EPA-600/2-76-046a
March 1976
Environmental Protection Technology Series
PRELIMINARY EMISSIONS ASSESSMENT OF
CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
Volume I • Executive Summary
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
-------
RESEARCH REPORTING SERIES
Research reports.of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/2-76-046a
March 1976
PRELIMINARY EMISSIONS ASSESSMENT OF
CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
VOLUME I--EXECUTIVE SUMMARY
Norman Surprenant, Robert Hall,
and Leonard M. Seale
GCA/Technology Division
GCA Corporation
Bedford, Massachusetts 01730
Contract No. 68-02-1316, Task 11
ROAP No. AAU-002
Program Element No. EHB525
EPA Project Officer: Ronald A. Venezia
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
-------
ABSTRACT
This document is an executive summary of a preliminary emissions assess-
ment of the air, water, and solid waste pollutants produced by conven-
tional stationary combustion systems. Results are summarized for the
follov/ing four principal categories of such systems: Utilities - electric
generation; Industrial - steam generation, space heating and stationary
engines; Commercial/Institutional - space heating and stationary engines;
and Residential - space heating. Process types and operating efficiencies,
fuel consumption, pollutant sources and characteristics, major research
and development trends, fuel consumption trends, and technical areas where
emission data are incomplete are summarized for each principal combustion
system category. A uniform combustion source classification system was
developed and the pollutant emissions from applicable unit operations are
summarized for each of 56 source classifications.
This report was submitted in fulfillment of Contract 68-02-1316, Task
Order No. 11, by the GCA/Technology Division under the sponsorship of
the Environmental Protection Agency. Work was completed as of
7 November 1975.
ill
-------
CONTENTS
Section
I Introduction and Summary 1
Program Overview 1
Emission Summaries 4
Conclusions 11
II Electric Utility Combustion Systems 16
Size of Industry, Sources of Energy, Fuel Consumption 16
Population and Characteristics of Combustion Equipment 21
Coal-Fired Boilers . , 21
Oil- and Gas-Fired Boilers 25
Internal Combustion 27
Solid Waste-Fired Boilers 28
Emission Sources 29
Air Emissions 31
Water Effluents 36
Solid Waste Generation 40
III Industrial Combustion Systems . 44
Fuel Consumption 44
Population and Characteristics of Combustion
Equipment 44
iv
-------
CONTENTS (continued)
Section Page
Emissions 45
Air Emissions 45
Water Emissions 51
Solid Waste 52
IV Commercial/Institutional Combustion Systems 53
V Residential Combustion Systems 59
VI Trends in Fuel Consumption and Combustion System Design 65
Fuel Consumption 65
Combustion Systems 67
VII On-Going and Planned Research Activities 69
VIII References 72
Appendixes
A Metric Conversions 73
B Acronyms Used in This Report 76
-------
FIGURES
No.
1 Geographical Distribution - Electric Utility Fuel
Consumption - 1973 19
2 Geographical Distribution - Electric Utility Coal
Consumption - 1973 20
3 Emission Sources Coal-Fired Steam-Electric Power Plants 30
4 Water Flows for a Typical 1000 MW Power Plant at Full
Load. 37
vi
-------
TABLES
No.
1 Fuel Consumption, Conventional Stationary Combustion
Systems 5
2 Major Emissions From Conventional Stationary Combustion
Sys terns 6
3 Magnitude of Air Emissions From Conventional Stationary
Combustion Sources Compared to All Man Made and Natural
Emissions in the U.S. 9
4 Trace Element Air Emissions: Percent of Total From Con-
ventional Stationary Combustion System Categories 10
5 Trace Elements in Solid Waste (Ash): Percent of Total
Generated by Conventional Stationary Combustion System
Categories 12
6 Utility Fossil-Fueled Electricity Production - Source of
Energy, Percent ' 17
7 Electric Utility System Fuel Consumption, 1974 22
8 Summary: Coal-Fired Utility Boilers - 1972 23
9 Distribution (%) of Fuel Consumption by Firing Patterns
and Size of Utility External Combustion Boilers Using
Oil and Gas, 1972 26
10 Applicability of Unit Operation and Process to Air,
Water, and Solid Waste Pollutants 29
11 Stack Emissions From the Generation of Electricity by
External Combustion 32
12 Important Aspects of Water Wastes 38
13 Ash Handling Emissions: Electric Utilities, 1974 41
14 Ash Trace Elements: Electric Utilities, 1974 43
vii
-------
TABLES (continued)
No' Page
15 Number and Size of Industrial Boilers, 1973 45
16 Industrial Boiler Capacity and Fuel Consumption by Com-
bustion System, 1973 46
17 Flue Gas Emissions From Industrial External Combustion,
1973 47
18 Commercial/Institutional Fossil Fuel Consumption - 1973 54
19 Flue Gas Emissions From Commercial/Institutional External
Combustion, 1973 55
20 Residential Fuel Use, 1973 59
21 Flue Gas Emissions From Residential Combustion, 1973 61
22 Fuel Consumption Trends, Stationary Combustion Sources 66
23 Electric Utility Fuel Consumption Trends to 1985 by
Combustion System Type 68
viii
-------
ACKNOWLEDGMENTS
The authors acknowledge the technical guidance of the following Environ-
mental Protection Agency personnel: Dr. Ronald Venezia, U.S. Environ-
mental Protection Agency (EPA), Industrial Environmental Research Labora-
tory, Research Triangle Park, North Carolina; Mr. Dennis Canon, Environ-
mental Protection Agency, Environmental Research Laboratory, Corvallis,
Oregon; Mr. Clyde J. Dial, Mr. Victor Jelen and Mr. Guy Nelson, Environ-
mental Protection Agency, Industrial Environmental Research Laboratory,
Cincinnati, Ohio; and Mr. Don Gilmore, Environmental Protection Agency,
Environmental Monitoring and Support Laboratories, Las Vegas, Nevada. In
addition, the authors acknowledge the contributions of the following GCA/
Technology Division staff members who participated in the analyses on
which this report is based: Dr. Steven Slater, Dr. Martin Sussman,
Dr. Donald Durocher, Mr. Charles Young, Mr. Lawrence Gordon, Mr. Robert
Engelman, Ms. Martha Fabuss, and Mr. Thomas Susa.
ix
-------
SECTION I
INTRODUCTION AND SUMMARY
PROGRAM OVERVIEW
The emission of pollutants to air and water and the generation of solid
waste by conventional stationary combustion systems were assessed in
this program. The assessment was confined to emissions resulting from
operations and processes at the combustion site and did not include remote
effects such as those arising from mining and transportation.
Four principal categories of conventional stationary combustion systems
were considered:
o Utilities - electric generation
« Industrial - steam generation, space heating, and
stationary engines (direct heating and
chemical conversion were excluded)
• Commercial/Institutional - space heating and stationary engines
9 Residential - space heating
The principal combustion categories were further divided into subcategories
according to a classification scheme based on fuel type, combustion unit
type, firing technique, thermal rate, fly ash reinjection and application
of control measures or devices. A total of 56 of the combustion system
subcategories were selected for emphasis in the contract investigations.
These systems were chosen for study because preliminary analyses indi-
cated they were the largest systems included in the classification system.
-------
Emission estimates for these selected systems were calculated and pre-
sented, on a unit operations basis, in a series of emission summary
tables. The data presented in the emission summary tables deal with
national averages or ranges based on the best available information.
While national figures cannot be related to individual plants, they do
indicate the relative importance of various emission streams.
The major unit operations or processes that were utilized as the basis
for summarizing air and water emissions and solid waste were:
*
• Flue gas emissions
« Ash handling
• Cooling systems
• Water treatment
• Fuel handling
» Flue gas desulfurization
The major pollutants for which emission estimates were derived were:
» Air: Particulates
Sulfur oxides (SOX)
Nitrogen oxides (NOX)
Hydrocarbons (HC)
Carbon monoxide (CO)
Trace elements (28 elements)
Benzene soluble organics (BSO)
Particulate polycyclic organic matter (PPOM)
Benzo(a)pyrenes (BaP)
Polyhalogenated hydrocarbons (PHH)
Polychlorinated biphenyls (PCB)
Polybrominated biphenyls (PBB)
Tladioactive elements
« Water: Total solids (TS)
Suspended solids (TSS)
Dissolved solids (TDS)
pH
Trace elements
A list of acronyms used in this report is provided in Appendix B.
-------
Solid: Bottom ash
Fly ash
Desulfurization solids
Trace elements
The emission estimates presented in the emission summary tables were
based on a survey of data existing in the literature and information sup-
plied through contact with members of industrial, governmental, and aca-
demic laboratories. A major use of these estimates will be to develop
a preliminary priority ranking of the selected combustion systems based
on the total emissions of these systems for the pollutants noted above.
To assist in the development of the priority ranking, fuel consumption and
composition data, by state and/or region, and by the four principal com-
bustion categories, were developed.
In addition to providing estimates of emissions from conventional sta-
tionary combustion sources, the contract effort involved development of
the following data:
e State-of-the-art developments in combustion technology
with respect to efficiency and pollutant generation.
• The number, type, location and size of the combustion
systems within the United States based upon'the selected
combustion classification system.
• Trends in fuel consumption and boiler design and their
impact on emissions.
• The extent and quality of available emission data.
• Identification of the major gaps in available pollu-
tant data with respect to: types of combustion sys-
tems, unit operations within combustion systems, fuel
composition and other parameters which can affect the
composition and quantity of pollutant emissions.
*
This priority ranking activity is being conducted for the EPA, Industrial
Environmental Research Laboratory, by Monsanto Research Corporation, Dayton,
Ohio, under Contract 68-02-1404, Task Order No. 18.
-------
• Identification of current and planned activities as-
sociated with emissions from conventional stationary
combustion sources.
These data were deemed to be essential for a comprehensive assessment of
the environmental impact of conventional combustion systems. Although
the work described in this report is only a first step toward obtaining
the information necessary for such an overall assessment, it enumerates
the major gaps in the data base and allows decisions to be made concern-
ing the additional work required to fill the data base gaps.
EMISSION SUMMARIES
The following discussion summarizes the contribution of the combustion
sources to total national emissions and also provides an overview of the
relative contributions of each of the four principal combustion system
categories.
Fuel consumption by the principal categories of combustion sources is showt
in Table 1. Coal was estimated to account for 26 percent of the combustion
released energy generated, but produced 90 percent of the particulate, 75
percent of the SO , 50 percent of the NO , and approximately 80 percent of
-------
Table 1. FUEL CONSUMPTION, CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
(1012 Btu/year)a
External combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum
Residual
Distillate
Natural gas
Internal combustion
Distillate oil
Natural gas
Total
Utilities
(1974)
14,798
8,502
8,264
38
200
3,039
2,901
138
3,257
589
312
277
15,387b
Industrial
(1973)
8,540
1,370
1,320
10
40
1,700
1,270
430
5,200
2,760
360
2,400
11,300C
Commercial
(1973)
4,450d
156
101
55
2,379
1,269
1,110
1,914
50
25
25
4,500d
Residential
(1973)
8,057e
192
115
75
2
2,280
0
2,280
5,450
0
0
0
8,057e
Total
35,845
10,220
9,800
178
242
9,398
5,440
3,958
15,821
3,399
692
2,702
39,244
Although it is EPA's policy to use the metric system for quantitative
descriptions, the British system is used in this report because the data
were originally reported in British units. Readers who are more accus-
tomed to metric units may use the table of conversions, Appendix A.
Solid Refuse fuel provided < 0.005 percent of this total.
°Includes 20 x 10 Btu of bagasse and 250 x 10 Btu of wood as fuel.
dlncludes 1 x 10 Btu of wood as fuel.
1 0
elncludes 135 x 10 Btu of wood as fuel.
-------
Table 2. MAJOR EMISSIONS FROM CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
Electric Generation
Industrial
Coa-crcial/
Institutional
Residential
Total. 103 ton/yr
Air
uloteii,
Z
63.8
28.3
4.9
3.0
7,060
so*.
*
72.5
14.5
6.7
6.3
22.100
NOX.
Z
64.8
24.7
7.3
3.2
10,950
IIC.
Z
34.0
22.3
12.2
31.5
•J53
CO,*
Z
33.6
14.9
7.7
44.7
1.070
OrcanicE"
1ISO,
Z
8.8
20.0
16.0
55.2
125
I'l'UM,
Z
0.3
0.5
0.2
99.0
4.14
Bal>,
^
0.2
1.3
0.4.
93.1
0.40
Water
Tot il
*
94
6
•< 1
NIL
5,000
Ui e«nl vt*il
Uollds,
Z
94
6
< 1
NIL
3.700
Was ie heat.
7.
80
20
< 1
NIL
7.9 x 1015 Btu/yr
Solid waste
Total
ash,
Z
87
10
1
2
54.000
Flv
ash.
Z
94
6
< 1
0
36.000
Dcsulfur-
; - "i * i '>r
Z
94
6
0
0
3,500
BSO • Benzene soluble organics
PFOM - Particulate polycyclic organic material
BaP • Benzo(a)pyrene
Does not include emissions of polyhalogenated biphenyls.
Total estimated emissions of polychlorinated blpheny'a baaed on « single emission aeasureoent
is »10 tons per year from coal-fired utility boiler»,
-------
presented along with the percentage contribution of the principal cate-
gories. Electric generation appears as the principal source of air pol-
lutants from conventional stationary combustion systems other than car-
bon monoxide and organics. The major source of these two pollutants
is residential combustion, suggesting that residential units burn fuel
incompletely, and that efforts to improve the combustion efficiency of
those myriad small sources are needed. Although representing only 2 per-
cent of the fuel consumed by residential sources, coal is the major
source of these emissions.
Emissions of polycyclic organic matter and polyhalogenated biphenyls (PHB)
have not been extensively measured. POM emissions, on the basis of
limited testing, are largely due to incomplete combustion, and as a result,
are attributable principally to low efficiency residential heating units.
Only one reference reported data for emissions of polychlorinated biphenyls
(PCB) from combustion. The average emission rate from a 125 MW pulverized
coal-fired boiler was 0.8 rag/10 Btu. Assuming the same emission rate for
all coal-fired boilers, the total PCB emission from coal would be 7.5
tons/yr. No data were found for emissions of PBB from coal and no data was
found for any PHH emissions from oil or gas. Because of the known toxicity
of these compounds, and their persistence in the environment, further work
is necessary to identify the contribution of all combustion sources to
existing levels in the environment.
The largest contributions to the burden of suspended and dissolved solids
discharged to water (approximately 5 million tons/year from all stationary
combustion sources) result from water used for coal ash handling. Ash
handling wastewater discharge contains an estimated 2,300,000 tons of solids,
largely in dissolved form. Waste water from boiler feedwater treatment is
also a significant contributor from the utility sector because of strin-
gent boiler water quality requirements. Over 90 percent of the water pollu-
tants resulting from stationary combustion are attributable to electric
-------
utilities. Coal ash constitutes the major solid waste material with ash
production at approximately 54 million tons/year and with electric utili-
ties contributing 87 percent of the total.
In order to place conventional stationary combustion source emissions in
perspective, Table 3 summarizes the air emissions of the criteria pollu-
tants from the combustion sources considered in this study along with
other man-made and natural sources of emissions in the United States.
Conventional stationary combustion sources are seen to be the largest
emitters of sulfur oxides and major emitters of airborne particulates
and nitrogen oxides, whereas their contribution to hydrocarbon and car-
bon monoxide emissions are of minor significance.
Trace element emissions to air trom all fuels are summarized in Table 4.
Electric generation by stationary combustion is again the source of most
of these emissions, largely as a result of the combustion of coal. Al-
though not shown by the table, only cadmium, cobalt, copper, nickel, and
vanadium, of the 28 trace elements tabulated, are produced in appreciable
quantities by burning oil. Analysis of the available emission data
indicates that approximately 50 to 80 percent of the combustion source
emissions of these elements are attributable to oil combustion.
Sources of trace metal element emissions to water are ash pond discharge,
cooling tower waters, and waste water from boiler water treatment pro-
cesses. Because of differences in system design and operating practices,
trace element emissions to water exhibit large variability. Because of
this variability, and the lack of sufficient emissions data, it has not been
possible to compile trace element data for water such as that presented in
Table 4 for air. However, it is estimated that over 95 percent of trace
metals from combustion sources (and over 90 percent of organic compounds),
are the result of electric utility operations. The utility industry is
estimated to contribute 14 percent of the total national discharge of metals,
including 50, 14, 10 and 21 percent, respectively, of chromium, copper, iron,
and zinc discharged, by industries designated as major water pollutant sources
by EPA.4
8
-------
Table 3. MAGNITUDE OF AIR EMISSIONS FROM CONVENTIONAL STATIONARY COMBUSTION SOURCES
COMPARED TO ALL MAN MADE AND NATURAL EMISSIONS IN THE U.S.3
Sourct
datura*
Stationary
Coosbuatton
Tranaportatlon
Industrial
Processes
Miscallaneous
Total
Particulatas
106
ton/yr
0s
7.1
0,8
14.4
12,8
35.1
X of
tot*l
U
U
U
U
U
U
X of
nan-aada
-
20.4
2.3
40.5
36.4
100.0
Sulfur oxide*
106
lon/yr
4.2
22.1
1.1
7.5
0.4
35.3
X of
total
11.9
62.6
3.1
21.1
%
1.1
100.0
X of
man-made
-
71.0
3.5
24.2
1.3
LOO.O
Nitrogen oxides
10*
ton/yr
U
11.0
11.2
0.2
2.4
2'.. 8
X of
total
U
U
U
U
U
U
X of
man-made
-
44.3
45.2
0.8
9.7
100.0
Mydrocnrbont
10*
ton/yr
30.7
0.4
19.8
5.5
11.2
67.6
I of
total
45.5
0.5
29.3
8.1
16.6
100.0
X of
nan-mad*
-
1.0
53.7
14.9
30.4
100.0
Carbon conoxidc
10*
ton/yr
NONE
1.1
111.5
12.0
26.1
150.7
t of
total
0
0,7
74.0
8.0
17.3
100.0
Z of
Ban-Bad*
-
0,7
74.0
8.0
17.3
100.0
*Esttoat*a for coabuation sourcts atudiad in thia nrogran wora davclop«d by CCA. Ochar «aiaclona bacad on
Robinson and Robbina2 and Ualchar.3
Natural aaicatena aaclutad by multiplying total natural aaiiflnna by th« ratio of U.S. to global land
turfaca areas.
CU • Unknown.
-------
Table 4. TRACE ELEMENT AIR EMISSIONS: PERCENT OF TOTAL FROM CON-
VENTIONAL STATIONARY COMBUSTION SYSTEM CATEGORIES
Electric Generation
Industrial
Commercial/ Institutional
Residential
Total, tons/year
Sb
87
10
3
0.05
59
As
90
8
2
0.06
3,300
Ba
88
9
3
0.1
3,050
Be
89
9
2
0.06
260
Bi
91
7
2
0.05
110
B
90
9
1
0.05
5,500
Br
84
13
2
1
6,700
Cd
61
21
18
0.007
330
Cl
83
13
2
2
710,000
Electric Generation
Industrial
Commercial/ Institutional
Residential
Total, tons/year
Cr
84
11
5
0.1
1,800
Co
63
23
14
0.3
510
Cu
72
16
12
0.07
2,800
F
83
13
2
2
37,000
Fe
77
20
3
0.2
170,000
Pb
92
7
1
0.05
1,300
Mn
89
10
i^
0.5
5,100
Hg
81
14
3
2
59
Ho
74
16
10
0.05
692
Electric Generation
Industrial
Coaaercial/Institutional
Residential
Total, tons/year
Hi
60
21
19
0.02
8,100
Se
85
13
2
1
870
Te
90
9
1
0.07
31
Tl
90
9
1
0.06
10
Sn
75
13
12
0.1
130
Ti
89
9
2
0.06
62,000
U
86
10
4
0.05
1,700
V
63
20
17
0.02
11,000
Zn
89
10
1
0.1
2,300
Zr -
78
20
2
0.2
2,300
-------
Electric coal-fired utilities are the principal source of solid waste
trace elements. The predominant sources of solid waste trace elements
are bottom ash, fly ash and solids produced by SO- recovery systems,
whose combined production Is now approximately 54 million tons per year.
This value will Increase with increasing coal consumption and will in-
crease several fold if predictions concerning flue gas desulfurizatlon
utilisation are realised. The trace element content of collected ash Is
summarized In Table 5.
CONCLUSIONS
The following text highlights some of the major conclusions which we have
drawn from the results of this study. In general, the conclusions and
interpretations apply to national emission levels; on a local level, any
of the combustion categories considered may present a serious environ-
mental problem due to the relative magnitude of the combustion system
emissions with respect to other sources and variations in fuel type, size,
operating practices, weather patterns, geology, hydrology, and population
density*
• Coal combustion is the largest contributor to the air,
water, and solid waste burden generated by stationary
combustion sources.
• The electric utility sector generates the largest per-
centage of most air, water, and solid waste pollutants.
The large amount of fuel consumed by the utility sector,
and specifically the very large amounts of coal burned,
accounts for this pollutant production.
• Industrial steam generation, space heating, and sta-
tionary engine operation are less significant as pollu-
tant sources than the electric utility sector. One
reason is the extensive use of natural gas.
• Commercial/institutional and residential combustion
systems are negligible contributors to the total burden
of water and solid waste pollutants. They contribute
negligible amounts of trace elements and only minor
amounts of particulate, SO^, and NO^ emission to the
environment. Coal-fired residential combustion systems
11
-------
Table 5. TRACE ELEMENTS IN SOLID WASTE (ASH): PERCENT OF TOTAL GENERATED BY
CONVENTIONAL STATIONARY COMBUSTION SYSTEM CATEGORIES
N9
Electric Generation
Industrial
Commercial/Institutional
Residential
To tal , tons /year
Sb
80.7
16.4
1.3
1.6
170
As
88.9
8.9
0.9
1.6
13,500
Ba
83.2
13.2
1.4
2.2
17,600
Be
83.1
12.5
1.8
2.6
812
Bi
84.3
13.3
0.8
1.6
349
B
84.6
12.8
1.1
1.6
17,900
Br
0
0
0
0
0
Cd
82.6
14.1
1.4
1.9
121
Cl
0
0
0
0
.0
Cr
75.1
11.7
5.4
7.8
5,550
Electric Generation
Industrial
Commercial/ Institutional
Residential
Total, tons /year
Co
69.3
8.9
8. -2
13.7
2,120
Cu
77.6
12.1
4.1
6.2
4,720
F
0
0
0
0
0
Fe
86.9
8.8
1.8
2.5
I
1,510,000
Pb
80.9
14.6
1.8
2.6
2,790
Mn
97.7
1.2
0.6
0.4
13,800
Hg
77.9
20.2
1.8
0.1
7
Mo
80.0
13.0
2.6
4.6
1,280
Ni
80.8
12.0
2.9
4.3
5,180
Electric Generation
Industrial
Commercial/ Institutional
Residential
Total, tons /year
Se
76.0
22.1
1.0
1.0
408
Te
83,7
13.1
1.2
1.9
99
Tl
83.4
12.6
1.7
2.4
34
Sn
76.1
12.5
1.4
9.9
383
Ti
83.1
12.8
1.7
2.4
197,000
U
84.5
12.9
1.1
1.6
4,970
V
83.6
13.1
1.3
2.0
9,320
Zn
82.6
12.8
1.8
2.8
7,600
Zr
85.5
11.1
1.4
2.1
19,000
-------
are, however, the principal source of organic emis-
sions. Within the stationary combustion sources, resi-
dential systems are also a large source of hydrocarbon
and carbon monoxide emissions.
The following discussion provides more extensive interpretations of the
results of this study and specifically enumerates those areas which
represent the major data gaps applicable to emissions from conventional
stationary combustion systems. A number of general needs are presented
first, followed by a listing of areas requiring further study which are
specific to air and water emissions and to the generation of solid waste,
• On the basis of the preliminary emissions assessment
completed in this program, it is apparent that a need
exists for further development and analysis of the
data base including: a compilation of critically
reviewed and acceptable data; a means of storing and
retrieving this data through the development of a
computerized data handling system relating combustion
systems and pollutants; and the development of software
to evaluate the ramifications and, significance of trends
in fuel consumption and boiler design in order to ade-
quately assess the environmental impact of stationary
conventional combustion sources. The Source Test Data
System (SOTDAT) could conceivably be used as a central
depository for source test data and its subsequent ana-
lysis for air emissions, but some modification of the
system is needed to insure adequate description of the
source.
• Additional research should be conducted on combustion
systems utilizing control practices and fuels that are
representative of the existing situation or which can
be expected to increase in prominence in the future.
These investigations should follow the recommendations
which are forthcoming from the priority ranking efforts
currently being undertaken by Monsanto Research Corpora-
tion based on the data base compiled under this contract
effort. This approach is important because numerous past
programs, such as some dealing with trace element emis-
sions to the air, have dealt with systems that are non-
representative of existing combustion sources and/or
their control equipment.
13
-------
• Greater effort should be expended in coordinating research
activities within and between government agencies, in-
dustrial, academic and trade organizations to ensure that
appropriate personnel are cognizant of activities in the
area of combustion source emissions.
• Research directed to emissions of particulates, SO ^ NO ,
and trace elements should concentrate on coal combustion
by electric utilities. Secondary efforts should be
directed towards coal combustion by the industrial sector.
• The importance of trace element emissions from conven-
tional stationary combustion systems cannot be precisely
defined. Comparison of concentrations produced to in-
dustrial TLV's indicate that for most elements the concen-
trations produced are well below the TLV values and the
emissions should not be particularly hazardous. However,
a very large population is exposed and some trace elements
produced by combustion tend to concentrate on the surface
of respirable fine particulates. In addition trace
elements may catalyze atmospheric reactions. Inves-
tigations of trace element emissions should continue.
• Fine particulate and vapor phase emissions and control
measures should be investigated with emphasis on coal
combustion by electric utilities. Scrubber efficiencies
should be determined for vapor phase trace elements and
POM.
• Emission factors for-POM's and PCB's, halogens and 803
should be developed for all sectors because of the large
uncertainties in the available data. Efforts should
initially be concentrated on the residential sector as
this sector produces most of the organics and may pro-
duce large amounts of S0
-------
• Emission factors and control measures for NO emissions
from stationary internal combustion engines should be
further developed.
• Water emission research and development efforts should be
directed primarily towards the electric utility sector
with secondary efforts directed to the industrial sector.
Efforts should also concentrate on coal combustion.
• A better definition of the electric utility and industrial
sectors water handling practices should be undertaken.
Information in these areas has been difficult to obtain.
Federal Power Commission data has been useful for the
electric utility sector, but the data should be subjected
to further analysis. Data on the practices of the in-
dustrial sector are particularly poor and should be improved.
The National Pollution Discharge Elimination Permit System
should be examined in detail as a potential source of addi-
tional information on both electric utility and industrial
practices. State agencies may also be able to provide
detailed data.
• Ash pond effluents should be characterized with regard to
total and suspended solids, including composition of trace
elements, organic, and organometallic compounds. Control
methods should also be investigated.
• Cooling water practices and effluent concentrations in the
industrial sector should be defined.
• The potential contribution of flue gas desulfurization
processes to water emissions should continue to re-
ceive strong emphasis.
• Product recovery of coal ash (fly ash, bottom ash, and
boiler slag) should be implemented to an increased extent.
• Ash handling practices of electric utilities and indus-
trial combustion sources should be examined and the
extent of control determined.
• The chemical composition (metals and organics) of coal
and ash should be studied in more detail with greater
emphasis on sampling and analytical procedures. In.
addition, although the amount of ash from residual oil
is very small, the amount and composition should be
investigated as no data are presently available.
• Methods for disposal of desulfurization wastes should be
investigated further. Control measures, such as pond
liners and stabilizers, should also be investigated.
15
-------
SECTION II
ELECTRIC UTILITY COMBUSTION SYSTEMS
SIZE OF INDUSTRY, SOURCES OF ENERGY, FUEL CONSUMPTION
Approximately 1,900 x 10 MWh of electrical energy was generated in the
United States during 1974, of which approximately 1,800 x 10 MWh, or
95 percent, was generated by utilities for general consumption. During
1974 fossil fuels produced 79 percent of the total electricity generated,
while hydropower and nuclear ' fuel produced 15 percent and 6 percent,
respectively. Seventy-seven percent of installed generation capacity
was driven by steam prime movers, 9 percent by internal combustion, and
14 percent by hydropower. Refuse, which is burned in small amounts to
produce electricity, is also considered in this report.
Fossil fuel consumption for electricity production increased 5 to 9 per-
cent per year in the period 1968 to 1973 with a total increase of 43 per-
cent. However, from 1973 to 1974 fossil fueled electric production de-
creased 3.5 percent, due primarily to the sharp increase in energy costs,
energy conservation efforts, the recession, and also as a result of
increased production from nuclear fuel and hydropower. Table 6 indicates
that over the past 7 years coal has been the predominant fossil fuel.
Oil's share of the electric utility market has more than doubled since
1968, from 9 to 22 percent while both coal and gas have decreased slightly.
In 1974, 54 percent of the fossil fuel consumed was bituminous coal,
0.25 percent anthracite, 1.3 percent lignite, 23 percent natural gas,
16
-------
Table 6. UTILITY FOSSIL-FUELED ELECTRICITY PRODUCTION - SOURCE OF
ENERGY, PERCENT3
\vear
Coal
Oil
Gas
1968
63
9
28
1969
60
12
28
1970
56
14
29
1971
53
18
29
1972
53
21
27
1973
55
22
23
1974
55
22
23
aTotals may not add due to rounding.
19 percent residual oil, and 2.9 percent distillate oil. The bituminous
coal category includes approximately 15 percent subbituminous coal. In-
cluded in the natural gas category is less than 0.6 percent combined
coke oven gas, refinery gas, and blast furnace gas. The use of liquified
natural gas and synthetic natural gas was essentially zero. All heavy
oils were included in the residual oil category and consisted of 0.6 per-
cent No. 4, 1.5 percent No. 5, 95.5 percent No. 6, and 2.4 percent crude.
Distillate oil consisted primarily of No. 2 fuel oil, and less than 10 per-
cent kerosene and jet fuel. Approximately 96 percent of the consumed
fuels were burned in external combustion systems and 4 percent in internal
combustion systems. A small undetermined amount of•fuel was burned in
combined cycle plants consisting of gas turbines followed by waste heat
boilers.
External combustion systems (boilers) produced 1419 x 10 MWh of
electricity in 1974 from an installed capacity-of 337,000 IN for a yearly
average load factor of 48 percent. In previous years the load factor
was 50 to 55 percent. Comparison of the fuel consumed to the electricity
produced yields a 1974 heat rate of 10,420 Btu/kWh, equivalent to a heat-
to-electricity efficiency of 33 percent.
17
-------
Internal combustion systems consist of gas turbines and reciprocating
engines burning distillate oil and natural gas. A few gas turbines
are designed to burn residual and/or crude oil after pretreatment, but no
such fuel use was reported for 1974. Fuel used by internal combustion
systems was only 3.8 percent of the electric utility total and consisted
of almost equal amounts of distillate oil and natural gas. Gas turbines
consumed seven times as much fuel as reciprocating engines. The predom-
inant turbine fuel was distillate oil while the predominant reciprocating
engine fuel was natural gas. Internal combustion systems are used primaril
for peaking, emergency, and reserve power, and therefore had a low yearly
average load factor of only 10 percent during 1974. Their heat rate of
14,750 Btu/kWh is higher than that of external combustion systems and
equivalent to an average efficiency of 23 percent.
During 1974, Union Electric Company of St. Louis was the only utility
in the United States burning refuse to produce electricity. Its capacity
was 12.5 tons per hour, and if operated at a 50 percent yearly load
factor, produced about 0.066 x 10 MWh of electricity.
Figure 1 presents the geographic distribution of utility fuel consump-
tion during 1973. Most of the fuel (75 percent) is consumed in the eastern
half of the United States with Texas (8.4 percent) and California (6.0 per-
cent) also consuming large quantities. Electric utility coal consumption
is presented in Figure 2. Coal consumption is concentrated in the eight-
state region of Michigan, Illinois, Indiana, Ohio, Pennsylvania, Kentucky,
West Virginia, and Tennessee, where 58 percent of the coal is consumed.
Oil consumption is concentrated in states along the eastern seaboard
including the New England, Middle Atlantic and South Atlantic regions
where a total of 72 percent of the oil is consumed. Fifty-three percent
of the gas is consumed in the West South Central Region (Arkansas,
Louisiana, Oklahoma, and Texas).
18
-------
NUMBERS ON MAP
DENOTE PERCENT OF TOTAL
UTILITY FUEL CONSUMPTION
I !<'*/•
nn 1-5%
Figure 1. Geographical Distribution - Electric Utility
Fuel Consumption - 1973.
-------
N>
O
NUMBERS ON MAP
DENOTE PERCENT OF TOTAL
UTILITY COAL CONSUMPTION
I |
-------
POPULATION AND CHARACTERISTICS OF COMBUSTION EQUIPMENT
The boiler systems emphasized in this study, and their associated fuel use,
are presented in Table 7. The data in Table 7 were derived from the pre-
viously discussed fuel use data and from boiler population and charac-
teristics, based primarily on computer analysis of individual boiler
data reported to the Federal Power Commission on Form FPC-67 and
stored on magnetic tape. All steam-electric plants of 25 MW or greater
capacity, which used 97 percent of the fuel consumed by steam-electric
plants, are required to complete Form FPC-67. The data gathered from
these forms was the most recent (1972) and the best available describing
*
the population of utility boilers.
Coal-Fired Boilers
The total number of coal-fired utility boilers included in the FPC data
was 1082 compared to 1500 reported to be in the National Emission Data
System (NEDS) file. The differences in the number of boilers may be due
to the fact that NEDS includes boilers of a lower size limit, and that
nonutility electric generation boilers are also included in the NEDS sys-
tem. During 1972 the reported coal-fired utility boiler heat rate was
10,252 Btu per kWh, compared to the GCA calculated design heat rate of
9670 Btu per kWh based on FPC data. The capacity average age of coal-
fired utility boilers at the end of 1972 was calculated to be 12 years.
The boiler data for coal combustion obtained from the FPC tape, are sum-
marized by major subcategories in Table 8. Almost 70 percent of the in-
stalled capacity consists of pulverized dry bottom boilers, approximately
16 percent were pulverized wet and 13 percent were cyclone boilers. Stoker-
fired boilers comprised a large segment of the boilers by number
FPC data for 1973 should be available for analysis late in 1975.
Capacity average age = I. (capacity x age)/E capacity.
21
-------
Table 7- ELECTRIC UTILITY SYSTEM FUEL CONSUMPTION, 1974
Classifi-
cation
system
number
1.0.00.0.0
1.1.00.0.0
1.1.10.0.0
1.1.11.0.0
1.1.11.1.0
1.1.11.2.0
1.1.11.3.0
1.1.11.4.0
1.1.12.0.0
1.1.12.1.0
1.1.12.2.0
1.1.12.3.0
1.1.12.4.0
1.1.13.0.0
1.1.13.1.0
1.1.13.2.0
1.1.13.3.0
1.1.13.4.0
1.1.20.0.0
1.1.21.0.0
1.1.21.0.1
1.1.21.0.2
1.1.22.0,0
1.1.22.0.1
1.1.22.0.2
1.1.30.0.0
1.1.30.0.1
1.1.30.0.2
1.1.40.1.1
1.2.00.0.0
1.3.00.0.0
1.3.20.0.0
1.3.30.0.0
1.4.00.0.0
1.4.20.0.0
1.4.30.0.0
Combustion system
category
Electric Generation
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Anthracite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Lignite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Petroleum
Residual Oil
Tangential Firing
All Other
Distillate Oil
Tangential Firing
All Other
Gas
Tangential Firing
All Other
Refuse
Internal Combustion
Turbine
Petroleum
Gas
Reciprocating
Petroleum
Gas
1012 Btu
15,387
14,798
8,502
8,264
5,971
1,118
1,118
57
38
13
0
0
25
200
120
30
30
20
3,039
2,901
1,128
1,773
138
54
84
3,257
791
2,466
0.6
589
515
286
229
74
26
48
aThe classification system utilized la
this -study is presented in Volume II.
22
-------
Table 8. SUMMARY: COAL-FIRED UTILITY BOILERS - 1972a
ISJ
Boiler type
Pulverized dry
Pulverized wet
Cyclone
Stoker
Boiler size,
106 Btu/hr
>5000
1500-5000
500-1500
<500
Number of boilers
percent of total
' i
57.8
17.1
6.6
18.4
5.2
19.2
31.8
43.9
Capacity
percent of total
69.5
15.8
12.6
2.2
27.5
38.8
23.8
9.9
Coal burned
percent of total
71.8
13.5
13.5
1.2
23.2
44.6
27.1
5.0
Capacity average
age , years
10
13
8
37
2
8
19
33
Nummary of data in Table 14, Volume II
Capacity average age
£ (Capacity x age)
£ Capacity
-------
(18 percent) but only a small segment by capacity (2.2 percent). In
addition, stoker-fired boilers were very old with a capacity average
age of 37 years compared to the overall average boiler capacity age of
12 years. Boilers above 5,000 x 10 Btu/hr were very new (approximately
2 years old), and compared to the number of boilers (5.2 percent), burned
a large fraction of the fuel (23 percent).
Pulverized coal-fired boilers burned approximately 85 percent of the
coal consumed by the electric utilities. Only 1.3 percent of these boil-
ers (by capacity) used fly ash reinjection. Few utility boilers used
vertical firing, 50 percent of the pulverized coal-fired boiler capacity
used tangential firing, and 32 percent used front firing. Only 18 per-
cent used opposed firing but these were the largest and newest boilers.
Anthracite coal is most commonly burned in industrial and commercial
boilers with stationary or traveling grates. Anthracite is not burned
in spreader stokers because of its high ignition temperature, but may
be burned as pulverized coal. However, because of ignition problems,
this practice is limited to only a few plants in eastern Pennsylvania.
Pulverized boilers burning anthracite are all dry bottom due to the very
high ash softening temperature, commonly above 2,900°F. It was estimated
that anthracite boilers are 65 percent stokers and 35 percent pulverized
dry, based on evaluation of NEDS data.
Lignite is burned in all boiler types. Although in the past lignite was
burned in small stokers, there has been a recer-t shift to large pulverized
and cyclone type boilers. Most of the large boilers burning lignite were
identified through the available FPC data, and it was estimated that 60 per-
cent of the lignite was burned in pulverized dry, 15 percent in pulverized
wet, 15 percent in cyclone and 10 percent in stoker-fired boilers.
The characteristics of bituminous coal-fired boilers were similar to all
coal-fired boilers, since bituminous coal represents 97 percent of the
24
-------
coal burned. Pulverized dry boilers accounted for approximately 72.3 per-
cent of the bituminous coal burned, whereas pulverized wet and cyclone
boilers accounted for 13.5 percent each, and stokers accounted for approx-
imately 0.7 percent.
Oil- and Gas-Fired Boilers
A similar analysis of the FPC magnetic tape was performed for oil- and
gas-fired utility boilers. Boilers were classified as oil-fired if
greater than 85 percent of the fuel was oil; gas-fired if greater than
85 percent of the fuel was gas, and if neither of the above conditions
applied, the boiler was classified as dual-fired. The data represent
approximately 72 percent of oil consumed at steam-electric plants and
83 percent of the gas consumed. Therefore, the data should be represen-
tative of the utility industry with the exception that a possibly large
number of small boilers are not included.
About 70 percent of the oil burned in steam-electric boilers was burned in
boilers classified as oil-fired, while most of the remaining was burned
in dual-fired boilers. There was a large difference in the ages of
oil-fired boilers between the less than 500 x 10° Btu/hr groups and each
of the other large size groups. Oil-fired boilers below 500 x 10 Btu/hr
had an average age of about 28 years, while larger boilers had an average
age of 14 years. Boilers using opposed firing, although burning only a
small fraction of the total oil, were the newest oil-fired boilers. It
was previously indicated that the newest coal-fired boilers also used
opposed firing.
Table 9 is a summary of the relative amounts of fuel burned by firing pat-
tern and size for oil- and gas-fired boilers. The table shows that approx-
imately 39 percent of the oil is burned in tangentially-fired boilers, and
47 percent is burned in front- or back-fired boilers. In addition, it
25
-------
Table 9. DISTRIBUTION (70) OF FUEL CONSUMPTION BY FIRING
PATTERNS AND SIZE OF UTILITY EXTERNAL COMBUSTION
BOILERS USING OIL AND GAS, 1972
Oil
Firing pattern
1.1.20.0.0.0 Oil 100.0
1.1.20.0.1.0 Tangential 38.9
1.1.20.0.2.0 All other (except tangential) 61.1
1.1.20.0.3.0 Front or back 46.8
1.1.20.0.4.0 Opposed 11.1
1.1.20.0.9.0 Other 3.2
Size
1.1.20.0.0.0 Oil 100.0
1.1.20.0.0.1 > 5000 x 106 Btu/hr 6.7
1.1.20.0.0.2 1500 - 5000 42.6
1.1.20.0.0.3 500 - 1500 38.0
1.1.20.0.0.4 < 500 12.7
Gas
Firing pattern
1.1.30.0.0.0 Gas 100.0
1.1.30.0.1.0 Tangential 24.3
1.1.30.0.2.0 All other (except tangential) 75.7
1.1.30.0.3.0 Front or back 46.8
1.1.30.0.4.0 Opposed 27.6
1.1.30.0.9.0 Other 1.3
Size
1.1.30.0.0.0 Gas . 100.0
1.1.30.0.0.1 > 5000 x 106 Btu/hr 10.5
1.1.30.0.0.2 1500 - 5000 48.6
1.1.30.0.0.3 500 - 1500 28.9
1.1.30.0.0.4 < 500 12.0
26
-------
should be noted that approximately 81 percent of the oil is burned in
boilers in the size range 500 to 5,000 x 10 Btu/hr.
The boiler sizes and firing methods used for burning gas are similar to
those burning oil. The newest boilers are the largest boilers, and in
general use opposed firing. The data in Table 9 indicate that 24 percent
of the gas is burned in tangentially-fired boilers and 47 percent in
front- or back-fired boilers. The largest amount of gas (49 percent) is
burned in the 1,500 to 5,000 x 10 Btu/hr size range.
Internal Combustion
Internal combustion engines are usually grouped in two classes: gas
turbines and reciprocating engines. They are used extensively in the
United States for peaking, emergency, and reserve electric generation
with some smaller electric utilities using them for base load also.
The average yearly load factor is about 10 percent for internal combus-
tion engines used in electric generation. Fuel use by internal combus-
tion engines was only about 4 percent of the electric utility total.
Gas turbines can use a variety of fuels, as long as the fuel used does
not form ash or contain dust which can erode the turbine blades. A few
gas turbines are designed to burn treated residual oil, but no such fuel
1 o
use was reported in 1974. Gas turbines used 286 x 10 Btu distillate
oil and 229 x 1012 Btu gas in 1974. The FPC has compiled detailed data
on gas turbines that consumed 90 percent of the gas turbine fuel in 1972.
Based .on these data, the average plant size was 82 MW (1260 x 10 Btu/hr)
and there were 299 plants. There were 989 units with an average size of
25 MW (385 x 106 Btu/hr). The average gas turbine heat rate is 15,400
Btu/kWh, corresponding to an efficiency of 22 percent.
The fuels used in reciprocating engines include primarily distillate oil
(26 x 1012 Btu/yr) and natural gas (48 x 1012 Btu/yr). The average
27
-------
reciprocating engine heat rate is 12,000 Btu/kWh, corresponding to an
efficiency of 29 percent.
Solid Waste Fired Boilers
The primary solid waste fuels are bagasse, wood bark and municipal refuse.
Bagasse, a sugar cane waste material, is used in Hawaii, Florida, and
Louisiana to produce steam and electricity, primarily for on-site use.
Whereas some electricity produced by bagasse may be sold to electric
utilities, there were no documented utility boilers burning bagasse in
1972.
Wood bark waste is used, in various regions of the United States, in the
lumber and paper industry for process steam. Electricity is also gener-
ated, in some locations, for -on-site use. There were no FPC documented
utility users of wood bark in the United States in 1972.
The only utility currently burning refuse is the- Meramac Plant of Union
Electric in St. Louis County. Currently, Union Electric has the capa-
bility to use refuse for 10 percent of the fuel requirement in a 125 MW
boiler. The boiler is a pulverized coal, tangentially-fired unit with
an electrostatic precipitator. The refuse is air classified and metals
are removed before it is fired at a rate of 12.5 tons/hr. At a 50 percent
load factor (typical of the utility industry), Union Electric would only
12
burn 0.5 x 10 Btu/yr of refuse. Therefore, at the present time refuse
represents an insignificant part of the total utility energy requirement
12
of 15,400 x 10 Btu/yr. Union Electric is currently expanding its ref-
use combustion capability to 8,000 tons/day (all the refuse generated in
the St. Louis area) and, if this program continues to be successful, ref-
use combustion by the utility sector may be more significant in the future,
Full utilization of solid waste (both municipal and agricultural) could
supplement the national energy supply by as much as 6 percent.
28
-------
EMISSION SOURCES
A large number of processes (or unit operations) utilized in the genera-
tion of steam and/or electricity generate emissions in the form of air,
water or solid waste pollutants. A coal-fired power plant has the largest
number of unit processes and emissions points; typical operations and emis-
sion sources in a coal-fired electric power plant are presented in Figure 3.
Many of the processes and emission points in this figure are not appli-
cable to gas- or oil-fired boilers and most are not applicable to internal
combustion engines.
The emission data contained in Volume II of this report is organized
around the unit operations presented in Table 10. The waste streams
emanating from individual unit process sources are frequently combined
and can be treated jointly. Ash handling includes both fly ash and
bottom ash.
Table 10. APPLICABILITY OF UNIT OPERATION AND PROCESS
TO AIR, WATER, AND SOLID WASTE POLLUTANTS
Unit operation
Flue gas emissions
Ash handling
Boiler blowdown
Equipment cleaning
Water treatment
Fuel handling
S02 scrubbing
Cooling systems
Air
X
0
NA
0
NA
0
NA
X
Water
NA
X
X
X
'x
X
X
X
Solid
waste
NA
X
0
0
0
0
X
NA
Note: X = Source
0 = Minor source
NA = Not applicable
29
-------
u*
o
At* CUICMMt , / Att
"
Figure 3. Eolssion sources coal-fired stea»-electric power plants
-------
Air omissions from electric power plants arise from a number ot sources,
but primarily from the combustion furnace stack, which is usually fitted
with an emission control device. The influence of control device per-
formance, px'inctpally electrostatic precipitators In the electric utility
industry, on the quantity of participate emissions is predominant. Emis-
sions and control device performance are principally affected by fuel,
boiler type, sulfur content and load factor. Low sulfur fuels decrease
the efficiency of precipitators, and the use of these fuels has hastened
the development of hot side and wet wall precipitators and other approaches
to control of stack emissions.
Other sources of air emissions are those arising from the handling, stor-
age and disposal of coal and'ash. These are relatively minov, amount-
ing to less than 1 percent of the stack emissions, and are considered to
be largely an in-plant problem. Cooling tower drift Is also a minor con-
*
tributor to air emissions although, under certain meteorological condi-
tions, It could be a source of major local problems.
The electric utility industry's contribution to total man-made and con-
ventional stationary combustion source pollutant emissions were summarized
earlier in Tables 2 and 3. Detailed emission estimates for external com-
bustion sources, In the United States, of the criteria pollutants, or-
ganlcs and trace elements, are presented in Table 11, As noted previously,
coal combustion i$ the predominant source on a nationwide basis of roost
of the pollutants studied in this program. The difference between the,
values given for electric generation and external combustion represent
the contribution of internal combustion sources. Internal combustion is
not a major contributor to emissions with the exception of NOX, with in-
ternal combustion accounting for over 8 percent of NO^ emissions from
the utility category. The emission factors used in the generation of
31
-------
Table 11.
STACK EMISSIONS FROM THE GENERATION OF
ELECTRICITY BY EXTERNAL COMBUSTION, 1974a
1.0.00.0.0 Electric Generation
1.1.00.0.0 External Combustion
1.1.10.0.0 Coal
1.1.11.0.0 Bituminous
1.1.11.1.0 Pulverized Dry
1.1.11.2.0 Pulverized Wet
1.1.11.3.0 Cyclone
1.1.11.4.0 All. Stokers
1.1.12.0.0 Anthracite0
1.1.12.1.0 Pulverized Dry
1.1.12.2.0 Pulverized Wet
1.1.12.3.0 Cyclone
1.1.12.4.0 All Stokers , .
1.1.13.0.0 Lignite*
1.1.13.1.0 Pulverized Dry
1.1.13.2.0 Pulverized Wet
1.1.13.3.0 Cyclone
1.1.13.4.0 All Stokers
1.1.20.0.0 Petroleum
1.1.21.0.0 Residual Oil6
1.1.21.0.1 Tangential Firing
1.1.21.0.2 All Other
1.1.22.0.0 Distillate Oilf
1.1.22.0.1 Tangential Firing
1.1.22.0.2 All Other
1.1.30.0.0 Gas8
1.1.30.0.1 Tangential Firing
1.1.30.0.2 All Other
Partlculates.
10^ tons/yr
Total
4,500
4,500
4,400
4.300
3.500
500
250
76
21
17
0
0
3.8
82
50
13
11 •'
8.4
78
74
29
45
3.9
1.5
2.4
16
3.1
12
<3ph
1,600
1,600
1,500
1,500
1,200
180
100
12
6.5
6.0
0
0
0.53
30
18
4.6
5.7
1.2
71
67
26
41
3.6
I.*
2.2
14
3.5
11
Gases,
103 tona/yr
S0x
16.000
16,000
14,000
14.000
10,000
1,900
1,900
99
41
15
0
0
26
120
74
19
19
12
1,500
1,500
570
890
16
6.1
9.6
0.9S
0.23
0.72
"°x
7,100
6,500
4,700
4,600
2.400
760
1,400
20
12
4.6
0
0
7.1
72
42
10
16
3.3
810
770
180
590
41
9.6
32
960
120
840
HC
120
85
64
57
41
7.6
7.6
1.2
0.098
0.008
0
0
0.09
6.2
3.7
1.0
0.93
0.63
19
18
7.2
11
0.99
0.38
0.61
1.6
0.39
1.2
CO
360
270
210
200
140
26
26
2.6
1.2
0.26
0
0
0.95
6.9
3.7
1.0
0.93
1.3
30
"28
11
17
1.5
0.58
0.90
27
6.6
20.5
Organ Ics,
tons/yr
BSO
11.000
11,000
10,000
9,700
7,000
1,300
1,300
58
50
15
0
0
35
250
150
40
38
25
300
300
130
170
14
6
8
360
90
270
PPOM
11
11
10
10
7.3
1.3
1.3
0.06
0.05
3.015
0
0
3.035
0.25
15
4.0
3.8
2.5
0.3
0.3
0.13
0.17
).014
).006
).OOS
0.35
0.09
0.27
BaP
o.a
0.8
0.75
0.73
0.52
0.1
0.1
0.006
0.004
0.001
0
0
0.003
0.02
0.01
0.003
0.003
0.002
0.02
0.02
O.OOS
0.012
0.001
0.0004
0.0006
0.03
0.008
0.022
NOTE: See Volume II, Table 27 for explanation of footnotes.
32
-------
Table 11 (continued). STACK EMISSIONS FROM THE GENERATION OF
ELECTRICITY BY EXTERNAL COMBUSTION, 1974*
1.0.00.0.0 Electric Generation
1.1.00.0.0 External Combustion
1.1.10.0.0 Coalk
1.1.11.0.0 Bituminous1
1.1.11.1.0 Pulverized Dry
1.1.11.2.0 Pulverized Wet
1.1.11.3.0 Cyclone
1.1.11.4.0 All Stokers
1.1.12.0.0 Anthracite"1
1.1.12.1.0 Pulverized Dry
1.1.12.2.0 Pulverized Wet
1.1.12.3.0 Cyclone
1.1.12.4.0 All Stokers
1.1.13.0.0 Lignite0
1.1.13.1.0 Pulverized Dry
1.1.13.2.0 Pulverized Wet
1.1.13.3.0 Cyclone
1.1.13.4.0 All Stokers
1.1.20.0.0 Petroleum0
1.1.21.0.0 Residual OilP
1.1.21.0.1 Tangential Firing
1.1.21.0.2 All Other
1.1.22.0.0 Distillate Oilq
1.1.22.0.1 Tangential Firing
1.1.22.0.2 All other
1.1.30.0.0 G«sr
1.1.30.0.1 Tangential Firing
1.1.30.0.2 All other
Trace elements,
tons/yr
Sb
51
51
48
48
35
6.3
6.3
0.33
0.04
0.01
0
0
0.03
^
2.9
2.9
1.1
1.8
ND
ND
ND
As
3,000
3,000
3,000
3,000
2,200
410
410
21
3.7
1.3
0
0
2.4
22
22
8
13
' 0.16
0.04
0.12
Ba
2,700
2,700
2,700
2,000
1,400
270
270
14
13
4.5
0
0
8.3
650
390
97
97
65
48
48
19
29
ND
ND
ND
Be
230
230
220
220
160
30
30
1.5
1.1
0.38
0
0
0.71
0.71
0.43
0.11
0.11
0.07
6.8
6.8
2.6
4.2
Bl
98
98
98
93
67
13
13
0.64
0.04
0.01
0
0
0.03
5.0
3.0
0.75
0.75
0.5
B
5.000
5,000
5,000
4,900
3,500
660
660
34
0.37
0.13
0
0
0.24
130
77
19
19
13
8.0
8.0
3.0
5.0
Br
5,600
5,600
5,600
5,600
4,000
760
760
39
1.5
0.51
0
0
0.95
0.57
0.36
0.08
0.08
0.06
12
12
4.8
7.5
0.04
0.01
0.03
Cd
200
200
54
54
39
7.3
7.3
0.38
0.05
0.02
0
0
0.03
150
150
57
89
ND
ND
ND
Cl
590,000
590,000
590,000
560,000
400,000
76,000
76,000
3,900
2,200
770
0
0
1,400
25,000
15,000
3,800
3,800
2.500
1,200
1,200
450
710
Cr
1,500
1,500
1,400
1,300
930
180
180
9.3
44
15
0
0
29
13
7.7
1.9
1.9
1.3
130
130
SO
80
NO
ND
m
NOTE: See Volume II, Table 27 for explanation of footnotes.
33
-------
Table 11 (continued)
STACK EMISSIONS FROM THE GENERATION OF
ELECTRICITY BY EXTERNAL COMBUSTION, 1974*
1.0.00.0.0 Electric Generation
1.1.00.0.0 External Combustion
1.1.10.0.0 Coalk
1.1.11.0.0 Bituminous1
1.1.11.1.0 Pulverized Dry
1.1.11.2.0 Pulverized Wet
1.1.11.3.0 Cyclone
1.1.11.4.0 All Stokers
1.1.12.0.0 Anthracite01
1.1.12.1.0 Pulverized Dry
1.1.12.2.0 Pulverized Wet
1.1.12.3.0 Cyclone
1.1.12.4.0 All Stokers
i. 1.13. 0.0 Lignite"
1.1.13.1.0 Pulverized Dry
1.1.13.2.0 Pulverized Wet
1.1.13.3.0 Cyclone
1.1.13.4.0 All Stokers
1.1.20.0.0 Petroleum0
1.1.21.0.0 Residual 01 lp
1.1.21.0.1 Tangential Firing
1.1.21.0.2 All Other
1.1.22.0.0 Distillate Ollq
1.1.22.0.1 Tangential Firing
1.1.22.0.2 All Other
1.1.30.0.0 C«sr
1.1.30.0.1 Tangential Firing
1.1.30.0.2 All Other
Trace elements ,J
tons/yr
Co
320
320
160
140
100
19
19
1.0
13
4.6
0
0
8.5
5.5
3.3
0.82
0.82
0.55
160
160
63
98
Cu
2,000
2,000
1,300
1,200
860
160
160
8.2
27
9.6
0
0
18
26
15
3.9
3.9
2.6
720
720
280
440
J.08
0.032
0.048
F
31,000
31,000
31,000
31,000
22,000
4,100
4,100
210
160
56
0
0
100
0.29
0.29
0.11
0.18
Fe
131.000
131,000
131.000
130,000
93,000
18,000
18,000
930
1.000
350
0
0
650
520
520
200
320
Pb
1,200
1,200
1,200
1,200
860
160
160
8.3
4.6
1.6
0
0
3.0
28
17
4.1
4.1
2.8
2.9
2.9
1.1
1.8
Hn
4,500
4,500
4,500
4,300
3.100
590
590
29
5.1
1.8
0
0
3.3
170
100
26
26
17
12
12
4.4
7.2
0.020
0.008
0.012
Hg
48
48
47
47
34
6.3
6.3
0.33
0.40
0.14
0
0
0.26
1.4
1.4
0.6
0.8
ND
ND
NO
Ho
510
510
350
340
240
46
46
2.4
3.7
1.3
0
0
2.4
4.9
2.9
0.73
0.73
0.49
160
160
64
100
Nl
4,900
4,900
1,300
1,300
930
180
180
9.3
18
6.4
0
0
12
8.7
5.2
1.3
1.3
0.87
3,600
3,600
1,400
2,200
ND
ND
ND
Se
740
740
730
730
520
99
99
5.1
0.20
0.07
0
0
0.13
9.9
9.9
3.9
6.0
ND
ND
ND
NOTE: See Volume II, Table 27 for explanation of footnotes.
-------
Table 11 (continued). STACK EMISSIONS FROM THE GENERATION OF
ELECTRICITY BY EXTERNAL COMBUSTION, 1974*
1.0.00.0.0 Electric Generation
1.1.00.0.0 External Combustion
1.1.10.0.0 Coalk
1.1.11.0.0 Bituminous1
1.1.11.1.0 Pulverized Dry
1.1.11.2.0 Pulverized Wet
1.1.11.3.0 Cyclone
1.1.11.4.0 All Stokers
1.1.12.0.0 Anthracite0
1.1.12.1.0 Pulverized Dry
1.1.12.2.0 Pulverized Wet
1.1,12.3.0 Cyclone
1.1.12.4.0 All Stokers
1.1.13.0.0 Lignite™
1.1.13.1.0 Pulverized Dry
1.1.13.2.0 Pulverized Wet
1.1.13.3.0 Cyclone
1.1.13.4.0 All Stokers
1.1.20.0.0 Petroleum0
1.1.21.0.0 Residual OilP
1.1.21.0.1 Tangential Firing
1.1.21.0.2 All Other
1.1.22.0.0 Distillate Oilq
1.1.22.0.1 Tangential Firing
1.1.22.0.2 All Other
1.1.30.0.0 Casr
1.1.30.0.1 Tangential Firing
1.1.30.0.2 All Other
Trace elements, J
tons/yr
Te
28
28
28
28
20
3.8
3.8
0.20
0.04
0.01
0
0
0.03
Tl
9.3
9.3
9.3
9.3
6.7
1.3
1.3
).064
0.04
0.01
0
0
0.03
Sn
100
100
98
88
63
12
12
0.64
0.37
0.13
0
0
0.24
10
5.5
1.4
1.4
0.92
6.4
0.08
0.032
0.048
6.4
2.5
3.9
Ti
55,000
55,000
55,000
55,000
39,000
7,400
7,400
380
220
77
0
0
140
39C
390
150
240
U
1,500
1,500
1,400
1,400
1,000
190
190
9.9
0.11
0.04
0
0
0.07
100
100
39
60
V
6,700
6,700
2,600
2,600
1,900
350
350
18
5.7
2.0
0
0
3.7
32
19
4.8
4.8
3.3
4,100
4,100
1,600
2,500
ND
ND
ND
7.n
2,000
2,000
2,000
2,000
1,400
270
270
14
12
4.2
0
0
7.3
5.8
3.5
0.86
0.86
0.58
5.6
S.6
2.2
3.4
ND
ND
ND
Zr
1,800
1,800
1,800
1,700
1,200
230
230
12
6.8
2.4
0
0
4.4
100
60
15
IS
10
NOTE: See Volume II, Table 27 for explanation of footnotes.
35
-------
Table 11, and sources of necessary supplementary data and the method-
ologies used to develop emissions, are described in detail in Volume II
of this report.
Discussions on the extent and quality of emission estimates are presented
in Volume II for each major class of pollutants. National emission esti-
mate data quality is considered to be generally fair to good for the cri-
teria pollutants and poor for organics and trace elements. Organic emis-
sion estimates are classified as poor because of both the limited amount
of data available and its questionable validity. The trace element emis-
sion quality rating of poor is attributable mainly to the questionable
validity of extrapolations from the limited amount of available good data
to national totals.
Water Effluents
i « ...
The major wastewater streams associated with coal-fired utility plants
are depicted in Figure 4. The flow volumes presented are typical for a
1,000 MW coal-fired plant but are subject to substantial plant-to-plant
variations. The figure illustrates that cooling water and ash pond dis-
charge are the principal sources of waste water associated with steam
electric generation utilities. To place the various emission streams of
fossil fueled utility boilers in the proper perspective, the total volume
of waste water emitted and the estimated solids content of the various
waste streams are given in Table 12. Many of the intermittent minor
sources may present severe problems if adequate control measures are not
followed.
Waste waters produced by a steam electric power plant result from a num-
ber of on-site operations. Some wastes are discharged continuously while
other wastes are produced intermittently, but on a fairly regularly
scheduled basis, such as daily or weekly. Waste water is produced
36
-------
80
/WITH COOLING)
22,950 \ TOWERJ
769,000/W|TH
I THROUGH
\ COOLING
ONCE\
GH I
NG /
BOILER
10
20
SLOWDOWN
10
(FLUE GAS)
4000
FLUE GAS
OESULFURIZATION
2000
20
METAL
EQUIPMENT
CLEANING
100
1450
OTHER
LOW-VOLUME
SOURCES
30
BOTTOM ASH
TRANSPORT
3300
FLY ASH
TRANSPORT
100
14,000
COOLING
TOWER
760,000 ^
CONDENSERS
4000
20
50
2000
500
5000
1600
.Sfl-
GLAND AND
MISC. LOSSES
10
SOOT
BLOWERS
20
ASH SETTLING
BASINS
9240
OVERFLOW
TREATMENT
9240
SLOWDOWN 200
DRIFT 10
EVAPORATION 13,690
760,000
Figure 4. Water flows for a typical 1000 MW power plant at
full load. All flow values in 10 gpd
-------
Table 12. IMPORTANT ASPECTS OF WATER WASTES
00
'
Waste gcnurating
process
Ash
handling
Cooling
Once-through .
Fresh
Sal In*
Keclrculativ*
Fuel
handling
toiler fcedvaur
treataaat
toiler
blovdown
Equipment
cleaning
Duration
of
flow
Continuous '
Continuous
Continuoui
Continuous
Intermittent
Continuous
Intermittent
Infrequent
once/2 yr.
Uaete water flow quantities
All boiler.
»0»
gal/yr
280C.
3'. 000*
1C. 000
5,300
7.9c'd
9.0e
6.6C
2.2C
Total
solids
103 ton
2(00
27S
670
1100
5.6
130
Coal-fired
bollcra
10«
gal/yr
280C
23,000e
1.600
2,700
7.9c'd
S.2e
3.8e
1.3C
Total
solid*
10' l ton
2400
140
.70
MO
3.2
77
Important
polluilonal
character la tic*
300-3500 t.g/1 TSS
trace eleuent
ind organic*
AT -15°r
free Cl residual
0.1-1.0 Kg/i
10-28,000 ag/i
acidity
1500-45.000 eg/t
TS
30,000 Bg/l TS
3.000 Bg/l
hardneaa
5-50 af./ 1
phosphate*
10-100 Bg/t
alkalinity
4,000 mg/l
hardness
14,000 Bg/i TS
AKsncl-iteJ *
hazardous
amblunt cdecte
Possible D.O. reduction
production of color.
Interference with water
reuse.
D.O. reduction result-
Ing In fish kills and
lowered capacity for
natural water processes.
Hazards to fish nnd IB-
p.ilrmcnt of water for
recreational and con-
sumptive use. Possible
D.O. reduction.
Possible D.O. reduction
production of color
turbidity, and odor.
Interference with water
reuse.
Eutrophicatlon and
tollda •edinentation.
Possible D.O. reduction
production of color
turbidity, and odor.
Interference with water
reute.
Overall
«6Sessr.?nt
of hazard
Tlic quantity of flow and solida
coiicent ration Is high. With
gnonlng of ash wastes, the solids)
concentration Is significantly
reduced. The average effluent
TSS Is 100 ir.s/l.e
Significant hazard with both
syctco*. The large flow quan-
tity Is the major cause of the
adverse Impact.
yjnor ambient hazard); for pro-
perly collected and treated
waste flovi. Shock effects cay
be significant :or unjer
-------
continuously from the following sources: cooling water systems, ash
handling systems, wet scrubber flue gas systems, and boiler feedwater
treatment. Waste water is discharged intermittently, on a regular basis,
by treatment operations such as boiler blowdown and boiler system equip-
ment cleaning. Other wastes are also produced intermittently, but at
less frequent intervals, and are generally associated with either the
shutdown or startup of a boiler or generating unit. Additional wastes
exist that depend upon climatological or other factors, an example of
which is coa.1 pile drainage.
Cooling systems use large volumes of water as the medium for cooling
boiler generated steam as it passes through the steam condensers. Cool-
ing is accomplished by using recirculative or once-through methods. Re-
circulative systems consist of various types of cooling towers, cooling
ponds, and spray ponds. These systems are essentially closed loops in
which used cooling water is cooled for reuse in order to minimize makeup
water requirements and eliminate thermal water pollution. Cooling towers
contribute significant amounts of moisture and heat to the atmosphere, as
well as drifts containing salt, corrosion inhibitors and algicides, such
as chlorine, that are added to the recirculating cooling water. Tower
blowdown, which is used to control dissolved and suspended solid concen-
tration in the cooling water, adds to the wastewater stream as shown in
Figure 4. Cooling canals or ponds are controlled volumes used for storage,
cooling, and reuse of cooling water. Spray cooling ponds utilize spray
nozzles at the water surface which spray heated water into the air to
increase the rate of cooling. The potential exists for emission of salt
drift and production of fog, but the problem is more localized than in
the case of cooling towers due to the low effective emission height.
In once-through systems, cooling water is passed to the condensers to cool
the working fluid and the cooling water is then discharged back to the
source. Once-through systems potentially contribute to thermal pollution
and the contamination of waters downstream of the plant with additives such
39
-------
as chlorine (used to prevent fouling of condenser surfaces). An apparent
trend is toward the use of wet/dry combination and dry cooling systems in
order to reduce water consumption, pollutant discharge and abatement of
fogs caused by vapor plumes.
The wastewater volumes from boiler blowdown, coal storage, drainage,
equipment cleaning, and water treatment are relatively small. They may
contribute, however, to the discharge of hazardous components (PCB, oil
or grease, low or high pH water, vanadium, nickel, etc.), that require
further processing to reduce effluents to acceptable levels.
Flu.e gas desulfurization (FGD) is a potentially large source of water
pollutants. Most trace elements in.FGD solids are more soluble than
similar fly ash constituents and pose a potential water quality hazard
if sludge liquor is operated in an open loop mode.
The operation and control practices of the utility industry are subject
to large plant-to-plant variations. Limited flow and composition data
concerning ash pond discharge, boiler blowdown, and cooling practices are
available from the Federal Power Commission. Perhaps the most comprehen-
sive emission data are on file with the Nationa?. Pollution Discharge Elim-
ination System. However, these data are fragmented and difficult to
compile, although some compilations have been made and national emissions
of some pollutants have been estimated. The data are highly variable re-
flecting differences in system design and operating practices, and extrap-
olation of limited data to national averages are highly questionable;
thus the emission estimate data quality factors assigned to most waste
water streams are generally poor.
Solid Waste Generation
Ash is the principal source of solid waste, accounting for almost 50 millios
.tons per year with coal combustion constituting over 90 percent of this
total (see Table 13). Approximately 15 percent of this ash is utilized,
40
-------
Table 13. ASH HANDLING EMISSIONS: ELECTRIC UTILITIES, 1974
1.0.00.0.0 Electric generation
1.1.00.0.0 External combustion
1.1.10.0.0 Cqal
1.1.11.0.0 Bituminous
1.1.11.1.0 Pulverized dry
1.1.11.2.0 Pulverized vat
1.1.11.3.0 Cyclone
1.1.11.4.0 All stokers
1.1.12.0.0 Anthracite
1.1.12.1.0 Pulverized dry
1.1.12.2.0 Pulverized vet
1.1.12.3.0 Cyclone
1.1.12.4.0 All stokers
1.1.13.0.0 Lignite
1.1.13.1.0 Pulverized dry
1.1.13.2.0 Pulverised vet
1.1.13.3.0 Cyclone
1.1.13.4.0 All stokers
1.1.20.0.0 Petroleum
1.1.21.0.0 Residual oil
1.1.21.0.1 Tangential firing
1.1.21.0.2 All other
1.1.22.0.0 Distillate oil
1.1.22.0.1 Tangential firing
1.1.22.0.2 All other
1.1.30.0.0 Cas
1.1.30.0.1 Tangential firing
1.1.30.0.2 All other
Bottom
nun,
ID3
tons
12,925
12,925
12,900
12,550
5,350
2,300
4,700
200
50
15
0
0
35
300
180
45
45
30
25
25
10
15
Nil
Nil
Nil
Nil
Nil
Nil
Fly ash,
10^ tons
34,125
34,125
34,100
33,200
27,800
3,850
1,300
250
100
35
0
0
65
800
480
120
120
80
25
25
10
15
Nil
Nil
Nil
Nil
Nil
Nil
Total,
103
tons
47,050
47,050
47,000
45,750
33,150
6,150
6,000
450
150
50
0
0
100
1.100
660
165
165
110
50
50
20
30
Nil
Nil
Nil
Nil
Nil
Nil
Aali
utilization,
tons
7,500,000
7,500,000
7,500,000
7.300,000
5,300.000
980,000
950,000
70,000
24,000
8,000.
0
0
16,000
174,000
105,000
26,000
26,000
17,000
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Ponding
acres/
yr
692
692
692
673
480
90
88
7
2.2
0.7
0
0
1.5
16
9.6
2.4
2.4
1.6
0.9
0.9
0.4
0.5
NIL
Nil
Nil
Nil
Nil
Nil
acre
teet/
yr
17,300
17,300
17,300
17,300
17,300
16,800
12,200
2,260
2.200
165
55
18
0
0
37
400
240
60
60
40
23
23
9
14
Nil
Nil
Nil
Nil
Landfill
acres/
yr
37
37
37
36
26
5
4
1
0.2
0.05
0
0
0.15
0.8
0.5
0.12
0.12
0.18
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
acre
feet/
yr.
876
876
872
850
610
115
115
9
2.7
0.9
0
0
1.8
21
12
3.2
3.2
2.3
Nil
Nil
mi
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Water8
discharge,
;06 gal/yr
310,000
310,000
310,000
301,000
218,200
40,300
39,400
3,100
985
314
0
0
671
7,160
4,300
1.070
1,070
720
400
400
180
220
Nil
Nil
Nil
Nil
Nil
Nil
Air
emissions,
103
tons/yr
20
20
20
19.3
14
2.6
2.5
0.2
0.06
0.02
0
0
0.037
0.47
0.28
0.07
0.07
O.OS
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
*Se« Voluoe II, Tiblea 47 «od 48, for properties of di»charge water*.
-------
while the remainder is ultimately disposed of in landfills along with
the settled solids from other waste streams that are collected in settling
basins or ponds. Although limited data are available concerning leachates,
the extent of contamination of ground and surface waters will depend upon
many factors including: control measures (ground covers, liners, fixation,
etc.); type of fuel used; and local meteorological, hydrological and geo-
logical conditions. National estimates of the trace metal content of
collected ash from coal-fired electric utilities are given in Table 14.
The solid waste disposal problems associated with combustion systems will
drastically increase if flue gas desulfurization processes become widely
implemented. For example, if estimates of about 70,000 MW of flue gas
desulfurization capacity by 1985 are realized, a total of 100,000,000
tons per year of sludge and ash would be produced. The flue gas desul-
furization sludge does not compact as well as ash and, because of its
higher sulfur content, compounds in the sludge are more soluble than fly
ash constituents. Some constitutent solubilities have been measured which
are substantially in excess of desirable water quality criteria. These
include mercury, selenium, boron, chloride, sulfate and total dissolved
solids. Chemical fixation .is receiving extensive study as a means of
reducing leachate problems.
42
-------
Table 14. ASH TRACE ELEMENTS: ELECTRIC UTILITIES, 1974'
Sb
As
Ba
Be
Bi
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Ti
U
V
Zn
Zr
Bituminous
138
12,000
11,500
670
279
14,800
0
99
0
4,000
1,300
3,500
0
1,200,000
2,200
13,000
5
1,000
4,100
310
83
28
265
163,000
4,200
7,700
6,100
15,300
Anthracite
0.11
10.9
72
3.3
0.11
1.1
0
1.0
0
131
118
83
0
8,900..
8.4
15.3
0.4
11
55
0.1
0.11
0.11
1.1
650
0.4
13
36
63
Lignite
—
—
3,100
2.1
15
380
0
—
0
38
50
77
0
—
51
520
— ..,:... .'
14.5
20
—
— •
—
27
—
—
75
140
900
*Tons collected,
43
-------
SECTION III
INDUSTRIAL COMBUSTION SYSTEMS
FUEL CONSUMPTION
Within the fuel use categories considered in this study industrial sources
consume 29 percent of the fuel, as shown in Table 1. Approximately 67
percent of the fuel used in industrial combustion applications is natural
gas whereas oil and coal account for 18 and 12 percent, respectively.
Wood and bagasse represent the remaining 3 percent of industrial fuel
consumption. These estimates of industrial fuel consumption were based
on Bureau of Mines statistics (coal, oil and gas) and NEDS data (wood
and bagasse).
The use of internal combustion engines is more prevalent in the industrial
sector than in the electric utility sector. Internal combustion engines
g
account for almost 25 percent of industrial fuel use as opposed to
4 percent in electric utilities. Their greater use is largely based on
their adaptability to required variations in demand and their simplicity
of operation.
POPULATION AND CHARACTERISTICS OF COMBUSTION EQUIPMENT
The number of industrial boilers and plants is much greater than the
number of utility boilers, although a complete accounting of these boilers
is not available. Estimates of boiler population and characteristics
have been made based on analysis of NEDS data, supplemented by boiler
sales information. An estimate of the number of boilers, in operation
44
-------
in the United States, and their sizes is presented in Table 15. Boiler
capacities and fuel consumption by the combustion system classification
considered in the study are shown in Table 16.
Table 15. NUMBER AND SIZE OF INDUSTRIAL BOILERS, 1973
EMISSIONS
Air Emissions
Size
106 Btu/hr
10-20
20-50
50-100
100-200
200-500
> 500
Totals
Number of boilers3
Coal
670
860
930
870
830
70
4,230
Oil
21,000
4,600
2,500
1,100
600
135
29,935
Gas
11,000
8,900
4,900
1,500
570
90
26,960
All
fuels
32,670
14,360
8,330
3,470
2,000
90
61,125
Includes boilers designed to burn the
primary fuel only as well as those
capable of burning a secondary fuel.
Emission estimates for industrial boilers operating in the United States
are presented in Table 17. Emissions from industrial fuel consumption
are governed by the same principles as the electric utility sector; how-
ever, because the combustion equipment design and operating practices
are different, the emission factors are different. Generally industrial
combustion equipment is smaller and is operated less efficiently than
electric utility systems. Emission rates of nitrogen oxides tend to be
lower due to decreased furnace temperatures; emission rates of hydrocarbons,
carbon monoxide, and organics tend to be higher due to less complete
-------
Table 16. INDUSTRIAL BOILER CAPACITY AND FUEL CONSUMPTION
BY COMBUSTION SYSTEM, 1973
2.0.00.0.0
2.1.00.0.0
2.1.10.0.0
2.1.11.0.0
2.1.11.1.0
2.1.11.2.0
2.1.11.3.0
2. 1.11. A. 0
2.1.11.5.0
2.1.11.6.0
2.1.11.7.0
2.1.12.0.0
2.1.12.1.0
2.1.12.2.0
2.1.12.4.0
2.1.13.0.0
2.1.13.1.0
2.1.13.2.0
2.1.13.4.0
2.1.13.5.0
2.1.13.6.0
2.1.13.7.0
2.1.20.0.0
2.1.21.0.0
2.1.21.0.1
2.1.21.0.2
2.1.22.0.0
2.1.22.0.1
2.1.22.0.2
2.1.30.0.0
2.1.30.0.1
2.1.30.0.2
2.1.40.0.0
2.1.41.0.0
2.1.42.0.0
Industrial
External combustion
Coal
Bituminous
Pulverized dry
Pulverized wet
Cyclone
All stokers
Overfeed stokers
Spreader stokers
Underfeed stokers
Anthracite
Pulverized dry
Pulverized wet
All stokers
Lignite
Pulverized dry
Pulverized wet
All stokers
Overfeed stokers
Spreader stokers
Underfeed stokers
Petroleum
Residual oil
Tangential firing
All other
Distillate oil
Tangential firing
All other
Gas
Tangential firing
All other
Refuse
Bagasse
Wood/Bark
Approximate
design capacity,
10^ Btu/hr steam
3,700
3,230
730
690
330
70
10
280
25
235
20
8
0
0
3
20
0
0
20
0
20
0
1,110
850
140
710
260
40
220
1,410
140
1,270
Fuel consumed,
1012 Btu/yr
11,280
8,540
1,370
1,320
650
130
40
500
30
450
20
10
0
0
10
40
0
0
40
0
40
0
1,700
1,270
200
1,070
430
70
360
5,200
520
4,680
270
20
250
46
-------
Table 17. FLUE GAS EMISSIONS FROM INDUSTRIAL EXTERNAL COMBUSTION, 1973C
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coal
2.1.11.0.0 Bituraincusb
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11.5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite0
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers
2.1.13.0.0 Llgnited
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum6
2.1.21.0.0 Residual Oil
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oil
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Casf
2.1.30.0.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse8
2.1.42.0.0 Wood/Barkh
Partlculotes,
103 tons/yr
Total
2,000
2,000
2,000
1,600
610
99
6
900
54
810
36
6.3
0
0
6.3
35
0
0
35
0
35
0
120
97
15
82
21
3
18
25
2.5
22
42
210
<^
200
200
66
65
29
4.8
3.8
27
1.5
24
1.1
0.12
0
0
0.12
0.68
0
0
0.68
0
0.68
0
110
87
14
73
19
3
16
23
2.3
21
Gases,
10^ tons/yr
S0x
3,200
3,200
2,200
2,200
1,100
220
68
850
51
770
34
7.3
0
0
7.3
25
0
0
25
0
25
0
1,000
1.000
160
840
41
6
35
1.4
0.14
1.3
0
18
"Ox
2,700
1,600
590
570
260
87
49
170
10
150
6.8
1.9
0
0
1.9
18
0
0
18
0
18
0
430
320
27
290
110
10
100
420
42
380
5.5
140
HC
80
76
17
16
4.3
0.87
0.27
11
0.66
".9
0.44
0.055
0
0
0.055
1.4
0
0
1.4
0
1.4
0
15
11
2
9
4.2
0.66
3.5
7.7
0.77
6.9
5.5
31
CO
160
150
73
57
15
2.9
0.89
22
1.3
20
0.83
1.7
0
0
1.7
14
0
0
14
0
14
0
21
15
3
12
5.7
0.89
4.8
41
4.1
37
5.5
44
Organlcs,1
tons/yr
BSO
25,000
25,000
2,800
2,700
1,200
250
50
1,200
97
970
97
19
0
0
19
90
0
0
90
0
90
0
11,000
8,600
940
7,600
2.400
280
2,100
11,000
2,000
9,000
PPOM
20
20
16
15
7.2
1.4
0.'29
7.7
0.55
5.6
0.55
0.11
0
0
0.11
0.52
0
0
0.52
0
0.52
0
1.4
l.l
0.12
0.96
0.33
0.044
0.33
2.2
0.4
1.8
BaP
5
5
4.0
3.8
1.8
0.36
0.072
1.7
0.14
1.4
0.14
0.028
0
0
0.028
0.13
0
0
0.13
0
0.13
0
0.36
0.27
0.03
0.24
0.094
0.011
0.083
0.55
0.10
0.45
NOTE: See Volume II, Table 91 for explanation of footnotes.
47
-------
Table 17 (continued).
FLUE GAS EMISSIONS FROM INDUSTRIAL
EXTERNAL COMBUSTION, 1973a
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coalk
2.1.11.0.0 Bituminous1
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Vet
2.1.11.3.0 Cyclone
2. 1. 11. 4. C All Stokers
2.1.11. 5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite™
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers ~
2.1.13.0.0 Lignite"
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum
2.1.21.0.0 Residual 011°
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oil?
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Casl
2.1:30.0.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse
2.1.42.0.0 Wood/Bark
Trace elements. J
tons/yr
Sb
5.8
5.8
4.5
4.5
2.3
0.34
0.022
1.8
0.11
1.6
0.072
0
0
0
0
0
*
0
0
1.3
1.3
0.20
1.1
KD
ND
NO
As
260
260
250
250
130
19
1.2
100
6.1
92
4.0
0.04
0
0
0.04
0
0
0
0
0
11
10
1.6
8.4
0.50
0.034
0.37
Ba
490
490
470
330
170
25
1.6
130
8.0
120
5.2
3.4
0
0
3.4
140
0
0
140
0
140
0
21
21
3.3
18
KD
ND
ND
Be
25
25
22
22
11
1.6
0.11
b .8
0.52
7.8
0.34
0.17
0
0
0.17
0.13
0
0
0.13
0
0.13
0
3.0
3.0
0.47
2.5
Bi
9.1
9.1
9.1
9.0
4.5
0.69
0.043
3.7
0.22
3.3
0.14
0
0
0
0.08
0
0
0.08
0
0.08
0
B
490
490
490
470
240
36
2.3
190
12
170
7.6
0
0
0
19
0
0
19
0
19
0
i3.6
3.6
0.56
2.9
Br
870
870
860
860
420
85
11
330
20
290
13
0.37
0
0
0.37
0.036
0
0
0.036
0
0.036
0
5.8
5.7
0.89
4.9
0.11
0.018
0.092
c
Cd
67
67
3.7
3.7
1.9
0.28
0.018
1.5
0.090
1.3
0.059
0
0
-.
0
0
0
0
63
63
9.9
53
ND
ND
MD
Cl
93,000
91,000
92,000
86,000
42,000
8,500
2,600
33,000
2,000
29,000
1,300
550
0
0
550
5,500
0
0
5,500
0
5,500
0
530
530
83
450
Cr
200
200
140
130
65
9.9
0.63
53
3.1
47
2.1
7.0
0
0
7.0
1.9
0
0
1.9
0
!.<»
0
58
58
9.1
49
ND
ND
ND
NOTE: See Volume II, Table 91 for explanation of footnotes.
48
-------
Table 17 (continued).
FLUE GAS EMISSIONS FROM INDUSTRIAL
EXTERNAL COMBUSTION, 1973a
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coaik
2.1.11.0.0 Bituminous^
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11. 5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite0
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers
2.1.13.0.0 Lignite"
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum
2.1.21.0.0 Residual 011°
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Ollp
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Cast
2.1.30.2.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse
2.1.42.0.0 Wood/Bark
Trace elements, J
tons/yr
Co
110
110
42
34
17
2.6
0.17
14
0.82
12
0.54
5.6
0
0
5.6
2.5
0
0
2.5
0
2.5
0
70
70
11
59
Cu
460
460
130
120
58
8.7
0.57
47
2.8
41
1.8
4.6
0
0
4.6
4.2
0
0
4.2
0
4.2
0
330
330
52
280
0.25
0.016
0.023
F
4.800
4,800
4,800
4,700
2,300
460
140
1,800
110
1,600
70
59
0
0
59
0
0
0
0
0.13
0.13
0.020
0.11
Fe
33,000
33,000
32,000
32,000
16,000
2.400
.'.50
13,000
760
11,000
500
420
0
0
420
0
0
0
0
235
235
37
200
Pb
86
86
85
81
41
6.2
0.40
33
2.0
29
1.3
0.56
0
0
0.56
3.0
0
0
3.0
0
3.0
0
1.3
1.3
0.20
1.1
Mn
510
510
510
480
210
31
15
180
10
160
6.6
0.84
0
0
0.84
25
0
0
25
0
25
0
5.0
5.0
0.79
4.2
0.066
0.011
0.055
Kg
8.1
8.1
7.4
7.3
3.6
0.72
0.22
2.8
0.17
2.5
0.11
0.091
0
0
0.091
0
0
0
0
0.65
0.65
0.10
0.55
ND
ND
ND
Mo
110
110
34
33
17
2.5
0.16
13
0.80
12
0.52
0.04
0
0
0.04
-0.7
0
0
0.7
0
0.7
0
72
72
11
61
Nl
1,700
1.700
130
130
65
9.9
0.63
53
3.1
47
2.1
3.0
0
0
3.0
1.4
0
0
1.4
0
1.4
0
1,600
1.600
250
1.300
ND
ND
KD
Se
110
110
110
110
55
11
3.4
42
2.5
38
1.7
0.051
0
0
0.051
0
0
0
0
4.5
4.5
0.71
3.8
KD
ND
ND
NOTE: See Volume II, Table 91 for explanation of footnotes.
49
-------
Table 17 (continued). FLUE GAS EMISSIONS FROM INDUSTRIAL
EXTERNAL COMBUSTION, 1973a
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coalk
2.1.11.0.0 Bituminous1
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11.5.0 Overfetd Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite0
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers
2.1.13.0.0 Lignite"
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleua
2.1.21.0.0 Residual Oil0
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oilp
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Cas«l
2.1.30.0.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse
2.1.42.0.0 Wood/Bark
Trace elements,]
tons/yr
Te
2.8
2.8
2.8
2.8
1.4
0.21
0.013
1.1
0.065
0.98
0.043
0
0
'
0
0
0
0
Tl
0.90
0.90
0.90
0.90
0.45
0.069
0.0043
0.37
0.022
0.33
0.014
0
0
0
0
0
0
Sn
18
16
9.9
8.6
4.3
0.66
0.043
3.5
0.21
3.1
0.14
0
0
1.3
0
0
1.3
0
1.3
0
5.6
0.90
4.7
Tl
5,600
5,600
5,400
5,400
2,700
400
26
2,200
130
1,900
84
35
0
0
35
0
0
0
0
1/0
170
27
140
U
180
180
140
140
68
10
0.67
55
3.3
49
2.2
0
0
0
0
0
0
44
44
6.9
37
V
2,100
2,100
260
250
130
19
1.2
100
6.0
90
4.0
0.81
0
0
0.81
4.2
0
0
4.2
0
4.2
0
1,800
1,800
280
1,500
NO
CD
HO
Zn
220
220
210
200
99
15
0.97
80
4.7
71
3.1
2.0
0
0
2.0
5.3
0
0
5.3
0
5.3
0
6.0
6.0
0.94
5.1
ND
ND
ND
Zr
460
460
460
420
210
32
2.0
170
10
150
6.7
2.9
0
0
2.9
39
0
0
39
0
39
0
NOTE: See Volume II, Table 91 for explanation of footnotes.
50
-------
combustion; and SO emission rates are virtually the same. Particulate
J\
emissions from coal (including many trace element emissions) are strongly
affected by control equipment efficiency and application, which are both
lower in the industrial sector. Control application increases with
increasing boiler size, ranging from a reported 21 percent for the smaller
boilers (10-200 x 106 Btu/hr) to 70 percent for large boilers (> 500 x 106
Btu/hr). Particulate emissions from oil in the industrial sector are
essentially uncontrolled and are estimated to be three times as high per
unit of fuel as in the utility sector, due largely to the release of
unburned carbon. Air emissions from coal pile storage and handling, ash
handling and cooling systems are substantially less in the industrial
area than similar emissions from utilities. Less coal usage and smaller
boiler capacities account for this difference.
Estimated emissions of polycyclic organic matter (POM) in the industrial
area are almost an order of magnitude higher per unit of fuel than in.
the utility sector. POM emissions data should be treated with caution,
however, as the estimates are based on a limited number of tests.
The difference in emissions between the industrial and external combustion
classification shown in Table 17 represents the contribution of internal
combustion engines. Only the emissions of NO from internal combustion
Jx
engines are of nationwide significance, accounting for almost 41 percent
of NO emissions from industrial combustion systems.
ji
Water Emissions
Waste water emissions from the pertinent unit operations described previ-
ously are difficult to define. In arriving at the estimates developed under
this contract and presented in detail in Volume II, it has been assumed
that operating parameters of large industrial boilers (> 500 x 10 Btu/hr)
parallel the practices followed by electric utilities. Smaller boiler
operating practices have been inferred from recommended operating prac-
tices by trade organizations and boiler manufacturers. Basically
51
-------
the greater use of clean fuels, natural gas and oil, lessens the water
pollution problem associated with combustion. The amount of waste water
from industrial equipment cleaning, fuel handling and ash handling is
reduced significantly. However, the lack of available data and des-
cription of operating practices makes estimation of the volumes and
composition of wastewater streams extremely questionable.
Solid Waste
The solid waste generated by the industrial sector is far less than that
generated by utilities due to the smaller amount of coal burned and the
less frequent application of particulate control devices. The total
.amount of ash collected in 1973 was estimated to be 5.2 million tons,
approximately an order of magnitude lower than that collected by the
utility sector. This total is comprised of 57 percent bottom ash and
43 percent fly ash. The amount of fly ash generated is estimated to be
4.5 million tons but only about 46 percent is collected.
Ash collected by the industrial sector is almost entirely disposed of as
landfill. Although the total amount generated is relatively minor on a
nationwide basis, improper disposal can have significant local impact.
52
-------
SECTION IV
COMMERCIAL/INSTITUTIONAL COMBUSTION SYSTEMS
This major classification of combustion sources was defined on the basis
of fuel consumption data rather than boiler size. All boilers in the
0.3 to 10 x 10 Btu/hr size range are generally considered to be commer-
cial boilers and have been included as such in this study. However, we
have chosen to add some larger institutional boilers to the coiranerical
category because of their inclusion in available fuel consumption statis-
tics. These larger boilers, generally associated with large governmental
and institutional facilities, account for about 17 percent of the fuel
consumed for space heating by the commercial/institutional sources con-
sidered. Estimated fuel consumption by the commercial/institutional
sector is shown in Table 18 which indicates that approximately 53 percent
of the fuel consumed was gas, whereas oil and coal accounted for 44 and
3 percent, respectively. Fuel -consumption by internal combustion engines
amounted to about 1 percent of the total fuel used.
Because oil and gas are clean fuels relative to coal, and because of the
smaller boiler sizes considered, most pollutant waste streams are small
and in many cases nonexistent, e.g., cooling waste discharge, water
treatment wastes, ash pond discharge, boiler blowdown, etc. Solid waste
emissions, resulting from ash handling, are minor due to the small amount
of coal consumed. Air emissions of the criteria pollutants, organics and
trace elements from the flue gas stack are shown in Table 19. Even though
these estimates are for uncontrolled emissions, the contribution of these
sources to nationwide emissions are minor, as shown previously in Tables 2
and 3.
53
-------
Table 18. COMMERCIAL/INSTITUTIONAL FOSSIL FUEL CONSUMPTION - 1973*
3.0.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.12.0.0
3.1.13.0.0
3.1.20.0.0
3.1.21.0.0
3.1.22.0.0
3.1.30.0.0
Commercial
Coal
Bituminous
Anthracite0
Lignite
Petroleum
Residual oil
Distillate oile
Gasf
Total
all uses
1012 Btu/yr
5,436
156
100
55
1
2,379
1,269
1,110
2,901
Space
heating
10iz Btu/yr
4,449
156
100
55
1
2,379
1,269
1,110
1,914
a
External combustion only.
b22.4 x 106 Btu/ton.
C26.0 x 106 Btu/ton.
d!46,000 Btu/gal-
e!40,000 Btu/gal.
fIncludes 8.5 percent LPG, 1020 Btu/ft3 (gas); 90,000 Btu/gal
(liquid).
54
-------
Table 19. FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973£
in
Ui
3.0.00.0.0 Commercial
3.1.00.0.0 External Combustion
3.1.10.0.0 Coal
3.1.11.0.0 Bituminousb
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3. 1.11. A. 0 All Stokers
3.1.12.0.0 Anthracite0
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oild
3.1.21.1.0 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oile
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Casf
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Particulates ,
10-* tons/yr
Total
350
340
0.70
0.50
0.60
4.8
50
21
21
0
0
0
0
150
92
0.73
91
, 59
0.59
58
9.1
0.39
8.7
1.4
<3pp
150
150
4.4
3.0
2.0
0.08
0.97
0.41
0.41
0
0
0
0
140
83
0.66
82
53
0.53
52
8.2
0.35
7.9
Gases ,
103 tons/yr
sox
1,500
1,500
230
210
42
2.1
170
20
20
0
0
0
0
1,300
1,200
9.5
f
1,200
130
1.3
•130
0.56
0.024
0.54
0.10
NOX
800
770
30
14
2.8
0.14
11
16
16
0
0
0
0
630
320
1.3
320
310
1.6
310
110
4.7
105
0.69
HC
43
41
7.0
6.8
1.3
0.067
5.4
0.21
0.21
0
0
0
0
24
12
0.095
12
12
0.12
12
7.2
0.31
6.9
2.5
CO
83
78
25
23
4.6
0.023
18
2.1
2.1
0
0
0
0
32
16
0.13
16
16
0.16'
16
19
0.81
18
2.1
Organics,
tons/yr
BSD
20,000
20,000
590
380
76
3.8
300
210
210
0
0
0
0
15,000
7,500
70
7,400
7,500
80
7,400
4,000
180
3,800
PPOM
6.8
6.8
3.5
2.3
0.44
0.022
1.8
1.2
1.2
0
0
0
0
2.0
1.0
0.008
1.0
1.0
0.01
1.0
1.3
0.056
1.2
BaP
1.7
1.7
0.86
0.56
0.11
0.0055
0.44
0.30
0.30
0
0
0
0
0.51
0.26
0.0021
0.26
0.25
0.0025
0.25
0.32
0.014
0.31
NOTE: See Volume II, Table 116 for explanation of footnotes.
-------
Table 19 (continued. FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973*
•
3.0.00.0.0 Commercial
3.1.00.0.0 External Combustion
3.1.10.0.0 Coalj
3.1.11.0.0 Bituminousk
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3.1.11.4.0 All Stokers
3.1.12.0.0 Anthracite1
3. 1.12. A. 0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oilm
3.1.21.1.0 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oiln
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gasf
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Barkg
Trace elements,
tons/yr
Sb
1.8
1.8
0.55
0.48
6.37
0.015
0.09
0.011
0.011
0
0
0
0
1.2
1.2
0.0095
1.'2
ND
ND
ND
As
39
39
28
27
21
0.85
5.0
1.1
1.1
0
0
0
0
11
9.4
0.075
9.3
1.3
0.013
1.3
Ba
60
60
40
34
26
1.0
6.6
6.1
6.1.
0
0
0
0
20
20
0.16
20
ND
ND
ND
Be
54
54
2.6
2.3
1.8
0.072
0.43
0.-31
0.31
0
0
0
0
2.8
2.8
0.022
2.8
IH
0.96
0.96
0.95
0.95
0.73
0.029
0.19
0.011
0.011
0
0
0
0
B
54
54
50
50
39
1.6
9.6
0.11
0.11
0
0
0
0
3.3
3.3
0.026
3.3
Br
160
160
70
68
13
0.68
54
2.2
2.2
0
0
0
0
89
5.3
0.0053
5.3
84
0.83
83
Cd
59
59
0.41
0.40
0.31
0.012
0.016
0.011
0.011
0
0
0
0
59
59
0.47
58
ND
ND
ND
Cl
10,000
10,000
9,900
6,700
1,300
68
5,400
3,200
3,200
0
0
0
0
500
500
5.0
500
Cr
79
79
26
13
10
0.42
2.6
13
13
0
0
0
0
53
53
6.43
53
ND
ND
ND
in
NOTE: See Volume II, Table 116 for explanation of footnotes.
-------
Table 19 (continued). FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973a
3.0.00.0.0 Commercial
3.1.00.0.0 External Combustion
3.1.10.0.0 Coalj
3.1.11.0.0 Bituminous
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3.1.11.4.0 All Stokers
3.1.12.0.0 Anthracite1
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oilm
3.1.21.1.0 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oiln
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gas0
3.1.30.0.1 Tangential Firing
3.1.30.0.2 , All Other
3.1.42.0.0 Wood/Bark8
Trace elements,
tons/yr
Co
79
79
13
3.5
2.7
0.11
0.66
9.6
9.6
0
0
0
0
66
66
0.52
65
Cu
330
330
20
12
9.4
0.36
2.3
7.9
7.9
0
0
0
0
310
310
2.5
310
0.66
0.0065
.0.65
F
700
700
700
360
59
2.3
100
340
340
0
0
0
0
0.12
0.12
0.0012
0.12
Fe
4,100
4,100
4,100
3,400
2,600
100
660
710
710
0
0
0
0
220
220
1.7
220
Pb
19
19
9.5
8.6
6.6
0.26
1.7
0.94
0.94
0
0
0
0
1.2
1.2
0.0095
1.2
Mn
5.0
5.0
45
44
34
1.3
8.6
1.4
1.4
0
0
0
0
4.7
4.7
0.037
4.7
0.17
0.0017
0.17
Hg
1.7
1.7
1.1
0.57
0.11
0.0057
0.46
0.52
0.52
0
0
0
0
0.61
0.61
0.0061
0.61
ND
ND
ND
Mo
72
72
4.5
3.4
2.6
0.10
0.66
1.1
1.1
0
0
0
0
67
67
0.52
66
Ni
1,500
1,500
18
13
10
0.42
2.6
5.3
5.3
0
0
0
0
1,500
1,500
12
1,500
ND
ND
ND
Se
13.4
13.4
9.1
8.8
1.7
0.092
7.0
0.29
0.29
0
0
0
0
4.3
4.3
0.043
4.3
ND
ND
ND
Ul
NOTE; See Volume II, Table 116 for explanation of footnotes.
-------
Table 19 (continued). FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973*
in
03
3.0.00.0.0 Commercial
3.1.00.0.0 External Combustion
3.1.10.0.0 CoalJ
3.1.11.0.0 Bituminousk
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3. 1.11. A. 0 All Stokers
3.1.12.0.0 Anthracite1
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oilm
3.1.21.1.0 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oil"
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gas0
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Trace elements,
ton/yr
Te
0.31
0.31
0.31
0.30
0.23
0.0091
0.056
0.011
0.011
0
. 0
0
0
Tl
0.12
0.12
0.12
0.095
0.073
0.0029
0.019
0.011
0.011
0
0
0
0
Sn
16
16
1.0
0.90
0.70
0.027
0.17
0.11
0.11
0
0
0
0
15
15
0.15
15
Ti
880
880
620
560
430
18
110
63
63
0
0
0
0
160
160
1.3
160
U
55
55
14
14
11
0.44
2.7
0.29
0.29
0
0
0
0
41
41
0.32
41
V
1,700
1,700
26
26
20
0.78
4.7
1.4
1.4
0
0
0
0
1,700
1,700
13
1,700
ND
ND
ND
Zn
30
30
24
21
16
0.62
3.9
3.1
3.1
0
0
0
0
5.6
5.6
0.044
5.6
ND
ND
ND
Zr
49
49
49
44
34
1.4
8.6
5.0
5.0
0
0
0
0
NOTE: See Volume II, Table 116 for explanation of footnotes.
-------
SECTION V
RESIDENTIAL COMBUSTION SYSTEMS
Total fuel consumption by the residential sector is estimated to be
10,350 x 10 Btu/yr, with 8,057 x 1012 Btu used for space heating.
Estimates for the major fuel classifications are presented in Table 20.
Residential fuel usage was based on apportionment of the available Bureau
of Mines fuel use data for the combined commercial/residential sectors to
the residential sector, by considering the number of dwellings in a state
using each fuel, the average degree days within each state, and the
appropriate fuel consumption factors per degree day.
Table 20. RESIDENTIAL FUEL USE, 1973
4.0.00.0.0
4.1.00.0.0
4.1.10.0.0
4.1.11.0.0
4.1.12.0.0
4.1.13.0.0
4.1.20.0.0
4.1.22.0.0
4.1.30.0.0
4.1.42.0.0
Residential
External Combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum"
Distillate Oil
Gas
Wood
Percent .
of total fuel
used for
o
space heating
78
100
100
100
100
94
94
70
100.
Fuel use:
space heating
1012 Btu/yr
8,057
8,057
192
115
75
2
2,280
2,280
5,450
135
Total fuel consumed in residential sector estimated to be
10,350 x 1012 Btu/yr.
bOver 95 percent No. 1 or No. 2 distillate oil.
59
-------
Nationwide emission estimates for residential combustion systems are pre-
sented in Table 21. Although residential units are a minor source of
criteria pollutant and trace element emissions, they are, on the basis of
the available data, the principal combustion source of polycyclic organic
matter emissions. Coal combustion appears to be the major contributor
to POM emissions despite the small amount of coal burned. It has also
been hypothesized that residual oil combustion contributes significantly
9
to high sulfuric acid levels in many eastern urban areas.
60
-------
Table 21. FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973'
4.0.00.0.0 Residential
4.1.00.0.0 External Combustion
4.1.10.0.0 Coal
4.1.11.0.0 Bituminousb»c
4.1.12.0.0 Anthraciteb»d
4.1.13.0.0 Lignite6
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate Oilf
4.1.30.0.0 Gas8
4.1.42.0.0 Wood/Barkh
Particulates,
10^ tons/yr
Total
230
230
69
53
15
1.4
82
82
52
25
<3ycl
120
120
1.3
1.0
0.29
0.027
74
74
47
0.49
. Gnscs,
10-* tons/yr
SOX
1,400
1,400
240
210
27
1.0
1,200
1,200
1.5
3.7
NOX
350
350
12
7.9
4.3
0.3
98
98
210
25
HC
110
110
57
53
3.6
0.05
25
25
21
5.0
CO
470
470
370
240
130
0.1
41
41
54
5.0
Organics ,
tons/yr
BSO
69,000
69,000
43,000
26,000
17,000
450
14,000
14,000-
12,000
840
PPOM
4,100
"4,100
4,000
2,400
1,600
42
11
5.2
6.3
77
BaP
390
390
. 380
230
150
3.6
1.1
0.50
0.60
7.4
NOTE: See Volume II, Table 126 for explanation of footnotes.
-------
Table 21 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973*
A. 0.00. 0.0 Residential
4.1.00.0.0 External Combustion
4. 1.10. 0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite™
4.1.13.0.0 Lignite0
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate .011°
4.1.30.0.0 GasP
4.1.42.0.0 Wood/Bark
Trace elements,^
tons/yr
Sh
0.031
0.031
0.031
0.03
0.001
ND
ND
As
1.9
1.9
1.8
1.6
0.15
0.05
0.05
Ba
3.2
3.2
3.2
1.9
0.89
0.42
ND
ND
Be
0.16
0.16
0.16
0.12
0.04
Bi
0.053
0.053
0.053
0.05
0.001
0.002
B
2.7
2.7
2.7
2.6
0.015
0.057
Br
83
83
31
78
2.9
2.0
2.0
Cd
0.021
0.021
0.021
0.020
0.0010
ND
ND
Cl
12,000
12,000
12,000
7,800
4,400
16
Cr
2.4
2.4
2.4
0.7
1.7
0.006
ND
ND
NOTE: See Volume II, Table 126 for explanation of footnotes.
-------
Table 21 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973*
A. 0.00. 0.0 Residential
A. 1.00. 0.0 External Combustion
4.1.10.0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite1"
4.1.13.0.0 Lignite0
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate Oil°
4.1.30.0.0 GasP
4.1.42.0.0 Wood/Bark
Trace c-lomunts,-'
tons/yr
Co
1 5
1.5 .
1.5
0.20
1.3
0.005
Cu
1.9
1.9
1.8
0.7
1.1
0.008
0.05
0.05
V
740
740
740
420
320
FC
280
280
280
180
99
l>b
0'.64
0.64
0.64
0.5
0.13
0.009
Mn
26
26
26
23
2.6
0.039
0.006
0.006
Hg
1.4
1.4
1.4
0.65
0.78
0.002
ND
ND
Mo
0.35
0.35
0.35
0.2
0.15
0.004
Ni
1.5
1.5
1.5
0.8
0.73
ND
ND
Se
10
10
10
10
0.4
ND
ND
NOTE: See Volume II, Table 126 for explanation of footnotes.
-------
Table 21 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973
a
4.0.00.0.0 Residential
A. 1.00. 0.0 External Combustion
A. 1.10. 0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite1"
4.1.13.0.0 Lignite"
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate 011°
4.1.30.0.0 GasP
4.1.42.0.0 Wood/Bark
Trace elements,
tons/yr
To
0.021
0.021
0.021
0.020
0.001
Tl
0.006
0.006
0.006
0.005
0.001
Sn
0.18
0.18
0.064
0.05
0.01
0.004
0.12
0.12
*
Ti
40
40
40
.31
8.7
U
0.8
0.8
0.8
0.8
0.004
V
1.6
1.6
1.6
1.4
0.19
0.012
ND
ND
Zn
3.1
3..1
3.1
1.1
2.0
0.018
ND
ND
Zr
3.8
3.8
3.8
2.4
1.4
NOTE: See Volume II, Table 126 for explanation of footnotes.
-------
SECTION VI
TRENDS IN FUEL CONSUMPTION AND COMBUSTION SYSTEM DESIGN
FUEL CONSUMPTION
The prediction of fossil fuel consumption patterns over the next decade
is dependent upon political, economic, environmental, and technological
considerations. Federal regulations and pricing policies will play a
major role in determining future fuel use patterns and boiler design
parameters. The trends presented in Volume II of this report are largely
based on the Project Independence Report published in November, 1974.
Estimates of fuel consumption trends from stationary combustion systems
are given in Table 22 for the major fuels. Coal consumption is predicted
to increase sharply, with oil decreasing in overall usage and gas under-
going a modest increase.
In the electric utility sector the use of coal is predicted to double
while the use of oil and gas will decline. Specifically the use of
bituminous, subbituminous and lignite will increase sharply whereas
anthracite consumption will decline. Western coal consumption will in-
crease faster than eastern coal and will increase from 11.6 percent of
coal consumed in 1974 to about 20 percent in 1985. The major effect of
the trend to western coal will be a reduction in the potential S02 emis-
sions per unit of fuel. Further the use of western coal will signifi-
cantly affect the design and application of boilers and control methods.
Coal and oil consumption by the industrial sector will increase 40 to 45
percent each and gas consumption will remain essentially constant. The
65
-------
Table 22. FUEL CONSUMPTION TRENDS, STATIONARY COMBUSTION SOURCES
a
Total
Coal
Oil
Gas
Electric utilities
Coal
Oil
Gas
Industrial
Coal
Oil
Gas
Commercial/Institutional
Coal
on
Gas
Residential
Coal
Oil
Gas
1973b
fuel
1012 Btu
38,701C'd»8
10,220
9,958
18,523
15,387
8,502
3,351
3,534
11,300C
1,370
2,060
7,600
4,500d
156
2,404
1,939
8,057g
192
2,143
5,450
1985
fuel
1012 Btu
49,843e'f'g
19,095
9,801
20,947
22,531e
16,994
3,016
2,485
12,934f
1,945
2,966
7,600
4,941
70
2,019
2,851
9,2588
86
1,800
8,011
Percent
change
1973b-l985
+29
+87
-2
+13
+46
+100
-10
-30
+14
+42
+44
+0
+10
-55
-16
+47
+15
-53
-16
+47
Electric generation process steam, space heating, and'stationary
engines.
^Utility data represents 1974
17 12
clncludes 250 x 10 Btu wood and 20 x 10 Btu bagasse
j J2
Includes 1 x 10 Btu wood.
T2
CIncludes 36 x 10 Btu refuse
1 *> 1*7
flncludes 400 x 10 Btu wood and 23 x 10 Btu bagasse
1 9
glncludes 135 x 10 Btu wood
66
-------
increase in coal consumption will increase the need for control equipment
in the industrial sector.
Fuel consumption trends for the commercial/institutional and residential
sectors were assumed to be .identical. The major trend for these sectors
is a large increase in the use of natural gas. Coal is only a minor fuel
for these sectors and its use will continue to decline.
COMBUSTION SYSTEMS
The trends to 1985 for combustion system types within each combustion
sector were estimated. Table 23 presents the detailed trend estimates
for the electric utility sector. Significant among the trends in the
electric utility sector is the lack of growth predicted for cyclone-
fired boilers due to their high NO emission levels, which generally
X
exceed New Source Performance Standards. In addition the use of gas
turbines will increase sharply. Detailed boiler age data presented in
Volume II indicates a trend to larger boilers and to opposed firing units.
Tangentially-fired units may also be widely used since NO emissions are
Ji
more easily controlled in this unit type. Regulations will be of
major significance in the modification of boiler design and operating
procedures. Practically all electric utilities and industrial plants
will be subject to Federal and State air, water and solid waste
regulations.
67
-------
Table 23. ELECTRIC UTILITY FUEL CONSUMPTION TRENDS
TO 1935 BY COMBUSTION SYSTEM TYPE
1.0.00.0.0
I. 1.00. 0.0
1. I. 10. 0.0
1.1.11.0.0
1. I. 11. 1.0
1.1.11.2.0
1.1.11.3.0
1.1.11.4.0
1.1.12,0.0
1.1.12.1.0
1.1.12.2.0
1.1.12.3.0
1.1.12.4.0
1.1.13.0.0
1.1.13.1.0
1.1.13.2.0
1.1.13.3.0
1.1.13.4.0
1.1.20.0.0
1.1.21.0.0
1.1.21.0.1
1.1.21.0.2
1.1.22.0.0
1.1.22.0.1
1.1.22.0.2
1.1.30.0.0
1.1.30.0.1
1.1.30.0.2
1.1.40.1.1
1.2.00.0.0
1.3.00.0.0
1.3.20.0.0
1.3.30.0.0
1.4.00.0.0
1.4.20.0.0
1.4.30.0.0
Electric Generation
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Anthracite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Lignite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Oil
Residual Oil
Tangential Firing
All Other
Distillate Oil
Tangential Firing
All Other
Gas
Tangential Firing
All Other
Refuse
Internal Combustion
Turbine
Oil
Gas
Reciprocating
Oil
G»9
1974
1012 Btu
15,387
14,798
8,502
8,264
5,971
1,118
1,118
57
38
13
0
0
25
200
120
30
30
20
3,039
2,901
1,128
1,773
138
54
84
3,257
791
2,466
0.6
589
515
286
229
74
26
48
1985
1012 Btu
22,531
20,932
16,994
14,976
11,877
1,952
1,118
29
19
9
0
0
10
2,000
1,730
220
30
20
2,172
2,060
801
1,259
99
38
61
1,780
356
1,344
36
1.549
1,467
815
652
82
29
53
Percent
change
1974-1985
+ 46
+ 42
+100
+ 81
+ 99
+ 75
+ 0
- 50
- 50
- 30
0
0
- 60
+1000
+1400
+ 730
+ 0
0
- 29
- 29
- 29
- 29
- 29
- 29
- 29
- 55
- 55
- 55
+6000
+262
+285
+285
+285
+ 10
+ 10
+ 10
68
-------
SECTION VII
ON-GOING AND PLANNED RESEARCH ACTIVITIES
A listing of current and planned investigations into pollutant emissions
from conventional stationary combustion sources is presented in Volume II.
Those projects which are identified include, when possible, the project
title and Contract Number, supporting and performing organization, princi-
pal investigator, a brief project description, and the planned completion
date. The program discussions are presented according to the major unit
operations contributing to pollutant emissions.
The following summary briefly identifies the major trends in research and
development investigations of emissions and the environmental impacts of
conventional combustion systems operation:
• Combustion - Studies are principally concerned with the
design of new units, boilers or internal combustion
engines, or modification of existing units in order to
improve combustion efficiency, lower pollutant levels,
or allow the burning of different fuels. NOX reduc-
tion measures and improvement of the combustion effi-
ciency of small burners are receiving attention.
o Flue Gas Emissions
Particulate - The trend is toward the investigation
of fine participate distributions and compositions
using cascade impactors and condensation nuclei
counters in order to determine fine particulate
distributions and control efficiencies. Fine par-
ticulates are of concern because of the health
effects associated with respirable particulates.
Emphasis is also being placed on secondary
reactions which occur in the plume after exit from
the stack with major interest pertaining to the
formation of sulfate, nitrate, and POM bearing
particulates.
69
-------
• Other Criteria Pollutants - Since a large portion of sul-
fur in fuel is emitted as SOX through the stack, research
has centered upon eliminating sulfur prior to combustion
or removing it from the flue gas after combustion. The
atmospheric sulfur cycle and 803 and sulfuric acid meas-
urement techniques are also being studied.
NOX emission reduction programs include analysis of
fuel conversion alternatives, boiler modification,
variation in operating parameters, catalytic stack gas
removal, flue gas scrubbing and alternatives to water
injection (for stationary engines).
Stationary combustion is a minor source of HC and CO
and has been researched accordingly.
• POM - Investigations include assessment of .sampling
procedures, analysis of POM compounds, and measurement
of total emissions of POM from stationary sources.
• Trace Elements - Fine particulate trace elements pre-
sent a potential health hazard due to their respirable
nature. The trend toward increased use of coal has em-
phasized the need to investigate trace element emis-
sions, control methods, and hazardous plume and atmos-
pheric transformations.
Ash Handling - Studies pertain to identification of bottom
ash and fly ash distribution and composition, and ash re-
utilization. Investigations into ash pond discharge, po-
tential leachates from landfill, fixation processes, and
the use and durability of pond liners are being conducted.
Analysis of soil migration rates, hazardous effects to
soil receptors, and interactions of metals and organics
are on-going or planned.
Cooling Systems - Current projects are investigating the
reduction of water consumption, elimination of salt drift,
and the reduction of thermal pollution and chemical con-
tamination of surface waters. The majority of these studies
involve dry and wet/dry cooling systems as a means to that end.
Water Recycle/Reuse - Current studies are underway to iden-
tify design and cost information on methods of reducing
water consumption and wastewater discharges through water
recycle/reuse and treatment. These studies are assessing
the potential for cascading water use and treatment of the
major plant wastewater streams.
70
-------
Boiler Water Treatment - Investigations are being made
into current boiler operating standards in order to es-
tablish the state-of-the-art and recommend required
alterations. The major problem areas are turbine damage
and control of corrosion and scale deposition in steam
generator tubing.
Fuels and Fuel Handling - A number of investigations are
on-going or planned to characterize air emissions and
acid drainage from coal storage piles. Cleaning of coal
prior to combustion is another area of study.
Flue Gas Desulfurization - The current research concerns
removal of SOX from flue gases by many processes in all
stages of development. Sludge disposal methods are under
active investigation.
Control Devices - A variety of studies are being performed
to determine the particulate control efficiency of elec-
trostatic precipitators, wet scrubbers, fabric filters, and
novel control devices. Attention is being given to the
effect of fuel and boiler type on control efficiencies of
fine particulates. Filters and scrubbers merit further study;
scrubbers are of interest because of their potential for
reduction of vapor phase emissions.
71
-------
SECTION VIII
REFERENCES
1. Cowherd, C., M. Marcus, C. Guenther and J. Spigarelli. Hazardous
Emission Characteristics of Utility Boilers. Midwest Research
Institute. U.S. Environmental Protection Agency Report No.
EPA 650/2-75-066. Research Triangle Park, N.C. July 1975.
2. Robinson, E. and R. C. Robbins. Sources, Abundance and Fate of
Gaseous Atmospheric Pollutants. Stanford Research Institute.
Menlo Park, California. 1968.
3. Walther, E. C. A Rating of the Major Air Pollutants and Their
Sources by Effect. JAPCA. 22(8). May 1972.
4. Development Document for Effluent Limitations Guidelines and New
Source Performance Standards for the Steam-Electric Power Generat-
ing Point Soutce Category. U.S. EPA Report NO. 44D/l-74-029a.
October, 1974.
5. Energy Use in 1974. Interior Department Preliminary Estimates.
Energy Users Report 81:201. The Bureau of National Affairs. 1975.
6. Federal Power Commission News. Washington, D.C. May 9, 1975.
7. Steam Electric Plant Factors/1974 Edition. National Coal Association,
8. McGowin, C. R. Stationary Internal Combustion Engines in the
United States. Shell Development Company, April 1973.
9. Air Quality and Stationary Source Emission Control. Report to
Congress. Committee on Public Works, Serial No. 94-4. March 1975.
10. Federal Energy Administration. Project Independence. Washington,
D.C. 1974.
72
-------
APPENDIX A
METRIC CONVERSIONS
A. CAPACITY, ENERGY, FORCE, HEAT
Multiply
By
To obtain
Btu
Btu/min
Btu/min
Btu/min
Btu/min
Btu/min
Horsepower (boiler)
Horsepower (boiler)
Horsepower-hours
Kilowatts
Kilowatts
Kilowatt-hours
Kilowatt-hours
Megawatts
Pound /hr steam
0.2520 ,
3.927 x 10~4
2.928 x 10~4
0.02356
0.01757
10-3
33,479
9.803
0.7457
56.92
1.341
3415
1.341
1360
0.454
Kilogram-calories
Horsepower-hrs
Kilowatt-hrs
Horsepower
Kilowatts
Pound/hr steam
Btu/hr
Kilowatts
Kilowatt-hours
Btu/min
Horsepower
Btu
Ho r s epower-hr s
Kilogram/hr steam
Kg/hr
Energy equivalences of various fuels:
Bituminous coal - 22.4 x 106 Btu/ton, 1971-1973
21.9 x 106 Btu/ton, 1974
Anthracite coal - 26.0 x 106 Btu/ton
Lignite coal - 16.0 x 106 Btu/ton
Residual oil - 147,000 Btu/gal
Distillate oil - 140,000 Btu/gal
Natural gas - 1,022 Btu/ft3
1 Ib of water evaporated from and at 212°F equals:
0.2844 Kilowatt-hours
0.3814 Horsepower-hours
970.2 Btu
73
-------
B. FLOW
C.
Multiply
Cubic feet /minute
Cubic feet/second
Cubic feet/second
Cubic meter/sec.
Cubic meter/sec.
Gallons /year
Gal Ions /min.
Liters/min.
Liters /min.
Million gals /day
Million gals /day
Million gals /day
Pounds of water/min.
LENGTH, AREA, VOLUME
Multiply
Acres
Acres
Acres
Acre-feet
Acre- feet
Acre- feet
Barrels-oil
Barrels -oil
Centimeters
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic meters'"
Cubic meters
Feet
Feet
By
0.1247
0.646317
448.831
22.8
8.32 x 109
10.37 x 10-6
2.228 x 10-3
5.886 x ID'4
4.403 x 10-3
1.54723
0.044
695
2.679 x lO'4
By
43,560
4047
1.562 x ID'3
43,560
325,851
1233.49
0.156
42
0.3937
2.832 x 104
1728
0.02832
0.03704
7.48052
28.32
35.31
264.2
30.48
0.3048
To obtain
Gallons/sec.
Million gals /day
Gallons /min
Million gals /day
Gallons /year
m3/day
Cubic feet/sec.
Cubic ft/sec,
Gals/sec.
Cubic ft/sec.
Cubic meters/sec.
Gal Ions /min.
Cubic ft/sec.
To obtain
Square feet
Square meters
Square miles
Cubic feet
Gallons
Cubic meters
Cubic meters
Gallons -oil
Inches
Cubic cms.
Cubic inches
Cubic meters
Cubic yards
Gallons
Liters
Cubic feet
Gallons
Centimeters
Meters
74
-------
Gallons
Gallons
Gallons, Imperial
Gallons water
. Liters
Meters
Meters
Square feet
Square feet
Square meters
Square meters
Square miles
0.1337
3.785 x 10~3
1.20095
8.3453
0.2642
3.281
39.37
2.296 x 10'5
0.09290
2.471 x 10'4
10.76
640
Cubic feet
Cubic meters
U.S. gallons
Pounds of water
Gallons
Feet
Inches
Acres
Square meters
Acres
Square feet
Acres
D. MASS, PRESSURE, TEMPERATURE, CONCENTRATION
Multiply
Atmospheres
Atmospheres
Atmospheres
Grams
Grams /liter
Grams /liter
Grams /liter
Kilograms
Parts /million
Parts/million
Pounds
Pounds of water
Pounds of water
Pounds/sq. inch
Pounds/sq. inch
Pounds/sq. inch
Temp. (°C) + 32
Temp. (°F) - 32
Tons (metric)
Tons (short)
Tons (short)
Tons (short)
By
29.92
33.90
14.70
15.43
58.417
8.345
0.062427
2.2046
0.0584
8.345
453.5924
0.01602
0.1198
0.06804
2.307
2.036
1.8
0.555
2205
2000
0.89287
0.9975
To obtain
Inches of mercury
Feet of water
Lbs/sq. inch
Grains (troy)
Grains /gal
Pounds/ 1000 gals.
Pounds /cubic ft
founds
Grains /U.S. gal
Lbs /million gal
Grams
Cubic feet
Gallons
Atmospheres
Feet of water
Inches of mercury
Temp. (°F.)
Temp. (°C.)
Pounds
Pounds
Tons ( long)
Tons (metric)
75
-------
APPENDIX B
ACRONYMS USED IN THIS REPORT
BaP Benzo(a)pyrene
BSO Benzene Soluble Organics
Btu British Thermal Units
EPA Environmental Protection Agency
FGD Flue Gas Desulfurization
FPC Federal Power Commission
kWh Kilowatt Hours
MW Megawatts
MWh Megawatt Hours
NPDES National Pollution Discharge Elimination System
NEDS National Emission Data System
PBB Polybrominated Biphenyls
PCB Polychlorinated Biphenyls
PHH Polyhalogenated Hydrocarbons
POM Polycyclic Organic Matter
SOTDAT Source Test Data System
TS Total Solids
TDS Total Dissolved Solids
TSS Total Suspended Solids
TLV Threshold Limit Value
76
-------
TECHNICAL REPORT DATA .
(Please read Jiitfjuctions on the revcnc before completing)
1. BLPORT NO.
EPA-600/2-76-04.6a
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Preliminary Emissions Assessment of Conventional
Stationary Combustion Systems; Volume I--Executive
Summary
5. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
GCA-TR-75-26-G(l)
7. AUTHOR(S)
Norman Surprenant, Robert Hall, and
Leonard M. Seale
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
GCA/Technology Division
GCA Corporation
Bedford, Massachusetts 01730
10. PROGRAM ELEMENT NO.
EHB525; ROAP AAU-002
11. CONTRACT/GRANT NO.
68-02-1316, Task 11
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
Task Final; 3/75-11/75
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES pr0ject officer for this report is R.A. Venezia, Ext 2547.
16. ABSTRACT
The report gives results of a preliminary emissions assessment of the air,
water, and solid waste pollutants produced by conventional stationary combustion
systems. It summarizes results in four principal categories: utilities (electric gen-
eration), industrial (steam generation, space heating, and stationary engines),
commercial/institutional (space heating and stationary engines), and residential
(space heating). For each principal combustion system category, it summarizes:
process types and operating efficiencies, fuel consumption, pollutant sources and
characteristics, major research and development trends, fuel consumption trends,
and technical areas where emission data are incomplete. It also summarizes the
pollutant emissions from applicable unit operations for each of 56 source classifi-
cations, using a uniform combustion source classification system.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Combustion
Utilities
Industries
Industrial Wastes
Residential Buildings
Steam Electric
Power Generation
Space Heating
Stationary Engines
Pollution Control
Stationary Sources
Emissions Assessment
Commercial/Institu-
tional
13B
21B
05C
10A
13A
21G
5. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
86
20. SECURITY CLASS (This page)
Unclassified
22. .^RICE
Form 2220-1 (9-73)
77
------- |