance with
any percent reduction requirements
under I 60.43a, any reduction In poten-
tial SO. emissions resulting from the
following processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurtzatlon of fuel
on, etc.),
(B) Coal pulverizers, and
(C) Bottom and flyash Interactions.
(11) Sulfttr dioxide control tvstem (%
R,}: Determine the percent sulfur di-
oxide reduction achieved by any sulfur
dioxide control system using emission
rates measured before and after the
control system, following the proce-
dures In Method 19 (Appendix A); or,
a combination of an "as fired" fuel
monitor and emission rates measured
after the control system, following the
procedures In Method 19 (Appendix
A). When the "as fired" fuel monitor
Is used, the percent reduction Is calcu-
lated using the average emission rate
from the sulfur dioxide control device
and the average 8O. input rate from
the "as fired" fuel analysis for 30 suc-
cessive boiler operating days.
(Ill) Overall percent reduction (%
R.): Determine the overall percent re-
duction using the results obtained In
paragraphs (bXl) (1) and (II) of this
section following the procedures In
Method 19 (Appendix A). Results are
calculated for each 30-day period
using the quarterly average percent
40 Ctt Ch. I (7-1-88 Edition)
sulfur reduction determined for fuel
pretreatment from the previous quar-
ter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period In the
current quarter.
(Iv) Percent emitted (% PCO; Calcu-
late the percent of potential combus-
tion concentration emitted to the at-
mosphere using the following equa-
tion: Percent PCC- 100-Percent R.
(2) Determine the sulfur dioxide
emission rates following the proce-
dures In Method 19 (Appendix A).
(c) The procedures and methods out-
lined In Method 19 (Appendix A) are
used In conjunction with the 30-day
nitrogen-oxides emission data collect-
ed under 160.47a to determine compli-
ance with the applicable nitrogen
oxides standard under ft 60.44.
(d) Electric utility combined cycle
gas turbines are performance tested
for partlculate matter, sulfur dioxide.
and nitrogen oxides using the proce-
dures of Method 19 (Appendix A). The
sulfur dioxide and nitrogen oxides
emission rates from the gas turbine
used In Method 19 (Appendix A) calcu-
lations, are determined when the gas
turbine Is performance tested under
Subpart OO. The potential uncon-
trolled partlculate matter emission
rate from a gas turbine Is defined as 17
ng/J (0.04 Ib/mllllon Btu) heat Input
t44 PR 83019. June II. 1970. as amended at
61 FR 43842. Nov. 29.1088)
0 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen
oxides, and partlculate matter emis-
sions, the performance test data from
the Initial performance test and from
the performance evaluation of the
continuous monitors (Including the
transmlssometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following Information Is re-
ported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/mllllon Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period In the quarter, rea-
sons for non-compliance with the
272
Environmental Protection Agency
emission standards: and. description of
corrective actions taken.
(3) Percent reduction of the poten-
tial combustion concentration of
sulfur dioxide for each 30 successive
boiler operating days, ending with the
last 30-day period In the quarter rea-
sons for non-compliance with the
standard; and, description of correc-
tive actions taken.
(4) Identification of the boiler oper-
ating days for which pollutant or dilu-
tent data have not been obtained by
an approved method for at least 18
hours of operation of the facility; jus-
tification for not obtaining sufficient
data; and description of corrective ac-
tions taken.
(5) Identification of the times when
emissions data have been excluded
from the calculation of average emis-
sion rates because of startup, shut-
down, malfunction (NO, only), emer-
gency conditions (SO» only), or other
reasons, and Justification for exclud-
ing data for reasons other than start-
up, shutdown, malfunction, or emer-
gency conditions.
(6) Identification of "F" factor used
for calculations, method of determina-
tion, and type of fuel combusted.
(7) Identification of times when
hourly averages have been obtained
based on manual sampling methods.
(8) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring.
system.
(9) Description of any modifications
to the continuous monitoring system
which could affect the ability of the
continuous monitoring system to
comply with Performance Specifica-
tions 2 or 3.
(c) If the minimum quantity of emis-
sion data as required by 9 60.47a Is not
obtained for any 30 successive boiler
operating days, the following Informa-
tion obtained under the requirements
of J60.46a(h) Is reported to the Ad-
ministrator for that 30-day period:
(1) The number of hourly averages
available for outlet emission rates (n.)
and Inlet emission rates (n,) as applica-
ble.
(2) The standard deviation of hourly
averages for outlet emission rates (s.)
and inlet emission rates (s,) as applica-
ble.
S 60.49a
(3) The lower confidence limit for
the mean outlet emission rate (£„•)
and the upper confidence limit for the
mean Inlet emission rate (E,*) as appli-
cable.
(4) The applicable potential combus-
tion concentration.
(5) The ratio of the upper confi-
dence limit for the mean outlet emis-
sion rate (E.*) and the allowable emis-
sion rate (E^) as applicable.
(d) If any standards under { 60.43a
are exceeded during emergency condi-
tions because of control system mal-
function, the owner or operator of the
affected facility shall submit a signed
statement:
(1) Indicating If emergency condi-
tions existed and requirements under
160.46a(d) were met during each
period, and
(2) Listing the following Informa-
tion:
(I) Time periods the emergency con-
dition existed;
(II) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(III) Amount of power purchased
from Interconnected neighboring utili-
ty companies during the emergency
period;
(Iv) Percent reduction In emissions
achieved:
(v) Atmospheric emission rate (ng/J)
of the pollutant discharged: and
(vl) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit
toward the sulfur dioxide emission
standard under } 60.43a Is claimed, the
owner or operator of the affected fa-
cility shall submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the cal-
endar quarter, and whether the credit
was determined in accordance with the
provisions of fi60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat con-
tent, and date each pretreated fuel
shipment was received during the pre-
vious quarter; the name and location
of the fuel pretreatment facility; and
the total quantity and total heat con-
tent of all fuels received at the affect-
ed facility during the previous quarter.
(f> For any periods for which opaci-
ty, sulfur dioxide or nitrogen' oxides
-------
c ma are ..„. aval .. the
owner or operator of the affected fa-
cility shall submit a signed statement
Indicating If any changes were made In
operation of the emission control
system during the period of data un-
availability. Operations of the control
system and affected facility during pe-
riods of data unavailability are to be
compared with operation of the con-
trol system and affected facility before
and following the period of data un-
availability.
(g) The owner or operator of the af-
fected facility shall submit a signed
statement Indicating whether
(1) The required continuous moni-
toring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to show compli-
ance was or was not obtained In ac-
cordance with approved methods and
procedures of this part and Is repre-
sentative of plant performance.
. (3) The minimum data requirements
have or have not been met: or. the
minimum data requirements have not
been met for errors that were unavoid-
able.
(4) Compliance with the standards
has or has not been achieved during
the reporting period.
(h) For the purposes of the reports
required under 160.7. periods of excess
emissions are defined as all 6-mlnute
periods during which the .average
opacity exceeds the applicable opacity
standards under |60.42a(b). Opacity
levels in excess of the applicable opaci-
ty standard and the date of such ex-
cesses are to be submitted to the Ad-
ministrator each calendar quarter.
(I) The owner or operator of an af-
fected facility shall submit the written
reports required under this section
and subpart A to the Administrator
for every calendar quarter. All quar-
terly reports shall be postmarked by
the 30th day following the end of each
calendar quarter.
49 CfR Ch. I (7-1-88 Edition)
subpart Db—Standard* of Perform-
ance for Indvttrial-Commerclal-
Initltutlonal Steam Generating
Units
SOUXCE 63 PR 47842, Dec 16. 1987. unless
otherwise noted.
060.40b Applicability and delegation of
authority.
(a) The affected facility to which
this subpart applies Is each steam gen-
erating unit that commences construc-
tion, modification, or reconstruction
after June 19, 1984. and that has a
heat Input capacity from fuels com-
busted In the steam generating unit of
greater than 29 MW (100 million Btu/
hour).
(b) Any affected facility meeting the
applicability requirements under para-
graph (a) of this section and commenc-
ing construction, modification, or re-
construction after June 19, 1984, but
on or before June 19, 1988, is subject
to the following standards:
(1) Coal-fired affected facilities
having a heat Input capacity between
29 and 73 MW (100 and 250 million
Btu/hour), Inclusive, are subject to
the participate matter and.nitrogen
oxides standards under this subpart.
(3) Coal-fired affected facilities
having a heat Input capacity greater
than 73 MW (250 million Btu/hour)
and meeting the applicability require-
ments under Subpart D (Standards of
performance for fossll-fuel-fIred steam
generators: 160.40) are subject to the
partlculate matter and nitrogen oxides
standards under this subpart and to
the sulfur dioxide, standards under
Subpart D (| 60.43).
(3) OU-flred affected facilities
having a heat Input capacity between
29 and 73 MW (100 and 250 million
Btu/hour), Inclusive, are subject to
the nitrogen oxides standards under
this subpart.
(4) Oil-fired affected facilities
•having a heat Input capacity greater
than 73 MW C250 million Btu/hour)
and meeting the applicability require-
ments under Subpart D (Standards of
performance for fossll-fuel-flred steam
generators: 160.40) are also subject to
the nitrogen oxides standards under
this subpart and the partlculate
274
•--Iran
ten
matter and sulfur dioxide standards
under Subpart O (8 60.42 and 5 60.43).
(c) Affected facilities which also
meet the applicability requirements
under Subpart J (Standards of per-
formance for petroleum refineries;
160.104) are subject to the partlculate
matter and nitrogen oxides standards
under this subpart and the sulfur di-
oxide standards under Subpart J
(160.104).
(d) Affected facilities which also
meet the applicability requirements
under Subpart E (Standards of per-
formance for Incinerators; i 60.50) are
subject to the nitrogen oxides and par-
tlculate matter standards under this
subpart.
(e) Steam generating units meeting
the applicability requirements under
Subpart Da (Standards of perform-
ance for electric utility steam generat-
ing units; | 60.40a) are not subject to
this subpart.
(f) Any change to an existing steam
generating unit for the sole purpose of
combusting gases containing TRS as
defined under 8 60.281 Is not consid-
ered a modification under 160.14 and
the steam generating unit Is not sub-
ject to this subpart.
(g) In delegating Implementation
and enforcement authority to a State
under section 11 He) of the Act. the
following authorities shall be retained
by the Administrator and not trans-
ferred to a State.
(1) Section 60.44b(f).
(2) Section 60.44b(g).
(3) Section Q0.49b(a)(4).
960.41b Definitions.
As used In this subpart. all terms not
defined herein shall have the meaning
given them In the Act and In Subpart
A of this part.
"Annual capacity factor" means the
ratio between the actual heat input to
a steam generating unit from the fuels
listed In 860.42b(a), J60.43b(a). or
160.44b(a). as applicable, during a cal-
endar year and the potential heat
input to the steam generating unit
had It been-operated for 8.760 hours
during a calendar year at the maxi-
mum steady state design heat Input
capacity. In the case of steam generat-
ing units that are rented or leased, the
actual heat Input shall be determined
based on the combined heat Input
from all operations of the affected fa-
cility In a calendar year.
"Byproduct/waste" means any liquid
or gaseous substance produced at
chemical manufacturing plants or pe-
troleum refineries (except natural gas.
distillate oil, or residual oil) and com-
busted in a steam generating unit for
heat recovery or for disposal. Gaseous
substances with carbon dioxide levels
greater than 50 percent or carbon
monoxide levels greater than 10 per-
cent are not byproduct/waste for the
purposes of this subpart.
"Chemical manufacturing plants"
means Industrial plants which are clas-
sified by the Department of Com-
merce under Standard Industrial Clas-
sification (SIC) Code 28.
"Coal" means all solid fuels classi-
fied as anthracite, bituminous, subbl-
tuminous. or lignite by the American
Society of Testing and Materials In
ASTM D388-77, Standard Specifica-
tion for Classification of Coals by
Rank (IBR—see 860.17), coal refuse,
and petroleum coke. Coal-derived syn-
thetic fuels, Including but not limited
to solvent refined coal, gasified coal.
coal-oil mixtures, and coal-water mix-
tures, are also Included In this defini-
tion for the purposes of this subpart.
"Coal refuse" means any byproduct
of coal mining or coal cleaning oper-
ations with an ash content greater
thaa 60 percent, by weight, and a
heating value less than 13.900 kJ/k*
(6.000 Btu/lb) on a dry basis.
"Combined cycle system" means a
system In which a separate source,
such as a gas turbine. Internal combus-
tion engine, kiln, etc., provides ex-
haust gas to a heat recovery steam
generating unit.
"Conventional technology" means
wet Hue gas desulfurizatlon (FDD)
technology, dry POD technology, at-
mospheric fluldlzed bed combustion
technology, and oil hydrodesulfuriza-
tlon technology.
"Distillate oil" means fuel oils that
contain 0.05 weight percent nitrogen
or less and comply with the specifica-
tions for fuel oil numbers 1 and 2. as
defined by the American Society of
Testing and Materials In ASTM D396-
78, Standard Specifications for Fuel
275
-------
}«0.41b
Oils (Incorporated by reference-
160.17).
"Dry flue gas desulfurlzatlon tech-
nology" means a sulfur dioxide control
system that is located downstream of
the steam generating unit and re-
moves sulfur oxides from the combus-
tion gases of the steam generating
unit by contacting the combustion
gases with an alkaline slurry or solu-
tion and forming a dry powder materi-
al This definition Includes devices
where the dry powder material Is sub-
sequently converted to another form.
Alkaline slurries or solutions used In
dry flue gas desulfurlzatlon technolo-
gy Include but are not limited to lime
and sodium.
"Duct burner" means a device that
combusts fuel and that Is placed In the
exhaust duct from another source,
such as a stationary gas turbine, Inter-
nal combustion engine, kiln, etc., to
allow the firing of additional fuel to
heat the exhaust gases before the ex-
haust gases enter a heat recovery
steam generating unit
"Emerging technology" means any
sulfur dioxide control system that Is
not defined as a conventional technol-
ogy under this section, and for which
the owner or operator of the facility
has applied to the Administrator and
received approval to operate as an
emerging technology under
160.40b(aK4).
"Federally enforceable" means all
limitations and conditions that are en-
forceable by the Administrator. In-
eluding the requirements of 40 CFR
Parts 60 and 61, requirements within
any applicable State Implementation
Plan, and any permit requirements es-
tablished under 40 CFR S2.21 or under
40 CFR 81.18 and 40 CFR 61.24.
"Fluldlzed bed combustion .technolo-
gy" means combustion of fuel In a bed
or series of beds (Including but not
limited to bubbling bed units and cir-
culating bed units) of limestone aggre-
gate (or other sorbent materials) In
which these materials are forced
upward by the flow of combustion air
and the gaseous products of combus-
tion.
"Fuel pretreatment" means a proc-
ess that removes a portion of the
sulfur In a fuel before combustion of
the fuel In a steam generating unit.
40 CFR Ch. I (7-148 Edition)
' "Full capacity" means operation of
the steam generating unit at 00 per-
cent or more of the maximum steady-
state design heat input capacity.
"Heat Input" means heat derived
from combustion of fuel In a steam
generating unit and does not Include
the heat Input from preheated com-
bustion air, reclrculated flue gases, or
exhaust gases from other sources,
such as gas turbines, Internal combus-
tion engines, kilns, etc.
"Heat release rate" means the steam
generating unit design heat Input ca-
pacity (In MW or Btu/hour) divided
by the furnace volume (in cubic
meters or cubic feet); the furnace
volume Is that volume bounded by the
front furnace wall where the burner Is
located, the furnace side waterwall.
and extending to the level just below
or In front of the first row of convec-
tion pass tubes.
"Heat transfer medium" means any
material that Is used to transfer heat
from one point to another point
"High heat release rate" means a
heat release rate greater than 730.000
J/sec-m* (70.000 Btu/hour-ft*).
"Lignite" means a type of coal classi-
fied as lignite A or lignite B by the
American Society of Testing and Ma-
terials In ASTM D388-77. Standard
Specification for Classification of
Coals by Rank (IBR—see I 60.17).
"Low heat release rate" means a
heat release rate of 730.000 J/sec-m*
(70,000 Btu/hour-ft1) or less.
. "Mass-feed stoker steam generating
unit" means a steam generating unit
where solid fuel is Introduced directly
Into a retort or Is fed directly onto a
grate where It Is combusted.
"Maximum heat Input capacity"
means the ability of a steam generat-
- Ing unit to combust a stated maximum
amount of fuel on a steady state basis.
as determined by the physical design
and characteristics of the steam gener-
ating unit
"Municipal-type solid waste" means
refuse, more than 50 percent of which
la waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other
combustible materials, and noncom-
bustlble materials such as glass and
rock.
276
Environmental Protection Agency
"Natural gas" means (1) a naturally
occurring mixture of hydrocarbon and
nonhydrocarbon gases found In geo-
logic formations beneath the earth's
surface, of which the principal constit-
uent is methane; or (2) liquid petrole-
um gas, as defined by the American
Society for Testing and Materials In
ASTM D1835-82. "Standard Specifica-
tion for Liquid Petroleum Oases"
(IBR-see 160.17).
"Noncontlnental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Com-
monwealth of Puerto Rico, or the
Northern Mariana Islands..
"Oil" means crude oil or petroleum
or a liquid fuel derived from crude oil
or petroleum. Including distillate and
residual oil.
"Petroleum refinery" means indus-
trial plants as classified by the Depart-
ment of Commerce under Standard In-
dustrial Classification (SIC) Code 29.
"Potential sulfur dioxide emission
rate" means the theoretical sulfur di-
oxide emissions (ng/J, Ib/mllllon Btu
heat input) that would result from
combusting fuel In an uncleaned state
and without using emission control
systems.
"Process heater" means a device
that Is primarily used to heat a mate-
rial to Initiate or promote a chemical
reaction in which the material partici-
pates as a reactant or catalyst.
"Pulverized coal-fired steam generat-
ing unit" means a steam generating
unit In which pulverized coal is Intro-
duced Into an air stream that carries
the coal to the combustion chamber of
the steam generating unit where it is
fired In suspension. This Includes both
conventional pulverized coal-fired and
mlcropulverlzed coal-fired steam gen-
erating units.
"Residual oil" means crude oil. fuel
oil numbers 1 and 2 that have a nitro-
gen content greater than 0.05 weight
percent, and all fuel oil numbers 4. 5
and 6, as defined by the American So-
ciety of Testing and Materials In
ASTM D396-78. Standard Specifica-
tions for Fuel Oils (IBR-see f 60.17).
"Spreader stoker steam generating
unit" means a steam generating unit
In which solid fuel Is Introduced to the
combustion zone by a mechanism that
throws the fuel onto a grate from
§ 60.41b
above. Combustion takes place both in
suspension and on the grate.
"Steam generating unit" means a
device that combusts any fuel or by-
product/waste to produce steam or to
heat water or any other heat transfer
medium. This term Includes any mu-
nicipal-type solid waste Incinerator
with a heat recovery steam generating
unit or any steam generating unit that
combusts fuel and is part of a cogen-
eratlon system or a combined cycle
system. This term does not Include
process heaters as they are defined In
this subpart
"Steam generating unit operating
day" means a 24-hour period between
12:00 midnight and the following mid-
night during which any fuel Is com-
busted at any time In the steam gener-
ating unit It Is not necessary for fuel
to be combusted continuously for the
entire 24-hour period.
"Very low sulfur oil" means a distil-
late oil or residual oil that when com-
busted without post combustion Sd
control has an 8Oi emission rate equal
to or less than 130 ng/J (0.30 Ib SO,/
million Btu).
"Wet flue gas desulfurteatlon tech-
nology" means a sulfur dioxide control
system that Is located downstream of
the steam generating unit and re-
moves sulfur oxides from the combus-
tion gases of the steam generating
unit by contacting the combustion gas
with an alkaline slurry or solution and
forming a liquid material. This defini-
tion applies to devices where the aque-
ous liquid material product of this
contact Is subsequently converted to
other forms. Alkaline reagents used In
wet flue gas desulfurlzatlon technolo-
gy include, but are not limited to. lime.
limestone, and sodium.
"Wet scrubber system" means any
emission control device that mixes an
aqueous stream or slurry with the ex-
haust gases from a steam generating
unit to control emissions of participate
matter or sulfur dioxide.
"Wood" means wood, wood residue,
bark, or any derivative fuel or residue
thereof. In any form. Including, but
not limited to. sawdust, sanderd :.
wood chips, scraps, slabs, millings.
shavings, and processed pellets made
from wood or other forest residues.
-------
§ 1,
1 6XM2b Standard for suitor dioxide.
(a) Except u provided In paragraphs
(b), (e), or (d) of this section, on and
after the date on which the perform*
ance test Is completed or required to
be completed under 1 60.8 of this part,
whichever date comes first, no owner
or operator of an affected facility that
combusts coal or oil shall cause to be
discharged Into the atmosphere any
gases that contain sulfur dioxide In
excess of 10 percent (0.10) of the po-
tential sulfur dioxide emission rate (90
percent reduction) and that contain
sulfur dioxide In excess of the emis-
sion limit determined according to the
following formula:
where:
E. Is the sulfur dJoxlde eralnton limit. In
nt/J or lb/mflllon Btu heat Input,
K. to 630 ng/J (or 1.3 Ib/mtlllon Btu).
K» U 340 nt/J (or 0.80 Ib/rallllon Btu).
H. Is the heat Input from the combustion of
coal. In J (million Btu).
R» Is the heat Input from the combustion of
oil. In J (million Btu).
Only the heat Input supplied to the af-
fected facility from the combustion of
coal and oil Is counted under this sec-
tion. No credit Is provided for the heat
Input to the affected facility from the
combustion of natural gas. wood, mu-
nicipal-type solid waste, or other fuels'
or heat Input to the affected facility
from exhaust gases from another
source, such as gas turbines, Internal
combustion engines, kilns, etc.
(b) On and after the date on which
the performance test Is completed or
required to be completed under 1 60.8
of this part, whichever comes first, no
owner or operator of an affected facili-
ty that combusts coal refuse alone In a
fluldteed bed combustion steam gener-
ating unit shall cause to be discharged
Into the atmosphere any gases that
contain sulfur dioxide In excess of 20
percent of the potential sulfur dioxide
emission rate (80 percent reduction)
and that contain sulfur dioxide In
excess of 520 ng/J (1.2 Ib/mllllon Btu)
heat Input. If coal or oil Is fired with
coal refuse, the affected facility Is sub-
ject to paragraph (a) or.(d). of this sec-
tion, as applicable.
(c) On and after the date on which
the performance test Is completed or
Is required to be completed under
Cf (7 Edll
160.8 of this part, whichever comes
first, no owner or operator of an af-
fected facility that combusts coal or
oil, either alone or in combination
with any other fuel, and that uses an
emerging technology for the control of
sulfur dioxide emissions, shall cause to
be discharged Into the atmosphere any
gases that contain sulfur dioxide In
excess of 50 percent of the potential
sulfur dioxide emission rate (50 per-
cent reduction) and that contain
sulfur dioxide In excess of the emis-
sion limit determined according to the
following formula:
where:
E, Is the sulfur dioxide emission limit, ex-
pressed In ng/J (Ib/mllllon Btu) heat
Input.
K. Is 360 ng/J (0.60 Ib/mllllon Btu).
K« Is 170 nt/J (0.40 Ib/mllllon Btu).
H, Is the heat .Input from the combustion of
coal. J (million Btu),
Ht Is the heat Input from the combustion of
oil. J (million Btu).
Only the heat.Input supplied to the af-
fected facility from the combustion of
coal and oil Is counted under this sec-
tion. No credit Is provided for the heat
Input to the affected facility from the
combustion of natural gas, wood, mu-
nicipal-type solid waste, or other fuels,
or from the heat Input to the affected
facility from exhaust gases from an-
other source, such as gas turbines, In-
ternal combustion engines, kilns, etc".
(d) On and after the date on which
the performance test Is completed or
required to be completed under 160.8
of this part, whichever comes first, no
owner or operator of an affected facili-
ty listed In paragraphs (d) (1), (2), (3).
or (4) of this section shall cause to be
discharged Into the atmosphere any
gases that contain sulfur dioxide In
excess of 820 ng/J (1.2 Ib/mllllon Btu)
heat input If the affected facility com-
busts coal, or 130 ng/J (0.30 Ib/mllllon
Btu) heat Input If the affected facility
combusts oil. Percent reduction re-
quirements are not applicable to af-
fected facilities under this paragraph:
(1) Affected facilities that have an
annual capacity factor for coal and oil
of 30 percent (0.30) or less and are sub-
ject to a federally enforceable permit
limiting the operation of the affected
facility to an annual capacity factor
278
Iroi
•IP
Ion
,... ey
for coal and oil to 30 percent (0.30) or
less*
(2) Affected facilities located In a
noncontlnental area;
(3) Affected facilities combusting
coal or oil, alone or In combination
with any other fuel. In a duct burner
as part of a combined cycle system
where 30 percent (0.30) or less of the
heat Input to the steam generating
unit Is from combustion of coal and oil
In the duct burner and 70 percent
(0.70) or more of the heat Input to the
steam generating unit Is from .the ex-
haust gases entering the duct burner:
or
(4) Affected facilities combusting
very low sulfur oil.
(e) Except as provided in paragraph
(f) of this section, compliance with the
emission llmlt(s) and percent reduc-
tion requirements under this section
are determined on a 30-day rolling av-
erage basis.
(f) Compliance with the emission
limits under this section are deter-
mined on a 24-hour average basis for
affected facilities which (1) have a fed-
erally enforceable permit limiting the
annual capacity factor for oil to 10
percent or less, (2) combust only oil
which emits less than 130 ng/J (0.3 Ib
SOt/mllllon Btu). and (3) do not com-
bust any other fuel.
(g) Except as provided in paragraph
(1) of this section, the sulfur dioxide
emission limits and percent reduction
requirements under this section apply
at all times. Including periods of start-
up, shutdown, and malfunction.
(h) Reductions In the potential
sulfur dioxide emission rate through
fuel pretreatment are not .credited
toward the percent reduction require-
ment under paragraph (c) of this sec-
tion unless:
(1) Fuel pretreatment results In a SO
percent or greater reduction In poten-
tial sulfur dioxide emissions and
(2) Emissions from the pretreated
fuel (without combustion or post com-
bustion sulfur dioxide control) are
equal to or less than the emission
limits specified In paragraph (c) of
this section.
(I) An affected facility subject to
paragraph (a), (b), or (c) of this sec-
tion may combust very low sulfur oil
or natural gas when the sulfur dioxide
control system Is not being operated
because of malfunction or mainte-
nance of the sulfur dioxide control
system.
0 60.43b Standard for partlculate matter.
(a) On and after the date on which
the Initial performance test Is com-
pleted or Is required to be completed
under 8 60.8 of this part, whichever
comes first, no owner or operator of an
affected facility which combusts coal
or combusts mixtures of coal with
other fuels, shall cause to be dis-
charged Into the atmosphere from
that affected facility any gases that
contain partlculate matter In excess of
the following emission limits:
(1) 22 ng/J (0.05 Ib/mllllon Btu)
heat input,
(1) If the affected facility combusts
only coal, or
(11) If the affected facility combusts
coal and other fuels and has an annual
capacity factor for the other fuels of
10 percent (0.10) or less.
(2) 43 ng/J (0.10 Ib/mtlllon Btu)
heat Input if the affected facility com-
busts coal and other fuels and has an
annual capacity factor for the other
fuels greater than 10 percent (0.10)
and Is subject to a federally enforcea-
ble requirement limiting operation of
the affected facility to an annual ca-
pacity factor greater than 10 percent
(0.10) for fuels other than coal.
(3) 86 ng/J (0.20 Ib/mllllon Btu)
heat Input If the affected facility com-
busts coal or coal and other fuels and
(I) Has an annual capacity factor for
coal or coal and other fuels of 30 per-
cent (0.30) or less,
(II) Has a maximum heat input ca-
pacity of 73 MW (250 million Btu/
hour) or less,
(ill) Has a federally enforceable re-
quirement limiting operation of the af-
fected facility to an annual capacity
factor of 30 percent (0.30) or less for
coal or coal and other solid fuels, and
(iv) Construction of the affected fa-
cility commenced after June 19, 1D84,
and before November 25.1986.
(b) On and after the date on which
the performance test Is completed or
required to be completed under { 60.8
of this part, whichever date comes
first, no owner or operator of an af-
279
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§60.44b
fected facility that combusts oil or
that combusts mixtures of oil with
other fuels shall cause to be dis-
charged Into the atmosphere from
that affected facility any gases that
contain particulate matter In excess of
43 ng/J (0.10 Ib/mllllon Btu) heat
Input
(c) On and after the date on which
the Initial performance test Is com-
pleted or Is required to be completed
under 160.8 of this part, whichever
date comes first, no owner or operator
of an affected facility that combusts
wood, or wood with other fuels, except
coal, shall cause to be discharged from
that affected facility any gases that
contain particulate matter In excess of
the following emission limits:
(1) 43 ng/J (0.10 Ib/mllllon Btu)
heat Input If the affected facility has
an annual capacity factor greater than
30 percent (0.30) for wood.
(2) 86 ng/J (0.20 Ib/mllllon Btu)
heat Input If
(I) The affected facility has an
annual capacity factor of 30 percent
(0.30) or less for wood.
(II) Is subject to a federally enforcea-
ble requirement limiting operation of
the affected facility to an annual ca-
pacity factor of 30 percent (0.30) or
less for wood, and
(III) Has a maximum heat Input ca-
pacity of 73 MW (250 million Btu/
hour) or less.
(d) On and after the date on which
the Initial performance test Is com-
pleted or Is required to be completed
under 160.8 of this part, whichever
date comes first, no owner or operator
of an affected facility that combusts
municipal-type solid waste or mixtures
of municipal-type solid waste with
other fuels, shall cause to be dis-
charged Into the atmosphere from
that affected facility any gases that
contain particulate matter In excess of
the following emission limits:
(1) 43 ng/J (0.10 Ib/mllllon Btu)
heat Input,
(I) If the affected facility combusts
only municipal-type solid waste, or
(II) If the affected facility combusts
municipal-type solid waste and other
fuels and has an annual capacity
factor for the other fuels of 10 percent
(0.10) or less.
40 CFI Ch. I (7-1-88 Edition)
(2) 88 ng/J (0.20 Ib/mllllon Btu)
heat Input If the affected facility com-
busts municipal-type solid waste or
municipal-type solid waste and other
fuels; and
(1) Has an annual capacity factor for
municipal-type solid waste and other
fuels of 30 percent (0.30) or less,
(11) Has a maximum heat input ca-
pacity of 73 MW (250 million Btu/
hour) or less.
(Ill) Has a federally enforceable re-
quirement limiting operation of the af-
fected facility to an annual capacity
factor of 30 percent (0.30) for munici-
pal-type solid waste, or municipal-type
solid waste and other fuels, and
(Iv) Construction of the affected fa-
cility commenced after June 19. 1984.
but before November 25.1986.
(e) For the purposes of this section.
the annual capacity factor Is deter-
mined by dividing the actual heat
Input to the steam generating unit
during the calendar year from the
combustion of coal, wood, or munici-
pal-type solid waste, and other fuels.
as applicable, by the potential heat
Input to the steam generating unit If
the steam generating unit had been
operated for 8.760 hours at the maxi-
mum design heat Input capacity.
(f) On and after the date on which
the Initial performance test Is com-
pleted or Is required to be completed
under 160.8 of this part, whichever
date comes first, no owner or operator
of an affected facility subject to the
particulate matter emission limits
under paragraph-(a), (b) or (c) of this
section shall cause to be discharged
Into the atmosphere any gases that
exhibit .greater than 20 percent opaci-
ty (6-minute average), except for one
6-mlnute period per hour of not more
. than 27 percent opacity.
(g) The particulate matter and opac-
ity standards apply at all tunes, except
during periods of startup, shutdown or
malfunction.
B 60.44b Standard for nitrogen oxides.
(a) On and after the date on which
the Initial performance test Is com-
pleted or Is required to be completed
under 160.8 of this part, whichever
date comes first, no owner or operator
of an affected facility that Is subject
280
Environmental Protection Agency
to the provisions of this section and
that combusts only coal, oil, or natural
gas shall cause to be discharged Into
the atmosphere from that affected fa-
cility any gases that contain nitrogen
oxides (expressed as NOi) In excess of
the following emission limits:
Fuol/St*am ggnaraOng unit typ*
(1) Natural gn and oHMat* oi. «re«pl (4):
(I) LOW h0d i*i
-------
"-ntr
lltle
neousiy combusts coal. oil. or natural
gas with byproduct/waste shall cause
to be discharged Into the atmosphere
from that affected facility any gases
that contain nitrogen oxides In excess
of an emission limit determined by the
following formula unless the affected
facility has an annual capacity factor
for coal. oil. and natural gas of 10 per-
cent (0.10) or less and Is subject to a
federally enforceable requirement
which limits operation of the affected
facility to an annual capacity factor of
10 percent (0.10) or less:
H.)]/
where:
E. to the nitrogen oxides emission limit (ex-
pressed as NO,), ng/J (Ib/mllllon Btu)
to the expropriate emission limit from
paragraph for combustion of nat-
ural gas or distillate oil. ng/J (Ib/mllllon
Btu).
B.. to the heat Input from combustion of
natural fas. distillate oil and gaseous by-
product/waste.. ng/J (Ib/mllllon Btu).
**->, to the appropriate emission limit from
paragraph (aX2> for combustion of re-
sidual 00. ng/J (Ib/mllllon Btu)
RK b the heat Input from combustion of re-
sidual oil and/or Mould byproduct/
waste.
EU Is the appropriate emission limit from
paragraph (aX3) for combustion of coal.
and
H. to the heat Input from combustion of
coal
(f) Any owner or operator of an af-
fected facility that combusts byprod-
uct/waste with either natural gas or
oil may petition the Administrator
within 180 days of the Initial startup
of the affected facility to establish a
nitrogen oxides emission limit which
shall apply specifically to that affect-
ed facility when the byproduct/waste
Is combusted. The petition shall In-
clude sufficient and appropriate data,
as determined by the Administrator.
such as nitrogen oxides emissions from
the affected facility, .waste composi-
tion (Including nitrogen content), and
combustion conditions to allow the
Administrator to confirm that the -af-
fected facility Is unable to comply
with the emission limits In paragraph
(e) of this section and to determine
the appropriate emission limit for the
affected faculty.
(1) Any owner or operator of an af-
fected facility petitioning for a facili-
ty-specific nitrogen oxides emission
limit under this section shall:
(I) Demonstrate compliance with the
emission limits for natural gas and dis-
tillate oil In paragraph (a)(l) of this
section or for residual oil In paragraph
(a)(2) of this section, as appropriate.
by conducting a 30-day performance
test as provided in 160.46b(e). During
the performance test only natural gas.
distillate oil. or residual oil shall be
combusted In the affected facility; and
(11) Demonstrate that the affected
facility Is unable to comply with the
emission limits for natural gas and dis-
tillate oil In paragraph (a)(l) of this
section or for residual oil In paragraph
(aX2) of this section, as appropriate,
when gaseous or liquid byproduct/
waste Is combusted In the affected fa-
cility under the same conditions and
using the same technological system
of emission reduction applied when
demonstrating compliance under para-
graph (f)(l)(l) of this section.
(2) The nitrogen oxides emission
limits for natural gas or distillate oil In
paragraph (aKl) of this section or for
residual oil In paragraph (a)(2) of this
section, as appropriate, shall be appli-
cable to the affected facility until and
unless the petition Is approved by the
Administrator. If the petition Is ap-
proved by the Administrator, a fadli-
ty-speclflc nitrogen oxides emission
limit will be established at the nitro-
gen oxides emission level achievable
when the affected facility is combust-
ing oil or natural gas and byproduct/
waste In a manner that the Adminis-
trator determines to be consistent
with minimizing nitrogen oxides emis-
sions.
(g) Any owner or operator of an af-
fected facility that combusts hazard-
ous waste (as defined by 40 CFR Part
261 or 40 CFR Part 761) with natural
gas or oil may petition the Administra-
tor within 180 days of the Initial start-
up of the affected facility for a. waiver
from compliance with the nitrogen
oxides emission limit which applies
specifically to .that affected facility.
The petition must Include sufficient
and appropriate data, as determined
by the Administrator, on nitrogen
oxides emissions from the affected fa-
282
ivln
itol
cflo
cility. waste destruction efficiencies.
waste composition (Including nitrogen
content), the quantity of specific
wastes to be combusted and combus-
tion conditions to allow the Adminis-
trator to determine If the affected fa-
cility Is able to comply with the nitro-
gen oxides emission limits required by
this section. The owner or operator of
the affected facility shall demonstrate
that when hazardous waste Is com-
busted In the affected facility, thermal
destruction efficiency requirements
for hazardous waste specified In an ap-
plicable federally enforceable require-
ment preclude compliance with the ni-
trogen oxides emission limits of this
section. The nitrogen oxides emission
limits for natural gas or distillate oil In
paragraph (a)(l) of this section or for
residual oil In paragraph (a)(2) of this
section, as appropriate, are applicable
to the affected facility until and
unless the petition Is approved by the
Administrator. (See 40 CFR 761.70 for
regulations applicable to the inciner-
ation of materials containing polychlo-
rlnated blphenyls (PCB's).)
(h) The nitrogen oxide standards
under this section apply at all times
Including periods of startup, shutdown
or malfunction.
§ 60.45b Compliance and performance test
methods and procedures for sulfur di-
oxide.
(a) The sulfur dioxide emission
standards under } 60.42b apply at all
times.
(b) In conducting the performance
tests required under i 60.8, the owner
or operator shall use the methods and
procedures In Appendix A of this part
or the method and procedures as spec-
ified In this section, except as provided
in 860.8(b). Section 60.8(f) does not
apply to this subpart. The 30-day
notice required In {80.8(d) applies
only to the Initial performance test
unless otherwise specified by the Ad-
ministrator.
(c> The owner or operator of an af-
fected facility shall conduct perform-
ance tests to determine compliance
with the percent of potential sulfur di-
oxide emission rate (% P.) and the
sulfur dioxide emission rate (E,) pur-
suant to { 80.42b following the proce-
gov.45b
dures listed below, except as provided
under paragraph (d) of this section.
(1) The initial performance test shall
be conducted over the first 30 consecu-
tive operating days of the steam gen-
erating unit. Compliance with the
sulfur dioxide standards shall be de-
termined using a 30-day average. The
first operating day Included In the Ini-
tial performance test shall be sched-
uled within 30 days after achieving the
maximum production rate at which
the affected facility will be operated.
but not later than 180 days after Ini-
tial startup of the facility.
(2) If only coal or only oil Is com-
busted. the following procedures are
used:
(I) The procedures In Method 19 are
used to determine the hourly sulfur
dioxide emission rate (£*.) and the 30-
day average emission rate (£«,). The
hourly averages used to compute the
30-day averages are obtained from the
continuous emission monitoring
system of 9 60.47b (a) or (b).
(II) The percent of potential sulfur
dioxide emission rate (% P.) emitted to
the atmosphere Is computed using the
following formula:
% P.-100 (l-» R./100Xl-% R./100)
where:
% R, to the sulfur dioxide removal efficiency
of the control device as determined by
Method 19, In percent.
% R, Is the sulfur dioxide removal efficiency
of fuel pretreatment as determined by
Method 19. In percent.
(3) If coal or oil Is combusted with
other fuels, the same procedures re-
quired In paragraph (c)(2) of this sec-
tion are used, except as provided In
the following:
(I) An adjusted hourly sulfur dioxide
emission rate (E^*) Is used In Equation
19-19 of Method 19 to compute an ad-
justed 30-day average emission rate
(E»«). The Efc. is computed using the
following formula:
where:
Ek." to the adjusted hourly sulfur dioxide
emission rate, ng/J (Ib/mllllon Btu).
Ek. to the hourly sulfur dioxide emission
rate. ng/J (Ib/mllllon Btu). •
283
-------
860.45b
E. to the sulfur dioxide concentration In
fuela other than coal and oil combusted
In the affected facility, aa determined by
the fuel sampling and analyst* proce-
dure! In Method IP. ng/J (Ib/mllllon
Btu). The value E. for each fuel lot Is
used for each hourly average during the
time that the lot U being combusted.
Xt to the fraction of total heat Input from
fuel combustion derived from coal. oil.
or coal and on, as determined by appli-
cable procedures In Method 10.
(11) To compute the percent of po-
tential sulfur dioxide emission rate (%
P.). an adjusted % R, (% R,*) Is com-
puted from the adjusted EM* from
paragraph (bX3Mi) of this section and
an adjusted average sulfur dioxide
Inlet rate (EU*) using the following for-
mula:
% R.— 100 U.O-E.*/ZM*>
To compute E,/. an adjusted hourly
sulfur dioxide Inlet rate (E«*) Is used.
The EM* Is computed using the follow-
ing formula:
where
EM* to the adjusted hourly sulfur dioxide
Inlet rate. ng/J (Ib/rallllon Btu).
EM Is the hourly sulfur dioxide Inlet rate.
ng/J (Ib/mUlion Btu).
(4) The owner or operator of an af-
fected facility subject to paragraph
(6X3) of this section does not have to
measure parameters E. or X* If the
owner or operator elects to assume
that X»-1.0. Owners or operators of
affected faculties who assume X*-1.0
shall
(I) Determine % P, following the
procedures In paragraph (c)(3) of this
section, and
(11) Sulfur dioxide emissions (E.) are
considered to be In compliance with .
sulfur, dioxide emission limits under
1 60.42b.
(5) The owner or operator of an af-
fected faculty that qualifies under the
provisions of 1 60.42b(d) does not have
to measure parameters E. or X» under
paragraph (bX3) of this section If the
owner or operator of the affected -fa-
cility elects to measure sulfur dioxide
emission rates of the coal or oU follow-
ing the fuel sampling arid analysis pro-
cedures under Method 19.
(d) The owner or operator of an af-
fected facility that combusts only oil
40 CFR Ch. I (7.148 Edition)
emitting less than 130 ng/J (0.3 lb/
million Btu) 8O», has an annual capac-
ity factor for oil of 10 percent (0.10) or
less, and Is subject to a federally en-
forceable requirement limiting oper-
ation of the affected facility to an
annual capacity for oU of 10 percent
(0.10) or less shall:
(1) Conduct the Initial performance
test over 24 consecutive steam generat-
ing unit operating hours at full load;
(2) Determine compliance with the
standards after the Initial perform-
ance test based on the arithmetic aver-
age of the hourly emissions data
during each steam generating unit op-
erating day If a continuous emission
measurement system (CEMS) Is used.
or based on a dally average if Method
6B or fuel sampling and analysis pro-
cedures under Method 19 are used.
(e) The owner or operator of an af-
fected facility subject to 160.42b(d)(l)
shall demonstrate the maximum
design capacity of the steam generat-
ing unit by operating the facility at
maximum capacity for 24 hours. This
demonstration will be made during the
Initial performance test and a subse-
quent demonstration may be request-
ed at any other time. If the 24-hour
average firing rate for the affected fa-
cility Is less than the maximum design
capacity provided by the manufactur-
er of the affected faculty, the 24-hour
average firing rate shall be used to de-
termine the capacity utilization rate
for the affected faculty, otherwise the
maximum design capacity provided by
the manufacturer Is used.
(f) For the Initial performance test
required under (60.8. compliance with
the sulfur dioxide emission limits and
percent reduction requirements under
160.42b is based on the average emis-
sion rates and the average percent re-
duction for sulfur dioxide for the first
30 consecutive steam generating unit
operating days, except as provided
under paragraph (d) of this section.
The Initial performance test Is the
only test for which at least 30 days
prior notice Is required unless other-
wise specified by. the Administrator.
The Initial performance test Is to be
scheduled so that the first steam gen-
erating unit operating day of the 30
successive steam generating unit oper-
ating days is completed within 30 days
Environmental Protection Agency
after achieving the maximum produc-
tion rate at which the affected facility
will be operated, but not later than
180 days after Initial startup of the fa-
cility. The boiler load during the 30-
day period does not have to be the
maximum design load, but must be
representative of future operating con-
ditions and Include at least one 24?
hour period at full load.
(g> After the initial performance test
required under 180.8. compliance with
the sulfur dioxide emission limits and
percent reduction requirements under
160.42b is based on the average emis-
sion rates and the average percent re-
duction for sulfur dioxide for 30 suc-
cessive steam generating unit operat-
ing days, except as provided under
paragraph (d). A separate perform-
ance test Is completed at the end of
each steam generating unit operating
day after the Initial performance test.
and a new 30-day average emission
rate and percent reduction for sulfur
dioxide are calculated to show compli-
ance with the standard.
(h) Except as provided under para-
graph (I) of this section, the owner or
operator of an affected facility shall
use all valid sulfur dioxide emissions
data In calculating % P. and Eh. under
paragraph (c), of this section whether
or hot the minimum emissions data re-
quirements under 160.48b are
achieved. All valid emissions data, in-
cluding valid sulfur dioxides emission
data collected during periods of start-
up, shutdown and malfunction, shall
be used In calculating % P. and EH.
pursuant to paragraph (c) of this sec-
tion.
(I) During periods of malfunction or
maintenance of the sulfur dioxide con-
trol systems when oil is combusted as
provided under {60.42b(i), emission
data are not used to calculate % P. or
E. under 160.42b (a), (b) or (c). howev-
er, the emissions data are used to de-
termine compliance with the emission
limit under 160.42b(l).
9 60.46b Compliance and performance test
methods and procedures for partleulate
matter and nitrogen oxides.
(a) The partleulate matter emission
standards and opacity limits under
160.43b apply at all times except
during periods of startup, shutdown.
§«0.4«b
or malfunction. The nitrogen oxides
emission standards under |60.44b
apply at aU times.
(b) Compliance with the particulate
matter emission standards under
160.43b shall be determined through
performance testing as described In
paragraph (d) of this section.
(c) Compliance with the nitrogen
oxides emission standards under
|60.44b shall be determined through
performance testing as described In
paragraph (e) or (f) of this section.
(d) The following procedures and
reference methods are used to deter-
mine compliance with the standards
for partleulate matter emissions under
160.43b.
(1) Method 3 Is used for gas analysis
when applying Method 6 or Method
17.
(2) Method 6, Method 6B. or Method
17 shall be used to measure the con-
centration of particulate matter as fol-
lows:
(1) Method 5 shall be used at affect-
ed facilities without wet flue gas desul-
furization (POD) systems; and
(11) Method 17 may be used at facili-
ties with or without wet scrubber sys-
tems provided the stack gas tempera-
ture does not exceed a temperature of
180 *C (320 *F). The procedures of sec-
tions 2.1 and 2.3 of Method SB may be
used In Method 17 only If It Is used
after a wet POD system. Do not use
Method 17 after wet POD systems if
the effluent Is saturated or laden with
water droplets.
(Ill) Method 5B Is to, be used only
after wet POD systems.
(3) Method 1 Is used to select the
sampling site and the number of tra-
verse sampling points. The sampling
time for each run Is at least 120 min-
utes and the minimum sampling
volume is 1.7 dscm (60 dscf) except
that smaller sampling times or vol-
umes may be approved by the Admin-
istrator when necessitated by process
variables or other factors.
(4) For Method 5. the temperature
of the sample gas In the probe and
filter holder Is monitored and is main-
tained at 160 *C (320 *F>.
(5) For determination of particulate
matter emissions, the oxygen or
carbon dioxide sample Is obtained si-
multaneously with each' run of
-------
TIC
M-
Itlo
Method 0, Method SB or Method 17 by
traversing the duet at the same sam-
pling location.
(6) For .each run using Method 5,
Method 6B or Method 17, the emission
rate expressed In nanograms per Joule
heat Input Is determined using:
(I) The oxygen or carbon dioxide
measurements and paniculate matter
measurements obtained under this sec-
tion,
(U) The dry basis F factor, and
(111) The dry basis emission rate cal-
culation procedure contained In
Method 19 (Appendix A).
(7) Method 9 Is used for determining
the opacity of stack emissions.
(e) To determine compliance with
the emission limits for nitrogen oxides
required under 160.44b. the owner or
operator of an affected facility shall
conduct the performance test as re-
quired under 860.8 using the continu-
ous system for monitoring nitrogen
oxides under 160.48(b>.
(1) For the Initial compliance test,
nitrogen oxides from the steam gener-
ating unit are monitored for 30 succes-
sive steam generating unit operating
days and the 30-day average emission
rate Is used to determine compliance
with the nitrogen oxides emission
standards under |60.44b. The 30-day
average emission rate Is calculated as
the average of ail hourly emissions
data recorded by the monitoring
system during the 30-day test period.
(2) Following the date on which the
Initial performance test Is completed
or Is required to be completed under
180.8 of this part, whichever date
comes first, the owner or operator of
an affected facility which. combusts
coal or which combusts residual oil
having a nitrogen content greater
than 0.30 weight percent shall deter-
mine compliance with the nitrogen
oxides emission standards under
160.44b on a continuous basis through
the use of a 30-day rolling average
emission rate. A new 30-day rolling av-
erage emission rate Is calculated, each
steam generating unit operating day
as the average of all of the hourly ni-
trogen oxides emission data for the
preceding 30 steam generating unit op-
erating days.
(3) Following the date on which the
Initial performance test Is completed
or Is required to be completed under
160.8 of this part, whichever date
comes first, the owner or operator of
an affected facility which has a heat
Input capacity greater than 73 MW
(250 million Btu/hour) and which
combusts natural gas, distillate oil. or
residual oil having a nitrogen content
of 0.30 weight percent or less shall de-
termine compliance with the nitrogen
oxides standards under 8 60.44b on a
continuous basis through the use of a
30-day rolling average emission rate. A
new 30-day rolling average emission
rate Is calculated each steam generat-
ing unit operating day as the average
of all of the hourly nitrogen oxides
emission data for the preceding 30
steam generating unit operating days.
(4) Following the date on which the
Initial performance test Is completed
or required to be completed under
860.8 of this part, whichever date
comes first, the owner or operator of
an affected facility which has a heat
Input capacity of 73 MW (250 million
Btu/hour) or less and which combusts
natural gas. distillate oil. or residual
oil having a nitrogen content of 0.30
weight percent or less shall upon re-
quest determine compliance with the
nitrogen oxides standards under
|60.44b through the use of a 30-day
performance test. During periods
when performance tests are not re-
quested, nitrogen oxides emissions
data collected pursuant to
160.48tKg)(l) or 8 60.48b(g)(2) are used
to calculate a 30-day rolling average
emission rate on a dally basis and used
to prepare excess'emission reports, but
will not be used to determine compli-
ance with the nitrogen oxides emission
standards. A new 30-day rolling aver-
age emission rate Is calculated each
steam generating unit operating day
as the average of all of the hourly ni-
trogen oxides emission data for the
preceding 30 steam generating unit op-
erating days.
(5) If the owner or operator of an af-
fected facility which combusts residual
oil does not sample and analyze the re-
sidual oil for nitrogen content, as spec-
ified In 860.49b(e). the requirements
of paragraph (III) of this section apply
and the provisions of paragraph (Iv) of
this section are Inapplicable.
286
onr
Pr
(f) To determine compliance with
the emission limit for nitrogen oxides
required by 8 60.44b(a)(4) for duct
burners used In combined cycle sys-
tems, the owner or operator of an af-
fected facility shall conduct the per-
formance test required under 860.8
using the nitrogen oxides and oxygen
measurement procedures In 40 CFR
Part 60 Appendix A. Method 20.
During the performance test, one sam-
pling site shall be located as close as
practicable to the exhaust of the tur-
bine, as provided by section 6.1.1 of
Method 20. A second sampling site
shall be located at .the outlet to the
steam generating unit. Measurements
of nitrogen oxides and oxygen shall be
taken at both sampling sites during
the performance test. The nitrogen
oxides emission rate from the com-
bined cycle system shall be calculated
by subtracting the nitrogen oxides
emission rate measured at the sam-
pling site at the outlet from the tur-
bine from the nitrogen oxides emission
rate measured at the sampling site at
the outlet from the steam generating
unit.
060.47b Emission monitoring for sulfur
dioxide.
(a) Except as provided In paragraph
(b) of this section, the owner or opera-
tor of an affected facility subject to
the sulfur dioxide standards under
§ 60.42b shall Install, calibrate, main-
tain, and operate continuous emission
monitoring systems (CEMS) for meas-
uring sulfur dioxide concentrations
and either oxygen (O.) or carbon diox-
ide (Cd) concentrations and shall
record the output of the systems. The
sulfur dioxide and either oxygen or
carbon dioxide concentrations shall
both be monitored at the Inlet and
outlet of the sulfur dioxide control
device.
(b) As an alternative to operating
CEMS as required under paragraph
(a) of this section, an owner or opera-
tor may elect to determine the average
sulfur dioxide emissions and percent
reduction by:
(1) Collecting coal or oil samples In
an as-fired condition at the Inlet to
the steam generating unit and analyz-
ing them for sulfur and heat content
according to Method 19. Method 19
§ W.-K it
provides procedures for converting
these measurements Into the format
to be used In calculating the average
sulfur dioxide Input rate, or
(2) Measuring sulfur dioxide accord-
Ing to Method 6B at the Inlet or outlet
to the sulfur dioxide control system.
An Initial stratification test Is required
to verify the adequacy of the Method
6B sampling location. The stratifica-
tion test shall consist of three paired
runs of a suitable sulfur dioxide and
carbon dioxide measurement train op-
erated at the candidate location and a
second similar train operated accord-
Ing to the procedures In Section 3.2
and the applicable procedures in Sec-
tion 7 of Performance Specification 2.
Method 6B, Method 6A; or a combina-
tion of Methods 6 and 3 or Methods
6C and 3A are suitable measurement
techniques. If Method 6B Is used for
the second train, sampling time and
timer operation may be adjusted for
the stratification test as long as an
adequate sample volume Is collected;
however, both sampling trains are to
be operated similarly. For the location
to be adequate for Method 6B 24-hour
tests, the mean of the absolute differ-
ence between the three paired runs
must be less than 10 percent.
(3) A dally sulfur dioxide emission
rate, ED, shall be determined using the
procedure described in Method 6A,
Section 7.6.2 (Equation 6A-8) and
stated In ng/J (Ib/mllllon Btu) heat
input.
(4) The mean 30-day emission rate Is
calculated using the dally measured
values in ng/J (Ib/mllllon Btu) for 30
successive steam generating unit oper-
ating days using equation 19-20 of
Method 19.
fc) The owner or operator of an af-
fected facility shall obtain emission
data for at least 75 percent of the op-
erating hours In at least 22 out of 30
successive boiler operating days. If
this minimum data requirement Is not
met with a single monitoring system,
the owner or operator of the affected
facility shall supplement the emission
data with data collected with other
monitoring systems as approved by
the Administrator or the reference
methods and procedures as described
In paragraph (b) of this section.
287
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§60.48b
(d) The 1-hour avenge sulfur diox-
ide emission rates measured by the
CEMS required by paragraph (a) of
this section and required under
|60.13(h) Is expressed In ng/J or lb/
million Btu heat Input and Is used to
calculate the average emission rates
under 160.42b. Each 1-hour average
sulfur dioxide emission rate must be
based on more than 30 minutes of
steam generating unit operation and
Include at least 2 data points with
each representing a 15-mlnute period.
Hourly sulfur dioxide emission rates
are not calculated If the affected facil-
ity Is operated less than 30 minutes in
a 1-hour period and are not counted
toward determination of a steam gen-
erating unit operating day.
(e) The procedures under 160.13
shall be followed for Installation, eval-
uation, and operation of the CEMS.
(1) All CEMS shall be operated In
accordance with the applicable proce-
dures under Performance Specifica-
tions 1,2, .and 3 (Appendix B).
(2) Quarterly accuracy determina-
tions and daily calibration drift tests
shall be performed In accordance with
Procedure 1 (Appendix F).
(3) For affected facilities combusting
coal or oil, alone or In combination
with other fuels, the span value of the
sulfur dioxide CEMS at the inlet to
the sulfur dioxide control device Is 125
percent of the maximum estimated
hourly potential sulfur dioxide emis-
sions of the fuel combusted, and the
span value of the CEMS at the outlet
to the sulfur dioxide control device Is
60 percent of the maximum estimated
hourly potential sulfur dioxide emis-
sions of the fuel combusted.
0 M.48b Emission monitoring for partleu-
late matter and nitrogen oxides.
(a) The owner or operator of an af-
fected facility subject to the opacity
standard under |60.43b shall Install,
calibrate, maintain, and operate a con-
tinuous monitoring system for measur-
ing the opacity of emissions dis-
charged to the atmosphere and record
the output of the system.
(b) Except as provided In paragraphs
(g) and (h) of this section, the owner
or operator of an affected facility sub-
ject to the nitrogen oxides standard of
160.44b(a) shall Install, calibrate,
40 CFR Ch. I (7-1-88 Edition)
maintain, and operate a continuous
monitoring system for measuring ni-
trogen oxides emissions discharged to
the atmosphere and record the output
of the system. .
(c) The continuous monitoring sys-
tems required under paragraph (b) of
this section shall be operated and data
recorded during all periods of oper-
ation of the affected facility except
for continuous monitoring system
breakdowns and repairs. Data* Is re-
corded during calibration checks, and
zero and span adjustments.
(d) The 1-hour average nitrogen
oxides emission rates measured by the
continuous nitrogen oxides monitor re-
quired by paragraph (b) of this section
and required under 160.13(h) shall be
expressed In ng/J or Ib/mllllon Btu
heat Input and shall be used to calcu-
late the average emission rates under
160.44b. The 1-hour averages shall be
calculated using the data points re-
quired under 160.13(b). At least 2 data
points must be used to -calculate each
1-hour average.
(e) The procedures under 160.13
shall be followed for Installation, eval-
uation, and operation of the continu-
ous monitoring systems.
(1) For affected facilities combusting
coal, wood or municipal-type solid
waste, the span value for a continuous
monitoring system for measuring
opacity shall be between 60 and 80
percent
(2) For affected facilities combusting
'coal, oil, or natural gas. the span value
for nitrogen oxides is determined as
follows:
FuM
Pitimgtt
Qf ..
r»*t
MtTtJTM
Span vtkm for
(PPM)
500
500
1.000
S00(»+n + 1.0001
where:
x Is the fraction of total heat Input derived
from natural gas.
y la the fraction of total heat Input derived
from oil. and
B Is the fraction of total heat Input derived
from coal.
288
Environmental Protection Agency
(3) All span values computed under
paragraph (e)(2) of this section for
combusting mixtures of regulated
fuels are rounded to the nearest 600
ppm.
(f) Wheh nitrogen oxides emission
data are not obtained because of con-
tinuous monitoring system break-
downs, repairs, calibration checks and
zero and span adjustments, emission
data will be obtained by using standby
monitoring systems. Method 7.
Method 7A, or other approved refer-
ence methods to provide emission data
for a minimum of 76 percent of the op-
erating hours In each steam generat-
ing unit operating day. In at least 22
out of 30 successive steam generating
unit operating days.
(g) The owner or operator of an af-
fected facility that has a heat input
capacity of 73 MW (250 million Btu/
hour) or less, and which has an annual
capacity factor for residual oil having
a nitrogen content of 0.30 weight per-
cent or less, natural gas, distillate oil.
or any mixture of these fuels, greater
than 10 percent (0.10) shall:
(1) Comply with the provisions of
paragraphs (b), (c). (d), (e)(2), (e)(3).
and (f) of this section, or
(2) Monitor steam generating unit
operating conditions and predict nitro-
gen oxides emission rates as specified
In a plan submitted pursuant to
8 60.49b(c).
(h) The owner or operator of an af-
fected facility which Is subject to the
nitrogen oxides standards of
160.44b(a)(4) Is not required to Install
or operate a continuous monitoring
system to measure nitrogen oxides
emissions.
(Approved by the Office of Management
and Budget under control number 2060-
0072)
060.49b Reporting and reeonikeeplng re-
quirements.
(a) The owner or operator of each
affected facility shall submit notifica-
tion of the date of Initial startup, as
provided by (60.7. This notification
shall Include:
(1) The design heat Input capacity of
the affected facility and Identification
of the fuels to be combusted In the af-
fected facility.
§ 60.49b
(2) If applicable, a copy of any feder-
ally enforceable requirement that
limits the annual capacity factor for
any fuel or mixture of fuels under
leO.UtXdMl). |60.44b(c).
|60.43(bXaX2>. |60.44tXd>.
|60.43tXaX3XIII>. | 60.44b(e). or
160.43tXCX3XII>. | 60.45IXd).
160.43MdX3XIII).
(3) The annual capacity factor at
which the owner or operator antici-
pates operating the facility based on
all fuels fired and based on each Indi-
vidual fuel fired, and.
(4-) Notification that an emerging
technology will be used for controlling
emissions of sulfur dioxide. The Ad-
ministrator will examine the descrip-
tion of the emerging technology and
will determine whether the technolo-
gy qualifies as an emerging technolo-
gy. In making this determination, the
Administrator may require the owner
or operator of the affected facility to
submit additional Information con-
cerning the control device. The affect-
ed facility is subject to the provisions
of 160.42b(a) unless and until this de-
termination is made by the Adminis-
trator.
(b) The owner or operator of each
affected facility subject to the sulfur
dioxide, partlculate matter and nitro-
gen oxides emission limits under
J60.42b, §60.43b. and {60.44b. shall
submit to the Administrator the per-
formance test data from the Initial
performance test and the performance
evaluation of the CEMS using the ap-
plicable performance specifications In
Appendix B.
(c) The owner or operator of each af-
fected facility subject to the nitrogen
oxides standard of } 60.44b who seeks
to demonstrate compliance with those
standards through the monitoring of
steam generating unit operating condi-
tions under the provisions of
i 60.48b(g)(2) shall submit to the Ad-
ministrator for approval a plan that
identifies the operating conditions to
be monitored under { 60.48b(g)(2) and
the records to be maintained under
160.40b(J). This plan shall be submit-
ted to the Administrator for approval
within 360 days of the Initial startup
of the affected facility. The plan shall:
(1) Identify the specific operating
conditions to be monitored and the re-
289
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560.49b
latlonsmp between these operating
conditions and nitrogen oxides emis-
sion rates (I.e.. ng/J or Ibs/mllllon Btu
heat Input). Steam generating unit op-
erating conditions Include, but are not
limited to, the degree of staged com-
bustion (I.e., the ratio of primary air
to secondary and/or tertiary air) and
the level of excess air (I.e., flue gas
oxygen level);
(2) Include the data and Information
that the owner or operator used to
Identify the relationship between ni-
trogen oxides emission rates and these
operating conditions;
(3) Identify how these operating
conditions. Including steam generating
unit load; will be monitored under
160.48b(g) on an hourly basis by the
owner or operator during the period of
operation of the affected facility; the
quality assurance procedures or prac-
tices that will be employed to ensure
that the data generated by monitoring
these operating conditions will be rep-
resentative and accurate: and the type
and format of the records of these op-
erating conditions. Including steam
generating unit load, that will- be
maintained by the owner or operator
under 160.49MJ).
If the plan Is approved, the owner or
operator shall maintain records of pre-
dicted nitrogen oxide emission rates
and the monitored operating condi-
tions. Including steam generating unit
load. Identified In the plan.
(d) The owner or operator of an af-
fected facility shall record and main-
tain records of the amounts of each
fuel combusted during each day and
calculate the annual capacity factor
Individually for coal, distillate oil. re-
sidual oil, natural gas, wood, and mu-
nicipal-type solid waste for each calen-
dar Quarter. The annual capacity
factor Is determined on a 12-month
rolling average basis with a new
annual capacity factor calculated at
the end of each calendar month.
(e) For affected facilities that: (1)
Combust residual oil having a nitrogen
content of 0.3 weight percent or less;
(2) have heat Input capacities of 73
MW (250 million Btu/hour) or less;
and (3) monitor nitrogen oxides emis-
sions or steam generating unit operat-
ing conditions under |60.48b(g). the
owner or operator shall maintain
records of the nitrogen content of the
oil combusted In the affected facility
and calculate the average fuel nitro-
gen content on a per calendar quarter
basis. The nitrogen content shall be
determined using ASTM Method
D3431-80, Test Method for Trace Ni-
trogen in Liquid Petroleum Hydrocar-
bons (IBR—see 8 60.17), or fuel specifi-
cation data obtained from fuel suppli-
ers. If residual oil blends are being
combusted, fuel nitrogen specifica-
tions may be prorated based on the
ratio of residual oils of different nitro-
gen content In the fuel blend.
(f) For facilities subject to the opaci-
ty standard under 160.43b. the owner
or operator shall maintain records of
opacity.
(g) For facilities subject to nitrogen
oxides standards under |60.44b. the
owner or operator shall maintain
records of the following information
for each steam generating unit operat-
ing day:
(1) Calendar date.
(2) The average hourly nitrogen
oxides emission rates (expressed as
NO,) (ng/J or Ib/milllon Btu heat
Input) measured or predicted.
(3) The 30-day average nitrogen
oxides emission rates (ng/J or Ib/mll-
Hon Btu heat input) calculated at the
end of each steam generating unit op-
erating day from'the measured or pre-
dicted hourly nitrogen oxide emission
rates for the preceding 30 steam gen-
erating unit operating days.
(4) Identification of the steam gener-
ating unit operating days when the
calculated 30-day average nitrogen
oxides emission rates are In excess of
the nitrogen oxides emissions stand-
ards under 160.44b, with the reasons
for such excess emissions as well as a
description of corrective actions taken.
(5) Identification of the steam gener-
ating unit operating days for which
pollutant data have not been obtained.
Including reasons for not obtaining
sufficient data and a description of
corrective actions taken.
(6) Identification of .the times when
emission data have been excluded
from the calculation of average emis-
sion rates and the reasons for exclud-
ing data.
290
•"flr» al r—-
(7) Identification of "F" factor used
for calculations, method of determina-
tion, and type of fuel combusted.
(8) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
system.
(9) Description of any modifications
to the continuous monitoring system
that could affect the ability of the
continuous monitoring system to
comply with Performance Specifica-
tion 2 or 3.
(10) Results of dally OEMS drift
tests and quarterly accuracy assess-
ments as required under Appendix F,
Procedure 1.
(h) The owner or operator of any af-
fected facility In any category listed In
paragraphs (h) (1) or (2) of this sec-
tion Is required to submit excess emis-
sion reports for any calendar quarter
during which there are excess emis-
sions from the affected facility. If
there are no excess emissions during
the calendar quarter, the owner or op-
erator shall submit a report semiannu-
ally stating that no excess emissions
occurred during the semiannual re-
porting period.
(1) Any affected facility subject to
the opacity standards under
160.43b(e) or to the operating parame-
ter monitoring requirements under
} 60.13(1X1).
(2) Any affected facility that Is sub-
ject to the nitrogen oxides standard of
8 60.44b, and that
(I) Combusts natural gas. distillate
oil. or residual oil with a nitrogen con-
tent of 0.3 weight percent or less, or .
(II) Has a heat input capacity of 73
MW (250 million Btu/hour) or less
and Is required to monitor nitrogen
oxides emissions on a continuous basis
under 5 60.48b(g)(l) or steam generat-
ing unit operating conditions under
{ 60.48b(g)<2).
(3) For the purpose of J80.43b.
excess emissions are defined as all 6-
mlnute periods during which the aver-
age opacity exceeds the opacity stand-
ards under 8 60.43b(f).
(4) For purposes of 8 80.48Wg)(l).
excess emissions are defined as any
calculated 30-day rolling average nitro-
gen oxides emission rate, as deter-
mined under J60.48b(e). which ex-
ceeds the applicable emission limits in
8 60.44b.
(I) The owner or operator of any af-
fected facility subject to the continu-
ous monitoring requirements for nitro-
gen oxides under 8 60.48(b) shall
submit a quarterly report containing
the Information recorded under para-
graph (g) of this section. All quarterly
reports shall be postmarked by the
30th day following the end of each cal-
endar quarter.
(J) The owner or operator of any af-
fected facility subject to the sulfur di-
oxide standards under 860.42b shall
submit written reports to the Adminis-
trator for every calendar quarter. All
quarterly reports shall be postmarked
by the 30th day following the end of
each calendar quarter.
(k) For each affected facility subject
to the compliance and performance
testing requirements of 8 60.45b and
the reporting requirement in para-
graph (j) of this section, the following
Information shall be reported to the
Administrator.
(1) Calendar dates covered In the re-
porting period.
(2) Each 30-day average sulfur diox-
ide emission rate (ng/J or Ib/mllllon
Btu heat Input) measured during the
reporting period, ending with the last
30-day period In the quarter: reasons
for noncompllance with the emission
standards: and a description of correc-
tive actions taken.
(3) Each 30-day average percent re-
duction In sulfur dioxide emissions cal-
culated during the reporting period.
ending with the last 30-day period In
the quarter; reasons for noncompll-
ance with the emission standards; and
a description of corrective actions
taken.
(4) Identification of the steam gener-
ating unit operating days that coal or
oil was combusted and for which
sulfur dioxide or diluent (oxygen or
carbon dioxide) data have not been ob-
tained by an approved method for at
least 75 percent of the operating hours
In the steam generating unit operating
day: justification for not obtaining
sufficient data; and description of cor-
rective action taken.
(6) Identification of the tunes when
emissions data have been excluded
from the calculation of average emls-
291
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{60.49b
sion rates; Justification for excluding
data; and description of corrective
action taken If data have been ex-
cluded for periods other than those
during which coal or oil were not com-
busted In the steam generating unit.
(6) Identification of "F* factor used
for calculations, method of determina-
tion, and type of fuel combusted.
(7) Identification of times when
hourly averages have been obtained
based on manual sampling methods.
(8) Identification of the times when
the pollutant concentration exceeded
full span of the GEMS.
(9) Description of any modifications
to the GEMS that could affect the
ability of the OEMS to comply with
Performance Specification 2 or 3.
(10) Results of dally CEMS drift
tests and quarterly accuracy assess-
ments as required under Appendix F,
Procedure 1.
(11) The annual capacity factor of
each fired as provided under para-
graph (d) of this section.
(1) For each affected facility subject
to the compliance and performance
testing requirements of f 60.45tXd)
and the reporting requirements of
paragraph (j) of this section, the fol-
lowing Information shall be reported
to the Administrator
(1) Calendar dates when the facility
was in operation during the reporting
period;
(2) The 24-hour average sulfur diox-
ide emission rate measured for each
steam generating unit operating day
during the reporting period that coal
or oil was combusted, ending In the
last 24-hour period In the quarter, rea-
sons for noncotnpllance with the emis-
sion standards: and a description of
corrective actions taken;
(3) Identification of the steam gener-
ating unit operating days that coal or
oil was combusted for which sulfur di-
oxide or diluent (oxygen or carbon di-
oxide) data have not been obtained by
an approved method for at least 75
percent of the operating hours: justifi-
cation for not obtaining sufficient
data; and description of corrective
action taken.
(4) Identification of the times when
emissions data have been excluded
from the calculation of average emis-
sion rates: justification for excluding
40 €FR Ch. I (7-148 Edition)
data; and description of corrective
action taken If data have been ex-
cluded for periods other than those
during which coal or oil were not com-
busted in the steam generating unit
(5) Identification of "F" factor used
for calculations, method of determlna- •
tion, and type of fuel combusted.
(6) Identification of times when
hourly averages have been obtained
based on manual sampling methods.
(7) Identification of the times when
the pollutant concentration exceeded
full span of the CEMS.
(8) Description of any modifications
to the CEMS which could affect the
ability of the CEMS to comply with
Performance Specification 2 or 3..
(9) Results of dally CEMS drift testa
and quarterly accuracy assessments as
required under Appendix F, Procedure
1.
(m) For each affected facility sub-
ject to the sulfur dioxide standards
under 160.42b for which the minimum
amount of data required under
160.47b(f) were not obtained during a
calendar quarter, the following Infor-
mation is reported to the Administra-
tor In addition to that required under
paragraph (k) of this section:
(1) The number of hourly averages
available for outlet emission rates and
Inlet emission rates.
(2) The standard deviation of hourly
averages for outlet emission rates and
inlet emission rates, as determined In
Method 19. Section 7.
(3) The lower confidence limit for
the mean outlet emission rate and the
upper confidence limit for the mean
Inlet emission rate, as calculated In
Method 19. Section 7.
(4) The ratio of the lower confidence
limit for the mean outlet emission rate
and the allowable emission rate, as de-
termined in Method 19. Section 7.
(n) If a percent removal efficiency
by fuel pretreatment (I.e.. % R,) is
used to determine the overall percent
reduction (I.e.. % R.) under (60.45b,
the owner or operator of the affected
facility shall submit a signed state-
ment with the quarterly report:
(1) Indicating what removal efficien-
cy by fuel pretreatment (I.e., % R,) was
credited for the calendar quarter.
(2) Listing the quantity, heat con-
tent, and date each pretreated fuel
292
Environmental Protection Agency
shipment was received during the pre-
vious calendar quarter the name and
location of the fuel pretreatment facil-
ity; and the total quantity and total
heat content of all fuels received at
the affected facility during the previ-
ous calendar quarter;
(3) Documenting the transport of
the fuel from the fuel pretreatment
facility to the steam generating unit
(4) Including a signed statement
from the owner or operator of the fuel
pretreatment facility certifying that
the percent removal efficiency
achieved by fuel pretreatment was de-
termined In accordance with the provi-
sions of Method 19 (Appendix A) and
listing the heat content and sulfur
content of each fuel before and after
fuel pretreatment
(o) All records required under this
section shall be maintained by the
owner or operator of the affected fa-
cility for a period of 2 years following
the date of such record.
(Approved by the Office of Management
and Budget under control number 2060-
0135)
Subpart E—Standards of Performance
for Incinerators
860.50 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to each Incinerator of
more than 45 metric tons per day
charging rate (50 tons/day), which Is
the affected facility.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after August
17,1971, Is subject to the requirements
of this subpart.
[42 FR 37036. July 25.1077)
860.51 Definitions.
As used In this subpart, all terms not
defined herein shall have the meaning
given them In the Act and in Subpart
A of this part.
(a) "Incinerator" means any furnace
used In the process of burning solid
waste for the purpose of reducing the
volume of the waste by removing com-
bustible matter.
(b) "Solid waste" means refuse, more
than 60 percent of which Is municipal
§60.54
type waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other
combustibles, and noncombustlble ma-
terials such as glass and rock.
(c) "Day" means 24 hours.
[36 FR 24877, Dec, 23, 1071, as amended at
39 PR 20702. June 14.1074)
9 60.52 Standard for partlenlate matter.
(a) On and after the date on which
the performance test required to be
conducted by f 60.8 Is completed, no
owner or operator subject to the provi-
sions of this part shall cause to be dis-
charged Into the atmosphere from any
affected facility any gases which con-
tain partlculate matter In excess of
0.18 g/dscm (0.08 gr/dscf) corrected to
12 percent COt.
139 PR 20702. June 14. 1074)
0 60.63 Monitoring of operations.
(a) The owner or operator of any In-
cinerator subject to the provisions of
this part shall record the dally charg-
ing rates and hours of operation.
8 60.54 Test methods and procedures.
(a) The reference methods In Appen-
dix A to this part, except as provided
for In 160.8(b). shall be used to deter-
mine compliance with the standard
prescribed In 8 60.52 as follows:
(1) Method 6 for the concentration
of partlculate matter arid the associat-
ed moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis and
calculation of excess air. using the In-
tegrated sample technique.
(b) For Method 5. the sampling time
for each run shall be at least 60 min-
utes and the minimum sample volume
shall be 0.85 dscm (30.0 dscf) except
that smaller sampling times or sample
volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator.
(c) If a wet scrubber Is used, the gas
analysis sample shall reflect flue gas
conditions after the scrubber, allowing
for carbon dioxide absorption, by sam-
pling the gas on the scrubber inlet and
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APPENDIX B
SAMPLE INSPECTION CHECKLISTS
B-1
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INSPECTION CHECKUST FOR COMBUSTION PROCESSES WITH
KNOWN INSTANTANEOUS FUEL-FIRING RATES
Liquid fuels fired:
Gaseous fuels fired:
Solid fuels fired:
Time firing data recorded
Date
gal/min No. 2 fuel oil
gal/min No. 6 fuel oil
gal/min supplemental fuels
GCV No. 2 fuel oil (as-fired), Btu/gal
GCV No. 6 fuel oil (as-fired), Btu/gal
GCV supplemental fuels (as-fired), Btu/gal
103 scfm - natural gas (NG)
GCV NG (as-fired), Btu/103 scfm-NG
ton/h
GCV of fuel (as-fired), Btu/lb
free moisture in fuel, %
am. p.m.
-------
INSPECTION CHECKLIST FOR FLUE GAS
CONDITIONS AT ARC SYSTEM
ARC equipment
Type
Design gas volume , acfm
Design gas temperature , °F
Baseline gas volume , acfm
Baseline gas temperature , °F
Baseline exit gas moisture (wet scrubbers) , % by volume
Flue gas oxygen content , %
Flue gas temperature , °F
Sampling location
Time gas measurements recorded a.m. p.m.
Date
-------
INSPECTION CHECKLISTS FOR BOILERS
Boiler No. Date
Heat output (instantaneous):
Time data was recorded • a.m. p.m.
Steam generation rate , 103 Ib/h
Steam drum pressure , psig
Steam drum pressure , psia (psig + 14.7)
Steam temperature ' , °F
Feedwater temperature entering boiler _^ , °F
Combustion air temperature , CF.
•
Rue gas conditions at boiler outlet (instantaneous):
Time gas measurements recorded __, • a.m. p.m.
Sampling location
Flue gas oxygen content • , %
Flue gas carbon dioxide content , %
Flue gas temperature , °F
-------
INSPECTION CHECKLIST FOR COMBUSTION
DEVICE FAN CONDITIONS
(For Use With Fan Curve/Table)
Fan location
Fan type (ID or FD)
Fan Manufacturer
Fan Model No.
Fan motor rated voltage , volts-AC
Fan motor service factor
Fan motor fractional efficiency
Fan motor current , amperes
3-phase system: yes no
Flue gas temperature at fan , °F
Fan static pressure:
Inlet in. W.G.
Outlet in. W.G.
Fan differential pressure in. W.G.
Fan rotation speed rpm
or
Fan motor rotation speed rpm
Fan pulley to motor pulley ratio :
Calculated fan rotation speed rpm
Time fan conditions measured a.m. p.m.
Date
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APPENDIX C
SAMPLE COMBUSTION CALCULATION FORMS
C-1
-------
COMBUSTION CALCULATIONS
Air Requirement
Ultimate Analysis Required for Combustion
Ib/lb As-Fired Fuel Ib/lb As-Fired Fuel
02 Air
C . (x2.66) (C x 11.53)
H2 (X7.94) (H2 X 34.34)
H20
Ash
Sum
(xl.OO) (S x 4.29)
Less 02 in fuel (deduct) - (02 x 4.32)
Total Required @ 0% Excess Air
%Excess Air (specify or calculate)
XExcess Air = %0.. „ inn
207T^%02 x 10°
02 requirement @ % Excess Air
[1 + (XExcess Air/100)] x 02 0 0% excess air = Ib/lb A.F. fuel
Excess 02 - (02 P X Excess Air - 02 0 OX Excess Air)
Air Requirement @ X Excess Air
[1 + (X Excess Air/100)] x Air 0 OX excess air = Ib/lb A.F. fuel
-------
Products of Combustion
At X Excess Air Ib/lb A.F. fuel
C02 = (C x 3.66)
H20 = (H, x 8.94) + (H20) + (0.0138 x Ib air/lb
A.T. fuel @ % excess air)
S02 = (2.00 x S)
02 = Excess 02
N2 = [(Ib air/lb A.F. fuel (? X excess air) x 0.7685] + N2
Total (wet)
Total Wet - H20 - Total (dry)
Standard air contains 0.013 Ib H20/lb air in
combustion calculations.
Flue Gas Composition
(C02/44.01) x 100 - % C02 (vol)
(S02/64.06) X 100 - X S02 (vol)
(02/32.00) x 100 = X 02 (vol)
(N2/28.016) x 100 = X N2 (vol)
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