Industrial Environmental Research EPA-600/7g79-178a
Laboratory Augus
Research Triangle Park NC 2771
Population and
Characteristics of
Industrial/Commercial
Boilers in the U.S.
Interagency
Energy/Environment
R&D Program Report
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EPA-600/7-79-178a
August 1979
Population and Characteristics of
Industrial/Commercial Boilers in the U.S
by
T. Devitt, P Spaite, and L. Gibbs
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603
Task No.19
Program Element No. EHE624A
EPA Project Officer: Charles J. Chatlynne
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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This report was furnished to the U.S. Environmental
Protection Agency by PEDCo Environmental, Inc., Cincinnati,
Ohio, in fulfillment of Contract No. 68-02-2603, Assignment
No. 19. 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 neces-
sarily those of the Environmental Protection Agency.
11
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PREFACE
The 1977 Amendments to the Clean Air Act required that emis-
sion standards be developed for fossil-fuel-fired steam generators.
Revisions to the 1971 new source performance standard (NSPS) for
large steam generators were recently promulgated by the U.S.
Environmental Protection Agency (EPA). Further, EPA has under-
taken a study of industrial boilers with the intent of proposing
an NSPS for this category of sources. The study is being dir&cted
by EPA's Office of Air Quality Planning and Standards, and tech-
nical support is being provided by EPA's Office of Research and
Development. As part of this support, the Industrial Environmental
Research Laboratory at Research Triangle Park, N.C. prepared a
series of technology assessment reports to aid in determining the
technological basis for the NSPS for industrial boilers. This
report is part of that series. The complete report series is
listed below:
Title
The Population and Characteristics of Indus-
trial/Commercial Boilers
Technology Assessment Report for Industrial
Boiler Applications: Oil Cleaning
Technology Assessment Report for Industrial
Boiler Applications: Coal Cleaning and Low
Sulfur Coal
Technology Assessment Report for Industrial
Boiler Applications: Synthetic Fuels
Technology Assessment Report for Industrial
Boiler Applications: Fluidized-Bed
Combustion
Technology Assessment Report for Industrial
Boiler Applications: NOX Combustion
Modification
Technology Assessment Report for Industrial
Boiler Applications: NOX Flue Gas
Treatment
Report No.
EPA-600/7-79-178a
EPA-600/7-79-178b
EPA-600/7-79-178c
EPA-600/7-79-178d
EPA-600/7-79-178e
EPA-600/7-79-178f
EPA-600/7-79-178g
111
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Technology Assessment Report for Industrial
Boiler Applications: Particulate Collection EPA-600/7-79-178h
Technology Assessment Report for Industrial
Boiler Applications: Flue Gas Desul-
furization EPA-600/7-79-178i
These reports will be integrated along with other informa-
tion in the document, "Industrial Boilers - Background Informa-
tion for Proposed Standards," which will be issued by the Office
of Air Quality Planning and Standards.
IV
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CONTENTS
Figures
Tables
Acknowledgement
Executive Summary
1. Introduction 1
References 5
2. The Industrial/Commercial Boiler Population and
Fuel Consumption 6
2.1 Boiler Classification 6
2.2 Present Boiler Population 8
2.3 Fuel Consumption 29
2.4 Growth Projections for Industrial/Commercial
Boiler Population 37
References 51
3. Atmospheric Emissions 52
3.1 Emission Factors 52
3.2 Current Levels of Uncontrolled Emissions 69
3.3 Emission Projections to 2000 76
References 87
4. Representative New Boilers and Characteristics 88
4.1 Typical Industrial Boilers 88
4.2 Boiler Characteristics 91
References 111
5. Basis for Cost Evaluations 112
5.1 Cost Elements 113
5.2 Cost Estimating Format 118
5.3 Unit Cost Recommendations 123
References 125
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CONTENTS (continued)
Page
6. Cost Estimates for New Boilers 127
6.1 Cost Estimating Procedure 127
6.2 Cost Estimates for New Boilers 137
References 141
Appendices
A. Detailed Boiler Descriptions A-l
B. Derivation of Boiler Capacity Data B*-l
C. Detailed Boiler Population Data Sheets C-l
D. Boiler Fuel Consumption D-l
E. Derivation of the PEDCo Industrial Growth Factor E-l
F. Estimation of Boiler Air Emissions F-l
G. Detailed Capital and Annualized Costs for
Representative Boilers G_l
VI
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FIGURES
No. Paqe
1 Distribution of commercial and industrial boiler
capacity by type. xix
2 Relative distribution of the number of industrial/
commercial boilers by type and size range. xx
3 Relative distribution of the capacity of the
industrial/commercial boiler population by type
and size. xxi
4 Relative distribution of the total capacity by fuel
type in each boiler class. xxii
5 Relative total emission levels of particulate matter,
SOX, and NOX by boiler class through 2000. xxiv
2-1 Possible combinations of characteristics associated
with U.S. industrial/commercial boilers. 9
2-2 Projected growth in energy use by boilers through
2000. 42
2-3 The EIA scenarios for energy demand projections. 47
3-1 Projected total uncontrolled particulate matter
emissions from the industrial/commercial boiler
population through 2000. 79
3-2 Projected total uncontrolled emissions of
particulate for alternate growth rates through 2000. 81
3-3 Projected total uncontrolled emission of SOX from
the industrial/commercial boiler population through
2000. 82
3-4 Projected total uncontrolled emissions of SOX for
alternate growth rates through 2000. 83
3-5 Projected total uncontrolled emissions of NOX from
the industrial/commercial boiler population through
2000. 84
3-6 Projected total uncontrolled emissions of NOx for
alternate growth rates through 2000. 86
vii
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TABLES
Number Page
1 Representative Boilers for Evaluation xxvi
2 Summary of the Estimated Capital and Annual Costs
for the Selected Representative Boilers xxvii
2-1 Categories of Industrial/Commercial Boilers 7
2-2 Summary of the Total Boiler Population by Fuel Used 10
2-3 Distribution of Nonutility Boilers by Sector 10
2-4 Distribution of Commercial/Industrial Boilers by Size 11
2-5 Distribution of U.S. Water-tube Boilers by Capacity
and Fuel Type 13
2-6 Distribution of U.S. Fire-tube Boilers by Capacity
and Fuel Type 14
2-7 Distribution of U.S. Cast Iron Boilers by Capacity
and Fuel Type 15
2-8 Distribution of U.S. Water-tube Commercial Boilers
by Capacity and Fuel Type 16
2-9 Distribution of U.S. Water-tube Industrial Boilers
by Capacity and Fuel Type 17
2-10 Distribution of U.S. Commercial Fire-tube Boilers
by Capacity and Fuel Type 18
2-11 Distribution of U.S. Industrial Fire-tube Boilers
by Capacity and Fuel Type 19
2-12 Distribution of U.S. Commercial/Institutional Cast
Iron Boilers by Capacity and Fuel Type 20
2-13 Distribution of U.S. Industrial Cast Iron Boilers
by Capacity and Fuel Type 21
2-14 Boiler Population Distributed by Heat-Transfer
Configuration 22
viii
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TABLES (continued)
Number Page
2-15 Distribution of U.S. Field-Erected Water-tube
Boilers by Capacity and Fuel Type 24
2-16 Distribution of U.S. Package Water-tube Boilers
by Capacity and Fuel Type 25
2-17 Distribution of SIC of Water-tube Boilers Sold
in Period 1965 through 1977 28
2-18 Annual Fuel Consumption by Industrial/Commercial
Boilers 29
2-19 Estimated Fuel Consumption by Industrial and
Commercial Boilers, 1975 30
2-20 Fuel Consumption for Industrial Boilers 31
2-21 Comparison of Fuel and Use Estimates 32
2-22 Estimated Load Factors for Industrial and Commercial
Boilers by Fuel 33
2-23 Comparison of Battelle and PEDCo Load Factors 34
2-24 Comparison of Boilers by Age 36
2-25 Projected Total Energy Usage by the Four Major
Energy-Intensive Industries 40
2-26 Total U.S. Capacity of Industrial/Commercial Boilers
by Fuel Type in 1977 43
2-27 Projected Total Capacity of U.S. Industrial/Commercial
Boilers by Fuel Type 44
2-28 Industrial Energy Demands from 1975 to 2000 46
3-1 Uncontrolled Particulate Emission Factors for Various
Coal-Fired Boilers 53
3-2 Uncontrolled Particulate Emission Factors for Various
Oil-Fired Boilers 54
3-3 Uncontrolled Particulate Emission Factors for Various
Natural-Gas-Fired Boilers 55
IX
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TABLES (continued)
Number Paxje
3-4 Uncontrolled S02 Emission Factors for Various
Coal-Fired Boilers 59
3-5 Uncontrolled SOX Emission Factors for Various
Oil-Fired Boilers 60
3-6 Uncontrolled S02 Emission Factors for Various
Natural-Gas-Fired Boilers 62
3-7 Uncontrolled NOX Emission Factors for Various
Coal-Fired Boilers 64
3-8 Uncontrolled NOX Emission Factors for Various
Oil-Fired Boilers 65
3-9 Uncontrolled NOX Emission Factors for Various
Natural-Gas-Fired Boilers 66
3-10 Estimated Distribution of Fuel Consumption by
Boiler Type for 1975 70
3-11 Estimated Uncontrolled Emissions of Particulate
Matter From the Industrial/Commercial Boiler
Population for 1975 72
3-12 Estimated Uncontrolled Emissions of SOX From the
Industrial/Commercial Boiler Population for 1975 74
3-13 Estimated Uncontrolled Emissions of NOX From the
Industrial/Commercial Boiler Population for 1975 75
3-14 Estimated Uncontrolled Emissions of CO From the
Industrial/Commercial Boiler Population for 1975 77
3-15 Estimated Uncontrolled Emissions of HC From the
Industrial/Commercial Boiler Population for 1975 78
4-1 Representative Boilers Selected for Evaluation 89
4-2 Design Parameters for a Distillate-Oil-Fired,
Package, Scotch Fire-tube Boiler 93
4-3 Design Parameters for a Natural-Gas-Fired, Package,
Scotch Fire-tube Boiler 94
4-4 Design Parameters for a Coal-Fired, Package,
Water-tube, Underfeed Boiler 95
x
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TABLES (continued)
Number Page
4-5 Design Parameters for a Coal-Fired, Field-Erected,
Water-tube, Chain-Grate Boiler 96
4-6 Design Parameters for Residual-Oil-Fired, Package,
Water-tube Boilers 97
4-7 Design Parameters for a Distillate-Oil-Fired,
Package, Water-tube Boiler 98
4-8 Design Parameters for a Natural-Gas-Fired, Package,
Water-tube Boiler 99
4-9 Design Parameters for a Coal-Fired, Field-Erected,
Water-tube, Spreader-Stoker Boiler 100
4-10 Design Parameters for a Field-Erected, Water-tube,
Pulverized-Coal-Fired Boiler with a Heat Input of
58.6 MW Thermal (200 x 106 Btu/h) 101
4-11 Design Parameters for a Field-Erected, Water-tube,
Pulverized-Coal-Fired Boiler with a Heat Input of
117.2 MW Thermal (400 x 106 Btu/h) 102
4-12 Ultimate Analyses of Fuels Selected for the
Representative Boilers 104
4-13 Typical Amounts of Excess Air Supplied to Fuel-
Burning Equipment 107
5-1 Typical Values for Indirect Capital Costs 116
5-2 Capital Recovery Factors 119
5-3 Recommended Format for Presenting Capital Costs 121
5-4 Recommended Format for Presenting Annualized Costs 122
5-5 Annual Unit Costs for Operation and Maintenance 124
6-1 Basic Equipment and Installation Items Included
in a New Boiler Facility 130
6-2 Sources of Cost Data for Equipment and Installation
Items Included in Boiler Plants 131
6-3 Direct Annual Operation and Maintenance Cost Items
Associated With Boilers
xi
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TABLES (continued)
Number
Page
6-4 Methods Used to Estimate Direct Annual Costs 135
6-5 Summary of the Manpower Requirements for the
Selected Representative Boilers 136
6-6 Summary of the Estimated Capital and Annual Costs
for the Selected Representative Boilers 138
XII
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ACKNOWLEDGEMENT
This report was prepared for the Industrial Environmental
Research Laboratory of the U.S. Environmental Protection Agency -
The EPA Project Officer was Dr. Charles J. Chatlynne. PEDCo
appreciates the direction and assistance provided by Dr. Chat-
lynne and by other IERL personnel including Messrs. Richard Stern
and J. David Mobley. PEDCo would also like to acknowledge the
assistance provided by the Economic Analysis Branch of the Office
of Air Quality Planning and Standards.
PEDCo also appreciates the information and assistance pro-
vided by the manufacturers representatives including Mr. William
Axtman of the American Boiler Manufacturers Association, Mr.
Louis F. Kurtz of Hydronics Institute, and Mr. Jerry lacouzze and
Mrs. Margaret McDonald of the Gas Applicance Manufacturers
Association.
Special credit must be given to Mr. Paul W. Spaite who was
instrumental in developing the study approach and of invaluable
assistance in project review.
The project was conducted under the overall direction of Mr.
Timothy W. Devitt. The PEDCo Project Director was Mr. William F.
Kemner. Mr. Larry L. Gibbs was Project Manager. Principal
authors were Messrs. Devitt, Spaite, Gibbs, Kemner, Duane S.
Forste, Douglas A. Paul, and John P. Abraham.
Xlll
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EXECUTIVE SUMMARY
PURPOSE
This report represents an initial background study to gener-
ate data in support of technology assessment studies for indus-
trial and commercial boilers. Industrial boilers are defined as
boilers used to generate process steam, electricity, or space
heat at industrial facilities. Commercial boilers are defined as
those used by commercial establishments, medical, or educational
institutions to provide steam. The project was designed primar-
ily to provide information to meet the specific needs of other
contractors responsible for conducting control technology assess-
ment studies. In addition, this study provides the statistical
basis for boiler population and characteristics, fuel consumption,
and emissions from which a broader study of overall environmental
impacts of nonutility boilers can be made.
Boilers consume about one-third of the fossil fuels burned
in the United States. Over 40 percent of these fuels are fired
in industrial/commercial boilers, the rest in utility boilers.
Although many studies have been made of utility boilers to ascer-
tain their energy consumption and the nature of their emissions,
no prior study has attempted to make a comprehensive assessment
of the total impact of criteria pollutant emissions from indus-
trial/commercial boilers. An earlier Battelle report (Locklin et
al.; 1974) was limited to the study of nitrogen oxides emissions
and the various technologies for controlling them. Other reports
(Ehrenfeld et al., 1971; Putnam et al., 1975) stopped short of
completely describing the amounts and kinds of air pollution
associated with all important categories of boilers. This study
updates and enlarges the work of others to provide the most
xiv
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complete description yet developed of the industrial/commercial
boiler population, its fuel consumption, and associated atmos-
pheric emissions.
It should be noted that this study makes exclusive use of
the International System of Units (SI). Boiler capacities are
expressed in watts thermal, the SI unit for power. Because the
data from which the statistics on boilers were obtained are in
English units, values are converted to the SI system.
There were about 1,800,000 industrial and commercial boilers
in the United States in 1977. Only about 0.1 percent of these
boilers, representing 17 percent of the total capacity, have a
heat input greater than 73.2 MW thermal (250 x 10 Btu/h), the
current size limit for boilers covered by New Source Performance
Standards (NSPS). The current NSPS for boilers therefore gener-
ally do not apply to this nonutility segment of the population.
It should be noted that this study does not concern itself with
residential boilers.
Nearly every State Implementation Plan (SIP) contains
regulations applicable to boilers of all sizes. Regulations
covering particulate matter and sulfur oxides (SO ) are usually
X
specific, although those for SO often take the form of fuel
A
regulations and are independent of boiler size.
Emission limitations for nitrogen oxides (NO ), carbon
X
monoxide (CO), and hydrocarbons (HC) are essentially nonexistent
in the SIP's. Furthermore, surveys of Regional Offices, pre-
sented in an interim report, indicate that regulations covering
smaller boilers have not been rigorously enforced.
Recognizing that these industrial and commercial boilers
represent a significant stationary source of emissions, Indus-
trial Environmental Research Laboratory/Research Triangle Park
formulated this study with two major objectives:
0 To develop a thorough and complete characterization of
the existing boiler population by developing sub-
categories of boiler types, boiler sizes, fuel usage,
and uncontrolled emissions.
xv
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To develop a standardized approach and basis for deter-
mining the cost of new boilers and their associated
emission control systems.
ORGANIZATION OF THE REPORT
The report is organized into six sections and seven appen-
dices. Section 1 describes the scope of the study and the key
subtasks. Section 2 characterizes the existing boiler population
and presents the statistical data base. It includes important
descriptive and analytical subcategories regarding the boiler
population. This section also presents projections of growth oi
boilers under various scenarios. Section 3 presents estimates of
uncontrolled emissions from existing boilers and projected emis-
sions through the year 2000. It includes a separate subsection
for each of the pollutants: particulate matter, SO , and NO .
X J^.
Section 4 provides the basis for the selection of standard
boilers representing a cross section of the industrial/commercial
population. It describes 23 boiler and fuel type combinations
and specifies the key design parameters and boiler character-
istics for each case.
Section 5 establishes a uniform procedure to be used in
calculating capital and annualized costs for new boilers and
emission control systems. It also provides formats for presenta-
tion of capital and annualized costs and recommended values for
unit costs.
Section 6 concludes the main body of the report and describes
the methodology for determining the capital and annualized costs
of several standard boilers. It also defines the sources of data
and key assumptions used to develop boiler costs.
Because this effort is a cornerstone study to be used by
diverse groups, considerable detail is provided in appendices.
These appendices can be used to follow the derivation of the
data, and they also provide the necessary detail for those per-
forming additional work. Key study assumptions are identified.
xvi
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For those interested only in the overview, however, no important
factors will be missed if the appendices are not addressed.
RESULTS
Time constraints made it necessary to perform a number of
tasks concurrently. These constraints also necessitated making
first estimates on the basis of readily available information and
then upgrading the data base as additional background information
became available. Boiler surveys and sales data provided the
basis for characterizing the boiler population. Fuel supply,
demand, and consumption data from various sources were used to
estimate fuel consumption. Preliminary calculations of emission
estimates were based on boiler capacity data and estimated use
factors, and later calculations were based on fuel consumption
data and accepted emission factors. The two approaches produced
different results. The estimates made from fuel consumption data
(the second approach) were considered more reasonable and were
used in the final report. The differences between the results of
the two approaches are discussed, but the limits of the study
precluded reconciling all the data, which were generally gathered
and reported in different ways. It is believed that, despite
problems encountered in interpreting the data, the work to date
provides a valuable new perspective to the nature of the air
pollution problems generated by the industrial and commercial
boilers of the United States.
The total number of industrial and commercial boilers in
place in 1977 is estimated to be about 1,800,000. The total
firing capacity of these boilers is about 1,300,000 MW thermal
(4,500,000 x 10 Btu/h). Less than 1 percent of the boilers
exceed the existing NSPS limiting size of 73.3 MW thermal (250 x
106 Btu/h), but they represent 17 percent of the installed
capacity. About 72 percent of these boilers are classified as
commercial and are used primarily for space heating in commercial
and institutional buildings. The other 28 percent are classified
xv li
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as industrial boilers and are used primarily for generating pro-
cess steam and for space heating. Although the absolute number
of commercial boilers is obviously greater, the industrial
boilers are generally much larger. Consequently, industrial
boilers represent 69 percent of the total firing capacity. The
use of industrial boilers is concentrated in four major indus-
tries: pulp and paper, primary metals, chemicals, and minerals.
These industries account for 82 percent of the total energy used
to make process steam.
Figure 1 summarizes the capacity and types of boilers in the
industrial and commercial categories.
The three major types of boilers are water-tube, fire-tube,
and cast iron. Many variations in boiler design are possible,
but these three categories represent an important basic classi-
fication. Figure 2 illustrates the distribution of the boiler
population by size within these three categories. In contrast,
Figure 3 illustrates the distribution on the basis of firing
capacity. It is apparent that cast iron boilers are small, the
largest having a heat input of 2.9 MW thermal (10 x 10 Btu/h).
Fire-tube boilers have the greatest range of capacity, and water-
tube boilers are generally the largest of the three types. Thus,
although there are relatively few water-tube boilers, they
constitute the majority of the capacity. Further analysis
indicates that water-tube boilers predominate in industry. About
three-quarters of water-tube boilers are package units (i.e.,
fabricated in the shop and shipped to the user as a complete
unit). Field-erected units supply more than half the total
capacity of water-tube boilers because they tend to be larger than
package units.
Figure 4 illustrates the distribution of relative firing
capacity by fuel type for each type of boiler. Natural-gas-fired
boilers comprise 45 percent of the total of commercial and
industrial boilers. Oil-fired boilers comprise 37 percent, and
coal-fired boilers the remaining 18 percent. The uncontrolled
particulate emissions from coal-fired boilers are dispropor-
xviii
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X
H-
X
1000
CO
o
CL.
-------
ZOO,000 -
150,000 -
100,000 -
50,000 -
970,980
-^-^^^-~ — ••
-— — ,
-
-
1 sgg 4] 5
L*t^~^— u^v^-w^.
/7//////X
^m
r | i
CAST IRON
oH:! FIRE-TUBE
/22; WATER-TUBE
-
-
'//////////////////.'///////ATTTTTTrT*
0.1-0.4 0.4-2.9 2.9-7.3 7.3-14.7 14.7-29.3 29.3-73.3 73.3-146.5 146.5-439.5 >439.5
SIZE RANGE, MW thermal
Figure 2. Relative distribution of the number of industrial/commercial
boilers by type and size range.
-------
X
X
H-
200.000
|
<
S
150,000
100,000
50.000
CAST IRON
FIRE-TUBE
WATER-TUBE
<0.1 0.1-0.4 0.4-2.9 2.9-7.3 7.3-14.7 14.7-29.3 29.3-73.3 73.3-146.5 146.5-439.5 >439.5
SIZE RANGE. MW thermal
Figure 3 Relative distribution Q£ the capacity of the industrial/commercial
boiler population by type and size.
-------
X
X
H-
H-
FIRE TUBE
WATER TUBE
CAST IRON
Figure 4. Relative distribution of the total capacity by fuel type in
each boiler class.
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tionate to the total amount of coal used relative to other fuels
because of the ash contained in coal.
Calculations of uncontrolled emissions from all boilers were
based on estimates of 1975 fuel consumption. Calculations of
projected emissions through the year 2000 were based on a 3.3
percent yearly growth rate in the consumption of fuel by boilers.
Figure 5 illustrates the resultant emission quantities for three
pollutants considered. This figure also shows the emissions by
boiler type. As shown in Figure 5, uncontrolled emissions will
more than double by the year 2000.
Two other annual growth rates under various scenarios were
analyzed, 0.5 and 4.6 percent. Uncontrolled emission rates under
these scenarios are also presented in the report. The projec-
tions do not take into account the expected increase in emissions
resulting from coal conversion strategies and increased use of
coal; insufficient data are available to quantify the extent of
such conversion. Particulate matter and SO are obviously the
major pollutants emitted by boilers, nitrogen oxides are next in
significance, and CO and HC are relatively minor.
Based on the fuel consumption estimates and the total in-
stalled firing capacity, load factors were estimated for the
various boiler categories. These load factors are significantly
lower than previously published estimates, the overall average
load factor being 26 percent rather than the 35 percent published
by Battelle (Putnam et al., 1975). The load factors calculated
in this report may be unrealistically low because of the methods
used to calculate replacement boiler capacity versus new capacity.
It is doubtful, however, that the actual load factors are as high
as previous estimates, indicating that a large number of boilers
are on standby and used seasonally.
In order to assess the relative impacts of various control
strategies on the costs of new industrial boilers, PEDCo selected
23 boiler/fuel combinations for detailed cost estimating.
Table 1 presents the boiler/fuel combinations selected. Key
operating and design parameters were specified for each of the
xxiii
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X
X
K:'A MATER-TUBE
CD FIRE-TUBE
II CAST IRON
1990
YEAR
Figure 5. Relative total emission levels of particulate matter, SOX, and NOX
by boiler class for the period 1975 through 2000.
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boiler fuel combinations including boiler configuration, design
heat input rate, fuel analysis, fuel consumption, air pollutant
emission rates, excess air usage, flue gas characteristics, and
annual load factor. These parameters are necessary for the
design of the various control technologies applicable to boilers.
In addition, standardized formats and bases are used for
estimation of costs of boilers and of various control methods.
Guidelines were developed for the items to be included under
direct capital costs, indirect capital costs, working capital,
annual operation and maintenance costs, overhead, and fixed
annual costs. For consistency, the costs of boilers and control
equipment are based on a new installation in the Midwest.
The costs for representative new boilers and fuel type com-
binations have been calculated according to the uniform pro-
cedure. These costs are summarized in Table 2 for each of the 23
boiler/fuel combinations. The total installed capital costs
range from $389,800 for a package fire-tube boiler firing natural
gas with a heat input of 4.4 MW thermal (15 x 10 Btu/h) to
$26,836,600 for a field-erected water-tube boiler firing pulver-
ized subbituminous coal with a heat input of 117.2 MW thermal
(400 x 10 Btu/h). These costs include land and working capital
and represent June 1978 dollars. The cost of boilers is highly
dependent on firing capacity and fuel.
Total annualized costs for the boilers just cited range from
$496,000 to $7,930,0,00. Although the procedures to be used in
determining costs for pollution control equipment are specified,
no actual costs have been calculated. Control equipment specifi-
cations, control capabilities, and control equipment costs are
subjects for future work.
xxv
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TABLE 1. REPRESENTATIVE BOILERS AND FUELS FOR EVALUATION
Boiler type
Fuel
Heat input, MW thermal
(106 Btu/h)
Package, Scotch fire-tube
Package, Scotch fire-tube
Package, water-tube
Package, water-tube, underfeed-
stoker
Field-erected, water-tube,
chain-grate-stoker
?s
X
P. Package, water-tube
Package, water-tube
Package, water-tube
Field-erected, water-tube,
spreader-stoker
Field-erected, water-tube
Field-erected, water-tube
Natural gas
Distillate oil
Residual oil
Coal (3 types)
Coal (4 types)
Natural gas
Residual oil
Distillate oil
Coal (3 types)
Pulverized coal
(3 types)
Pulverized coal
(4 types)
4.4 (15)
4.4 (15)
8.8 (30)
8.8 (30)
22.0 (75)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
58.6 (200)
117.2 (400)
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TABLE 2. SUMMARY OF THE ESTIMATED CAPITAL AND ANNUALIZED COSTS
FOR THE SELECTED REPRESENTATIVE BOILERS
Boiler type
Package, fire-tube
Package, fire-tube
Package, water-tube
Package, water-tube
underfeed -stoker
Package, water-tube
under feed -stoker
Package, water-tube
under feed- stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Package, water-tube
Fuel
Natural gas
Distillate oil
Residual oil
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Eastern low-
sulfur coal
Eastern medium-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coa 1
Natural gas
Boiler capacity,
MW thermal
(106 Btu/h)
4.4 (15)
4.4 (15)
8.8 (30)
8.8 (30)
8.8 (30)
8.8 (30)
22.0 (75)
22.0 (75)
22.0 (75)
22.0 (75)
44.0 (150)
Capital cost,
S
389,800
405,100
797,800
1,665,200
1,891,300
2,257,100
4,067,900
4 ,165,300
4,554 , 400
5,341,000
2,118,700
Annua 1
O and M, $
439,900
501,000
678,800
721,600
682,500
653,300
1,330,500
1,283,900
1,217,900
1,120,100
2,035,100
Fixed
cost, S
56,100
57,600
109,600
236,300
269,800
323,600
563,400
577,600
633,300
745,700
287,800
Total annualized
cost, $
496,000
558,600
788,400
957,900
952,300
976,900
1,893,900
1,861,500
1,851,200
1,865,800
2,322,900
(continued)
-------
TABLE 2 (continued)
Boiler type
Package, water-tube
Package, water-tube
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Fuel
Residual oil
Distillate oil
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Eastern low-
sulfur coal
Eastern medium-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
_ _!
Boiler capacity,
MW thermal
(106 Btu/h)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
58.6 (200)
58.6 (200)
58.6 (200)
117.2 (400)
117.2 (400)
117.2 (400)
117.2 (400)
Capital cost,
$
2,244,900
2,379,700
7,804,100
8,784 ,200
10,395,800
10,823,200
12,202,400
14,468,400
20,094,000
20,707 , 300
22,638,000
26,836,600
Annual
0 and M, $
2,223, 100
2,793,900
2,101,800
1,849,100
1,665,400
2,875,600
2,544,800
2,343,000
5, 317,000
4 ,957,700
4,624,100
4 , 171, 800
Fixed
cost, $
304,100
317,100
1,084,500
1,225,900
1,455,800
1,504,400
1,702,900
2,025,600
2,792,500
2,883,000
3,159,500
3,758,200
Total annualized
cost, $
2,527,200
3,111,000
3,186,300
3,075,000
3,121,100
4,380,000
4,247,700
4,368,600
8,109,500
7,840,700
7,783,600
7,930,000
X
X
<
H-
H-
H-
-------
SECTION 1
INTRODUCTION
Boilers, particularly large utility boilers, have long been
recognized as major contributors to atmospheric pollution in the
United States.* The emissions from boilers include the criteria
pollutants (e.g., particulate matter, sulfur oxides, and nitrogen
oxides) as well as various metal' oxides and possibly some hazar-
dous substances. The emissions are dependent on the fuel that is
used, the size and type of the boiler, and of course the number
of boilers.
Almost every state has specific regulations governing the
emissions of particulate matter and sulfur dioxide from boilers,
but emissions of other pollutants are generally not regulated.
The U.S. Environmental Protection Agency (EPA) has promulgated
regulations for particulate matter, sulfur dioxide, and nitrogen
oxides from new boilers with a heat input of 73.25 MW thermal
(250 x 10 Btu/h) or larger. To date emphasis has been on en-
forcing these regulations as they pertain to large utility boil-
ers because of the higher emission values associated with each
individual source and in aggregate.
The impact of industrial and commercial boilers on national
air quality has not been well defined. Organization of the fun-
damental data required, such as the number and sizes of boilers
by boiler type, the types of fuel used, and the effect of such
variables as boiler design on emission rates, has been lacking.
Furthermore, basic information on emission rates for noncriteria
pollutants, geographical distribution of boilers by type, health
effects of specific pollutants, and population-at-risk determinations
* Throughout this report the term "boiler" is used to represent a
steam generator system consisting of both a furnace where the
fuel is burned and a boiler in which the water is heated for
use as hot water or steam.
-------
is limited; however, in the aggregate, it has been recognized
that industrial and commercial boilers do contribute signifi-
cantly to nationwide totals of TSP, SOX, and NOX emissions.
The purpose of this study is to develop the data base to
conduct a comprehensive evaluation of the environmental impacts
of industrial and commercial boilers.
Specifically, the tasks defined by the Industrial Environ-
mental Research Laboratory, Research Triangle Park (IERL-RTP) for
study were:
0 Categorize the boilers in the United States by type,
number, capacity, fuel consumption and use; project the
growth within these categories.
0 Estimate air pollutant emissions from industrial and
commercial boilers as a function of boiler type and
fuel use.
0 Establish the technical and cost bases for evaluating
the cost of boilers and emission control systems.
0 Select representative boilers for detailed cost evalua-
tion and for control technology assessment studies.
0 Estimate capital and annualized costs for the repre-
sentative boilers.
The information obtained in the performance of these tasks
will form the basis for control technology assessment studies for
the generation of Individual Technology Assessment Reports
(ITAR).
The initial step in the project was to characterize the U.S.
boiler population by establishing categories for boilers with
similar air emissions for possible development of individual
standards. (Utility and residential boilers were outside the
scope of the study by definition.) Characterization involved
identifying the types of boilers in use and then estimating the
number of boilers in each category and their total fuel-burning
capacity. The basic boiler population data were developed by
updating and expanding upon prior boiler studies by Walden
(Ehrenfeld et al., 1971) and Battelle (Locklin et al., 1974;
-------
Putnam et al., 1975). Material for updating was supplied by the
American Boiler Manufacturers Association (ABMA), the Hydronics
Institute (HI), the Department of Energy (DOE), and the EPA.
The next step was to determine the amount of fuel consumed
in each boiler category of the present boiler population. Con-
sumption of the various fuels by boiler type was based on avail-
able data from annual surveys by government agencies such as the
Bureau of Mines and the Department of Energy.
Estimates of growth in boiler use and fuel consumption
through 2000 were based on forecasts and estimates from previous
studies by others (Stanford Research, 1972; Fejer and Larson
1974; Edison Electric Institute, 1976; Energy Information Admin-
istration, 1977) .
Total aggregated emissions from the existing and projected
industrial boiler population were then estimated, based on fuel
consumption data and published emission factors in Compilation of
Air Pollutant Emission Factors, AP-42 (EPA, 1977).
Given this foundation, the next step was to provide a basis
for conducting cost evaluations. These technical and cost bases
were developed for use by other contractors in their assessment
of costs of emission control systems. Standardized procedures,
formats, and prices were determined with guidance from the
Economic Analysis Branch (EAB) of the EPA. Recommended values
for specific cost items were obtained by surveying trade publica-
tions and contacting marketing organizations.
Specific boilers were selected for detailed cost estimation.
Selection of representative units was based on three criteria:
the portion of the boiler population each unit represents, the
potential emissions contribution of the unit, and a representa-
tion of each of the various fuel types. Design and operational
parameters for each boiler were determined from published manu-
facturers' data and engineering calculations.
The cost guidelines developed in the study were used to
estimate costs for each of the representative boilers, based on
quotes from equipment manufacturers.
-------
Section 2 describes the development of the boiler population
and fuel consumption data base. Section 3 discusses atmospheric
emission estimates and projections. Section 4 describes the
design characteristics of the boilers considered representative
of important boiler categories. Section 5 presents the basis to
be used in developing boiler and control equipment costs (includ-
ing the elements that should be included in cost evaluations),
the recommended format for presentation of results, and unit
price recommendations for annual operating cost elements. Sec-
tion 6, which presents representative boiler costs, concludes the
.body of the report. The appendices describe the methodology used
and present details of the boiler population data base.
-------
REFERENCES FOR SECTION 1
Edison Electric Institute. 1976. Economic Growth in the Future
- The Growth Debate in National and Global Perspective.
New York City.
Ehrenfeld, J.R., R.H. Bernstein, K. Carr, J.C. Goldish, R.G.
Orner, and J. Parks. 1971. Systematic Study of Air Pollu-
tion from Intermediate-size Fossil-fuel Combustion Equipment,
CPA 22-69-85. Walden Research Corporation, Cambridge,
Massachusetts.
Energy Information Administration. 1977. Projections of Energy
Supply and Demand and Their Impacts, Vol. II. Annual Report
to Congress: U.S. Department of Energy, Washington, D.C.
Fejer, M.E., and D.H. Larson. 1974. Study of Industrial Uses
of Energy Relative to Environmental Impacts. Institute of
Gas Technology, Chicago.
Putnam, A.A., E.L. Kropp, and R.E. Barrett. 1975. Evaluation
of National Boiler Inventory. EPA 68-02-1223, Battelle-
Columbus Laboratories, Columbus, Ohio.
Locklin, D.W., H.H. Krause, A.A. Putnam, E.L. Kropp, W.T. Reid,
and M.S. Duffy. 1974. Design Trends and Operating Prob-
lems in Combustion Modification of Industrial Boilers.
EPA R-802402, Battelle-Columbus Laboratories, Columbus,
Ohio.
Stanford Research Institute. 1972. Patterns of Energy Consump-
tion in the United States. Washington, D.C.
U.S. Environmental Protection Agency. 1977. Compilation of Air
Pollutant Emission Factors, AP-42, Second Edition.
-------
SECTION 2
THE INDUSTRIAL/COMMERCIAL BOILER POPULATION AND FUEL CONSUMPTION
The population of industrial/commercial boilers consists of
many different types of units, which use various fuels and
methods of heat transfer. The following subsections present the
categories of classification for industrial/commercial boilers,
the population of each category, the fuels consumed in each
category, and the projections of growth of fuel consumption by
the boiler population through the year 2000.
2.1 BOILER CLASSIFICATION
Boilers can be and have been classified in a number of ways,
using such bases of categorization as boiler type, fuel use, and
method of manufacture. Two main factors were considered in
selecting the parameters of classification for this study.
First, consideration was given to whether variation in the param-
eter was likely to produce a significant change in air emis-
sions. The second consideration asks whether the parameter had
been regarded as an important variable in collecting and storing
the data needed to construct boiler population estimates. The
final list of parameters was developed from analysis of past work
and reflects comments of reviewers who are associated with boiler
manufacturing organizations and know what data are available.
The basic boiler classifications appear in Table 2-1. As
the table shows, units were categorized by construction method
and heat transfer configuration, then by firing mechanism and
fuel. Descriptions of the various types of boilers shown in
Table 2-1 are presented in Appendix A.
Each type of industrial/commercial boiler was further
subcategorized by heat transfer mechanism, type of use, and size,
using the following classification scheme.
6
-------
TABLE 2-1. CATEGORIES OF INDUSTRIAL/COMMERCIAL BOILERS
Field-erected/Water-tube
Pulverized coal
Spreader-stoker
Overfeed-stoker coal
Underfeed-stoker coal
Residual oil
Distillate oil
Natural gas
Package Boilers/Water-tube
Pulverized coal
Spreader-stoker coal
Overfeed-stoker coal
Underfeed-stoker coal
Residual coal
Distillate oil
Natural gas
Package/Fire-tube
Coal/Horizontal Return Tubular (HRT)
Coal/Firebox
Coal/Scotch
Coal/Other
Residual oil/Horizontal Return Tubular (HRT)
Residual oil/Firebox
Residual oil/Scotch
Residual oil/Other
Distillate oil/Horizontal Return Tubular (HRT)
Distillate oil/Firebox
Distillate oil/Scotch
Distillate oil/Other
Natural gas/Horizontal Return Tubular (HRT)
Natural gas/Firebox
Natural gas/Scotch
Natural gas/Other
Package/Cast Iron
Coal
Residual oil
Distillate oil
Natural Gas
-------
Heat transfer medium:
Supercritical steam
High-pressure steam
Low-pressure steam
Hot water
Use:
Commercial/institutional space heating
Industrial space heating
Industrial process heat
0 Size:
MW thermal (Btu/h)
•
Equal to or under 0.1 (Equal to or under 0.4 x 106)
Over 0.1 - 0.4 (over 0.4 x 106 - 1.5 x 106)
Over 0.4 - 2.9 (over 1.5 x 106 - 10 x 106)
Over 2.9 - 7.3 (over 10 x 106 - 25 x 106)
Over 7.3 - 14.7 (over 25 x 106 - 50 x 106)
Over 14.7 - 29.3 (over 50 x 10^ - 100 x 106)
Over 29.3 - 73.3 (over 100 x 1()6 - 250 x 106)
Over 73.3 - 146.5 (over 250 x 106 - 500 x 106)
Over 146.5 - 439.5 (over 500 x 106 - 1500 x 1()6)
Over 439.5 (over 1500 x 106)
Possible combinations of the classifications used in this
study are illustrated in Figure 2-1.
During the course of the study, many rearrangements of the
data were used to compare the relative significance of various
categories, with regard to such factors as total capacity, fuel
consumption, and emissions. The next section describes the
boiler population according to the final classifications selected.
2.2 PRESENT BOILER POPULATION
Estimates of the number and capacity of present industrial/
commercial boilers are derived from combining data in studies by
Battelle (Locklin et al., 1974; Putnam et al., 1975) and Walden
(Ehrenfeld et al., 1971) with sales records of the American Boiler
Manufacturers Association (ABMA) and the Hydronics Institute
(HI) .
The total number of boilers categorized by fuel type, size,
type of use, heat transfer configuration, and method of construction
8
-------
WATER-TUBE
FIELD-ERECTED
PACKAGE
PULVERIZED
COAL
SPREADER
STOKER
RESIDUAL OIL
DISTILLATE OIL
NATURAL GAS
OVCRFEED
UNDERFEED
CAST IRON
COAL
HORIZONTAL RETURN TUBULAR
PACKAGE
FIRE-TUBE |
RESIDUAL OIL
DISTILLATE OIL
NATURAL GAS
SCOTCH
FIREBOX
OTHER
PACKAGE
COAL
RESIDUAL OIL
DISTILLATE OIL
NATURAL GAS
Figure 2-1. Possible combinations of characteristics
associated with U.S. industrial/commercial boilers.
-------
(i.e., package versus field-erected) are discussed in the follow-
ing subsections. The methods used to develop the estimates are
explained in Appendix B. Data sheets for all boiler types and
subcategories are presented in Appendix C.
The total number and capacity of industrial/commercial
boilers according to fuel used are shown in Table 2-2. The
various fuels are burned in boilers that differ widely in size,
use (e.g., space heating and electric generation), and type of
hardware (e.g., fire-tube, water-tube, and cast iron). In order
to focus on these differences, it is necessary to examine various
subcategories. The nonutility boilers being considered can be
separated into two broad sectors, commercial and industrial.
Commercial boilers are generally the smaller of the two, and are
used primarily for space heating in commercial and institutional
buildings. Industrial boilers are used to generate process
steam, space heating, and electricity. The distribution between
the two sectors is shown in Table 2-3.
TABLE 2-2. SUMMARY OF THE TOTAL BOILER POPULATION BY FUEL USED
Fuel
Coal
Residual oil
Distillate oil
Natural gas
Number of boilers
214,400
389,104
244,206
954,350
Total capacity, a
MW thermal (106 Btu/h)
239,110 (815,830)
358,570 (1,223,800)
127,040 (433,600)
588,590 (2,008,800)
Throughout this section totals for capacity do not always agree
because figures are rounded.
TABLE 2-3. DISTRIBUTION OF NONUTILITY BOILERS BY SECTOR
Sector
Commercial
Industrial
Number of boilers
1,295,130
506, 930
Total capacity,
MW thermal (106 Btu/h)
402,780 (1,374,690)
910,480 (3,107,440)
10
-------
Because the size of a boiler can directly relate to the
total quantity of pollutants discharged and the feasibility and
economics of control, it is necessary to distribute the total
industrial/commercial population by size,^. Table 2-4 presents
such a display. As shown in this table, 1,094,000 MW thermal
(3,733,800 x 106 Btu/h), or 83 percent of the industrial/com-
mercial boiler capacity, is comprised of units whose size is less
than 73.25 MW thermal (250 x 106 Btu/h), the lower limit for the
existing New Source Performance Standards for boilers.
TABLE 2-4. DISTRIBUTION OF COMMERCIAL/INDUSTRIAL BOILERS BY SIZE
Size,
MW thermal (106 Btu/h)
Number of
boilers
Total capacity,
MW thermal (106 Btu/h)
Equal to or under 0.1
(equal to or under 0.4)
Over 0.1 to 0.4
(over 0.4 to 1.5)
Over 0.4 to 2.9
(over 1.5 to 10)
Over 2.9 to 7.3
(over 10 to 25)
Over 7.3 to 14.7
(over 25 to 50)
Over 14.7 to 29.3
(over 50 to 100)
Over 29.3 to 73.3
(over 100 to 250)
Over 73.3 to 146.5
(over 250 to 500)
Over 146.5 to 439.5
(over 500 to 1500)
Over 439.5 (over 1500)
970,980
568,415
208,659
25,081
16,483
6,840
4,266
1,018
253
65
69,180 (236,100)
143,820 (490,700)
240,270 (820,000)
126,770 (432,600)
178,350 (608,700)
147,380 (503,000)
185,160 (632,000)
98,280 (335,400)
56,080 (191,400)
68,050 (232,200)
11
-------
A basic and important way to classify boilers is according
to heat transfer configuration, i.e., water-tube, fire-tube, and
•ast iron. In water-tube boilers, the water being heated flows
through tubes and the hot gases circulate outside of the tubes.
In fire-tube boilers, the opposite is true. In cast iron boilers,
the gas is also contained inside the tubes that are surrounded by
the water being heated, but the units are constructed of cast iron
rather than steel. Classification by type is important because
water-tube boilers are generally much larger than fire-tube or
cast iron boilers. The potential emissions are different for the
various types of boilers.
Tables 2-5 through 2-7 provide the distributions for the
three types of boilers according to the size range and fuel used.
It will be noted that Table 2-5 provides a subcategorization for
coal-fired units according to firing mechanism. In Tables 2-8
through 2-13, these distributions are presented individually for
the commercial sector and the industrial sector.
Table 2-14 summarizes the results and clearly indicates that
water-tube boilers represent over half the total capacity.
Furthermore, the average size of water-tube boilers exceeds that
of fire-tube boilers by more than 10 times.
In summary, the derived data indicate the following char-
acteristics of the boiler population:
0 Natural gas is the predominant fuel, accounting for 45
percent of the capacity.
0 Ranking of the other fuels by capacity is residual oil
at 27 percent, coal at 18 percent, and distillate oil
at 10 percent.
0 Distribution of the industrial/commercial boiler pop-
ulation is 69 percent of the capacity in industrial
applications and 31 percent in commercial applications.
0 Forty percent of the industrial/commercial boiler
capacity is in the range of 1 to 73 MW thermal. Seven-
teen percent of the capacity is above 73 MW thermal,
and 44 percent is below 7 MW thermal.
12
-------
TABLE 2-5. DISTRIBUTION OF U.S. WATER-TUBE BOILERS
BY CAPACITY AND FUEL TYPE
ru«l
Pulv«rii*d coal
Number of untt»
Total capacity, HH
thermal (10* Btu/h)
Number of unit*
Total capacity, HU
th«rm«l (10*- Dtu/h)
Und«rf**d-Btok«r coal
Number of unit!
T*»tal eapac i ty , W
thormal (10* itu/h)
Or*rf «*d-n tokar coal
Total capacity, *•*
thermal (10* itu/h)
toaiduAl oil
Numtxtr of unit*
V»e*l capacity, »•*
thermal (10* »tu/M
Distillate oil
Number of unit*
Total capacity. r«
thermal (10* Btu/h)
Number of units
Total capacity, M<
thermal (10* itu/h)
Tot* I «11 fuel*
Number of unit*
Tot a 1 capacity, W
thermal (10* »tu/h)
0 J to 0. 4
(0.4 to 1.5)
0
0
5)2
150
(500)
10
(30)
1,173
410
(1.400)
2,928
1,030
(3,5001
2,414
1)0
(2.900)
7,075
2.4SO
(•,3)01
(1.5 to 101
0
103
150
(500)
929
1,410
(4,1001
ISO
1(00)
3,215
4,8)0
(16.5001
2,*sa
3,460
(11,100)
l.Clf
4,«20
lit, 100)
10,934
14.950
151,000)
(10 to 25)
0
142
110
(2,400)
657
3,230
(11,000)
440
(1,500)
2.731
13,010
(44,400)
65*
2,9(0
(10,100)
2,535
12.630
(43,100)
6,813
32,9>0
(112.500)
C
(25 to 50)
0
521
5,830
(19,900)
1.509
I*. 760
(57,200)
402
4,430
(15,100)
5,022
53.560
(112,800)
914
9,310
(31. (00)
4.163
52.710
(179,900)
13.231
142,600
(486.700)
(50 to 100)
0
343
7,440
(25,400)
950
20,800
171,000)
5,370
(18,300)
2,205
47,520
(162.200)
291
6,710
(22.900)
2.795
59,540
(203,200)
6,840
147. 380
(503,000)
HH th«nul (
(100 to 250)
467
20,510
(70,000)
504
21,590
(73,700)
110
7,530
(25,700)
3.710
(12,900)
1.237
53.310
(1(2.000)
201
1,150
(10,200)
1.586
69.510
(237.500)
4,166
185,160
(632,000)
10^ Btu/h)
(250 to 500)
191
18,460
(63,000)
(3
7.500
(25,600)
38
3,490
(11.900)
2,350
((.000)
300
19.240
(99,100)
41
4,150
(14,5001
339
32,990
1112,6001
1.011
91.180
(115,400)
(500 to 1500)
<4
11.980
(47,700)
9
2,160
(7,700)
5
1,110
(1,100)
710
(2.500)
62
11,190
(47,400)
7
1.510
(5,1001
101
11,5*0
(77,100)
151
56,010
(191.400)
439. 5
(1500)
11
7.740
(26,400)
1
1,850
(6,300)
1
910
11,100)
(20
(1.100)
«
5, (10
(19,100)
1
(70
(1.100)
40
50, (10
(171,1001
(5
(1.050
(211.200)
TotoJo
711
60,690
(207,1001
1.701
47.130
(1(1.500)
4,100
55,190
1189.000)
1 003
17.910
1(1,010)
15,951
111.410
1755.700)
8.008
11,760
(111.100)
It. 1*1
106,440
(1.045,900)
50.495
747,910
(1,551,510)
-------
TABLE 2-6. DISTRIBUTION OF U.S. FIRE-TUBE BOILERS
BY CAPACITY AND FUEL TYPE
Fuel
Coal
Number of units
Total capacity, MW
thermal (106 Btu/h)
Residual oil
Number of units
Total capacity, MW
thermal (1Q6 Btu/h)
Distillate oil
Number of units
Total capacity, MW
thermal (10& Btu/h)
Natural gas
Number of units
Total capacity, MW
thermal (10° Btu/h)
Total all fuels
Number of units
Total capacity, MW
thermal (10° Btu/h)
Size range, MW thermal (106 Btu/h)
0.1 to 0.4
(0.4 to 1.5)
19,227
5,630
(19,200)
46,267
13,570
(46,300)
30,191
8,850
(30,200)
83,483
24,470
(83,500)
179,168
52,520
(179,200)
0.4 to 2.9)
(1.5 to 10)
5,210
8,790
(30,000)
21,511
34,630
(118,200)
14,089
22,680
(77,400)
33,577
54,620
(186,400)
74,387
120,720
(412,000)
2.9 to 7.3
(10 to 25)
1,533
7,850
(26,800)
5,072
26,050
(88,900)
3,318
17,050
(58,200)
8,345
42,840
(146,200)
18,268
93,790
(320,100)
7.3 to 14.7
(25 to 50)
358
3,930
(13,400)
833
9,140
(31,200)
543
5,980
(20,400)
1,518
16,700
(57,000)
3,252
35,750
(122,000)
Totals
26,328
26,200
(89,400)
73,683
83,390
(284,600)
48,141
54,560
(186,200)
126,923
138,630
(473,100)
275,075
302,780
(1,033,300)
-------
TABLE 2-7. DISTRIBUTION OF U.S. CAST IRON BOILERS
BY CAPACITY AND FUEL TYPE
Fuel
Coal
Number of units
MW thermal input
(106 Btu/h)
Residual oil
Number of units
MW thermal input
(106 Btu/h)
Distillate oil
Number of units
MW thermal input
(106 Btu/h)
Natural gas
Number of units
MW thermal input
(106 Btu/h)
Total all fuel
Number of units
MW thermal input
(106 Btu/h)
Size range, MW thermal (106 Btu/h)
<0.1
(<0.4)
113,287
6,010
(20,500)
203,569
15,030
(51,300)
127,833
9,430
(32,200)
526,291
38,710
(132,100)
970,980
69,180
(236,100)
0.1 to 0.4
(0.4 to 1.5)
46,760
12,310
(42,000)
71,614
16,090
(54,900)
44,979
10,080
(34,400)
218,819
50,340
(171,800)
382,172
88,820
(303,100)
0.4 to 2.9
(1.5 to 10)
19,782
13,270
145,300)
24,285
22,650
(77,300)
15,245
14,210
(48,500)
64,026
54,470
(185,900)
123,338
104,600
(357,000)
Total
179,829
31,590
(107,800)
299,468
53,770
(183,500)
188,057
33,720
(115,100)
809,136
143,520
(489,800)
1,476,490
262,600
(896,200)
-------
TABLE 2-8.
DISTRIBUTION OF U.S. WATER-TUBE COMMERCIAL BOILERS
BY CAPACITY AND FUEL TYPE
rwi
Pulv«rii«d coal
•tavbvr oC unit*
Total capacity. Ml
tharmal (10« Itu/M
Spra+o^r-atoltar coal
•uatwr or unlta
Total capacity. •*>
thcraal (10* »tu/h)
Und*rfMd-»tok«r coal
•unbar of units
total capacity. W
thanaal (10* Itu/M
OnrfMd-atokar coal
Total capacity. •*
thermal (10* •tn/kl
•Midual oil
Hiattwr of unita
•tul capacity, W
tfcaraal 110* Itn/k)
Dlatlllata oil
fmtitr of unit*
total capacity. 1C
Ovai-mal (10* Itw/k)
natural gaa
•unbar of unit!
Total capacity. W
ttaraal (10* itu/h)
Total all fiwlc
•umber of unit*
Total capacity. W
thcnul (lot Btu/h)
(0.< to l.M
0
0
31J
lot
(1JO)
s
(101
]••
140
(410)
1S52
»0
(KtO)
113
)10
(1070)
1J)»
1110
(17101
11.% to 10)
0
57
80
(280)
510
775
(2.640)
100
<3JO I
772
1,160
(l.?«0>
1,11]
1, )80
(4,720)
723
985
11.160)
], )09
4.480
(IS, 290)
110 to 25)
0
53
260
(890)
243
1.195
(4,070)
160
(S60)
710
3.380
(11.540)
204
920
(3,130)
330
1.640
(5,600)
1,573
7.555
(25.7901
Ca
(25 to 50)
0
146
1,6)0
(5.570!
421
4,690
(16,020)
1,240
14,2)0)
1,406
15,000
(51,180)
302
3.070
(10,490)
515
5,800
(19,790)
2,925
31,4)0
(107,280)
ISO to 100)
0
58
1,26%
(4, 120)
162
},5)5
(12.070)
915
(1,1101
551
11,880
(40,550)
107
1,415
(8,240)
280
5,955
<2C,320)
1,200
25,965
(88,610)
MW thermal <1(
(100 to 250)
14
61S
12,1001
10
1,295
14,420)
11
450
(1,540)
225
(7701
198
8.5)0
(29,120)
12
2,480
18,460)
14)
6,260
(21,370)
4))
19.855
167,780)
6 Btu/hl
(250 to 500)
0
7
too
12,050)
)
210
(950)
190
(*40)
39
3,800
112,970)
16
1,700
(5,8001
J7
3,630
(12,3*0)
104
10,200
(34,800)
1500 to 1500)
•
0
0
t
1,190
(4.740)
)
(55
(1.240)
7
1,580
(5,400)
3.62*
112.380)
4)9.5
(1500)
•
0
0
a
0
«
I.MS
17.110)
4
5.065
111,210)
Total*
14
«15
(2.1001
151
5,1)0
(17.5)01
1,724
11.010
(37.640)
171
1,115
(•,660)
4,0*1
4S.lt*
(154,54*1
l.lt*
11.171
(44,940)
2,»S2
11,225
(104.580)
12,799
lot, us
(372,990)
-------
TABLE 2-9.
DISTRIBUTION OF U.S. WATER-TUBE INDUSTRIAL BOILERS
BY CAPACITY AND FUEL TYPE
rv*i
Pulwritad coal
Ihakber of units
Total capacityt HH
thermal (10* Itu/h)
•preader-atoker coal
number of unit*
Total capacity. MM
thermal (10* (tu/h)
Underfeed-atoker coal
•unber of unit*
teul capacity. KW
thermal (10* Itu/h)
Overfeed-atoker coal
Biiaiiai or unit*
Total capacity. *•>
thermal (10* «tu/h>
tosUual oil
Irumber of unlta
*»ul capacity, "•<
thermal (10* Itu/h)
Diatlllate oil
•umber of unlta
T«c«l capacity. nV
thermal (10* >tii/h)
matural gee
number of unlta
Total capacity. Ml
thermal (10* Itu/h)
Total all ruela
•umber of unlta
Total capacity, W
thermal (10* *tu/h)
0.1 to 0.4
(0.4 to 1.5)
0
0
uo
45
(1501
1
i
(10)
774
270
(»20)
1371
410
(1*40)
IS21
540
(1810)
1819
1 )40
(45501
11.5 to 10)
0
46
70
(220)
418
415
(2.1601
SI
§0
(270)
2,44)
3, 470
112,540)
1.775
2,080
17,010)
2.B91
1,9)5
113.440)
7.626
10,470
(35,710)
(10 to 2SI
0
e»
450
(1,510)
414
2.035
(6.930)
56
280
(940)
2,021
9,630
(12, KOI
455
2,040
(6.970)
2,205
10,990
(37,500)
5,240
25,425
186,710)
Ca
(25 to 50)
0
175
4,200
(14,330)
1,086
12,070
(41,180)
289
3,190
110,870)
3,616
38,560
(131,620)
612
6,2*0
(21.310)
4,328
46,910
1160,110)
10. 101.
1 1 1 . 1 7(1
I )79,4 JO)
150 to 100)
0
285
6,175
(21.080)
738
17,265
158,930)
207
»,455
(K.190)
1.654
35,640
(121,650)
191
4.295
(1*. 660)
2.615
5),S85
1181, aaoi
5.440
II\.«li
(414.390)
HW thariaal (1
1100 to 250)
453
19,895
(47,900)
474
20.295
(69,280)
169
7,080
(74,160)
85
3.555
(12,110)
1,019
44,790
(152,880)
170
6, 370
121,740)
1,443
61, 120
1216, 110)
1.81J
165. 105
-------
TABLE 2-10. DISTRIBUTION OF U.S. COMMERCIAL
FIRE-TUBE BOILERS BY CAPACITY AND FUEL TYPE
CO
Fuel
Coal
Number of units
Total capacity, MW
thermal (106 Btu/h)
Residual oil
Number of units
Total capacity, MW
thermal (10° Btu/h)
Distillate oil
Number of units
Total capacity, MW
thermal (10° Btu/h)
Natural gas
Number of units
Total capacity, MW
thermal (10° Btu/h)
Total all fuels
Number of units
Total capacity, MW
thermal (10° Btu/h)
Size range, MW thermal (10* Btu/h)
0.1 to 0.4
(0.4 to 1.5)
13,459
3,940
(13,500)
15,731
4,610
(15,700)
16,001
4,690
(16,000)
30,889
9,050
(30,900)
76,080
22,290
(76,100)
0.4 to 2.9
(1.5 to 10)
2,866
4,830
(16,500)
5,163
8,310
(28,400)
5,636
9,070
(31,000)
6,715
10,920
(37,300)
20,380
33,130
(113,200)
2.9 to 7.3
(10 to 25)
567
2,900
(9,900)
•1,319
6,770
(23,100)
1,029
5,290
(18,000)
1,085
5,570
(19,000)
4,000
20,530
(70,000)
7.3 to 14.7
(25 to 50)
100
1,100
(3.800)
233
2,560
(8,700)
179
1,970
(6,700)
167
1,840
(6,300)
679
7,470
(25,500)
Totals
16,992
12,770
(43,700)
22,446
22,250
(75,900)
22,845
21,020
(71,700)
38,856
27,380
(93,500)
101,139
83,420
(284,800)
-------
TABLE 2-11.
DISTRIBUTION OF U.S. INDUSTRIAL FIRE-TUBE BOILERS
BY CAPACITY AND FUEL TYPE
Fuel
Coal
Numb»r of units
Total capacity, MW
thermal (106 Btu/h)
Residual oil
Number of units
Total capacity, MW
thermal (106 Btu/h)
Distillate oil
Number of units
Total capacity, MW
thermal (106 Btu/h)
Natural gas
Number of units
Total capacity, MW
thermal (10^ Btu/h)
Total all fuels
Number of units
Total capacity, MW
thermal (10^ Btu/h)
Size range, MW thermal (10 Btu/h)
0.1 to 0.4
(0.4 to 1.5)
5,768
1,690
(5,700)
30,536
8,960
(30,600)
14,190
4,160
(14,200)
52,594
15,420
(52,600)
103,088
30,230
(103,100)
0.4 to 2.9
(1.5 to 10)
2,344
3,960
(13,500)
16,348
26,320
(89,800)
8,453
13,610
(46,400)
26,862
43,700
(149,100)
54,007
87,590
(298,800)
2.9 to 7.3
(10 to 25)
966
4,950
(16,900)
•3,753
19,280
(65,800)
2,289
11,760
(40,200)
7,260
37,270
(127,200)
14,268
73,260
(250,100)
7.3 to 14.7
(25 to 50)
258
2,830
(9,600)
600
6,580
(22,500)
364
4,010
(13,700)
1,351
9,230
(50,700)
2,573
28,280
(96,500)
Totals
9,336
13,430
(45,700)
51,237
61,140
(208,700)
25,296
33,540
(114,500)
88,067
111,250
(379,600)
173,936
219,360
(748,500)
-------
Table 2-12. DISTRIBUTION OF U.S. COMMERCIAL/INSTITUTIONAL
CAST IRON BOILERS BY CAPACITY AND FUEL TYPE
to
o
Fuel
Coal
Number of units
MW thermal input
(106 Btu/h)
Residual oil
Number of units
MW thermal input
(106 Btu/h)
Distillate oil
Number of units
MW thermal input
(106 Btu/h)
Natural gas
Number of units
MW thermal input
(106 Btu/h)
Total all fuel
Number of units
MW thermal input
(106 Btu/h)
Size range, MW thermal (106 Btu/h)
<0.1
(<0.4)
90,630
4,810
(16,400)
162,855
12,010
(41,000)
102,266
7,530
(25,700)
421,033
30,970
(105,700)
776,784
55,320
(188,800)
0.1 to 0.4
(0.4 to 1.5)
37,408
9,840
(33,600)
57,291
12,860
(43,900)
35,983
8,090
(27,600)
175,055
40,260
(137,400)
305,737
71,050
(242,500)
0.4 to 2.9
(1.5 to 10)
15,826
10,610
(36,200)
19,428
18,140
(61,900)
12,196
11,370
(38,800)
51,221
43,570
(148,700)
98,671
83,690
(285,600)
Total
-
143,864
25,260
(86,200)
239,574
43,010
(186,800)
150,445
26,990
(92,100)
647,309
114,800
(391,800)
1,181,192
210,060
(716,900)
-------
TABLE 2-13.
DISTRIBUTION OF U.S. INDUSTRIAL CAST IRON BOILERS
BY CAPACITY AND FUEL TYPE
Fuel
Coal
Number of units
Total capacity, MW
thermal (106 Btu/h)
Residual oil
Number of units
Total capacity, MW
thermal (106 Btu/h)
Distillate oil
Number of units
Total capacity, MW
thermal (10^ Btu/h)
Natural gas
Number of units
Total capacity, MW
thermal (10^ Btu/h)
Total all fuels
Number of units
Total capacity, MW
thermal (106 Btu/h)
Size range, MW thermal (10 Btu/h)
<0.1
(<0.4)
22,657
1,200
(4,100)
40,714
3, 020
(10,300)
25,567
1,880
(6,400)
105,258
7, 740
(26,400)
194,196
13,840
(47,200)
0.1 to 0.4
(0.4 to 1.5)
9,352
2,460
(8,400)
14,323
3,220
(11,000)
8,996
2,020
(6,900)
43,764
10, 080
(34,400)
76,435
17,780
(60,700)
0.4 to 2.9
(1.5 to 10)
3,956
2,670
(9,100)
4,857
4, 540
(15,500)
3,049
2,840
(9,700)
12,805
10,900
(37,200)
24,667
20,950
(71,500)
Totals
35,965
6,330
(21,600)
59,894
10,780
(36,800)
37,612
6,740
(23,000)
161,827
28,720
(98,000)
295,298
52,570
(179,400)
-------
TABLE 2-14. BOILER POPULATION DISTRIBUTED BY
HEAT-TRANSFER CONFIGURATION
Heat transfer
configuration
Water-tube
Fire-tube
Cast iron
Number of boilers
50,495
275,075
1,476,490
Total capacity,
MW thermal (10° Btu/h)
747,930 (2,552,500)
302,780 (1,033,300)
262,600 (896,200)
22
-------
Distribution of the industrial commercial boiler
capacity by the three major types is 57 percent water-
tube, 23 percent fire-tube, and 20 percent cast iron.
Given the significance of water-tube boilers, it is appro-
priate to examine further details of the population.
Based on sales data from the ABMA and HI, it was determined
that about 20 percent of the water-tube boiler capacity currently
in place is less than 7 years old. (The sales data from ABMA
were available only for the past 7 years). About 25 percent of
the current capacity of fire-tube and cast iron boilers is less
than 10 years old. About 62 percent of industrial/commercial •
water-tube boiler capacity is field-erected. The rest are pack-
age units (i.e., fabricated in the shop and transported in one
piece to the plant site). In contrast, all fire-tube and cast
iron boilers are package units. Tables 2-15 and 2-16 provide a
distribution of the water-tube boilers by size and fuel type for
the field-erected and package units. Although there are three
times as many package units, these only represent a third of the
total capacity.
The majority of the total water-tube boiler capacity is
represented by boilers below 73.3 MW thermal (250 x 106 Btu/h),
the present lower limit for units subject to NSPS. The dis-
tribution by size, (excerpted from Table 2-5) is:
Size, Total capacity,
MW thermal (106 Btu/h) MW thermal (1Q6 Btu/h)
Equal to or under 7.3
(equal to or under 25) 50,380 (171,800)
Over 7.3 - 14.7 (over 25 - 50) 142,600 (486,700)
Over 14.7 - 29.3 (over 50 - 100) 147,380 (503,000)
Over 29.3 - 73.3 (over 100 - 250) 185,160 (632,000)
Over 73.3 (over 250) 222,410 (759,000)
Only 6.7 percent of the total water-tube capacity is below
7.3 MW thermal (25 x 106 Btu/h). Water-tube units below 73.3
MW thermal account for nearly 49 percent of the boilers not
presently covered by NSPS.
23
-------
TABLE 2-15.
DISTRIBUTION OF U.S. FIELD-ERECTED WATER-TUBE BOILERS
BY CAPACITY AND FUEL TYPE
ruel
rulv«rii«d coal
Number of unite
Total capacity, m
thermal (10* Itu/h)
SpraaMler-etokvr coal
NuaOjar of unite
Total capacity. Ml
thermal (10* Btu/h)
Undarfvad-etokor coal
•untMr of units
*»tal capacity. Hi
tbarmal (10* Btn/h)
Ov«rf««d-etokcr coal
•iiirtiai of unita
Total capacity, «t*
thereat (10* Itu/h)
•aeleual oil
ffinaheir of units
••Ml capacity. •*
thcroal (10* (ta/h)
Olatllletc oil
•uBbar of unite
fatal capacity. Mt
tharmal 110* Itu/hl
natural gas
Kupibar of unita
Total capacity. Ml
trwnal (10* Itu/hl
Total all fuels
HvMbcr or unite
Total capacity, ft*
thainul (lot «tu/hl
0.1 to 0.4
1 0 . « to 1 . i 1
0
0
0
0
0
0
0
0
US to 1 0 1
0
0
0
0
0
0
0
0
(10 to 251
0
4)
210
(7001
197
970
(3,]00)
2k
120
(400)
819
1.900
(13, 300)
197
980
(3,000)
760
3,780
112,900)
2,042
9,860
133,600)
(25 to 50)
0
157
1,760
((,000)
453
5,040
117,200)
120
1, 120
(4,500)
1,507
16,060
(54,8001
274
2,780
(9,500)
1,459
15.820
(54,000)
1,970
42,780
(146,000)
150 to 100)
0
120
2,610
(1,900)
313
7,470
125,500)
87
1,880
(6,4001
771
16,640
(56,800)
105
2,140
(8,000)
979
20,810
171,100)
2,195
51,770
(176,700)
(100 to 2501
150
15, 100
(52,500)
179
16,200
(55,100)
115
5,650
IH, 100)
67
2.840
(9.700)
928
39,990
(116,5001
151
6,620
(22,600)
1,189
52,180
(178,100)
3,199
138, 8UO
(474,000)
1250 to 500)
190
19.170
(62,700)
82
7,410
(25,100)
17
1.400
111. tOO)
25
2.260
(7,700)
29«
28,950
196.8001
40
4.160
114.200)
J37
32,700
(111. tOO)
1,009
91,250
1331, 1001
(500 to 1SOOI
64
11, MO
147,700)
»
2,260
17,700)
5
1,110
(1.600)
1
710
(2,500)
62
11,190
(47,400)
7
1.520
(5.200)
101
22,590
(77,100)
251
56.080
(1*1,4001
419.5
(1500)
11
7,740
(24.4*0)
)
1.ISO
(6,100)
1
»10
(1,1001
1
C20
(2.100)
1
5.610
11*. 100)
I
670
(2,100)
40
50,6)0
(171,100)
65
68.050
(1)2,200)
Totals
615
55,470
(189,100)
791
32,100
(110,200)
1.161
24,550
(81,800)
129
9,770
(11,100)
4,191
125,060
(426,800)
775
11,970
(64,800)
4,867
178,5)0
(677,600)
12,913
464,650
(1,585,800)
to
-------
TABLE 2-16.
DISTRIBUTION OF U.S. PACKAGE WATER-TUBE BOILERS
BY CAPACITY AND FUEL TYPE
r»«i
Pulvvniad coal
•unbar of unit*
Tt>t«l capacity. MM
tharmal (10« .tu/hl
Number of unit*
Total capacity. MM
thatmal |lo' Itu/hl
Uadarf wd-atokcr coal
Nur*ber of units
t»tal opacity. ••
tbarmal (10* itu/h)
Ov«rfa«d-atok*r coal
•uBbar of units
ratal capacity. ••>
tharmal (10* ttu/M
ftMldual oil
ItiaWiar of unit*
ffjftal capacity, *l
thermal (10* itu/h)
Dtltlllat* oil
••••in of unit*
Total capacity. W
Uvaraal (10* Itii/h)
•aturai qaa
•unbar of unlta
Total capacity. >•*
thermal (10* Itu/h)
Total all fuala
Hiaih«r of unlta
Total capacity, n*
tltarval (10* »tu/h)
0.1 1 1> 0.4
(0.4 CO 1 .4)
0
0
5J2
ISO
(500)
2t
10
(10)
1171
410
11400)
2928
10)0
11500)
2414
• 50
11900)
7075
2450
(I))OI
11.5 to 10)
0
10J
1'jO
1500)
*;s
1 ,410
14, »00)
114
UO
ItOO)
1,215
4,8)0
lit. 500
2,956
1.460
(11,100)
1,616
4,»20
(It, BOO)
10,914
14.950
(51.000)
110 to 25)
0
99
500
11,700)
4tO
2.21,0
(7,700)
6)
120
(1.100)
1,912
9.110
U1.100)
462
2.080
(7,100)
1,775
8,850
130,200)
4,771
21,120
(78,900)
C.
125 to 50)
0
164
4,070
111,900)
1,056
11.720
(40.000)
2H2
1.110
110,600)
),515
)7.500
1121.000)
640
6,5)0
(22,300)
3,404
)t,B90
(125,900)
9,261
99,820
(340,700)
(50 to 1001
0
221
4,810
lit, 500)
617
1). 1)0
(45,500)
162
1,490
(11,900)
1,4)4
10,880
(105,400)
19)
4,)70
(14,900)
1,816
19,710
11)2,100)
4,445
95,610
(126.100)
(100 to 250)
117
5,110
(17,500)
125
5. 190
118,400)
45
1.8UO
(6,4001
2)
940
11,200)
309
1),))0
(45.500)
51
2,2)0
(7,600)
)97
17,400
(59,400)
1 ,067
it. )QQ
1159,000)
0' Btu/h)
1250 to 500)
1
90
( 1001
1
90
1)00)
1
90
(100)
1
90
1)001
2
290
(1000)
1
90
(300)
2
290
11000)
,idi
(500 to 1500)
0
0
0
0
0
0
0
0
4)9. t
11500)
0
0
0
0
0
•
0
0
Total*
118
5,220
117,800)
915
15.0)0
151,3001
3,639
30,840
(105,200)
671
8,140
(27,7)0)
11,540
96, 150
1328,900)
7,2)3
19.790
(67,5001
13,424
107.910
(368, 300)
37,562
283,280
(9tt,730l
ro
ui
-------
The capacity represented by boilers between 7.3 and 73.3 MW
thermal (25 and 250 x 106 Btu/h) is large for both field-erected
and package water-tube boilers. Approximately 93.5 percent of
the capacity of package boilers is in this -range. For field-
erncted boilers, the distribution is:
Size, Total capacity,
MW thermal (106 Btu/h) %
Equal to or under 7.2 (equal to or under 25) 2.1
Over 7.2 - 73.2 (25 - 250) 50.3
Over 73.2 (over 250) 47.6
The distribution of capacity by fuel for all water-tube
boilers (excerpted from Table 2-5) is:
Total capacity,
Fuel MW thermal (1Q6 Btu/h)
Natural gas 306,440 (1,045,900)
Residual oil 221,410 (755,700)
Coal 181,320 (618,600)
Distillate oil 38,760 (132,300)
Water-tube boilers account for only 27 percent of the over-
all capacity of commercial units; the balance comes from fire-
tube and cast iron boilers.
In summary, the industrial/commercial water-tube boiler
population has the following characteristics:
0 It represents the majority of total capacity.
0 It represents the fewest boilers.
The average boiler size is the largest of the
three types.
The majority of the total water-tube boiler capacity is
field-erected.
Most units are industrial rather than commercial.
26
-------
Table 2-6 presented the total estimated fire-tube capacity
by size and fuel. Only 11.8 percent of this capacity is provided
by boilers larger than 7.3 MW thermal (25 x 106 Btu/h).
Most fire-tube boilers have a capacity between 0.4 and 7.3
MW thermal (1.5 and 25 x 10 Btu/h). Water-tube units also
account for some capacity in the small size ranges; but for
boilers under 7.3 MW thermal (25 x 106 Btu/h), fire-tube units
represent five times as much capacity as water-tube boilers.
Thus boilers with different heat transfer configurations pre-
dominate in different size ranges.
Tables 2-10 and 2-11 presented the distribution of fire-tube
capacity between commercial and industrial boilers. Approxi-
mately 21 percent of the total commercial boiler capacity comes
from fire-tube units. Most fire-tube boilers, however, are used
by industry.
The total capacity of cast iron boilers was presented by
size and fuel in Table 2-7. All industrial/commercial units
below 0.1 MW thermal (0.4 x 10 Btu/h) are cast iron. Above this
size through 2.9 MW thermal (10 x 10 Btu/h), cast iron and fire-
tube boilers overlap considerably. No cast iron units are larger
than 2.9 MW thermal (10 x 106 Btu/h).
Tables 2-12 and 2-13 presented estimates of cast iron
boiler capacity in commercial and industrial applications. The
tables show that 80 percent of all cast iron boiler capacity are
used commercially. It should be noted that this ratio was based
on estimates by Walden and could not be verified independently in
this study. The same is true of the fire-tube and water-tube
boiler distributions discussed previously- In all cases, the
ratio of commercial to industrial capacity was assumed in this
study to be independent of fuel. This assumption may have intro-
duced errors in the industrial/commercial distribution but would
not significantly affect the overall size and fuel distributions.
The classification of total boiler population by type of
industry is an important parameter. Sales data from ABMA for
water-tube boilers sold during the period 1966 to 1977 are classi-
fied by the Standard Industrial Classification (SIC). Table 2-17
27
-------
TABLE 2-17. DISTRIBUTION BY SIC OF WATER-TUBE BOILERS
SOLD IN PERIOD 1965 THROUGH 1977
(1C
00
IS
20
22
24
2t
28
29
30
33
37
It
• s
72
10
12
Industry
Offices, chopping
centers. Milt
rood
Textile Bill*
Lumber and wood
products
Piper, allied
products
products
Rubber products
Primary Metal
Transportation
Miscellaneous
Manufacturing
Apertnenta
Boiltr rentals
Hospitals, Mdicel
centers, booes
school i and
universities
Fuel
Coal
Oil
Gas
Sub total
Oil
Cas
Eub total
Coal
Oil
Cat
Sub total
Coal
Oil
Ca>
Sub total
Coal
Oil
Gas
Sub total
Coal
Oil
Cat
Sub total
Oil
Cat
Sub total
Oil
Cas
Sub total
Oil
Gas
Sub total
Coal
Oil
Cai
Sub total
Coal
Oil
Cai
Sub total
Coal
Oil
Cas
Sub total
Cas
Sub total
Oil
Cai
Sub total
Coal
Oil
Cas
Bub total
Coal
Oil
Cas
Sub total
TOTAL
No. of boilers
26
J49
126
1,203
2
10
12
ie
140
496
656
15
124
266
405
3
33
37
73
14
126
114
254
48
305
530
193
2
143
213
358
53
104
157
9
36
110
155
26
56
133
217
29
311
436
«7t
11
11
is
71
IK
31
zee
Til
1,0*0
12
17«
MB
S74
4,840
C«p«ci ty
(10' »tu/M
412 (1,644)
1,824 (30,116!
12,194 (44,0061
22,200 (75,768)
234 (800)
293 (1,000)
521 (1,800)
1,116 (3,810)
2,771 (9,457)
9,344 (31 ,892)
13,232 (45,159)
533 (1,8201
1,912 (6,526)
3,942 113,453)
6,387 (21,799)
26 190)
585 (1,996)
593 (2,023)
1.204 (4,109)
1,393 (4,754)
1,911 (13,350)
3,999 113,647)
»,303 (31.751)
3,316 (11,318)
9,334 (31,856)
14,656 (50,019)
27,306 (93,193)
44 1150)
4,336 (21,625)
7,396 (25,243)
13.776 (47,018)
1,012 (3.453)
1,750 15,972)
2.762 (9,425)
158 (540)
1,044 (3,630)
3,097 (10,571)
«,319 (14,741)
1,272 (4.340)
1,469 (5,015)
2,940 (9,690
5,581 (19,049)
1,097 (3, 74 3)
«.«64 (15,919)
9,518 (32,464)
SS.379 (52,146)
1I« («40)
129 <440)
1,152 (3,933)
J.263 (7.725)
S,«16 111, (56)
237 (910)
9.151 (9,731)
7,3U (24,967)
10,404 (15,501)
(11 (3,006)
J.13t (10,704)
6,046 (20,704)
19,683 194,414)
K5,t06 1497,978)
by induit r y
15.2
0.4
9.1
4 . 4
0.6
6.4
18.7
9.4
1.9
3.0
3.6
>0. 5
Nil
2.3
7.1
6.9
99.9
28
-------
presents a tabulation of the ABMA sales data by fuel type and SIC
code. Boilers in the nonmanufacturing sector (i.e., commercial/
institutional) are denoted with a SIC code of zero.
As the data indicate, the chemical, petroleum refinery, and
food industries are the largest purchasers of new water-tube
boilers, and the chemical industry purchased twice the capacity of
the other two industries.
2.3 FUEL CONSUMPTION
The major fuels consumed by industrial and commercial
boilers are coal, residual oil, distillate oil, and natural gas.
Among the other fuels burned are wood wastes, liquified petroleum
gas, asphalt, and kerosene. Since the four major fuels con-
stitute the vast majority of all fuels burned (estimated at
greater than 90%), and since the use of other fuels is site-
specific and difficult to document, the consumption figures of
only the four major fuels were compiled and analyzed.
Figures for the consumption of fuel in industrial/commercial
boilers were derived from statistical reports compiled by the
Department of Energy. The procedure is fully described in
Appendix D.
The summary presenced in Table 2-18 shows that gas is the
most widely used boiler fuel, and that residual oil is burned in
industrial/commercial boilers in greater quantities than coal.
TABLE 2-18. ANNUAL FUEL CONSUMPTION BY INDUSTRIAL/
COMMERCIAL BOILERS
Fuel type
Gas
Residual oil
Distillate oil
Coal
Total
Total energy,
6,734.5
1,861.0
1,192.9
1,163.3
10,951.7
1015 J (1012 Btu)
(6,381.2)
(1,762.3)
(1,129.6)
(1,101.6)
(10,374.7)
29
-------
TABLE 2-19. ESTIMATED FUEL CONSUMPTION BY
INDUSTRIAL AND COMMERCIAL BOILERS, 1975
Consumption
Sector
Industrial
Coal
Residual oil
Distillate oil
Natural gas
Total
Commercial
Coal
Residual oil
Distillate oil
Natural gas
Total
Quantity
33,906 Gg
19,881 x 103 m3
7281 x 103 m3
112,237 x 106 m3
(39,374 x 103 tons)
(125,067 x 103 bbl)
(45,799 x 103 bbl)
(3,963,635 x 106 ft3)
4575 Gg
24,657 x 103 m3
23,521 x 103 m3
64,233 x 106 m3
(5,043 x 103 tons)
(155,103 x 103 bbl)
(147,959 x 103 bbl)
(2,268,128 x 106 ft3)
Heat content,
1015 Joules (1012 Btu)
1031.0 (976.5)
830.8 (786.7)
282.0 (267.0)
4282.3 (4058.8 )
6426.1 (.6089.0)
132.1 (125.1)
1030.2 (975.6)
910.9 (862.6)
2452.5 (2322.4)
4525.7 (4285.7)
OJ
o
-------
A further distribution into industrial and commercial sectors
shows that industrial boilers consume more fuel overall (a little
over 58 percent of the total) but that commercial boilers do con-
tribute substantially to total consumption, and that they use a
considerable amount of "dirty" fuel (i.e., coal and residual
oil). These data are presented in Table 2-19.
The figures for consumption of major fuels were subdivided
for industrial consumption into quantities used for generation of
electricity, process steam, and space heating. The distribution
was based upon end-use-fuel estimates obtained from the Depart-
ment of Energy survey of Major Fuel Burning Installations (MFBI),
(DOE, 1975). These end-use distributions were applied to the
total industrial fuel consumption figure, reported in the Mineral
Industry Surveys (Bureau of Mines, 1976 a, b, c) using the pro-
cedures described in Appendix D. The results are shown in Table
2-20.
TABLE 2-20. FUEL CONSUMPTION FOR INDUSTRIAL BOILERS
Fuel
Coal
Residual oil
Distillate oil
Natural gas
Total energy, 1015 J (1012 Btu)
Electric
generation
257.8 (244)
108.8 (102)
38.4 (36)
475.8 (451)
880.8 (833)
Process
steam
618.6 (586)
606.5 (574)
90.8 (86)
3330.6 (3157)
4646.5 (4403)
Space
heat
154.6 (147)
115.5 (111)
152.8 (145)
475.8 (451)
898.7 (854)
The MFBI data, however, are less than completely satis-
factory- Only boilers having a capacity over 29 MW (100 x 10
Btu/h) were included, and the number of boilers (3670) was
limited. All the boilers in this size range are water-tube
boilers, and the present study estimates that 5603 water-tube
boilers have a capacity greater than 29 MW (100 x 106 Btu/h).
Thus, the DOE survey accounted for only 65 percent of the estimated
31
-------
boiler population. In addition, the MFBI data contained obvious
errors that in validated some of the data and cast doubt on the
validity of the remaining information.
An attempt was made to verify the percent distributions for
each usage by comparing the MFBI based finding with those re-
ported by Stanford Research Institute (Stanford, 1970). The
basis for the Stanford study differed in that it combined indus-
trial process steam and space heat into one category, and that it
reported a total for petroleum products. Table 2-21 presents the
results of the comparison of the two different studies.
TABLE 2-21. COMPARISON OF FUEL AND USE ESTIMATES
Fuel
Coal
Oil
Natural
Gas
Study
Stanford study
Present study
Stanford study
Present study
Stanford study
Present study
Electric
generation
3.8%
26.8%
3.7%
13.4%
3.9%
11.1%
Process steam and
space heat
96.2%
71.2%
96.3%
86.6%
96.1%
88.9%
The fuel usage estimate for generation of electricity,
derived from MFBI data, is consistently higher than the usage
estimated by Stanford. The Stanford study does not state how the
distribution between electric generation and other industrial
uses was determined, but the similarity between values for dif-
ferent fuels suggests that a single factor was used for all
fuels.
Since the MFBI study focused on boilers over 29 MW (100 x
10 Btu/h), and it is this boiler capacity category that is
likely to account for almost all of the electricity generation by
industrial boilers, applying the MFBI fuel usage distribution to
the total industrial fuel consumption creates an unrealistically
high estimate for the percent of fuel being used to generate
electricity. Adjusting these values to reflect fuel consumption
by all types and sizes of industrial boilers should yield values
32
-------
between 10 and 15 percent of consumption of coal for the generation
of electricity and 5 to 10 percent of consumption for gas and
oil. No further attempt was made at reconciling the differences
between the MFBI generated and Stanford values. There are
insufficient data to permit calculation of fuel consumption by
size of boiler (needed to determine actual enduse-fuel distribu-
tion) , and further efforts to reconcile the values are not
justified in light of the limited utility of such findings.
The estimates of fuel consumption and capacity permitted the
computation of overall load factors. The results of this compu-
tation are shown in Table 2-22.
TABLE 2-22. ESTIMATED LOAD FACTORS FOR INDUSTRIAL
AND COMMERCIAL BOILERS BY FUEL
Industrial
fuel
Coal
Residual oil
Capacity,
MW thermal
(106 Btu/h)
181,601
248,464
Distillate oil 66,277
Gas
Commercial
fuel
Coal
Residual oil
433,406
57,926
110,783
Distillate oil 61,471
Gas
Total
169, 090
1, 329, 019
(619,800)
(848, 000)
(226,200)
(1,479,200)
(197,700)
(378,100)
(209,800)
(577,100)
(4, 535, 900)
Consum
ioi
(1012
1,031.2
830.8
282. 0
4,282. 0
132.1
1, 030.2
910.9
2,452.5
10,951.7
ption,
5 J
Btu)
(976.5)
(786.7)
(267.0)
(4,058.8)
(125.2)
(975.6)
(862. 6)
(2,322.4)
(10,374.7)
Calculated
load
factor
0.180
0.106
0.135
0.313
0. 072
0.295
0.469
0.459
0.261
The figures in some categories are low compared with previous
estimates, and the weighted average of 26.1 percent is lower than
the estimate of 35 percent from a previous boiler study (Ehrenfeld
et al., 1971). Estimates from Battelle (Putnam et al., 1974) are
in Table 2-23 with the comparable value from the present study.
33
-------
TABLE 2-23. COMPARISON OF BATTELLE AND PEDCO LOAD FACTORS
Estimated load factors by fuel
Pulverized coal and cyclone
Other coal fired
Residual oil
Distillate oil
Natural gas
Commercial
Battelle
0.424
0.305
0.245
0.206
0.318
PEDCo
0.072
0.295
0.469
0.459
Industrial
Battelle
0.524
0.426
0.368
0.330
0.518
PEDCo
0.180
0.106
0.135
0.313
The Battelle estimates were derived from data contained in
the EPA National Emissions Data System (NEDS). These data have
known limitations (e.g., New York State is not included), and
contain some errors. Battelle reported, for example, that for
some boilers the reported capacity and fuel consumption produced
a load factor greater than 1.0. Thus the Battelle load factors,
although generally considered as the best available, are not
based on complete data; differences with them do not necessarily
diminish the credibility of the data used to derive national
average load factors for this study.
Nevertheless the values derived in this study for industrial
units appear low. This is probably because of assumptions con-
cerning replacement rates. Based upon discussions with boiler
manufacturers, it was assumed that 27 percent of the sales of
water-tube and fire-tube boilers and 50 percent of the sales of
cast iron boilers were replacements. These assumptions directly
affect the total boiler capacity calculations (e.g., 27 percent
of the new capacity additions for water-tube boilers replace
existing units yielding a net increase in capacity of 73 percent
of the sales). Furthermore, the assumptions do not factor in
replacement of coal-fired units by new oil- and gas-fired capac-
ity (i.e., if a new oil- or gas-fired unit is purchased to re-
place a coal-fired unit, no corresponding reduction in the coal-
fired capacity was incorporated in the study). The sales data
34
-------
for water-tube and fire-tube boilers were obtained from ABMA for
1966 through 1975, and the data on cast iron boilers were obtained
from the Hydronics Institute for 1965 through 1975. Sales of
coal-fired boilers were quite low for the period covered; hence,
the assumed retirement rate was also low. The average boiler age
data presented in Table 2-24 suggest that the assumption led to
overestimates of existing coal-fired boilers, since the percent
of new capacity for coal-fired?units is much lower than for other
fuels.
On the other hand, the figures may indicate that a substan-
tial number of boilers are on standby. The relatively low load
factors for boilers firing residual oil may be explained in the
same manner, since sales of water-tube boilers (which are by far
the largest class) were low in relation to the total number of
water-tube boilers. The low load factor for boilers firing dis-
tillate oil in industrial service and the high load factor for
those in commercial service suggest that some assumptions made
about type of service may be invalid. The load factors for gas
are not unreasonable, except that the factor for industrial
service was expected to be higher than that for commercial
service. The use of interruptible gas by industrial concerns may
be a partial explanation, however, or the ratios presented by
Battelle and used in this study for industrial versus commercial
boilers (Putnam et al., 1974) may not be applicable to the pre-
sent population of boilers.
Additional work is required to resolve the replacement,
retirement, and standby issues in order to generate better esti-
mates of capacity; the required information could probably be
obtained most effectively by canvassing the boiler manufacturers
and contacting the ABMA.
Although considerable effort was expended in this study to
develop good estimates of capacity, the retirement and replace-
ment issue could not be pursued further within the existing study
constraints. Furthermore, the calculated load factors are not
used directly in other parts of the study since emission estimates
35
-------
TABLE 2-24. COMPARISON OF BOILERS BY AGE
Boiler type
Water-tube
Coal
Residual oil
Distillate oil
Natural gas
Fire-tube
Coal
Residual oil
Distillate oil
Natural gas
Cast iron
Coal
Residual oil
Distillate oil
Natural gas
All boilers
Coal
Residual oil
Distillate oil
Natural gas
Boiler capacity,
MW thermal (106 Btu/h)
Old
170,400
177,100
33,000
220,300
26,200
52,700
34,300
101,100
30,500
30,500
19,600
100,500
227,100
260,300
86,900
421,900
(581,600)
(604,400)
(112,500)
(752,000)
(89,400)
(179,800)
(117,200)
(345,100)
(104,200)
(104,100)
(66,800)
(343,000)
(775,200)
(888,300)
(296,500)
(1,440,100)
Newa
9,700
43,400
5,700
86,100
0
30,700
20,200
37,500
1,100
23,300
14,300
43,000
10,800
97,400
40,200
166,600
(33,100)
(148,100)
(19,400)
(293,800)
(0)
(104,800)
(69,000)
(127,900)
(3,600)
(79,500)
(48,700)
(146,800)
(36,700)
(332,300)
(137,100)
(568,500)
% New
5.4
19.7
14.7
28.1
0
36.8
37.1
27.0
3.3
43.3
42.2
30.0
4.5
27.2
31.6
28.3
New represents capacity added between the years 1967 and 1977
36
-------
are based on fuel consumption statistics, and further analysis of
trends of the past 10 years would not necessarily provide addi-
tional insight on current and future practice.
2.4 GROWTH PROJECTIONS FOR INDUSTRIAL/COMMERCIAL BOILER
POPULATION
The major factors affecting the future growth of the indus-
trial/commercial boiler population are the economic growth of the
Nation, technological advancements in energy production and use,
fuel use patterns, and energy and environmental regulatory
trends. Although the projections contained in this section are
based only on economic growth, the qualitative effect of the
other factors will be discussed.
In the industrialized states, State Implementation Plan
(SIP) requirements for fossil-fuel-fired boilers include regu-
lations governing emissions of particulate matter and sulfur
dioxide (SO2) from industrial boilers. A typical equation based
on the Illinois SIP for allowable particulate emissions is:
E = 5.18 Q-°'715
where E is allowable particulate emissions in lb/10 Btu
Q is heat input rate in 106 Btu/h.
The allowable particulate emission rate ranges from 430 to
43 ng/J (1.0 to 0.1 Ib/lO^ Btu) as the heat input varies from 2.3
to 73.25 MW thermal (10 to 250 x 106 Btu/h).
Regulations governing SO2 emissions vary for each type of
fuel. For coal firing, SO2 regulations vary from 86 to 2580 ng/J
(0.2 to 6.0 lb/106 Btu). For fuel oil firing, the regulations
(normally expressed as a limitation on the sulfur content in the
fuel) are equivalent to 86 to 344 ng/J (0.2 to 0.8 lb/106 Btu).
To date no Federal regulations have been promulgated for new
boiler installations under 73.3 MW thermal (250 x 106 Btu/h) heat
input, and manufacturers of industrial boilers have not yet had
to deal extensively with emission limitation problems. The
37
-------
relative distribution of boiler types (package versus field-
erected) could change dramatically, however, in response to
Federally mandated regulations.
In addition to being affected by environmental regulations,
new boilers with a heat input greater than 29.3 MW thermal (100 x
106 Btu/h) will be subject to the DOE coal conversion strategy
for new boilers. This DOE strategy seeks to restrict the use of
natural gas and oil by prohibiting the burning of fuels other
than coal, coal-derived liquids, and refuse-derived fuels without
prior DOE critical review and approval. Obviously, mandatory
coal firing will change the distribution of fuels fired in large
industrial boilers by the year 2000; however, near-term DOE
policies (i.e., up to 1980 or 1981) are emphasizing the burning
of more natural gas at the expense of oil.
Technological advancements such as fluidized-bed combustion
also may increase the coal usage as cleaner, more efficient,
firing processes are developed. New sources of energy and
advances in energy conservation also will influence boiler
growth rate and fuel usage patterns. The scope of this study,
however, does not address the quantitative effects of these
factors.
Because of the uncertainties, boiler manufacturers are
unwilling to predict growth trends in the industrial boiler
population. The Institute of Gas Technology (IGT) made some
projections in 1974 of economic growth and boiler fuel distri-
butions, however, and these were utilized to derive the results
presented in this section. It should be noted that projected
growth rate for the industrial boilers is based on growth in
energy consumption, assuming no shift in load factors; the growth
rate for commercial boilers is assumed to parallel that of indus-
trial boilers.
The IGT study (Fejer and Larson, 1974) considers the growth
of the five most energy-intensive industries in the United States
38
-------
Paper and allied products SIC 26
Chemical products SIC 28
Petroleum refining SIC 29
Mineral products SIC 32
Primary metals SIC 33
Based on 1971 production for these industries and assumptions
concerning anticipated future market demands, IGT projected the
production of these industries for 1975, 1980, and 1985. Using
the 1971 energy use for steam production per unit of output as a
base, IGT calculated the 1975, 1980, and 1985 energy use for each
of the industries except petroleum refining; energy usage in
petroleum refining is not easily related to production.
Table 2-25 presents projections of energy usage for pro-
ducing steam for the four key industries through 1985. These
projections were derived from the IGT data based on two important
assumptions:
0 The relative proportion of energy used for producing
steam will remain constant through the projection
period.
0 The amount of energy consumed per unit of production
will remain constant (i.e., new technologies with
different efficiencies are not considered).
A composite industrial annual growth rate of 3.3 percent was
derived from the data in Table 2-25 for the period 1975 through
1985, and this growth rate was assumed to continue from 1985 to
2000.
Based on the report by the Stanford Research Institute
(1972), the total energy used by the four key industries for
process steam accounted for approximately 82 percent of the total
process steam energy used by all industries in 1971. Furthermore,
it was assumed that total energy consumption for process steam by
the four key industries will continue to be 82 percent of the
total energy consumed industrywide for process steam. Therefore,
the growth rate of energy consumption for process steam by the
four key industries from 1971 to 1985 was assumed to be repre-
sentative of the growth rate of energy consumption for process
steam by all industries.
39
-------
TABLE 2-25. PROJECTED TOTAL ENERGY USAGE BY THE FOUR
MAJOR ENERGY-INTENSIVE INDUSTRIES
[1015 J (1012 Btu)]
Industry
Paper and allied
products
Chemical products
Mineral products
Primary metals
Total
1971a
1,284 (1,218)
3,969 (3,764)
724 (687)
4,074 (3,864)
10,051 (9,533)
1975
1,537 (1,459)
4,824 (4,575)
802 (761)
4,884 (4,632)
12,047 (11,426)
1980
1,766 (1,675)
587 (5,569)
879 (834)
5,894 (5,590)
14,411 (13,668)
1985
2,018 (1,914)
6,936 (6,484)
948 (899)
6,921 (6,564)
16,723 (15,861)
Actual reported energy usage.
-------
Given these assumptions, industrywide energy consumption for
process steam in the year 2000 can be calculated by dividing the
energy consumption for process steam by the four key industries
by 0.82.
The growth in energy use for production of steam of all
industries (presented in Figure 2-2) was calculated in this
manner.
The growth rate for capacity of industrial and commercial
boilers is assumed to equal the energy growth rate. Therefore,
the projected emissions shown later in Section 3.3 are based on
the application of the energy growth rate (i.e., 3.3% per year)
to the actual 1975 fuel consumption data derived in Section 2.3.
Table 2-26 presents a summary of the capacity of industrial and
commercial boilers in place in 1977 by fuel type. These totals
and the projected growth factor determined earlier form the basis
for calculating the total capacity of industrial/commercial
boilers for 1980, 1985, and 2000 (Table 2-27). The calculations
required the following additional assumptions:
0 The relationship between boiler capacities and total
energy consumed (i.e., the load factor) will remain
constant over the projected period.
0 The energy use projection factor of 1.033 can be
applied to total boiler capacity-
Data from other studies by Edison Electric Institute (1976)
and the Energy Information Administration (1977) can be used to
check the reasonableness of the 3.3 percent growth rate.
The well-researched book written by the Edison Electric
Institute (1976) analyzes the growth of energy use as it relates
to economic growth. Several scenarios were developed representing
interactions of nine separate elements: (1) population, (2)
agriculture, (3) growth of income and consumption, (4) minerals
demand and supply, (5) energy demand and supply, (6) conservation
and environment, (7) pricing policies, (8) capital requirements,
and (9) relations with the rest of the world. By varying some of
these elements, EEI formulated three scenarios of energy demand
41
-------
35,000
£ 25,000
o
o
m
~ is.ooof-
Q_
5,000
1970
1980 1990
YEAR (Y)
2000
Figure 2-2. Projected growth in energy use by boilers
through 2000.
42
-------
TABLE 2-26. TOTAL U.S. CAPACITY OF INDUSTRIAL/COMMERCIAL BOILERS
BY FUEL TYPE IN 1977
Fuel type
Stoker coal
Pulverized coal
Residual oil
Distillate oil
Natural gas
Total
1977 Capacity,
MW thermal (106 Btu/h)
178,450
(608,850)
60,690
(207,100)
358,570
(1,223,800)
127, 040
(433,700)
588,590
(2, 008,800)
1,313,340
(4,482,230)
% of
total
13.6
4.6
27.3
9.7
44.8
100
43
-------
TABLE 2-27. PROJECTED TOTAL CAPACITY OF U.S. INDUSTRIAL/COMMERCIAL
BOILERS BY FUEL TYPE
[MW thermal (1Q6 Btu/h)]
Fuel type
Stoker coal
Pulverized coal
Residual oil
Distillate oil
Natural gas
Total
Year
1980
195,192
(665,947)
66,383
(226,530)
392,210
(1,338,611)
138,959
(474,388)
643,809
(2,197,256)
1,436,553
(4,902,732)
1985
229,044
(781,446)
77,897
(265,817)
460,232
(1,570,772)
163,058
(556,663)
755,467
(2,578,335)
1,685,698
(5,753,033)
2000
373,236
(1,273,394)
126,936
(433,159)
749,964
(2,559,629)
265,709
(907,106)
1,231,061
(4,201,490)
2,746,906
(9,374,778)
-------
growth: Case A - high economic growth; Case B - moderate economic
growth; Case C - low (or no) economic growth. Case A is pre-
dicted to result in a 4.0 percent annual increase in U.S. energy .
demand by the industrial sector to the year 2000; Case B is
predicted to result in a 3 percent annual increase; and Case C is
predicted to result in only a 0.5 percent annual increase. The
EEI projections are for total energy demand by the economic
sector, whereas the projections prepared in this report represent
only energy used in the industrial sector for process steam
production (i.e., boilers). According to DOE (1978) information
on major fuel burning installations, process steam characteris-
tically represents about 70 percent of total energy use in the
industrial sector. Given this ratio, PEDCo adjusted the IGT pro-
jections for total steam energy demand to obtain an estimate of
projected total industrial energy demand on the assumption that
the rates remain constant. Table 2-28 presents the EEI (1976)
estimates and the adjusted IGT projections. The table shows that
the PEDCo and EEI predictions for the year 2000 differ by about
12 percent; most of this difference is attributable to the fact
that the EEI estimate of total energy demand by the industrial
sector in 1975 is 19 percent higher than the PEDCo estimate for
1975.
The study prepared for the Energy Information Administration
in 1978 contains estimates for six basic scenarios of six con-
ditions of energy supply and demand and are represented by the
matrix shown in Figure 2-3.
The EIA (1978) growth factors range from 3.8 to 4.6 percent
for the 1975 to 1985 period. To approximate most nearly the
estimates derived from the IGT work, Scenario E (3.8 percent
growth) was chosen from the EIA study. This most conservative
EIA estimate for growth assumes low demand and low supply con-
ditions. The 1985 to 1990 growth factor for Scenario E is 2.7
percent. If this factor is applied for the period 1985 to 2000,
the effective growth factor for the entire 25-year period (1975
to 2000) is 3.2 percent. As shown in Table 2-28, by the year
45
-------
TABLE 2-28.
INDUSTRIAL ENERGY DEMANDS FROM 1975 TO 2000
[1015 j (1012 Btu)]
1975
1980
1985
2000
Demand for
process steam
Four SIC's
12,047
(11,426)
14,411
(13,668)
16,723
(15,861)
28,840
(27,353)
Total
14,691
(13,934)
17,574
(16,668)
20,394
(19,343)
35,170
(33,357)
Total energy demand by industrial sector
PEDCo estimate,
adjusted from IGT
20,988
(19,906)
24,628
(23,359)
28,980
(27,487)
45,570
(43,220)
EEI estimate,
Case A
26,010
(24,669)
30,720
(29,136)
35,587
(33,753)
51,876
(49,202)
EIA estimate,
Case E
21,380
(20,278)
25,810
(24,480)
31,156
(29,550)a
46,989
(44,567)b
en
Assumed annual growth factor from 1975 to 1985 of 3.84%.
Assumed annual growth factor from 1985 to 2000 of 2.7%.
-------
Energy demand
Energy
Supply
High
Medium
Low
High
A
D
Medium
C
Low
B
E
Case F = High Import Prices
Figure 2-3. The EIA scenarios for energy demand projections
47
-------
2000 the projections based on EIA data are within 3 percent of
those derived from the IGT data.
Although this study does not take into account the changes
in fuel mix that may accompany boiler growth, the EIA (1978) and
EEI (1976) studies project changes in fuel patterns expected in
the United States over the next 25 years. The EIA report pro-
jects coal usage to increase at an annual rate of 1.9 to 4.6
percent between 1975 and 1985 and residual oil usage at an annual
rate of 6.7 to 8.8 percent. Natural gas consumption is predicted
to decrease by 0.3 percent for the same period. The EIA pro-
jections for the period 1985 to 1990 show natural gas usage
increasing 2.8 percent annually; coal, 0.9 percent; and residual
oil, 3.2 percent.
According to EEI (1976), the use of all fuels will increase
by about 3.5 to 4.5 percent between 1975 and 1985, except coal
usage, which will decrease. The period 1985 to 2000 shows
increases in the usage of all fuels, with electricity and synthetic
gas accounting for about 21.2 percent of the consumption in 2000.
Neither study (EEI, 1974; EIA, 1978) addresses the influence
that the DOE strategy for conversion to coal firing will have on
industrial fuel consumption over the next two decades. This and
other strategies to conserve the Nation's oil and natural gas
will undoubtedly change fuel-use distribution, especially between
1985 and 2000.
A more accurate and reliable prediction of the growth of
industrial boiler capacity than that provided in this study would
require a clearer definition of the extent of boiler emission
regulations and their enforcement, and the effects of a full-
scale coal-conversion strategy regarding new construction.
Extensive use of coal will undoubtedly place new burdens and
responsibilities on related coal mining and transportation
activities. Anticipated mining and delivery problems related to
coal supply and the effects of these problems on pricing must be
considered.
48
-------
Although the projected growth in total boiler capacity has
been determined, no firm data are available for estimating the
changes in the mix of boiler types that may occur.
To evaluate the capability of manufacturers to meet pro-
jected demand for boiler capacity, the average annual growth
rates in capacity were calculated from sales data. For the
period 1969 to 1975, the sales of water-tube boilers grew at an
average annual rate of 3.2 percent. Fire-tube boiler sales from
1966 through 1975 grew at an annual average rate of 2.4 percent.
The growth rate of cast iron boilers was calculated to be about
1.7 percent for the 1965 through 1975 period.
The 3.3 percent annual average growth rate would correspond
with the growth in fuel consumption, not necessarily with boiler
capacity. Comparison of the sales growth rates with the pro-
jected annual growth of 3.3 percent indicates that to meet this
demand would require greater utilization of existing boilers.
The previous assumption that load factors will remain constant is
not correct and, in fact, load factors must increase in the
future. The average load factor for existing boilers of 26.1
percent as calculated in Section 2.3 is very low, and it is not
unreasonable to expect greater utilization under conditions of
high demand. The low growth rate in cast iron boiler capacity
would indicate that the use of cast iron boilers will not grow at
the same rate as water-tube and fire-tube boilers, and therefore
the emissions as represented in Section 3.3 will be overstated
for cast iron boilers. The total emissions as presented are
correct, with water-tube and fire-tube boilers accounting for a
greater share.
The same uncertainties related to projecting fuel mix make
it equally difficult to project quantitative changes in the mix
of boiler types. Therefore the emission projections shown later
in Section 3.3 are based on the present mix of boiler types.
To provide comparative figures for other rates of economic
growth, emission projections for the EIA high growth case (4.6
percent annual growth rate) and for the EEI low growth case (0.5
49
-------
percent annual growth rate) are also given in Section 3.3. For
these two cases, the same assumptions are made regarding no
change in fuel mix or the distribution in boiler types through
the year 2000.
50
-------
REFERENCES FOR SECTION 2
Bureau of Mines. 1976a. Mineral Industry Survey: Bituminous
Coal and Lignite Distribution - 1975. U.S. Department of
Interior, Washington, D.C., April.
Bureau of Mines. 1976b. Mineral Industry Survey: Sale of Fuel
Oil and Kerosene in 1975. U.S. Department of Interior,
Washington, D.C., September.
Bureau of Mines. 1976c. Mineral Industry Survey: Natural Gas
Production and Consumption. U.S. Department of Interior,
Washington, D.C., October.
Edison Electric Institute. 1976. Economic Growth in the Future
- The Growth Debate in National and Global Perspective.
New York City.
Ehrenfeld, J.R., R.H. Bernstein, K. Carr, J.C. Goldish, R.G.
Orner, and J. Parks. 1971. Systematic Study of Air Pollu-
tion from Intermediate-size Fossil-fuel Combustion Equip-
ment, CPA 22-69-85. Walden Research Corporation, Cambridge,
Massachusetts.
Energy Information Administration. 1977. Projections of Energy
Supply and Demand and Their Impacts, Vol. II. Annual Report
to Congress. U.S. Department of Energy, Washington, D.C.
Fejer, M.E., and D.H. Larson. 1974. Study of Industrial Uses of
Energy Relative to Environmental Impacts. Institute of Gas
Technology, Chicago.
Locklin, D.W., H.H. Krause, A.A. Putman, E.L. Kropp, W.T. Reid,
and M.A. Duffy. 1974. Design Trends and Operating Problems
in Combustion Modification of Industrial Boilers. EPA
R-802402, Battelle-Columbus Laboratories, Columbus, Ohio.
Putman, A.A., E.L. Kropp, and R.E. Barrett. 1975. Evaluation of
National Boiler Inventory. EPA 68-02-1223, Battelle-
Columbus Laboratories, Columbus, Ohio.
Stanford Research Institute. 1972. Patterns of Energy Consumption
in the Jnited States. Washington, D.C.
51
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SECTION 3
ATMOSPHERIC EMISSIONS
The burning of fuel in boilers causes emissions of signifi-
cant quantities of particulate matter, sulfur dioxide (862)/ and
nitrogen oxides (NOX). Relatively minor amounts of carbon mon-
oxide (CO) , and hydrocarbons (HC) are also emitted. The following
sections deal with factors affecting the emission rates, the
estimated total quantity of each pollutant emitted from the 1975
boiler population, and projections of emissions through the year
2000.
3.1 EMISSION FACTORS
Exclusive use was made of the emission factors published in
EPA's "Compilation of Air Pollutant Emission Factors" (U.S. EPA,
1977), hereafter referred to as "AP-42 emission factors." These
factors represent averages of emissions test data. Depending
upon the confidence in the amount and validity of data used in
developing the emission factors, EPA has ranked each set of
emission factors. The factors for boilers have been assigned the
best ranking, indicating good confidence in the data. The fol-
lowing subsections describe variables that can affect the emis-
sions from an individual boiler.
3.1.1 Particulate Emissions
Ranges of Particulate Emission Factors--
Tables 3-1 through 3-3 present the AP-42 particulate emis-
sion factors for industrial and commercial/institutional boilers
by fuel. The emission factors for coal are listed by firing
mechanism for various types and sizes of boilers. The factors
are expressed in kilograms of particulate matter emitted per
52
-------
TABLE 3-1. UNCONTROLLED PARTICULATE EMISSION FACTORS FOR
VARIOUS COAL-FIRED BOILERS3
Boiler
input capacity,
t MW thermal
(106 Btu/h)
>29. 3 (>100)
2.9 - 29.3
(10 - 100)
< 2. 9 ( < 10)
Emission factor, g/kg coal burned (Ib/ton coal burned)
Pulverized
Wet bottom
6.5b
(13b)
c
c
Dry bottom
8 5b
(17b)
c
c
Other
(16b)
c
c
Stoker
Spreader
c
6.5b
(13b)
c
Underfeed
c
c
lb
(2b)
Other
c
2.5b
c
•J\
U.S. EPA, 1977.
The weight percentage of ash in the coal should be multiplied by the
factor given.
No emission factor given in AP-42.
-------
TABLE 3-2.
UNCONTROLLED PARTICULATE EMISSION FACTORS FOR
VARIOUS OIL-FIRED BOILERS3
Diler input capacity,
MW thermal
(106 Btu/h)
.7 - 63
L5 - 250)
J - 3.7
).5 - 15)
Emission factor,
kg/10 liters oil burned
(lb/103 gal oil burned)
Residual oil
1.25 (S)b + 0.38
[ 10 (S) + 3]
c
Distillate oil
c
0.25
(2)
U.S. EPA, 1977.
S is the sulfur content of the fuel in percentage.
No emission factor given in AP-42.
54
-------
TABLE 3-3. UNCONTROLLED PARTICULATE EMISSION FACTORS FOR
VARIOUS NATURAL GAS-FIRED BOILERS3
Boiler input capacity,
MW thermal
(106 Btu/h)
All
Emission factor, kg/10 m
(lb/106 ft3
Industrial
80 - 240
(5 - 15)
Domestic
80
(5
gas burned
gas burned)
and commercial
- 240
- 15)
U.S. EPA, 1977.
-------
kilogram of ash in the coal; therefore, given a specific coal
heating value and percent ash content, it is possible to calcu-
late the uncontrolled particulate emissions for a specific size
and type of industrial boiler.
Particulate emission factors for the firing of residual oil
are given by capacity ranges versus boiler firing mechanism. The
emissions generated by residual oil firing are correlated with
the sulfur content of the oil and are expressed as a function of
sulfur content.
Particulate emission factors for the firing of distillate
oil are also given by capacity ranges versus boiler firing
mechanism. Because the emissions generated by distillate oil
firing do not necessarily correlate with the ash content of the
oil, emission factors are expressed simply as kilograms of par-
ticulate matter per joule fired (pounds particulate per million
Btu fired). The emission factors for industrial boilers firing
natural gas are also given in this manner.
Factors Influencing Particulate Emissions--
Coal—-Particulate emissions from coal-fired boilers may con-
sist of unburned carbon, condensable tars, and fly ash. The
first two relate to the volatile content of the coal, whereas the
last depends on the ash content.
Generally, pulverized-coal-fired units produce more par-
ticulate matter than coal-fired stokers, which in turn produce
more than coal-fired cyclone boilers. Because coal is blown into
a pulverized-coal unit, combustion occurs while the coal particles
are in suspension. As it burns, the particle becomes smaller and
thus is more likely to be exhausted with the flue gas. Because
coal is placed on a bed in a stoker furnace, particles are less
likely to be exhausted with the flue gas. Emissions of partic-
ulate matter are lowest from a cyclone furnace because most of
the fly ash is collected on the walls of the boiler, which are
coated with molten slag (Cato et al., 1974).
56
-------
Low loads can cause emission problems in pulverized-coal-
fired units. Lower furnace temperatures cause poor combustion,
which leads to high emissions of particulate matter containing
unburned carbon. Conversely, efficient combustion reduces the
unburned carbon portion of particulate emissions. Complete com-
bustion requires adequate oxygen, complete mixing, and a tempera-
ture above the ignition point of the fuel.
Oil—Distillate and residual oil are the primary types of
fuel oil fired in industrial boilers. Distillate oil is normally
fired in smaller units, and residual oil in the larger, more
complicated, industrial units.
Fuel oil properties such as API gravity, carbon residue, ash
content, viscosity, and volatility are important in determining
particulate emissions from oil-fired units; these properties
influence atomization and vaporization, which contribute to prop-
er combustion.
Proper oil atomization is necessary to achieve complete,
smoke-free combustion of oil. The quantity of emitted particu-
late matter is directly dependent on the size of the oil drop-
lets, which is a function of burner type or atomization method.
Incomplete vaporization of large oil droplets contributes to
particulate emissions.
The current AP-42 particulate emission factor for firing of
No. 6 residual oil is based on sulfur content. The theory re-
flected is that the sulfur level of the oil affects SO., adsorp-
tion; thus, greater particulate formation occurs with higher
sulfur oils.
Particulate emissions from residual oil firing decrease as
boiler size in reases, probably because of better combustion
control and an increased level of maintenance. The size-emission
relationship is not so pronounced with distillate-oil-fired
units; burner type appears to be the predominant design parameter
affecting particulate emissions from these boilers (Offen et al.,
1976).
57
-------
Operating parameters affecting participate emissions are
boiler load, cycling, and maintenance. According to AP-42, for
units firing No. 6 residual oil, particulate matter emissions per
unit of fuel burned are lower when operating at reduced load.
The effect of load reduction in distillate-oil-fired units is not
as great.
Oil-fired boilers and furnaces used for space heating are
often operated cyclically, i.e., with on-off cycling. This type
of operation results in high particulate emission levels at
startup because cold combustion chamber walls cause incomplete
combustion.
Operating at high temperature and high oxygen levels may
reduce particulate emissions, but it will increase NO emissions.
2\.
Some balanced or optimized level of operation may be necessary
(-Offen et al. , 1976) .
Gas—Coke particles or soot, which result from incomplete
combustion, are rarely a problem in gas-fired units (Cato et al.,
1974) .
3.1.2 Sulfur Oxides Emissions
Emissions of sulfur oxides (SO ) are predominantly in the
X
form of sulfur dioxide (S02) , although sulfur trioxide (SO.,) can
also be emitted. The emissions are often reported as SO to
X
encompass both pollutants, even though the SO-, may constitute
only 1 or 2 percent of the total (U.S. EPA, 1977). SO emissions
X
are highly dependent on the sulfur content of the fuel. Thus,
firing of fuels with low sulfur content reduces the quantity of
SO^ emissions at a given firing rate. Boiler type, firing
mechanism, and mode of operation have little, if any, effect on
SO emissions.
X
Ranges of SO Emission Factors--
J\.
Tables 3-4 and 3-5 present SO emission factors from AP-42
J\.
for firing of coal, residual oil, and distillate oil in various
boiler sizes. Because natural-gas-fired units generate negligible
amounts of S0x/ data on emissions from these boilers, given in
58
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TABLE 3-4. UNCONTROLLED SO2 EMISSION FACTORS FOR VARIOUS
COAL-FIRED BOILERS
Boiler
input capacity,
MW therraal
(106 Btu/h)
>29.3 (> 100)
2.9 - 29.3
(10 - 100)
22.9 ( < 10)
Emission factor, g/kg coal burned
(Ib/ton coal burned)
Pulverized
Wet bottom
19Sb
(38S)
c
c
Dry bottom
19S
(38S)
c
c
Other
19S
(38S)
c
c
Stoker
Spreader
c
19S
(38S)
c
Underfeed
c
c
19S
(38S)
Other
c
c
c
U.S. EPA, 1977.
S is the sulfur content of the fuel in percentage.
No emission factor given in AP-42.
-------
TABLE 3-5.
UNCONTROLLED SOX EMISSION FACTORS FOR
VARIOUS OIL-FIRED BOILERS3
Boiler input capacity,
MW thermal
(106 Btu/h)
3.7 - 63
(15 - 250)
0.13 - 3.7
(0.5 - 15)
Emission factor,
kg/lO^ liters oil burned
(lb/103 gal oil burned)
Industrial and commercial
Residual
19.25Sb
(159S)
c
Distillate
c
17.25Sb
(144S)
U.S. EPA, 1977.
S is the sulfur content of the fuel in percentage.
No emission factor given in AP-42.
60
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Table 3-6, are very limited. The SO emission factors in Table
X
3-4 are given as a function of coal-firing mechanism, and those
in Table 3-5 as a function of types of oil. Although the data
show that SO emissions depend almost entirely upon the sulfur
X
content of the fuel, other considerations also may affect the
total SO emissions from coal-fired units.
X
Factors Influencing SO Emissions--
X
Coal—According to AP-42, 5 percent of the sulfur available
in coal is emitted with particulate matter or enters the bottom
ash or slag. Because particulate emissions and ash formation
depend on the firing mechanism, the SO emissions would also
X
depend on the firing mechanism. Such effects are believed to be
minor.
It is also postulated that SO emissions are affected by the
form in which the sulfur occurs in the coal as well as the
alkalinity of the ash. High-sulfur coals may contain inorganic
sulfate, which contributes to the total sulfur content of the
fuel but is not converted to SO gas. This inorganic sulfate
X
could, however, add to particulate emissions (Cato et al., 1974).
Highly alkaline ash can react with SO and cause a small amount
to be removed with the fly ash.
Oil--The SO emissions from oil-fired units, like those from
—~- - J\
coal-fired units, are chiefly dependent on sulfur content.
According to AP-42, the boiler size, grade of fuel oil, and
burner design/atomization method do not affect SO emissions.
X
Natural Gas—Because natural gas contains no sulfur, there
should be no SO emissions. As stated in AP-42, however, the
X
chemicals that are added to natural gas for detection purposes do
contain sulfur. Thus, small amounts of SO are emitted from
JC
natural-gas-fired units.
3.1.3 Nj-trogen Oxides^ Emissions
Much recent research has focused on emissions of NO from
J*i.
boilers. Nitrogen oxides are mainly nitric oxide (NO) and
61
-------
TABLE 3-6. UNCONTROLLED S02 EMISSION FACTORS FOR
VARIOUS NATURAL-GAS-FIRED BOILERS3
Boiler input capacity,
MW thermal
(106 Btu/h)
All
Emission factor,
kg/106 m3 gas burned,
(lb/106 ft3 burned)
Industrial
9.6
(0.6)
Domestic
and commercial
9. 6
(0.6)
U.S. EPA, 1977.
62
-------
nitrogen dioxide (NO,). Of a total NO measurement, more than 90
^ X
percent is usually NO; when it is emitted to the atmosphere, most
NO eventually becomes N0?.
Two mechanisms contribute to NO emissions. Atmospheric
X
nitrogen in the combustion air combines with oxygen at the high
flame temperatures attained in boilers. Nitrogen oxides produced
by this mechanism are called thermal NO . The portion of the
X
total NO that is formed from the nitrogen in the fuel is called
X
fuel NO .
x
Ranges of NO Emission Factors--
J\.
Tables 3-7 through 3-9 show NO emission factors for firing
of boilers with coal, oil, and natural gas. The data are pre-
sented by boiler capacity ranges versus firing mechanisms.
Factors Inf luenci.' ~ NO Emissions--
X
Formation of fuel NO is affected primarily by the nitrogen
J\.
content of the fuel and the availability of oxygen. Burning
mechanisms also indirectly influence the formation of fuel NO .
JC
Formation of thermal NO is influenced by operating parameters,
X
e.g., flame temperature, firing rate, and excess air.
The highest emissions of NO are from coal-fired boilers,
X
apparently because of the nitrogen content of the fuel. With few
exceptions, fuel NO is also the major contributor to total NO
X ^C
emissions from residual-oil-fired boilers. Fuel NO plays only
J\.
a minor role in emissions from units fired by distillate oil and
natural gas because the nitrogen content of these fuels is low.
Formation of thermal NO depends chiefly on temperature and
X
oxygen concentration. These depend, in turn, upon such items as
combustion air temperature, flue gas rt rculation, heat release
rate, excess air, and the air-to-fuel ratxo. The effects of
these elements are fairly consistent with all types of boilers
and fuels.
Heating the combustion air increases flame temperature and
enhances formation of thermal NO . Flue gas recirculation has
x ^
the opposite effect.
63
-------
TABLE 3-7. UNCONTROLLED NOX EMISSION FACTORS
FOR VARIOUS COAL-FIRED BOILERS3
Boiler
input capacity,
MW thermal
(106 Btu/h)
> 29.3 (> 100)
2.9 - 29.3
(10 - 100)
< 2.9 ( < 10)
Emission factor, g/kg coal burned (Ib/ton coal burned) a
Pulverized
Wet bottom
9
(18)
b
b
Dry bottom
15
(30)
b
b
Other
9
(18)
b
b
Stoker
Spreader
b-
7.5
(15)
b
Underfeed
b
b
3
(6)
Other
b
b
01
U.S. EPA, 1977.
No emission factor given in AP-42.
-------
TABLE 3-8. UNCONTROLLED NOX EMISSION FACTORS
FOR VARIOUS OIL-FIRED BOILERS3
Boiler
(106
3.7 -
(15 -
0.13 -
(0.5 -
input capacity,
MW thermal
Btu/h)
63
250)
3.7
15)
Emission factor, kg/10 liters oil
(lb/103 gal oil
burned
burned)
Industrial and commercial
Residual
7.5
(60)
b
Distillate
b
2.8
(22)
U.S. EPA, 1977.
No emission factor given in AP-42.
65
-------
TABLE 3-9. UNCONTROLLED NOX EMISSION FACTORS FOR
VARIOUS NATURAL GAS-FIRED BOILERS3
Boiler input capacity,
MW thermal
(106 Btu/h)
Emission factor, kg/10 m gas burned
(lb/106 ft3 gas burned)
Industrial
Commercial
< 29.3
( < 100)
> 29.3
(> 100)
1920 - 3680
(120 - 230)
11,200
(700)
1920
(120)
b
U.S. EPA, 1977.
No emission factor given in AP-42.
66
-------
Excess air seemingly plays a dual role in generation of
thermal NO . Although excess air should reduce flame temperature
and thus reduce the formation of thermal NO , it simultaneously
provides additional oxygen, which enhances NO formation. In-
creasing the oxygen concentration appears to be the dominating
mechanism, because increasing the excess air increases NO
.X.
emissions (Barrett et al., 1972).
3.1.4 Carbon Monoxide Emissions
The rate of carbon monoxide (CO) emissions from boilers is
dependent upon the efficiency of the combustion of the fuel.
Ranges of Carbon Monoxide Emission Factors--
The emission factors for uncontrolled carbon monoxide from
boilers firing coal, oil, and natural gas (expressed per unit of
fuel burned) are presented below:
Emission factors (EPA, 1977)
Coal-fired boilers,
Pulverized coal
Spreader stoker
Underfeed stoker
Other stoker
Oil-fired boilers,
Residual oil
Distillate oil
Natural-gas-fired boilers,
Industrial
Commercial
g/kg
0.5
1.0
5. 0
5.0
(Ib/ton)
(1)
(2)
(10)
(10)
kg/106 liters (lb/1000 gal)
0.63 (5)
0.63 (5)
kg/106 m3 (lb/106 ft3)
272 (17)
320 (20)
Factors Influencing CO Emissions--
Efficiency of combustion and boiler maintenance have a major
influence on CO emissions. Because proper combustion will lower
emission levels, the unit should be operated with a careful
control of excess air rates, use of high combustion temperatures,
and provision for intimate air-fuel contact.
Small boilers are often left unattended and are poorly
maintained. Improper operation and on/off cycling of smaller
boilers can increase CO emissions by several orders of magnitude.
67
-------
During the off cycle, the CO emissions increase drastically as
the amount of excess air is decreased (Grammer et al., 1976).
These problems are not usually encountered on larger units,
because they are continuously operated and well maintained.
3.1.5 Hydrocarbon Emissions
The rate of hydrocarbon (HC) emissions from boilers is
dependent upon the efficiency of the combustion of the fuel.
Hydrocarbon emissions are minimal when proper combustion prac-
tices are used.
Ranges of Hydrocarbon Emission Factors--
The emission factors for uncontrolled hydrocarbons from
boilers firing coal, oil, and natural gas (expressed per unit of
fuel burned) are presented below:
Emission factors (EPA, 1977)
Coal-fired boilers, 9/kg (Ib/ton)
Pulverized coal 0.15 (0.3)
Spreader stoker 0.5 (1)
Underfeed stoker 1.5 (3)
Other stoker 1.5 (3)
Oil-fired boilers, kg/103 liters (lb/1000 gal)
Residual oil 0.12 (1)
Distillate oil 0.12 (1)
Natural-gas-fired boilers, kg/106 m3 (lb/106 ft3)
Industrial 48 (3)
Commercial 128 (8)
Factors Influencing HC Emissions—
The emission of unburned combustibles, such as hydrocarbons,
is influenced by the efficiency of combustion and the condition
of the boiler. Careful control of excess air rates, use of high
combustion temperatures, and provision of intimate fuel-air
contacts (high turbulence) will minimize HC emissions.
Emissions from a particular boiler will also be affected by
fuel changes. For example, a liquid or gaseous fuel may have
better mixing and firing characteristics than a solid fuel. The
68
-------
substitution of oil or natural gas for coal should, therefore,
reduce HC emissions.
3.2 CURRENT LEVELS OF UNCONTROLLED EMISSIONS
Estimates of the total quantities of particulate matter,
S0~ , NO , CO, and HC emitted by the industrial/commercial boiler
^ X
population are based on the estimated quantity of fuel burned by
each segment of the population, an average analysis of these
fuels, and the emission factors presented in the preceding
section. Details of the emissions calculations for each pollu-
tant are presented in Appendix F.
The estimated fuel consumption figures presented in Section
2.3 are for the entire boiler population, and actual fuel con-
sumption by boiler type (i.e., water-tube versus fire-tube) is
not known. For purposes of estimating emissions, fuel consump-
tion is assumed to be proportional to total capacity within a
given boiler type. The estimated fuel consumption for each
boiler type, proportioned by capacity, is shown in Table 3-10,
and these values are used throughout this section for calculation
of emissions.
3.2.1 Particulate Emissions
Particulate emissions from coal-fired boilers are correlated
with the ash content of the coal. To estimate emissions, average
ash content of coal in the United States was calculated by
weighting the average ash content of the coal consumed in each
state by the quantity of coal consumed by boilers in that state.
Ash content values were obtained from data published by the
Federal Power Commission (FPC, 1976) .
Particulate emissions from residual-oil-fired boilers are
correlated with the sulfur content of the oil. The average
sulfur content of residual oil in the United States was calcu-
lated by weighting the average sulfur content of residual oil
consumed in each state by the quantity of residual oil consumed
69
-------
TABLE 3-10. ESTIMATED DISTRIBUTION OF FUEL CONSUMPTION BY BOILER TYPE FOR 1975
Boiler type
Water-tube
Fire-tube
Cast iron
Consumption by fuel/firing
Pulverized
coal ,
Gg/yr
(10J tons/yr)
10,193
(11,236)
0
0
Spreader-
stoker coal,
Gg/yr
(103 tons/yr)
7,979
(8,795)
444
(489)
161
(178)
Underfeed-
stoker coal,
Gg/yr
(10J tons/yr)
9,388
(10,349)
3,304
(3,642)
4,513
(4,975)
Other
stoker coal ,
Gg/yr
(10J tons/yr)
3,022
(3,331)
645
(711)
645
(711)
Residual
oil,
m3/yr
(103 bbl/yr)
658
(173,706)
244
(64,439)
159
(42,025)
Distillate
oil,
m3/yr
(103 bbl/yr)
227
(60,066)
315
(83,316)
191
(50,376)
Natural
gas
m-yyr
(106 ft3/yr)
E5,977
(3,036,153)
40,235
(1,420,618)
50,259
(1,774,992)
-------
by boilers in that state. The values for sulfur content were
obtained from data published by DOE (1977) .
Particulate emissions from distillate oil and natural gas
are correlated only with the quantity of fuel burned; fuel
analyses are not needed.
Total estimated particulate emissions from the industrial/
commercial boiler population (presented in Table 3-11) were
calculated by applying the appropriate emission factor to the
total quantity of fuel consumed in each category.
An estimated 2.5 Tg (2.8 x 10 tons) of uncontrolled partic-
ulate matter were emitted by boilers in 1975. Almost all of
this was attributable to coal firing with about half being
associated with pulverized coal and half associated with stoker
coal. The average control efficiency is estimated to be 56
percent, resulting in a controlled emission amount of 1.1 Tg.
Total nationwide particulate emissions in 1975 were estimated to
be 14.4 Tg (EPA, 1976), thus industrial/commercial fuel consump-
tion accounts for approximately 8 percent of nationwide total
suspended particulate emissions.
3.2.2 SO Emissions
X.
Sulfur oxides emissions are dependent upon the quantity of
fuel consumed (Table 3-10) and the sulfur content of the fuel.
Therefore, it was necessary to obtain an average sulfur content
for each fuel type except natural gas. The average sulfur
content of coal in the United States was calculated by weighting
the average sulfur content of coal consumed in each state by the
quantity of coal consumed by boilers in that state. The values
for sulfur content were obtained from data published by the FPC
(1976). The same procedure and data source were used to develop
an average sulfur value for distillate oil as were described in
Section 3.2.1 for residual oil.
The total SO emissions were calculated by using the appro-
J\.
priate emission factor from Section 3.1.2, the average sulfur
content of the fuel, and "the quantity of fuel listed in Table
3-10.
71
-------
TABLE 3-11. ESTIMATED UNCONTROLLED EMISSIONS OF PARTICULATE MATTER
FROM THE INDUSTRIAL/COMMERCIAL BOILER POPULATION FOR 1975
NJ
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Estimated emissions by fuel, Mg/yr (tons/yr)
Pulverized
coal
1 ,092,300
(1,204,000)
0
0
1,092,300
(1,204,000)
Stoker
coal
1,084,100
(1,195,000)
104,300
(115,000)
96, 200
(106,000)
1,284,600
(1,416,000)
Residual
oil
59,900
(66,000)
22,200
(24,500)
14,500
(16,000)
96,600
(106,500)
Distillate
oil
2,300
(2,500)
3,200
(3,500)
1,900
(2,100)
7,400
(8,100)
Natural
gas
13,800
(15,200)
6,400
(7,100)
8,000
(8,900)
28,200
(31,200)
Total
2,252,400
(2,482,700)
136,100
(150,100)
120,700
(133,000)
2,509,200
(2,765,800)
-------
The estimates for sulfur oxide emissions are shown on Table
3-12. Most of the 2.9 Tg of emissions estimated for 1975,
accounting for 12 percent of the nationwide total, is divided
about equally between coal and residual-oil-fired boilers. Less
than 15 percent is discharged from pulverized-coal burning
boilers, which are all in the size categories of 29.3 to 73.3 MW
thermal (100 to 250 x 10 Btu/h) and larger. About 25 percent of
the total is from stoker coal-fired boilers. The residual-oil-
fired water-tube boilers are the largest single source of SO
2\,
among all the boiler capacities. For this category, over 90 per-
cent of the total capacity is represented by boilers over 7.3 MW
thermal (22 x 10 Btu/h) and over two-thirds are between 7.3 MW
thermal (25 x 106 Btu/h) and 29.3 MW thermal (250 x 106 Btu/h).
It thus appears that SO comes mainly from small industrial and
X
commercial boilers likely to discharge pollutants at low levels,
and thus having the potential for significantly contributing to
high ambient SO,., levels.
3.2.3 NO Emissions
—x
The NO emissions factors from AP-42 (EPA, 1977) can be
X
applied without fuel analyses. Therefore, total NO emissions
^C
were calculated by applying the emission factors from Section
3.1.3 to the fuel consumption listed in Table 3-10. Results of
the calculations are presented in Table 3-13. The estimated
emissions of NO are about 1.8 Tg. This is significantly lower
JC
than the U.S. Environmental Protection Agency estimate of 4.5 Tg
for NO from industrial boilers (EPA, 1976). The exact origin of
2*C
the EPA estimate is not known.
3.2.4 CO Emissions
Carbon monoxide emissions are dependent upon boiler config-
uration and fuel consumption rather than fuel analysis. Total CO
emissions were calculated by applying the emission factors from
Section 3.1.4 to the quantity of fuel consumed by the approximate
boiler type as presented in Table 3-10. Results of the calculations
73
-------
TABLE 3-12. ESTIMATED UNCONTROLLED EMISSIONS OF SOX
FROM. THE INDUSTRIAL/COMMERCIAL BOILER POPULATION FOR 1975
-j
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Estimated emissions by fuel, Mg/yr (tons/yr)
Pulverized
coal
387,000
(427,000)
0
0
387,000
(427,000)
Stoker
coal
775,000
(854,000)
167,000
(184,000)
202,300
(223,000)
1,144, 300
(1, 261,000)
Residual
oil
794 ,500
(875,800)
294,700
(324,900)
192,200
(211,900)
1,281,400
(1,412,600)
Distillate
oil
38,700
(42,700)
53,700
(59,200)
32,500
(35,800)
124,900
(137,700)
Natural
gas
800
(900)
400
(400)
500
(500)
1,700
(1,800)
Total
1,996, 000
(2,200,400)
515,800
(568,500)
427,500
(471,200)
2,939,300
(3,240,100)
-------
TABLE 3-13. ESTIMATED UNCONTROLLED EMISSIONS OF NOX
FROM THE INDUSTRIAL/COMMERCIAL BOILER POPULATION FOR 1975
Ln
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Estimated emissions by fuel, Mg/yr (tons/yr)
Pulverized
coal
91,600
(101,000)
0
0
91,600
(101,000)
Stoker
coal
110,700
(122,000)
19,100
(21,000)
19,100
(21,000)
148, 900
(164,000)
Residual
oil
198,600
(218,900)
73,700
(81,200)
48,000
(53,000)
320,300
(353,100)
Distillate
oil
25,200
(27 ,800)
34,900
(38,500)
21,100
(23,300)
81,200
(89,600)
Natural
gas
962,900
(1,062,700)
112,700
(124,300)
105,300
(116,300)
1,180,900
(l.,303,300)
Total
1, 389,000
(1,532,400)
240,400
(265, OCC)
193,500
(213,600)
1,822,900
(2,011,000)
-------
are presented in Table 3-14". About half the total CO emissions
arise from water-tube boilers. Total CO emissions, amounting to
0.2 Tg/yr, are insignificant compared to particulate matter and
SOX emissions, and were less significant when compared with the
total nationwide CO emission estimate of 85.9 Tg/yr (EPA, 1976).
3.2.5 HC Emissions
Hydrocarbon emissions, like CO emissions, are dependent only
on boiler configuration and fuel consumption. Total HC emissions
were calculated by applying the emission factors from Section
3.1.5 to the quantity of fuel consumed by the approximate boiler
type as presented in Table 3-10. Results of the calculation are
presented in Table 3-15. Total HC emissions from boilers are
insignificant, contributing only 0.06 Tg/yr out of a nationwide
total of 26.2 Tg/yr.
3.3 EMISSION PROJECTIONS TO 2000
Based on the 1975 uncontrolled emission levels determined in
Section 3.2, projected emissions from industrial and commercial
boilers can be calculated by using the growth rate for these
boilers as presented in Section 2.4. The weighted average annual
growth rate was determined to be 3.3 percent. Projections are
presented in this section for each type of boiler for particu-
late, SOX, and NOX emissions. Hydrocarbon and carbon monoxide
emissions were not projected because of their insignificant
contribution to nationwide totals.
3.3.1 Particulate Emissions
Figure 3-1 shows projected, uncontrolled emissions of par-
ticulate matter from water-tube, fire-tube, and cast iron boilers
for the period 1975 to 2000 with a 3.3 percent growth rate in
fuel consumption. Total particulate emissions are sensitive to
the relative quantity and ash content of coal used compared with
oil and natural gas. The probable increase in coal consumption
76
-------
TABLE 3-14= ESTIMATED UNCONTROLLED EMISSIONS OF CO
FROM THE INDUSTRIAL/COMMERCIAL BOILER POPULATION FOR 1975
-j
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Estimated emissions by fuel, Mg/yr (tons/yr)
Pulverized
coal
5,100
(5,600)
0
0
5,100
(5,600)
Stoker
coal
57,900
(63,800)
18, 400
(20,300)
23,400
(25,800)
99,700
(109, 900)
Residual
oil
16,500
(18,200)
6,100
(6,800)
4,000
(4,400)
26,600
(29,400)
Distillate
oil
5,700
(6,300)
7,900
(8,700)
4,800
(5,300)
18,400
(20,300)
Natural
gas
24,100
(27,300)
12,100
(13,400)
16,100
(17,700)
52,300
(58,400)
Total
109,300
(121,200)
44,500
(49,200)
48,300
(53,200)
202,100
(223,600)
-------
TABLE 3-15. ESTIMATED UNCONTROLLED EMISSIONS OF EC
FROM THE INDUSTRIAL/COMMERCIAL BOILER POPULATION FOR 1975
CO
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Estimated emissions by fuel, Mg/yr (tons/yr)
Pulverized
coal
1,500
(1,700)
0
0
1,500
(1,700)
Stoker
coal
19,600
(21,600)
5, 700
(6, 300)
7,500
(8, 300)
32,800
(37,200)
Residual
oil
3,300
(3,600)
1,200
(1,400)
800
(900)
5,300
(5,900)
Distillate
oil
1,100
(1,300)
1,600
(1,800)
1,000
(1,100)
3,700
(4,200)
Natural
gas
5,400
(6,000)
3,500
(3,900)
6,400
(7,100)
15,300
(17,000)
Total
30,900
(34,200)
12,000
(13,400)
15,700
(17,400)
58,600
(66,000)
-------
8.0 x 106
7.5 x TO6
7.0 x 1O6 -
6.5 x 106
6.0 x 106
5.5 x 106
5.0 x 106
c-
£ 4.5 x 106
o
(/•>
""> K
£ 4.0 x 10b
UJ
,3.5 x 106
3.0 x 106
2.5 x TO6
2.0 x 106
1.5 x 106
1.0 x 106
5 x 105
1 x 105
1975
1980
1985 1990
YEAR
1995
2000
jure 3-1. Projected total uncontrolled particulate matter
emissions from the industrial/commercial boiler
population through 2000.
79
-------
as a result of coal conversion strategies is not reflected in the
emission projections presented here. As coal conversion strate-
gies are implemented, particulate emissions wi-ll increase above
the levels shown in Figure 3-1.
To illustrate the effects of other growth rates upon the
amount of particulate emissions, total particulate emissions were
calculated for annual growth rates of 4.6 percent and 0.5 per-
cent, corresponding to the EEI high-growth scenario and the EIA
low-growth scenario, respectively- The results of this analysis
are presented in Figure 3-2 with the emissions for the 3.3
percent growth case for comparative purposes. In the absence of
controls, emissions under the 3.3 percent growth scenario will
more than double by the year 2000. About 80 percent of the total
emissions will be from boilers in the industrial sector.
3.3.2 SOX Emissions
Figure 3-3 shows projected uncontrolled SOX emissions from
water-tube, fire-tube, and cast iron boilers for the period 1975
to 2000. Since total SOX emissions will change in direct propor-
tion to changes in sulfur content of the fuels burned, total SOX
emissions will also increase somewhat beyond those projected in
proportion to the replacement of natural gas and distillate oil
with coal.
To illustrate the effects of other growth rates upon the
amount of SOX emissions, total SOX emissions were also calculated
for annual growth rates of 4.6 percent and 0.5 percent, and are
shown in Figure 3-4 with the emissions for the 3.3 percent
growth case for comparison. Coal conversion strategies will have
little impact on the commercial sector and limited impact on the
industrial sector because coal sulfur content is restricted by
the requirement that SOX emissions cannot increase when con-
verting to coal.
3.3.3 NOX Emissions
Figure 3-5 shows projected uncontrolled NOX emissions for
the period 1975 to 2000. The NOX emissions from boilers are most
80
-------
8.0 x 106
7.5 x TO6
7.0 x 106
6.5 x TO6
6.0 x 106
5.5 x 106
5.0 x 106
4.5 x TO6
~ 4.0 x 106
3.5 x 10'
3.0 x
2.5 x 10C
2.0 x 10l
1.5 x 10'
1.0 x
5 x 10-
1 x 10'
1975
1980
1985 1990
YEAR
1995
2000
Figure 3-2. Projected total uncontrolled emissions of
particulate for alternate growth rates through 2000.
81
-------
8 x io
7 x 10
6 x 10
5x10
>,
cri
S 4 x 10
3 x 10'
2 x 10'
1 x 10'
I I
i i
j i
1975 1980
7985T990~
YEAR
1995 2000
Figure 3-3. Projected total uncontrolled emissions of SO
from the industrial/commercial boiler population through 2000.
82
-------
i_
>>
9 x TO6
8 x 10 -
7 x 10° -
6 x 10" -
5xlOu-
4 x 10U-
3 x 10
2 x 10°-
1 x 10
6_
1975 1980
1985 1990
YEAR
1995 2000
Figure 3-4. Projected total uncontrolled emissions of SO
for alternate growth rates through 2000.
x
-------
4 x 10
3 x 10'
2 x 10
1 x 10
1 x 10
1975
1980
1985 1990
YEAR
1995
2000
Figure 3-5. Projected total uncontrolled emissions of NOX
from the industrial/commercial boiler population through 2000
84
-------
sensitive to boiler configuration and are independent of fuel
type. The projected emissions are based on the same boiler types
as those in the 1975 data base. Coal conversion strategies would
probably not have a great impact on the total NOX emissions since
rates of emissions from coal-fired units are not significantly
different from oil- and natural-gas-fired units.
Total NOX emissions were also calculated for annual growth
rates of 4.6 percent and 0.5 percent and are presented in Figure
3-6 with the emissions for the 3.3 percent growth case for
comparison.
85
-------
4 x 10'
3 x 10
2 x 10'
1 x 10'
1 x 10
197!
1980
1985 1990
YEAR
1995 2000
Figure 3-6. Projected total uncontrolled emissions of NO
for alternate growth rates through 2000. 3
86
-------
REFERENCES FOR SECTION 3
Cato, G.A., H.J. Buening, C.C. DeVivo, B.C. Morton, and J.M.
Robinson. 1974. Field Testing - Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers - Phase I. EPA-650/2-74-078a.
Cato, G.A., L.J. Muzio, and D.C. Shore. 1976. Field Testing -
Application of Combustion Modification to Control Pollutant
Emissions from Industrial Boilers - Phase II. EPA-600/2-96-
086a.
Federal Power Commission. 1976. Annual Summary of Cost and
Quality of Steam - Electric Plant Fuels. Washington,
D.C.
Offen, G.R., J.P. Kesselring, K. Lee, G. Doe, and K.J. Wolfe.
1976. Control of Particulate Matter from Oil Burners of
Boilers. EPA-450/3-76-005.
U.S. EPA. 1977. Compilation of Air Pollutant Emission Factors,
AP-42, Third Edition.
Grammar, R.D., R.B. Engdahl, and R.E. Barrett. 1976. Emissions
from Residential and Small Commercial Stoker-Coal-Fired
Boilers Under Smokeless Operation. EPA-600/7-76-029. Battelle-
Columbus Laboratories, Columbus, Ohio.
-------
SECTION 4
REPRESENTATIVE NEW BOILERS AND CHARACTERISTICS
To assess the relative impacts of possible regulations
affecting industrial boilers, it is necessary to determine the
costs of several different boiler types and emission control
systems. The following subsections present the boilers selected
for detailed evaluation, the rationale for their selection, and
their design and operating characteristics.
4.1 TYPICAL INDUSTRIAL BOILERS
The following criteria were used in the selection of repre-
sentative boilers:
0 Extent of usage
0 Potential for uncontrolled emissions of particulate
matter, SO , and NO
2C X
0 Representation of a cross section of the population
0 Potential for future installation
Eleven boilers (Table 4-1) were selected as representative
of the industrial boiler population. These boilers were proposed
jointly by PEDCo, IERL-RTP, and OAQPS and were selected by agree-
ment among industry representatives (ABMA), other contractors,
and EPA representatives. The criteria each selected boiler
satisfies are described in the following subsections.
4.1.1 Package, Scotch Fire-tube Boiler
A boiler that fires distillate oil or natural gas at a heat
input of 4.4 MW thermal was selected as representative of the
fire-tube boiler population. Because its capacity is near the
maximum for fire-tube boilers (Appendix A), it is likely to have
88
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TABLE 4-1. REPRESENTATIVE BOILERS SELECTED FOR EVALUATION
Boiler type
Fuel
Heat input, MW thermal
(106 Btu/h)
Package, Scotch fire-tube
Package, Scotch fire-tube
Package, water-tube, underfeed-
stoker
Package, water-tube
Field-erected, water-tube,
chain-grate-stoker
03 Package, water-tube
Package, water-tube
Package, water-tube
Field-erected, water-tube
spreader-stoker
Field-erected, water-tube
Field-erected, water-tube
Distillate oil
Natural gas
Coal
Residual oil
Coal
Residual oil
Distillate oil
Natural gas
Coal
Pulverized coal
Pulverized coal
4.4 (15)
4.4 (15)
8.8 (30)
8.8 (30)
22.0 (75)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
58.6 (200)
117.2 (400)
-------
the greatest impact on emissions. Distillate oil and natural gas
are relatively clean fuels in terms of potential air emissions;
however, these fuels are fired by the majority of the fire-tube
units. Because distillate oil and natural gas are both widely
used in fire-tube boilers, separate estimates were prepared for
boilers firing each fuel. Sales data from ABMA for the 10-year
period from 1966 to 1975 show that the Scotch fire-tube configur-
ation is preferred, accounting for 50 percent of fire-tube sales
(Locklin et al., 1974). These data also show that no coal-fired
fire-tube boilers were sold during this 10-year period, thus
eliminating them from consideration.
4.1.2 Package Water-tube Boiler With an Underfeed Stoker
A boiler that fires coal at a heat input of 8.8 MW thermal
(30 x 106 Btu/h) was chosen as representative of small package
water-tube units. The boiler has the potential for emitting
large quantities of particulate matter, SOX, and NOX. About 60
percent of the coal-fired boilers in this size range use under-
feed stokers (Locklin et al., 1974).
4.1.3 Package Water-tube Boilers
Boilers that fire residual oil at heat inputs of 8.8 MW
thermal (30 x 106 Btu/h) and 44 MW thermal (150 x 106 Btu/h),
distillate oil at 44 MW thermal (150 x 106 Btu/h), and natural
gas at 44 MW thermal (150 x 1Q6 Btu/h) were selected as repre-
sentative of large package boilers. About 25 percent of the
boilers in the range from 29 to 73 MW thermal (100 to 250 x 106
Btu/h) are shop-fabricated (Locklin et al., 1974). Three fuels
were selected so that fuel impact could be represented in the
overall analysis. The boilers have the potential for emitting
significant quantities of SOX and NOX when firing residual oil.
4.1.4 Field-Erected Water-tube Boiler With Chain-grate Stoker
A boiler that fires coal at a heat input of 22 MW thermal
(75 x 106 Btu/h) was selected as representative of small field-
erected water-tube boilers. A boiler of this type has the
90
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potential for emitting significant, uncontrolled quantities of
particulate matter, SOX, and NOX. The chain-grate stoker was
chosen because it is a common fuel-firing mechanism for this size
boiler.
4.1.5 Field-Erected Water-tube Boiler With Spreader Stoker
A boiler that fires coal at a heat input of 44 MW thermal
(150 x 106 Btu/h) was selected as representative of large, field-
erected, stoker-fired boilers. Seventy-five percent of the
boilers in the 29 to 73 MW thermal (100 to 250 x 106 Btu/h) size
range are field-erected, and 60 percent of the stoker-fired
boilers in this size range utilize spreader stokers (Locklin et
al., 1974). Spreader stokers have the potential for emitting
large quantities of particulate matter, SOX, and NOX.
4.1.6 Field-Erected, Water-tube, Pulverized-Coal-Fired Boilers
Boilers that fire pulverized coal at heat inputs of 58.6 MW
thermal (200 x 106 Btu/h) and 117.2 MW thermal (400 x 106 Btu/h)
were selected as representative of pulverized-coal-fired boilers.
Pulverized-coal-fired units account for 15 percent of the coal-
fired boilers in the size range from 29 to 73 MW thermal (100 to
250 x 106 Btu/h) and 58 percent in the size range from 73 to 147
MW thermal (250 to 500 x 106 Btu/h). (Locklin et al., 1974.)
These boilers have the potential for emitting significant quan-
tities of particulate matter, SOX, and NOX.
The boiler configurations chosen are believed to represent
designs most commonly purchased currently or projected to be
purchased. An attempt was made to select a boiler for evaluation
that contributes significantly to the emissions from the major
class it represents and one on which possible emission limita-
tions could have the most impact.
4.2 BOILER CHARACTERISTICS
Operational and design parameters had to be specified for
the selected boilers before the costs of new boilers could be
91
-------
estimated and emission control equipment could be designed and
costed. The following key operating and design parameters are
required for each boiler:
0 Boiler configuration
0 Design heat input rate
0 Fuel analysis
0 Fuel consumption
0 Emission rates
0 Excess air usage
0 Flue gas characteristics
0 Load factor
The values determined for these operating and design param-
eters (Tables 4-2 through 4-11) are based on published data and
practical knowledge of good boiler operating practices. The
methodology used to determine these values is described in the
following subsections.
4.2.1 Boiler Configuration
Boiler configuration was specified as an initial step in the
selection of representative boilers, and the basis for each was
described in Section 4.1.
4.2.2 Design Heat Input Rate
This rate is based on the available capacities of the boil-
ers within the selected configurations. The selection of the
capacity range reflects the greatest potential for generating
emissions and the most common capacities within a particular
boiler configuration. For example, Scotch fire-tube boilers are
available in capacities ranging from 0.1 to 8.8 MW thermal (0.3
to 30 x 10 Btu/h). The largest portion of these boilers is in
the 0.4 MW to 2.9 MW range, but boilers with a capacity of 4.4 MW
thermal (15 x 10 Btu/h) are also quite common and their poten-
tial for emissions is larger than that of the boilers in the most
common capacity range.
92
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TABLE 4-2. DESIGN PARAMETERS FOR A DISTILLATE-OIL-FIRED,
PACKAGE, SCOTCH FIRE-TUBE BOILER
Heat input, MW thermal (106 Btu/h)
Fuel rate, m3/h (gal/h)
Analysis
% Sulfur
% Ash
Heating value, MJ/m (Btu/gal)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
so2
NO
x
CO
HC as CH,
4.4 (15)
0.41 (108)
0.5
Trace
38,712 (139,000)
15
2.36 (5,000)
450 (350)
45
0.10 (0.22)
3.47 (7.67)
1.08 (2.38)
0.24 (0.54)
0.05 (0.11)
93
-------
TABLE 4-3. DESIGN PARAMETERS FOR A NATURAL-GAS-FIRED, PACKAGE,
SCOTCH FIRE-TUBE BOILER
Heat input, MW thermal (106 Btu/h)
Fuel rate, m3/h (ft3/h)
Analysis
% Sulfur
% Ash
Heating value, KJ/m3 (Btu/ft3)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
so2
NO
x
CO
HC as CH.
4.4 (15)
424.8 (15,000)
Trace
Trace
37,218 (1000)
15
2.45 (5,200)
450 (350)
45
0.07 (0.15)
0.005 (0.01)
1.19 (2.63)
0.12 (0.26)
0.02 (0.05)
94
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TABLE 4-4.
DESIGN PARAMETERS FOR A COAL-FIRED, PACKAGE,
WATER-TUBE UNDERFEED BOILER
Eastern high-
sulfur coal
Eastern low-
sulfur coal
Subbituminous
coal
tn
Heat input, MW thermal (106 Btu/h)
Fuel rate, kg/s (tons/h)
Analysis
% Sulfur
% Ash
Heating value, kJAg (Btu/lb)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
so2
NO
x
CO
HC as CH,
8.8 (30)
0.32 (1.27)
3.5
10.60
27,477 (11,800)
50
6.09 (12,900)
478 (400)
60
30.49
76.52
8.63
1.15
0.58
(67.31)
(168.91)
(19.05)
(2.54)
(1.27)
8.8 (30)
0.27 (1.09)
0.9
6.90
32,099 (13,800)
50
5.76 (12,200)
450 (350)
60
8.8 (30)
0.39 (1.56)
0.60
5.40
22,330 (9,600)
50
5.90 (12,500)
450 (350)
60
17.04
16.89
7.41
0.99
0.49
(37.61)
(37.28)
(16.35)
(2.18)
(1.09)
19.08
16.13
10.60
1.41
0.71
(42.12)
(35.60)
(23.40)
(3.12)
(1.56)
-------
TABLE 4-5. DESIGN PARAMETERS FOR A COAL-FIRED,
WATER-TUBE, CHAIN-GRATE BOILER
FIELD-ERECTED
Heat input, MW thermal (106 Btu/h)
Fuel rate, kg/s (tons/h)
Analysis
I Sulfur
1 Ash
Heating value, kj/kg (Btu/lb)
Excess air, %
Flue gas flow rate, m3/s (acfm)
Flue gas temperature, °K (CF)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
S02
NOX
CO
HC as CH4
Eastern high-
sulfur coal
22.0
0. 80
3.5
10.6
27,447
50
15.24
478
60
76.35
191.59
21.61
2.88
1.44
(75)
(3.18)
(11,800)
(32,300)
(400)
(168.54)
(422.94)
(47.70)
(6.36)
(3.18)
Eastern medium-
sulfur coal
22.0
0.72
2.3
13.2
30,703
50
14.73
450
60
84.31
111.65
19.16
2.55
1.28
(75)
(2.82)
(13,200)
(31,200)
(350)
(186.12)
(246.47)
(42.30)
(5.64)
(2.82)
Eastern low-
sulfur coal
22.0
0.69
0.9
6.9
32,099
50
14.21
450
60
42.51
42.14
18.48
2.46
1.23
(75)
(2.72)
(13,800)
(30,100)
(350)
(93.84)
(93.02)
(40.80)
(5.44)
(2.72)
Subbituminous
coal
22.0
0.99
0.6
5.4
22,330
50
14.82
450
60
47.82
40.38
26.57
3.54
1.77
(75)
(3.91)
(9,600)
(31,400)
(350)
(105.57)
(89.15)
(58.65)
(7.82)
(3.91)
-------
TABLE 4-6. DESIGN PARAMETERS FOR RESIDUAL-OIL-FIRED, PACKAGE, WATER-TUBE BOILERS
Heat input, MW thermal (106 Btu/h)
Fuel rate, m3/h (gal/h)
Analysis
% Sulfur
% Ash
Heating value, MJ/m3 (Btu/gal)
Excess air, %
Flue gas flow rate, m3/s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituents, kg/h (Ib/h)
Fly ash
S02
NOX
CO
HC as CH4
8.8 (30)
0.76 (200)
3.0
0.1
41,714 (149,800)
15
4.62 (9800)
478 (400)
55
2»99 (6<,60)
42.73 (94020)
5.44 (12.0)
0.45 (1.0)
0.09 (0.20)
44.0 (150)
3.79 (1000)
3.0
0.1
41,714 (149,800)
15
22.04 (46,700)
478 (400)
55
14.95 (33.0)
213,36 (471.0)
27=18 (60,0)
2.27 (5.0)
0.45 (1.0)
-------
TABLE 4-7. DESIGN PARAMETERS FOR A DISTILLATE-OIL-FIRED,
PACKAGE, WATER-TUBE BOILER
Heat input, MW thermal (106 Btu/h)
Fuel rate, m /h (gal/h)
Analysis
% Sulfur
% Ash
Heating value, MJ/m3 (Btu/gal)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituents, kg/h (Ib/h)
Fly ash
S02
N0x
CO
HC as CH
44.0
4.09
0.5
Trace
38,712
15
21.78
450
55
0.98
34.78
10.75
2.44
0.49
(150)
(1080)
(139,000)
(46,200)
(350)
(2.16)
(76.61)
(23.74)
(5.40)
(1.08)
98
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TABLE 4-8. DESIGN PARAMETERS FOR A NATURAL-GAS-FIRED,
PACKAGE, WATER-TUBE BOILER
Heat input, MW thermal (10 Btu/h)
Fuel rate, m3/h (ft3/h)
Analysis
% Sulfur
% Ash
Heating value, MJ/m3 (Btu/gal)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituents, kg/h (Ib/h)
Fly ash
so2
N0x
CO
HC as CH4
44.0
4,248
Trace
Trace
37,218
15
22.15
450
55
0.68
0.04
11.92
1.16
0.20
(150)
(150,000)
(1000)
(46,900)
(350)
(1.50)
(0.09)
(26.26)
(2.56)
(0.46)
99
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TABLE 4.9. DESIGN PARAMETERS FOR A COAL-FIRED, FIELD-ERECTED,
WATER-TUBE^ SPREADER-STOKER BOILER
Eastern high-
sulfur coal
Eastern low-
sulfur coal
Subbituminous
coal
o
o
Heat input, MW thermal (10 Btu/h)
Fuel rate, kg/s (tons/h)
Analysis
% Sulfur
% Ash
Heating value, kJ/kg (Btu/lb)
Excess air, %
3
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
so2
NO
x
CO
HC as CH,
44.0 (150)
1.60 (6.36)
3.5
10.6
27,447 (11,800)
50
30.58 (64,800)
478 (400)
60
397.01 (876.41)
383.18 (845.88)
43.22 (95.40)
5.76 (12.72)
2.88 (6.36)
44.0 (150)
1.37 (5.43)
0.9
6.9
32,099 (13,800)
50
28.69 (60,800)
450 (350)
60
220.64 (487.07)
84.12 (185.71)
36.90 (81.45)
4.92 (10.86)
2.46 (5.43)
44.0 (150)
1.97 (7.81)
0.6
5.4
22,330 (9,600)
50
29.64 (62,800)
450 (350)
60
248.36 (548.26)
80.67 (178.07)
53.07 (117.15)
7.08 (15.62)
3.54 (7.81)
-------
TABLE 4-10. DESIGN PARAMETERS FOR A FIELD-ERECTED, WATER-TUBE,
PULVERIZED-COAL-FIRED BOILER WITH A HEAT INPUT OF 58.6 MW THERMAL (200 x 106 Btu/h)
Eastern high-
sulfur coal
Eastern low-
sulfur coal
Subbituminous
coal
Fuel rate, kg/s (tons/h)
Analysis
% Sulfur
Heating value, k J/k g (Btu/lb)
Excess air, %
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
so2
NO
x
CO
HC as CH,
2.13 (8.47)
3.5
10.6
27,447 (11,800)
30
35.30 (74,800)
478 (400)
60
650.74 (1436.51)
510.31 (1126.51)
69.06 (152.46)
3.84 (8.47)
1.15 (2.54)
1.83 (7.25)
0.9
6.9
32,099 (13,900)
30
33.32 (70,600)
450 (350)
60
362.58 (800.40)
112.32 (247.95)
59.12 (130.50)
3.28 (7.25)
0.99 (2.18)
2.63 (10.42)
0.6
5.4
22,330 (9,600)
30
34.55 (73,200)
450 (350)
60
407.83 (900.29)
107.62 (237.58)
84.96 (187.56)
4.72 (10.42)
1.42 (3.13)
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TABLE 4-11. DESIGN PARAMETERS FOR A FIELD-ERECTED, WATER-TUBE,
PULVERIZED-COAL-FIRED BOILER WITH A HEAT INPUT OF 117.2 MW THERMAL (400 x 10b Btu/h)
Fuel rate, kg/s (tons/h)
Analysis
% Sulfur
% Ash
Heating value, kj/kg (Btu/lb)
Excess air, %
Flue gas flow rate, m3/s (acfm)
Flue gas temperature, "K (°F)
Load factor, %
Flue gas constituent, kg/h (Ib/h)
Fly ash
S02
NOX
CO
HC as CH4
Eastern high-
sulfur coal
4. 27
3.5
10.6
27,447
30
70.63
478
60
1304.0
1022.6
138.4
7.7
2.3
(16.95)
(11,800)
(149,600)
(400)
(2874.72)
(2254.35)
(305.10)
(16.95)
(5.09)
Eastern medium-
sulfur coal
3.82
2.3
13.2
30,703
30
71.35
478
60
1450.4
600.2
123.6
6.9
2.1
(15.14)
(13,200)
(151,200)
(400)
(3197.57)
(1323.24)
(272.52)
(15.14)
(4.54)
Eastern low-
sulfur coal
3.65
0.9
6.9
32,099
30
66.80
450
60
725.6
224.8
118.3
6.6
2.0
(14.49)
(13,800)
(141,500)
(350)
(1599.70)
(495.56)
(260.82)
(14.49)
(4.34)
Subbituminous
coal
5.25
0.6
5.4
22,330
30
68.89
450
60
816.3
215.4
170.1
9.4
2.8
(20.83)
(9,600)
(146,000)
(350)
(1799.71)
(474.92)
(374.94)
(20.83)
(6.24)
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4.2.3 Fuel Analysis
Fuel type for each representative boiler was specified as
part of the initial selection process. The fuel analyses pre-
sented in Table 4-12 for natural gas and distillate and residual
oil were determined from data about "average" fuels presented by
Babcock & Wilcox (1972). The Babcock & Wilcox analysis of Bir-
mingham natural gas was selected as average. The values selected
for distillate oil represent No. 2 fuel oil; they were selected
from the middle of the ranges presented, except for sulfur con-
tent, which was chosen from the upper part of the range for
evaluation of a distillate oil with a relatively high sulfur
content. The analysis for the residual oil was selected from the
range of values given for No. 6 fuel oil; again, all values were
taken from the middle of the ranges except the sulfur value,
which comes from the upper part of the range so that a high-
sulfur residual oil can be evaluated.
Four coal analyses were used to represent the major coal-
producing areas and classes of coals available in the United
States. Data from Babcock & Wilcox (1972) served as the basis
for the analyses of eastern high-sulfur, high-ash, bituminous
coal; eastern low-sulfur, low-ash, low-moisture, bituminous coal;
and western low-sulfur, low-ash, high-moisture, subbituminous
coal. Versar, Inc., provided the analysis of eastern medium-
sulfur, high-ash, low-moisture, bituminous coal.
4.2.4 Fuel Consumption
Given the heat input rate specified for each representative
boiler in Table 4-1, fuel consumption was calculated by dividing
the heat input rate by the heating value of the fuel used. For
example, if a package, water-tube, underfeed stoker with a heat
input rate of 8.8 MW thermal (30 x 106 Btu/h) fires eastern coal
at 27,447 kJ/kg, the amount of fuel required is equal to 8800
kj/s v 27,447 kJ/kg, or 0.32 kg/s.
103
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TABLE 4-12. ULTIMATE ANALYSES OF FUELS SELECTED FOR THE
REPRESENTATIVE BOILERS3
Fuel
Natural gas
Distillate oil
Residual oil
Eastern high-sulfur,
high-ash coal
Eastern medium-sulfur,
high-ash coal
Eastern low-sulfur,
low-ash coal
Western low-sulfur,
low-ash coal
Composition, % by weight
Water
0.02
0.05
0. 08
8.79
0.80
2.54
20. 80
Carbon
69.26
87.17
86.62
64.80
74.80
78.64
57.60
Hydrogen
22.67
12.28
10.20
4.43
4. 56
4.70
3.20
Nitrogen
8.05
Trace
Trace
1.30
1.19
1.48
1.20
Oxygen
Trace
Trace
Trace
6.56
3.17
4.88
11.20
Sulfur
Trace
0.50
3.00
3.54
2.28
0.90
0.60
Ash
- 0
Trace
0.10
10.58
13.20
6.86
5.40
Heating value,
kj/kg (Btu/lb)
50,707 (21,800)
45,346 (19,500)
43,043 (18,500)
27,447 (11,800)
30,703 (13,200)
32,099 (13,800)
22,330 (9,600)
3 All analyses are based on engineering judgments by PEDCo about information from Babcock & Wilcox (1972),
except for the analysis of eastern medium-sulfur, high-ash coal, which Versar, Inc., provided in a memo
of March 22, 1979, to J. Kilgroe, IERL, Research Triangle Park, North Carolina.
-------
Because input capacities are specified, it is not necessary
to consider the efficiencies of boiler heat transfer or fuel
burning.
4.2.5 Emission Rates
All emission factors for particulates, sulfur oxides, nitro-
gen oxides, carbon monoxide, and hydrocarbons for the representa-
tive boilers were obtained from AP-42 (EPA, 1977). Each repre-
sentative boiler type and fuel are listed in the emission factor
tables (in Section 3.1) with the exception of the field-erected,
water-tube, spreader-stoker boiler with a heat input of 44 MW
thermal (150 x 10 Btu/h). Emissions from this boiler were
assumed to resemble most closely those from spreader-stoker,
coal-fired, industrial boilers with a heat input between 2.9 and
29.3 MW thermal (10 and 100 x 10 Btu/h); therefore these emission
factors were used.
The factors presented in AP-42 are generally dependent upon
the analysis and amount of the fuel burned, and they represent
uncontrolled emissions under normal operating conditions. The
emission rate for a particular time period is determined by
applying the emission factor to the amount of fuel burned in the
time period, using fuel analysis parameters where appropriate.
For example, the particulate emission factor applicable to the
package, water-tube, underfeed-stoker boiler firing eastern high-
sulfur coal is (2.5 x A) kg/10 kg of coal burned, where A is the
ash content of the fuel. Eastern high-sulfur coal has an ash
content of 10.60 percent and is burned at a rate of 0.32 kg/s.
The particulate emission rate is calculated as follows:
Particulate emissions = 2.5(10.60) kg/103 kg coal burned
x 0.32 kg coal burned/s x 1 x 10
kg/1000 kg x 3600 s/h
= 30.5 kg/h (61.31 Ib/h)
The same approach is used for calculating emissions from
each representative boiler/fuel type combination.
105
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4.2.6 Excess Air Usage
The amount of excess air selected for each boiler type is
based on practical knowledge of good boiler operating practices.
Table 4-13 presents ranges (percentages bv weight) of excess air
common to different boiler types. A value for each representa-
tive boiler was selected out of this range, based upon previous
experience and data on boiler operating characteristics.
A mass balance was then performed to obtain the amount of
excess air. The combustion air was assumed to have a temperature
of 27°C (80°F), a relative humidity of 60 percent, and a pressure
of 101 kPa (14.7 psi). The amount of air required for complete
combustion of the fuel was calculated on a molal basis from the
ultimate analysis of the fuel and the emission rates of the
various flue gas constituents.
An example of the procedure is shown below using the pack-
age, water-tube, underfeed-stoker boiler with a heat input of 8.8
MW thermal (30 x 106 Btu/h).
The molal configuration for each of the gaseous constituents
of the flue gas (determined by emission factors) is calculated by
dividing the mass rate by the molecular weight of the constitu-
ent. The results for the example boiler are shown below:
Constituent moles/h
Carbon monoxide (CO) 0.09
Hydrocarbons (as CH ) 0.07
Sulfur dioxide (SCO 2.80
Nitrogen oxides (as NO ) 0.23
The molal rate of each component is then calculated using
the fuel mass rate per hour and the ultimate analysis of the
fuel. The results for the example boiler are tabulated below:
106
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TABLE 4-13. TYPICAL AMOUNTS OF EXCESS AIR SUPPLIED
TO FUEL-BURNING EQUIPMENTS
Fuel
Type of burners
Excess air,
% by weight
Pulverized coal
Coal
Fuel oil
Natural gas
Partially water-cooled
for dry ash removal
Spreader stoker
Chain-grate and
traveling-grate stokers
Underfeed stoker
Multifuel and flat-flame
Multifuel
15-40
30-60
15-50
20-50
10-20
7-15
Babcock & Wilcox, 1963.
107
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Mass rate,
Fuel constituent kg/h (Ib/h) Molal rate
Carbon (C) 12.44 (1646) 137.1
Hydrogen (H2> 0.85 (113) 56.1
oulfur (S) 0.68 (90) 2.8
Oxygen (02) 1.26 (167) 5.2
Nitrogen (N2) 0.25 (33) 1.2
Water (H20) 1.69 (223) 12.4
The remaining flue gas constituents (CO,,, H20, N2) are cal-
culated by molal balance by subtracting the calculated moles of
emissions (AP-42) from the moles of equivalent components in the
fuel. For example, the CO and CH. represent part of the carbon
from the fuel. Assuming the remaining carbon is oxidized to CO,.,,
the molal quantity of CO2 is 137.17 moles of carbon minus 0.09
moles of CO minus 0.07 moles of CH. or 137.01 moles of C02- The
results of similar analyses for the other flue gas constituents
of the example boiler are as follows:
Constituent Molal quantity
C02 137.0
H20 68.5
N2 1.1
To calculate the stoichiometric oxygen required, each flue
gas constituent is examined in terms of equivalent oxygen content.
The following is a presentation of data for the example boiler.
108
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Flue gas
constituent
CO 2
CO
CH4
so2
H20
N0x (as N02)
N
Moles Moles
per hour per mole
137.
0.
0.
2.
68.
0.
1.
0
09
07
80
5
23
1
1.
0.
0.
1.
0.
1
0.
of 02 Moles of 62
constituent per hour
0
5
0
0
5
0
137
0
0
2
34
0
0
.0
.4
.0
.8
.2
.23
.0
Total 174.27
Of the 174.3 moles of 0,., required, the O« in the coal sup-
plies 5.2 moles and the HO in the coal supplies 6.2 moles.
Therefore the theoretical requirement from the combustion air is
162.9 moles of 0,,. The excess air for this boiler is 50 percent
of stoichiometric. Therefore the total oxygen required is 1.5
times the theoretical requirement, or 244.4 moles. It was
assumed that the combustion air is 21 percent oxygen and 79
percent nitrogen. Therefore the N_ required is 919 moles. The
weight of dry air supplied is then 15,256 kg/h (33,564 Ib/h). At
the previously assumed combustion air conditions, 0.0212 mole of
water is contained in the wet air per mole of dry air (24 moles
of HO total). The total wet combustion air supplied is then
15,453 kg/h (33,996 Ib/h).
4.2.7 Flue Gas Characteristics
The volume of the exit flue gas is dependent upon its compo-
sition, the amount of excess air, and the exit temperature. The
total moles of the various flue gas constituents was determined
for each boiler in the excess air calculations. At standard
conditions, the volume of a mole of gas is 10.2 m (359 ft ),
assuming ideal behavior. Therefore the volume of the flue gas at
standard conditions can be calculated.
109
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The actual volume of the flue gas must be calculated at the
flue gas temperature. Assumed temperatures of the exit flue gas
from each boiler were based on typical temperatures from previous
boiler studies. The calculated volumes of flue gas were then
adjusted from standard conditions to the actual temperature. It
was assumed that the flue gas pressure is constant at 101 kPa
(14.7 psi) .
For example, for the package, water-tube, underf eed-stoker
boiler with a heat input of 8.8 MW thermal (30 x 10 Btu/h) ,
total dry flue gas was calculated to be 1135.9 moles. On a wet
basis, flue gas was calculated to be 1228.4 moles. At the assumed
exhaust temperature of 478°K (400°F) the flue gas volume is:
Q A 7 ft ° K
1228.4 moles/h x 10.2 m /mole x *'
0
/ / J IN.
21,938 m3/h (775,204 ft3/h)
21,938 m3/h v 3600 s/h = 6.09 m3/s (12,800 ft3/min)
4.2.8 Load Factor
Assumed load factors for the representative boilers were
based on ranges of load factors for industrial boilers. Battelle
(Locklin, et al., 1974) estimated load factors in industrial/
commercial boilers to range from 30 to 80 percent. Selection of
values from the range for each representative boiler was based on
previous boiler studies and data on typical load factors. The
load factors are believed to be representative of new industrial
boilers supplying process steam. The overall industry and com-
mercial load factors discussed in Section 2 are lower because
they reflect standby capacity and seasonal use.
110
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REFERENCES FOR SECTION 4
Babcock & Wilcox. 1963. Steam - Its Generation and Use, Thirty-
seventh Edition. New York City-
Babcock & Wilcox. 1972. Useful Tables for Engineers and Steam
Users, Twelfth Edition. New York City.
Locklin, D.W., H.H. Krause, A.A. Putman, E.L. Kropp, W.T. Reid,
and M.A. Duffy. 1974. Design Trends and Operating Problems
in Combustion Modification of Industrial Boilers. EPA
R-802402, Battelle-Columbus Laboratories, Columbus, Ohio.
U.S. EPA. 1975. Compilation of Air Pollutant Emission Factors,
AP-42, Second Edition.
Ill
-------
SECTION 5
BASIS FOR COST EVALUATIONS
To evaluate the economic impact of controlling pollution
from new industrial and commercial boilers, one must determine
the cost of the various types of new boilers and also the cost of
the pollution control equipment. The percentage increase in cost
of a controlled system over that of an uncontrolled system can
then be determined. Both the capital cost and the annual operat-
ing cost are evaluated. The capital cost"is then translated into
an annual cost component and added to the annual operating cost
to derive an "annualized" cost estimate.
The design parameters and operating characteristics of the
boilers to be controlled strc igly influence the cost. Section 4
described the basis for establishing a standard set of design
parameters and operating characteristics for the boiler and the
associated pollution control equipment. The next step is to
establish a common basis for determining costs. This section
presents a standardized procedure and rationale for determining
the capital cost, annual operating cost, and annualized cost of
new boilers and pollution abatement equipment.
Capital costs include both direct and indirect cost compo-
nents. Section 5.1 describes the items ,^ be included in both
categories, as well as the normal range of values for indirect
cost components. The reliability of cost estimates developed
with the guidelines presented here is expected to be plus or
minus 30 percent. This is the degree of accuracy expected for a
study estimate in which only approximate specifications for sizes
and materials are available. If the control process is untried,
however, reliability can be as poor as plus 100 percent or minus
50 percent.
112
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As a process is developed, the design parameters and equipment
specifications are established with greater certainty, and cost
estimates become more accurate.
Recommended formats for presentation of capital and annual
costs are presented in Section 5.2. These are provided as
guidelines to ensure consistency in cost estimates for industrial
boiler control systems.
Section 5.3 gives recommended values for unit prices to be
used in estimating costs.
5.1 COST ELEMENTS
5.1.1 Capital Costs
The capital cost of a boiler or an emission reduction
system consists of the direct and indirect costs incurred up to
the successful commissioning of the facility. The first step in
determining these costs is specification of the battery limits of
the system. This definition of what is included in the system is
used to develop an equipment list. Direct costs include the
cost of the various equipment items and cost of the labor and
material required for installing the items and interconnecting
the system. The cost of land required for the equipment is also
a direct cost. Indirect costs are costs entailed in developing
the overall facility, but not attributable to a specific equip-
ment item. Indirect costs include such items as construction and
field expenses, engineering, construction fees, startup, perfor-
mance tests, and contingencies. Working capital, also included
under indirect costs, represents the assets required to cover
items needed for current operation of a facility. It includes
raw material stocks, in-process inventory, product inventory,
accounts receivable, and current obligations for employee wages
and other services.
113
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Direct Costs—
The "bought-out" cost of equipment and auxiliaries and the
cost of installation are considered direct costs. The costs of
equipment and auxiliaries are obtained from vendor estimates or
pricing catalogs. Transportation costs are then added to obtain
the total delivered cost. Installation costs include costs of
foundations, supporting structures, enclosures, piping, ducting,
stacks, control panels, instrumentation, insulation, painting,
and similar items. Costs for interconnection of postcombustion
control equipment items include site development and construction
of access roads and walkways. The cost of administrative facili-
ties is also considered parL of the direct installation costs.
These items are usually estimated as a percentage of the equip-
ment cost. When data are available on actual installation
requirements (such as cubic meters of concrete for foundations or
total length of connecting pipe), the installation costs should
be calculated directly. The costs of research and development
and the cost of lost production during installation and startup
are not included.
Indirect Costs—
Indirect costs are those that cannot be attributed to
specific equipment. Items included in indirect costs are described
below:
Engineering costs: includes administrative, process,
project,and general engineering; design and related func-
tions for specifications; bid analysis; special studies;
cost analysis; accounting; reports; purchasing; procurement;
travel expenses; living expenses; expediting; inspection;
safety; communications; modeling; pilot plant studies;
royalty payments during construction; training of plant
personnel; field engineering; safety engineering; and
consultant services.
Construction and field expenses: includes costs for tempo-
rary field offices; warehouses; craft sheds; fabrication
shops; miscellaneous buildings; temporary utilities; tempo-
rary sanitary facilities; temporary roads; fences; parking
lots; storage areas; field computer services; equipment fuel
and lubricants; mobilization and demobilization; field office
114
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supplies; telephone and telegraph; time clock system; field
supervision; equipment rental; small tools; equipment
repair; scaffolding; and freight.
Contractor's fee; includes costs of field labor payroll;
supervision field office; administrative personnel; travel
expenses; permits; licenses; taxes; insurance; field over-
head; legal liabilities; and labor relations.
Startup; includes costs associated with system startup and
shakedown.
Performance test: includes cost of a one-time test to
determine compliance with equipment performance guarantees.
Contingency costs; an account set up to deal with uncer-
tainties such as unforeseen escalation in costs, malfunc-
tions, equipment design alterations, and overlooked cost
items.
Working capital: includes costs of raw material stocks and
a fund to cover operation and maintenance of a system for a
given period of time. A period of 90 days is recommended
for boiler installations.
Indirect costs are determined as a percentage of the instal-
led equipment cost items and vary with each project. Table 5-1
gives typical ranges of each indirect capital cost factor as well
as values recommended for use in cost estimates. These values
are provided solely for guidance; where other values are speci-
fied, a rationale for their use should be given.
The month and year on which costs are based must be speci-
fied to allow cost comparisons on a consistent basis. It is
recommended that all costs be adjusted to June 30, 1978. Stand-
ard indexes, such as the chemical engineering cost index, should
be used to adjust costs to this date, and details of the adjust-
ment method should be specified.
5.1.2 Annual Costs
Annual operating costs of emission control systems also
consist of two components: operation and maintenance, with
associated overhead, and capital-related expenses. Operation and
maintenance charges include those for labor, raw materials,
115
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Table 5-1. TYPICAL VALUES FOR INDIRECT CAPITAL COSTS
Cost item
Range of values
Engineering
Construction and field
expenses
Contractor's fee
Shakedown
Performance test
Contingency
Working capital
8 to 20 percent of installed cost.
High value for small projects; low
value for large projects.
Recommend 10 percent
7 to 20 percent of installed cost.
Recommend 10 percent
10 to 15 percent of installed cost.
Recommend 10 percent
1 to 6 percent of installed cost.
Recommend 2 percent
Minimum value of $2000.
10 to 30 percent of total direct
and indirect costs dependent upon
accuracy of estimate.
Recommend 20 percent
15 to 35 percent of the total
annual operation and maintenance
costs.
Recommend 25 percent
Values are based on material -from 1!
at the end of Section 5.
sources that are listed
116
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utilities, and waste disposal required to operate the system on
a day-to-day basis. Capital-related expenses are those associ-
ated with owning the equipment, including depreciation, taxes,
insurance, and interest on borrowed capital.
Operation and Maintenance Costs--
Utilities: includes water for process use and cooling;
steam; electricity to operate controls, fans, motors,
pumps, valves, and lighting; and fuel if required.
Raw materials: includes any chemicals required for opera-
tion of the system.
Operating labor: includes supervision and the skilled and
unskilled labor required to operate, monitor, and control
the system.
Maintenance and repairs: consists of manpower and materials
needed to keep the system operating efficiently-
Byproduct costs: for systems producing a salable product,
a credit for that product; for systems producing a product
for disposal, the cost of disposal.
Fuel costs: where a fuel other than the normal supply is
used, the incremental cost of the fuel over and above normal
costs.
Another component of operating cost is overhead, which
represents a business expense that is not charged directly to a
particular part of the process but is allocated to it. Overhead
costs include administrative, safety, engineering, legal, and
medical services; payroll expenses including FICA; employee
benefits; and public relations. Overhead costs are usually
presented as payroll overhead and plant overhead. Following are
recommended values for each:
Payroll overhead - 30 percent of direct labor
Plant overhead = 26 percent of labor and materials.
Capital-Related Expenses--
The capital investment in a facility is generally translated
into annual capital charges. These charges, along with the
117
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annual operating costs, represent the total annualized cost of a
given system.
EPA classifies annual capital-related charges for cost
purposes under the following components: general and administra-
tive costs, taxes, insurance; a capital-recovery factor, which
represents a levelized principal and interest payment; and
interest on working capital. The first three components are set
at a total of 4 percent of depreciable investment. The capital-
recovery factor should be determined at 10 percent interest over
the life of a facility- Typical useful lifespans of some pollu'-
tion control devices are 20 years for an electrostatic precipi-
tator, 10 years for a venturi scrubber, and 20 years for a fabric
filter system. For other devices, a value for useful life should
be based on experience or on reliable data. Capital-recovery
factors for various time spans are presented in Table 5-2. For
example, with an annual interest rate of 10 percent and an equip-
ment life of 20 years, the capital-recovery factor is 0.11747 or
11.75 percent, which is the portion of the original capital
investment set aside per year to cover depreciation of the equip-
ment.
The interest on working capital is also 10 percent, repre-
senting the cost of foregoing other investment use of this fund.
5.2 COST ESTIMATING FORMAT
To provide consistent cost estimates for the ITAR studies, a
standardized format was developed under the guidance of the
Economic Analysis Branch, Office of Air Quality, Planning, and
Standards. Adherence to the format will allow a direct compari-
son of the costs of various control technologies and of each cost
category. Table 5-3 presents the format for capital costs.
Table 5-4 presents the format for annual costs.
118
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TABLE 5-2. CAPITAL RECOVERY FACTORS
Equipment
life, yr
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Annual compounded interest rate, %
5
1. 05000
0. 53780
0.36721
0. 28201
0.23097
0.19702
0.17282
0.15472
0.14069
0.12950
0.12039
0.11283
0.10646
0.10102
0. 09634
0. 09227
0.08870
0. 08555
0. 08275
0.08024
6
1. 06000
0.54544
0.37311
0.28859
0. 23740
0.20336
0.17914
0.16104
0.14702
0.13587
0.12679
0.11928
0.11296
0.10758
0.10296
0. 09895
0.09544
0. 09236
0. 08962
0. 08718
7
1. 07000
0.55309
0.38105
0.29523
0.24389
0.20980
0.18555
0.16747
0.15349
0.14238
0.13336
0.12590
0.11965
0.11434
0.10979
0.10586
0.10342
0.09941
0.09675
0.09439
8
1.08000
0.56077
0.38803
0.30192
0.25046
0.21632
0.19207
0.17401
0.16008
0.14903
0.14008
0.13270
0.12652
0.12130
0.11683
0.11298
0.10963
0.10670
0.10413
0.10185
10
1.10000
0.57619
0.40211
0.31547
0.26380
0.22961
0.20541
0.18744
0.17464
0.16275
0.15396
0.14676
0.14078
0.13575
0.13147
0.12782
0.12466
0.12193
0.11955
0.11747
12
1.12000
0.59170
0.41635
0.32923
0.27741
0.24323
0.21912
0.20130
0.18768
0.17698
0.16842
0.16144
0.15568
0.15087
0.14682
0.14339
0.14046
0.13794
0.13576
0.13388
15
1.15000
0.61512
0.43798
0-.35027
0.29832
0.26424
0.24036
0.22285
0.20957
0.19925
0.19107
0.18448
0.17911
0.17469
0.17102
0.16795
0.16537
0.16319
0.16134
0.15976
20
1.20000
0.65455
0.47473
0.38629
0.33438
0.30071
0.27742
0.26061
0.24808
0.23852
0.23110
0.22526
0.22062
0.21689
0.21388
0.21144
0.20944
0.20781
0. 20646
0.20536
(continued)
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TABLE 5-2 (continued)
Equipment
life, yr
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
40
45
50
Annual compounded interest rate, %
5
0. 07800
0. 07597
0. 07414
0. 07247
0.07,095
0. 06956
0. 06829
0. 06712
0. 06605
0. 06505
0. 06413
0. 06328
0. 06249
0. 06176
0. 06107
0. 05828
0. 05626
0.05478
6
0.08500
0.08305
0.08128
0.07968
0. 07823
0. 07690
0.07570
0.07459
0. 07358
0.07265
0. 07179
0.07100
0.07027
0.06960
0.06897
0.06646
0.06480
0.06344
7
0. 09229
0.09041
0.08871
0. 08719
0.08581
0.08456
0.08343
0.08239
0.08145
0.08059
0.07980
0.07907
0.07841
0.07780
0.07723
0.07501
0.07350
0. 07246
8
0.09983
0.09803
0.09642
0.09498
0.09368
0.09251
0.09145
0.09049
0.08962
0.08883
0.08811
0.08745
0.08685
0.08630
0.08580
0.08386
0.08259
0.08174
10
0.11562
0.11401
0.11257
0.11130
0.11017
0.10916
0.10826
0.10745
0.10673
0.10608
0.10550
0.10497
0.10450
0.10407
0.10369
0.10226
0.10139
0.10086
12
0.13224
0.13081
0.12956
0.12846
0.12750
0.12665
0.12590
0.12524
0.12466
0.12414
0.12369
0.12328
0.12292
0.12260
0.12232
0.12130
0.12074
0.12042
15
0.15842
0.15727
0.15628
0.15543
0.15470
0.15407
0.15353
0.15306
0.15265
0.15230
0.15200
0.15173
0.15150
0.15131
0.15113
0.15056
0.15028
0.15014
20
0.20444
0.20369
0.20307
0.20255
0.20212
0.20176
0.20147
0.20122
a. 20102
0.20085
0.20070
0.20059
0.20049
0.20041
0.20034
0.20014
0.20005
0.20002
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TABLE" 5-3. RECOMMENDED FORMAT FOR PRESENTING CAPITAL COSTS
EQUIPMENT COST
Basic equipment -(includes freight) .
Required auxiliaries
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Foundations and supports
Duct work (not incl. w/boiler)
Piping
Insulation
Painting
Electrical
Buildings
Total Installation Costs
TOTAL DIRECT COSTS
(Equipment + Installation)
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Startup (2% of direct costs)
Performance tests (minimum $2000)
TOTAL INDIRECT COSTS
Contingencies
(20% of direct and indirect costs)
TOTAL TURNKEY COSTS
(Direct + Indirect + Contingencies)
Land
Working capital (25% of total direct
operating costs)a
GRAND TOTAL
(Turnkey + Land + Working Capital)
From annual cost table.
121
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TABLE 5-4. RECOMMENDED FORMAT FOR PRESENTING ANNUALIZED COSTS
DIRECT COST
Direct labor
Supervision
Maintenance labor
Maintenance materials
Replacement parts
Electricity
Steam
Cooling water
Process water
Fuel
Waste disposal
Chemicals
Total Direct Cost
OVERHEAD
Payroll (30% of direct labor)
Plant (26%?of labor, parts, and maint.)
Total Overhead Cost
Byproduct Cost or Credit
CAPITAL CHARGES
G & A, taxes, and insurance
(4% of total turnkey costs)
Capital recovery factor
( %a of total turnkey costs)
Interest on working capital
(10% of working capital)
Total Capital Charges
TOTAL ANNUALIZED COSTS
Calculated from the expected lifetime of the equipment and the
annual interest rate.
122
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5.3 UNIT COST RECOMMENDATIONS
To estimate the annual costs of operation and maintenance of
boilers and the associated control devices, one must estimate
both the quantities of raw materials, utilities, and labor, and
also the unit price of each of these items, such as dollars per
man-hour for labor. For consistent cost estimation, the same
unit prices should be used in all cases. Although these unit
prices depend on many factors, geographical location is one of
the most significant. As a consistent basis for cost comparison,
the Midwest region was selected. The Midwest was chosen because
it has a heavy concentration of industry, and thus a large number
of industrial boilers.
Unit prices applicable to the Midwest were obtained through
review of periodicals giving cost statistics for fuels, labor,
chemicals, and utilities. Table 5-5 presents the recommended
unit prices for the operation and maintenance items and lists the
source of each value.
123
-------
TABLE 5-5.
ANNUAL UNIT COSTS FOR OPERATION AND MAINTENANCE
(June 1978 dollars)
Cost factors
Direct labor, $/man-hour
Supervision, $/man-hour
Maintenance labor,
$/man-hour
Electricity, mills/kWh
Untreated water, $/10 gal
Process water, $/10 gal
Cooling water, $/10 gal
Boiler feed water, S/10 gal
Coal, $/106 Btu
Eastern high-sulfur
Eastern medium-sulfur
Eastern low-sulfur
Wyoming low-sulfur
No. 2 fuel oil, $/106 Btu
No. 6 fuel oil, $/10 Btu
Natural gas, $/106 Btu
Lime (bulk, delivered), S/ton
Limestone (bulk, delivered) , $/ton
Sodium hydroxide (bulk, 50% basis, f.o.b. works), 5/ton
Sodium carbonate (bulk, delivered), $/ton
Ammonia (delivered) , $/ton
Ammonium hydroxide (29.3% NH3 basis, freight equalized), $/ton
Recommended value
12
15
14
25
0
0
0
1
0
0
1
0
3
2
1
35
3
158
90
130
173
.02*
.63b
.63a
.8C
.12d
.15d
.18e
.oof
.749
.95h
.16g
.42g
.OO1
.211
.95^
OO"'1
.0 Ok , m
.ook
.ook"'
.ook
.ook
Engineering News-Record, June 29, 1978, pp. 52-52. Average for Chicago, Cincinnati, Cleveland,
Detroit, and St. Louis.
Estimated at 30 percent over direct labor rate.
EEI members publication for June, 1978. Average for Boston, Chicago, Indianapolis, Houston,
San Francisco, and Los Angeles.
Peters, M.S., and K.D. Timmerhaus. Plant Design and Economics for Chemical Engineers, 2nd
Edition. McGraw-Hill Book Co. New York 1968. p. 772. Adjusted to 1978 prices using
Nelson Refinery Operating Cost Indexes for Chemicals. July 1978.
Perry J.H., et al.
1963, pp. 26-29.
Chemical Engineer1?; Handbook. McGraw-Hill Book Co. New York,
Nelson, w.L. Guide to Refinery Operating Costs. The Petroleum Publishing Company,
1966, p. 27. vii
Coal Outlook, July 18, 1978. Spot market prices.
Average of prices for high- and low-sulfur coal.
Electrical Week, May issues, 1978. Spot market prices.
Gas Facts, 1977. American Gas Association. Average U.S. price.
Chemical Marketing Reporter, June 19, 1978. F.u.b. cost.
Value includes assumed delivery cost of S3.00/ton.
Value includes assumed delivery cost of S2.00/ton.
Value includes assumed delivery cost of $30.00/ton.
124
-------
SOURCES OF TYPICAL VALUES LISTED IN TABLE 5-1
Aries, R.S., and R.D. Newton. 1955. Chemical Engineering Cost
Estimation. McGraw-Hill Book Co., New York.
Baasel, W.D. 1976. Preliminary Chemical Engineering Plant
Design. Elsevier Publishing Co., Inc., New York.
Bauman, H.C. 1960. Cost of Starting Up the Chemical Process
Plant. Ind. and Engn. Chem.
Bauman, H.C. 1964. Engineering Costs. In: AACE Cost Engineers
Notebook, Index 4.410, Paper A7.
Burns, T.J., and H.S. Hendrickson. 1972. The Accounting Primer:
An Introduction to Financial Accounting. McGraw-Hill Book
Co., New York.
Chilton, C.H. 1949. Cost Data Correlated. In: Chem. Eng.
56(6):97.
Derrick, G.C., and W.L. Sutur. 1977. Estimation of Industrial
Plant Strategy Costs. In: AACE Cost Engineers Notebook,
Index C-2.300.
McGlamery, G.G., R.L. Torstrick, W.J. Broadfeet, J.P- Simpson,
L.J. Henson, S.V. Tomlinson, J.F. Young. 1975. Detailed
Cost Estimates for Advanced Effluent Desulfurization Pro-
cess. Tennessee Valley Authority, EPA-600/2-75-006; NTIS
PB242-541.
Uhl, V.W. 1978. A Standard Procedure for Cost Analysis of Pol-
lution Control Operations. Third Draft. Special Studies
Staff, Industrial Environmental Research Laboratory, Research
Triangle Park, North Carolina.
Ford, Bacon & Davis, Inc. 1978. Private communication. Dallas,
October.
Guthrie, K.M. 1974. Process Plant Estimating, Evaluation, and
Control. Craftsman Book Co. of America, Solana Beach,
California.
Jelen, F.C. 1970. Cost and Optimization Engineering. McGraw-
Hill Book Co., New York.
125
-------
Junker, T.J. 1962. Plant Startup Expenses. Preprint of Paper
No. 32. AACE Annual Convention.
Matley, J. 1969. Keys to Successful Plant Startups. Chem. Eng.,
Vol., page.
Perry, J.H., et al. 1963. Chemical Engineers' Handbook.
McGraw-Hill Book Co., New York.
Peters, M.S., and K.D. Timmerhaus. 1968. Plant Design Economics
for Chemical Engineers. McGraw-Hill Book Co., New York.
Pyle, W.W., and J.A. White. 1972. Fundamental Accounting Princi-
ples. Richard D. Irwin, Inc., Homewood, Illinois.
Rudd, D.F., and C.C. Watson. 1968. Strategy of Process Engineer-
ing. John Wiley & Sons, New York.
126
-------
SECTION 6
COST ESTIMATES FOR NEW BOILERS
As a basis for comparative evaluation of various pollution
control techniques and their annualized costs, estimates were
developed for the cost of new installations of each of the typical
boilers described earlier. An outline of the procedures used in
developing the costs is followed by the cost estimates.
6.1 COST ESTIMATING PROCEDURE
Cost of a boiler facility includes the costs of basic equip-
ment, the costs of installation, and the costs of operating and
maintaining the boiler. In accordance with the procedure de-
scribed in Section 5, a capital cost estimate is developed by the
following steps:
0 Define the battery limits of the facility.
0 Develop a list of equipment required.
0 Obtain prices for each equipment item.
0 Calculate installation costs.
0 Calculate indirect capital costs.
Costs are all-inclusive, accounting for the material and
labor needed to complete an operational boiler plant. The esti-
mates were prepared from a detailed equipment summary- Estimates
of erection costs are based on experience and on actual cost of
erection at similar plants.
Battery limits of the facility extend as from the fuel-
receiving equipment to the ash disposal operation, inclusively.
Excluded are steam and condensate piping beyond the boiler build-
ing and pollution control equipment. Costs of ducting and the
stack are included.
127
-------
Based on guidelines presented by H.K. Ferguson (Coffin,
1978), an equipment list was developed for each boiler. The
major equipment items are described below.
Water enters the system through a treatment process—for
this study a standard Zeolite softening system. The makeup
water is then fed to a deaerator, which has a 15-minute holding
capacity at full flow. The return condensate is piped to the
condensate return tank. It is assumed that 20 percent makeup is
required. The overflow storage tank for the condensate return
tank is sized to hold the condensate generated in 1 hour at full
load capacity-
A continuous-blowdown flash tank and drain heat recovery
system recover all available heat from both the flash steam and
the drains.
Two boiler feed pumps are provided, 100 percent capacity
each. Automatic recirculation shutoff is not included. A fixed
minimum-flow bypass orifice is used for simplicity.
Each oil-fired boiler has 100 percent Maximum Capacity
Rating (MCR) oil-burning capability and includes a storage tank
and transfer pump facility. In the plant, a pump and heater set
are provided, consisting of two pumps (100 percent capacity)
for firing of No. 6 oil. Capacity of the storage tank provides
approximately 7 days firing at MCR.
Coal is stored in the plant in overhead bunkers supported by
the building steel. Coal is loaded into the bunkers by a con-
veying system designed to fill the bunkers completely during an
8-hour shift. Bunker capacity is sufficient to operate the plant
for 24 hours at full load.
The conveying system includes the under-track hopper, which
supplies a coal silo with 10 days' storage; a bucket elevator or
belt conveyor, depending on building height (100 ft maximum for a
bucket elevator); and an over-bunker tripper conveyor to load
each bunker section. A crusher included with the hopper allows
some sizing of the coal feed.
128
-------
The stoker-fired plants include an under-bunker conveyor,
tripper mechanism, and a nonsegregating conical distributor to
the stoker hopper.
The pulverized-coal-fired p_tant includes gravimetric feeders
to the pulverizers.
Ash handling systems of the pneumatic type (dry) transport
fly ash and bottom ash to a temporary storage silo for later
removal by truck. The bottom ash handling equipment includes a
clinker breaker.
Except for the pulverized-coal-fired boiler, which requires
an air heater to dry the coal sufficiently, all boilers are
equipped with economizers.
Controls are provided to regulate combustion, feedwater, and
flame safety. The pulverized-coal-fired boiler also has an
electronic pulverizer control system for safe and reliable start-
ing of the pulverizers.
The building, constructed of insulated steel, includes a
small office area and employees' washroom. No provision is made
for an enclosed control room for the operators; rather, the
boiler control panels are free-standing in front of the boiler
firing aisle. Lighting, ventilation, ladders, gratings, and
painting are included.
A 4047- to 8094-m2 (1- to 2-acre) parcel of land is allocated
to each boiler, depending on the boiler size. Table 6-1 lists
the basic equipment and installation items included in the capital
cost estimates. Table 6-2 lists the sources of data used in
estimating capital costs. Costs were obtained for the low-sulfur
bituminous coal; costs were then apportioned to the subbituminous
and high-sulfur bituminous coals by use of factors obtained from
boiler manufacturers. Indirect capital costs were estimated
according to guidelines in Section 5.
The costs are based on a Greenfield boiler installation with
no pollution control equipment, located in the Midwest. Regional
cost factors may be used to estimate costs in areas other than
the Midwest.
129
-------
TABLE 6-1. BASIC EQUIPMENT AND INSTALLATION ITEMS INCLUDED
IN A NEW BOILER FACILITY
Equipment:
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers or Stoker system
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Installations:
Foundations and supports
Piping
Insulation
Painting
Electrical
Building
130
-------
TABLE 6-2.
SOURCES Oi COST DATA FOR EQUIPMENT AND INSTALLATION
ITEMS INCLUDED IN BOILER PLANTS
Equipment item
Sources of cost data
Boiler (with fans and ducts)
Stacks
Instrumentation
Pulverizers or stoker system
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
(continued)
Babcock & Wilcox Co.
Combustion Engineering, Inc.
Cleaver-Brooks Division of
Aqua-Chem
Erie City Energy Division of Zurn
E. Keeler Co.
Airtek
Rust Engineering
Richardson Cost Estimating Manual3
Aedes Associates, Inc.
Babcock & Wilcox Co.
Combustion Engineering, Inc.
Cleaver-Brooks Division of
Aqua-Chem
Erie City Energy Division of Zurn
E. Keeler Co.
Babcock & Wilcox Co.
Combustion Engineering, Inc.
Cleaver-Brooks Division of
Aqua-Chem
Erie City Energy Division of Zurn
E. Keller Co.
Jeffrey Manufacturing Co.
Babcock & Wilcox Co.
Combustion Engineering, Inc.
Cleaver-Brooks Division of
Aqua-Chem
Erie City Energy Division of Zurn
E. Keeler Co.
Pennsylvania Crusher Co.
Richardson Cost Estimating Manualc
Chicago Heater Co.
Cochrane Environmental Systems
Richardson Cost Esimating Manual
Ingersoll-Rand
Richardson Cost Estimating Manual'
Richardson Cost Estimating Manual'
131
-------
TABLE 6-2 (continued)
Equipment items
Sources of cost data
Condensate system
Water treatment system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel oil system
Foundations and supports
Piping
Insulation
Painting
Electrical
Building
Richardson Cost Estimating Manual'
Crane Cochran Zeolite
Calgon Corp.
Milton Roy Co.
Richardson Cost Estimating Manual'
Ingersoil-Rand
Richardson Cost Estimating Manual'
Jeffrey Manufacturing Co.
Caterpillar Co.
Richardson Cost Estimating Manual'
Allen-Sherman-Hoff, Inc.
United Conveyor
Richardson Cost Estimating Manual'
Aedes Associates, Inc.
Coen Co.
Aedes Associates, Inc.
Aedes Associates, Inc.
Aedes Associates, Inc.
Aedes Associates, Inc.
Aedes Associates, Inc.
Aedes Associates, Inc.
Aedes Associates, Inc.
Richardson, 1978.
132
-------
Given equipment costs and installation costs, the indirect
capital costs such as engineering and contractor's fee were
calculated according to the guidelines in Section 5.
Table 6-3 lists the elements of annual operating and main-
tenance costs; Table 6-4 indicates the methods used in developing
the costs; Table 6-5 shows the manpower requirements on which the
labor costs are based. Annual overhead charges are estimated in
accordance with Section 5 guidelines, as are capital-related
charges.
The cost of disposing of bottom ash from a coal-fired boiler
is based on a 32-km (20-mi) one-way haul to ultimate disposal in
an environmentally sound landfill. The bottom ash is assumed to
be wetted to 20 percent moisture and hauled in covered trucks.
The disposal cost components include truck loading, washing the
loaded trucks, truck transportation, road cleaning and repair,
truck unloading, washing the unloaded trucks, and landfill fees,
including treatment. The ash disposal operation is conducted by
an outside contracting firm rather than the company itself. The
waste disposal cost is estimated at $44/Mg ($40/ton). This is a
conservative estimate of the average cost for a typical industrial
boiler with a heat input of about 30 MW thermal (100 x 106
Btu/h). Although the waste disposal cost can vary greatly
depending upon the haul distance and the method of disposal, this
conservative estimate reflects good environmental practice.
Annual operating and maintenance costs are based on require-
ments for labor, materials, and utilities as cited by manufac-
turers of boilers and auxiliary equipment, together with the unit
costs specified for the Midwest in Table 5-5.
Capital recovery factors are based on the following boiler
life expectancies:
Expected life,
Boiler type years
Package Scotch fire-tube 20
Package water-tube 30
Field-erected water-tube 45
133
-------
TABLE 6-3.
DIRECT ANNUAL OPERATION AND MAINTENANCE COST ITEMS
ASSOCIATED WITH BOILERS
Operational labor
Supervision
Maintenance labor
Replacement labor
Electricity
Process water
Fuel
Waste disposal
Chemicals
134
-------
TABLE 6-4. METHODS USED TO ESTIMATE DIRECT ANNUAL COSTS
Cost item
Method of obtaining cost
Operational labor
Supervision
Maintenance labor
Replacement parts
Oil or gas-fired boilers
Stoker units
Pulverized-coal-fired units
Process water
Fuel
Waste disposal
Chemica1s
Multiply manpower requirements from
Table 6-5 by rate given in Table 5-5.
Multiply manpower requirements from
Table 6-5 by rate given in Table 5-5.
Multiply manpower requirements from
Table 6-5 by rate given in Table 5-5.
Aedes Associates, Inc., detsrmined
percentages of total equipment cost
based on actual jobs (8 to 211).
Based on major equipment and lighting
loads.
114 to 379 kW
250 to 773 kW
1700 to 5100 kW
Multiply kW by ooeratina hours to obtain
annual kwh. Multiply annual kwh by
electric rate given in Table 5-5.
Requirement calculated assuming 80
percent return of condensate (20%
make-up). Multiply annual usage
by water rate given in Table 5-5.
Fuel requirement calculated based on
design heat input multipled by hours
per year operated based on load fac-
tors given in Tables 4-2 to 4-n.
Multiply annual fuel requirement by
appropriate rate from Table 5-5.
Requirement calculated from total
ash in fuel minus the quantity
emitted as fly ash. Multiply the
annual quantity of waste by an
average cost of $44/Mg ($40/ton) for
disposal in an environmentally sound
landfill 32 km (20 mi) from the plant
site.
Requirement calculated assuming
constant water quality and 80 per-
cent return of condensate (201 make-
up) . Multiply amount of chemicals used
•by average costs obtained from
chemical suppliers.
135
-------
TABLE 6-5. SUMMARY OF THE MANPOWER REQUIREMENTS
FOR THE SELECTED REPRESENTATIVE BOILERS
(man-years)
Boiler type
Heat input, 4.4 MW thermal
(15 x lO6 Btu/h)
Natural-gas-fired
Oil-fired
Heat input, 8.8 MW thermal
(30 x 106 Btu/h)
Oil-fired
Coal-fired
Heat input, 22.0 MW thermal
(75 x 106 Btu/h)
Coal-fired
Heat input, 44 MW thermal
(150 x 106 Btu/h)
Natural-gas-fired
Oil-fired
Coal-fired
Heat input, 58.6 MW thermal
(200 x 106 Btu/h)
Coal-fired
Heat input, 117.2 MW thermal
(400 x 106 Btu/h)
Coal-fired
Direct
labor
4
4
4
6
8
8
8
12
16
28
Supervision
2
2
2
2
4
2
2
4
4
6
Maintenance
labor
1
1
1
2
4
2
2
4
6
12
-------
From these values for boiler life ana the assumed interest rate
of 10 percent (Section 5), the capital recovery factors calculated
for each boiler type are as follows:
Capital recovery
Boiler type factor, %
Package Scotch fire-tube 11.75
Package water-tube 10.61
Field-erected water-tube 10.14
6.2 COST ESTIMATES
Costs are estimated for each of the typical boilers iden-
tified in Section 4. The basic boiler costs were obtained as
verbal or written quotations from various boiler manufacturers
including Babcock and Wilcox; Cleaver Brooks; Zurn Industries,
Inc.; Erie City; and Combustion Engineering. Capital cost
estimates for auxiliary equipment (e.g., water treatment systems)
are based on quotations obtained from manufacturers in related
projects.
Table 6-6 summarizes the estimated capital and annualized
costs for the representative boilers. Details of the cost esti-
mates for each combination of representative boiler and fuel type
are presented in Appendix G.
The estimated costs for new boilers vary widely. The total
capital costs of the boilers considered in this study range from
$389,800 for a package fire-tube boiler firing natural gas with
a heat input of 4.4 MW thermal (15 x 106 Btu/h) to $26,836,600
for a field-erected water-tube boiler firing pulverized sub-
bituminous coal with a heat input of 117.2 MW thermal (400 x 106
Btu/h). The major factors influencing cost are boiler size and
fuel. Coal-fired boilers are generally more expensive to build
than gas- or oil-fired boilers because of the need for larger
furnaces and more elaborate fuel handling equipment, but are
cheaper to operate because of lower fuel prices.
137
-------
TABLE 6-6. ESTIMATED CAPITAL AND ANNUALIZED COSTS
FOR THE SELECTED REPRESENTATIVE BOILERS
Boiler type
Package, fire-tube
Package, fire-tube
Package, water-tube
Package, water-tube
under feed -stoker
Package, water-tube
underfeed-stoker
Package, water-tube
underfeed-stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Field-erected, water-
tube, chain-grate-
stoker
Package, water-tube
Fuel
Natural gas
Distillate oil
Residual oil
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbi turn i nous
coal
Eastern low-
sulfur coal
Eastern medium-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Natural gas
Boiler capacity,
MW thermal
(106 Btu/h)
4.4 (15)
4.4 (15)
8.8 (30)
8.8 (30)
8.8 (30)
8.8 (30)
22.0 (75)
22.0 (75)
22.0 (75)
22.0 (75)
44.0 (150)
Capital cost,
S
389, 800
405, 100
797 ,800
1,665,200
1,891,300
2,257,100
4, 067,900
4,165,300
4 , 554 ,400
5,341,000
2,118 ,700
Annual
O and M, S
439,900
501,000
678 ,800
721,600
682, 500
653, 300
1,330,500
1,283,900
1,217,900
1,120, 100
2,035, 100
Fixed
cost, $
56,100
57,600
109,600
236, 300
269,800
323,600
563,400
577,600
633,300
745,700
287,800
Total annualized
cost , S
496,000
558,600
788,400
957,900
952,300
976,900
1,893,900
1,861, 500
1,851,200
1,865,800
2,322,900
U)
00
(continued)
-------
TABLE 6-6 (continued)
Boiler type
Package, water-tube
Package, water-tube
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, spreader-stoker
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Field-erected, water-
tube, pulverized-coal
Fuel
Residual oil
Distillate oil
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Eastern low-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Eastern low-
sulfur coal
Eastern medium-
sulfur coal
Eastern high-
sulfur coal
Subbituminous
coal
Boiler capacity,
MW thermal
(106 Btu/h)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
58.6 (200)
58.6 (200)
58.6 (200)
117.2 (400)
117.2 (400)
117.2 (400)
117.2 (400)
Capital cost,
$
2,244,900
2, 379,700
7,804,100
8,784,200
10, 395,800
10,823,200
12,202,400
14,468,400
20,094,000
20,707,300
22,638.000
26,836,600
Annual
0 and M, S
2,223, 100
2,793,900
2,101,800
1,849, 100
1 ,665,400
2,875,600
2,544,800
2,343,000
5, 317,000
4 ,957,700
4,624, 100
4 , 171,800
Fixed
cost, $
304,100
317,100
1,084,500
1,225,900
1,455,800
1, 504,400
1,702,900
2,025,600
2,792,500
2,883,000
3, 159,500
3,758,200
Total annualized
cost, $
2,527,200
3,111,000
3,186,300
3,075,000
3,121,100
4,380,000
4,247,700
4,368,600
8,109,500
7,840,700
7,783,600
7,930,000
OJ
VD
-------
Another factor that strongly affects costs is the method of
boiler construction. Field-erected boilers are much more expen-
sive than package boilers because construction is more complex.
The major factor affecting annual operating and maintenance
costs is the price of the fuel. Total fixed annual costs are
directly proportional to the turnkey cost of the boilers and are
in the range of 10 to 40 percent of total annualized costs.
140
-------
REFERENCES FOR SECTION 6
Coffin, B.D. 1978. Costing Examples of Industrial Applications,
Coal-fired Boiler Plants. H.K. Ferguson Co., Cleveland,
Ohio.
Richardson Engineering Services, Inc. 1978. Process Plant Con-
struction Estimating and Engineering Standards. Solana
Beach, California.
141
-------
APPENDIX A
DETAILED BOILER DESCRIPTIONS
There are three major types of boilers: water-tube, fire-
tube, and cast iron. Each type of boiler is suited to specific
applications and sites. Water-tube boilers are used in a variety
of applications ranging from supplying large amounts of process
steam to providing space heat for industrial and commercial
facilities. Fire-tube boilers are not available with capacities
as large as those of water-tube boilers, but they also are used
in a variety of applications, such as to supply process steam and
for space heating. Cast iron boilers are limited in size and are
used only to supply space heat. Figure A-l illustrates the
occurence of various important parameters in different sizes of
boilers. Following are detailed discussions of each boiler type.
WATER-TUBE BOILERS
A water-tube boiler is one in which the hot combustion gases
resulting from combustion of fuel are in contact with the outside
of the heat transfer tubes while the boiler water and steam
contact the inside of the tubes. The tubes are interconnected to
common water channels and to a steam outlet or outlets. Figure
A-2 is a simplified diagram of a water-tube boiler.
Water-tube boilers generate high-pressure, high-temperature
steam. The boilers are available in many sizes; the tubes are of
relatively small diameter, providing rapid heat transfer, good
response to steam demands, and high efficiency.
Used in a variety of utility, industrial, and commercial
applications, water-tube boilers are available as packaged or
field-erected units. Capacity of the packaged units ranges from
4,540 kg (10,000 Ib) of steam per hour to as high as 113,000 kg
A-l
-------
i
N)
Parameter
Fuel
Pulverized coal
Stoker coal
Residual oil
Distillate oil
Gas
Heat transfer
configuration
Water-tube
Fire -tube
Cast iron
Tubeless
Capacity range, 10 Btu/hour
0.4 1.0 10 25 100 500 1,500
(continued)
Figure A-l. Occurrence of various boiler parameters by capacity range.
-------
I
OJ
Parameter
Heat transfer
medium
Steam (super-
critical)
Steam (high
pressure)
Steam (low
pressure)
Hot water
Heat transfer
fluid
Hot air
Usage
Utility
Industrial
(process)
Industrial
(spaceheat)
Commercial-
Institutional
Domestic
Capacity range, 10 Btu/hour
0.4
••M
—
I 1.
•^•B
0 1
•i
••
0 2
5 1C
10 5C
)0 1,1
>00
••••••
Figure A-l. Occurrence of various boiler parameters by capacity range (continued)
-------
TO
ATMOSPHERE
STEAM
BOILER
Figure A-2. Simplified diagram of a water-tube boiler.
A-4
-------
(250,000 Ib) of steam per hour. Units of higher capacity are
field-erected.
Water-tube boilers can burn any economically available fuel
very efficiently. They are available in a variety of designs and
configurations to fit any plant capacity and space requirement.
Major types of water-tube boilers are vertical, vertically
inclined, and horizontal (and combinations of these). These
classifications refer to the orientation of the tubes within the
furnace. All water-tube boilers are characterized by the inter-
connection of tube sections, headers, and drums.
Water-tube boilers are also classified as units with natural
or forced circulation. Natural circulation results from the
difference in water and steam density. Forced circulation is
achieved with pumps that circulate water and steam through the
boiler. These units do not include drums because water is not
recirculated through the boiler and separation of the steam and
water is unnecessary. Forced circulation boilers can operate in
the supercritical range at capacities exceeding 4,536 Mg
(10,000,000 Ib) of steam per hour.
Coal-fired water-tube boilers consist of two main types:
stoker-fired and pulverized-coal-fired.
A stoker is a conveying system that feeds coal into a
furnace and also provides a moving grate upon which the coal is
burned. The feed rates to stoker furnaces are limited; stokers
are generally used on units rated at less than 176 MW thermal
(600 x 10 Btu/h) heat input. The following paragraphs describe
the three main types of stoker furnaces: underfeed, overfeed,
and spreader.
Underfeed Retort Stokers
Various underfeed retort stokers are available, depending on
whether the coal is fed horizontally or by gravity, whether the
ash is discharged from the end or the sides, and the number of
retorts.
A-5
-------
Single- or double-retort units can be designed in sizes up
to 120 megawatts thermal (400 million Btu/h) heat input. Multi-
ple-retort gravity-fed stokers can be designed to generate up to
180 Mg (400,000 Ib) of steam per hour.
In the side-discharge, horizontal underfeed stoker, shown in
Figure A-3, coal is fed intermittently to the fuel bed by a ram
or, in very small units, is fed continuously by a screw. The
coal moves in a longitudinal channel, called a retort, and air is
supplied through tuyeres on each side and through openings in the
side grates.
Overfire air is commonly used with underfeed stokers to
provide some combustion air and turbulence in the flame zone
directly above the active fuel bed. The air is provided by a
separate overfire-air fan and is injected through small nozzles
in the furnace walls.
An underfeed stoker can burn a wide range of coals, includ-
ing coking coals and anthracite, but it is best suited for bitu-
minous coals. The size of the coal directly affects the capacity
and efficiency of the underfeed stoker. The most desirable size
consists of pieces 3.2 cm (1-1/4 in.) and smaller, with not more
than 50 percent fines that will pass through a 0.6-cm (1/4-in.)
screen.
Overfeed (Chain-Grate or Moving-Grate) Stokers
Moving-grate stokers are classified as overfeed stokers.
They are equipped with chain or moving grates and with refractory
arches or overfire-air jets to improve combustion. This type of
stoker is usually designed for forced draft; natural draft de-
signs are gradually becoming obsolete.
Chain-grate and moving-grate stokers can produce up to
140 Mg (300,000 Ib) of steam per hour. A continuous fuel burning
rate of 5700 MJ/m2 (500,000 Btu/ft2) of grate per hour can be
achieved.
In chain-grate and traveling-grate stokers, assembled links
of grates are joined in an endless belt that passes over sprockets
or return bends located at the front and rear of the furnace. As
A-6
-------
OVERFIRE
AIR
COAL
HOPPER
STROKE
ADJUSTER
PUSHER1BLOCKS
AIR CHAMBER
RETORT^
PUSHER
BLOCK
Figure A- 3.
Single-retort, horizontal underfeed stoker
with side ash discharge.
A-7
-------
shown in Figure A-4, coal is fed from the hopper onto the moving
assembly and enters the furnace after passing under an adjustable
gate that regulates the thickness of the fuel bed. At the far
end of the grate, combustion is completed and ash is discharged
into the ashpit.
Most stoker-fired furnaces are provided with water cooling.
Completely water-cooled furnaces require less maintenance and
form less slag than refractory or air-cooled furnaces.
The chain-grate and traveling-grate stoker can be designed
to burn all kinds of solid fuels.
Spreader Stokers
The spreader stoker combines suspension burning and a thin,
fast-burning fuel bed on a grate. Capacities of spreader stokers
range from 2.3 to 180 Mg (5000 to 400,000 Ib) of steam per hour.
The modern spreader stoker, as shown in Figure A-5, consists
of feeder units (arranged to distribute fuel over the grate
area), a grate, forced-draft systems for both undergrate and
overgrate air, and combustion controls to coordinate air and fuel
supply.
An integral part of many spreader-stoker firing systems is
the provision for fly ash recirculation, wherein the fly ash that
is removed from the flue gas stream is reinjected into the
furnace. A gravity-flow fly ash return is shown in Figure A-6.
Pneumatic conveying systems are used for reinjection in the high
temperature zone above the grate.
Traveling-grate spreader stokers are generally installed
with one large plenum or air chamber under the entire grate
surface. Overfire-air systems are useful in promoting good
combustion and reducing the formation of smoke, especially at low
loads.
Spreader stokers are versatile and can be designed to burn
almost any type of solid fuel. Free-burning bituminous and
lignite coals are commonly used, and other fuels such as bagasse
(sugar cane refuse) and wood waste are also satisfactory -
A-8
-------
OVERFIRE-AIR
NOZZLES
COAL
HOPPER
AIR-CONTROL DAMPERS
RETURN
BEND
DRAG
PLATE
STOKER
CHAIN
DRIVE
SPROCKET
HYDRAULIC
DRIVE
Figure A-4. Chain-grate stoker with rear ash discharge.
-------
i
i—
o
COAL
HOPPER
FEEDER
• : ASH ' : : : :
: HOPPER ::
Figure A-5. Traveling-grate spreader stoker with
front ash discharge.
-------
TO STACK
STEAM OUTLET
FLY ASH
RETURNX
COAL FEEDER
GRATE
Figure A-6- Spreader stoker with gravity-
flow fly ash return.
(Courtesy of Babcock & Wilcox)
A-ll
-------
Anthracite generally is not satisfactory because it is a low-
volatility fuel and does not burn adequately in suspension.
Pulverized-Coal-Fired Units
Pulverized-coal-fired units operate on the principle of
suspension burning. Coal is pulverized to the consistency of
talcum powder and injected into the furnace pneumatically. These
furnaces are classified as dry-bottom or wet-bottom, depending on
whether the ash is removed in the solid or molten state. Figure
A-7 illustrates a direct-fired pulverized-coal unit. In the
direct-firing system, hot primary air is ducted to the pulver-
izer, where the raw coal is dried and pulverized and then is
conveyed to the burners in a continuous pattern. The coal is
mixed with primary air before entering the burner.
Another pulverized-coal-firing system is the now outdated
bin system. The coal is processed at a location apart from the
furnace. It is dried, pulverized, classified within the pulver-
izer, and then stored. From storage, the pulverized coal is
conveyed pneumatically to utilization bins. This system was used
extensively before reliable pulverizers were developed, but has
essentially been replaced by the direct-firing system.
The maximum capacity of individual burners used in pulver-
ized-coal-f ired boilers is 48 MW thermal (165 x 10 Btu/h). As
many as 70 burners may be used, although 16 to 30 burners is more
common. The circular type of burner, shown in Figure A-8, is
most frequently used.
FIRE-TUBE BOILERS
In fire-tube boilers the products of combustion flow through
a tube that is surrounded by a water basin. Figure A-9 is a
simplified diagram of a fire-tube boiler. These units are small
[up-to 5.9 MW thermal (20 x 106 Btu/h)] and are used primarily
for heating systems, industrial process steam, and portable power
boilers. Fire-tube boilers are generally used where loads are
relatively constant because they are susceptible to structural
A-12
-------
TEMP. AIR
PULVERIZERSTTl
Figure A-7. Dry-bottom pulverized-coal-fIred unit,
(Courtesy of Babcock & Wilcox)
A-13
-------
PULVERIZED COAL
AND PRIMARY AIR
PRIMARY AIR VANES
FUEL OIL GAS
Figure A-8. Circular burners for firing pulverized coal,
A-14
-------
TO
ATMOSPHERE
STEAM OUT
Figure A-9. Simplified diagram of a fire-tube boiler,
A-15
-------
failure when subjected to large variations in steam demand.
These units produce steam more efficiently than a simple shell
boiler because the water basin absorbs heat through the shell and
also through the tubes.
Most of the fire-tube boilers currently installed have
internal furnaces; that is, the combustion chamber is enclosed in
the boiler shell. In an external furnace arrangement, the boiler
shell and combustion chamber are separate. Internal furnaces are
preferred because of better water circulation and easier ash
removal.
There are six possible configurations in the fire-tube
boiler class: horizontal return tubular (HRT), Scotch marine,
vertical, locomotive, short firebox, and compact boilers. The
three most common configurations are the HRT, Scotch marine, and
vertical units. All six are discussed in the following sections.
Horizontal Return Tubular (HRT)
In an HRT boiler the fire-tubes are horizontal to the ground
The fuel firing mechanism is at one end, and the products of
combustion make two, thre'e, or four passes through the water
medium. The furnace is set on rollers or suspended on hangers to
allow for expansion and contraction. The boiler is encased with
brick and is sloped 2.5 to 7.5 cm (1 to 3 in.) from front to rear
(Woodruff and Lammers, 1977) . These boilers are well suited for
industrial use because they are compact and automatic and the
initial cost is low.
In a two-pass boiler, the furnace is at the bottom corner of
the unit, as shown in Figure A-10. The products of combustion
flow over the bridge wall to the other end of the boiler. As the
flue gas passes under the boiler, it heats the outer shell of the
water basin. At the other end of the unit, the flue gases enter
the fire-tubes. As the gases flow through the tubes, additional
heat is transferred to the water and produces steam or hot water.
The gases are then exhausted through the stack.
A-16
-------
TOP WATER COLUMN
CONNECTION
ROLLERS
STEAM GAGE
FLUSH FRONT
SETTING
FEED WATER
LINE
LOWER WATER
COLUMN CONNECTION
BRIDGE WALL
GRATES
Figure 10. Horizontal return-tubular boiler.
From Steam-Plant Operation by Woodruff, E.B., and
H.B. Lammers. Copyright (c) 1977, McGraw-Hill Book Co., New York,
Used with permission of McGraw-Hill Book Company.
-------
In a four-pass boiler, the furnace is at the end of the
unit, as shown in Figure A-ll. The first pass goes through the
furnace tube, which is an extension of the combustion chamber.
The flue gases then pass beneath the furnace tube and then make
two passes above the furnace tube. A forced-draft fan must be
used to operate a four-pass HRT boiler.
The HRT boiler comes in various sizes ranging from 0.15 to
5.9 MW thermal (0.5 to 20 x 10 Btu/h) heat input, with pressures
at 100 to 1,700 kPa (15 to 250 psi). The smaller sizes are two-
pass units and the larger sizes are four-pass units. Although
HRT boilers can fire all fuels, firing of coal can cause scaling
and slagging. HRT boilers offer longer boiler life, lower main-
tenance requirements, and higher firing rates than most fire-tube
boilers. Water circulation through these units is poor, however,
and thus the heating efficiency is only 70 percent (Thompson et
al., 1972).
Scotch Marine
A Scotch marine (Scotch) boiler comes in two-, three-, or
four-pass units, consisting of a water-cooled furnace and well-
cooled fire-tubes. A two-pass Scotch marine boiler is shown in
Figure A-12. The boiler and the furnace are contained in the
same shell. The fuels are burned in the lower half of the unit.
The products of combustion (flue gases) first flow through the
furnace tube, heating the bottom of the water basin, then pass
through the fire-tubes, heating the water in the basin.
The capacity of Scotch boilers ranges up to 3.4 MW thermal
(12 x 10 Btu/h) heat input with pressures up to 1400 kPa (200
psi). Heating efficiency is approximately 80 percent (Thompson
et al., 1972). The units range from 0.9 to 2.4 m (3 to 8 ft) in
diameter and 1.2 to 5.5 m (4 to 18 ft) long.
Scotch boilers are self-contained, portable, package units.
They are compact, require little space, and need no mountings.
The internal firing mechanisms can fire all types of fuel.
Again, however, firing of coal causes slagging and scaling.
A-18
-------
Figure A-ll. Horizontal four-pass forced-draft boiler.
From Steam-Plant Operation by Woodruff, E.B., and
H.B. Lammers. Copyright (c) 1977, McGraw-Hill Book Co., New York.
Used with permission of McGraw-Hill Book Company.
A-19
-------
Figure A-12. Scotch marine boiler.
H.B. Lasers?"
wlth
E.B., and
Co., New York.
A-20
-------
Vertical
A vertical boiler is a single-pass unit in which the fire-
tubes come straight \io from the water-cooled furnace. These
self-contained, portable units are small and require little
space; the initial cost is low. Vertical boilers are classified
as exposed-tube or submerged-tube boilers, depending on the
length of the fire-tube in relation to the water level.
An exposed-tube boiler is shown in Figure A-13. The fire-
tubes extend from the top of the furnace into the steam space.
This causes the steam to be superheated and reduces carryover of
moisture; however, the fire-tubes have a tendency to crack at the
point where they expand into the tube sheet.
A submerged-tube boiler is shown in Figure A-14. The
firetubes extend from the top of the furnace to the tube sheet,
which is below the water level. This design prevents the ends of
the tubes from overheating. A conical flue gas connector is
attached above the tube sheet and directs the flue gases into the
stack. Use of the vertical, submerged-tube boiler has essen-
tially been abandoned because the connector is difficult to build
and has a tendency to leak.
Capacities of vertical boilers range from 0.06 to 0.73 MW
thermal (0.2 to 2.5 x 106 Btu/h) at pressures of 700 kPa (100
psi). The size range is from 0.91 to 1.5 m (3 to 5 ft) in dia-
meter and 1.5 to 3.0 m (5 to 10 ft) in height. The fire-tubes
are 5 to 8 cm (2 to 3 in.) in diameter. These boilers can fire
all types of fuels at a heating efficiency of approximately 70
percent (Thompson et al., 1972). The furnace volume can be
expanded from its standard size to provide a higher heating
efficiency. The volume must be increased if coal is fired. This
is accomplished by elevating the boiler and setting it on a
refractory base.
Locomotive, Short Firebox, and Compact Boilers
A locomotive boiler is a single-pass horizontal fire-tube
unit. It is a portable power boiler with an internal water-
jacketed furnace. These units require long fire-tubes to prevent
A-21
-------
SAFETY
VALVE
BLOW OFF
INJECTOR
Figure A-13. Exposed-tube vertical boiler.
From .Steam-Plant Operation by Woodruff, E.B., and
H.B. Lammers. Copyright (c) 1977, McGraw-Hill Book Co., New York
Used with permission of McGraw-Hill Book Company.
A-22
-------
WATER
COLUMN
STEAM
OUTLET
STAY BOLTS
Figure A-14. Submerged-tube vertical boiler.
From Steam-Plant Operation by Woodruff, E.B., and
H.B. Lammers. Copyright (c) 1977, McGraw-Hill Book Co., New York.
Used with permission of McGraw-Hill Book Company.
A-23
-------
excessive heat loss. Even so, the heating efficiency is only
about 70 percent (Thompson et al., 1972).
A short firebox boiler is a two-pass horizontal firetube
unit, which can be used for space heating or process steam gen-
eration. This unit requires little floor space, and heating
efficiency is approximately 80 percent (Thompson et al., 1972).
The unit is limited by flame length and combustion volume.
A compact boiler is a three-pass horizontal boiler with an
internal, steel-encased, water-jacketed firebox. Heating effi-
ciency is approximately 80 percent (Thompson et al., 1972). The
capacity is limited by flame length and combustion volume.
CAST IRON BOILERS
Cast iron boilers are used in domestic or small commercial
operation to produce either low-pressure steam or hot water.
Capacities range from 0.001 to 4.0 MW thermal (0.003 to 14 x 10
Btu/h) heat input.
A domestic cast iron boiler is a small, round unit in which
the furnace is surrounded by a water basin, which is lanced with
flues. The flues allow the products of combustion to escape from
the combustion chamber and to transfer heat from the gases to the
water.
Commercial cast iron boilers are usually square or rectangu-
lar, as shown in Figure A-15, and consist of several vertical
sections. Water enters each section at the bottom and the steam
or hot water exits from the top. In each section the combustion
gases pass through a maze of tubes. These tubes transfer heat
from the gas to the water. The capacity of the commercial cast
iron boiler is determined by the number of sections.
Cast iron boilers are reliable, with an average boiler life
of about 50 years (Thompson et al., 1972). They require little
maintenance and can handle overloading or demand surges. The
major problem associated with cast iron boilers is that the
sections tend to deform, which may cause flue gases to leak from
the joints.
A-24
-------
Figure A-15. Cast iron boiler.
(Courtesy of Weil-McLain Company)
A-25
-------
REFERENCES FOR APPENDIX A
Thompson, O.F., H.R. Mehts, and W. McCormick. 1972. Survey of
Domestic, Commercial and Industrial Heating Equipment and
Fuel Usage. Catalytic, Inc. EPA Contract No. 68-02-0241.
Woodruff, E.B., and H.B. Lammers. 1977. Steam-Plant Operation.
Fourth edition, McGraw-Hill Book Co., New York.
A-26
-------
APPENDIX B
DERIVATION OF BOILER CAPACITY DATA
This Appendix provides a detailed description of the data
sources and procedures used to develop estimates of boiler capacity,
The International System of Units (SI) is not used here, because
the original sources were not in SI units. To make it easier to
process the data, they were not converted to SI units until final
figures were obtained.
Data from three prior studies were updated and expanded to
obtain information about the present boiler population. From
these studies and the new material available, basic data sheets
were compiled for boiler families having the parameters described
in Section 2.1. The three studies are:
Battelle Columbus Laboratories. Evaluation of National
Boiler Inventory. EPA-650/2-74-032, October 1975. (Re-
ferred to here as the Battelle boiler inventory.)
Battelle Columbus Laboratories. Design Trends and Operating
Problems in Combustion Modification of Industrial Boilers.
EPA-600/2-75-067, March 1974. (Referred to here as the
Battelle design study.)
Walden Corp. Systematic Study of Air Pollution from Inter-
mediate Size Fossil Fuel Combustion Equipment. EPA Contract
CPA 22-69-85, July 1971. (Referred to here as the Walden
boiler study.)
Major Fuel Burning Installation Data File Department of
Energy - 1975 Washington, D.C. (Referred to here as MFBI.)
The materials used for the updating and expansion are:
American Boiler Manufacturers Association (ABMA) sales
information for fire-tube and water-tube boilers for the
years 1966 to 1975.
B-l
-------
Shipment data for cast iron boilers for the years 1965 to
1975, supplied by the Hydronics Institute.
Data from the Major Fuel Burning Installation (MFBI) Survey
conducted by the Department of Energy in 1975.
The mechanics of developing the basic data are discussed in
this Appendix.
In the first step, the data from the Battelle boiler inven-
tory were rearranged into the size categories to be used in this
study. The corresponding sizes or capacities are shown below.
Battelle boiler
inventory
ize Capacity, Btu/1
1
0
1
2
3
4
5
6
7
8
9
0
11
1
1
1
2
3
4
5
1
2
5
1
2
5
1
2
5
1
2
5
1
to
to
to
to
to
to
to
to
to
to
to
to
to
to
>2
10 x
2 x
5 x
10 x
2 x
5 x
10 x
2 x
5 x
10 x
2 x
5 x
10 x
2 x
x 10
1
10
10
1
10
10
1
10
10
1
0
£.
\J
6
0
7
-J
1
0
B
U
Q
\J
0
5
fi
\J
7
/
p
*_>
109
10
1
10
10
Q
-7
0
q
_/
10
Present study
Capacity,
Size 1Q6 Btu/h (Corresponding category)
a) <10.4 (no corresponding cate-
gory)
b) 0.4 to 1.5 (size 0, and 1/2 the
population in size 1)
c) 1.5 to 10
(1/2 the population in
size 1, all of size 2
and 3)
d)
e)
f)
g)
h)
10 to 25
25 to 50
50 to 100 (size 6)
(size 4, and 1/6 the
population in size 5)
(5/6 the population in
in size 5)
100 to 250 (size 7, and 1/6 the
population in size 8)
250 to 500 (5/6 the population in
size 8)
i) 500 to 1500 (size 9, and 1/2 the
population in size 10)
j) >1500 (1/2 the population in
size 10, and sizes 11,
12, and 13)
Note: Size 14 was excluded from this study because
no boilers exist in this category.
B-2
-------
The distribution shown above assumes that the number of
boilers is evenly distributed in a category.
The capacity data were distributed on the assumption that
for each fraction of a category, the average size was equal to
the value of the midpoint of the range. For example, to calcu-
late values for sizes b) and c), the population of size 1 (1 to 2
x 10 Btu) was distributed with half going into each group: 50
percent of the 1 to 1.5 x 10 Btu/h group into size b); and 50
percent of the 1.5 to 2.0 x 10 Btu/h group going into size c).
The average boiler sizes of the two new groups were assumed to be
1.25 x 106 Btu/h and 1.75 x 106 Btu/h. The percentage of total
capacity contained in each of the two groups was calculated as:
^-|| (100) = 42 percent i^| - 58 percent
Equivalences between the capacity data from the two studies were:
Size a) None
Size b) All of size 0 and 42 percent of size 1
Size c) 58 percent of size 1 and all of sizes 2 and 3
Size d) All of size 4 and 10 percent of size 5
Size e) 90 percent of size 5
Size f) All of size 6
Size g) All of size 7 and 10 percent of size 8
Size h) 90 percent of size 8
Size i) All of size 9 and 42 percent of size 10
Size j) 58 percent of, size 10, all of sizes 11, 12, and 13.
For convenience, the Battelle inventory data for commercial
and industrial boilers were combined. The basic Battelle popu-
lation data are shown in Table B-l.
In the second step, the basic data were divided into three
categories representing water-tube, fire-tube, and cast iron
boilers. Data from the Battelle design study were used for this
B-3
-------
step. The size categories in the Battelle report and those
chosen for the present report were not exactly comparable. The
Battelle data show the percent distribution of the three basic
boiler types for various boiler sizes. For this study, the size
categories shown below were assumed to have the same distribution
of basic boiler types.
Battelle design study Present study
10 to 50 boiler horsepower 0.4 to 1.5 x 10 Btu/h
(0.335 to 1.68 x 106 Btu/h)
51 to 100 boiler horsepower
(1.68 to 3.35 x 106 Btu/h)
1.5 to 10 x 10U Btu/h
101 to 300 boiler horsepower
(3.35 to 10.04 x 106 Btu/h)
10 to 16 x 106 Btu/h 10 to 25 x 106 Btu/h
17 to 100 x 106 Btu/h 25 to 50 x 106 Btu/h
The applicable percent distribution from Table A-3 in the
Battelle design study is shown below.
Size Water-tube (%) Fire-tube (%) Cast iron (%) Misc.
0.4 -
1.5 -
10 -
25 -
1.5
10
25
50
6.0
5.8
22.0
79.0
48.0
74.1
78.0
21.0
45.0
19.9
1.0
0.2
>50 All water-tube
It was assumed that the distribution between water-tube,
fire-tube, and cast iron was applicable to all the fuel categories
shown in Table B-l. Tables B-2, B-3, and B-4 were derived by
applying the above percentages to the data in Table B-l. When a
data base was established for each of the three boiler cate-
gories, the data were further refined by boiler type. The water-
tube boiler population was derived from Table B-2 (Battelle
boiler inventory). The populations of fire-tube and cast iron
boilers were developed from the Walden boiler study, since these
data appear to be most comprehensive for these boiler types.
B-4
-------
TABLE B-l. COMMERCIAL AND INDUSTRIAL BOILER POPULATION (1971)
FROM BATTELLE REDISTRIBUTED INTO THE STUDY SIZE CATEGORIES
Size range ,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total
Fuel
Stoker
coal
No.
9, 341
19, 712
3,989
3,025
1,909
718
142
17
5
38,858
Capacity
11, 161
102,338
66,590
114,646
140,588
102,990
44,024
13,948
11,574
607,859
Pul ver ized
coal
No.
718
1,479
r>69
390
327
462
183
56
11
4,195
Capac i ty
1,018
6, 359
9,578
15,650
27,197
69,041
59,912
39,750
26,354
254,859
Res idua 1
oil
No.
19,556
55,182
11 ,239
5,818
2,406
948
272
54
7
95,482
Cnpacity
23,790
281,349
178,293
210,761
175,815
137,312
89,724
41,811
13,142
1,151,997
Dist- i Hate
oi 1
No.
48,R02
50,965
2,R37
1,083
324
163
38
6
1
104,219
r.ipaci ty
58,756
203,024
42,920
37,459
24,871
23,992
13,095
4, 399
2,274
410,790
Natural
gas
No.
40,225
61,951
8,423
4 ,735
2,382
1,078
299
98
40
119,231
Capacity
48,880
286,464
134,708
173,989
173,885
161,609
99,425
73,531
172,769
1,325,260
Total
No.
118,462
189,289
27,057
15,031
7,348
3,369
934
231
64
361,985
Capacity
143,605
879,534
132,089
552,505
542,356
494,944
306,180
173,439
226,113
3,750,765
td
I
-------
TABLE s-2.
DISTRIBUTION OF INDUSTRIAL/COMMERCIAL WATER-TUBE
BOILER POPULATION BY FUEL (1971)
W
I
Size range,
186 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total
ruel
Stoker
coal
No.
560
1, 143
878
2,390
1,508
718
142
17
5
7, 361
Capacity
670
5,936
14,650
90,570
111,065
102,990
44,024
13,948
11,574
395,427
Pulverized
coal
No.
43
R6
125
308
258
462
183
56
11
1,53?
Cnpaci ty
61
369
2,107
12, 364
21,486
69,041
59,912
39,750
26, 354
231,444
Residual
oil
No.
1,173
3,200
2,473
4,596
1,901
948
272
54
7
14,624
Capaci ty
1,427
16, 318
39,224
166,501
138,894
137,312
89,724
41,811
13,142
64-1, 353
Distillate
oil
No.
2,928
2,156
624
856
256
163
38
6
1
7,82R
Cnpac i ty
3,525
11,775
9,442
29,593
19,649
23,992
13,095
4 ,399
2,274
117,744
Natural
qas
No.
2,414
3,593
1,853
3,741
1,882
1,078
299
98
40
14,998
Cnpac i t y
2,933
16,615
29,63fi
137,451
137, 369
161,609
99,425
73,531
172,769
B31, 338
Total
7,118
10,978
5,953
11,891
5,805
3, 369
934
231
64
46,343
8,616
51,013
95, 059
436,479
428,463
494,944
306,180
173,439
226,113
2,220,306
-------
TABLE B-3.
DISTRIBUTION OF THE INDUSTRIAL/COMMERCIAL FIRE-TUBE
BOILER POPULATION BY FUEL (1971)
W
I
Sire range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>108.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total
Fuel
Stoker
coal
No.
4,484
14,607
3,111
635
401
23,238
Capacity
5,357
75,832
51,940
24,076
29,523
186,728
Pulverized
coal
No.
345
1, 096
444
82
69
2,036
Capacity
238
4,712
7,471
3,287
5,711
21,419
Res idua 1
oil
No.
9, 3B7
40, 890
8, 766
1,222
505
60,770
Capacity
11,419
208, 4RO
139,069
44,260
36,921
440,149
Disti Hate
oil
No.
73.-125
37,765
2,213
227
68
63,603
Capac i ty
2R, 203
150,441
33,478
7,866
5,223
225,21 1
Natural
qas
No.
19,308
45,906
6,570
994
500
71 , 278
Capacity
23,462
212,270
105,072
36,538
36,516
413,858
Total
Mo.
56,949
140,264
21,104
3,160
1,543
223,020
Capacity
68,679
651,735
337,030
116,027
113,894
1,287,365
-------
TABLE B-4. DISTRIBUTION OF THE INDUSTRIAL/COMMERCIAL
CAST IRON BOILER POPULATION BY FUEL (1971)
OS
I
oo
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total
Fuel
Stoker
coal
No.
4,203
3,923
8, 126
Capacity
5,022
20,365
25,387
Pulverized
coal
No.
323
294
617
Capacity
458
1, 265
1,723
Residual
oil
No.
8,800
10,987
19,781
Capacity
10, 706
55,988
66. 61"
Distillate
oil
No.
21,961
10,142
32,103
Capacity
26,440
40,402
66,842
Natural
gas
No.
18,101
12,328
30,429
Capaci ty
21,996
57,006
79,002
Total
No.
53,388
37,668
91,056
Capacity
64,622
175,026
239. B48
-------
Following are details of the procedure for deriving the data for
water-tube, fire-tube, and cast iron boilers.
WATER-TUBE BOILERS
It was first necessary to determine how many water-tube
boilers were erected in the field, and how many were package
units (shop-fabricated). The Battelle design study had estab-
lished that only water-tube boilers were field-erected. The
percentages of different types of construction for the size
ranges shown in Table B-2 were derived from Battelle design study
data. These are shown in Table B-5. These percentages were used
to divide the data in Table B-2 into the information presented in
Table B-6, which shows data for field-erected units, and Table
B-7, which shows data for package units. Pulverized-coal-fired
(PC) units having a capacity less than 100 x 10 Btu/h were
excluded at this point, based on information from ABMA that no PC
units of this size were constructed.
Of the water-tube boilers, the stoker-fed coal units were
divided into overfeed, underfeed, and spreader stokers. The per-
centages of the stoker types were taken from the Battelle design
study, and are presented for the different size catagories in
Table B-8. These are normalized percentages for the three cate-
gories of stoker.
The combined percentage of boilers in the 51 to 100 bhp and
the 101 to 300 bhp categories was obtained by calculating the
population in these two categories from data in Table 7 of the
Battelle boiler inventory. The calculations followed the meth-
odology described previously for rearranging the Battelle data
into the size categories used in the present study. These popu-
lation figures and percentages from the Battelle design study
were used to derive the combined percentages for the 1.5 to 10 x
10 Btu/h category.
B-9
-------
TABLE B-5. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL WATER-TUBE
BOILER POPULATION BY CONSTRUCTION METHOD
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Percent of total
construction method
Package
70.0
70.0
65.0
25.0
0.5
0
0
Field -erected
30.0
30.0
35.0
75.0
99.5
100
100
-------
TABLE B-6. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL FIELD-ERECTED,
WATER-TUBE BOILERS BY FUEL (1971)
Cd
I
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total •
Pulverized
coal
No.
263
717
528
538
141
17
5
2,209
Capacity
4,395
27, 171
38,872
77,242
43, 774
13,948
11,574
216,976
Stoker
coal
No.
346
182
56
11
595
Capacity
51,781
59,612
39,750
26, 354
177,497
Euel
Re
No.
742
1,379
665
711
271
54
7
3,829
sidual
oil
Capaci ty
11,767
49,950
48,613
102,984
89,275
41,811
13,142
357,542
Distillate
oil
No.
187
257
90
122
37
6
1
700
Capacity
2,833
8,878
6,877
17,994
12,840
4, 399
2,274
56,095
Natural
gas
No.
556
1,122
659
808
298
98
40
3,581
Capacity
8,891
41,235
48,079
121,207
98,928
73,531
172,769
564,640
Total
No.
1,748
3,475
1,942
2,525
929
231
64
10, 914
Capaci ty
27,886
127,234
142,441
371,208
304,429
173,439
226,113
1,372,750
-------
TABLE B-7.
DISTRIBUTION OF INDUSTRIAL/COMMERCIAL WATER-TUBE
BOILERS BY FUEL (1971)
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
MOO.O to 250.0
>250.0 to 500.0
>500.0 to 1500.
>1500
Total
Fuel
Pul ver i zed
coa 1
No.
560
1,143
615
1,673
980
180
1
5,152
Capacity
670
5,936
10,255
63,399
72,193-
25,748
250
8,451
Stoker
coa 1
No.
116
1
117
Capacity
17,260
300
17,560
Residual
oil
No.
1,173
3,200
1,731
3,217
1,236
237
1
10,795
Capacity
1,427
16, 318
27,457
116,551
90,281
34,328
449
86,811
Distillate
oil
No.
2,928
2,956
437
599
166
41
1
7,128
Capacity
3,525
11,775
6,609
20,715
12,722
5,998
255
61,599
Natural
No.
2,414
3,593
1,297
2,619
1,223
270
1
11,417
gas
Capacity
2,933
16,615
20,745
96,216
89,290
40,402
497
266,698
Total
No.
7,075
10,892
4,080
8,108
3,605
844
5
34,609
Capacity
8,555
50,644
65,066
296,881
264,536
123,736
1,751
811,169
-------
TABLE B-8. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL STOKER-FIRED BOILERS
I
t—
OJ
> 0 . 4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Percentage of total
Spreader
stoker
9
16
21
21
63
55
55
55
Underfeed
stoker
95
81
74
63
63
25
27
27
27
Overfeed
stoker
5
10
10
16
16
12
18
18
18
-------
Tables B-9 and B-10 show the distribution among types of
stokers for field-erected and package boilers. It was assumed
that the same distribution patterns applied in both categories.
The ABMA sales data were then used to update the figures.
These sales data for all water-tube boilers are shown in Table
B-ll. Tables B-12 and B-13 show the distribution of field-
erected and package boilers; Table B-14 shows the distribution of
oil-fired boilers into units using distillate and residual oil.
The figures in the sales tables were obtained by taking raw data
from ABMA and adjusting it to reflect an ABMA estimate of 27
percent replacement boilers and 73 percent new boilers. The
distributions between field-erected and package boilers, and
between units firing residual oil and firing distillate oil, were
made by using elements from the Battelle design study. Table
B-15 shows the combined data from the Battelle boiler study and
the ABMA sales figures.
FIRE-TUBE BOILERS
Data from the Walden boiler study were used to develop the
data base for fire-tube boiler capacity. Tables 4-1 and 4-2 of
the Walden study show the 1967 fire-tube boiler population as:
Number of
units Capacity, 10 Btu/h
239,000 813,000
An attempt was made to distribute data from the Walden
boiler study by size according to ratios derived from ABMA sales
data. (A description of the sales data is presented later in
this section.) The results that were obtained were obviously
erroneous. When the average size from the Walden data (3.4 x 106
Btu/h) is compared with the average size from the sales data (6.2
x 10 Btu/h), it is clear that a significant shift toward larger
sizes has occurred in recent years. Data from the sales records
were all within three size categories (0.4 to 1.5, 1.5 to 10, and
10 to 25 x 10 Btu/h). Most of the capacity was in the two
B-14
-------
TABLE B-9. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL FIELD-ERECTED,
STOKER-FIRED, WATER-TUBE BOILERS (1971)
W
I
h-1
Ul
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Spreader
stoker
No.
42
151
111
339
78
9
3
733
Capacity
703
5,706
8,163
48,662
23,962
7,700
6,300
101, 196
Underfeed
stoker
No.
195
452
333
135
37
5
1
1,158
Capacity
3,252
17,118
24,489
19,311
11,627
3,780
3,111
82,688
Overfeed
stoker
No.
26
114
84
64
25
3
1
317
Capacity
440
4,347
6,220
9,269
7,675
2,519
2,074
32,544
Total
No.
263
717
528
538
140
17
5
2,208
Capacity
4,395
27,171
38,872
77,242
43,264
13,999
11,485
216,428
-------
TABLE B-10.
DISTRIBUTION OF INDUSTRIAL/COMMERCIAL PACKAGE,
STOKER, WATER-TUBE BOILERS (1971)
Size range.
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Si
1
No.
0
103
98
351
206
113
1
872
jreader
stoker
Capacity
0
534
1,641
13,314
15,161
16,222
251
47,123
Und
st
No.
532
1,926
455
1,054
617
45
1
3,630
erfeed
.oker
Capacity
637
4,808
7,589
39,941
45,482
6,437
259
105,153
Ov
s
No.
28
114
62
268
157
22
1
652
erfeed
toker
Capacity
33
594
1,025
10,144
11,550
3,089
250
26,685
1
No.
560
1,143
615
1,673
980
180
3
5,154
Potal
Capacity
670
5,936
10,255
63,399
72,193
25,748
760
178,961
-------
TABLE B-ll. DISTRIBUTION OF WATER-TUBE BOILER SALES BY FUEL (1969-1975)
Size range ,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0,
>10. 0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Fuel
Pul ver ized
coa 1
No.
0
0
0
0
7
11
11
29
Capacity
0
0
0
0
1,325
4, 260
6,835
12,420
Spreader
stoker
coal
No.
0
2
26
35
69
5
137
Capacity
0
50
1,150
2,758
12, 179
1,600
17,737
Underfeed
stoker
coal
No.
2
10
5
17
Capacity
20
182
152
354
Overfeed
stoker
coal
No.
0
1
27
11
5
44
Capaci ty
0
25
989
840
750
2,604
Residual and
distillate
oil
No.
24
402
664
474
450
43
9
1
2,067
Capacity
240
8,090
25,313
36,320
69,518
15,635
6,350
6,024
167,490
Natural
C(as
No.
31
935
1,537
1,251
696
53
7
0
4,510
Capacity
282
18,458
58,091
90,279
103,836
18,041
4,850
0
293,837
Total
No.
57
1,350
2,259
1,771
1,227
112
27
1
6,804
Capacity
542
26,805
85,695
130,197
187,608
39,536
18,035
6,024
494,442
to
I
-------
TABLE B-12. DISTRIBUTION OF FIELD-ERECTED, WATER-TUBE
BOILER SALES BY FUEL (1969-1975)
W
I
M
00
Size range,
106 Btu/h
>0.4 to 1.5
>1. 5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Pul ver ized
coa 1
No. Capacity
5 994
11 4,260
11 6,835
27 12,089
Spreader
stoker
~NoT"
1
8
12
52
5
78
coal
Capacity
15
345
965
9, 134
1,600
12,059
Underfeed
stoker coal
No.
3
2
5
Capacity
55
46
101
Overfeed
stoker coal
No.
8
4
4
16
Capacity
277
279
562
1,118
Oil
No.
121
199
166
337
43
9
1
876
Capac i ty
2,427
7,594
12,712
52,138
15,635
6,530
6,024
102,880
Natural
gas
No.
2BC
461
436
52^
44
7
1,75:
Capacity
5,537
17,437
31,598
7,787
15,635
4,850
152,934
Total
No.
405
678
620
920
103
27
.1
2,75?
Capacity
8,044
25,699
45,554
140,705
37,130
18,035
6,024
281,181
-------
TABLE B-13. DISTRIBUTION OF PACKAGE WATER-TUBE BOILER SALES BY FUEL (1969-1975)
Size range,
106 Btu/h
> 0 . 4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Fuel
Pulverized
coal
No.
0
0
0
0
2
0
2
Capacity
0
0
0
0
331
0
331
Spreader
stoker
coa 1
No.
0
1
18
23
17
0
59
Capacity
0
35
805
1,793
3,045
0
5,678
Underfeed
stoker
coal
No.
2
7
3
12
Capac i ty
20
127
106
253
Overfeed
stoker
coal
No.
0
1
19
7
1
28
Capaci ty
0
25
712
561
188
1,485
Residual and
distillate oil
No.
24
281
465
308
113
0
1,191
Capacity
240
5,663
17,719
23,608
17,380
0
65,610
Natural
qas
No.
31
655
1,076
813
174
9
2,758
Capacity
282
12,921
40,664
58,681
25,959
2,406
140,913
Total
No.
57
945
1,581
1,151
307
9
4,050
Capacity
542
18, 77}
60,006
84,643
46,903
2,406
213,271
td
I
-------
TABLE B-14. DISTRIBUTION OF OIL-FIRED, WATER-TUBE BOILER SALES (1969-1975)
I
KJ
O
>0. 4 to 1.5
>1. 5 to 10. 0
>10.0 to 25.0
>25.0 to 50.0
>50.0 to 100.0
>100. 0 to 250. 0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total
Residual
oil
No.
21
354
584
417
396
38
8
1
1,819
Capacity
211
7,119
22,275
31,962
61,176
13,759
5,588
6,024
143,114
Distillate
oil
No.
3
48
80
57
54
5
1
248
Capacity
29
971
3,038
4,358
8,342
1,876
762
19,376
Total
No.
24
402
664
474
450
43
9
1
2,067
Capacity
240
8,090
25,313
36,320
69,518
15,635
6,350
6,024
167,490
-------
TABLE B-15. DISTRIBUTION OF WATER-TUBE BOILER POPULATION (1977) BY FUEL
I
NJ
Silrf ranqa,
IO*1 Btu/h
>0.< to 1.5
>1.5 to 10.0
>10.0 to 25. 0
>25.0 to 50.0
>50.0 to 100.0
>100.0 to 250.0
>250.0 to 500.0
>500.0 to 1500.0
>1500
Total!
Pulv«rli»d
COB 1
Ho.
0
0
0
0
0
467
111
(4
11
733
Capacity
0
0
0
0
0
70,000
6), 000
44,700
26,400
204,100
Spreader
atokar
coa 1
Ho.
0
103
142
521
343
504
83
9
3
1,708
Capacity
0
500
2,400
19,900
25,400
73,700
25,600
7,700
6, 300
161 , 500
Under faed
atoker
coal
No.
532
928
657
1,509
950
180
3B
5
1
4,800
Capacity
500
4, »00
11,000
57,200
71,000
25,700
11,900
3,800
3, 100
189, 000
fVl«l
Ov«r f «ed
atokar
coa 1
Ho.
28
114
89
402
249
90
26
3
1
1,002
Capacity
30
(00
1,500
15,100
ie. 300
12,900
8,000
2,500
2, 100
61,030
Real dual
oil
Ho.
1,173
3,215
2,731
5,022
2,205
1,237
300
62
8
15,953
Capacity
1.400
16 , 500
44,400
182,800
162,200
192,000
99,800
47 , 400
19,200
755,700
Dlatlllau
oil
Ho.
2,92(1
2,958
659
914
298
202
41
7
1
8,000
Capacity
3,500
11,800
10.100
31,800
23,900
30.200
^ 14,500
5,200
2, 300
132,300
natural
aaa
Ho.
2,414
J.616
2,535
4,163
2,7»5
1,516
339
103
40
11,291
Capacity
2.900
16,100
43.100
179, SCO
203,200
237,500
112,600
77,100
172,800
1,045,900
Total
Ho.
7,075
10, 934
6,11)
13,231
6,140
4,266
1,018
253
65
50,4tl
Capacity
1.330
SI,' 000
112.500
466,700
503,000
632,000
335,400
lag, 400
232,200
2, 549,530
-------
larger sizes. It was therefore assumed that the data from the
Walden boiler study would follow the same general pattern, with
the number of boilers in smaller sizes being somewhat higher
because of the smaller average capacity per unit reflected in
these data. By trial and error, it was determined that the
following percent distribution was consistent with the Walden
data on population and capacity, and also consistent with the
general pattern of the sales data:
Capacity by
size categories, 10^ Btu/h
0.4 to 1.5 1.5 to 10 10 to 25 25 to 50 Total
Percentage of 21.5 33.5 30 15 100
capacity
No. of boilers 174,795 272,355 243,900 121,950 813,000
Capacity, 174,795 47,366 13,937 3,252 239,350
106 Btu/h
The capacity for each size category was determined by
applying the assumed percent distribution to the data from the
Walden boiler study. The population figures were derived by
assuming the average boiler size in each category to be the
midpoint of the capacity range. The figures derived from the
assumed distribution totaled close to those given in the Walden
study; hence, the derived data were considered sufficiently
accurate for the purposes of this study.
The fuel consumption data shown in the Walden boiler study
(Table 3-2, p. 56) were converted to Btu's as follows:
Coal: (11 x 106 tons) x (24 x 106 Btu/ton) - 264 x 1012 Btu
Residual oil: (98 x 106 bbl) x (42 gal/bbl) x (149,000 Btu/gal)
= 613 x 1012 Btu
Distillate oil: (69 x 10G bbl) x (42 gal/bbl) x (139,000 Btu/ga.
= 403 x 1012 Btu
Gas: (1.12 x 1012 ft3) x (1000 Btu/ft3) = 1120 x 1012 Btu
Total = 2400 x 1012 Btu/yr
B-22
-------
The percentage contributed by each fuel to the total consumption
was then calculated:
Distribution by fuel, percent
Coal
Residual oil
Distillate oil
Gas
11
25
16
46
100.0
Capacity was assumed to be distributed proportional to fuel
consumption, and was calculated on the basis of these percentages
Fuel
Coal (11%)
Residual oil (25.6%)
Distillate oil (16.7%)
Gas (46.7%)
Total
Capacity, 10 Btu/h
89,430
208,128
135,771
379,671
813,000
The distribution of total capacity among the various types
of fire-tube boilers (Scotch, firebox, HRT, and others) was
derived from data in the Battelle design study (Table A-3):
1)
Data in the 10 to 50 boiler hp (0.335 to 1.67 x 10
Btu/h) category were assumed to be applicable to the
0.4 to 1.5 x 10 Btu/h category of the present study.
The normalized percentages for this category are shown
below.
Battelle percentages Normalized percentages
Scotch
Firebox
HRT
Other
15
25
5
3
31
52
10
7
2)
10
Data from the 51 to 100 boiler hp (1.67 to 3.35 x ^ ,
Btu/h) and the 101 to 300 boiler hp (1.67 to lO.OgX 10
Btu/h) were taken to represent the 1.5 to 10 x 10
Btu/h category.
B-23
-------
Scotch
Firebox
HRT
Other
20
25
10
3.5
30
30
15
5
Battelle percentages Normalized percentage Percentage used
51 to 100 101 to 30_0_ 51 to 100 101 to 300 1.5 to 10 x 1Q6
34 37 36
43 38 40
17 19 18
66 6
For sizes 10 to 25 x 106 Btu/h and 25 to 50 x 10 Btu/h in
the present study, the distributions in Battelle for 10 to 16 x
106 Btu/h and 25 to 50 x 106 Btu/h were considered applicable.
The normalized percentages are:
Battelle Normalized Battelle Normalized
percentage percentage percentage percentage
10 to 16 x 106 10 to 25 x 106 25 to 50 x 106 25 to 50 x 10
Btu/h Btu/h Btu/h Btu/h
Scotch
Firebox
HRT
Other
30
25
20
3
38
32
26
4
10
10
1
0
48
48
4
0
Table B-16 shows data from the Walden boiler study distributed
by boiler size and fuel type. Tables B-17, B-18, B-19, and B-20
show the data obtained by using the distribution by boiler type
(given above) for each type of fuel. The distribution factors
were assumed to be independent of type of fuel.
Next, the ABMA sales data were tabulated. The size cate-
gories used by ABMA were matched with those for the present
study:
ABMA size range Present study size range
Boiler hp 106 Btu/h 106 Btu/h
15 to 50 0.502 to 1.67 0.5 to 1.5
50 to 300 1.670 to 10.0 1.5 to 10.0
300 to 700 10.0 to 23.4 10.0 to 25.0
ABMA data gave the size of the boiler and the number of
units sold. Capacity was calculated for each category, after
excluding the 27 percent, that was assumed to represent replace-
ment boilers.
B-24
-------
TABLE B-16.
COMMERCIAL AND INDUSTRIAL FIRE-TUBE BOILER POPULATION (1967)
REDISTRIBUTED INTO THE STUDY-SIZE CATEGORIES3
CO
i
Size range,
106 Btu/h
>0.4 to 1. 5
>1.5 to 10
>10 to 25
>25 to 50
Total
Coal
No.
19,227
5,210
1, 533
358
26,328
Capacity
19,227
29,959
26,829
13,415
89,430
Residual oil
No.
44,748
12,126
3,568
833
61,275
Capacity
44,748
69,723
62,438
31,219
208,128
Distillate oil
No.
29,191
7,910
2,327
543
39,971
Capacity
29,191
45,483
40,731
20,366
135,771
Natural gas
No.
81,629
22, 120
6,509
1,518
111,776
Capacity
81,629
127,190
113,902
56,950
379,671
Total
No.
174,795
47,366
13,937
3,252
239,350
Capacity
174,795
272,355
243,900
121,950
813,000
Ehrenfeld et al., 1971.
-------
TABLE B-17. DISTRIBUTION OF COMMERCIAL/INDUSTRIAL COAL-FIRED
FIRE-TUBE BOILER POPULATION BY TYPE (1967)
CO
I
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
5,960
1,876
583
172
8,591
Capacity
5, 960
10,785
10, ?95
6,439
33,379
Firebox
No.
9,998
2,084
491
172
12,745
Capacity
9,998
11,984
8,585
6,439
37,006
HRT
No.
1,923
938
399
14
3,274
Capacity
1,923
5,393
6,976
537
14,829
Others
No.
1, 346
312
60
0
1,718
Capacity
1,346
1,797
1,073
0
4,216
Total
No.
19,227
5,210
1,533
358
26,328
Capacity
19,227
29,959
26,829
13,415
89,430
-------
TABLE B-18. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL RESIDUAL-OIL-FIRED
FIRE-TUBE BOILER POPULATION BY TYPE (1967)
03
I
IsJ
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
13,872
4,365
1,356
400
19,993
Capacity
13,872
25, 100
23,726
14,985
77, 683
Firebox
No.
23,269
4,850
1,142
400
29, 661
Capacity
23,269
27,889
19,980
14,985
86,123
HRT
No.
4,475
2, 183
928
0
7,586
Capacity
4,475
12,550
16, 234
0
33,259
Others
No.
3,132
728
142
33
4 ,035
Capacity
3,132
4,184
2,498
1,249
11,063
TotaJ
No.
44,748
12,126
3,568
833
61,275
Capacity
44,748
69,723
62,438
31,219
208,128
-------
TABLE B-19. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL DISTILLATE-
OIL-FIRED FIRE-TUBE BOILER POPULATION BY TYPE (1967)
W
I
K)
00
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
9,049
2,848
884
261
13,042
Capacity
9,049
16,374
15,478
9,776
50,677
Firebox
No.
15,179
3,164
745
261
19,349
Capacity
15, 179
18,193
13,034
9,776
56,182
HRT
No.
2,919
1,424
605
21
4,969
Capacity
2,919
8,187
10,590
814
22,510
Others
No.
2,044
474
93
0
2,611
Capacity
2,044
2,729
1,629
0
6,402
Total
No.
29,191
7,910
2,327
543
39,971
Capacity
29,191
45,483
40,731
20,366
135,771
-------
TABLE B-20. DISTRIBUTION OP INDUSTRIAL/COMMERCIAL NATURAL-
GAS-FIRED FIRE-TUBE BOILER POPULATION BY TYPE (1967)
w
I
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10. 0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
25,305
7,963
2,473
729
36,470
Capacity
25,305
45,788
43,283
27, 336
141,712
Firebox
No.
42, 447
8,848
2,083
729
54 ,107
Capacity
42,447
50,876
36,449
27,336
157,108
HRT
No.
8,163
3,982
1,692
60
13,897
Capacity
8,163
22,894
29,615
2,278
62,950
Others
No.
5,714
1,327
261
0
7,302
Capacity
5,714
7,632
4,555
0
17,901
Total
No.
81,629
22,120
6,509
1,518
111,776
Capacity
81,629
127,190
113,902
56,950
379,671
-------
Size
No. of No. of boilers Capacity,
Btu/boiler hp boilers (adjusted) 1C)6 Btu/h
712
519.8
261.0
15 boiler hp 33,480
The basic data aggregated from the sales records are shown
below:
Capacity range, 10^ Btu/h
0.5 to 1.5 15 to 10 10 to 25
No. of boilers
Capacity
4,373 27,021 4,331
4,362 139,584 76,215
To distribute these data by fuel type, the records on oil,
gas, and combination firing were examined. These are shown
below:
Number of boilers
Year
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
Oil-fired
2,827
2,131
1,900
2,319
1,545
1,538
1,741
2,088
1,536
1,294
18,919
Gas-fired
Combination-
fired Total
2,
1,
1,
2,
1,
1,
177
819
868
427
587
166
897
808
726
439
1,
1,
1,
1,
1,
1,
1,
1,
1,
1,
598
564
524
838
600
718
577
922
476
233
6,
5,
5,
6,
4,
4,
4,
4,
3,
2,
602
514
292
584
732
422
215
818
738
966
13,914
16,050
48,883
Total number of oil- and gas-fired units (from sales data)
= 32,833
The boiler population after adjustments for replacement
boilers had a combined capacity of 220,200 x 106 Btu/h as com-
pared with a population shown by the Walden boiler study of
813,000 x 10 Btu/h. The general trend toward increased use of
oil (instead of gas) that started in 1971 was not specifically
considered in figuring the distribution of the population by fuel
type. The fractions were derived as averages over the last 10
years of sales:
B-30
-------
I Q
Fraction for oil = *' = 0.576
J Z. i
Fraction for gas - .O'QTO = 0.4
24
For this derivation, it was assumed that the combined firing
v
of gas and oil in boilers would have the same relative fuel dis-
tribution as is found in single fuel boilers.
The distribution between residual oil and distillate oil was
based on percentages derived from the Walden boiler study and
presented earlier. The distribution is as follows:
1 9
Residual oil = 613 x 10 Btu/yr
Distillate oil = 403 x 1012 Btu/yr
Total oil - 1016 x 1012 Btu/yr
Fraction residual = - • ., . = 0.603
1016
4 o o
Fraction distillate = TTTTC = 0.397
1016
Using these factors and the boiler population data given
above, Table B-21 was developed, to show the population and
capacity of boilers sold between 1966 and 1975 on the basis of
size and fuel type.
Sales records also showed that no coal-fired fire-tube
boilers were sold in that period.
To distribute the sales of fire-tube boilers by type of
fire-tube (i.e., Scotch, Firebox, HRT, other), data on the units
installed in 1970 were taken from the design study (p. A-22).
These values were normalized to obtain the distribution by type.
The percentages are given in terms of the Battelle size range,
which corresponds to the range for this study as follows:
10 to 50 = 0.4 to 1.5 x 106 Btu/h
50 to 100 and
101 to 300 boiler hp = 1 . 5 to 10 x 10 Btu/h
10 to 16 x 106 Btu/h = 10 to 25 x 106 Btu/h
17 to 100 x 106 Btu/h - 25 to 100 x 106 Btu/h
B-31
-------
TABLE B-21. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL
FIRE-TUBE BOILER SALES BY FUEL (1966-1975)
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10
>10 to 25
Total
Residual oil
No.
1,519
9,385
1,504
12,408
Capacity
1,515
48,481
26,472
76,468
Distillate oil
No.
1,000
6,179
991
8,170
Capacity
998
31,919
17,428
50,345
Natural gas
No.
1,854
11,457
1,836
15,147
Capacity
1,849
59,184
32,315
93,348
Total
No.
4,373
27,021
4,331
35,725
Capacity
4,362
139,584
76,215
220,161
-------
Type of Fire-tube Boilers, by percentage
10 to
boiler
50
hp
50 to
boiler
Normal-
Scotch
Firebox
HRT
Other
Battelle
11
18
nil
9
10 to
ized
28.9
47.4
nil
23.7
100.0
16 x
Battelle
Scotch
Firebox
HRT
Other
44
40
nil
1
Battelle
22
17
nil
4
106 Btu/h
Normalized
51.8
47.0
nil
1.2
100
hp
Normal-
ized
51.2
39.5
nil
9.3
100.0
101 to
boiler
Battelle
41
35
1
2
300
hp
Normal-
ized Used
51.9
44.3
1.3
2.5
51
42
1
6
100.0 100
17 to 100
Battelle
5
1
nil
x 106 Btu/h
Normalized
83.3
16.7
nil
nil
100.0
100.0
An approximate percentage was used for the combined factor
for the 1.5 to 10 x 10 Btu/h category, because earlier calcula-
tions showed that a more precise treatment produced no significant
change in the approximate values. The above factors were applied
to the sales data to develop Tables B-22, B-23, and B-24, which
show the distribution of fire-tube boiler sales by size, by fuel,
and by type.
The total fire-tube boiler population, distributed by size
and then by fuel, was developed by combining the data from the
Walden boiler study with the ABMA sales data to obtain Table B-25.
The total fire-tube boiler population by fuel, distributed by
size and by type, was developed by combining the appropriate data
from Walden with ABMA sales data to obtain Tables B-26, B-27,
B-28, and B-29.
CAST IRON BOILERS
Capacity estimates for cast iron boilers were based on
information from the Walden boiler study (Tables 4-1 and 4-2),
which shows:
B-33
-------
TABLE B-22. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL RESIDUAL-
OIL-FIRED FIRE-TUBE BOILER SALES BY TYPE (1966-1975)
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
Total
Scotch
No.
439
4,786
779
6,004
Capacity
438
24,725
13,712
38,875
Firebox
No.
720
3,942
707
5, 369
Capacity
718
20,362
12,442
33,522
HRT
No.
0
94
0
94
Capacity
485
485
Others
No.
360
563
18
941
Capacity
359
2,909
318
3,586
Total
No.
1,159
9,385
1,504
12,408
Capacity
1,515
48,481
26,472
76,468
-------
TABLE B-23. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL
DISTILLATE-OIL-FIRED FIRE-TUBE BOILER SALES BY TYPE (1966-1975)
w
I
U)
Ln
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
Total
Scotch
No.
289
3,151
513
3,953
Capacity
288
16,279
9,028
25,595
Firebox
No.
474
2,595
466
3, 535
Capacity
473
13,406
8,191
22,070
HRT
No.
0
62
0
62
Capacity
319
319
Others
No.
237
371
12.
620
Capacity
237
1,915
209
2,361
Total
No.
1,000
6,179
991
8,170
Capacity
998
31,919
17,428
50,345
-------
TABLE B-24. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL NATURAL -
GAS-FIRED FIRE-TUBE BOILER SALES BY TYPE (1966-1975)
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
Total
Scotch
No. [Capacity
536
5,843
951
7,330
534
30,184
16,739
47,457
Firebox
No.
879
4,812
863
6,554
Capacity
876
24,857
15,188
40,921
HRT
No.
0
115
0
115
Capacity
592
592
Others
No.
439
687
22
1,148
Capacity
439
3,551
388
4,378
Total
No.
1,854
11,457
1,836
15,147
Capacity
1,849
59,184
32,315
93,348
-------
TABLE B-25,
DISTRIBUTION OF TOTAL FIRE-TUBE BOILER POPULATION
BY FUEL (1977)
w
I
U)
Size range,
10& Btu/h
> 0 . 4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Coal
No.
19,227
5,210
1,533
358
26,238
Capacity
19,227
29,959
26,829
13,415
89,430
Residual oil
No.
46,267
21,511
5,072
833
73,683
Capacity
46,263
118,204
88,910
31,219
284,596
Distillate oil
No.
30,191
14,089
3,318
543
48,141
Capacity
30,189
77,402
58,159
20,366
186,116
Natural gas
No.
83,483
33,577
8,345
1,518
126,923
Capacity
83,478
186,374
146,217
56,950
473,019
Total
No.
179,168
74,387
18,268
3,252
275,075
Capacity
179,157
411,939
320,115
121,950
1,033,161
-------
TABLE B-26. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL COAL-FIRED
FIRE-TUBE BOILER POPULATION BY TYPE (1977)
I
LO
OD
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
5,960
1,876
583
172
8,591
Capacity
S, 960
10,785
10,195
6,439
33,379
Firebox
No.
9,998
2,084
491
172
12,745
Capacity
9,998
11,984
8,585
6,439
37,006
HRT
No.
1,923
938
399
14
3,274
Capacity
1,923
5,393
6,976
537
14,829
Others
No.
1,346
312
60
0
1,718
Capacity
1,346
1,797
1,073
4,216
TotalL
No.
19,227
5,210
1,533
358
26,328
Capacity
19,227
29,959
26,829
13,415
89,430
-------
TABLE B-27. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL
RESIDUAL-OIL-FIRED FIRE-TUBE BOILER POPULATION BY TYPE (1977)
w
i
OJ
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
14 ,311
9,151
2,135
400
25,997
Capacity
14,310
49, 825
37,438
14,985
116, 558
Firebox
No.
23,989
8,792
1,849
400
35,030
Capacity
23,987
48,251
32,422
14,985
119,645
No.
4,475
2,277
928
0
7,680
HRT
Capacity"
4,475
13,035
16,234
0
33,744
Others
No.
3,492
1,291
160
33
4,976
Capacity
3,491
7,093
2,816
1,249
14,649
Total
No.
46,267
21,511
5,072
833
73,683
Capacity
46,263
118,204
88,910
31,219
284,596
-------
TABLE B-28. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL
DISTILLATE-OIL-FIRED FIRE-TUBE BOILER POPULATION BY TYPE (1977)
tt)
I
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
9,338
5,999
1,397
261
16,995
Capacity
9,337
32,653
24, 506
9,776
76,272
Firebox
No.
15,653
5,759
1,211
261
22,884
Capacity
15,652
31,599
21,225
9,776
78,252
HRT
No.
2,919
1,486
605
21
5,031
Capacity
2,919
8, 506
10,590
814
22,829
Others
NO.
2,281
.845
105
0
3., 231
Capacity
2,281
4,644
1,338
0
8,763
Total
No.
30,191
14,089
3,318
543
48,141
Capacity
30,189
77,402
58,159
20,366
186,116
-------
TABLE B-29. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL NATURAL-
GAS-FIRED FIRE-TUBE BOILER POPULATION BY TYPE (1977)
CO
I
Size range,
106 Btu/h
>0.4 to 1.5
>1.5 to 10.0
>10.0 to 25.0
>25.0 to 50.0
Total
Scotch
No.
25,851
13,806
3,424
729
43,800
Capacity
25,839
75,972
60,022
27,336
189,169
Firebox
No.
43, 326
13,660
2,946
729
60,661
Capacity
43,323
75,733
51,637
27,336
198,029
HRT
No.
8,163
4,097
1,692
60
14 ,012
Capacity
8,163
23,486
29,615
2,278
63 , 542
Others
No.
6,153
2,014
283
0
8, 450
Capacity
6,153
11,183
4,943
0
22,279
Total
No.
83,483
33,577
8,345
1,518
126,923
Capacity
83,478
186,374
146,217
56,950
473,019
-------
No. of units Capacity
1270 x 103 757 x 106 pounds steam/h
(assumes 1000 Btu/lb of steam)
Annual fuel consumption data from the same source (Table 3-2)
were used to derive the distribution of boilers by fuel type.
Coal = (11 x 106 tons/yr) x (24 x 106 Btu/ton) = 264 x 1012 Btu/yr
Residual oil = (56 x 106 bbl/yr) x (42 gal/bbl) x (149 x 103 Btu/gal)
= 350 x 1012 Btu/yr
Distillate oil = (37 x 106 bbl/yr) x (42 gal/bbl) x (139 x 10
Btu/gal) = 216 x 1012 Btu/yr
Gas - (1.03 x 1012 ft3/yr) x (1000 Btu/ft3) - 1030 x 1012 Btu/yr
Total = 1860 x 1012 Btu/yr
Distribution by fuel type, percentage
Coal 14
Residual oil 19
Distillate oil 12
Gas 55
100
The split between residual oil (62 percent) and distillate
oil (38 percent) was also used in subsequent calculations.
Application of these percentages to the total shown by the
Walden boiler study yields the following:
No. of boilers (1,270,000)
Coal 177,800
Residual oil 241,300
Distillate oil 152,400
Gas 698,500
Capacity (757 x 1012 Btu/h)
Coal (14%) 106.0
Residual oil (19%) 143.8
Distillate oil (12%) 90.8
Gas (55%) 416.4
B-42
-------
Since cast iron boilers are concentrated in two size cate-
gories, it is reasonable to assume that the boiler size distri-
bution is the same for all fuels. The application of the per-
centages for fuel consumption to both boiler population and
boiler capacity was based on this assumption.
The next step was to assemble data from the Hydronics
Institute on cast iron boiler shipments from 1965 to 1975. The
data were regrouped into the size categories used for the
present study:
Hydronics Institute Present study
200,000 to 249,999 Btu/h <0.4 x 106 Btu/h
250,000 to 449,999 Btu/h <0.4 x 1()6 Btu/h
450,000 to 949,999 Btu/h 0.4 to 1.5 x 106 Btu/h
950,000 to 1,549,999 Btu/h 0.4 to 1.5 x 106 Btu/h
>1,550,000 Btu/h 1.5 to 10 x 10^ Btu/h
The assumption was made, based upon information from the
Hydronics Institute, that 50 percent of the sales were replace-
ment boilers. It was further assumed, on the basis of Walden
field studies, that 80 percent of the nonresidential units were
commercial boilers and 20 percent were industrial, and all
boilers having capacity less than 200,000 Btu/h were residential
units.
Table B-30 shows basic population data from the Hydronics
Institute for boilers of more than 200,000 Btu/h capacity,
adjusted downward to reflect the 50 percent for replacement
boilers. Capacity was calculated on the assumption that the
midpoint of the range was equal to the average size, except for
boilers of more than 1,550,000 Btu/h capacity, which were assumed
to have an average size of 3,400,000 Btu/h.
These calculations are illustrated for oil-fired boilers in
the 1.5 to 10 x 10 Btu/h category:
Included sizes, Sales, Average size, Capacity,
Btu/h NO. of boilers Btu/h Btu/h
1,550,000 and over 8,040 3,400,000 27,336,000,000
B-43
-------
TABLE B-30. SUMMARY OF THE HYDRONICS INSTITUTE SALES DATA FOR
INDUSTRIAL/COMMERCIAL CAST IRON BOILERS FOR 1965-1975 (ADJUSTED BY 50%)
W
i
Size range,
106 Btu/h
<0.4
>0.4 to 1.5
>1. 5 to 10.0
Total
Fuel
Stoker
coal
No.
1,277
530
222
2, 029
Capacity
342
705
755
1,802
Residual
oil
No.
39, 489
13,704
4, 985
58, 178
. Capacity
11,026
-11,753
16,948
39,727
Distillate
oil
No.
24,203
8,399
3,055
. 35,657
Capacity
6,758
7,204
10,388
24,350
Natural
qas
No.
72,261
30,219
8,146
110,626
Capacity
19,691
26,019
27,696
73,406
Total
No.
137,230
52,852
16,408
206,490
Capacity
37,817
45,681
55,787
139,285
-------
The residual oil and distillate oil capacities were dtrived on
the basis of the 62 percent and 38 percent figures from the
Walden boiler study.
Table B-31 shows the number of boilers and the capacity data
from the Walden boiler study, distributed by size and fuel type,
using the following ratios derived from Hydronics Institute sales
data.
Percentage Distribution of Cast Iron
Boilers from Sales Data (1965-1975)
Size range
<0.4 0.4 to 1.5 1.5 to 10
Number, Capacity.- Number, Capacity, Number, Capacity,
Fuel percent percent percent percent percent percent
Coal
Residual oil
Distillate oil
Gas
Average cast iron boiler size derived from Walden data:
757 X 1Q9 Bt"/h 0.596 Btu/h
1,270 x 10
Average cast iron boiler size derived from Hydronics Institute data:
9
63
68
68
65
19
28
28
27
26
24
24
27
39
30
30
35
11
8
8
8
42
42
42
38
139 X 1C) = 0.671 Btu/h
207 x 10
Reasonable comparison suggests that there has been no great
shift in size distribution.
In Table B-32, data from B-30 and B-31 are combined to give
the present estimate for all cast iron boilers.
In Tables B-33 and B-34, data from B-32 are divided to
reflect the 80 percent commercial and 20 percent industrial
usage.
B-45
-------
TABLE B-31. DISTRIBUTION OF INDUSTRIAL/COMMERCIAL
CAST IRON BOILER POPULATION (1967)
w
I
Size range,
106 Btu/h
<0.4
>0.4 to 1.5
>1.5 to 10.0
Total
Fuel
Stoker
COa I
No.
112, 010
46, 230
19,560
177,800
Capacity
20,140
41, 340
44, 520
Res idual
oil
No.
164,080
57,910
19, 300
106,000 1 241,290
Capaci ty
40,260
43,140
60,400
143,800
Distillate
oil
No.
103,630
36,580
12, 190
152,400
Capacity
25,420
27,240
38,140
90,800
Natural
qas
No.
454,030
188,600
55,880
698,570
Capacity
112,430
145,740
158,230
416,400
Total
No.
833,750
329,320
106,930
1, 270, 000
Capac i ty
138,250
257,460
301,290
757,000
Walden, 1971.
-------
TABLE B-32. DISTRIBUTION OF TOTAL CAST IRON BOILER POPULATION BY FUEL (1977)
W
i
Size range,
106 Btu/h
<0. 4
> 0 . 4 to 1.5
>1. 5 to 10. 0
Total
Fuel
Stoker
coal
No.
113,287
46,760
19,782
179,829
Capacity
20,500
42,000
45, 300
107,800
Residual
oil
No.
203,569
71,614
24,285
299,468
Capacity
51,300
54,900
77,300
183, 500
Distillate
oil
No.
127,833
44,979
15,245
188,057
Capacity
32,200
34,400
48,500
115,100
Natural
gas
No.
526,291
218,819
64,026
809,136
Capacity
132,100
171,800
185,900
489,800
Total
No.
970,980
382,172
123,338
1,476,490
Capacity
236,100
303,100
357,000
896,200
-------
TABLE B-33. DISTRIBUTION OF THE COMMERCIAL/INSTITUTIONAL
CAST IRON BOILER POPULATION (1977)
td
I
Size range,
106 Btu/h
<0.4
>0.4 to 1.5
>1.5 to 10.0
Total
Fuel
Stoker
coal
No.
90,630
37,408
15,826
143,864
Capaci ty
16,400
33,600
36,200
86, 200
Residual
oil
No.
162, B55
57,291
19,428
239,574
Capacity
41 ,000
43,900
61,900
186,800
Distillate
oil
No.
102,266
35,983
12, 196
150,445
Capacity
25,700
27,600
38,800
92,100
Natural
gas
No.
421,033
175,055
51,221
98,671
Capacity
105, 700
137,400
148,700
285,600
Total
No.
776,784
305,737
't8,671
1, 181,192
Capacity
188,800
242,500
285,600
716,900
co
-------
TABLE B-34. DISTRIBUTION OF THE INDUSTRIAL CAST IRON BOILER POPULATION (1977)
td
I
Size ranqe,
106 Btu/h
<0.4
> 0 . 4 to 1.5
>1 .5 to 10.0
Total s
Fuel
Stoker
COd 1
No.
22,657
9, 352
.1,956
35,965
Capjr 1 1 y
4, 100
8, 400
9, 100
21, 600
Res idual
oil
No.
40,714
14, 323
4,857
59,894
Capac i ty
10, 300
11,000
15,500
36,800
Distillate
oil
No.
25, 567
8,996
3,049
37,612
Capac i ty
6,400
6,900
9,700
23,000
Natural
gas
No.
105,258
43,764
12,805
161,827
Capacity
26,400
34,400
37,200
98,000
Total
No.
194,196
76,435
24,667
295,298
Capacity
47,200
60,700
71,500
179,400
-------
APPENDIX C
DETAILED BOILER POPULATION DATA SHEETS
This appendix presents detailed summaries of the population
of industrial and commercial boilers that were in place in 1977.
The tables, which give ~data on the important characteristics of
the boiler population, are organized in the following manner:
Information Table No.
Total Industrial/Commercial Boiler Population
Total Water-tube Boiler Population
Distribution of the Field-erected Water-tube
Boiler Population
Distribution of the Package Water-tube
Boiler Population
Total Fire-tube Boiler Population
Total Fire-tube Boiler Population by Fuel
Distribution of the Fire-tube Boiler
Population by Fuel by Type
Total Cast Iron Boiler Population
Total Cast Iron Boiler Population by Fuel
Distribution of the Commercial Water-tube
Boiler Population
Distribution of the Commercial Fire-tube
Boiler Population
Distribution of the Commercial Cast Iron
Boiler Population
Distribution of the Industrial Water-tube
Boiler Population
Distribution of the Industrial Fire-tube
Boiler Population
Distribution of the Industrial Cast Iron
Boiler Population
C-l
C-2
C-3 through C-9
C-10 through C-16
C-17
C-18 through C-21
C-22 through C-37
C-38
C-39 through C-42
C-43 through C-49
C-50 through C-65
C-66 through C-69
C-70 through C-76
C-77 through C-92
C-93 through C-96
C-l
-------
Table C-l. THE 1977 POPULATION OF
INDUSTRIAL/COMMERCIAL BOILERS
Boiler classification: All types of boilers
Fuel and firing mechanism: All fuels
Class population 1
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional 1
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
.802.060
Capacity,
thermal MW
(10<5 Btu/h)
1,313,340 (4,4*82,230)
295,130
506,930
402,765 (1.374.690)
910,575 (3,107,440)
970,980
568,415
208, 659
69,180 (236,100)
143,820 (490,730)
240,270 (820,100)
r,081 126,770 (432,600)
16,483 178,350 (608,700)
6,840 147,380 (503,000)
4,266 185,160 (632,000)
1,018 98,280 (335,400)
253 56,080 (191,400)
65 68,050 (232,200)
C-2
-------
Table C-2. THE 1977 POPULATION OF
INDUSTRIAL/COMMERCIAL WATER-TUBE BOILERS
Boiler classification:
Water-tube
Fuel and firing mechanism:
All fuels
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
50.495
12, 799
37.696
1,018
253
Capacity,
thermal MW
(106 Btu/h)
747,930 (2,552,530)
109.285 (372,990)
638.645 (2,179,540)
7,
10,
6,
13,
6,
07 5
934
813
231
840
2
14
32
142
147
r450
,950
,980
,600
,380
(8.3
(51,
(112
(486
(503
3
0)
000)
i
r
i
500)
700)
000)
4.266 185,160 (632,000)
65
98,280 (335,400)
56,080 (191,400)
68,050 (232,200)
C-3
-------
TABLE C-3. THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING PULVERIZED COAL
Boiler oiassifixation: Water-tube (field-erected)
Fuel and firing mechanism: Pulverized coal
Capacity,
thermal MW
Number (106 Btu/h)
Class population 615 55,470 (189,300)
Distribution by heat-transfer medium
Supercritical steam 12 1,110 (3,800)
Steam (high-pressure) 603 54,360 (185,500)
Steam (low-pressure) °
Hot water °
Distribution by usage
Commercial-institutional
(space heating) 1£ 460 (1,600)
Industrial (space heating) 101 9,280 (31,700)
Industrial (process heat) 504 45,730 (156,000)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 0
Over 0.1 to 0.4 (0.4 to 1.5) 0
Over 0.4 to 2.9 (1.5 to 10) 0
Over 2.9 to 7.3 (10 to 25) 0 .
Over 7.3 to 14.7 (25 to 50) 0
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to 73.3 (100 to 250) 350 15,380 (52,500)
Over 73.3 to 146.5 (250 to 500) 190 18,370 (62,700)
Over 146.5 to 439.5 (500 to 1500) §1 13,980 (47,700)
Over 439.5 (1500) 11 7,740 (26,400)
C-4
-------
TABLE C-4. THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING COAL (SPREADER STOKER)
Boiler classification: Water-tube (field-erected)
Fuel and firing mechanism; Coal, spreader-stoker
Number
Class population 793
Distribution by heat-transfer medium
Supercritical steam 0
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
135
626
32
110
165
518
43
157
120
379
82
Capacity,
thermal MW
(106 Btu/h)
32,300 (110,200)
5.490 (18.700)
25,520 (87,100)
1,290
2,570
22,520
210
1,760
2,610
1,850
(4,400)
(8,800)
7,190 (24,500)
(76,900)
(700)
(6,000)
(8,900)
16,200 (55,300)
7,410 (25,300)
2,260 (7,700)
(6,300)
C-5
-------
TABLE C-5. THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING COAL (OVERFEED STOKER)
Rni ler classification: Water-tube (field-erected)
me] and firing mechanism: Coal, overf eed-stoker
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
329 9,
0
56 1,
260 7,
13
65 1,
80 2,
184 6,
0
0
0
26
120 1,
87 1,
67 2,
25 2,
3
1
Capacity, <«
thermal MW
(106 Btu/h)
770 (33,300)
660 (5,700)
720 (26,300)
390 (1,300)
090 (3,700)
620 (9,000)
060 (20,600)
120 (400)
320 (4,500)
880 (6,400)
840 (9,700)
260 (7,700)
730 (2,500)
620 (2,100)
C-6
-------
TABLE C-6.
THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING COAL (UNDERFEED STOKER)
Boiler classification: Water-tube 1
[field-erected)
Fuel and firing mechanism: Coal, underfeed-stoker
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
1.161 24,
0
197 4 ,
917 19,
47
268 3,
236 5,
657 15,
0
0
0
197
453 5,
333 7,
135 5,
37 3,
5 1,
1
Capacity,
thermal MW
(106 Btu/hJ
550 (83.800)
170 (14.200)
390 (66,200)
980 (3,400)
650 (12.400)
570 (19.000)
330 (52.400)
970 (3,300)
040 (17,200)
470 (25,500)
650 (19,300)
400 (11,600)
110 (3,800)
910 (3,100)
C-7
-------
TABLE C-7.
THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification; Water-tube (field-erected)
Fuel and firing mechanism: Residual oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
4.393
88.
4.305
1,120
573
2 .801
819
1,507
771
928
298
62
Capacity,
thermal MW
(106 Btu/h)
125,060 (426,800)
2.500
:8.500)
122.560 (418.300^
20.940
(76.300)
17.720
(66.200)
64.070 (322.000)
3,900 (13.300)
16,060 (54,800)
16,640 (56,800)
39,990 (136,500)
28,950 (98.800)
13.890 (47.400)
5,630 (19,200)
C-8
-------
TABLE C-8.
THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification: Water-tube (
field-erected)
Fuel and firing mechanism: Distillate oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
775
15
760
0
0
250
89
436
0
0
0
197
274
105
151
40
7
1
Capacity,
thermal MW
(106 Btu/h)
18,970 (64,800)
380 (1,300)
18,590 (63,500)
6,190 (21,100)
2,160 (7,300)
10,620 (36,400)
•
880 (3,000)
2,780 (9,500)
2,340 (8,000)
6,620 (22,600)
4,160 (14,200)
1,520 (5,200)
670 (2,300)
C-9
-------
TABLE C-9.
THE 1977 POPULATION OF FIELD-ERECTED WATER-TUBE
BOILERS FIRING NATURAL GAS
Rni ler classification: Water-tube (field-erected)
Fnpl and firing mechanism: Natural gas
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
4.867
98
4,769
0
0
512
732
3,623
0
0
0
760
1,459
979
1,189
337
103
40
Capacity,
thermal MW
(106 Btu/h)
198.530 (677.600)
4, 000 (1 3rfiOO)
194,530 (664.000)
19,400 (66,100)
30,230 (103,000)
148,900 (508,500)
3,780 (12.900)
15,820 (54,000)
20,830 (71,100)
52,180 (178.100)
32,700 (111,600)
22,590 (77.100)
50,630 (172,800)
C-10
-------
TABLE C-10.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING PULVERIZED COAL
Boiler classification; Water-tube (package)
Fuel and firing mechanism; Pulverized coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
118
20
93
31
83
117
Capacity,
thermal MW
(10<5 Btu/h)
5,220 (17,800)
890
210
150
1,420
90
(3.000)
4,120 (14,100)
(700)
:soo)
(4,800)
3.650 (12.500'
5,130 (17,500)
(300)
C-ll
-------
TABLE C-ll.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING COAL (SPREADER STOKER)
Boiler classification; Water-tube (package)
Fuel and firing mechanism: Coal, spreader-stoker
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Ovei 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
915
156
723
36
477
342
96
103
99
364
223
125
Capacity,
thermal MW
(106 Btu/h)
15,030 (51.300:
2.555
601
2.520
150
500
4 .070
90
(R .721 )
11.874 (40.527)
(2,052)
(8.600)
3.250 (llrlQQ)
9.260 (31.600)
(500)
H .700)
'13.900)
4.830 (16.500)
5.390 (18.400)
(300)
C-12
-------
TABLE C-12.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING COAL (OVERFEED STOKER)
Boiler classification: Water-tube
(packaqe)
Fuel and firing mechanism: Coal, overf eed-stoker
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
673 8f
0
118 1.
527 6,
28
213 1,
122 1,
338 4 .
0
28
114
63
282 3,
162 3,
23
1
0
0
Capacity,
thermal MW
(106 Btu/h)
140 (27.7TD)
390
420
330
750
680
710
10
180
320
110
490
940
90
(4.730)
(21,890)
(1,110)
(5.970)
(5.800)
(15 .960)
(30)
(600)
(1,100)
(10,600)
(11,900)
(3,200)
(300)
C-13
-------
TABLE C-13.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING COAL (UNDERFEED STOKER)
Boiler classification: Water-tube
(package)
Fuel and firing mechanism: Coal, underf eed-stoker
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
3,639
0
619
2,875
145
1,460
578
1,601
0
532
928
460
1,056
617
45
1
0
0
Capacity,
thermal MW
(106 Btu/h)
30,840 (105,200)
5.240
24,360
1,240
7,400
6,090
17,350
150
1,410
2,260
11,720
13,330
1,880
90
(17,880)
(83,100)
(4,220)
(25.250)
(20,780)
(59.170)
(500)
(4,800)
(7.700)
(40,000)
(45,500)
(6,400)
(300)
C-14
-------
TABLE C-14.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING RESIDUAL OIL-
Boiler classification: Water-tube (package)
Fuel and firing mechanism:
Residual oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
11,560
231
11,329
0
0
3,061
1,447
7,052
1.173
3.215
1.912
3.515
1,434
309
Capacity,
thermal MW
(106 Btu/h)
410
4.830
9,110
13,330
290
1
94
.930
.420
(6r580)
n ?. ? _ •} ? m
24
12
60
,060
,290
,000
(82,180)
(41,960)
(204,760)
.400)
(16 .500)
(31.100)
37.500 (128.000)
30.880 (105.400)
(45.500)
(1.000)
C-15
-------
TABLE C-15.
THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING DISTILLATE OIL
Boiler classification: Water-tube
(package)
Fuel and firinq mechanism: Distillate oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial -institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
7.223
144
7,079
0
0
3,173
753
3,297
0
2,928
2,958
462
640
193
51
1
0
0
Capacity,
thermal MW
(106 Btu/h)
19,790 (67.5001
400
19.390
6,960
2,450
10,380
1,030
3,460
2,080
6,530
4,370
2,230
90
(1,400)
(66.100)
(23,800)
(8,300)
(35.400)
(3.500)
(11.800)
(7.100)
(22,300)
(14,900)
(7.600)
(300)
C~16
-------
TABLE C-16. THE 1977 POPULATION OF PACKAGE WATER-TUBE BOILERS
FIRING NATURAL GAS
Boiler classification:
Water-tube (package)
Fuel and firing mechanism: Natural gas
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
13,424
268
13,156
0
0
2.439
1.881
9.104
0
2.414
3.616
1.775
3.404
1.816
397
Capacity,
thermal MW
(106 Btu/h)
107.910 (368.300)
2 .160
105.750
11 .960
16 .110
850
4 .920
8 .850
17 .400
290
(7.37m
MO. 800)
.oon)
79.840 ( ? 7 ? . 5 0 0)
(2f9no)
n 6 .Rom
.?oo)
36.890 (125,900)
38.710 (132.100)
(59 .4001
(1 .000)
C-17
-------
Table C-17. THE 1977 POPULATION OF INDUSTRIAL/COMMERCIAL
FIRE-TUBE BOILERS
Boiler classification; Fire-tube boilers
Fuel and firing mechanism: All fuels
Number
Capacity,
thermal MW
(106 Btu/h)
Class population
Distribution by heat-transfer medium
275.075 302.780 (1.033.300)
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7. 3 to 14. 7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
0
145,788
68,771
60,516
] m , i 39
173r 936
0
179,168
74,387
18,268
3,252
0
0
0
0
0
160,435 (547,
75,680 (258,
66,665 (227,
83P420 (284
219f360 (748
52,520 (179
120,720 (412
93,790 (320
35,750 (122
556)
282)
462)
,800)
.500)
,200)
,000)
,100)
,000)
C-18
-------
TABLE C-18
THE 1977 POPULATION OF FIRE-TUBE
BOILERS FIRING COAL
Boiler classification; Fire-tube
Fuel and firing mechanism: Coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0,4 to 2.9 (1.5 to 10)
Over 2,9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73,3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146,5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
26,328
0
13,954
6,583
5,791
16,993
9,335
0
0
19.227
5,210
1,533
358
Capacity,
thermal MW
(106 Btu/h)
26,201 (89,430)
13,886 (47,397)
6,551 (22,358)
5,764 (19,675)
12,778 (43,617)
13,423 (45,813)
5,632 (19,227)
8,778 (29,959)
7,860 (26,829)
3,931 (13,415)
C-19
-------
TABLE C-19. THE 1977 POPULATION OF FIRE-TUBE BOILERS
FIRING RESIDUAL OIL
Boiler classification: Fire-tube
Fuel and firinq mechanism: Residual
oil
Number
Class population 73.683
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure) 39
Steam (low-pressure) 18
Hot water 16
Distribution by usage
Commercial-institutional
(space heatina) 22
Industrial (space heating) 51
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5) 46
Over 0.4 to 2.9 (1.5 to 10) 21
Over 2.9 to 7.3 (10 to 25) 5
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
0
,051
,421
,211
,445
.238
0
0
,267
,511
,072
833
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
83,388 (284r596)
44,195 (150,836)
20,847 (71,149)
18,345 (62,611)
22,256 (77,339)
61.132 (207.257)
13,555 (46,263)
34,634 (118,204)
26,051 (88,910)
9,148 (31,219)
C-20
-------
Table C-20.
THE 1977 POPULATION OF FIRE-TUBE BOILERS
FIRING DISTILLATE OIL
Boiler classification; Fire-tube
Fuel and firing mechanism: Distillate oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
48,141
0
25.514
12,036
10,591
22,845
25,296
0
30,191
14,089
3,318
543
Capacity,
thermal MW
(106 Btu/h)
54,560 (186,200)
28,895 (98,633)
13,631 (46,525)
11,994 (40,942)
21,187 (71,709)
33,373 (114,491)
8,850 (30,200)
22,680 (77,400)
17,050 (58,200)
5,980 (20,400)
C-21
-------
Table C-21.
THE 1977 POPULATION OF FIRE-TUBE BOILERS FIRING
NATURAL GAS
Boiler classification: Fire-tube
Fuel and firing mechanism: Natural gas
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
126,923
0
67.269
31,731
27,923
38.856
88,067
0
83,483
33,577
8,345
1,518
Capacity,
thermal MW
(106 Btu/h)
138,630 (473,100)
73,459 (250,690)
34,651 (118,250)
30,472 (104,060)
27,375 (93.440)
111,255 (379,660!
24,470 (83,500)
54,620 (186,400)
42,840 (146,200)
16,700 (57,000)
C-22
-------
TABLE C-22.
THE 1977 POPULATION OF SCOTCH FIRE-TUBE
BOILERS FIRING COAL
Boiler classification: Fire-tube
(Scotch)
Fuel and firing mechanism: Coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2. 9 to 7. 3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
8,591
0
4,553
2,148
1,890
5,468
3.123
0
5,960
1,876
583
172
0
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
9,780 (33,379)
5,183 (17,691)
2,445 (8,345)
2,152 (7,343)
4,593 (15,678)
5.187 (17.701)
1,746 (5,960)
3,160 (10,785)
2,987 (10,195)
1,887 (6,439)
C-23
-------
TABLE C-23.
THE 1977 POPULATION OF FIREBOX FIRE-TUBE
BOILERS FIRING COAL
Boiler classification: Fire-tube (firebox)
Fuel and firing mechanism:.
Coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
12.745
0
6, 755
3,186
2,804
8.375
4,370
0
0
9 .998
2 .084
491
172
Capacity,
thermal MW
(106 Btu/h)
10,842 (37,006:
5,746 (19.613)
2,711
2.929
2,515
(9,252)
2,385 (8,141)
5.440 (18.569)
5,402 (18,437)
3,511 (11,984;
(8,585)
1,887 (6,439)
C-24
-------
TABLE C-24.
THE 1977 POPULATION OF HRT FIRE-TUBE
BOILERS FIRING COAL
Boiler classification: Fire-tube (HRT)
Fuel and firing mechanism; Coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
3,274
1.735
819
720
2.014
1,260
0
0
1.923
938
399
14
Capacity,
thermal MW
(106 Btu/h)
4,344 (14,289)
157
2.302 (7,859)
1,086 (3,707)
956 (3,263)
2,063 (7,043)
2,281 (7,246)
563 (1,923)
1,580 (5,393)
2,044 (6,976)
:537)
C-25
-------
TABLE C-25.
THE 1977 POPULATION OF OTHER FIRE-TUBE
BOILE.RS FIRING COAL
Boiler classification; Fire-tube (other)
Fuel and firing mechanism; Coal
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
1 .718
91 1
430
377
1,136
582
0
1,346
312
60
Capacity,
thermal MW
(106 Btu/h)
1.235 (4.216)
309 (1,054)
271
(928)
682 (2,327)
553 (1,889)
394 (1,346)
527 (1,797)
314 (1,073)
C-26
-------
TABLE C-26. THE 1977 POPULATION OF SCOTCH FIRE-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification: Fire-tube (Scotch)
Fuel and firing mechanism; Residual oil
Number
Class population 25 ,997
Distribution by heat-transfer medium
Supercritical steam 0
Steam (high-pressure) 13 ,778
Steam (low-pressure) 6,499
Hot water 5,720
Distribution by usage
Commercial-institutional
(space heating) 7,729
Industrial (space heating) 18,268
Industrial (process heat) 0
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 0
Over 0.1 to 0.4 (0.4 to 1.5) 14,311
Over 0.4 to 2.9 (1.5 to 10) 9,151
Over 2.9 to 7.3 (10 to 25) 2,135
Over 7.3 to 14.7 (25 to 50) 400
Over 14.7 to 29.3 (50 to 100) °
Over 29.3 to 73.3 (100 to 250) °
Over 73.3 to 146.5 (250 to 500) °
Over 146.5 to 439.5 (500 to 1500) °
Over 439.5 (1500) °
Capacity,
thermal MW
(106 Btu/h).
34,152 (116,558)
18,100 (61.776)
8,538
:29,140)
7,513 (25,642;
9,010 (30,753)
25,142 (85,805)
4,192 (14,310)
14,599 (49,825)
10,970 (37,438)
4,391 (14,985)
C-27
-------
TABLE C-27,
THE 1977 POPULATION OF FIREBOX FIRE-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification: Fire-tube
(firebox)
Fuel and firina mechanism: Residual oil
Class population
Distribution by heat-transfer mediu
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial -institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
35,030
m
0
18,566
8,758
7,706
10.859
24,171
0
0
23.989
8.792
1.849
400
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
35,056 (119,645)
18,580 ( 6 3 , 4 1 7 )
8,764 (29.911)
7,712 (26,322)
9.482 (33.744)
25,574 (85,901)
7.028 (23.987)
14,138 (48.251)
9,499 (32.422)
4,391 (14,985)
C-28
-------
TABLE C-28. THE 1977 POPULATION OF HRT FIRE-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification; Fire-tube (HRT)
Fuel and firing mechanism: Residual oil
Class population
Distribution by heat-transfer medium
Capacity,
thermal MW
Number (106 Btu/h)
9.887 (3,1.744)
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
0
4.070
1,920
1,690
2,309
5,371
0
0
4 ,475
2,277
928
0
0
0
0
0
0
5,240 (17.884)
2,472 (8,436)
2,175 (7,424)
2,600 (8.871)
7,287 (24,873)
1,311 (4.475)
3,819 (13,035)
4,757 (16.234)
C-29
-------
TABLE C-29. THE 1977 POPULATION OF OTHER FIRE-TUBE
BOILERS FIRING RESIDUAL.OIL
Boiler classification: Fire-tube (other)
Fuel and firing mechanism: Residual
Class population
Distribution by heat- transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
oil
Number
4,976
i
0
2.637
1,244
1,095
1,548
3 , 4 2 8
0
3,492
1.291
160
33
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
4,293 (14,649)
2.275 (7.764)
1,073 (3,662)
945 (3,223)
1,164 (3.971)
3r129 (10,678)
1,024 nr491)
2,078 (7,093)
825 (2,816)
366 (1,249)
C-30
-------
TABLE C-30. THE 1977 POPULATON OF SCOTCH FIRE-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification; Fire-tube (Scotch)
Fuel and firing mechanism; Distillate oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to -100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
16,995
0
9.007
4,249
3,739
7 > 868
9,127
0
0
9,338
5,999
1/397
Capacity,
thermal MW
(106 Btu/h)
22,340 (76,300)
11,840 (40,439)
5,585 (19,075)
4,915 (16,786)
8,445 (28,838)
13,895 (47,462)
2,730 (9,300)
9,570 (32,700)
7,180 (24,500)
2,860
:9,800)
C-31
-------
TABLE C-31. THE 1977 POPULATION OF FIREBOX FIRE-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification: Fire-tube
(firebox)
Fuel and firinq mechanism: Distillate oil
Class population
Distribution by heat-transfer mediu
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
22.884
in
0
12,129
5,721
5,034
11,061
11,823
0
0
15,653
5,759
1,211
261
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h).
22,930 (78,300)
12,153 (41,499)
5,733 (19,575)
5,044 (17,226)
9,009 (30,767)
13,921 (47,533)
4,590 (15,700)
9,260 (31,600)
6,220 (21,200)
2,860 (9,800)
C-32
-------
TABLE C-32.
THE 1977 POPULATION OF HRT FIRE-TUBE BOILERS
FIRING DISTILLATE OIL
Boiler classification; Fire-tube (HRT)
Fuel and firing mechanism; Distillate oil
Number
Class population 5,031
Distribution by heat-transfer medium
Supercritical steam 0
Steam (high-pressure) 2,666
Steam (low-pressure) 1,258
Hot water 1,107
Distribution by usage
Commercial-institutional
(space heating) 2, 336
Industrial (space heating) 2/ 595
Industrial (process heat) 0
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) Q
Over 0.1 to 0.4 (0.4 to 1.5) 2,919
Over 0.4 to 2.9 (1.5 to 10) 1.486
Over 2.9 to 7.3 (10 to 25) 605
Over 7.3 to 14.7 (25 to 50) 21
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to 73.3 (100 to 250) Q
Over 73.3 to 146.5 (250 to 500) 0
Over 146.5 to 439.5 (500 to 1500) 0
Over 439.5 (1500) Q
Capacity,
thermal MW
(106 Btu/h)
6,680 (22,800)
3.540 (12.084)
1,670 (5,700)
1,470 (5,016)
2,667 (8,487)
4,013 (14,313)
850
240
(2,900)
2,490 (8,500)
3,100 (10,600)
(800)
C-33
-------
TABLE C-33. THE 1977 POPULATION OF OTHER FIRE-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification: Fire-tube
(other)
Fuel and firing mechanism: Distillate oil
Class population
Distribution by heat-transfer mediu
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
3,231
m
0
1,71 2
808
711
1,580
1,651
0
0
2,281
845
105
0
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
2,570 (8,700)
Ir362 (4,611)
643 (2,175)
565 (1,914)
1,066 (3,617)
1,504 (5,083)
670 (2,300)
1,360 (4,600)
540 (1,800)
C-34
-------
TABLE C-34.
THE 1977 POPULATION OF SCOTCH FIRE-TUBE
BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube (Scotch)
Fuel and firing mechanism: Natural qas
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73,3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Capacity,
thermal MW
Number (106 Btu/h)
43.800 ^,4?n (IRQ 1QQ)
0
23r214 29.378 (100.223)
10,950 13,858 (47,275)
9,636 12,194 (41,602)
12,847 10,421 (35,549)
30,953 45,009 (153,551)
0
0
25,841 7,570 (25,800)
13,806 22,260 (76,000)
3,424 17,590 (60,000)
729 8,010 (27,300)
0
0
0
0
0
C-35
-------
TABLE C-35. THE 1977 POPULATION OF FIREBOX
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube
Fuel and firinq mechanism: Natural
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
(firebox)
gas
Number
60,661
0
32,150
15,165
13,346
19,226
41,435
0
0
43,326
13,660
2,946
729
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
58,020 (197,900)
30,751 (104,887)
14,505 (49,475)
12,746 (43,538)
11,981 (40,872)
46,039 (157,028)
12,690 (43,300)
22,190 (75,700)
15,130 (51,600)
8,010 (27,300)
C-36
-------
TABLE C-36. THE 1977 POPULATION OF HRT FIRE-TUBE
BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube
(HRT)
Fuel and firing mechanism: Natural qas
Class population
Distribution by heat- transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
14,012
0
7r426
3.503
3,083
4,066
9,946
0
0
8.163
4,097
1,692
60
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
18,620 (63,600)
9,869 (33.708)
4,655 (15,900)
4,096 (13,992)
3,462 (11,835)
15,158 (51,765)
2,390 (8,200)
6,880 (23,500)
8,680 (29,600)
670 (2,300)
C-37
-------
TABLE C-37. THE 1977 POPULATION OF OTHER FIRE-TUBE
BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube
Fuel and firinq mechanism: Natural
Class population
Distribution by heat-transfer mediu
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial -institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
(other)
gas
Number
8,450
m
0
4 .479
2,113
1,858
2.717
5P733
0
0
6,153
2,014
283
0
0
0
0
0
0
Capacity,
thermal MW
(106 Btu/h)
6,350 (22,400)
3,461 (11,872)
1,633 (5,600)
1,436 (4,928)
1.511 (5.184)
4.839 (17.216)
1,800 (6,200)
3,280 (11,200)
1,450 (5,000)
C-38
-------
Table C-38.
THE 1977 POPULATION OF INDUSTRIAL/COMMERCIAL
CAST IRON BOILERS
Boiler classification:
Cast iron
Fuel and firing mechanism: All fuels
Class population
Number
1 ,476,49 0
Capacity,
thermal MW
(106 Btu/h)
262,600 (896,200)
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
Industrial
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500;
Over 439.5 (1500)
1,181,192
295,298
0
210,060 (716,900)
52,570 (179,400)
970,980 69,180 (236,100)
382,172 88,820 (303,100)
123,338 104,600 (357,000)
C-39
-------
TABLE C-39. 1977 POPULATION OF CAST IRON
BOILERS FIRING COAL
Boiler classification:
Cast iron
Fuel and firing mechanism:_
Coal
Capacity,
thermal MW
Number (106 Btu/h)
179.829 31.586 (107.802'
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
0
n
0
0
143.864 25r269
35,965 6r317
0
113.287 6.001
46r7fiO 12r319
19r782 13.266
0
0
0
0
0
0
0
(86r242)
(21r560)
(20.482)
(42r045)
(45,275)
C-40
-------
TABLE C-40. 1977 POPULATION OF CAST IRON
BOILERS FIRING RESIDUAL OIL
Boiler classification: Cast iron
Fuel and firing mechanism: Residual oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
299,468
239.574
59.894
0
Capacity,
thermal MW
(106 Btu/h)
53,774 (183,527)
43,019 (146,821;
10,755 (36,706;
203
71
24
f
f
f
0
0
56
61
28
9
4
5
15
16
22
,027
,084
,663
(51
(54
(77
,286)
,89
,34
3)
8)
C-41
-------
TABLE C-41. 1977 POPULATION OF CAST IRON
BOILERS FIRIniG DISTILLATE OIL
Boiler classification:
Cast iron
Fuel and firing mechanism; Distillate oil
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
188,057
150,455
37,612
0
127,833
44,979
15,245
0
Capacity,
thermal MW
(106 Btu/h)
33,739 (115,150)
26,991 (92,119)
6,748 (23,031)
9,428 (32,178)
10,092 (34,444)
14,219 (48,528)
C-42
-------
TABLE C-42. 1977 POPULATION OF CAST IRON
BOILERS FIRING NATURAL GAS
Boiler classification:
Cast iron
Fuel and firing mechanism; Natural gas
Class population
Distribution by heat-transfer medium
Supercritical steam
Steam (high-pressure)
Steam (low-pressure)
Hot water
Distribution by usage
Commercial-institutional
(space heating)
Industrial (space heating)
Industrial (process heat)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Capacity,
thermal MW
Number (106 Btu/h)
809,136 143,512 (489,806)
647,309
161,827
114,810
28,702
(391,845)
(137,599)
0
526
218
64
r
r
291
819
026
38
50
54
,711
,325
,476
(1
32
(171
(1
85
,121)
,759)
,926)
0
0
C-43
-------
TABLE C-43. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING PULVERIZED COAL
Boiler classification; Water-tube, commercial
Fuel and firing mechanism: Pulverized coal
Capacity, thermal
Number MW (10" Btu/h)
Class population 14 615 (2,100)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) Q—
Over 0.1 to 0.4 (0.4 to 1.5) Q
Over 0.4 to 2.9 (1.5 to 10) 0
Over 2.9 to 7.3 (10 to 25) Q
Over 7.3 to 14.7 (25 to 50) 0
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to-73.3 (100 to 250) 14 615 (2,100)
Over 73.3 to 146.5 (250 to 500) 0
Over 146.5 to 439.5 (500 to 1500) 0
Over 439.5 (1500) 0
C-44
-------
TABLE C-44. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING SPREADER-STOKER COAL
Boiler classification; Water-tube, commercial
Fuel and firing mechanism; Coal, spreader-stoker
Class population
Distribution by capacity ranges,
thermal MW (10& Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
351
_5JZ_
53
146
58
30
Capacity, thermal
MW (106 Btu/h)
(17.530)
80 (280)
260 (890)
1.630 (5.570)
1.265 (4.320)
1,295 (4,420)
600 (2,050)
C-45
-------
TABLE C-45. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING UNDERFEED-STOKER COAL
Boiler classification: Water-tube, commercial
Fuel and firing mechanism; Coal, underfeed-stoker
Capacity, thermal
Number MW (10° Btu/h)
Class popul
Distributio
the
0 to 0.1
Over 0.1
Over 0.4
Over 2.9
Over 7 . 3
Over 14.7
Over 29.3
Over 73.3
Over 146.
Over 439.
ation 1,724
n by capacity ranges,
rmal MW (10^ Btu/h)
(n t-o n. 4) 0
tin 0.4 (0.4 t-.n 1 . 5) 372
to 2.9 (1 .5 1-n 1 CM 51°
to 7.3 n 0 to 25) 243
to 14.7 (25 to 50) 423
to 29.3 (50 to TOO) 162
to-73.3 (100 to 250) ll
to 146.5 (250 to 500) 3
5 to 439.5 (500 to 1500) °
5 (1500) °
11,030 (37,640)
105 (350)
775 (2,640)
1,195 (4,070)
4,690 (16,020)
3,535 (12,070)
450 (1,540)
280 (950)
C-46
-------
TABLE C-46. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING OVERFEED-STOKER COAL
Boiler classification; Water-tube, commercial
Fuel and firing mechanism; Coal, overfeed-stoker
Capacity, thermal
Number MW (10° Btu/h)
Class j
Distrih
0 to
Over
Over
Over
Over
Over
Over
Over
Over
Over
jopulation 278 2.835 (9.660)
)ution by capacity ranges,
thermal MW (1Q6 Btu/h)
0.1(01-00.4) 0
n. 1 to 0.4 (0.4 to 1 . 51 20 5 (20)
0.4 1-o 2.9 (1,5 t-o in) 63 100 (330)
2.9 to 7.3 MO 1-0 251 33 160 (560)
7,? to 14.7 (25 to 50) 113 1,240 (4,230)
14.7 to 29.3 (50 to 1 Om 42 915 (3,110)
29.3 to-73.3 non to 2501 5 225 (770)
73.3 to 146.5 (250 to 5001 2 190 (640)
14fi,5 to 419.5 (500 t-o 1500) 0
419,5 (1500) 0
C-47
-------
TABLE C-47. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification; Water-tube, commercial
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class £
Distril
0 to
Over
Over
Over
Over
Over
Over
Over
Over
Over
Dopnlation 4,081
>ution by capacity ranges,
thermal MW (10^ Btu/h)
n. 1 (0 to n. 4) n
0.1 1-o 04 (0.4 4-o 1,5) 399
0,4 1-o 2.9 (1.5 t-n 10) 772
2.9 to 7. 3 (1 0 to 25) 710
7.3 to 14.7 (25 to 50) 1,406
14.7 to 29.3 (50 to 100) 551
29.3 to-73.3 (100 to 250) 198
73.3 to 146.5 (250 to 500) 39
146.5 to 439.5 (500 to 1500) 6
439.5 (1500) 0
45, 280
140
1,160
3,380
15,000
11,880
8,530
3,800
1,390
(154.540)
(48
(3,
(11
(51
(40
(29
(12
(4,
0)
960)
,540)
,180)
,550)
,120)
,970)
740)
C-48
-------
TABLE C-48. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification; Water-tube, commercial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class j
Distrit
0 to
Over
Over
Over
Over
Over
Over
Over
Over
Over
)opulation 3,399
mtion by capacity ranges,
thermal MW (106 Btu/h)
0 . 1 ( o 1-0 0 T 4 ) 0
0. 1 to 0.4 (0.4 to 1.5) 1,552
0.4 to 2.9 (1.5 1-o 10) 1,183
2 , 9 t-o 7. 1 (1 0 to 25) 204
7,1 1-o 14.7 (25 tin 50) 302
14.7 tin 29.3 (50 1-0 100) 107
29.1 tin -73. 3 (100 to 250) 32
73.3 tin 146.5 (250 tin 500) 16
14fi.5 1-o 419.5 (500 to 1500) 3
41Q.5 (1500) 0
13,170 (44,940)
550 (1,860)
1.380 (4,720)
920 (3,130)
3,070 (10,490)
2,415 (8,240)
2,480 (8,460)
1,700 (5,800)
655 (2,240)
C-49
-------
TABLE C-49. THE 1977 POPULATION OF COMMERCIAL WATER-TUBE
BOILERS FIRING NATURAL GAS
Boiler classification; Water-tube, commercial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class popu
Distributi
th
0 to 0.1
Over 0.1
Over 0.4
Over 2 . 9
Over 7.3
Over 14.
Over 29.
Over 73.
Over 146
Over 439
lation
on by capacity ranges,
ermal MW (10^ Btu/h)
(0 to 0.4)
to 0.4 (0.4 to 1.5)
to 2.9 (1.5 to 10)
to 7.3 (10 to 25)
to 14.7 (25 to 50)
7 to 29.3 (50 to 100)
3 to-73.3 (100 to 250)
3 to 146.5 (250 to 500)
.5 to 439.5 (500 to 1500)
.5 (1500)
2r952
n
893
723
330
535
280
143
37
7
4
31.225
310
985
1,640
5,800
5,955
6,260
3,630
1,580
5,065
(106,580)
(1,
(3P
(5,
(19
(20
(21
(12
(5,
(17
070)
360)
600)
,790)
,320)
,370)
,390)
400)
,280)
C-50
-------
TABLE C-50. THE 1977 POPULATION OF COMMERCIAL SCOTCH
FIRE-TUBE BOILERS FIRING COAL
Boiler classification; Fire-tube (Scotch), commercial
Fuel and firing mechanism; Coal
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (1C)6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
5,468
0
4,172
1,032
216
48
0
0
0
0
0
4.593 (15,678)
1,222 (4,172)
1,738 (5,932)
1,105 (3,772)
528 (1,802)
C-51
-------
TABLE C-51. THE 1977 POPULATION OF COMMERCIAL FIREBOX
FIRE-TUBE BOILERS FIRING COAL
Boiler classification; Fire-tube (firebox), commercial
Fuel and firing mechanism: Coal
Class population
Distribution by capacity ranges,
thermal MW (10& Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
8,375
5,999
1.146
182
48
Capacity, thermal
MW (1QQ Btu/h)
5,440 (18.569)
2 .050
1.931
931
528
(6.999)
(6.591)
(3.176)
(1.803)
C-52
-------
TABLE C-52. THE 1977 POPULATION OF COMMERCIAL HRT
FIRE-TUBE BOILERS FIRING COAL
Boiler classification: Fire-tube (HRT), commercial
Fuel and firing mechanism: Coal
Capacity, thermal
Number MW (10$ Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
2,014
0
1.346
516
148
4
0
0
0
0
0
2,063 (7,043)
394 (1,346)
869 (2r966)
756 (2,581)
44 (150)
C-53
-------
TABLE C-53. THE 1977 POPULATION OF OTHER COMMERCIAL
FIRE-TUBE BOILERS FIRING COAL
Boiler classification: Fire-tnhp. (other} . commercial
Fuel and firinq mechanism: Coal
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
1,136
0
942
172
22
0
0
0
0
0
0
Capacity, thermal
MW (10& Btu/h)
682 (2,327)
276 (942)
290 (988)
116 (397)
C-54
-------
TABLE C-54. THE 1977 POPULATION OF COMMERCIAL SCOTCH
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification: Fire-tube (Scotch), commercial
Fuel and firing mechanism: Residual oil
Class population
Distribution by capacity ranges,
thermal MW (10^ Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
Number
7^729
4 .866
2,196
555
112
Capacity, thermal
MW (10° Btu/h)
9.010 (30.753)
Ir425 (4.865)
3,504 (11,958)
2,852 (9,734)
1,229 (4,196)
C-55
-------
TABLE C-55. THE 1977 POPULATION OF COMMERCIAL FIREBOX
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification; Fire-tube (firebox), commercial
Fuel and firing mechanism: Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
10,589
0
8,156
2,110
481
112
0
0
0
0
0
9,482 (32.362)
2.390 (8,156)
3.393 (11,580^
2,470 (8,430)
1,229 (4,196)
C-56
-------
TABLE C-56. THE 1977 POPULATION OF COMMERCIAL HRT
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification; Fire-tube (HRT), commercial
Fuel and firing mechanism: Residual oil
Capacity, therm'al
Number MW (106 Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (1Q6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
2,309
0
1,522
546
241
0
0
0
0
0
0
2,660 (8,871)
466 (1,522)
917 (3,128)
1,237 (4,221)
C-57
-------
TABLE C-57. THE 1977 POPULATION OF OTHER COMMERCIAL
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification; Fire-tube (other), commercial
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
1,548
0
1,187
310
42
9
0
0
0
0
0
1,164 (3,971)
348 (1,187)
499 (1,702)
215 (732)
102 (350)
C-58
-------
TABLE C-58. THE 1977 POPULATION OF COMMERCIAL SCOTCH
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification: Fire-tube (Scotch), commercial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
7r868
0
4,949
2,400
433
86
0
0
0
0
0
8,445 (28r838)
1,447 (4,929)
3,828 (13,080)
2,226 (7,595)
944 (3,234)
C-59
-------
TABLE C-59. THE 1977 POPULATION OF COMMERCIAL FIREBOX
FIRE-TUBE BOILERS, FIRING DISTILLATE OIL
Boiler classification:
Fire-tube (firebox), commercial
Fuel and firing mechanism:
Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
11.061
0
8,296
2,304
375
86
0
0
0
0
0
9r009 (30,767)
2,433 (8,321)
3,704 (12,640)
1,928 (6,572)
944 (3,234)
C-60
-------
TABLE C-60. THE 1977 POPULATION OF COMMERCIAL HRT
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification; Fire-tube (HRT), commercial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (1QQ Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (1Q6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
2,336
0
Ir457
594
188
7
0
0
0
0
0
2,667 (8.487)
451 (1,537)
Ir176 (3r400)
961 (3,286)
79 (264)
C-61
-------
TABLE C-61. THE 1977 POPULATION OF OTHER COMMERCIAL
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification: Fire-tube (other), commercial
Fuel and firing mechanism; Distillate oil
Capacity, thermal
Number MW (1QQ Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
1.580 1.066 (3,617)
0
1,209 355 (1,219)
338 544 (1,840)
33 167 (588)
0
0
0
0
0
0
C-62
-------
TABLE C-62. THE 1977 POPULATION OF COMMERCIAL SCOTCH
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification; Fire-tube (Scotch), commercial
Fuel and firing mechanism: Natural gas
Capacity, thermal
Number MW (106 Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
12,847
0
9.561
2,761
445
80
0
0
0
0
0
10.421 (35.549)
2.801 (9.546)
4.452 (15.200)
2,287 (7,800)
881 (3,003)
C-63
-------
TABLE C-63. THE 1977 POPULATION OF COMMERCIAL FIREBOX
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube (firebox), commercial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
19,226
0
16,031
2,732
383
80
0
0
0
0
0
11,981 (40,872)
4,695 (16,021)
4,438 (15,140)
1,967 (6,708)
881 (3,003)
«
C-64
-------
TABLE C-64. THE 1977 POPULATION OF COMMERCIAL HRT
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification; Fire-tube (HRT), commercial
Fuel and firing mechanism: Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class population 4'066 3,462 (H,835)
Distribution by capacity ranges,
thermal MW (10^ Btu/h)
0 to 0.1 (0 to 0.4) °
Over 0.1 to 0.4 (0.4 to 1.5) 3,020 884 (3,034)
Over 0.4 to 2.9 (1.5 to 10) §JL9 1,376 (4,700)
Over 2.9 to 7.3 (10 to 25) 220 1,128 (3,848)
Over 7.3 to 14.7 (25 to 50) 1 1A (253)
Over 14.7 to 29.3 (50 to 100) 9.
Over 29.3 to-73.3 (100 to 250) °
Over 73.3 to 146.5 (250 to 500) __2 . .
Over 146.5 to 439.5 (500 to 1500) °_
Over 439.5 (1500) 2—
C-65
-------
TABLE C-65. THE 1977 POPULATION OF OTHER COMMERCIAL
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification; Fire-tube (others), commercial
Fuel and firing mechanism; Natural gas
Capacity/ thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (10^ Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
2,717
0
2,277
403
37
0
0
0
0
0
0
1,511 (5,184)
666 (2.294)
656 (2.240)
189 (650)
C-66
-------
TABLE C-66. THE 1977 POPULATION OF COMMERCIAL CAST IRON
BOILERS FIRING COAL
Boiler classification; Cast iron, commercial
Fuel and firing mechanism; Coal
Capacity, thermal
Number MW (10° Btu/h)
Class population 143,864 25,269 (86,242)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 90,630 4.801 (16r386)
Over 0.1 to 0.4 (0.4 to 1.5) 37.408 9.855 (33.636)
Over 0.4 to 2.9 (1.5 to 10) 15.826 10.613 (36.220)
Over 2.9 to 7.3 (10 to 25) 0
Over 7.3 to 14.7 (25 to 50) 0
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to-73.3 (100 to 250) °
Over 73.3 to 146.5 (250 to 500) °
Over 146.5 to 439.5 (500 to 1500) 9.
Over 439.5 (1500) 9.
C-67
-------
TABLE C-67. THE 1977 POPULATION OF COMMERCIAL CAST IRON
BOILERS FIRING RESIDUAL OIL
Boiler classification: Cast iron, commercial
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (10^ Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 .(100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
239.574
162,855
57,291
19,428
0
0
0
0
0
0
0
43.019 (146,8211
12,022 (41,029)
12,867 (43,914)
18,130 (61,878)
C-68
-------
TABLE C-68. THE 1977 POPULATION OF COMMERCIAL CAST IRON
BOILERS FIRING DISTILLATE OIL
Boiler classification; Cast iron, commercial
Fuel and firing mechanism; Distillate oil
Capacity, thermal
Number MW (1QQ Btu/h)
Class population 150.455 26,991 (92,119)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
n 1-0 n. i (n 1-0 n. 4) 102,266
Ov^r n.l 1-0 n.4 (0.4 l-o 1,^ 35.983
rvw^r n,4 1-o 2.Q (t.R 1-o in) 12.196
Ov^r 2 . q 1-o 7, 3 (1 n to 25) 0
ovpr ] 4 . 7 1-0 29 , T (^n 1-0 i nn) 0
OVPT 73.3 to 146.5 (250 -fo 500) ^
r>v^r 146 5 to 4^^.c> (^^O to 1500) 0
7,542 (25.742)
8.074 (27,555)
11,375 (38r822)
C-69
-------
TABLE C-69. THE 1977 POPULATION OF COMMERCIAL CAST IRON
BOILERS FIRING NATURAL GAS
Boiler classification: Cast iron, commercial
Fuel and firing mechanism: Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
647.309 114,810 (391,845)
421,033 30,969 (105.697)
175,055 40.260 (137.407)
51,221 43,581 (148.741)
0
0
0
0
0
0
0
C-70
-------
TABLE C-70. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING PULVERIZED COAL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism: Pulverized coal
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (10^ Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
719
0
0
0
0
0
0
453
191
64
11
60,075 (205,000)
19,895 (67,900)
18,460 (63,000)
13,980 (47,700)
7,740 (26,400)
C-71
-------
TABLE C-71. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING SPREADER-STOKER COAL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Coal, spreader-stoker
Capacity, thermal
Number MW (1QQ Btu/h)
Class popu
Distributi
th
0 to 0.1
Over 0.1
Over 0.4
Over 2 . 9
Over 7 . 3
Over 14.
Over 29.
Over 73.
Over 146
Over 439
lation
on by capacity ranges,
ermal MW (106 Btu/h)
( 0 to 0 . 4 )
to 0.4 (0.4 to 1.5)
to 2.9 (1.5 to 10)
to 7.3 (10 to 25)
to 14.7 (25 to 50)
7 to 29.3 (50 to 100)
3 to -73.3 (100 to 250)
3 to 146.5 (250 to 500)
.5 to 439.5 (500 to 1500)
.5 (1500)
1,357
0
0
46
89
375
285
474
76
9
3
42
4
6
20
6
2
1
,200
70
450
,200
,175
,295
,900
,260
,850
(14
3,900)
(220)
df
(14
(21
(69
(23
(7,
(6,
510)
,330)
,080)
,280)
,550)
700)
300)
C-72
-------
TABLE C-72. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILhKS FIRING UNDERFEED-STOKER COAL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Coal, underfeed-stoker
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
3.076
0
160
418
414
1,086
788
169
35
5
1
45
635
2,035
12,070
17,265
7,080
3,210
1,110
910
(1 5
(150)
(2,
(6,
(41
(58
(24
(10
(3,
(3,
160)
930)
,180)
,930)
,160)
,950)
800)
100)
C-73
-------
TABLE C-73. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING OVERFEED-STOKER COAL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Coal, overfeed-stoker
Capacity, thermal
Number MW (10° Btu/h)
Class
Distri
0 to
Over
Over
Over
Over
Over
Over
Over
Over
Over
population
bution by capacity ranges,
thermal MW (106 Btu/h)
0.1 (0 to 0.4)
0.1 to 0.4 (0.4 to 1.5)
0.4 to 2.9 (1.5 to 10)
2.9 to 7.3 (10 to 25)
7.3 to 14.7 (25 to 50)
14.7 to 29.3 (50 to 100)
29.3 to-73.3 (100 to 250)
73.3 to 146.5 (250 to 500)
146.5 to 439.5 (500 to 1500)
439.5 (1500)
724
0
8
51
56
289
207
85
24
3
1
15,075
5
80
280
3,190
4,455
3,555
2,160
730
620
(51,370)
(10)
(270)
(940)
(10,870)
(15,190)
(12,130)
(7,360)
(2,500)
(2,100)
C-74
-------
TABLE C-74. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population ii, 87? I7fir13n ffim rism
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 0
Over 0.1 to 0.4 (0.4 to 1.5) 774 270 (920)
Over 0.4 to 2.9 (1.5 to 10) 2,443 3,670 (12.54Q)
Over 2.9 to 7.3 (10 to 25) 2.021 9.630 (32.860)
Over 7.3 to 14.7 (25 to 50) 3.616 38.560 (131.620)
Over 14.7 to 29.3 (50 to 100) 1.654 35.640 (121.650)
Over 29.3 to-73.3 (100 to 250) 1.039 44,790 (152,880)
Over 73.3 to 146.5 (250 to 500) 261 25,440 (86,830)
Over 146.5 to 439.5 (500 to 1500) 56. 12.500 (42.660)
Over 439.5 (1500) 8 5.630 (19,200)
C-75
-------
TABLE C-75. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING DISTILLATE OIL
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Distillate oil
Capacity, thermal
Number MW (1QQ Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
4P609
0
1.376
1.775
455
612
191
170
25
4
1
25.590
480
2,080
2,040
6,240
4,295
6,370
2,550
865
670
(87.360)
(1,640)
(7,080)
(6,970)
(21,310)
(14,660)
(21,740)
(8,700)
(2,960)
(2,300)
C-76
-------
TABLE C-76. THE 1977 POPULATION OF INDUSTRIAL WATER-TUBE
BOILERS FIRING NATURAL GAS
Boiler classification; Water-tube, industrial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2. 9 to 7. 3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
1 R, ITQ
n
1.521
2,893
2.205
4.328
2,515
1,443
302
96
36
275.215
540
3,935
10.990
46,910
53,585
63,320
29,360
21,010
45,565
(939.320)
(1.830)
(13.440)
(37.500)
(160,110)
(182,880)
(216,130)
(100,210)
(71,700)
(155,520)
C-77
-------
TABLE C-77. THE 1977 POPULATION OF INDUSTRIAL SCOTCH
FIRE-TUBE BOILERS FIRING COAL
Boiler classification; Fire-tube (gno-hnh), industrial
Fuel and firing mechanism: Coal
Capacity, thermal
Number MW (10" Btu/h)
Class population 3, 1 ?3 5,187 (17,701)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) Q
Over 0.1 to 0.4 (0.4 to 1.5) 1.788 524 (1,788)
Over 0.4 to 2.9 (1.5 to 10) 844 1.422 (4,853)
Over 2.9 to 7.3 (10 to 25) 367 1,882 (6,423)
Over 7.3 to 14.7 (25 to 50) 124 1,359 (4,637)
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to-73.3 (100 to 250) 0
Over 73.3 to 146.5 (250 to 500) 0
Over 146.5 to 439.5 (500 to 1500) °
Over 439.5 (1500) 0
-------
TABLE C-78. THE 1977 POPULATION OF INDUSTRIAL FIREBOX
FIRE-TUBE BOILERS FIRING COAL
Boiler classification: Fire-tube, (firebox), industrial
Fuel and firing mechanism: Coal
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7. 3 to 14. 7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
4,370
0
2,999
938
309
124
0
0
0
0
0
5,402 (18,437)
879 (2,999)
1,580 (5,393)
1,584 (5,409)
1,359 (4,636)
C-79
-------
TABLE C-79. THE 1977 POPULATION OF INDUSTRIAL HRT
FIRE-TUBE BOILERS FIRING COAL
Boiler classification: Fire-tube (HRT), industrial
Fuel and firing mechanism; Coal
Capacity, thermal
Number MW (10°Btu/h)
Class i
Distril
0 to
Over
Over
Over
Over
Over
Over
Over
Over
Over
iopulation 1,260 2.281 (7,786)
iution by capacity ranges,
thermal MW (106 Btu/h)
n. l (n to o. 4) 0
0.1 to 0.4 (0.4 to 1 . =n 577 169 (577)
0.4 to 2.9 n.5 tn 10) 422 711 (2,427)
2.9 to 7.3 MO to 25) 251 1,288 (4,395)
7.3 to 14.7 (25 to 50) 10 113 (387)
14.7 to 29.3 (50 to 1 00^ .0
29.3 to 73.3 (100 to 250^ 0
73.3 to 146.5 (250 to 500^ 0
146.5 to 439.5 (500 to J500) 0
439.5 (1500) 0
C-80
-------
TABLE C-80. THE 1977 POPULATION OF OTHER INDUSTRIAL
FIRE-TUBE BOILERS FIRING COAL
Boiler classification; Fire-tube (other), industrial
Fuel and firing mechanism; Coal
Capacity, thermal
Number MW (10° fitu/h)
Class population
Distribution by capacity ranges,
thermal MW (1C)6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2. 9 to 7. 3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
582 553 (1,889)
0
404 118 (404)
140 237 (809)
38 198 (676)
0
0
0
0
0
0
C-81
-------
TABLE C-81. THE 1977 POPULATION OF INDUSTRIAL SCOTCH
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification: Fire-tube (Scotch) industrial
Fuel and firing mechanism: Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (1C>6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
18,268
0
9,445
6,955
1,580
288
0
0
0
0
0
25,142 (85,805)
2,767 (9,445)
11,095 (37,867)
8,118 (27,704)
3,162 (10,789)
C-82
-------
TABLE C-82. THE 1977 POPULATION OF INDUSTRIAL FIREBOX
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification: Fire-tube (firebox), industrial
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (10& Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2. 9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
24 .171
0
15, 833
6r682
1,368
288
0
0
0
0
0
25,574 (87,283)
4.638 (15,831)
10.745 (36.671)
7,029 (23,992)
3,162 (10,789)
C-83
-------
TABLE C-83. THE 1977 POPULATION OF INDUSTRIAL HRT FIRE-TUBE
BOILERS FIRING RESIDUAL OIL
Boiler classification; Firp—tnhp (HRT), industrial
Fuel and firing mechanism: Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
5,371 7,287 (24,873)
0
2,953 865 (2,953)
1,731 2,902 (9,907)
687 3,520 (12,013)
0
0
0
0
0
0
C-84
-------
TABLE C-84. THE 1977 POPULATION OF OTHER INDUSTRIAL
FIRE-TUBE BOILERS FIRING RESIDUAL OIL
Boiler classification; Fire-tube (other), industrial
Fuel and firing mechanism: Residual oil
Capacity, thermal
Number MW (10° Btu/h)
Class population 3,428
Distribution by capacity ranges,
thermal MW (106 Btu/h)
n t<~> 0, j (0 1-0 0T 4) 0
O.VPT- n,i 1-0 0,4 (0.4 1-0 1,5) 2,305
O-v^r 0, 4 to 2. 9 (1 . 5 to 10) 981
Ov^-r 2 9 to 7_ 3 M 0 to 251 118
OVP-T 73 1-o 14. 7 ( 2 5 to 501 24
Ov^r 14.7 1-n 29.3 (50 to 100) 0
Ovp_r 29.3 to 73.3 HOO to 2501 0
Ovpr 73 . 3 to 146.5 f250 to 5001 0
Dvpr 146 5 to 439.5 (500 tn 1500) 0
OVPT 4^^5(1500) 0
3,129 (10.678)
676 (2,304)
1.579 (5,391)
610 (2,084)
264 (899)
C-85
-------
TABLE C-85. THE 1977 POPULATION OF INDUSTRIAL SCOTCH
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification: Fire-tube (Scotch) , industrial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
9,127
0
4,389
3,599
964
175
0
0
0
0
0
13,895 (47,462)
1,283 (4,371)
5,742 (19,620)
4,954 (16,905)
1,916 (6,566)
C-86
-------
TABLE C-86. THE 1977 POPULATION OF INDUSTRIAL FIREBOX
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification;_.._ Fire-tube (firebox), industrial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population 11,823 13,921 (47,533)
Distribution by capacity ranges,
thermal MW (1Q6 Btu/h)
0 to 0.1 (0 to 0.4) 0
Over 0.1 to 0.4 (0.4 to 1.5) 7,357 2,157 (7,379)
Over 0.4 to 2.9 (1.5 to 10) 3,455 5,556 (18,960)
Over 2.9 to 7.3 (10 to 25) 836 4,292 (14,628)
Over 7.3 to 14.7 (25 to 50) 175 1,916 (6,566)
Over 14.7 to 29.3 (50 to 100) 9
Over 29.3 to-73.3 (100 to 250) °
Over 73.3 to 146.5 (250 to 500) °
Over 146.5 to 439.5 (500 to 1500) 2
Over 439.5 (1500) °_
C-87
-------
TABLE C-87. THE 1977 POPULATION OF INDUSTRIAL HRT
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification; Fire-tube (HRT). industrial
Fuel and firing mechanism: Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population 2,695 4,013 (14,313)
Distribution by capacity ranges,
thermal MW (1C)6 Btu/h)
0 to 0.1 (0 to 0.4) Q
Over 0.1 to 0.4 (0.4 to 1.5) 1,462 399 (1,363)
Over 0.4 to 2.9 (1.5 to 10) 892 If314 (5,100)
Over 2.9 to 7.3 (10 to 25) 417 2.139 (7.314)
Over 7.3 to 14.7 (25 to 50) 14 161 (536)
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to-73.3 (100 to 250) 0
Over 73.3 to 146.5 (250 to 500) 0
Over 146.5 to 439.5 (500 to 1500) 0
Over 439.5 (1500) 0
C-J
-------
TABLE C-88. THE 1977 POPULATION OF OTHER INDUSTRIAL
FIRE-TUBE BOILERS FIRING DISTILLATE OIL
Boiler classification; ^i rp-l-nhp- (n-hh^r
Fuel and firing mechanism; Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2. 9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
1.651
n
1.072
507
72
0
0
0
0
0
0
1.504 (5,083)
315 (1,081)
816 (2,760}
373 (1.212)
C-89
-------
TABLE C-89. THE 1977 POPULATION OF INDUSTRIAL SCOTCH
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube (Scotch), industrial
Fuel and firing mechanism: Natural gas
Number
Capacity, thermal
MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7. 3 to 14. 7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to 73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
in, QR?
0
16r280
11.045
2,979
649
0
0
0
0
0
4R, nr>Q n R^ RRI \
4,769 (16.254)
17,808 (60,800)
15,303 (52,200)
7,129 (24,297)
C-90
-------
TABLE C-90. THE 1977 POPULATION OF INDUSTRIAL FIREBOX
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification; Fire-tube (firebox), industrial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (106 Btu/h)
Class population 41,435 46.039 (157,028)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 0
Over 0.1 to 0.4 (0.4 to 1.5) 27.295 7.995 (27.279)
Over 0.4 to 2.9 (1.5 to 10) 10,928 17,752 (60,560)
Over 2.9 to 7.3 (10 to 25) 2,563 13.163 (44.892)
Over 7.3 to 14.7 (25 to 50) 649 7,129 (24.297)
Over 14.7 to 29.3 (50 to 100) Q
Over 29.3 to-73.3 (100 to 250) 2
Over 73.3 to 146.5 (250 to 500) °
Over 146.5 to 439.5 (500 to 1500) P.
Over 439.5 (1500) 9
C-91
-------
TABLE C-91. THE 1977 POPULATION OF INDUSTRIAL HRT
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification: Fire-tube (HRT), industrial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (10^ Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
0
5,143
3,278
1,472
53
0
0
0
0
0
1,506 (5.166)
5.504 (18,800)
7,552 (25,752)
596 (2,047)
C-92
-------
TABLE C-92. THE 1977 POPULATION OF OTHER INDUSTRIAL
FIRE-TUBE BOILERS FIRING NATURAL GAS
Boiler classification; Fire-tube (other), industrial
Fuel and firing mechanism; Natural gas
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
5.733 4r839 (17,216}
0
3,876 1,134 (3,906)
1,611 2,624 (8,960)
246 1.261 (4.350)
0
0
0
0
0
0
C-93
-------
T<~BLE C-93. THE 1977 POPULATION OF INDUSTRIAL CAST IRON
BOILERS FIRING COAL
Boiler classification; Cast iron, industrial (space heating)
Fuel and firing mechanism: Coal
Number
Capacity, thermal
MW (loo Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
35.965
22,657
9.352
3.956
0
0
0
0
0
0
0
6.317 (21r560)
1,200 (4,096)
2,464 (8,409)
2.653 (9P055)
C-94
-------
TABLE C-94. THE 1977 POPULATION OF INDUSTRIAL CAST IRON
BOILERS FIRING RESIDUAL OIL
Boiler classification; Cast iron, industrial (space heating)
Fuel and firing mechanism; Residual oil
Capacity, thermal
Number MW (10& Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (1Q6 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
59,894
40,714
14.323
4,857
0
0
0
0
0
0
0
10,755 (36,706)
3,005 (10,257)
3,217 (10,979)
4,533 (15,470)
C-95
-------
TABLE C-95. THE 1977 POPULATION OF INDUSTRIAL CAST IRON
BOILERS FIRING DISTILLATE OIL
Boiler classification: Cast iron, industrial (space heating)
Fuel and firing mechanism; Distillate oil
Capacity, thermal
Number MW (10° Btu/h)
Class population
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4)
Over 0.1 to 0.4 (0.4 to 1.5)
Over 0.4 to 2.9 (1.5 to 10)
Over 2.9 to 7.3 (10 to 25)
Over 7.3 to 14.7 (25 to 50)
Over 14.7 to 29.3 (50 to 100)
Over 29.3 to-73.3 (100 to 250)
Over 73.3 to 146.5 (250 to 500)
Over 146.5 to 439.5 (500 to 1500)
Over 439.5 (1500)
37,612
25,567
8,996
3,049
0
0
0
0
0
0
0
6.748 (23,031)
1,886 (6,436)
2,018 (6,889)
2,844 (9,706)
C-96
-------
TABLE C-96. THE 1977 POPULATION OF INDUSTRIAL CAST IRON
BOILERS FIRING NATURAL GAS
Boiler classification: Cast iron, industrial (space heating)
Fuel and firing mechanism: Natural gas
Capacity, thermal
Number MW (1QQ Btu/h)
Class population 161,827 28,702 (137,599)
Distribution by capacity ranges,
thermal MW (106 Btu/h)
0 to 0.1 (0 to 0.4) 105.258 7.742 (66.062)
Over 0.1 to 0.4 (0.4 to 1.5) 43.764 10.065 (34.352)
Over 0.4 to 2.9 (1.5 to 10) 12.805 10.895 (37.185)
Over 2.9 to 7.3 (10 to 25) 0
Over 7.3 to 14.7 (25 to 50) 0
Over 14.7 to 29.3 (50 to 100) 0
Over 29.3 to-73.3 (100 to 250) 0
Over 73.3 to 146.5 (250 to 500) 0
Over 146.5 to 439.5 (500 to 1500) 0
Over 439.5 (1500) Q
C-97
-------
APPENDIX D
BOILER FUEL CONSUMPTION
This appendix provides a description of the data sources and
procedures used to develop estimates of boiler fuel consumption.
The International System of Units (SI) is not used here, because
the original sources were not in SI units. To make it easier to
process the data, they were not converted to SI units until final
figures were obtained.
Fuel consumption figures for industrial boilers were derived
from five sources:
Mineral Industry Survey: Bituminous Coal and Lignite
Distribution in 1975. U.S. Bureau of Mines, Washington,
D.C., April 1976. (Referred to here as MIS-Coal.)
Mineral Industry Survey: Sale of Fuel Oil and Kerosene
in 1975. U.S. Bureau of Mines, Washington, D.C.,
September 1976. (Referred to here as MIS-Oil.)
Mineral Industry Survey: Natural Gas Production and
Consumption. U.S. Bureau of Mines, Washington, D.C.,
October 1976. (Referred to here as MIS-Gas.)
Fuel and Energy Data: United States by States and
Census Divisions in 1974. U.S. Bureau of Mines Infor-
mation Circular 1C 8739, 1977. (Referred to here as 1C
8739.)
Major Fuel Burning Installation Data File. Federal
Energy Administration, Washington, D.C., 1975.
(Referred to here as MFBI data.)
Other references used less frequently are cited in the text.
In most instances, the categories used in the sources to
tabulate energy consumption statistics do not match the cate-
gories used in this study, which are:
D-l
-------
Industrial Boilers
Coal
Residual oil
Distillate oil
Gas
Commercial and Institutional Boilers
Coal
Residual oil
Distillate oil
Gas
The sections that follow describe how the data from the
energy reports were used, and how the estimates of boiler fuel
consumption were compiled.
INDUSTRIAL BOILERS
Coal
MIS-Coal gives the destinations for 1975 coal shipments:
Category Coal shipments, 1CH tons
Electric utilities 438,558
Coke and gas plants 92,497
Retail dealers 5,043
All others 53,718
Exports, plus misc. 51,010
categories
Total 640,826
The miscellaneous uses include such items as coal consume'd at
mines.
It was assumed for the categories, which were derived from
these data (i.e., industrial and commercial coal consumption),
that shipments would approximate consumption. The total indus-
trial shipments shown above for 1975 (coke and gas plants, and
the item labelled "all others") totalled 157.0 x 106 tons (p. 48,
MIS-Coal); while 1C 8739 reported 1974 consumption as 148.7 x 106
tons. Based on this information, the assumption seems reasonable.
The most recent consumption data was compiled in 1977, when 1C
8739 was published.
D-2
-------
"All others" includes the coal that is directly consumed in
industrial processes other than utility boilers and coke plants.
The two major components in this category are boiler fuel and
direct process heat. The MFBI data for individual states divides
industrial coal consumption into percentages used in electric
generation, process steam, industrial space heating, and other
uses (Table D-l). These percentages were applied to the "all
others" category of coal consumption for each state, so that
figures for the different uses could be derived. The totals were
then used to derive weighted averages for type of usage. The
usage percentages are:
Category Percentage
Electric generation 25
Space heat 15
Process steam 60
The combined consumption for industrial process steam, industrial
space heating, and electric generation was taken as the estimate
for coal consumption in boilers:
Category Consumption, 10^ tons
Electric generation 9,844
Space heat 5,906
Process steam 23,624
Total boiler fuel 39,371
Residual Oil
The consumption data for residual oil were taken from MIS-
Oil (Table 3, p 4). Sales of residual oil were:
Category Consumption 10 bbl
Heating 155,103
Industrial 112,362
(excluding refineries)
Oil company use 50,487
Electric utility co. 454,939
Railroads 583
Vessels 96,673
Military 19,068
All other 6,066
Total 895,281
D-3
-------
TABLE D-l. DISTRIBUTION OF COAL CONSUMPTION BY USE FROM MFBI DATA
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Consumption,
103 tons/yr
2,163
500
112
34
275
680
24
22
246
18
365
0
386
3,494
3,545
1,089
113
1,328
0
25
Electrical
generation
%
19
33
0
a
0
17
a
a
1
a
5
a
3
18
22
4
a
1
0
a
103 tons
411
165
0
0
116
2
18
12
629
780
44
13
0
Space heating
%
2
60
0
a
10
2
a
a
86
a
5
a
0
15
6
4
a
20
40
a
10 tons
42
300
0
28
14
212
18
0
524
213
44
266
0
Process steam
%
50
7
0
a
90
20
a
a
12
a
61
a
68
50
16
48
a
68
60
a
10 tons
1,082
35
0
247
136
30
223
262
1,747
567
523
903
0
Other
%
29
0
100
a
0
61
a
a
1
a
29
a
29
17
56
44
a
11
0
a
10 tons
628
0
112
0
414
2
106
112
594
1,985
478
146
0
o
I
(continued)
-------
TABLE D-l (continued)
•State
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
Consumption,
103 tons/yr
294
91
3,883
1,140
20
1,502
42
259
63
4
38
0
2,121
1,245
480
8,355
17
98
4,598
1
994
Electrical
generation
%
10
a
5
10
0
5
a
33
35
a
0
a
5
11
10
19
a
2
14
a
39
10 tons
29
194
114
0
75
86
22
0
106
137
48
1,584
2
644
388
Space heating
%
0
a
23
18
0
9
a
0
30
a
25
a
18
15
2
9
a
0
7
a
4
10 tons
893
205
0
135
0
19
10
382
187
10
750
0
322
40
Process steam
%
30
a
36
72
0
28
a
67
15
a
75
a
64
63
88
37
a
54
24
a
57
10 tons
88
1,398
821
0
421
173
10
28
1,357
784
422
3,084
53
1,104
566
Other
%
60
a
36
0
100
58
a
0
20
a
0
a
13
11
0
35
a
44
55
a
0
10 tons
177
1,398
0
20
871
0
12
276
137
0
2,197
43
2 ,528
0
o
I
01
(continued)
-------
TABLE D-l (continued)
a
i
CTl
State
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Total
Consumption,
103 tons/yr
50
1,589
2,325
460
2
2,362
390
3,385
1,842
539
52,588
Electrical
generation
%
100
5
80
21
a
15
0
30
20
27
18
103 tons
50
79
1,860
97
354
0
1,016
368
146
9,589
Space heating
%
0
12
1
4
a
10
14
5
19
3
11
10 tons
0
191
23
18
236
55
169
350
16
5,672
Process steam
%
0
72
14
19
a
66
86
54
59
51
44
10 tons
0
1,144
326
87
1,559
335
1,828
1,087
275
22,705
Other
%
0
11
5
56
a
9
0
11
2
19
27
10 tons
0
175
116
258
213
0
372
37
102
14,229
Not available.
-------
The heating category comprises household and commercial use.
Fuels for industrial boilers are .included under the categories
for industrial and oil company use. Battelle (Kim, et al., 1974)
estimated the consumption in the industrial category to be 90
percent by boilers and oil company use was estimated to be 40
percent by boilers.
These estimates yield the following totals for residual oil
consumption in boilers:
Industrial 112,362 x 0.90 = 101,125 x 103 bbl
Oil company use 50,487 x 0.40 = 20,194 x 103 bbl
Total 121,319 x 103 bbl
MFBI data were used to derive percentages of residual oil
usage comparable to those derived for coal:
Category Percentage
Electric generation 10
Space heat 11
Process steam 56
Other 23
When applied to the total consumption of 162,849 bbl, this
distribution yields the following boiler consumption:
Category Consumption, 10 bbl
Electric generation 16,285
Space heat 17,914
Process steam 91,195
Total boiler fuel 124,394
Values for individual states are shown in Table D-2.
Distillate Oil
The consumption data for distillate oil were taken from
MIS-Oil (Table 2, p.4). Values given by category are listed
below:
D-7
-------
TABLE D-2. DISTRIBUTION OF RESIDUAL OIL CONSUMPTION BY
USE FROM MFBI DATA
D
I
oo
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Consumption,
103 bbl
2,575
574
140
2,968
3,786
973
5,151
1,678
0
6,616
4,330
187
109
3,428
4,041
76
214
220
3,533
4,067
Electrical
generation
%
9
4
100
17
0
5
11
18
0
11
12
0
a
2
9
0
0
0
6
19
103 bbl
232
23
140
505
0
49
567
302
0
728
520
0
69
364
0
0
0
212
773
Space heating
%
2
0
0
2
0
20
14
6
88
2
1
0
a
3
13
8
2
2
2
6
103 bbl
52
0
0
59
0
195
721
101
0
132
43
0
103
525
6
4
4
71
244
Process steam
%
68
96
0
74
26
55
50
76
12
65
75
68
a
58
53
92
48
52
54
69
103 bbl
1,751
551
0
2,196
984
534
2,576
1,275
0
4,300
3,247
127
1,988
2,142
70
103
114
1,920
2,806
Other
%
21
0
0
7
74
20
25
0
0
22
12
32
a
37
25
0
90
46
38
6
103 bbl
540
0
0
208
2,802
195
1,287
0
0
1,456
520
60
1,268
1,010
0
107
102
1,330
244
(continued)
-------
TABLE D-2 (continued)
a
i
State
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
Consumption ,
103 bbl
2,526
5,319
1,373
1,829
1,155
396
543
34
12
1,406
6,013
587
5,034
5,445
9
3,499
331
1,530
7,305
937
2,345
Electrical
generation
%
4
11
3
2
45
a
0
0
9
16
11
97
5
19
14
1
1
0
2
23
11
103 bbl
101
585
41
37
520
0
0
1
225
661
569
252
1,035
1
35
3
0
146
216
258
Space heating
%
40
30
24
27
1
a
0
0
7
18
14
0
17
6
3
11
1
6
14
9
3
103 bbl
1,010
1,596
330
494
12
0
0
1
253
842
0
856
327
0
385
3
92
1,203
84
70
Process steam
%
36
50
46
50
49
a
4
0
4
59
71
3
33
64
66
38
81
94
40
68
63
103 bbl
909
2,660
632
915
566
22
0
0
830
4,269
18
1,661
3,485
6
1,330
268
1,438
2,922
637
1,477
Other
%
20
9
27
21
5
a
96
100
80
7
4
0
45
11
17
50
17
0
44
0
23
103 bbl
506
478
370
383
57
521
34
10
98
241
0
2,265
598
2
1,749
57
0
3,214
0
540
(continued)
-------
i;ABLE D-2 (continued)
D
I
State
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Total
Consumption ,
103 bbl
51
237
5,704
2,737
195
6,501
2,968
834
410
431
111,611
Electrical
generation
%
a
0
4
0
a
13
28
1
15
49
10
103 bbl
0
228
0
845
831
8
62
211
11,355
Space heating
%
a
0
1
0
a
25
19
2
5
0
11
103 bbl
0
57
0
1,625
564
17
21
0
11,922
Process steam
%
a
100
92
10
a
58
48
40
80
6
56
103 bbl
237
5,248
274
3,771
1,425
334
327
26
62,371
Other
%
a
0
3
90
a
4
5
57
0
45
23
103 bbl
0
171
2,463
260
148
475
0
194
25,963
Not available.
-------
Category Consumption, 1C)3 bbl
Heating 487,120
Industrial (excluding
oil company use) 63,993
Oil company use 13,633
Electric utility Co. 65,203
Railroads 93,191
Vessels 26,138
Military 18,004
On-highway diesel 217,206
Off-highway diesel 48,977
All other 10,096
Total 1,043,561
As with residual oil, the industrial boiler consumption is
included in the categories for industrial and oil company use.
The MFBI data were again used to derive weighted averages for
type of usage.
Category Percent
Electric generation 8
Space heat 19
Process steam 32
Other 41
The data for individual states are shown in Table D-3.
The percentages were then applied as follows:
Category Consumption, 10^ bbl
Industrial 63,993
Oil company use 13,633
Total 77,626
Category Percent Consumption, 10 bbl
Electric generation 13.6 6,210
Space heat 32.2 14,749
Process steam 54.2 24,840
Total boiler fuel 100.0 45,799
It was assumed that the consumption of kerosene in boilers
was negligible (See MIS-Oil, 1, p. 4). Data shown for kerosene
use in 1975 are:
D-ll
-------
TABLE D-3. DISTRIBUTION OF DISTILLATE OIL CONSUMPTION BY
USE FROM MFBI DATA
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Dist, of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Consumption,
103 bbl
1,285
305
2,694
628
4,174
482
702
377
13
1,220
1,401
145
789
2,211
2,023
708
168
1,181
1,984
303
Electrical
generation
%
a
a
45
a
a
0
0
a
10
0
0
a
a
2
12
0
a
0
a
a
103 bbl
1,212
0
0
1
0
0
44
243
0
0
Space heating
%
a
a
0
a
a
23
0
a
70
0
8
a
a
62
18
5
a
25
a
a
103 bbl
0
111
0
10
0
112
1,371
364
35
295
Process steam
%
a
a
0
a
a
19
0
a
2
35
25
a
a
16
23
95
a
75
a
a
103 bbl
0
92
0
0
427
350
354
465
673
886
Other
%
a
a
55
a
a
58
100
a
18
65
67
a
a
20
47
0
a
0
a
a
103 bbl
1,482
279
702
2
793
939
442
951
0
0
D
I
M
NJ
(continued)
-------
TABLE D-3 (continued)
State
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhoda Island
South Carolina
Consumption,
103 bbl
1,309
823
2,017
725
540
1,059
1,236
240
281
94
2,329
798
2,078
2,301
87
5,362
1,117
1,640
4,331
191
872
Electrical
generation
%
88
0
2
a
a
24
a
a
0
0
0
0
2
0
a
7
0
0
4
a
a
103 bbl
1,152
0
40
254
0
0
0
0
42
0
375
0
0
173
Space heating
%
2
0
44
a
a
2
a
a
33
0
41
0
10
0
a
16
0
0
54
a
a
103 bbl
27
0
887
21
93
0
955
0
208
0
858
0
0
2,339
Process steam
%
5
0
40
a
a
74
a
a
67
0
0
0
18
0
a
42
100
0
33
a
a
103 bbl
65
0
807
784
188
0
0
0
374
0
2,252
1,117
0
1,429
Other
%
5
100
14
a
a
0
a
a
0
100
59
100
70
100
a
35
0
100
9
a
a
103 bbl
65
823
283
0
0
94
1,374
798
1,454
2,301
1,877
0
1,640
390
D
I
(continued)
-------
TABLE D-3 (continued)
D
i
State
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Totalb
Consumption,
103 bbl
63
1,433
2,832
1,426
79
2,273
1,803
704
477
680
44,206
Electrical
generation.
%
a
0
32
0
0
11
0
0
0
79
8
103 bbl
0
906
0
0
250
0
0
0
537
3,767
Space heating
%
a
22
0
0
0
3
16
0
38
0
19
103 bbl
315
0
0
0
68
288
0
181
0
8,435
Process steam
%
a
65
68
100
0
86
4
0
27
0
32
103 bbl
931
1,926
1,426
0
1,955
72
0
129
0
14,074
Other
%
a
13
0
0
100
0
80
100
35
21
41
103 bbl
187
0
0
79
0
1,433
704
167
143
17,930
a Not available.
Excluding Arizona, Iowa, and Virginia due to erroneous data.
-------
Category Consumption, 10-^ bbl
Heating 45,127
All other uses 12,864
Total 57,991
Gas
The industrial gas consumption was obtained from MIS-Gas
(Table 7). The total for industrial gas is shown as 6,979,963 x
a *3 a "D
10 ft ; this figure includes 945,557 x 10 ft used as refinery
fuel, 26,246 x 10 ft used for carbon black production, andean
unspecified amount used as chemical feedstocks. The chemical
feedstock consumption was estimated by using data from a Shell
Oil Company Report (Shell, 1978). In this report the consumption
of natural gas for use as feedstocks is shown as 705 x 10
Btu/yr or an equivalent 688,480 x 10J ft .
The MFBI data given below, are assumed to include the
refinery and carbon black consumption, and the percentage dis-
tributions derived for boiler fuels and other consumption were
applied to the total industrial gas consumption minus the esti-
mated feedstock consumption.
The percentages of industrial gas consumption derived from
MFBI data were:
Category Percentage
Electric generation 7
Process steam 49
Space heat 7
Other 37
Total 100
The data from individual states are shown in Table D-4,
The total consumption for boiler fuels was calculated to be;
Category 106 ft3
Electric generation 440,404
Process steam 3,082,827
Space heat 440,404
Total boiler fuel 3,963,635
D-15
-------
TABLE D-4. DISTRIBUTION OF NATURAL GAS CONSUMPTION BY
USE FROM MFBI DATA.
O
I
I—
CTl
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine, N« Hampshire
Maryland, D.C.
Consumption,
106 ft3
153,540
22,388
50,868
128,151
581,609
65,609
15,553
6,957
Included with
83,364
145,479
0
29,898
352,291
223,383
121,489
124,378
64,856
922,673
3,330
43,165
Electrical
generation
%
2
10
39
5
2
15
5
0
106 ft3
3,071
2,239
19,839
6,407
11,632
9,841
778
0
Maryland
13
7
a
5
5
1
13
7
1
17
0
36
10,837
10,184
0
1,495
17,615
2,234
15,794
8,706
649
156,854
0
15,539
Space heating
%
1
21
0
1
1
14
34
1
4
11
a
1
7
5
7
4
22
2
100
6
106 ft3
1,535
4,071
0
1,282
5,816
9,185
5,288
70
3,335
16,003
0
299
24,660
11,169
8,504
4,975
14,268
18,453
3,330
2,590
Process steam
%
50
28
9
63
45
34
45
37
41
56
a
94
40
23
48
57
71
60
0
52
106 ft3
76,770
6,269
4,578
80,735
261,724
22,307
6,999
2,574
34,179
81,468
0
28,104
140,916
51,378
58,315
70,895
46,048
553,604
0
22,446
Other
«
47
41
52
31
52
37
16
62
42
26
a
0
48
71
32
32
6
21
0
6
106 ft3
72,164
9,179
26,451
39,727
302,437
24,276
2 ,488
4,313
35,013
37,824
0
0
169,100
158,602
38,876
39,802
3,^91
193,762
0
2,590
(continued)
-------
TABLE D-4 (continued]
o
I
State
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
Consumption ,
106 ft3
23,986
301,573
100,539
98,848
89,913
31,631
72,792
10,043
Electrical
generation
%
4
12
7
3
5
13
0
0
Included with Maine
52,361
57,773
104,429
62,094
1,975
341,612
142,813
57,332
261,447
5,820
70,329
17
36
5
9
a
8
2
0
4
a
3
106 ft3
959
36,189
7,038
2,965
4,496
4,112
0
0
8,901
20,798
5,221
5,588
27,329
2,856
0
10,458
2,110
Space heating
%
7
28
19
1
15
9
6
0
13
27
20
36
a
6
4
3
5
a
10
106 ft3
1,679
84,440
19,102
988
13,487
2,847
4,368
0
6 ,807
15,599
20,886
22,354
20,497
5,713
1,720
13,072
7,033
Process steam
%
88
29
46
58
56
39
41
0
46
8
19
47
a
29
56
73
30
a
51
106 ft3
21,108
87,456
46,248
57,332
50,351
12,336
29,845
0
24,086
4,622
19,842
29,184
99,067
79,975
41,852
78,434
35,868
Other
%
1
31
26
38
24
39
53
100
24
29
56
8
a
57
38
24
61
a
36
106 ft3
240
93,488
28,151
37,563
21,579
12,336
38,579
10,043
12,567
16,754
58,480
4,968
194,719
54,269
13,760
159,483
25,318
(continued!
-------
TABLE D-4 (continued)
O
I
M
CO
State
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Totals'3
Consumption,
106 ft3
5,813
111,281
1,396,790
48,104
Electrical
generation
%
0
9
3
59
Included with Maine
36,427
92,142
66,155
152,443
43,618
6,846,885
2
2
2
7
4
7
106 ft3
0
10,015
41,904
28,381
729
1,843
1,323
10,671
1,745
506,266
Space heating
%
5
5
1
0
15
15
8
36
1
7
106 ft3
291
5,564
13,698
0
5,464
13,821
5,292
54,879
436
475,035
Process steam
%
70
64
63
1
75
52
54
42
72
49
106 ft3
4,069
71,220
879,978
481
27,320
47,914
35,724
64,026
31,405
3,364,965
Other
%
25
22
33
40
8
31
36
15
23
37
106 ft3
1,453
24,482
460,941
19,242
2,914
28,564
23,816
22,867
10,032
2,500,619
Not available.
Excluding Arizona, Idaho, Rhode Island, and Wyoming due to erroneous data.
-------
COMMERCIAL BOILERS
Coal
The figures for commercial coal consumption were obtained
from MIS-Coal (p. 48). The basic data have been discussed
earlier in the section for industrial coal. The categories
involved are:
Coal shipments, 10 tons
Category
Electric utilities 438,558
Coke and gas plants 92,497
Retail dealers 5,043
All others 53,718
Exports, plus misc. 51,010
categories (totaling
2.3 x 103 tons)
Total 640,826
Consumption in residential boilers was considered negligi-
ble. Shipments to retail dealers were assumed to be used in
commercial boilers. For 1974, 1C 8739 shows coal consumption in
the household-commercial category at 6558 x 10 tons (p. 22).
This figure is similar to the reported 1975 coal shipments to
retail dealers of 6792 x 103 tons (MIS-Coal, p. 48). Hence, the
categories are comparable.
Residual Oil
The data for commercial boiler consumption were derived from
MIS-Oil (Table 3, p. 4). In this source, the category labelled
"Heating" in the discussion of industrial residual oil consump-
tion was assumed to refer to commercial boilers. The 1975 sales
for residual oil in this category totaled 172,892 x 10 bbl. The
1974 consumption figures from 1C 8739 (p. 134) show 167,415 x 10
bbl in the household-commercial category- According to Battelle,
fuel in this category would be burned in large apartment and
commercial buildings, using boilers of the type classified as
commercial for this study. Consequently, the 155,103 x 10 bbl
of residual oil given in MIS-Oil (Table 3, p. 4) were classified
as commercial boiler fuel.
D-19
-------
Distillate Oil
The data for "Heating" shown in MIS-Oil (Table 2, p. 4) were
used to derive the amounts of distillate oil consumed in commer-
cial boilers. A considerable portion of the distillate oil in
this category was known to be burned in residences. Because
residential consumption is not reported separately, an indirect
approach was taken to determine the portion. The number of
residential burners in service as of January 1, 1976, was re-
ported to be 12,020,936 (Fuel Oil and Oil Heat, 1978). The
Battelle boiler inventory report (Putman et al., 1975) estimated
the average residential burner to be a unit consuming 153 x 10
Btu/yr. This figure was apparently an error in computation, if
other Battelle data (Tables 10 and 11, p. 24) are correct. The
number of oil-burning residential units is given as 14,800 x 10
units, and the consumption of oil and kerosene in residential
12
units as 2,424 x 10 Btu. The calculated average residential
consumption is:
Avg. consumption per unit = 2424 x 10 Btu = 164 x 106 Btu
14.8 x 10 Btu
Using this figure and the total number of residential burners in
service, the total residential consumption is calculated as:
Residential consumption, 1975 = 12,020,936 x 164 x 106 Btu
= 1977.3 x 1012 Btu
The total heating value of oil in MIS-Oil under the heating
category is:
Heating category = 487,120 x 103 bbl x 5.83 x 106
, - bbl
= 2839.9 x 10 Btu
Subtracting the residential consumption from the total, the com-
mercial consumption is calculated as:
All heating 2839.9 x 1012 Btu
Residential consumption 1977.3 x 1012 Btu
Commercial consumption 862.6 x 1012 Btu
12
Commercial consumption = ^^ * 10^ = 147'959 x 1C)3
D-20
-------
Gas
Data for gas burned in commercial boilers were derived from
MIS-Gas (Table 7). The total amount of gas delivered to com-
mercial customers was 2,268,128 x 10 ft . According to Stanford
(1972), 66 percent of the gas sent to commercial customers is
used for space heating, with the balance of 34 percent being used
for water heating, air conditioning, and cooking.
Total for commercial boilers = 0.66 (2,268,126) x 106 ft3
- 1,496,963 x 106 ft3
FUEL CONSUMPTION SUMMARY
Factors for converting the figures for fuel consumed to
Btu's were taken from 1C 8739 and are shown below:
p 7, Natural gas 1024 Btu/ft3
p 7, Distillate oil 5.83 x 106 Btu/bbl
p 7, Residual oil 6.29 x 106 Btu/bbl
p 22, Coal 24.8 x 106 Btu/ton
The coal value was calculated from the total industrial coal
shipments for 1974 (148,772 x 103 tons) and the reported Btu
12
equivalent (3689.2 x 10 Btu).
Final consumption figures are summarized below:
12
Industrial Quantity Btu's, 10
Coal (103 tons) 39,374 976.5
Residual oil (103 bbl) 125,067 786.7
Distillate oil (103 bbl) 45,799 267.0
Gas (10<5 ft3) 3,963,635 4,058.8
Commercial
Coal (103 tons) 5,043 125.1
Residual oil (103 bbl) 155,103 975.6
Distillate oil (103 bbl) 147,959 862.6
Gas (106 ft3) 2,268,128 2322.4
D-21
-------
REFERENCES FOR APPENDIX D
Fejer, M.E., and Larson, D.H., 1974. Study of Industrial Uses of
Energy Relative to Environmental Effects. Institute for Gas
Technology.
Fuel Oil and Oil Heat, 1978. Special Report. Industry Publica-
tions, Inc.
Kim, B.C., K. Murthy, and D.M. Jenkins, 1974. Pollutants from
Residual Oil Combustion. Battelle Columbus Laboratories.
EPA Contract No. 68-02-1323, Task 4.
Putnam, A.A., E.L. Kropp, and R.E. Barrett, 1975. Evaluation of
National Boiler Inventory. Battelle Columbus Laboratories.
EPA Contract No. 68-02-1223, Task 31.
Shell Oil Company, 1978. National Energy Outlook, 1980 to 1990.
Stanford Research Institute, 1972. Patterns of Energy Consump-
tion in the United States. PB-212776.
D-22
-------
APPENDIX E
DERIVATION OF THE PEDCO INDUSTRIAL BOILER GROWTH FACTOR
This appendix provides a description of the data sources and
procedures used to develop estimates of boiler growth. The
International System of Units (SI) is not used here, because the
original sources were not in SI units. To make it easier to
process the data, they were not converted to SI units until final
figures were obtained.
The main reference used for the development of the PEDCo
industrial boiler growth factor was: Study of Industrial Uses of
Energy Relative to Environmental Effects, written by the In-
stitute of Gas Technology (IGT) for the U.S. Environmental Pro-
tection Agency in July 1974. From this report, energy uses for
the four most energy-intensive industries were calculated for the
years 1971, 1975, 1980, and 1985. The report provides the IGT
estimates of future industrial production. By assuming a con-
stant ratio of energy consumed to tons of product produced, the
energy for other years was calculated. For example (IGT, p. II-
1), the total energy use for the paper and paperboard industries
in 1971 was 1310 x 10 Btu. The production for 1971 was 56 x
10 tons. The IGT report estimates that the 1980 production of
this industry will be 77 x 10 tons. The ratio of energy use to
tons of product was held constant at 23.39 x 10 Btu/ton. Thus,
ft 1 ?
in 1980, to produce 77 x 10 tons would require 1802 x 10 Btu.
The energy use for the four key industries in 1971, 1975, 1980,
and 1985 are presented in Table E-l.
Two calculations were then conducted to determine:
0 The percentage that each Standard Industrial Classifi-
cation (SIC) represented of the total energy use for
each year.
0 The percentage rate of growth for the total time inter-
val (i.e., 1971-1985) for each SIC.
E-l
-------
TABLE E-l. PROJECTED TOTAL ENERGY USAGE BY THE FOUR
MAJOR ENERGY-INTENSIVE INDUSTRIES
J (1012 Btu)]
Industry
Paper and allied
products
Chemical products
Mineral products
Primary metals
Total
1971
1,284 (1,218)
3,969 (3,764)
724 (687)
4,074 (3,864)
10,051 (9,533)
1975
1,537 (1,459)
4,824 (4,575)
802 (761)
4,884 (4,632)
12,047 (11,426)
1980
1,766 (1,675)
587 (5,569)
879 (834)
5,894 (5,590)
14,411 (13,668)
1985
2,018 (1,914)
6,936 (6,484)
948 (899)
6,921 (6,564)
16,723 (15,861)
H'
-------
The purpose of these calculations was to determine an over-
all growth factor for the four industries during the 1971 to 1985
period.
The percentage of the total energy use for each indicated
year is shown in Table E-2.
TABLE E-2. PERCENTAGE OF TOTAL ENERGY USE
BY INDUSTRIAL CLASSIFICATION
Standard
Industrial
Classification
26
28
32
33
Total
1971
12.8
39.5
7.2
40. 5
100
1975
12.8
40.0
6.7
40.5
100
1980
12.3
40.7
6.1
40.9
100
1985
12.1
40.9
5.6
41.4
100
Avg . , %
12.5
40.3
6.4
40.8
100
The rate of growth for the 14-year period was derived by the
following expression:
14
1985 energy use
1971 energy use
For example, for SIC 26,
14
Rate of growth =
1914
1218
= 1.033
These rates of growth were then utilized with the percentage
of the total energy use by each SIC to derive a weighted average
rate of growth industry-wide. This calculation is presented as:
SIC 26 SIC 28 SIC 32 SIC 33
(0.125 x 1.033) + (0.403 x 1.04) + (0.064 x 1.02) + (0.408 x 1.039;
= 1.037.
E-3
-------
The growth factor was assumed to be representative for all
industry and applicable through the year 2000. Thus, a formula
for calculating use for any given year was derived.
The equation for calculating energy use for the four key
industries for this period can be expressed as:
Ef = (E ) (1.037X)
where
Ef = Energy use at some future date
E = Energy use in 1985
P
x = The number of years between 1985 and the future date.
E-4
-------
APPENDIX F
ESTIMATION OF BOILER AIR EMISSIONS
GENERAL
The reports from which emissions were derived are as follows:
Annual Summary of Cost and Quality of Steam - Electric Plant
Fuels - 1975. Federal Power Commission, May 1976. (Re-
ferred to here as FPC.)
Mineral Industry Survey. Bituminous Coal and Lignite Dis-
tributions - 1975. U.S. Bureau of Mines, Washington, D.C.
April 1976. (Referred to here as MIS - Coal.)
Major Fuel Burning Installation Data File. Federal Energy
Administration, Washington, D.C. 1975. (Referred to here
as MFBI.)
AP-42 Emission Factors, Section 1. External Combustion
Sources. U.S. Environmental Protection Agency. (Referred
to here as AP-42.)
Heating Oils - 1977. Battesville Energy Research Center.
Energy Research and Development Administration. August
1977. (Referred to here as Heating Oils.)
Design Trends and Operating Problems in Combustion Modifica-
tion of Industrial Boilers. Battelle Columbus Laboratories.
March 1974. (Referred to here as Battelle design study.)
Mineral Industry Survey. Sale of Fuel Oil and Kerosene
in 1975. U.S. Bureau of Mines, Washington, D.C. September
1976. (Referred to here as MIS - Oil.)
The basic steps in deriving estimates of boiler emissions
are described below:
1) Average percentages of sulfur and ash were derived from
data on quality of coal, residual oil, and distillate
oil being used.
F-l
-------
2) Emission factors from AP-42 were reviewed to find those
that corresponded to particular boiler types. On this
basis, the present boiler population was divided into
the following nine categories:
a) Pulverized coal
b) Spreader stoker
c) Overfeed stoker
d) Underfeed stoker
e) Other stoker
f) Residual oil
g) Distillate oil
h) Natural gas (industrial)
i) Natural gas (commercial)
3) The boiler capacity data were analyzed to determine the
percentage of total capacity in each of the above
categories.
4) Fuel consumption, which was assumed to be proportional
to total capacity, was calculated for each boiler
category by using the percentages derived in Step 3.
5) Estimates were compiled for uncontrolled discharges of
sulfur dioxide, particulate matter, nitrogen oxides,
hydrocarbons, and carbon monoxide, based on the level
of fuel consumption and the sulfur and ash content.
These computations are discussed below.
DETERMINATION OF SULFUR AND ASH PERCENTAGES
State coal consumption in the "all others" category (MIS-
Coal, 1975, pp. 49-50) was multiplied by the fraction of coal
that is consumed as boiler fuel (MFBI, 1975) to find the amount
for coal burned in boilers. This amount was used with the weighted
average percentage of sulfur in coals burned in utility boilers
to find the amount of sulfur in the coal. The percentage of
sulfur was taken from data from the Federal Power Commission
(FPC, 1976, pp. 4-5) and the values reported for utility boilers
were assumed to apply to all boilers in the individual states.
The total sulfur in the coals burned in each state was calculated.
Based on this total and on the total boiler fuel burned in indus-
trial boilers, a weighted average sulfur content was derived for
the coal burned in individual states.
F-2
-------
Sample calculations are shown below:
Alabama
Consumption of "all others" coal, from
MIS-Coal (p. 50) 2163 x 10 tons
Percentage of boiler coal, from MFBI (1975) 71 percent
Percentage of sulfur in coal, from FPC 2.3 percent
Sulfur content of boiler coal
= 2163 x 103 (0.71)(0.023) - 35,000 tons
The tons of sulfur per ton of coal and the total coal con-
sumption were summed for individual states. From this, a
weighted average percentage of sulfur in boiler coals was cal-
culated.
The "all other" consumption data, the MFBI percentage for
industrial boilers, the percentage of sulfur in the coal, and the
derived values for sulfur content are shown in Table F-l. The
weighted national average for sulfur was 2.0 percent.
The same approach was used to find the weighted national
average for ash, which is 13.4 percent. The data for this com-
putation are shown in Table F-2.
A similar approach was used to find the national average
percentages of sulfur in residual and distillate oil. For oil,
individual state sulfur levels were taken from Heating Oils (1977,
p. 13, Table 6). Regional values were used for all states
included in the regions shown in Figure 1 of that publication for
states that were included in more than one region, and an average
value was used. Data on oil consumption, by state, were taken
from MIS-Oil. The results showed average sulfur levels for resid-
ual and distillate oils at 1.51 and 0.235 percent, respectively.
Data for the computations are shown in Tables F-3 and F-4.
AP-42 EMISSION FACTORS
The emission factors from AP-42 pertaining to industrial
boilers were given as:
F-3
-------
TABLE F-l. SULFUR CONTENT OF COAL
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
Mew Mexico
Total coal
consumption,
103 tons
2,163
112
34
275
680
24
22
18
365
386
3,494
3,545
1,089
113
1,328
-0-
25
294
91
3,883
1,140
20
1,502
42
259
63
4
38
-0-
Consumption
by
boilers, %
71
N.A.
73
73
39
73
73
71
73
73
83
44
56
73
89
100
73
40
73
64
100
N.A.
42
73
100
80
73
100
73
Sulfur
content ,
%
2. 3
0. 5
0. 6
0.5
0.5
1.9
2.1
2.9
1. 8
0.5
2.4
2.8
2.0
3.2
3.3
0.6
1.9
1.6
1.0
2.4
1.3
2.6
3.3
0.7
0.9
0.4
2.4
1.9
0.6
Sulfur
content ,
tons
35,300
-0-
149
1,003
1,326
«
333
337
371
4,796
1,409
69,600
43,674
12,197
2,640
39,003
-0-
347
1,882
664
59,6*3
14,820
-0-
20,818
215
2,331
202
70
722
-0-
[continued)
F-4
-------
TABLE F-l (continued)
State
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washi ngton
West Virginia
Wisconsin
Wyoming
Alaska
Hawaii
Total
Total coal
consumption,
103 tons
2,121
1,245
480
8,335
17
98
4,598
1
994
50
1,589
2,325
460
2
2,362
390
3,385
1,842
539
500
246
52,588
Consumption
by
boilers, %
87
89
100
65
73
56
45
73
100
100
89
95
44
73
91
100
89
98
81
100
73
Sulfur
content,
%
1.9
1.1
0.6
3.0
0.6
0. 5
2.1
1.9
1.3
0.8
2.9
0.6
0.5
1.0
0.8
0.5
2.1
2.3
0.5
0.5
0.7
2.0
(avg. )
Sulfur
content,
tons
35,060
12,189
2,880
162,532
74
274
43,451
14
12,922
400
41,012
13,253
1,012
15
17,195
1,950
63,266
41,519
2,183
2,500
1,257
768,810
F-5
-------
TABLE F-2. ASH CONTENT OF COAL
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
Total coal
consumption,
103 tons
2,163
112
34
275
680
24
22
18
365
386
3,494
3,545
1,089
113
1,328
0
25
294
91
3,883
1,140
20
1,502
42
259
63
4
38
Consumption
by
boilers, %
71
N.A.
73
73
39
73
73
71
73
73
83
44
56
73
89
100
73
40
73
64
100
N.A.
42
73
100
80
73
100
Ash
content ,
%
14.2
9.9
11.9
15.0
8.8
9.2
12.9
10.9
11.6
12.6
10.2
11.6
10.2
18.9
15.6
11.9
9-2
13.1
13.2
11.9
9.6
10.1
13.3
8.7
9.4
10. 3
8.0
10.9
Ash
content,
tons
218
0
3
30
23
2
2
1
31
36
296
181
62
16
184
0
2
15
9
296
109
0
84
3
24
5
1
4
N.A. - "Jot applicable.
(-continued)
F-6
-------
TABLE F-2 (continued)
State
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Alaska
Hawaii
Total
Total coal
consumption,
103 tons
0
2,121
1,245
480
8,335
17
98
4,598
1
994
50
1,589
2,325
460
2
2,362
390
3,385
1,8*2
539
500
246
52, 588
Consumption
by
boilers, %
73
87
89
100
65
73
56
45
73
100
100
89
95
44
73
91
100
89
98
81
100
73
Ash
content,
22.3
13.7
13.8
10.3
16.1
11.9
15.0
16.1
9.2
11.7
7.4
15.9
11.9
10.8
8.6
14.4
15.0
16.0
10.6
10.4
15.0
15.0
13.4
(avg. )
content,
tons
0
253
153
49
872
1
8
333
0
116
4
225
263
22
0
310
59
482 *
191
45
75
27
5,125
F-7
-------
TABLE F-3. SULFUR CONTENT OF RESIDUAL OIL
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
Total
residual oil
consumption ,
103 bbl
2,575
140
2,968
3,786
973
5,151
1,678
6,616
4,330
109
3,428
4, 041
76
214
220
3,533
4, 067
2,526
5,319
1,373
1,829
1,155
396
543
34
12
1,406
6,013
Consumption
by
boilers, %
79
100
93
26
80
75
100
78
88
77
63
75
100
50
54
62
94
80
91
73
79
95
77
4
0
20
93
96
Sulfur
content,
%
1, 95
1.32
1.72
1.30
1.36
1.26
1.26
1.95
1.95
1.33
1.64
1.64
1.64
1.64
1.45
1.95
1.26
1.26
1.26
1.45
1. 64
1.95
1.64
1.36
1.55
1.30
1.26
1.26
Sulfur
content,
tons
13,245
617
15,852
4,273
3,579
16,253
7 ,060
33,600
24,810
373
11,826
16,596
416
586
575
14,262
16,084
8, 502
20,364
4,853
7 ,912
7,114
1,670
99
0
10
5,501
24,286
(continued)
F-f
-------
TABLE F-3 (continued)
State
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Alaska
Hawaii
Total
Total
residual oil
consumption,
103 bbl
587
5,034
5,445
9
3,499
331
1, 530
7 ,305
937
2,345
51
237
5,704
2,737
195
6,50]
2,968
834
410
431
574
187
1 12,362
Consumption
by
boilers, %
100
55
89
83
50
83
100
56
100
77
77
100
97
10
77
96
95
43
100
55
100
68
Sulfur
content,
%
1.36
1.26
1.95
1.55
1.26
1.57
1.30
1.26
1.26
1.95
1.55
1.95
1.65
1.35
1.26
1.26
1.30
1.26
1.64
1.36
1.30
1.30
1.51
Sulfur
content,
tons
2,666
11,648
31,553
. 39
7,360
1,440
6,641
17,211
3,942
11,757
203
1,543
30,483
1,234
632
26,257
12,239
1,509
2,245
1,076
2,492
552
435,040
F-9
-------
TABLE F-4. SULFUR CONTENT OF DISTILLATE OIL
State
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
Total
distillate oil
consumption,
103 bbl
1,285
2,694
628
4,174
482
702
377
1,220
1,401
789
2,211
2,023
708
168
1,181
1,984
303
1,309
823
2,017
725
540
1,059
1,236
240
281
94
2,329
Consumption
by
boilers, %
61
61
61
61
42
0
61
35
33
61
80
53
61
61
100
61
61
95
0
86
61
61
100
61
61
100
0
41
Sulfur
content,
%
0.196
0.275
0.245
0.282
0.258
0.228
0.228
0.196
0.196
0.258
0.251
0.251
0.251
0.251
0.240
0.196
0.228
0.228
0.228
0.251
0.251
0.196
0.251
0.258
0.253
0.282
0.228
0.228
Sulfur
content,
tons
1,536
4,519
939
7,180
522
0
524
837
906
1,242
4,440
269
1,084
257
2,834
2,372
421
2,835
0
4,354
1,110
646
2,658
1,945
370
792
0
2,177
(continued)
F-10
-------
TABLE F-4 (continued)
State
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Alaska
Hawaii
Total
Total
distillate oil
consumption,
103 bbl
798
2,078
2,301
87
5,362
1,117
1,640
4,331
191
872
63
1,433
2,832
1,426
79
2,273
1,803
704
477
680
305
145
63,953
Consumption
by
boilers, %
0
30
0
61
65
100
0
91
61
61
61
87
100
100
0
61
20
0
65
79
61
61
Sulfur
content ,
%
0.258
0.228
0.196
0.252
0.228
0.252
0.282
0.228
0.228
0.196
0.252
0.196
0.235
0.262
0.228
0.228
0.282
0.228
0.251
0.258
0.282
0.282
0.23
(avg. )
Sulfur
content,
tons
0
1,421
0
134
7,946
2,815
0
8 ,986
266
1,043
97
2,444
6,655
3,736
0
3,161
1,017
0
778
1,386
525
249
91,850
F-ll
-------
Particulate
Boiler matter S0» CO Hydrocarbons NO
^ J\
Pulverized coal 16A 38S 1 0.3 18
Spreader stoker 13A 38S 21 15
Overfeed stoker ISA 38S 21 15
Underfeed stoker 2A 38S 10 3 6
Other stoker 5A 38S 10 3 6
Residual oil 10S+3 159S 51 60
Distillate oil 2 144S 51 22
Gas (industrial) 10 0.6 17 3 175
Gas (commercial) 10 0.6 20 8 100
A = percentage of ash S = percentage of sulfur
Factors for coal are given as Ib/ton of coal burned
Factors for. oil are given as lb/103 gallons
Factors for gas are given as lb/10^ ft^
The factors for spreader stokers were assumed to apply to
overfeed stokers. Factors for underfeed stokers were assumed to
apply to "other stoker" firing except particulates, where a
separate value was given. For oil burning, factors that were
specified for S0~ and SO., were combined. Where a range of values
was given for gas-burning factors, the average value was used.
FUEL CONSUMPTION BY BOILER TYPE
For coal-burning boilers, the capacity data were distributed
on the basis of the percentages from the Battelle design study
(p. A21). Data for cast iron and fire-tube boilers are shown in
Table F-5. Combined data for the water-tube, fire-tube, and cast
iron boilers burning coal are shown in Table F-6. Table F-7
shows fuel consumption distributed in proportion to boiler
capacity for each type of coal-burning boiler listed in column 3
of that table. The columns on the left of the table show uncon-
trolled emissions as calculated from the AP-42 factors for
percentages of coal sulfur and ash. Sample calculations for
boilers firing pulverized coal are shown below.
Particulate matter (tons) = 16 (13'4^236 X ^
= 1,204,500 tons
- 1204 x 103 tons
F-12
-------
TABLE F-5. DISTRIBUTION OF CAPACITY OF FIRE-TUBE AND CAST IRON BOILERS
Total capacity of
coal-fired fire-tube
and cast iron boilers,
106 Btu/h
Distribution by type
of coal burner, %
Spreader stoker
Underfeed stoker
Overfeed stoker
Pulveri zed-coal- fired
Other
Distributed capacity of
fire-tube and cast iron
boilers ,
106 Btu/h
Spreader stoker
Underfeed stoker
Overfeed stoker
Pulveri zed-coal -fired
Other
Capacity range, 10 Btu/h
<0.4
20,482
nil
90
5
0
5
0
18,434
1,024
0
1,024
0. 4 - 1.5
61,272
nil
90
5
0
5
0
55,145
3,063
0
3,064
1.5 - 10
72,004
7.5
77.5
10
0
5
5,400
55,800
7,200
0
3,600
10 - 25
26,829
15
70
10
0
5
4,024
18,780
2,683
0
1,342
25 - 50
13,415
20
60
15
0
5
2,683
8,049
2,012
0
671
I
I-1
U)
-------
Table F-6. TOTAL INDUSTRIAL/COMMERCIAL COAL-FIRED BOILER CAPACITY
BY SIZE AND BURNER TYPE
I
H-
•fc-
Boiler type
Pulveri zed-coal
fired
Capacity, 106
Btu/h
Percent of total
Spreader stoker
Capacity, 106
Btu/h
Percent of total
Underfeed stoker
Capacity, 106
Btu/h
Percent of total
Overfeed stoker
Capacity, 106
Btu/h
Percent of total
Other
Capacity, 106
Percent of total
Capacity range, 10 Btu/h
<0. 4
0
0
0
0
18,400
2.1
1,000
0.1
1,000
0.1
0.4-1. 5
0
0
0
0
55,700
5.5
3,100
0.4
3,100
0.4
1.5-10
0
0
6000
0.7
64,500
7.5
8,200
1.0
3,800
0.4
10-25
0
0
6400
0.7
13,700
1.6
63,200
7.3
1,300
0.2
25-50
0
0
22,600
2.6
65,200
7.6
17,100
2.0
700
0.1
50-100
0
0
25,400
3.0
71,000
8.3
18,300
2.1
0
0
100-250
70,000
8.1
73,700
8.6
25, 700
3.0
12,900
1.5
0
0
250-500
63,000
7.3
25,600
3.0
11,900
1.4
8,000
0.9
0
0
500-1500
47,000
5.5
7,700
0.9
3,800
0.4
2,500
0. 3
•o
0
>1500
26,400
3.1
6,300
0.7
3,100
0.4
2,100
0.2
0
0
-------
TABLE F-7. UNCONTROLLED EMISSIONS FROM COAL-FIRED BOILERS
Water-tube
Pulverized coal
Spreader stoker
Underfeed stoker
Overfeed stoker
Other stoker
Fire-tube
Spreader stoker
Underfeed stoker
Overfeed stoker
Other stokers
Cast iron
Spreader stoker
Underfeed stoker
Overfeed stoker
Other stokers
Total
Capacity,,
106 Btu/h
207,100
161,600
190,200
61,130
0
8,954
67,359
8,652
4,471
3,396
91,363
7,654
5,390
817,269
Fraction of
total coal-fired
capacity
0.253
0.198
0.233
0.075
0
0.011
0.082
0.011
0.005
0.004
0.112
0.009
0.007
1.000
Coal
consumption ,
103 tons
11,236
8,795
10,349
3,331
0
489
3,642
489
222
178
4,975
400
311
44,417
Particulate
matter
1204
766
139
290
0
43
49
16
7
16
67
13
10
2620
Emissions, 10 tons
so2
427
334
393
127
0
19
138
19
8
7
189
15
12
1,688
NO
X
101
66
31
25
0
4
11
4
2
1
15
3
2
265
HC
1.7
4.4
15.5
1.7
0
0.2
5.5
0.25
0.3
0.1
7.5
0.2
0.5
37.85
CO
5.6
8.8
51.7
3.3
0
0.5
18.2
0.5
1.1
0.2
24.9
0.4
0.3
115.5
-------
en = 38(2) (11236) 103
x 2000
= 426,968
s~
= 427 x 103 tons
Nn = 18(11,236) x 1Q3
x 2000
= 101,125
= 101 x 10 tons
Hr _ 0.3(11,236) x 103
HC 2000
= 1685
= 1.7 x 10 tons
rn - 1(11,236) x 103
2000
= 5618
= 5.6 x 10 tons
Tables F-8 and F-9 show distribution of capacity for boilers
fired by residual oil and distillate oil. These tables also show
consumption for these fuels distributed in proportion to capacity.
Tables F-10 and F-ll show capacity and distributed fuel consump-
tion by boiler type for commercial and industrial gas-fired
boilers. The oil and gas capacity data were multiplied by the
appropriate AP-42 emission factor to estimate emissions. Esti-
mates for 1975 are presented in Section 3.2.
F-16
-------
TABLE F-8. DISTRIBUTION OF CAPACITY AND CONSUMPTION OF RESIDUAL-OIL-FIRED BOILERS
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Total boiler
capacity firing
residual oil,
106 Btu/h
759,100
284,596
183,527
1,227,223
Distribution,
%
62
23
15
100
Corresponding
fuel consumption,
103 bbl
173,706
64,439
42,025
280,170
I
M
-O
-------
TABLE F-9. DISTRIBUTION OF CAPACITY AND CONSUMPTION OF DISTILLATE-OIL-FIRED BOILERS
Boiler type
Water-tube
Fire-tube
Cast iron
Total
Total boiler
capacity firing
distillate oil,
106 Btu/h
134,800
186,116
115,066
436,066
Distribution,
%
31
43
26
100
Corresponding
fuel consumption,
103 bbJ
60,066
83,316
50,376
193,758
I
(—•
00
-------
TABLE F-10. DISTRIBUTION OF CAPACITY AND CONSUMPTION OF
COMMERCIAL NATURAL-GAS-FIRED BOILERS
Boiler type
Fire-tube
Water-tube
Cast iron
Total
Total boiler
capacity,
106 Btu/h
93,435
106,580
391,845
591,860
Distribution,
%
15.8
18.0
66.2
100.0
Corresponding
fuel
consumption,
106 ft3
*
358,364
408,263
1,501,501
2,268,128
F-19
-------
TABLE F-ll. DISTRIBUTION OF CAPACITY AND CONSUMPTION OF
INDUSTRIAL NATURAL-GAS-FIRED BOILERS
Boiler type
Fire-tube
Water-tube
Cast iron
Total
Total boiler
capacity,
106 Btu/h
379,585
939,320
98,000
1,416,905
Distribution,
%
26.8
66.3
6.9
100.0
Corresponding
fuel
consumption,
106 ft3
589,248
1,457,730
151,710
2,198,688
F-20
-------
APPENDIX G
DETAILED CAPITAL AND ANNUALIZED COSTS
FOR REPRESENTATIVE BOILERS
This appendix presents detailed cost estimates for 23 repre-
sentative boiler/fuel combinations. For each boiler, two tables
are provided: one gives detailed capital cost estimates, and the
other gives detailed annualized cost estimates. The list of
representative boilers and the cost tables associated with each
is shown below:
Boiler
Package Scotch fire-tube
Package Scotch fire-tube
Package, underfeed stoker,
water-tube
Package, underfeed stoker,
water-tube
Package, underfeed stoker,
water-tube
Field-erected, chain-grate-
stoker, water-tube
Field-erected, chain-grate-
stoker, water-tube
Field-erected chain-grate-
stoker, water-tube
Package water-tube
Field-erected, spreader
stoker, water-tube
Field-erected, spreader
stoker, water-tube
Field-erected, spreader
stoker, water-tube
Field-erected, pulverized
coal, water-tube
Fuel
Distillate oil
Natural gas
Eastern high-sulfur
bituminous coal
Eastern low-sulfur
bituminous coal
Western subbituminous
coal
Eastern high-sulfur
bituminous coal
Eastern low-sulfur
coal
Western subbituminous
coal
Residual oil
Eastern high-sulfur
bituminous coal
Eastern low-sulfur
bituminous coal
Western subbituminous
coal
Eastern high-sulfur
bituminous coal
Cost tables
G-l, G-2
G-3, G-4
G-5, G-6
G-7, G-8
G-9, G-10
G-ll, G-12
G-13, G-14
G-15, G-16
G-17, G-18
G-19, G-20
G-21, G-22
G-23, G-24
G-25, G-26
G-l
-------
Boiler
Fuel
Cost tables
Field-erected, pulverized
coal, water-tube
Field-erected, pulverized
coal, water-tube
Package, water-tube
Package, water-tube
Package water-tube
Field-erected, chain-
grate stoker, water-tube
Field-erected, pulverized
coal, water-tube
Field-erected, pulverized
coal, water-tube
Field-erected, pulverized
coal, water-tube
Field-erected, pulverized
coal, water-tube
Eastern low-sulfur
bituminous coal
Western subbituminous
coal
Residual oil
Distillate oil
Natural Gas
Eastern medium-
sulfur coal
Eastern medium-
sulfur coal
Eastern high-sulfur
bituminous coal
Eastern low-sulfur
bituminous coal
Western subbituminous
coal
G-27, G-28
G-29, G-30
G-31, G-32
G-33, G-34
G-35, G-36
G-37, G-38
G-39, G-40
G-41, G-42
G-43, G-44
G-45, G-46
G-2
-------
TABLE G-l. ESTIMATED CAPITAL COSTS OF A PACKAGE FIRE-TUBE
BOILER FIRING DISTILLATE OIL WITH A THERMAL INPUT OF 4.4 MW
(15 x 1Q6 stu/h; 300_hp; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE June 30, 1978 (FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and duct)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 36,100
2,700
Incl. w/boiler
N.A.
N.A.
N.A.
4,000
N.A.
6,100
5,000
1,400
Incl. w/boiler
N.A.
N.A.
N.A.
N.A. ,
16,000
$ 71,300
$ 5,000
1,500
Incl. w/boiler
N.A.
N.A.
N.A.
1,500
N.A.
1,200
1,000
1,500
400
N.A.
N.A.
N.A.
3,000
(continued)
G-3
-------
TABLE G-l (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 3,500
Duct work (not incl. w/boiler) N.A.
Piping 20,000
Insulation 10,000
Painting 3,000
Electrical 15,000
Buildings 50,000
Total Installation Costs $ 116,600
TOTAL DIRECT COSTS
(Equipment + Installation) $ 187.900
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 18.800
Construction and field expense
(10% of direct costs) 18.800
Construction fees
(10% of direct costs) 18.800
Startup (2% of direct costs) 3,800
Performance tests (minimum $2000) 2,OOP
TOTAL INDIRECT COSTS $ 62,200
Contingencies
(20% of direct and indirect costs) $ 50,000
Total turnkey costs
(Direct + Indirect + Contingencies) $ 300,100
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 103,000
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 405,100
Quote from Cleaver-Brooks, May 11, 1978
N.A. - Not applicable.
G-4
-------
TABLE G-2. ESTIMATED ANNUALIZED COSTS OF A PACKAGE, FIRE-TUBE
BOILER FIRING DISTILLATE OIL WITH A THERMAL INPUT 'OF 4 . 4 MW
(15 x 106 Btu/h; 300 hp; 150 psig/sat. temp, design)
DIRECT COST
Direct labor
CAPITAL CHARGES
G i A, taxes & insurance
(4% of total turnkey costs)
nn
Supervision 68 , 500
Maintenance labor _ 32 , OOP
Maintenance materials _ a
Replacement parts 15, OOP
Electricity 11/600
Steam _ N . A.
Cooling water _ N. A.
Process water _ 200
Fuel 177, 40P
Bottom ash disposal _ N. A.
Chemicals 2,000
Total direct cost $ 412,000
OVERHEAD
Payroll (301 of direct labor) $ 31,600
Plant (26% of labor, parts & maint.) 57'400
Total overhead costs $ 89, OOP
BYPRODUCT CREDITS . - N.A.
Capital recovery factor
(11.75* of total turnkey costs) _ 35, 3PO
Interest on working capital
(10% of working capital) 10,300
Total capital charges $ 57, 600
TOTAL ANNUALIZED COSTS $ 558,600
Included with replacement parts.
N.A. - Not applicable.
G-5
-------
TABLE G-3. ESTIMATED CAPITAL COSTS OF A PACKAGE, FIRE-TUBE
BOILER FIRING NATURAL GAS WITH A THERMAL INPUT OF 4.4 MW
(15 x 10 Btu/h; 300 hp; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30., 1978
(FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 36.100
2.700
Incl. w/boiler
N.A.
N.A.
N.A.
4.000
N.A.
6.100
5.000
1.400
Incl. w/boiler
N.A.
N.A.
N.A.
N.A.
16.000
$ 71,300
$ 5,000
1,500
Incl. w/boileT"
N.A.
N.A.
N.A.
1,500
N.A.
1.200
1.000
1,500
400
N.A.
N.A.
N.A.
3.000
(continued)
G-6
-------
TABLE G-3 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 3, 500
Duct work (not incl. w/boiler) N.A.
Piping 20,000
Insulation iof QQQ
Painting 3 ,QQQ
Electrical 15 , OOP
Buildings 50 f QQQ
Total Installation Costs $ 116,600
TOTAL DIRECT COSTS
(Equipment + Installation) $ 187,900
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 18,800
Construction and field expense
(10% of direct costs) 18,800
Construction fees
(10% of direct costs) 18/800
Startup (2% of direct costs) 3 , 800
Performance tests (minimum $2000) 2,OOP
TOTAL INDIRECT COSTS $ 62 >200
Contingencies
(20% of direct and indirect costs) $ 5P,OOP
Total turnkey costs
(Direct + Indirect + Contingencies) $ 300,100
Land $ 2,000
Working capital (25-e- of total direct
operating costs) $ 37,700
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 389,800
a Quote from Cleaver-Brooks, May 11, 1978.
N.A. - Not applicable.
G-7
-------
TABLE G-4. ESTIMATED ANNUALIZED COSTS OF A PACKAGE,FIRE-TUBE
BOILER FIRING NATURAL GAS WITH A THERMAL INPUT OF 4.4 MW
(15 x 106 Btu/h; 300 hp; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 105,300
Supervision 6^'nnn
Maintenance labor 32• 00°
Maintenance materials
Replacement parts 15, 00°
Electricity 11,.600
Steam N-A-
Cooling water N.A.
Process water ^00
Fuel lib,
Bottom ash disposal N.A.
Chemicals 3.000
Total direct cost $ 350.900
OVERHEAD
Payroll (30% of direct labor) $ 31,600
Plant (26% of labor, parts £, maint.) 57,400
Total overhead costs $ 89,000
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) ? 12,000
Capital recovery factor
(11.75* of total turnkey costs) 35,300
Interest on working capital
(10% of working capital) 8'800
Total capital charges $ 56.100
TOTAL ANNUALIZED COSTS $ 496,000
Included with replacement parts.
N.A. - Not applicable.
G-i
-------
TABLE G-5. ESTIMATED CAPITAL COSTS OF A PACKAGE,
WATER-TUBE, UNDERFEED-STOKER BOILER FIRING EASTERN HIGH-SULFUR
COALgWITH A THERMAL INPUT OF 8.8 MW
(30 x 10 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30r 19.7R (FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 308,900
3,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
5,200
N.A.
13,400
7.700
8,000
1,400
N.A.
136,700
99,500
N.A.
N.A.
$ 583.800
$ 105,300
1,500
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
2,500
N.A.
3,000
1,100
2,000
800
81,900
41,000
N.A.
N.A.
(continued)
G-9
-------
TABLE G-5 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 35,100
Duct work (not incl. w/boiler) N.A.
Piping 41,000
Insulation 29,300
Painting . 5,900
Electrical 30,000
Buildings 140.400
Total Installation Costs $ 520.800
TOTAL DIRECT COSTS
(Equipment + Installation) $ 1,104,600
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 110,500
Construction and field expense
(10% of direct costs) H0>500
Construction fees
(10% of direct costs) HO,500
Startup (2% of direct costs) 22,100
Performance tests (minimum $2000) 3 ,500
TOTAL INDIRECT COSTS $ 357,100
Contingencies
(20% of direct and indirect costs) $ 292,300
Total turnkey costs
(Direct + Indirect + Contingencies) $ 1,754,OOP
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 135,300
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 1,891,300
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-10
-------
TABLE G-6. ESTIMATED ANNUALIZED COSTS OF A PACKAGE, WATER-TUBE
UNDERFEED-STOKER BOILER FIRING EASTERN HIGH-SULFUR
COAL WITH A THERMAL INPUT OF 8.8 MW
(30 x 106 Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 157,900
Supervision 68,500
Maintenance labor 64,100
Maintenance materials a
Replacement parts 70,200
Electricity 40,100
Steam N.A.
Cooling water N.A.
Process water
Fuel 116.700
Bottom ash disposal 21,000
Chemicals 2 . 300
Total direct cost $ 541,300
OVERHEAD
Payroll (301 of direct labor) $ 47,400
Plant (26% of labor, parts & maint.) 93,800
Total overhead costs $_ 141,200
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes £ insurance
(4% of total turnkey costs) v_ 70,200
Capital recovery factor
0.0.61* of total turnkey costs) 186,100
Interest on working capital
(10% of working capital) _ 13'500
Total capital charges $.. 269.800
TOTAL ANNUALIZED COSTS $_ 952,300
Included with replacement parts.
N.A. - Not applicable.
G-ll
-------
TABLE G-7. ESTIMATED CAPITAL COSTS OF A PACKAGE, WATER-TUBE,
UNDERFEED-STOKER BOILER FIRING EASTERN LOW-SULFUR COAL
WITH A THERMAL INPUT OF 8.8 -MW
(30 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST
Boiler (with fans and duct)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
. Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulveri zers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 264.000
3.000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
Incl. .. w/coal handling
5,200
N.A.
13,400
7,700
8,000
1.400
N.A.
116 .800
85.000
N/A.
N.A.
504,500
90,000
1,500
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
2,500
N.A.
3,000
1,100
2.000
800
70.000
35,000
N.A.
N.A.
(continued)
G-12
-------
TABLE G_7 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 30 , OOP
Duct work (not incl. w/boiler) N.A.
Piping 35,000
Insulation 25 ,000
Painting 5,000
Electrical 30,000
Buildings 120, OOP
Total Installation Costs $ 450,900
TOTAL DIRECT COSTS
(Equipment + Installation) $ 955,400
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 95,500
Construction and field expense
(10% of direct costs) 95,500
Construction fees
(10% of direct costs) 95,500
Startup (2% of direct costs) 19,100
Performance tests (minimum $2000) 3 ,500
TOTAL INDIRECT COSTS $ 309,100
Contingencies
(20% of direct and indirect costs) $ 252,900
Total turnkey costs
(Direct + Indirect + Contingencies) $ 1,517,400
Land _$ 2,OPO
Working capital (25% of total direct
operating costs) $ 145,800
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 1,665,200
a Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-13
-------
TABLE G-8. ESTIMATED ANNUALIZED COSTS OF A PACKAGE, WATER-TUBE,
UNDERFEED-STOKER BOILER FIRING EASTERN LOW-SULFUR
COAL WITH A THERMAL INPUT OF 8.8 MW
(30 x 106 Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 157,900
Supervision 68r500
Maintenance labor 64,100
Maintenance materials
Replacement parts 60'000
Electricity r ' 34y30»
Steam - N'A-
Cooling water N'A-
Process water
Fuel 182,900
Bottom ash disposal 12,600
Chemicals 2,300
Total direct cost $ 583,100
OVERHEAD
Payroll (30% of direct labor) $ 47'400
Plant (26% of labor, parts & maint.) 91f1QO
Total overhead costs $ 138,500
BY-PRODUCT CREDITS . Nuuu
Interest on working capital
(10% of working capital) 14,600
Total capital charges $ 236,300
TOTAL ANNUALIZED COSTS ? 957,900
Included with replacement parts.
N.A. - Not applicable.
G-14
-------
TABLE G-9. ESTIMATED CAPITAL COSTS OF A PACKAGE, WATER-TUBE,
UNDERFEED-STOKER BOILER FIRING SUBBITUMINOUS COAL
WITH A THERMAL INPUT OF 8.8 MW
_ L30 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST a
Boiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 380,200
3,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
5,200
N.A.
13,400
7,700
8,000
1.400
N.A.
168.200
122.400
N.A.
N.A.
$ 709.500
$ 129.600
1,500
Incl. w/bpiler
Incl. w/boiler
Incl. v/coal handling
Incl. w/coal handling
2,500
N.A.
3,000
1.100
2 .000
BOO
100.600
5Q.4QQ
N.A.
N.A.
(continued)
G-15
-------
TABLE G-9 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports ft 43,200
Duct work (not incl. w/boiler) N.A.
Piping 50,40^"
Insulation 36,000
Painting 7,200
Electrical 30.000
Buildings 172,800
Total Installation Costs $ 631.300
TOTAL DIRECT COSTS
(Equipment + Installation) $ 1.340.800
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 134,100
Construction and field expense
(10% of direct costs) 134,100
Construction fees
(10% of direct costs) 134,100
Startup (2% of direct costs) 26,800
Performance tests (minimum $2000) 3 ,500
TOTAL INDIRECT COSTS $ 432,600
Contingencies
(20% of direct and indirect costs) $ 354,700
Total turnkey costs
(Direct + Indirect + Contingencies) $ 2,128,100
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 127^000
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 2,257,100
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-16
-------
TABLE G-10. ESTIMATED ANNUALIZED COSTS OF A PACKAGE, WATER-TUBE,
UNDERFEED-STOKER BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 8.8 MW
(30 x 106 Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 157,900
Supervision 68,500
Maintenance labor 64,100
Maintenance materials
Replacement parts 86,400
Electricity 49,400"
Steam N.A.
Cooling water N.A.
Process water 500
Fuel bb,2UU
Bottom ash disposal 12,600
Chemicals 2,300
Total direct cost $ 507,900
OVERHEAD
Payroll (301 of direct labor) $ 47,400
Plant (26% of labor, parts & ma int.') 98,000
Total overhead costs $ 145,400
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes fc insurance
(4% of total turnkey costs) ? 85,100
Capital recovery factor
(10.61* of total turnkey costs) 225,800
Interest on working capital
(10% of working capital) 12,700
Total capital charges $ 323,600
TOTAL ANNUALIZED COSTS $ 976,900
Included with replacement parts.
N.A. - Not applicable.
G-17
-------
TABLE G-11. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER BOILER FIRING EASTERN HIGH-SULFUR
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978 (FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and duct)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system.
Ash disposal system
Thawing equipment
Fuel-oil system
$ 760,500
80, 000
50,000
150,000
tncl. w/coal handling
Incl. w/coal handling
15,900
N.A.
25,300
8,700
15,000
1,400
N.A.
165,400 ~
136,000
N.A.
N.A.
$1,408,200
491,400
20,000
15,000
_
Incl. w/boiler
Incl. w/coal
Incl. w/coal
3.500
hand 1 ing
handling
N.A.
5.500
1. 300
2,500
1,500
70.200
N.A.
N.A.
(continued)
G-18
-------
TABLE G-11 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports _ 93 , 600
Duct work (not incl. w/boiler) _ N.A.
Piping _ _ 58,500
Insulation _ 46,800
Painting __ 8f 200
Electrical _ 75,000
Buildings _ 234 , OOP
Total Installation Costs $ 1,302.500
TOTAL DIRECT COSTS
(Equipment + Installation) $ 2,710, /DO
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 271,100
Construction and field expense „_, ,_
(10% of direct costs) 7 /1UU
Construction fees
(10% of direct costs) ^/-i
Startup (2% of direct costs) _ 54,200
Performance tests (minimum $2000) _ 7,000
TOTAL INDIRECT COSTS $ R74,500
Contingencies
(20% of direct and indirect costs) ? 717,000
Total turnkey costs
(Direct + Indirect + Contingencies) y 4,302,200
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 250,200
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 4,554,400
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-19
-------
TABLE G-12. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE CHAIN-GRATE-STOKER BOILER FIRING EASTERN HIGH-SULFUP
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 210,600
Supervision 136,900
Maintenance labor 128,200
Maintenance materials
Replacement parts 117,000
Electricity 57.600
Steam N.A.
Cooling water N.A.
Process water 1,100
Fuel 291,700
Bottom ash disposal 52,600
Chemicals 4,900~
Total direct cost $1,000,600
OVERHEAD
Payroll (30% of direct labor) $ 63.200
Plant (26% of labor, parts & maint.) 154,100
Total overhead costs $ 217,300
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes t, insurance
(4% of total turnkey costs) ^ 172,100
Capital recovery factor
(10.14* of total turnkey costs) 436,200
Interest on working capital
(10% of working capital) 25.000
Total capital charges $ 633.300
TOTAL ANNUALIZED COSTS $ 1,851.200
Included with replacement parts.
N.A. - Not applicable.
G-20
-------
TABLE G-13. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE CHAIN-GRATE-STOKER BOILER FIRING EASTERN LOW-SULFUR
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
Jung 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COSTa
Boiler (with fans and ducts]
Stack
Instrumentation
Stoker
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating syster,
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 650,000
80,000
50,000
150,000
Incl. w/coal handling
Incl. w/coal handling
15,900
25,300
8,700
15,000
1,400
N.A.
141,400
116,200
N.A.
N.A.
$ 1,253,900
$ 420,000
20,000
15,000
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
3,500
N.A.
5,500
1_^3JDO
2,500
1,500
150,000
60,000
N.A.
N.A.
(continued)
G-21
-------
TABLE G-13 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 80, OOP
Duct work (not incl. w/boiler) N.A.
Piping • 50,000
Insulation 40,000
Painting 7,000
Electrical 75.000
Buildings 200,000
Total Installation Costs $ 1,131,300
TOTAL DIRECT COSTS
(Equipment + Installation) $ 2.385.200
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 238.500
Construction and field expense
(10% of direct costs) 238.500
Construction fees
(10% of direct costs) 238.500
Startup (2% of direct costs) 47,700
Performance tests (minimum $2000) 7,000
TOTAL INDIRECT COSTS $ 770,200
Contingencies
(20% of direct and indirect costs) $ 631,100
Total turnkey costs
(Direct + Indirect + Contingencies) $ 3,786,500
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 279 , 4 0Q_
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 4,067,900
Quote from Zurn Industries, Inc., May 25. 1978.
N.A. - Not applicable.
G-22
-------
TABLE G-14. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER BOILER FIRING EASTERN LOW-SULFUR
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psi9/sat. temp, design)
DIRECT COST
Direct labor $ ?i n fino
a Included with replacement parts.
N.A. - Not applicable.
G-23
Supervision 1 36 , 900
Maintenance labor 128 , 200
Maintenance materials _ a
Replacement parts 100, OOP
Electricity 49.200
Steam N.A.
Cooling water N.A.
Process water 1 ,
Fuel 457,300
Bottom ash disposal 29.400
Chemicals 4,900
Total direct cost $1,117,600
OVERHEAD
Payroll (301 of direct labor) $ 63,200
Plant (26% of labor, parts & maint.) _ 149.700
Total overhead costs $ 212.900
/
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes fc insurance
(4% of total turnkey costs) $ 151,500
Capital recovery factor
(10. 14* of total turnkey costs) 384,000
Interest on working capital
(10% of working capital) _ 27'900
Total capital charges $ 563.400
TOTAL ANNUALIZED COSTS $ 1,893,900
-------
TABLE G-15. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER-BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING;
EQUIPMENT COST3
Boiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 936,000
80,000 "
50,000
150,000
Incl. .w7coal handling
Incl. w/coal handling
15,900
N.A.
25,300
8,700
15, OOP
1 ,400
N.A.
203.600
167 .300
N.A.
N.A.
$1.653,200
$ 601,000 _
_ 20,000
_ 15,000
Incl . w/hoi ler _
Incl. w/coal handling
incl . w/coal handling
3^500
5.500
1,300
2.500
1.500
216,000
86.400
N.A.
N.A.
(continued)
G-24
-------
TABLE G-15 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports
Duct work (not incl. w/boiler)
Piping
Insulation
Painting
Electrical
Buildings
Total Installation Costs
TOTAL DIRECT COSTS
(Equipment + Installation)
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Startup (2% of direct costs)
Performance tests (minimum $2000)
TOTAL INDIRECT COSTS
Contingencies
(20% of direct and indirect costs)
Total turnkey costs
(Direct + Indirect + Contingencies)
Land
Working capital (25% of total direct
operating costs)
GRAND TOTAL
(Turnkey + Land + Working Capital)
115,200
N.A.
72,000
57,600
10,100
75,000
203,000
*** i , s 7 o, fi n n
3,223,800
322f 400
322,400
322,400
64,
7, QUO
$ 1 ,03^700
S EJ . i i E; nnn
2,000
$ 224,000
$5,341,000
a Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-25
-------
TABLE G-16. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 22.0 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 210,600
Supervision 136,90 0
Maintenance labor 128,200
Maintenance materials a
Replacement parts 144 ,000
Electricity 70,900
Steam N.A.
Cooling water N
Process water ^
Fuel 165f 600
Bottom ash disposal 33.600
Chemicals 4 f 900
Total direct cost $ 895 . 800
OVERHEAD
Payroll (301 of direct labor) $ 63,200
Plant (26% of labor, parts & maint.) 161,100
Total overhead costs $ 224,300
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G t, A, taxes & insurance
(4% of total turnkey costs) $ 204,600
Capital recovery factor
(10.14* of total turnkey costs) 518/700
Interest on working capital
(10% of working capital) 22,400
Total capital charges $ 745,700
TOTAL ANNUALIZED COSTS $ 1,865,800
Included with replacement parts.
N.A. - Not applicable.
G-26
-------
TABLE G-17. ESTIMATED CAPITAL COSTS OF A PACKAGE, WATER-TUBE,
RESIDUAL OIL-FIRED BOILER WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deareator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$
Incl.
600,000
14,
,500
w/boiler
N.
N.
N.
21,
N.
53,
6,
18.
1.
N.
N.
N.
N.
50,
A.
A.
A.
600
A.
600
700
000
500
A.
A.
A.
A.
000
765^900
20.000
6,500
Incl. w/boiler
_ N.A.
_ N.A.
_ N.A.
_ 4 ,000
_ N.A. _
_ 7,500
_ 1,500
_ 3,000
_ 500
_ N.A.
_ N.A.
_ N.A.
_ 20.000
(continued)
G-27
-------
TABLE G-17 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports
Duct work (not incl. w/boiler)
Piping
Insulation
Painting
Electrical
Buildings
Total Installation Costs
TOTAL DIRECT COSTS
(Equipment + Installation)
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs)
Construction and field expense
(10% of direct costs)
Construction fees
(10% of direct costs)
Startup (2% of direct costs)
Performance tests (minimum $2000)
TOTAL INDIRECT COSTS
30,000
N.A.
65,000
20,000
5,000
40,000
100r 000
$ 323,000
$ 1,088,900
* 108,900
108,900
10Sr900
21,800
3,500
$ 352.000
Contingencies
(20% of direct and indirect costs) $ 288,200
Total turnkey costs
(Direct + Indirect + Contingencies) $ 1,729,100
Land $ 2,000
Working capital (25% of total direct
operating costs)
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 2,244, 900
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-28
-------
TABLE G-18. ESTIMATED ANNUALIZED COSTS OF A PACKAGE, WATER-TUBE,
RESIDUAL OIL-FIRED BOILER WITH A THERMAL INPUT OF 44 MW
(150 X 106 Btu/h; 750 psig/750°F design)
DIRECT COST
Direct labor $ 21Or600
Supervision 68 .500
Maintenance labor 64.100
Maintenance materials a
Included with replacement parts.
N.A. - Not applicable.
G-29
Replacement parts 60, OOP
Electricity 47.100
Steam N.A.
Cooling water N.A.
Process water 2 ,100
Fuel 1,597,200
Bottom ash disposal N.A.
Chemicals 5,5 0 0~
Total direct cost $2.055,100
OVERHEAD
Payroll (301 of direct labor) $ 63,200
Plant (26% of labor, parts & ma int.) 104,800
Total overhead costs $ 168,OOP
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) $ 69,200
Capital recovery factor
(L0.61* of total turnkey costs) 183,500
Interest on working capital
(10* of working capital) 51,400
Total capital charges $ 304'10Q
TOTAL ANNUALIZED COSTS $ 2,527,200
-------
TABLE G-19. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED, WATER-TUBE,
SPREADER-STOKER BOILER FIRING HIGH-SULFUR EASTERN COAL
WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 450 psig/600°F design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST
a
Boiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 1.753.800
300,000
113,500
227.600
Incl. w/coal handling
Incl. w/coal handling
21.600
N.A.
44,500
9,200
18,000
1,500
N.A.
282,300
167,500
Incl. w/coal handling
N.A.
$ 2,939,500
$ 936,000
50,000
25,000
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
4,000
N.A.
7,000
1,500
3,000
1,500
292,500(incl. site prep.)
117,000
Incl. w/coal handling
N.A.
(continued)
G-30
-------
TABLE G-19 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 175,500
Duct work (not incl. w/boiler) N.A.
Piping 81,900
Insulation 87 ,800
Painting 11,700
Electrical 150,000
Buildings 409,500
Total Installation Costs $ 2,353,900
TOTAL DIRECT COSTS
(Equipment + Installation) $ 5,293,400
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 529,300
Construction and field expense
(10% of direct costs) 529,300
Construction fees
(10% of direct costs) 529,300
Startup (2% of direct costs) 105,900
Performance tests 10 , OOP
TOTAL INDIRECT COSTS $ 1,703,800
Contingencies
(20% of direct and indirect costs) $ 1,399 ,400
Total turnkey costs
(Direct + Indirect -I- Contingencies) $ 8 , 396 ,600
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 385(600
GRAND TOTAL
(Turnkey + Land -I- Working Capital) $ 8t784,200
a Quote -from Babcock & Wilcox, Inc., August 17, 1978.
N.A. - Not applicable.
G-31
-------
TABLE G-20. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED
WATER-TUBE, SPREADER-STOKER BOILER FIRING HIGH-SULFUR EASTERN
COAL WITH A THERMAL INPUT_OF 44 MW
(150 x 106 Btu/h; 450 psig/600°F design)
DIRECT COST
Direct labor $ 315.900
Supervision 136,900
Maintenance labor 128,200
Maintenance materials
Replacement parts 234,000
Electricity 85,200
Steam N-A-
Cooling water N.A.
Process water 2'30°
Fuel 583,400
Bottom ash disposal 50,500
Chemicals 6,000
Total direct cost $1,542,400
OVERHEAD
Payroll (301 of direct labor) $ 94,800
Plant (26% of labor, parts & maint.) 211,900
Total overhead costs $ 306.700
/
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G i A, taxes & insurance
(4% of total turnkey costs) $ 335,900
Capital recovery factor
(10.14* of total turnkey costs) 851,400
Interest on working capital
(10% of working capital) 38,600
Total capital charges Sir??Rfqnn
TOTAL ANNUALIZED COSTS $3.075.000
Included with replacement parts.
N.A. - Not applicable.
G-32
-------
TABLE G-21. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, SPREADER-STOKER BOILER FIRING LOW-SULFUR
EASTERN COAL WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 450 psiq/600°F design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST a
Soiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Cherical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 1.499.000
300.000
113.500
194.500
Incl. w/coal handling
Incl. w/coal handling
21.600
N.A.
44.500
9,200
18,000 '
1.500
N.A.
241.300
143.200
Incl. w/coal handling
N.A.
$ 2.586.300
$ 800,000
50,000
25,000
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
4,000
N.A.
7,000
1,500
3,000
1,500
250,000 (incl. site prep,
100,000
Incl. w/coal handling
N.A.
(continued)
G-33
-------
TABLE G-21 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 150,OOP
Duct work (not incl. w/boiler) N.A. .
Piping 70,000
Insulation 75.000
Painting . 10.000
Electrical 150, OOP
Buildings 350.PPP
Total Installation Costs $ 2,047,000
TOTAL DIRECT COSTS
(Equipment + Installation) $ 4,633,3PO
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 463,300
Construction and field expense
(10% of direct costs) 463,300
Construction fees
(10% of direct costs) 463,300
Startup (2% of direct costs) 92,700
Performance tests (minimum $2000) 10,OOP
TOTAL INDIRECT COSTS $ 1,492,600
Contingencies
(20% of direct and indirect costs) $ 1,225,200
Total turnkey costs
(Direct -l- Indirect + Contingencies) $ 7 .351,100
Land __$ 2,000
Working capital (25% of total direct
operating costs) $ 451,000
GRAND TOTAL
(Turnkey -I- Land + Working Capital) $ 7 , 3 0 4 {10 0
Quote from Babcock & Wilcox, Inc., August 17, 1978.
N.A. - Not applicable.
G-34
-------
TABLE G-22. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, SPREADER-STOKER BOILER FIRING LOW-SULFUR
EASTERN COAL WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 450 psig/600°F design)
DIRECT COST
Direct labor $ 315,900
Supervision 136,900
Maintenance labor 128,200
Maintenance materials
Replacement parts 200,001)
Electricity 72.800
Steam N.A.
Cooling water N.A.
Process water 2 , 300
Fuel 914,500
Bottom ash disposal 27,300
Chemicals 6,000
Total direct cost $1,803,900
OVERHEAD
Payroll (30% of direct labor) $ 94,800
Plant (26% of labor, parts fc maint.) 203,100
Total overhead costs $ 297,900
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G £. A, taxes fc insurance
(4% of total turnkey costs) *
Capital recovery factor
(10.144 of total turnkey costs) 745.400
Interest on working capital
(10% of working capital) 45,100
Total capital charges $ 1.084.500
TOTAL ANNUALIZED COSTS $ 3,186,300
Included with replacement parts.
N.A. - Not applicable.
G-35
-------
TABLE G-23. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, SPREADER-STOKER BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 450 psig/600°F desiqn)
CAPITA! COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans and ducts)
Stack
Instrumentation
Stokers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 2,158,600
300,000
113,500
280,100
Incl. w/coal handing
Incl. w/coal handling
21,600
N.A.
44,500
9,200
18,000
1,500 ~
N.A.
347.500
206.200
Incl. w/coal handling
N.A.
$ 3.500.700
$ 1,152.000
50,000
25,000
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
4,000
N.A.
7,000
1,500
3,000
1,500
360,000 (incl. site prep.)
144,000
Incl. w/coal handling
N.A.
(continued)
G-36
-------
TABLE G-23 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 216,000
Duct work (not incl. w/boiler) N.A.
Piping 100,800
Insulation 108 ,000
Painting 14 ,400
Electrical 150,000
Buildings 504 ,000
Total Installation Costs $ 2,841,200
TOTAL DIRECT COSTS
(Equipment + In' tallation) $ 6,341,900
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 634,200
Construction and field expense
(10% of direct costs) 634,200
Construction fees
(10% of direct costs) 634,200
Startup (2% of direct costs) 126,800
Performance tests (minimum $2000) 10> 00°
TOTAL INDIRECT COSTS $ 2,039,400
Contingencies
(20% of direct and indirect costs) $ 1,676,300
Total turnkey costs
(Direct + Indirect + Contingencies) $10,057,600
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 336/200
GRAND TOTAL
(Turnkey + Land + Working Capital) $10,395,800
Quote from Babcock & Wilcox, Inc., August 17, 1978.
N.A. - Not applicable.
G-37
-------
TABLE G-24. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, SPREADER-STOKER BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 450 psig/600°F design)
DIRECT COST
Direct labor S 315.900
Supervision 136.900
Maintenance labor 128.200
Maintenance materials
Replacement parts 288,OOP
Electricity 104,800
Steam N.A.
Cooling water N.A.
Process water 2 > 30°
Fuel 331,100
Bottom ash disposal 31,500
Chemicals 6,00~Q~
Total direct cost $1,344,700
OVERHEAD
Payroll (301 of direct labor) $ 94,800
Plant (26% of labor, parts & maint.) 225,900
Total overhead costs $ 320,700
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance $ 402 300
(4% of total turnkey costs) '
Capital recovery factor
(10.14* of total turnkey costs) 1,019,800
Interest on working capital
(10% of working capital) 33,600
Total capital charges $ 1,455,700
TOTAL ANNUALIZED COSTS $ 3,121,100
Included with replacement parts.
N.A. - Not applicable.
G-38
-------
TABLE G-25. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
HIGH-SULFUR COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 psig/750°F design)
CAPITAL COSTS ~~~—~ ~
DATE OF ESTIMATE
June 30, 197!
(FOR COSTS INDEXING)
EQUIPMENT COST a
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 2.492,100
365.000
228.000
613.100
128,700
Incl. w/coal handling
29.000
Incl. w/boiler _
58.000
16,300
20,000
1,500
23,400
308.800
210.600
Incl. w/coal handling
N.A.
4.494 .500
$ 1.270.000
60,000
35,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
5,000
Incl. w/boiler
8,000
2,000
3,500
1,500
321,800 (incl. site prep,
140,400
Incl. w/coal handling
N.A.
(continued)
G-39
-------
TABLE G-25 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 210.600
Duct work (not incl. w/boiler) N.A.
Piping 93.600
Insulation 93f600
Painting 11.700
Electrical 160.000
Buildings 444 ,600
Total Installation Costs $ 2fR61 ,
TOTAL DIRECT COSTS
(Equipment + Installation) $ 7,355.800
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) _$
Construction and field expense
(10% of direct costs) _^
Construction fees
(10% of direct costs)
Startup (2% of direct costs) 147^100
Performance tests (minimum $2000) 10,000
TOTAL INDIRECT COSTS $ 2
Contingencies
(20% of direct and indirect costs) $ i
Total turnkey costs
(Direct + Indirect + Contingencies) _$JJL
Land $ 2,000
Working capital (25% of total direct
operating costs) S 5 3 6 f R n 0
GRAND TOTAL
(Turnkey + Land + Working Capital) $12,202,400
Quote from Babcock & Wilcox, Inc., August 17, 1978.
N.A. - Not applicable.
G-40
-------
(4% of total turnkey costs)
TABLE G-26. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED COAL-FIRED BOILER FIRING EASTERN
HIGH-SULFUR COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 ps';g/7500F design)
DIRECT COST
Direct labor $ 421,100
Supervision 136,900
Maintenance labor 192,200
Maintenance materials a
Replacement parts 292,500
Electricity 278.300
Steam N.A.
Cooling water N.A.
Process water 3,000
Fuel 777,900
Bottom ash disposal 37,800
Chemicals 7.500
Total direct cost $2.147,300
OVERHEAD
Payroll (30% of direct labor) $ 126,400
Plant (26% of labor, parts & maint.) 271,100
Total overhead costs $ 397,500
BYPRODUCT CREDITS N.A,
CAPITAL CHARGES
G £ A, taxes £ insurance
$ 466,500
Capital recovery factor
(10.14* of total turnkey costs) 1,182,700
Interest on working capital
(10% of working capital) . 53,700
Total capital charges $1,702,900
TOTAL ANNUALIZED COSTS $4,247,700
Included with replacement parts.
N.A. - Not applicable.
G-41
-------
TABLE G-27. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
LOW-SULFUR COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE
June.30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COSTa
Boiler (with fans and ducts)
Stack
In strumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 2,130,000
365,000
228,000
524,500
110,000
Incl. w/coal handling
29,000
Incl. w/boiler
58,000
16,300
20,000
1,500
20,000
263,900
180,000
Incl._w/coal handling
N.A.
$ 3,946,200
$ 1,085,000
60,000
35,000 ~~
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
5,000
Incl. w/boiler
8,000
2.000
3.500
1.500
275,000(incl. site prep.)
120.000
Incl. w/coal handling
N.A.
(continued)
G-42
-------
TABLE G-27 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 180,OOP
Duct work (not incl. w/boiler) N.A.
Piping 80,000
Insulation 80.000
Painting 10, OOP
Electrical 160 ,POO
Buildings 380 , OOP
Total Installation Costs $ 2,485,OOP
TOTAL DIRECT COSTS
(Equipment + Installation) $ 6.431.200
INSTALLATION COSTS, INDIRECT
Engineering $ 643 10Q
(10% of direct costs) '
Construction and field expense
(10% of direct costs) b4J,iUO
Construction fees
(10% of direct costs) 643 .100
Startup (2% of direct costs) 128 ,600
Performance tests (minimum $2000) 10,OOP
TOTAL INDIRECT COSTS $ 2.067,900
Contingencies
(20% of direct and indirect costs) $ 1,699,800
Total turnkey costs
(Direct + Indirect + Contingencies) $ 10,198,900
Land _$ 2,000
Working capital (25% of total direct
operating costs) $ 622,300
GRAND TOTAL
(Turnkey + Land + Working Capital) $10,823,200
a Quote from Babcock & Wilcox, Inc., August 17, 1978
N.A. - Not applicable.
G-43
-------
TABLE G-28 ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE PULVERIZED-COAL-FIRED BOILER FIRING EASTERN LOW-SULFUR
COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 psig/750°F design)
DIRECT COST
Direct labor $ 421,200
Supervision 136,900
Maintenance labor 192,200
Maintenance materials a
Replacement parts 250'000
Electricity 237.900
Steam N.A.
Cooling water N.A.
Process water 3,OOP
Fuel 1,219,400
Bottom ash disposal 21,00~0~
Chemicals 7,500
Total direct cost $2,489,100
OVERHEAD
Payroll (30% of direct labor) $ 126,400
Plant (26% of labor, parts & roaint.) 260,100
Total overhead costs $ 386.500
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G i A, taxes & insurance
(4% of total turnkey costs) $ 408,000
Capital recovery factor
(10.14* of total turnkey costs) 1,034,200
Interest on working capital
(10% of working capital) 62.200
Total capital charges SI.504.400
TOTAL ANNUALIZED COSTS $4,380,000
Included with replacement parts.
N.A. - Not applicable.
G-44
-------
TABLE G-29. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 psig/750° F design)
CAPITAL COSTS
DATE OF ESTIMATE
June 30, 1978
(FOR COSTS INDEXING)
EQUIPMENT COST a
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COSTS, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 3,067,200
365,000
228,000
754,600
158,400
Incl. w/coal handling
29.000
Incl. w/boiler
58.000
16,300
20,000
1.500
28.800
380.000
259.200
Incl. w/coal handling
N.A.
$ 5,366,000
$ 1,560,000
60,000
35,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
5,000
Incl. w/boiler
8,000
2,000
3., 500
1,500
396,000
172,800
Incl. w/coal handling
N.A.
(continued)
G-45
-------
TABLEG-29 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 259,200
Duct work (not incl. w/boiler) N.A.
Piping 115,200
Insulation 115,200
Painting 14 ,400
Electrical 160.000
Buildings 547,200
Total Installation Costs $ 3,455,000
TOTAL DIRECT COSTS
(Equipment + Installation) $ R,R?l
INSTALLATION COSTS, INDIRECT
Engineering
(10%. of direct costs) $ 8P2.,i.pp
Construction and field expense
(10% of direct costs) 8.8_2.^1.0H_
Construction fees
(10% of direct costs) 882.JLOCL
Startup (2% of direct costs) 176,400
Performance tests (minimum $2000) 10,OOP
TOTAL INDIRECT COSTS $ 2
Contingencies
(20% of direct and indirect costs) $ 2 ,330 ,700
Total turnkey costs
(Direct + Indirect + Contingencies) $ 13,984,400
Land $ 2,000
Working capital (25% of total direct
operating costs) § 482,000
GRAND TOTAL
(Turnkey + Land + Working Capital) $ 14,468,400
a
Quote from Babcock & Wilcox, Inc., August 17, 1978.
N.A. - Not applicable.
G-46
-------
TABLE G-30. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING SUBBITUMINOUS
COAL WITH A THERMAL INPUT OF 58.6 MW
(200 x 106 Btu/h; 750 psig/75fl?F design)
DIRECT COST
Direct labor 5 421.200
Supervision 136,900
Maintenance labor 192,200
Maintenance materials
Replacement parts 360,000
Elf" icity 342.500
Sti-.v N.A.
Coc.-i.ug water N.A.
Process water 3, OOP
Fuel 441,500
Bottom ash disposal 23,100
Chemicals 7,500
Total direct cost $1.927,900
OVERHEAD
Payroll (301 of direct labor) $ 126,400
Plant (26% of labor, parts & maint.) 288'700
j
Total overhead costs $ 415,100
/
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes £ insurance
(4% of total turnkey costs) $ 559,400
Capital recovery factor
(10.14* of total turnkey costs) 1,418,000
Interest on working capital
(10% of working capital) 48,200
Total capital charges s7:,n25f60Q
TOTAL ANNUALIZED COSTS $4.368.600
Included with replacement parts.
N.A. - Not applicable.
G-47
-------
TABLE G-31. ESTIMATED CAPITAL COSTS OF A PACKAGE
WATER-TUBE BOILER FIRING RESIDUAL OIL WITH A THERMAL INPUT OF 8.8 MW
(30 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30, 1978
EQUIPMENT COST a
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
.(FOR COSTS INDEXING)
$ 150,000
5,000
Incl. w/boiler
N.A.
N.A.
N.A.
7,000
N.A.
13,500
3.500
8.000
1,500
N.A.
N.A.
N.A.
N.A.
33,000
$ 221,500
$ 10,000
3,000
Incl. w/boiler
N.A.
N.A.
N.A.
2,500
N.A.
3,000
1,000
2,000
1,500
N.A.
N.A.
N.A.
8,000
(continued)
G-48
-------
TABLE G-31 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 15rOOO
Duct work (not incl. w/boiler) N.A.
Piping 26.000
Insulation 2QfOQQ
Painting 4.000
Electrical 21.000
Buildings 70.000
Total installation cost S 187.000
TOTAL DIRECT COSTS
(equipment + installation) $ 408,500
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 40,800
Construction and field expense
(10% of direct costs) 40,800
Construction fees
(10% of direct costs) 40/800
Startup (2% of direct costs) 8,200
Performance tests (minimum $2000) 2,000
TOTAL INDIRECT COSTS $ 132,600
Contingencies
(20% of direct and indirect costs) ? 108,200
Total Turnkey Costs
(direct+indirect+contingencies) $ 649,300
Land S 2.000
Working capital (25% of .total direct
operating costs) ? 146,500
GRAND TOTAL $ 797,800
(turnkey+land+working capital) .. . . - :
a Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-49
-------
TABLE G-32. ESTIMATED ANNUALIZED COSTS OF A PACKAGE
WATER-TUBE BOILER FIRING RESIDUAL OIL WITH A THERMAL INPUT OF 8.8 MW
OF 8.8 MW (30 x 106 Btu/h; 150 psig/sat. temp, design)
D3RECT COST
Direct labor
Supervision 68,,r5.0JL
Maintenance labor .——32,090
Maintenance materials
Replacement parts „_ 30,000,
Electricity 29,300
Steam __-_~_JLsA£_,
Cooling water -,, ,N.A.
Process water
Fuel 3_19,400
Bottom ash disposal N.A.
Chemicals —. I
Total direct cost S 585.900
OVERHEAD
Payroll (301 of direct labor) l__li*100_
Plant (26% of labor, parts & maint.) 61,300
Total overhead costs $ 92,900
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G fc A, taxes £ insurance
(4% of total turnkey costs) $ 26,_000_
Capital recovery factor
(10.61% of total turnkey costs) 68,900
Interest ©n working capital
(10% of working capital) „
Total capital eharges $_
TOTAL ANNUALIEED COSTS $
Included with replacement parts.
N.A. - Not applicable.
G-50
-------
TABLE G-33. ESTIMATED CAPITAL COSTS OF A PACKAGE
WATER-TUBE BOILER FIRING DISTILLATE OIL WITH A THERMAL INPUT
OF 44 MW (150 x 106 Btu/h; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30. 197!
.(FOR COSTS INDEXING!
EQUIPMENT COST
Boiler (with fans & ducts)
Stack
Instrumentation
Pulveri zers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulveri zers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
OOP
1 4 .500
Incl. w/boiler
N
A .
N A
N . A -
21
N
53
____£
JLB
1
M
N
N
N
39
754
^finn
.A.
,600
r700
,000
.500
A .
.A.
.A.
.A.
rooo
,900
$ 20.000
6.500
Incl. w/boiler
N.A.
N.A.
N.A.
4.000
N.A.
7,500
1.500
3.000
1.500
N.A.
N.A.
N.A.
15000
(continued)
G-51
-------
TABLE G-33 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 30,000
Duct work (not incl. w/boiler) N.A.
Pipina 65,000
Insulation 30,000
Painting
Electrical
Buildings 100,000
Total installation cost $—329,000
TOTAL DIRECT COSTS
(equipment 4 installation) ?1,083,900
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 108,400
Construction and field expense
(101 of direct costs) —108,400
Construction fees
(10% of direct costs) 108,400
Startup (2% of direct costs) 21.700
Performance tests (minimum $2000) 3 , 500
TOTAL INDIRECT COSTS 5 350,400
Contingencies
(20% of direct and indirect costs) $ 286,QOO
Total Turnkey Costs
(direct+indirect+contingencies) $If721f200
Land $ 2.000
Working capital (25% of total direct
operating costs) $ 656,500
GRAND TOTAL
(turnkey+land+working capital) $ 2,379,700
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Not applicable.
G-52
-------
TABLE G-34. ESTIMATED ANNUALIZED COSTS OF A PACKAGE,
WATER-TUBE BOILER FIRING DISTILLATE OIL WITH A THERMAL INPUT OF
44 MW. (150 x 1€ Btu/h; 750 psig/750°F design)
DIRECT COST
Direct labor $. 210,6.0.0,
Supervision - 6.8j_5_P_0_
Maintenance labor - 64,100
Maintenance materials - a^ -
(4% of total turnkey costs)
a Included with replacement parts.
N.A. - Not applicable.
G-53
Replacement parts - 60 ,000
Electricity _ 41 ,100
Steam - N.A.
Cooling water - N.A.
Process water - 2 , 000
Fuel 2,168.100
_ N.A.
Chemicals 5,500
Total direct cost $2,625,900,
OVERHEAD
Payroll (30% of direct labor) $ 63,200
Plant (26% of labor, parts & maint.) —104,800
Total overhead costs $ 168,000
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G £. A, taxes & insurance ^
68,800
Capital recovery factor
( 10.63 of total turnkey costs) 182,600
Interest on working capital
(10% of working capital) 65,700
. , v $ 317,100
Total capital charges _ '
$ 3,111,000
TOTAL ANNUALIZED COSTS v—. .
-------
TABLE G-35. ESTIMATED CAPITAL COSTS OF A PACKAGE,
WATER-TUBE BOILER FIRING NATURAL GAS WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 750 psig/7508F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30. 1978 (FOR COSTS INDEXING)
EQUIPMENT COSTa
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ finn,nno
14r5QO
Incl. w/boiler
N.A.
N.A.
N.A.
21f600
N.A.
53r600
6.700
18.000
1,500
N.A.
N.A.
N.A.
N.A.
N.A.
$ 715,900
$ 20.000
6,500
Incl. w/boiler
N.A.
N.A.
N.A.
4,000
N.A.
7,500
1.500
3,000
1,500
N.A.
N.A.
N.A.
N.A.
(continued)
G-54
-------
TABLE G-35 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 30rQOQ
Duct work (not incl. w/boiler) . N.A.
Pipina 74.000
Insulation 30,000
Painting 5,000
Electrical 40.000
Buildings 100.000
Total installation cost $ 323.000
TOTAL DIRECT COSTS
(equipment + installation) $1 ,038,900
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 103.900
Construction and field expense
(101 of direct costs) 103.900
Construction fees
(10% of direct costs) 103.900
Startup (2% of direct costs) 20,800
Performance tests (minimum $2000) 3,500
TOTAL INDIRECT COSTS S 3"36,000
Contingencies
(20% of direct and indirect costs) § 273,000
Total Turnkey Costs
(direct+indirect+contingencies) $ 1,649,900
Land $ 2,000
Working capital (25% of total direct
operating costs) § 466,800
GRAND TOTAL
(turnkey+land+working capital) $ 2,118,700
Quote from Cleaver-Brooks, May 11, 1978.
N.A. - Not applicable.
G-55
-------
TABLE G-36. ESTIMATED ANNUALIZED COSTS OF A PACKAGE,
VJATER-TUBE BOILER FIRING NATURAL GAS WITH A THERMAL INPUT OF 44 MW
(150 x 106 Btu/h; 750 psig/750°F)
DIRECT COST
Direct labor $ - 210,600
Supervision - 68 , 500
Maintenance labor - 64 , 1 flfl
Maintenance materials -- a^ -
Replacement parts - 6Q ,QQQ
Electricity - 47,100
Steam - N.A.
Cooling water - N.A.
Process water _ 2 . OOP
Fuel 1,409.300
_ N.A.
Chemicals 5,500
Total direct cost $ 1,867,100
OVERHEAD
Payroll (30% of direct labor) $ 63,200
Plant (26% of labor, parts & maint.) 104,800
Total overhead costs $ 168,000
BYPRODUCT CREDITS . N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) $ 66.000
Capital recovery factor
(10.61* of total turnkey costs) 175,100
Interest on working capital
(10% of working capital) 46,700
Total capital charges $ 287,800
TOTAL ANNUALIZED COSTS $ 2,322,900
Included with replacement parts.
N. A. - Not applicable.
G-56
-------
TABLE G-37. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER BOILER FIRING EASTERN MEDIUM-SULFUR
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 106 Btu/h; 150 psig/sat. temp, design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30. 1978
EQUIPMENT COST
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulveri zers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
.(FOR COSTS INDEXING)
673.400
80,000
150.000
Incl. w/coal handling
Incl. w/coal handling
15f9QO
_ N.A.
25.300
8.700
15.000
1.400
N.A.
146.500
120,000
N.A.
N.A.
ft 1 .286.600
5 435,100
20rOOO
15.000
Incl. w/boiler
Incl. w/coal handling
Incl. w/coal handling
3.500
N.A.
.5,500
.If 300,
2,500
1.500
.155 f 400
62,200
N.A.
N.A.
(continued)
G-57
-------
TABLE G-37 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 82,900
Duct work (not incl. w/boiler) N.A.
Piping
Insulation _ 41,4QQ_
Painting _ 7,300
Electrical 75,000
Buildings 207.200
Total installation cost $ 1,167.600
TOTAL DIRECT COSTS
(equipment + installation) $ 2,454 ,200
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 245.400
Construction and field expense
(101 of direct costs) 245.400
Construction fees
(10% of direct costs) 245.400
Startup (2% of direct costs) _ 49,100
Performance tests (minimum $2000) 7,000
TOTAL INDIRECT COSTS $ 792,300
Contingencies
(203, of direct and indirect costs) $ 649f300
Total Turnkey Costs
(direct+indirect+contingencies) $3.895.800
Land $ 2,000
Working capital (25% of total direct
operating costs) $ 267,500
GRAND TOTAL
(turnkey+land+working capital) $4,165,300
Quote from Zurn Industries, Inc., May 25, 1978.
N.A. - Wot applicable.
G-58
-------
TABLE G-38. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, CHAIN-GRATE-STOKER BOILER FIRING EASTERN MEDIUM-SULFUR
COAL WITH A THERMAL INPUT OF 22 MW
(75 x 10° Btu/h; 150 psig/sat. temp, design)
DIRECT COST
Direct labor $ 21Qr600
Supervision 136.900
Maintenance labor 128.200
Maintenance materials a •
Replacement parts 103,600
Electricity 51(400
Steam N .A.
Cooling water N.A.
Process water 1,100
Fuel 374,500
Bottom ash disposal 58,900
Chemicals 4*900
Total direct cost $ 1,070,100
OVERHEAD
Payroll (30% of direct labor) $ 63,2QQ
Plant (26% of labor, parts &, maint.) 150,000
Total overhead costs $ 213,80.0
BYPRODUCT CREDITS N.A .
CAPITAL CHARGES
G (, A, taxes & insurance
(4% of total turnkey costs) $ 1 55,8QQ
Capital recovery factor
(10.14* of total turnkey costs) 395.000
Interest on working capital
(10% of working capital) 2
Total capital charges $ 577,600_
TOTAL ANNUALIZED COSTS $ J.,861,500_
a Included with replacement parts,
N. A. - Not applicable.
G-59
-------
TABLE G-39. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
MEDIUM-SULFUR COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30. 1978 (FOR COSTS INDEXING)
EQUIPMENT COST
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 3,571,300
65nrnnn
378,600
877,000
186,800
Incl. w/coal handling
60,000
Jncl. w/boiler
150,000
25,000
60,000
4,000"
41,80lT
1,044,000
344,500
Incl. w/coal handling
N.A.
$7,393,000
$ 2,265,500
Incl. w/equipment
110,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
12,000
Incl. w/boiler
18,000
10,000
16,000
2,000
657,701?
271,400
Incl. w/coal handling
N.A.
(continued)
G-60
-------
TABLE G-39 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 344,500
Duct work (not incl. w/boiler) N.A.
Piping 130,500
Insulation 114,8M
Painting 16f700
Electrical 340, OOu"
Buildings 678,600
Total installation cost $ 4,987,700
TOTAL DIRECT COSTS
(equipment + installation) $ 12,380,700
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 1,238,100
Construction and field expense
(10% of direct costs) 1,238,100
Construction fees
(10% of direct costs) ->*•> 'Inn
Startup (2% of direct costs) 24/,6UU
Performance tests (minimum $2000) 15,000
TOTAL INDIRECT COSTS $ 3,976,900
Contingencies
(20% of direct and indirect costs) $ 3,271,500
Total Turnkey Costs
(direct+indirect+contingencies) $ 19,629,100
Land $ 4'000
Working capital (25% of total direct
operating costs) $ 1,074,200
'GRAND TOTAL
(turnkey+land+working capital) $ 20,707,300
a Quote from Babcock & Wilcox, Inc., August 19, 1978.
N.A. - Not applicable.
G-61
-------
TABLE G-40. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
MEDIUM-SULFUR COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
DIRECT COST
Direct labor $ 737,100
Supervision 205,400
Maintenance labor 384,500
Maintenance materials 5
Replacement parts 365,400
Electricity 501,100
Steam N.A.
Cooling water N.A.
Process water 6,100
Fuel 1.997.000
Bottom ash disposal 84,000
Chemicals 16,000
Total direct cost S4. 296.600
OVERHEAD
Payroll (30% of direct labor) $ 221,100
Plant (26% of labor, parts & maint.) 440'000
Total overhead costs $ 661,100
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) $ 785,200
Capital recovery factor
(10.14% of total turnkey costs) 1,QQQ,4QQ
Interest on working capital
(10% of working capital) 107,400
Total capital charges $ 2,883,000
TOTAL ANNUALIZED COSTS $ 7,840,700
a Included with replacement parts.
N.A. - Not applicable.
G-62
-------
TABLE G-41. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
HIGH-SULFUR COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/75,0°F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30. 1978 fFDE COSTS INDEXING)
EQUIPMENT COSTa
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
$ 4,002,300
650,000
378.600
982.800
209,300
Incl. w/coal handling
60,000
Incl. w/boiler
150,000
25,000
60,000
4,000
46.800
1.170,000
386,100
Incl. w/coal handling
N.A.
$ 8,124,900
$ 2,538,900
Incl. w/equipment
110.000
Incl. w/boiler
Jncl. w/boiler
Incl. w/coal handling
12rOQO
Incl. w/boiler
18:000
10.000
16.000
2.000
737.100
304,200
Incl. w/coal handling
N.A.
(continued)
G-63
-------
TABLE G-41 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 286,000
Duct work (not incl. w/boiler) N.A.
Pipino 1^6,000
Insulation 129,000
Painting _ 19,000
Electrical _ 340,000
Buildings _ 761,000
Total installation cost $ 5,529,200
TOTAL DIRECT COSTS
(equipment + installation) $ 13f 654 , 100
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ i,.xfiq,4nn
Construction and field expense
(10% of direct costs) i , Tg^dQQ
Construction fees
(10% of direct costs) 1,365,400
Startup (2% of direct costs) - 273'100
Performance tests (minimum $2000) _ 1 5 , n n n
TOTAL INDIRECT COSTS $ 4,384,300
Contingencies
(20% of direct and indirect costs) $ 3,607,700
Total Turnkey Costs
(direct+indirect+contingencies) $ 21,646,100
Land $ 4
Working capital (25% of total direct
operating costs) ? 937,900
'GRAND TOTAL
(turnkey+land+working capital) $ 22,638,000
Quote from Babcock & Wilcox, Inc., August 19, 1978.
N.A. - Not applicable.
G-64
-------
TABLE G-42. ESTIMATED ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
HIGH-SULFUR COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
DIRECT COST
Direct labor $ 737,100
Supervision 205,400
Maintenance labor 384,500
Maintenance materials a
Replacement parts 409,500
Electricity 561,600
Steam N.A.
Cooling water N.A.
Process water 6,100
Fuel 1,555,800
Bottom ash disposal 75,500
Chemicals 16,000
Total direct cost $ 3r951f500
OVERHEAD
Payroll (301 of direct labor) $ 221,100
Plant (26% of labor, parts & maint.) 451,500
Total overhead costs $ 672,600
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance ,,
(4% of total turnkey costs) * 865,800
Capital recovery factor
(10.14* of total turnkey costs) 2.194.900
Interest on working capital
(10% of working capital) 93,BOO
Total capital charges $ 3,159,500
TOTAL ANNUALIZED COSTS $ 7,783.600
Included in replacement parts.
N.A. - Not Applicable
G-65
-------
TABLE G-43. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
LOW-SULFUR COAL WITH A THERMAL INPUT OF 117,2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30, 1978 (FOR COSTS INDEXING)
EQUIPMENT COST3
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
3.420,800
650.000
378,600
840,000
178,900
Incl. w/coal handling
60,000
Incl. w/boiler
150,000
25,000
60,000~
"" "4,000
40,OD~0~
330.000
Incl. w/coal handling
N'.A.
$ 7,137,300
$ 2,170,
Incl. w/equipment
110,000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
12,000
Incl. w/boiler
18,000~
10, OW
16,000
~~~ 2,000
"~~°63 0, POTT
260,QUIT
Incl. w/coal handling
N.A.
[continued)
G-66
-------
TABLE G-43 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports $ 330,000
Duct work (not incl. w/boiler) N.A.
Piping 125,000
Insulation 110/000
Painting 16,000
Electrical 340,000
Buildings 650,000
Total installation cost $ 4,799,000
TOTAL DIRECT COSTS
(equipment -$- installation) $11, 936f 300
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) $ 1.193.600
Construction and field expense
(10% of direct costs) 1,193.,6.QQ
Construction fees
(10% of direct costs) 1.193.6QQ
Startup (2% of direct costs) 238,700
Performance tests (minimum $2000) I5/000
TOTAL INDIRECT COSTS $-3,834,500
Contingencies
(20% of direct and indirect costs) $ 3,154,200
Total Turnkey Costs
^iRQ^^nnn
(direct+indirect+eontingencies) 9J-0 T ?^~>' uuu
Land $ 4'000
Working capital (25% of total direct
operating costs) $ 1,165
'GRAND TOTAL
(turnkey+land+working capital) $2Qf094,000
a Quote from Babcock & Wilcox, Inc., August 19, 1978.
N.A. - Not applicable.
G-67
-------
TABLE G-44. ESTIMATED.ANNUALIZED COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING EASTERN
LOW-SULFUR COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
DIRECT COST
Direct labor $ 737,100
Supervision 205,400
Maintenance labor 384,500
Maintenance materials <*
Replacement parts 350,OOP
Electricity 480,000
Steam N.A.
Cooling water N.A.
Process water 6_, 100
Fuel ?,4?R,»nn
Bottom ash disposal 42,OOP
Chemicals 16f QQQ
Total direct cost $ 4,659,900
OVERHEAD
Payroll (30% of direct labor) $ 221.1PP
Plant (26% of labor, parts & maint.) 436.000
Total overhead costs $... 657,100
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) $ 757,000
Capital recovery factor
(10.14* of total turnkey costs) 1,919,000
Interest on working capital ,, . _-n
(10% of working capital) 116,500
Total capital charges $ 2,792,500
TOTAL ANNUALIZED COSTS $ 8,109,500
Included with replacement parts.
N.A. - Not Applicable
G-68
-------
TABLE G-45. ESTIMATED CAPITAL COSTS OF A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING
SUBBITUMINOUS COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
CAPITAL COSTS
DATE OF ESTIMATE.
June 30, 1978 (FDP COSTS INDEXING)
EQUIPMENT COST a
Boiler (with fans & ducts)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
Total Equipment Cost
INSTALLATION COST, DIRECT
Boiler (including founda-
tions and steel)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate system
Water treating system
Chemical feed
Coal handling system
Ash disposal system
Thawing equipment
Fuel-oil system
4.926rOOQ
650.000
378.600
1.209.600
257.600
Incl. w/coal handling
60.000
Incl. w/boiler
150.000
25.000
60.000
4,000
57,600
1,440,000
475,200
Incl. w/coal handling
N.A.
$ 9,693,600
$ 3,124,800
Incl. w/equipment
110.000
Incl. w/boiler
Incl. w/boiler
Incl. w/coal handling
12,000
Incl. w/boiler
18,000
10,000
16,000
2,000
907,200
374,400
Incl. w/coal handling
N.A.
(continued)
G-69
-------
TABLE G-45 (continued)
INSTALLATION COSTS, DIRECT (cont.)
Foundations and supports 475,000
Duct work (not incl. w/boiler) N.A.
Pipina 180,000
Insulation 158,000
Painting ,^'°°°
Electrical 340,000
Buildings 936,000
Total installation cost $ 6,686,400
TOTAL DIRECT COSTS .
(equipment + installation) $16,380,000
INSTALLATION COSTS, INDIRECT
Engineering
(10% of direct costs) ? 1,638,000
Construction and field expense
(101 of direct costs) If638f000
Construction fees
(10% of direct costs) 1,638,000
Startup (2% of direct costs) 327,600
Performance tests (minimum $2000) 15,QQQ
TOTAL INDIRECT COSTS $ 5,256,600
Contingencies ^
(20% of direct and indirect costs) * 4>327'300
Total Turnkey Costs
(direct+indirect+contingencies) $ 25,Qfi3,Qnn
Land $ 4, OOP
Working capital (25% of total direct
operating costs) $ 868f70Q
"GRAND TOTAL
(turnkey-i-land+working capital) $ 26,836,600
Quote from Babcock & Wilcox, Inc., August 19, 1978.
N.A. - Not applicable.
G-70
-------
TABLE G-46. ESTIMATED ANNUALIZED COSTS FOR A FIELD-ERECTED,
WATER-TUBE, PULVERIZED-COAL-FIRED BOILER FIRING
SUBBITUMINOUS COAL WITH A THERMAL INPUT OF 117.2 MW
(400 x 106 Btu/hr; 750 psig/750°F design)
DIRECT COST
Direct labor $ 737.100
Supervision 205.400
Maintenance labor 384 .500
Maintenance materials §
Replacement parts 5Q4 , 00Q
Electricity £Qi,?nn
Steam rc. A.
Cooling water TJ.A.
Process water 6 ,100
Fuel 883,OOP
Bottom ash disposal 47.300
Chemicals 16,QQO
Total direct cost S 3r474.600
OVERHEAD
Payroll (30% of direct labor) $ 221,100
«
Plant (26% of labor, parts & maint.) 476,100
Total overhead costs $ 697,200
BYPRODUCT CREDITS N.A.
CAPITAL CHARGES
G & A, taxes & insurance
(4% of total turnkey costs) $ 1,Q38.600
Capital recovery factor
(10.14* of total turnkey costs) 2.632,700
Interest on working capital
(10% of working capital) 86,900
Total capital charges $ 3,,758,200
TOTAL ANNUALIZED COSTS $ 7.930,000
aincluded in replacement parts.
N.A. - Not Applicable
G-71
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-178a
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Population and Characteristics of Industrial/Commer-
cial Boilers in the U.S.
5. REPORT DATE
August 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
T.Devitt, P.Spaite, and L. Gibbs
8. PERFORMING ORGANIZATION REPORT NO.
PN 3310-S
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2603, Task 19
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND.PER.IOp COVERED
Task Final; 3/78 - 5/79
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES IERL-RTP project officer is Charles J. Chatlynne, Mail Drop 61,
919/541-2915.
16. ABSTRACT
The report describes a study of boiler population and characteristics,
fuel consumption, emissions, and boiler costs that provides a basis irom which
a broader study of overall environmental impacts of non-utility boilers can be
made. Boilers consume about one-third of the fdssil fuels burned in the U.S.
Over 40% of this is fired in industrial/commercial boilers; the rest, in utility boilers
There are about 1. 8 million industrial/commercial boilers in the U.S. Only about
0.1% of these have a firing capacity greater than 73.2 MW. These larger boilers,
however, represent 17% of the total U.S. capacity. About 72% of the total boilers are
classified as commercial, used primarily for space heating. The industrial boilers
represent 69% of the total firing capacity and are concentrated in four major indus-
tries: pulp and paper, primary metals, chemicals, and minerals. Estimated uncon-
trolled particulate matter emissions in 1975 from industrial/commercial boilers
were about 2. 5 Tg per year in addition to about 2. 9 Tg per year of SOx and 1. 8 Tg
per year of NOx. CO and HC emissions are relatively minor. Using a 3. 3% annual
growth rate, the emissions will more than double by the year 2000. Capital and
annualized operating costs were determined for 23 boiler/fuel combinations repre-
senting a cross section of the boiler population.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Pollution
Boilers
Population (Statistics!
Characteristics
Fuel Consumtpion
Emission
Expenses
Pollution Control
Stationary Sources
13 B
13A
12A
14B
21D
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
462
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
G-72
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