&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 2771 1
EPA-600/7-79-233
October 1979
Overview of Pollution
from Combustion of Fossil
Fuels in Boilers of the
United States
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-233
October 1979
Overview of Pollution from Combustion of
Fossil Fuels in Boilers of the United States
by
P.W. Spaite (Consultant) and T.W. Devitt
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 Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
The report describes the fossil-fuel-fired boiler population
of the United States, presenting data on the number and capacity
of boilers for categories with most relevance to production of
pollution. This information includes:
0 Type of fuel burned
(coal, residual oil, distillate oil, natural gas)
0 Usage sector
(utility, industrial, commercial)
0 Size category
(<25 x 10* Btu/hr, 25-250 x 106 Btu/hr, >250 x 106 Btu/hr)
0 Heat transfer configuration
(Water tube, fire tube, cast iron)
Fuel consumption data are presented for each type of fuel burned
in each usage sector. These data are used to make estimates for
the amount of sulfur oxide, nitrogen oxide, and particulate air
emissions produced by boilers operation. Other air pollutants
are discussed qualitatively. Solid waste and water pollution
from boiler operation are discussed generally-
1979 by Paul W. Spaite
In accordance with the terms of the contract, the contractor has granted
to the Government a royalty-free, nonexclusive, and irrevocable license
throughout the world for Government purposes to publish, translate, repro-
duce, deliver, perform, dispose of, and to authorize others to do so, the
copyrighted material contained herein.
11
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CONTENTS
Page
Abstract ii
Figures iv
Tables v
1. Introduction 1
Background 1
Report Organization 4
2. Boiler Population of the United States 6
3. Annual Fuel Consumption 16
4. Atmospheric Emissions from Boiler Operation:
Sulfur Oxides, Nitrogen Oxides, Particulate Matter,
Carbon Monoxide, and Hydrocarbons 23
Emission Estimates 23
Projected Discharges 27
5. Atmospheric Emissions from Boiler Operation: Trace
Metals, Polycyclic Organic Matter, and Sulfates 33
6. Water Pollution and Solid Waste Discharges from
Boiler Operation 44
7. Conclusions and Recommendations 51
Collect Additional Data on Boiler Population 52
Measurement of Air Emissions 53
Factors Influencing Fuel Use Patterns 53
Future Research and Development Needs
References 56
in
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FIGURES
Number Page
1 Relative Distribution of the Capacity of the
Industrial/Commercial Boiler Population by
Type and Size 12
2 Projected Emissions of Particulate Matter, SO
and NO from Utility and Industrial/Commercial
Boiler! 29
3 Projected Sulfur Oxide Emissions for Coal-Fired
Power Plants 30
IV
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TABLES
Number Page
1 Summary of the Total Boiler Population by
Type of Fuel, 1977 8
2 Summary of Total Boiler Population by
Consuming Sector, 1977 9
3 Summary of Total Boiler Capacity by Size, 1977 11
4 Summary of the Total Boiler Capacity by Type
of Heat Transfer Configuration, 1977 13
5 Fuel Consumption for Boilers in the United
States, 1975 19
6 Distribution of Boiler Capacity and Fuel
Consumption by Sector and Fuel Type 20
7 Overall Annual Capacity Factor for Boilers
in the United States, 1975 18
8 Estimated Emissions of Three Criteria
Pollutants from Boilers, 1975 24
9 Relative BaP Emission Rates from Stationary
Fuel Combustion Sources 38
10 Mean Analytical Values for 101 Coals 41
11 Distribution of 28 Trace Metals in Ashes of
24 Crude Oils 42
12 Utility Wastewater Discharges 47
13 Projected Ash and FGD Sludge Generation,for
Coal-Fired Boilers Larger than 250 x 10 Btu/h 49
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CONVERSION TABLE
ENGLISH TO METRIC
English Unit
British thermal unit (Btu)
Btu/hour
105 Btu/hour
Ton
Gallon
Multiplier
1,055.056
0.2931
0.2931
907.185
0.003785
To Metric Unit
joule (J)
watt (W)1
megawatt (MW)
kilogram (kg)
3
cubic meter (m )
Thermal units not to be confused with electrical.
VI
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SECTION 1
INTRODUCTION
BACKGROUND
Annual consumption of fossil fuels in the United States in
recent years has totalled about 75 x 10 Btu. One-third of this
total was consumed in boilers. This exceeds even transportation
(19 x 10 Btu/yr) which is by far the next largest usage. Other
major categories for consumption of fossil fuels are residential
usage (about 14.4 x 10 Btu) and fuel for direct heating of
processes (about 8.6 x 10 Btu). These four categories account
for some 89 percent of all fossil fuel consumption. The balance
is used for feedstocks, raw materials, and other miscellaneous
uses. Further, most of the "dirty" fuels (coal and residual oil)
go into boilers. Hence boilers are, by virtue of amount and type
of fuel burned, by far the largest single source of air pollution
from sulfur oxides and are a significant source of particulate
matter and nitrogen oxides. While the contribution of other
sources to environmental pollution is recognized as important,
the present study is limited to the development of background
information on boiler combustion which is sufficiently important
to warrant the effort to analyze the complex nature of the prob-
lems presented.
-------
Fuel consumption in boilers is divided into three sectors:
utility boilers producing steam for generation of electricity
(59%); industrial boilers generating steam or hot water for
process heat, generation of electricity, or space heat (24%); and
boilers for space heating for commercial and institutiononal
facilities (17%). Some space heating for the residential sector
takes place in boilers, and some fuel burned in boilers classi-
fied as institutional is probably providing heat for multi-family
dwellings. No attempt was made to correct these minor departures
from complete accuracy in boiler classification because they
probably have no significant impact on the results of the inves-
tigation.
The fuels consumed in boilers in large quantities are nat-
ural gas, distillate oil, residual oil, and coal. Additional
energy is derived from the burning of waste fuels such as bark,
bagasse, liquid hydrocarbon waste materials, etc. These fuels
contribute only a small percentage to energy needs. They may,
however, present environmental problems out of proportion to the
Btu's supplied especially in the immediate future when high fuel
costs and increasing cost to dispose of waste materials will
provide new incentives to burn them. Problems in this area have
not been addressed because of the need to focus on more funda-
mental boiler-fuel-pollution relationships which are not pres-
ently understood. New Source Performance Standards (NSPS) for
boilers burning waste are to be developed in the near future.
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Further information on present and projected waste burning prac-
tices will be developed in connection with this activity.
For the fossil fuels being considered, various combinations
of consuming sectors (i.e., utility, industrial, and commercial),
types of application (i.e., generation of electricity, process
steam and space heat) and type of fuel, have independent and
significant environmental consequences. An overall analysis of
pollution from boiler operation is complicated by the fact that
boilers employed are of three basically different types, i.e.
watertube, firetube and cast iron. In addition, each type varies
in size, predominant type of fuel fired, combustion conditions,
type of application, and other factors influencing the character
and quantity of environmental discharges.
The complexity of analyzing the impacts of boiler operation
in the United States has given rise to a series of studies by the
U.S. Environmental Protection Agency. These studies have as-
sessed various aspects of the environmental consequences of
boiler operation and have progressively advanced our overall
understanding of the impacts of specific pollutants and the
control technology appropriate for different boilers. This
overview is intended to place these findings in perspective and
to suggest priorities for developing control systems and strate-
gies. No attempt was made to include detailed economic analyses
or in-depth evaluations of pollution control technology since
such information is not needed to develop the perspective that
this study is attempting to provide.
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REPORT ORGANIZATION
This report is organized into seven sections which discuss
the general character of the boiler population, the environmental
impacts from boiler operation, and recommended future actions.
Section 2 presents information on the estimated fuel burning
capacity of each important type of boiler. The values presented
are derived from previous boiler studies by updating earlier
estimates with boiler sales data for the past 10 years. Section
3 presents estimates for amount and type of fuel actually con-
sumed in different types of boiler service, and discusses capa-
city factors derived from the total capacity and fuel consumption
figures. Data are presented for coal, residual oil, distillate
oil and natural gas burned in the utility, industrial and commer-
cial sectors.
Section 4 discusses potential discharges and emission esti-
mates for sulfur oxides, nitrogen oxides, particulate matter,
carbon monoxide, and hydrocarbons, 5 of the 7 criteria pollu-
tants. Section 5 discusses trace metals (including lead, a
criteria pollutant), polycyclic organic matter, and sulfates.
Section 6 discusses the impact of wastewater and solid waste
associated with boiler operation.
Section 7 presents conclusions of the report and recommen-
dations for further work in four areas.
0 Improvement of the information on application, oper-
ating practices, etc. for existing boilers
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Obtaining better data for characterization of boiler
air emissions
R&D to control environmental discharges
Work to anticipate environmental problems which may
accompany future changes in boiler and fuel usage
patterns
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SECTION 2
BOILER POPULATION OF THE UNITED STATES
For this analysis, the boiler population of the United
States has been divided into categories which are considered most
significant for determining potential environmental impact.
These categories are:
(1) Type of fuel burned
(coal, residual oil, distillate oil, natural gas)
(2) Usage sector
(utility, industrial, commercial)
(3) Size category fi fi
(less than 25 x 10 Btu/h, 25-250 x 10 Btu/h, more
than 250 x 10 Btu/h)
(4) Heat transfer configuration
(watertube, firetube, cast iron)
The population (number of boilers) and total fuel burning
capacity (10 Btu/h) have been estimated for each category. Data
were taken from a report by Walden (Ehrenfeld et al., 1970), and
two reports by Battelle (Locklin et al. , 1974), and (Putnam et
al., 1975). These data were refined and updated using boiler
sales data for the past 10 years which were supplied by the
American Boiler Manufacturers Association and the Hydronics
Institute. The procedures used to develop the estimates are
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described in a recent PEDCo report (Devitt et al. , 1979). Tables
showing the detailed estimates are also contained in the PEDCo
report.
The distribution of boiler capacity by fuel type is shown in
Table 1. Totals are shown for the utility sector, and for the
industrial and commercial sectors combined, to permit comparison
of utility and non-utility boilers. Total capacity of commercial
and industrial boilers is shown to be roughly equivalent to that
of utility boilers. Further, the total capacity for units con-
suming "dirty fuels" (coal and residual oil) is roughly equiva-
lent. Natural gas is the dominant fuel in the industrial and
commercial sectors. Replacement of large parts of this capacity
by additional coal- and oil-fired units would greatly increase
the pollution from boilers in these sectors. Conversely, the
present trend towards firing more natural gas in lieu of oil is
an improvement from an environmental perspective. The long-term
trend away from oil and natural gas to coal-firing may be an
environmental improvement to the extent that well controlled
coal-fired units might emit less offensive pollution than uncon-
trolled oil-fired units which are typical of those in commercial
and industrial service.
The distribution of boilers among the commercial and indus-
trial sectors is shown in Table 2, along with average capacities
for all sectors.
7
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TABLE 1. SUMMARY OF THE TOTAL BOILER POPULATION BY TYPE OF FUEL, 1977
Utility Boilers
Coal
Residual oil
Distillate oil
Natural gas
Total Utility
Industrial/Commercial
Coal
Residual oil
Distillate oil
Natural gas
Total Industrial/Commercial
All Boilers
Coal
Residual oil
Distillate oil
Natural gas
Total All Boilers
Number of boilers
1,533
1,038
196
984
3,751
214,400
389,104
244,206
954,350
1,802,060
215,933
390,142
244,402
955,334
1,805,811
Capacity (106 Btu/h)
1,833,000
743,600
57,300
1,013,700
3,647,600
815,800
1,223,800
433,600
2,008,800
4,482,000
2,648,800
1,967,400
490,900
3,022,500
8,129,600
00
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TABLE 2. SUMMARY OF TOTAL BOILER POPULATION BY
CONSUMING SECTOR, 1977
Usage sector
Utility
Industrial
Commercial
No. of
Boilers
3,751
506,930
1,295,130
1,805,811
Total capacity,
(106 Btu/hr)
3,647,500
3,107,400
1,374,700
8,129,600
Average capacity,
(106 Btu/h)
972
6.1
1.1
Although the total capacity of utility boilers is roughly equiva-
lent to that of industrial and commercial boilers, there is a
great disparity in terms of numbers. The greater number of
industrial and commercial boilers, combined with their smaller
average size and greater proximity to population centers, com-
plicates controlling their emissions and increases their environ-
mental impact potential. The variation in average size is ex-
treme, being almost 1000 x 10 Btu/h for utility boilers versus
about 6 x 10 Btu/h for industrial boilers and 1 x 10 Btu/h for
commercial boilers. Assessing the environmental impact potential
of industrial and commercial boilers is made more difficult by
differences in heat transfer configuration, i.e. watertube,
firetube or cast iron versus watertube only for utilities.
Furthermore the industrial boilers may be used to generate elec-
tricity, to produce process steam, or for space heating; all of
these uses call for different load swings and variation in other
operating conditions that can influence both the rate and type of
emissions as well as their resulting impact.
-------
The distribution of boilers by size category is shown in
Table 3. Boiler size is of great importance as far as relative
impact of boiler operation is concerned. Pollution from larger
boilers may often, despite the much greater amount being gen-
erated, produce relatively modest environmental impacts. Instal-
lation of environmental control equipment is generally required;
and the combustion process is better controlled, burning the fuel
more completely and forming fewer potentially hazardous air
pollutants per unit of fuel burned.
The data in Table 3 show that a little over half of the
existing boiler capacity and well under 1 percent of the boilers
by number are subject to the size limitations (250 x 10 Btu/h or
greater) of the New Source Performance Standard (NSPS) promul-
gated December 23, 1971. However, NSPS are currently being
considered for the industrial boiler population. These standards
are only in the formulative stage, but it is possible that a
lower cutoff limit of 25 x 10 Btu/h may be established. The
speculation concerning the lower size limit is based upon the
almost even distribution of boiler capacity between those less
than 25 x 106 Btu/h and those between 25 x 106 Btu/h and 250 x
C £i
10 Btu/h. Those having a capacity less than 25 x 10 Btu/h are
mostly cast iron or firetube boilers (about 90 percent), whereas
those between 25 x 10 Btu/h and 250 x 106 Btu/h are mostly
watertube boilers. This is illustrated by Figure 1 which shows
boiler capacity distribution by size and boiler type.
10
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TABLE 3. SUMMARY OF TOTAL BOILER CAPACITY BY SIZE, 1977
Utility
Size (106 Btu/h)
< 25
25-250
> 250
Industrial/Commercial
Size (106 Btu/h)
< 25
25-250
> 250
All Boilers
< 25
25-250
> 250
Number of Boilers
193
1,183
2,375
3,751
Number of Boilers
1,773,135
27,589
1,336
1,802,060
Number of Boilers
1,773,328
28,772
3,711
1,805,811
Total Capacity
2,200
160,700
3,484,600
3,647,500
Total Capacity
1,979,400
1,743,700
759,000
4,482,100
Total Capacity
1,981,600
1,904,400
4,243,600
8,129,600
(106 Btu/h)
(106 Btu/h)
(106 Btu/h)
-------
800,000 h
600.000 I-
400,000 I-
200,000 I-
<0.4 0.4-1 1-10 10-25 25-50 50-100 100-250 250-500 500-1500 >1500
SIZE RftNGE, 106 Btu/h
Figure 1. Relative distribution of the capacity of the
industrial/commercial boiler population by type and size.
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Classification by heat transfer configuration is an impor-
tant consideration in evaluation of environmental impacts of the
boiler population, partly because configuration has a direct
effect on combustion conditions (and resulting emissions) but
also because there is a great difference in size of boilers using
the three basic types of heat transfer configuration. The dis-
tribution of the boiler population by type of heat transfer
configuration is shown in Table 4.
TABLE 4. SUMMARY OF THE TOTAL BOILER CAPACITY
BY TYPE OF HEAT TRANSFER CONFIGURATION, 1977
Heat transfer
configuration
Watertube (Utility)
Watertube (Non-utili
Firetube
Cast Iron
Number of
boilers
3,751
ty) 50,495
275,075
1,476,490
1,805,811
Total, capacity,
(10 Btu/h)
3,647,500
2,552,500
1,033,300
896,200
8,129,500
Average size
(10b Btu/h)
972
50
3.7
0.6
These data show that watertube boilers make up over 80
percent of the total estimated capacity. The smaller firetube
and cast iron boilers do however, constitute a significant part
of the capacity and amount to over 95 percent of the total popu-
lation. It is interesting to note that the average size for
watertube non-utility boilers is about 50 x 10 Btu/h as compared
to about 6 x 106 Btu/h for all industrial boilers. This differ-
ence reflects the use of a significant number of firetube boilers
in industrial applications and is another illustration of the
wide variety of boiler practices in the industrial sector.
13
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In summary, boilers can be classified in a number of ways.
Their characteristics by configuration can best be summarized as
follows:
Utility Watertube
0 These boilers account for 45 percent of the total
boiler capacity.
0 Over 95 percent are above 250 x 10 Btu/h in capacity.
0 The average size is much greater than that of indus-
trial or commercial boilers (almost 20 times greater
than the largest industrial category).
0 Almost all units are field-erected.
0 About half of the total capacity is designed to burn
coal.
Industrial/Commercial Watertube
0 These boilers make up the majority of total indus-
trial/commercial capacity.
0 They represent the least number of industrial/com-
mercial boilers.
0 The average boiler size is the largest of the three
types used in industrial/commercial applications.
0 Field-erected units represent the majority of the total
capacity.
0 Most units are industrial rather than commercial.
Firetube
They may be used for generation of process steam,
electricity, or space heat.
These boilers represent 13 percent of the total boiler
capacity and 25 percent of the industrial/commercial
boiler capacity-
The average boiler size is small compared with water-
tube boilers.
14
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0 They represent 15 percent of the total number of boil-
ers .
0 All units are package (shop fabricated).
0 Very few fire coal.
Cast Iron
0 These boilers comprise 11 percent of the total boiler
capacity and 20 percent of the industrial/commercial
boiler capacity.
0 They represent the largest number of boilers (81%).
0 The average boiler size is the smallest of all the
categories.
0 All units are package.
0 Most are used for generation of space heat and hot
water.
0 Most are commercial rather than industrial.
15
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SECTION 3
ANNUAL FUEL CONSUMPTION
Ideally, analysis of boiler fuel consumption in the evalua-
tion of environmental impacts would begin with study of the
important combinations of consuming sector, boiler type and
application. These combinations are:
Sector Boiler type Application
Utility Watertube Electric generation
Industrial Watertube Electric generation
Industrial Watertube Process steam
Industrial Watertube Space heat
Industrial Firetube Process steam
Industrial Firetube Space heat
Commercial Watertube Space heat
Commercial Firetube Space heat
Commercial Cast iron Space heat
Each of these groups, for a given fuel type, would be ex-
pected to have unique process-discharge characteristics which
would be reasonably uniform within the group. Collectively, the
groups would represent essentially all boiler combustion. Given
details on type and amount of fuel burned in each category, it
would be possible to make a definitive comparison of environ-
mental discharges.
16
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Unfortunately data on fuel consumption are not sufficiently
detailed to permit such an analysis. In fact, considerable in-
vestigation was required to develop reasonable estimates for
amounts of each type of fuel used in each of the three basic
consuming sectors. The details of this investigation were re-
ported by PEDCo (Devitt et al. , 1979). Data from the Federal
Power Commission were the primary data source for utility boiler
consumption (Federal Power Commission, 1976a). For the indus-
trial and commercial sectors, reports from the Department of
Energy (Bureau of Mines, 1976 a, b, and c) contained basic data.
The data reported for utilities were specific and detailed. For
the industrial and commercial sectors considerable analysis was
necessary to estimate the amount of the total fuel consumption
which was attributable to boiler operation. For example, data
were available for total industrial fuel usage but secondary
sources of information were needed to estimate boiler fuel con-
sumption. The supplementary sources included the Survey of Major
Fuel Burning Installations (Department of Energy, 1975) and the
Stanford Research report on energy patterns of the United States
(Stanford Research Institute, 1972). For the commercial sector
similar problems of data interpretation were encountered e.g.,
figures for total gas consumption were available (Bureau of
Mines, 1976 c) but the distribution among boiler fuel and other
uses such as water heating, cooking, etc., was not given. Per-
centages from the Stanford study were used to estimate the space
heat fraction and it was assumed that this represented boiler
fuel.
17
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Although interpretations and assumptions have undoubtedly
led to some inaccuracies, the results provide a reasonable basis
for analysis of the environmental impacts of boiler operation in
all consuming sectors. This is illustrated by a comparison made
between the boiler fuel consumption patterns by sector and boiler
capacity by sector. Consumption data are shown in Table 5 for
categories comparable to those used for capacity in Table 1. For
all categories, there is reasonable agreement in the distribution
between sectors for capacity and consumption. This is illus-
trated by the values in Table 6.
Using these data, overall annual capacity factors* were
developed. These factors are shown in Table 7.
TABLE 7. OVERALL ANNUAL CAPACITY FACTOR FOR BOILERS
IN THE UNITED STATES, 1975
Sector/Fuel Type
Utility
Coal
Residual oil
Distillate oil
Natural gas
Industrial/Commercial
Coal
Residual oil
Distillate oil
Natural gas
Capacity factor
0.580
0.396
0.258
0.340
0.154
0.164
0.297
0.322
*The capacity factor was derived by (1) dividing the total
national capacity (in 10' Btu/h) into the fuel consumption
for 1975 (in Btu) to calculate hours of operation possible
for all boilers on the amount of fuel consumed; and (2)
dividing this value by the total number of hours in a year.
18
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TABLE 5. FUEL CONSUMPTION FOR BOILERS IN THE UNITED STATES, 1975
Sector/Fuel Type
Utility
Coal (103 tons)
Residual oil (103 bbl)
Distillate oil (103 bbl)
Natural gas (106 ft3)
I ndustr i al/Commerc i al
Coal (103 tons)
Residual oil (103 bbl)
Distillate oil (103 bbl)
Natural gas (106 ft3)
All Boilers
Coal (103 tons)
Residual oil (103 bbl)
Distillate oil (103 bbl)
Natural gas (106 ft3)
Quantity
431,075
446,699
22,245
2,945,969
i
44,417
280,170
193,758
i 6,231,641
i?
475,492
726,869
216,003
9,776,610
12
Fuel Consumption (10 Btu)
9,310.0
2,590.8
129.7
3,016.7
15,047.2
1,101.6
1,762.3
1,129.6
6,381.2
10,374.7
10,411.6
4,353.1
- 1,259.3
9,397.9
25,421.9
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TABLE 6. DISTRIBUTION OF BOILER CAPACITY AND FUEL
CONSUMPTION BY SECTOR AND FUEL TYPE
Percent of
total capacity
Percent of
total consumption
Utility
Coal
Residual oil
Distillate oil
Natural gas
22.6
9.1
0.7
12.5
36.6
10.2
0.5
11.9
Industrial/Commercial
Coal
Residual oil
Distillate oil
Natural gas
10.0
15.1
5.3
24.7
4.3
6.9
4.4
25.1
20
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The capacity factor for some categories is lower than re-
ported in previous studies, e.g., Battelle (Putnam et al. , 1975)
reported factors ranging from 0.206 to 0.524 for commercial and
industrial boilers burning coal, oil or natural gas. Also the
weighted average of 26.1 percent from this study is lower than
the estimate of 35 percent from a previous boiler study
(Ehrenfeld et al., 1971). 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 capacity and fuel consump-
tion values produced a load factor much greater than 1.0. Never-
theless some of the values derived here for industrial units
appear to be low. This bias may be caused by assumptions con-
cerning replacement rates, as discussed in the PEDCo report
(Devitt, et al., 1979).
On the other hand, the figures may indicate, at least in
part, that a substantial number of boilers are on standby. A
brief survey in connection with this study identified a number of
sites with 100 percent excess steam-raising capacity. In the
opinion of several industry representatives, this is a common
practice in the chemical and petroleum refining industries.
Information on specific plants indicates that not only are there
many spare or stand-by boilers, but also that individual boilers
are sized in excess of demand. Several instances were found
where only 50 to 75 percent of boiler capacity was required for
21
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plant needs. Another factor having a large impact on overall
capacity factor is the seasonal operation of many boilers. For
instance, many food processing plants only operate 2 to 3 months
out of a year with their boilers idle during the remaining
months. Thus unit capacity factors in these situations may be
significantly lower than previously estimated.
In summary, the most important comments on boiler fuel con-
sumption are as follows:
0 Data are not available to relate amount and type of
fuel burned to type of boiler and type of application
of the various boiler-fuel combinations.
0 Determination of the percentage of each type of fuel
being consumed in boilers involves the use of secondary
sources of information, some of which are dated or of
questionable reliability.
0 In spite of these data limitations sufficient informa-
tion is available to relate type and amount of fuel
burned to major consuming sectors.
° Utility consumption of all fuels is about 60 percent of
the total fuel consumed in boilers. Coal is the major
utility fuel. About 60 percent of the coal produced in
the United States is burned in utility boilers.
0 Industrial and commercial boilers consume over half of
the combined production of distillate and residual oil
burned in boilers. This represents about one-fourth of
the oil burned in the United States.
22
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SECTION 4
ATMOSPHERIC EMISSIONS FROM BOILER OPERATION: SULFUR
OXIDES, NITROGEN OXIDES, PARTICULATE MATTER, CARBON MONOXIDE,
AND HYDROCARBONS
EMISSION ESTIMATES
Air pollution discharges from boilers were estimated using
fuel consumption data for 1975 and emission factors presented in
EPA's "Compilation of Air Pollutant Emission Factors," (U.S. EPA,
1977). These factors which are given for emissions per unit of
fuel burned, represent a compilation of test data on various
boiler types and fuels. The EPA has ranked these factors as
"very good" with respect to the data used to derive the factors.
PEDCo has compiled more recent test data on boiler emissions and
the results were not significantly different from the EPA values.
In most cases the EPA values were within 5 to 20 percent of the
more recent test data.
Estimated emissions from boilers of particulate matter,
sulfur oxides, and nitrogen oxides are shown in Table 8 along
with EPA estimates for the total annual emissions for the United
States. It should be noted that AP-42 factors yield an estimate
for total uncontrolled particulate emissions. A 1973-1974 survey
by PEDCo (PEDCo, 1976) determined that the overall particulate
collection efficiency at that time was approximately 94 percent
for utility boilers; the particulate emission value in Table 8
23
-------
TABLE 8. ESTIMATED EMISSIONS OF THREE CRITERIA
POLLUTANTS FROM BOILERS, 1975
Sector/fuel
Utility
Coal
Oil
Gas
Industrial/commercial
Coal
Oil
Gas
Total emissions for U.S.a
Emissions, 10 tons/yr
Particulate
matter
1.381
0.08
0.00
0.422
0.11
0.05
16.0
N0x
2.29
1.11
1.00
0.26
0.44
0.43
24.4
S0x
16.31
1.49
0.00
1.69
1.55
0.00
28.5
(U.S. EPA, 1976).
Reflects an assumed control efficiency of 95 percent.
Reflects an assumed control efficiency of 84 percent.
24
-------
reflects an assumed 95 percent average efficiency for 1975. The
value of the EPA estimate for utility particulate emissions in
1975 (3.9 x 10 tons) is significantly different from the value
in Table 8. However the EPA value is based upon NEDS data for
control levels and fuel consumption that are probably less accu-
rate than the more recent reports used in this study. Industrial
and commercial boilers use less sophisticated control equipment
and are less likely to use control devices. Examination of NEDS
data indicates an average of about 84 percent control efficiency
for industrial/commercial boilers. This value was used for the
estimates in Table 8. On this basis, the utility and industrial/
commercial sectors represent about 8.8 and 3.6 percent of the
total nationwide particulate emissions. However, it is probable
that the NEDS data are more complete for larger, well-controlled
boilers and use of these data has probably led to an overestimate
of the nationwide level of control for industrial/commercial
boilers. It is possible therefore that this group would also
account for about 5 to 10 percent of the total nationwide par-
ticulate emissions.
Boiler firing accounted for 5.5 million tons of nitrogen
oxides compared with 24.4 million tons estimated as the total for
1975. Much of this was from coal-fired utility boilers that are
not, at present, effectively controlled. The modest contribution
from industrial and commercial boilers is surprising considering
that they consumed 36 percent of the total boiler fuel burned in
1975. This difference is attributable to lower emission factors
25
-------
for these boilers. For gas-fired boilers which are important
contributors to NC> from all sectors, the NO emission factors
X X
are 700, 175, and 100 lb/106 cu. ft. of gas fired for utility,
industrial, and commercial boilers, respectively. These factors
from AP-42 compare favorably with the previously mentioned test
data on the emissions from industrial boilers. Differences are
generally small except in a few instances where differences of ±
20-25 percent were found. Therefore it appears that industrial
and commercial boilers are modest contributors to the total
emissions of nitrogen oxides compared to utility boilers and
other sources.
The total contribution of sulfur oxides from boilers repre-
sents the dominant portion of the total emissions estimated for
1975 (19.5 million tons out of a total of 28.5 million tons).
Again, the utility contribution is much greater than that of
non-utility boilers. However, the industrial and commercial
emissions do amount to about 10 percent of the total for 1975;
and the impacts associated with low level discharges from small
boilers with short stacks in urban areas may be especially signi-
ficant. Also, the industrial/commercial SO emissions are
Ai
largely attributable to residual oil (about 50 percent). Sulfur
oxides from oil burning may have special significance due to
association with co-contaminants, (see Section 5).
The estimated amounts of hydrocarbons from the national
boiler population are 68,600 tons from the industrial/commercial
sector and 86,000 tons from the utility sector. These quantities
26
-------
are insignificant compared with an estimated nationwide total of
28.9 million tons in 1975. Estimated quantities of carbon mon-
oxide emitted by the boiler population are also insignificant
amounting to only 213,000 tons from the industrial/commercial
sector and 270,000 tons from the utility sector, compared with an
estimated nationwide total of 95 million tons in 1975.
PROJECTED DISCHARGES
Development of definitive projections for overall growth of
a boiler population made up of different types of equipment which
are applied by many industries in different types of services
would be difficult even if equipment and usage patterns were not
poorly defined. Attempts to translate the impact of growth in
boiler population into estimates of future air pollution dis-
charges are further complicated by the need to predict fuel use
patterns of the future. This involves trying to estimate the
impact of legislation, the effect of shifting economics associ-
ated with the price fixing on imported oil, and many other fac-
tors which are beyond the scope of this study. It was considered
important however, to determine whether modest growth in usage
might change the relative importance of the boiler contribution
to pollution levels. For purposes of such projections a 3.7
percent growth rate estimate by PEDCo (Devitt et al, 1979) was
used for industrial and commercial boilers. This estimate as-
sumed (among other things) that boiler fuel consumption would
vary directly with projected increases in total fuel consumption
27
-------
in five industries which consume about 80 percent of the indus-
trial fuel. A 5.2% growth rate for utility boilers (the rate
predicted by FPC for all power generation) was used for coal and
residual oil fired boilers (FPC, 1976b).
Figure 2 illustrates the projected increase, based on this
growth rate, in emissions of SO particulate matter, and NO
X X
from utility and industrial/commercial boilers. As can be seen
from this figure and the values in Table 8, SO emissions from
X
utility coal-fired boilers dominate from a criteria pollutant
perspective.
Because of this dominance and the high level of interest in
controlling SO emissions from utility coal-fired sources, pro-
X
jections of SO emissions were prepared for utility coal-fired
2\
boilers under several different growth and control scenarios.
One set of estimates for SO is shown in Figure 3. The upper
Ji
curve shows the amount of sulfur oxides that would be discharged
from coal-fired power plants if no emission controls were used
beyond those being applied in 1975 (i.e., no control of new
plants). The second highest curve shows the emissions estimated
to occur if current (December 1971) NSPS are met by all new
boilers coming on stream between 1975 and 1990. The next lower
curve shows estimated emissions if all new boilers use flue gas
desulfurization to achieve 90 percent control of sulfur oxides.
The lower curve shows the amount discharged from boilers in
operation in 1975 and continuing to operate in future years
28
-------
c
o
in
22
21
20
19
18
17
16
14
13
11
10
9
8
7
6
5
4
3
2
1
I[UTILITY
ES13 INDUSTRIAL/COMMERCIAL
so.
NO,
SO,
SO,
SO,
1975
1980 1985
YEAR
1990
Figure 2. Projected emissions of participate matter, SO and
x
NO from utility and industrial/commercial boilers.
X
29
-------
40
UNCONTROLLED
c
o
Id
o
X
o
oo
o
oo
•z.
o
I—I
00
oo
35
30
25
20
15
10
CURRENT NSPS
90% CONTROL
EXISTING
BOILERS 1975
NO ADDITIONAL
CONTROL
_L
1975
1980 1985
YEAR
1990
Figure 3, Projected sulfur oxide emissions for
coal-fired power plants.
30
-------
assuming normal retirement rates and no further SO controls
X
applied.
Several important conclusions can be drawn from this figure.
First, there would be a significant increase in SO emissions if
A.
controls were not applied to new units. Second, meeting current
NSPS will keep emissions from increasing significantly. Third,
the benefits possible if more stringent controls are met may be
marginal. Finally, boilers in operation in 1975 are likely to be
significant sources of pollution in 1990 and beyond. It should
be noted that, as indicated earlier, these curves assume a 5.67
percent growth rate for coal fired boilers which is the growth
prediction of the Federal Power Commission for all power genera-
tion (FPC, 1976b). Any change in the assumed rate of growth,
however, will have a significant impact upon the conclusions
drawn above. For instance, under a higher growth rate of about 9
percent, a 90 percent control level for new boilers would be
required to maintain utility SO emissions at the 1975 level.
X
Another consideration in examining future levels of SO
X
emissions from utility sources is the attainment of State Imple-
mentation Plan (SIP) control levels on the boilers in existence
in 1975. Control to the current SIP requirements for SO emis-
X
sion levels is estimated to reduce SO emissions by about 4
X
million tons per year by 1990 (Gibbs et al. 1978). If this
occurs, the current NSPS (December 1971) would be sufficient to
maintain total SO emissions at 1975 levels through the year
X
1990, even assuming a 9 percent growth rate.
31
-------
In summary the most important observations from analysis of
atmospheric emissions of criteria pollutants are as follows:
0 Except for the SO emissions from coal- and oil-fired
units boilers are not a dominant contributor to
national levels of pollution from criteria pollutants.
Their contribution to NO and particulate matter is
quite significant howeverx when compared to other in-
dividual sources.
0 Projections for future air discharges from boilers
(based on a growth estimate which could vary consider-
ably without changing the general conclusions) indicate
that NO and particulate discharges could assume in-
creasing relative importance as the volume from boilers
increases, and that from other important sources such
as motor vehicles are more closely controlled.
0 The greatest threat of increased pollution from SO
emissions comes from the expanded use of coal-firea
utility boilers. Given modest increases in capacity
(5.2%) meeting present standards for new boilers should
keep total annual discharges about where they are now.
A greater rate of increase would require more stringent
standards for either existing or new boilers to prevent
significant increase in total SO discharged.
32
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SECTION 5
ATMOSPHERIC EMISSIONS FROM BOILER OPERATION: TRACE
METALS, POLYCYCLIC ORGANIC MATTER, AND SULFATES
Sulfates, polycyclic organic matter (POM), and trace metal
compounds are air pollutants that are also of great concern in
boiler operations. In addition, the presence of radioactive
elements in coal ash has been reported but there are insufficient
data for determining whether there is cause for concern
(Santhanam, 1978).
Sulfur-bearing coal and residual oil produce sulfates di-
rectly on combustion (primary) or when sulfur oxide emissions are
converted to sulfates in the atmosphere (secondary).* While
there is much that is not understood about mechanisms of forma-
tion and the relative contribution from various sources of sul-
fates to general pollution, it is believed that they represent a
significant environmental problem. Various epidemiological
studies have implicated suspended water soluble sulfates as
respiratory irritants and available toxicological data tend to
*Technigues used to monitor air emissions and ambient air quality
measure sulfates as a composite group of various sulfate
species. The concentration of sulfates measures by these tech-
niques is generally considered a reasonable measure of potential
for adverse environmental impact from this class of compounds.
33
-------
support these implications (Gerstle and Richards, 1976). Exten-
sive toxicological studies are currently underway, and the re-
sults will help to quantify the potential impact of specific
sulfates.
Primary sulfates represent a small percentage of the sulfur
oxides discharged from combustion sources. They range from about
1 to 3 percent for coal-fired sources and from 3 to 12 percent
for oil-fired sources. Primary sulfates can impact directly when
they occur as local pollutants, i.e., as emissions from low level
stacks in urban areas where greater numbers of people would be
affected. Secondary sulfates are considered to be the dominant
factor in "remote pollution" which manifests itself as acid rain
or impaired visibility. They are usually produced from the
combustion of coal and oil in boilers. The potential for envir-
onmental impact of sulfates from boilers can vary significantly
with the type of boiler, its mode of operation, fuel composition,
and other variables.
Information on the possible role of boiler-related factors
in sulfate production was presented recently (Ando, 1978). Data
presented in this report show that reductions of SO emissions in
J^.
Japan have resulted in a corresponding drop in ambient concentra-
tions of sulfates. This is contrary to U.S. experience where
substantial reductions in SO concentrations have been accompa-
X
nied by very small decreases, if any, in sulfate concentrations.
Part of the reason for this difference is attributed to lower
34
-------
direct sulfate emissions from Japanese boilers. The factors
cited as causative are as follows:
0 In the United States many oil-fired boilers, (which
produce more sulfate than coal-fired boilers) were
installed in the last 15 years.
0 Very few oil-fired boilers in the United States are
equipped with electrostatic precipitators. In Japan
electrostatic precipitators with ammonia injection for
control of corrosion are used. The ammonia reacts with
SO3 and much of the resulting sulfate is collected in
the precipitator.
0 Oxidation catalysts which are used in the United
States, but not in Japan, may promote sulfate formation
in the boiler.
0 Unspecified work to reduce NO emissions from utility
boilers in Japan, which is n^t being applied in the
United States, are felt to contribute to reductions in
sulfate emissions.
The author goes on to suggest that the success in control of
SO and sulfates from large boilers may not be a complete solu-
X
tion. Japan (like the United States) has many small oil-fired
boilers which have neither electrostatic precipitators nor good
combustion control, and can emit sulfates at low levels in urban
areas.
Some further conclusions regarding the relationship between
boiler variables and sulfate emissions were reported in a recent
workshop (EPA, 1978). Studies suggested that sulfate emissions
from oil-burning sources are 3 to 10 times greater than from
sources burning coal with an equivalent sulfur content. It is
believed that the higher flame temperatures, the vanadium and
nickel content, and the lack of particulate control devices for
35
-------
oil-firing contribute significantly to the observed sulfate
emissions (Homolya, 1978). In addition, a number of studies
demonstrated that available boiler oxygen in excess of stoichio-
metric will enhance sulfate formation (Homolya, 1978).
The estimated amounts of oil (mostly residual) burned in
12
U.S. utilities is equivalent to about 2700 x 10 Btu/yr while
oil burned in industrial and commercial boilers is equivalent to
12
about 2900 x 10 Btu/yr, 60 percent of which is residual oil.
Much of the combustion in industrial and commercial boilers is
likely to be poorly controlled for conditions such as excess air.
If we are to continue to burn large amounts of oil it appears
that more effective control of both large and small oil-fired
boilers would be necessary for effective reduction of the expo-
sure of the U.S. population to sulfates.
Polycyclic organic matter (POM) has been defined most simply
as all organic matter with two or more benzene rings. Discharges
of this class of compounds have been considered potentially
hazardous in that many are toxic and some are known carcinogens.
POM concentrations are frequently used as an index of the poten-
tial for adverse environmental impact of organic air emissions.
Incomplete combustion, natural or man-made is accepted as the
primary source of POM in the environment. Very little is known
however, about the relative contribution of various sources to
the total volume of POM discharged to the environment and the
data for estimation of the relative impact of the individual
36
-------
compounds are very sparse. Quantitative information about sta-
tionary sources is mainly limited to that developed for dis-
charges of benzo(a)pyrene (BaP) that were reported some years ago
(Hangebrauck et al., 1967).
It is believed, however, that both mobile and stationary
sources of combustion make significant contributions to high POM
levels in urban areas. While some sources such as coke ovens are
especially suspect as a significant contributor to high ambient
concentrations, other stationary sources such as boilers are also
believed to be significant sources. Two interrelated boiler
characteristics have a great effect on the amounts of POM gen-
erated: type of fuel and combustion efficiency. In general more
POM would be expected from burning of coal or oil than from gas.
And larger boilers operated continuously under well-controlled
conditions would produce less POM. Small boilers which are
generally used in applications where loosely controlled operation
and poor maintenance are much more common, can emit much larger
quantities of POM per unit of fuel burned.
The relationship between fuel type, boiler efficiency and
POM discharges is illustrated by data from the Hangebrauck study
shown in Table 9. For the units burning coal, those units which
would be expected to have lowest combustion efficiency have by
far the largest emissions of POM. These data also show average
values for gas and oil furnaces which suggest that oil- and
gas-firing will produce less BaP than coal firing. It must be
considered, however, that these data represent results of a very
37
-------
TABLE 9. RELATIVE BaP EMISSION RATES FROM
STATIONARY FUEL COMBUSTION SOURCES
(Hangebrauck et al, 1967)
Fuel
Coal
Oil
Natural gas
Source
Residential - hand stoked
Residential - underfeed
Commercial
Industrial
Utility
Estimated BaP
emission rate
((jg/106 Btu)
1,400,000
44,000
5,000
2,700
90
200
100
-------
old screening study which did not provide final answers relative
, )
to potential impacts of discharges from the units tested. The
test data are insufficient to justify a conclusion that gas- and
oil-fired units are not significant contributors to POM pollu-
tion.
These general conclusions and the small amount of data
available suggest that the fuel burned in utility boilers (about
12
12,000 x 10 Btu/yr for coal and oil) would produce less POM
than similar fuels burned in industrial and commercial boilers
(about 4000 x 10 Btu/ yr). Furthermore the small industrial
and commercial boilers burning coal and oil are located mostly in
urban areas and emit POM at low elevations from a very large
number of sources. These sources could impact much more on human
health than the larger more remote sources.
Many of the metal ions present in coal and oil (such as
arsenic, cadmium, and mercury) have potential for being emitted
as toxic compounds but there is very little information available
to establish whether they, in fact, are. Some metals (vanadium
and nickel) have potential for catalyzing undesirable atmospheric
transformations such as the conversion of sulfur . dioxide to
sulfates. While there is some evidence to suggest that this is
occurring, data are not available to establish the seriousness of
the resulting environmental impact. It appears, however, that
trace metal compounds from fossil fuel combustion could prove to
be a problem in the future. If so, boiler fuel consumption could
be expected to play a prominent role.
39
-------
Trace metal compounds associated with fossil fuels vary
widely in kind and amount. While trace elements in coal have
been studied intensively, it is still difficult to generalize
relative to their occurrence (Mezey et al. , 1976). This is
demonstrated by Table 10 which shows data for 101 coals of the
U.S. Data for trace elements from oil are less plentiful but
that which are available suggest that crude oils are equally
variable as far as composition is concerned. Table 11 shows data
for 24 crude oils. It should be noted that these values (except
for those shown for copper, nickel, uranium and vanadium) are
shown only as percent in ash from crude oil. They are intended
mainly to show variability- It is worth noting also that vana-
dium and nickel can be expected to occur in some amount in all
crudes and may be present in amounts which will produce high
concentrations when it is concentrated in the residual oil. This
can be illustrated by considering that vanadium which can be
present in crude oil in amounts up to 100 ppm may be concentrated
in residual oil by a factor of 5 to 10 or more by the refining
process.
These data and fuel consumption data suggest that trace
metal emissions from coal combustion in boilers are primarily
1 ?
from utility boiler consumption (about 9000 x 10 Btu/yr) rather
12
than industrial and commercial boilers (about 1000 x 10
Btu/yr). Whether the environmental impacts from many small, less
efficient boilers burning lesser amounts of fuel but discharging
emissions at low levels outweigh those from a much smaller number
40
-------
TABLE 10. MEAN ANALYTICAL VALUES FOR 101 COALS
(Ruch et al, 1974)
Constituent
As
Be
Cd
Cr
F
Hg
Ni
Pb
V
Zn
Mean
14.02
1.61
2.52
13.75
60.94
0.20
21.07
34.78
32.71
272.29
Unit
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
Standard
deviation
17.70
0.82
7.60
7.26
20.99
0.20
12.35
43.69
12.03
694.23
MIN
0.50
0.20
0.10
4.00
25.00
0.02
3.00
4.00
11.00
6.00
MAX
93.00
4.00
65.00
54.00
143.00
1.60
80.00
218.00
78.00
5350.00
41
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TABLE 11. DISTRIBUTION OF 28 TRACE METALS
ASHES OF 24 CRUDE OILS
(Mezey et al, 1976)
IN
Metal
Occurrence in
percent of
samples
Concentration, >
range in ash,* '
percent
Concentration range' '
Percent of ash ppm in crude
Al
Fe
Ti
Mn
Ca
Mg
Na
K
Ag
As
B
Ba
Ce
Co
Cr
Cu
Ga
La
Mo
Nd
Ni
Pb
Sr.
Sr
V
Zn
Zr
U
100
100
50
96
100
100
88
8
17
21
17
100
33
100
100
100
67
38
83
8
100
96
38
92
100
58
33
100
0.001. - 10
0.01 - >10
0.001 - 1.0
0.001 - 1.0
0.01 - >10
0.1 - 10
0.1 - >10
1-10
0.1 - 1
0.001 - 1
0.001 - 1
0.001 - 1
0.01 - 1
0.001 - 1
0.001 - 0.1
0.001 - >10
0.0001 - 0.01
0.001 - 1
0.001 - 1
0.1 - 1
0.01 - >10
0.001 - 1.0
0.001 - 1.0
0.0001 - 1.0
0.001 - >10
0.01 - 10
0.001 -. 1.0
0.0001 - 0.01
13 - 0.007 1.7 - 0.03
16 - 0.1 35 - 0.03
46 • 0.41 106 - 0.002
0.0075-0.001 0.013-0.00012
(a) Semiquantitative values.
(b) Quantitative values.
42
-------
of large boilers whose emissions will be widely dispersed is open
to question. The same factors must be considered in weighing the
relative impacts from utility and non-utility boilers burning
residual oil. It would appear that the roughly equivalent con-
sumption figures for the different sectors would make the non-
utility boiler impact more significant as far as any adverse
effects might be concerned.
Important points from the analysis of information on these
air pollutants from boilers are as follows:
0 Data needed for assessment of potentially hazardous
impacts from boiler associated sulfates, POM, and trace
metal compounds are very sparse and inconclusive.
0 Burning of residual oil in small boilers may be pro-
ducing potentially hazardous discharges of sulfates,
POM, and trace metal compounds.
0 Burning of distillate oil may be producing potentially
hazardous discharges of sulfates and POM.
43
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SECTION 6
WATER POLLUTION AND SOLID WASTE
DISCHARGES FROM BOILER OPERATION
For practical purposes the problems of water pollution
associated with boiler operation are limited to wastewater from
large watertube boilers. Cast iron and firetube boilers being
used mainly for space heating do not require cooling water which
is the main source of wastewater from boilers. Solid waste
disposal problems involve ash, and in some situations, sludge
from SO~ scrubbing systems. Ash is a significant problem only
for coal-fired watertube boilers. Scrubber sludge can result
from control of watertube boilers burning either coal or residual
oil. Only a few cast iron and firetube boilers burn coal and in
small amounts so that dry collection and landfill disposal of ash
presents no significant problem. Since S02 control is not prac-
ticed for boilers in these categories no sludge is produced.
Boilers in the utility and industrial sector are the only
ones for which wastewater and solid waste is a serious consider-
ation. The handling of waste disposal and water management
practices are not well defined for the industrial sector but it
is generally assumed that conventions and procedures used' by
utilities are being applied (GCA, 1976).
44
-------
Utility boilers, because of their size and number, have con-
siderable potential for environmental impact from discharges of
wastewater, ash or scrubber sludges. As a result they have been
the subject of numerous assessment studies. While these problems
are generally felt to be managable using presently available
control technology, some discussion to illustrate the nature of
the problems to be dealt with seems appropriate.
The main sources of wastewater are cooling water systems,
ash disposal systems, and boiler feedwater treatment systems.
These discharges are continuous during boiler operation. Other
discharges of wastewater occur on an intermittent basis from such
sources as boiler blowdown, boiler cleaning systems, and runoff
from coal storage piles. Another potential source of wastewater
effluent is wet scrubber flue gas cleaning systems.
The most significant of these sources is the effluent from
cooling water systems. These effluents are potential causes of
thermal pollution, stream depletion, and contamination from water
treatment additives. Where cooling towers are used, the blowdown
discharge contains dissolved and suspended solids and contami-
nants such as corrosion inhibitors and algicides.
The wastewater from ash handling systems can contain sig-
nificant quantities of dissolved and suspended solids and poten-
tially hazardous materials (cadmium, arsenic, and lead). Seepage
and leaching from ash sedimentation basins are potential sources
of ground water pollution unless the basins are controlled with
proper lining materials.
45
-------
The quantities of wastewater from boiler blowdown, boiler
cleaning operations, water treatment systems and coal pile runoff
are insignificant compared with cooling water discharges and ash
handling discharges. However, these sources are potential con-
tributors to hazardous material discharges such as PCB, nickel,
zinc, antimony, low or high pH water, and many others. These
streams are usually treated to reduce effluents to acceptable
levels.
Table 12 presents the estimated quantities of wastewater
from utility plants in 1973 (GCA, 1976). These data indicate the
relative importance of different sources.
Ash produced by coal-fired power plants is a function of ash
content of the coal which can vary from about 8 to 15 percent.
The average for utility coal was 13.4 percent in 1975 (FPC,
1976). Coal-fired boilers generated an estimated 64 million tons
of ash in 1975. Of this total about 30.4 million tons was
emitted as fly ash (47.5%) while the rest was produced as bottom
ash. Utility coal-fired boilers account for over 90 percent of
the total ash generated. Although a large percentage is emitted
as fly ash, utility plants have very efficient fly ash control
devices (95% average collection efficiency). Of the total fly
ash emitted, an estimated 28.9 million tons are collected by
control equipment and must be disposed of.
Disposal methods include land filling and ash settling
ponds. In addition, approximately 20 to 25 percent of the bottom
46
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TABLE 12. UTILITY WASTEWATER DISCHARGES'
Waste stream
Ash handling
Cooling
Once -through
Recirculated
Fuel handling
Boiler feed water
Treatment
Boiler blowdown
Equipment cleaning
Total
Flow quantity
(109 gal/yr)
280
49,000
5,300
7.9
9.0
6.6
2.2
54,605.7
Data from Table 23 in reference (GCA, 1976).
47
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ash (7 to 8 million tons) is recycled for use as road-base aggre-
gate, for use as aggregate in concrete block production, and for
application to icy roadways (National Ash Association, 1978).
The major potential environmental impacts of disposal of ash
from boiler operation is contamination of water and soil by
leaching and runoff. Significant quantities of potentially
hazardous materials including trace metal compounds, can be
carried in thes3 discharges.
Sludges are now being produced in relatively small quanti-
ties by scrubbing systems which utilize lime or limestone to
collect SO from flue gases. Table 13 shows estimates from a
.X
study assessing the impact of burning more coal as indicated in
the National Energy Plan. Projections for fuel consumption and
degree of application of flue gas desulfurization (FGD) are based
on predictions by the Department of Energy under the National
Energy Plan (Santhanam, et al. 1978). Such projections are
necessarily very uncertain. The rate at which coal use will
expand and FGD will be applied are debatable. These data do
indicate, however, what the magnitude of the disposal problem may
be for the two materials and show the general relationship be-
tween the quantity of the two materials that would be generated.
In summary, the most important considerations relating to
wastewater and solid waste generated by boilers are:
0 Solid waste and wastewater are produced in significant
quantities only by large watertube boilers burning coal
or residual oil. Coal burning utility boilers are the
dominant contributor.
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TABLE 13. PROJECTED ASH AND FGD SLUDGE GENERATION FOR
COAL-FIRED BOILERS LARGER THAN 250 X 1Q6 Btu/ha
Industrial boilers
Coal ash
FGD sludge
Utility boilers
Coal ash
FGD sludge
Total
Coal ash
FGD sludge
3
Ash and sludge, 10 tons
1975
5,600
0
59,800
6,800
65,400
6,800
1985
18,987
6,500
72,947
26,100
91,934
32,600
2000
43,518
23,100
85,842
34,600
129,360
57,700
a 1975 estimates are derived from data in (Devitt et al., 1978).
Projections for 1985 and 2000 are from (Santhanam et al., 1978)
49
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Wastewater and solid waste are produced by utility
boilers in amounts that are comparable to the amounts
produced in other major industries of the United
States.
Presently available control technology is adequate to
dispose of both wastewater and solid waste from boilers
in environmentally sound ways.
The cost of pollution control is a function of strin-
gency of control. The scale of the operations involv-
ing boilers is such that levels of control, which are
set pursuant to the many laws that apply, can have
significant impact on the national cost for environ-
ment? 1 protection.
50
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SECTION 7
CONCLUSIONS AND RECOMMENDATIONS
The present study has developed data that provide new in-
sights into the contribution of boiler operation to levels of
pollution in the United States. The findings suggest that new
activities could be undertaken to better protect against present
and future pollution. The activities that are suggested fall
into the following four categories:
1. Additional information should be collected to fill gaps
in the data base describing the boiler population of
the United States. This information could be used to
confirm and expand on conclusions in this study.
2. Sampling and analysis to better characterize air emis-
sions (especially those of noncriteria pollutants such
as sulfates, unburned hydrocarbons, and trace metal
compounds) is needed for a number of different types of
boilers.
3. Information needed to understand past and future
changes in boiler fuel consumption patterns should be
collected so that potential adverse environmental
impacts associated with fuel switching can be ade-
quately understood.
4. A research and development program should be initiated
to address potential environmental problems which have
been identified for industrial and commercial boilers.
These four areas of recommended activity are discussed in further
detail below.
51
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COLLECT ADDITIONAL DATA ON BOILER POPULATION
Data now available are not adequate for clear definition of
all factors that are needed to assess the environmental impacts
associated with boiler operation, e.g., the relationship between
type of boiler and type of service (space heating, process steam,
etc.) is not well established. Also, background on average
boiler age and typical use factors is incomplete. The main
sources of information on boiler operation are the National
Emissions Data System (NEDS) of the U.S. Environmental Protection
Agency, the Major Fuel Burning Installation Survey (MFBI) con-
ducted by the Department of Energy in 1975, and the Census of
Manufacturers of the Department of Commerce which gives data on
energy consumption. All sources of information have known de-
ficiencies that have never been thoroughly evaluated. Since
boiler firing consumes more fossil fuel than any other activity
(including transportation), efforts to clear up ambiguities in
the data base would be worthwhile. Specific activities that
could be undertaken to build a more reliable data base include
the following:
0 Make further .detailed cross comparisons between data
available from NEDS, MFBI, and the present study to
establish the reliability of data from the different
sources.
0 Contact boiler manufacturers and major users of boilers
in industrial and commercial service to collect in-
formation on operating and maintenance practices.
0 Consult state agencies, insurance companies, and other
groups that are concerned with boiler safety to deter-
mine whether data are available to cross check informa-
tion from other sources.
52
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0 Work with the American Boiler Manufacturers Association
(ABMA) to develop a questionnaire to obtain information
needed to fully define the boiler population.
MEASUREMENT OF AIR EMISSIONS
Better data are needed for emissions from all types of
boilers. Information on pollutants including direct sulfates,
polycyclic organic materials and trace metals is very limited.
Several types of boilers appear to need full characterization
from the standpoint of air pollutants emissions.
Cast iron and firetube boilers burning distillate oil need
to be tested to determine whether poorly maintained commercial
and institutional boilers with cyclic and intermittent operation
are producing potentially hazardous emissions of unburned hydro-
carbons and sulfates.
Cast iron and firetube boilers burning residual oil in com-
mercial service should be characterized giving special attention
to unburned hydrocarbons, sulfates, and trace metal emissions.
Stoker-fed coal-fired watertube boilers with capacities in
the neighborhood of 25 to 50 x 10 Btu/h should be characterized
to determine whether a shift to coal from natural gas and oil
would increase potential air pollution in small watertube
boilers.
FACTORS INFLUENCING FUEL USE PATTERNS
Future fuel use patterns are of obvious importance to poten-
tial pollution from boiler operation, e.g., it is important to
53
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know whether the use of petroleum based fuels will continue
despite efforts to increase coal consumption. Oil burning might
continue because production of petroleum fuels is tied to in-
creasing amounts of gasoline consumption or because coal-burning
hardware capable of meeting present needs is not available. Also
it is important to know more about waste materials being used as
boiler fuels. Increasing fuel cost, coupled with increasing
difficulty in disposal of materials which are potentially harmful
to the environment, is resulting in more burning of materials
whose impact on air quality is not understood. At present our
understanding of the needs served by boilers and the hardware
available is very sketchy except for large watertube boilers. In
addition, information on where boilers fit into the overall
energy picture is out of date. While the Department of Energy is
responsible for generating information on energy use patterns,
the U.S. Environmental Protection Agency may need to insure that
it has the data base to anticipate future energy related environ-
mental impacts.
FUTURE RESEARCH AND DEVELOPMENT NEEDS
Collection of data of the type described above would permit
a more definitive assessment of research and development needs.
Some specific projects are, however, apparent from background
developed during the present study.
It appears that a low-pollution coal burning boiler is
required in the capacity range of 25 to 50 x 105 Btu/h. The
54
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capability for building such a system with available technology
needs to be investigated.
High efficiency burners for combustion of oil in small
c
boilers (less than 10 x 10 Btu/h) would contribute substantially
to minimizing potential for environmental impact from boiler
operation. The applicability of catalytic combustion for high
efficiency and minimum NO production appears to be worthy of
<&
investigation.
Methods for clean combustion of residual oil appear to be
needed. Large amounts are now being burned in a great number of
small boilers where the impact of the pollutants produced on the
populace is at a maximum. There is a need for more effective
means of utilizing petroleum residues which will be with us as
long as gasoline is used.
Methods are needed for minimizing the potential pollutants
input with the coal fed to small boilers, not amenable to control
by other methods. Also, evaluation of the applicability of
gasification to produce industrial boiler fuels appears to be
needed.
The potential for substitution of electric-boilers for those
now burning fossil fuels directly, needs to be investigated.
Also, the ability to substitute heat pumps for boilers now being
used for space heat should be evaluated. Use of electricity from
well-controlled central generating stations would minimize pollu-
tion from direct combustion in smaller combustion units.
55
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REFERENCES
Ando, J. 1978. SO9 Abatement for Stationary Sources in Japan.
U.S. Environmental Protection Agency. Office of Research
and Development. Washington, D.C.
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.
Department of Energy. 1975. Major Fuel Burning Installation
Data File, Washington, D.C.
Devitt, T.W., and L. Gibbs. 1979. Background Study in Support
of New Source Performance Standards for Industrial Boilers.
PEDCo Environmental, Inc. Cincinnati, Ohio.
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.
Federal Power Commission. 1976a. Annual Summary of Cost and
Quality of Steam Electric Plant Fuels, 1975. Washington,
D.C.
Federal Power Commission. 1976b. Report on Electric Utility
Expansion Plans, 1986-1995. Washington, D.C.
GCA, Inc. 1976. Preliminary Assessment of Conventional Sta-
tionary Combustion Systems. Research Triangle Park, North
Carolina.
56
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Gibbs, L., D.S. Forste, and D.A. Paul. 1978. Sulfur Dioxide
Emissions from Utility Coal-fired Boilers and Economics of
Control Through 1990. PEDCo Environmental, Inc. Cincin-
nati, Ohio.
Gerstle, R.W., and J. Richards. 1976. Stationary Source Control
Aspects of Ambient Sulfates: A Data-Base Assessment. PEDCo
Environmental, Inc. Cincinnati, Ohio.
Hangebrauck, R.P., D.J. von Lehmden, and J.E. Meeker. 1967.
Sources of polynuclear hydrocarbons in the atmosphere. PHS
Publ. No. 999-AP-33. Washington, D.C.
Homolya, James B., and James L. Cheney. 1978. An Assessment of
Sulfuric Acid and Sulfate Emissions from the Combustion of
Fossil Fuels. U.S. Environmental Protection Agency, Envi-
ronmental Services Research Laboratory, Research Triangle
Park, North Carolina.
Locklin, D.W., H.H. Krause, A.A. Putnam, E.L. Kropp, W.T. Reed,
and M.A. Duffy. 1974. Design Trends and Operating Problems
in Combustion Modification of Industrial Boilers. Battelle-
Columbus Laboratories, Columbus, Ohio.
Mezey, E.J., Surjit Singh, and D.W. Hinoy. 1976. Fuel Contami-
nants, Volume 1. Chemistry. Battelle-Columbus Labora-
tories, Columbus, Ohio.
National Ash Association. 1978. Ash at Work. Volume X, No. 4.
Washington, D.C.
PEDCo Environmental, Inc. 1976. Air Pollution Control Compli-
ance Analysis Report on Fossil Fuel-Fired Steam Electric
Power Plants. EPA 68-02-1355. Cincinnati, Ohio.
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.
Ruch, R.R., Gluskoter, H.J., and Shimp, N.F. 1974. "Occurence
and Distribution of Potentially Volatile Trace Elements in
Coal", Final Report, Environmental Geology Note, No. 72,
Illinois State Geological Survey.
Santhanam, C.J. et al. 1978. Health and Environmental Impacts
of Increased Generation of Coal Ash and FGD Sludges. Arthur
D. Little, Inc., Cambridge, Massachusetts.
Stanford Research Institute. 1972. Patterns of Energy Consump-
tion in the United States. Washington, D.C.
57
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U.S. Environmental Protection Agency. 1977. Compilation of Air
Pollutant Emission Factors, AP-42, Second Edition.
U.S. Environmental Protection Agency. 1976. National Air
Quality and Emissions Trends Report, 1976. Office of Air
and Waste Management. Research Triangle Park, North
Carolina.
U.S. Environmental Protection Agency, 1978. Workshop Proceedings
on Primary Sulfate Emissions from Combustion Sources, Envi-
ronmental Sciences Research Laboratory. Research Triangle
Park, North Carolina.
58
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing/
1. REPORT NO.
EPA-600/7-79-233
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Overview of Pollution from Combustion of Fossil Fuels
in Boilers of the United States
5. REPORT DATE
Oc tober 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
P.W. Spaite (Consultant) and T.W. Devitt
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
F.HF,fi?4A
11. CONTRACT/GRANT NO.
68-02-2603, Task No. 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 PERIOD COVERED
Final: 1/79 - 6/79
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 the fossil-fuel-fired boiler population of the U.S.
It presents data on the number and capacity of boilers for categories most relevant
to producing pollution. Information presented includes: type of fuel burned (coal,
residual oil, distillate oil, natural gas); usage sector (utility, industrial, commer-
cial); size category (less than 25 million Btu/hr, 25-250 million Btu/hr, greater
than 250 million Btu/hr); and heat transfer configuration (water tube, fire tube,
cast iron). Fuel consumption data are presented for each type of fuel burned in
each usage sector. These data are used to estimate the amount of sulfur oxide,
nitrogen oxide, and particulate air emissions produced by boiler operation. Other
air pollutants are discussed qualitatively. Solid waste and water pollution from
boiler operation is discussed generally.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDEDTERMS
c. COSATI Field/Group
Pollution
Fossil Fuels
Combustion
Boilers
Fuel Consumption
Sulfur Oxides
Nitrogen Oxides
Dust
Aerosols
Pollution Control
Stationary Sources
Particulate
13B
2 ID
21B
13A
2 IK
07B
11G
07D
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
65
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
59
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