&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/2-79-019e
June 1979
Research and Development
Source Assessment:
Dry Bottom Industrial
Boilers Firing Pulverized
Bituminous Coal
•
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the ENVIRONMENTAL PROTECTION TECH-
NOLOGY series. This series describes research performed to develop and dem-
onstrate instrumentation, equipment, and methodology to repair or prevent en-
vironmental 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
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-79-01$e
June 1979
Source Assessment:
Dry Bottom Industrial Boilers
Firing Pulverized Bituminous Coal
by
W.R. McCurley, C.M. Moscowitz, J.C. Ochsner,
and R.B. Reznik
Monsanto Research Corporation
P.O. Box 8, Station B
Dayton, Ohio 45407
Contract No. 68-02-1874
ROAPNo. 21AXM-071
Program Element No. 1AB015
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
-------
PREFACE
The Industrial Environmental Research Laboratory (IERL) of the
U.S. Environmental Protection Agency (EPA) has the responsibility
for insuring that pollution control technology is available for
stationary sources to meet the requirements of the Clean Air Act,
the Federal Water Pollution Control Act, and solid waste legis-
lation. If control technology is unavailable, inadequate, or
uneconomical, then financial support is provided for the develop-
ment of the needed control techniques for industrial and extract-
ive process industries. Approaches considered include: process
modifications, feedstock modifications, add-on control devices,
and complete process substitution. The scale of the control
technology programs ranges from bench- to full-scale demonstra-
tion plants.
The Chemical Processes Branch of the Industrial Processes Divi-
sion of IERL has the responsibility for developing control tech-
nology for a large number of operations (more than 500) in the
chemical industries. As in any technical program, the first
question to answer is, "Where are the unsolved problems?" This
is a determination which should not be made on superficial infor-
mation; consequently, each of the industries is being evaluated
in detail to determine if there is, in EPA's judgment, sufficient
environmental risk associated with the process to indicate that
pollution reduction is necessary. This report contains the data
necessary to make that decision for air emissions, water efflu-
ents, and solid residues from dry bottom industrial boilers
firing pulverized bituminous coal.
Monsanto Research Corporation has contracted with EPA to investi-
gate the environmental impact of various industries which repre-
sent sources of pollution in accordance with EPA's responsibility
as outlined above. Dr. Robert C. Binning serves as Program
Manager in this overall program, entitled "Source Assessment,"
which includes the investigation of sources in each of four cate-
gories: combustion, organic materials, inorganic materials, and
open sources. Dr. Dale A. Denny of the Industrial Processes
Division at Research Triangle Park serves as EPA Project Officer.
In this study of dry bottom industrial boilers firing pulverized
bituminous coal, Dr. Ronald A. Venezia served as EPA Task Officer.
111
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ABSTRACT
This report describes and assesses the potential impact of air
emissions, wastewater effluents, and solid wastes resulting from
the operation of dry bottom industrial boilers firing pulverized
bituminous coal. Consuming approximately 2.3 x 107 metric tons
of such coal per year, this source type constitutes the primary
method of firing coal in industrial boilers.
Air emissions were characterized by a literature survey and a
field sampling program. Significant emissions resulting from
coal combustion were particulate matter, sulfur oxides, nitrogen
oxides, hydrocarbons, polycyclic organic materials, and a number
of elements emitted as particles and vapors. The potential
environmental impact of each emission species after passing
through state-of-the-art controls was individually assessed using
a calculated quantity known as the source severity. This quan-
tity is the ratio of the maximum ground level concentration, as
determined through dispersion equations, to a potentially hazard-
ous concentration. Species determined to have source severities
greater than 1.0 were nitrogen oxides (1.7), sulfur oxides (2.2),
and polycyclic organic materials (6.0). Estimates of the human
population around an average source in this category exposed to
a severity greater than 1.0 ranged from 1,225 persons for nitro-
gen oxides to 7,536 persons for polycyclic organic materials.
Pollutant concentrations were also measured in wastewater and
solid waste streams. Effluent source severities, defined as the
ratio of the concentration of a pollutant in the receiving water
after dispersion to a potentially hazardous concentration, were
found to be significantly less than 1.0 for most species. The
potential impact of solid waste discharges on the quality of air
and of ground and surface water was also found to be minor when
available controls are applied.
This report, submitted under Contract No. 68-02-1874 by Monsanto
Research Corporation under the sponsorship of the U.S. Environ-
mental Protection Agency, covers the period from August 1974
through June 1979.
IV
-------
CONTENTS
Preface iii
Abstract iv
Figures vi
Tables viii
Abbreviations and Symbols xi
1. Introduction 1
2. Summary 3
3. Source Description 11
Source definition 11
Steam production process 17
Combustion process 25
4. Air Emissions and Control Technology 30
Source and nature of air emissions 30
Emissions data 37
Potential environmental effects 47
Air emissions control technology 62
5. Wastewater Effluents and Control Technology 77
Sources and characteristics 77
Potential environmental effects 89
Wastewater treatment 95
6. Solid Wastes and Control Technology 96
Sources and composition 96
Disposal of waste solids 99
Potential environmental effects 103
Control of emissions and effluents at disposal
sites 105
7. Future Growth and Technology 106
8. Unusual Results 108
Boiler size distribution 108
Post-ESP sulfur oxide emissions 108
SASS train trace metal results 110
References Ill
Appendices
A. Summary of NEDS data 127
B. River flow rate data 141
-------
CONTENTS (continued)
C. Description of the sampling program 146
D. Derivation of source severity equations 166
Glossary
Conversion Factors and Metric Prefixes
VI
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FIGURES
Number
1 Fossil fuel consumption by end use .......... 2
2 Distribution of industrial boiler fuel types ..... 2
3 Distribution of coal-fired industrial boiler designs. 2
4 Simplified process schematic for industrial pulverized
bituminous coal-fired boiler ............ 18
5 Various methods of firing pulverized bituminous coal. 20
6 Combustion of a solid ................ 29
7 Distribution of boilers in this source type by design
capacity ...................... 109
VII
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TABLES
Number Page
1 States Containing >5% of the Total Number of Boilers
as Defined for this Source Category 4
2 Percent Contribution of this Source to Total State
Emissions of Criteria Pollutants 4
3 Efficiencies of Particulate Control Devices Applied to
Dry Bottom Industrial Boilers Firing Pulverized
Bituminous Coal, as Reported in NEDS 5
4 Controlled Emission Factors, Source Severities, and
Affected Populations for an Average Source 6
5 Effluent Factors, Effluent Concentrations, and Efflu-
ent Source Severities for a Combined Waste Stream
for an Average Source 9
6 Coal Capacity of Industrial Boilers 14
7 Efficiency and Load Estimates of Industrial Boilers. . 15
8 Estimated Geographical Distribution of Source Type . . 16
9 Typical Characteristics of Boiler Water Supplies ... 21
10 Water Impurities, Problems, and Treatment 22
11 Classification of Coals by Rank 26
12 Arithmetic Mean of Proximate and Ultimate Analyses and
Elemental Composition for Appalachian Coal Region
Samples 2g
13 Classification of Elements According to Their Parti-
titioning Behavior 32
14 Emission Factors for Industrial Dry Bottom Boilers
Firing Pulverized Bituminous Coal 39
15 SASS Particle Size Data Reported as a Percent of
the Total Particulate Mass Emissions 41
16 Sulfur Oxides and Particulate Sulfate Emission Factors 42
17 Controlled POM Emission Factors. ...... 44
18 Detection Limits for PCB Compounds Expressed as
Minimum Detectable Emission Factors 45
viii
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TABLES (continued)
Number
19 Percentage of Each Element Entering the Boiler Found
in the Flue Gas Before and After Controls 46
20 Pollutant Severity Equations for Elevated Sources. . .49
21 Ambient Air Quality Standards for Criteria Pollutants. 50
22 Threshold Limit Values Used for Noncriteria Pollutants 52
23 Emission Rates and Source Severities of an Average
Plant 54
24 Emission Rates and Source Severities of the Smallest
Plant 56
25 Emission Rates and Source Severities of the Largest
Plant 58
26 Affected Population for Emissions with a Source
Severity Greater than 0.05 and 1.0 60
27 Total Emissions and Percent Contributions to State
Emission Burdens from Dry Bottom Industrial Boilers
Firing Pulverized Bituminous Coal 61
28 State-By-State Summary of Emission Controls Data in
NEDS for Dry Bottom Industrial Boilers Burning
Pulverized Bituminous Coal 63
29 Distribution of Control Types for Those Dry Bottom
Industrial Boilers Burning Pulverized Bituminous
Coal Having Controls 65
30 Design and Reported Efficiencies of Commercial
Particulate Controls Applied to Industrial Sized
Boilers 65
31 U.S. Industrial Boiler S02 Control Systems 69
32 Descriptions of Industrial SO2 Scrubbers 70
33 Chemical Additives Used in Steam Plants for Various
Applications 78
34 Pollutants and Pollutant Parameters Associated With
Various Boiler Waste Streams 79
35 Measured Values for Pollutant Concentrations and Water
Quality Parameters for Water Source and Wastewater
Streams gg
36 Elemental Concentrations Measured in Water Source and
Wastewater Streams 87
37 Estimated Discharge Rates of Wastewater Streams. ... 88
ix
-------
TABLES (continued)
Number
38 Effluent Factors for Combined Waste Stream ...... 88
39 Effluent Hazard Factors for Water Pollutants and
Water Quality Parameters .............. 93
40 Effluent Source Sevrities for an Average Source. ... 94
41 Distribution of Coal Ash by Boiler Type ........ 96
42 Typical Physical Properties of Fly Ash from Pulverized
Coal Fired Plants ...... ............ 97
43 Chemical Constituents of Coal Ash ........... 98
44 Mineral Phases Found in Coal Ash ........... 98
45 Trace Elements Present in Raw Sludge and in Leachate
from Sludge after Fixation ............. 101
46 Results of the Ash Leachate Measurement ........ 104
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ABBREVIATIONS AND SYMBOLS
a. . .
A
AA
A. . .
Aa
AAQS
AR
ASTM
BOD
B
, 2
n
CC
CD
CM
CO
COD
DC
DP
e
EF
ESP
exp
F
Fe
FF
FGD
FGT
FMZ
GC
GC-MS
H
ICAP
LC5o (96-hr)
M
NEDS
NPDES
constants used in dispersion equations
ash percent of coal
atomic absorption
atmospheric stability classes
area containing the affected population, km2
ambient air quality standard
ratio Q/aciru
American Society for Testing and Materials
biological oxygen demand
ratio -H2/2c2
confidential
organic molecules containing from 1 to n carbon
atoms
centrifugal collector
concentration of a pollutant in an effluent, g/m3
combustion modification
carbon monoxide
chemical oxygen demand
direct current
population density, persons/km2
2.72
emission factor, g/kg
electrostatic precipitator
exponent of e
hazard factor, g/m3
effluent hazard factor/ g/m3
fabric filter
flue gas desulfurization
flue gas treatment
fraction of river flow in a mixing zone
gravity collector
gas chromatography-mass spectroscopy
height of emission release, m
inductively coupled argon plasma
concentration lethal to 50% of a group of test
organisms in a 96-hr period, g/m3
molar
National Emissions Data System
nitrogen oxides
National Pollutant Discharge Elimination System
XI
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ABBREVIATIONS AND SYMBOLS (continued)
NSPS — new source performance standards
OPEC — oil producing and exporting countries
P1 — total affected population
PCB — polychlorinated biphenyls
pH — negative log of the hydrogen ion concentration
POM — polycyclic organic materials
ppm — parts per million
Q — emission rate, g/s
R — rate of fuel flow
S — percent of sulfur content of coal
sa — source severity of air pollutant emissions
SM[Z ~ effluent source severity after the mixing zone
SASS — source assessment sampling system
SBD — effluent source severity before dilution
sco ~~ source severity of carbon monoxide emissions
se " source severity of an effluent species
SHC ~ source severity of hydrocarbon emissions
SMZ ~" effluent source severity in the mixing zone*
SN02 "" source severity of nitrogen dioxide emissions
SO — sulfur oxides
a
SP "' source severity of particulate emissions
SS02 ~~ source severity of sulfur dioxide emissions
t — averaging time, min
fco "" short-term averaging time, (3 min)
T.C. — thermocouple
TDS — total dissolved solids, g/m3
TLV ~ threshold limit value, g/m3
TS — total solids, g/m3
TSS — total suspended solids, g/m3
u — wind speed, m/s
JL -- average wind speed, m/s
uses — United States Geological Survey
vr — river flow rate, m3/s
VR — minimum river flow rate, m3/s
WS — wet scrubber
x — downwind emission dispersion distance from source
of emission release, m
XAD-2 — resin used for trapping organic emissions
Y — horizontal distance from centerline of disper-
sion, m ^
xn
-------
ABBREVIATIONS AND SYMBOLS (continued)
TT — 3.1416
a — standard deviation of horizontal dispersion, m
a — standard deviation of vertical dispersion, m
z
x" — time-averaged ground level concentration of an
emiss ion, g/m3
Y — instantaneous maximum ground level concentration,
max g/m3
"\ — time-averaged maximum ground level concentration,
max
Xlll
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SECTION 1
INTRODUCTION
The purpose of this study was to characterize air emissions,
water effluents, and solid residues resulting from the combustion
of pulverized bituminous coal in industrial dry bottom boilers.
The report contains a source description that defines process
operations, process chemistry, plant capacity, and source loca-
tions. The multimedia emissions characterization identifies all
emission points and emission species, determines their emission
rates, and evaluates the potential environmental effect due to
their release. Present and emerging control technologies are
also considered. The final sections of the report discuss the
growth and nature of the source type and unusual results of this
study.
A general indication of the size and position of this source type
within all combustion sources is shown in Figures 1 through 3 (1).
From Figure 1, industrial combustion is the second largest con-
sumer of fossil fuel, representing 29% of national fossil fuel
consumption. Within the industrial boiler sector, coal is the
third largest energy source, representing 16% of industrial fuel
consumption. All three coals (anthracite, bituminous, and lig-
nite) are used in industrial boilers, but bituminous is the
primary fuel (96%). Within bituminous coal-fired industrial
boilers, pulverized dry bottom units represent nearly half (49%)
of all fuel consumption, followed in order of decreasing fuel
consumption by stokers, pulverized wet bottom units, and cyclones
Overall this source type consumes 7.8% of the fossil fuel used in
industrial boilers and 2.3% of the total quantity of fossil fuels
used for the generation of power or heat in the United States (1)
(1) Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and
C. Young. Preliminary Environmental Assessment of Conven-
tional Stationary Combustion Systems; Volume II, Final Report
EPA-600/2-76-046b (PB 252 175)a, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, March 1976
557 pp.
This number designates the National Technical Information System
(NTIS) access number.
-------
ui 70
o
£ 60
=j
erf 50
£ 40
S 30
I 20
o
g 10
D_
0
39%
29%
21%
11%
ELECTRIC INDUSTRIAL COMMERCIAL/ RESIDENTIAL
UTILITY INSTITUTIONAL
Figure 1
70 r
Fossil fuel consumption by end use (1) .
o
60
50
40
30
10
0
r 61%
-
-
20%
16%
3%
1 1
o
I
GAS OIL COAL REFUSE
Figure 2. Distribution of industrial boiler fuel types (1)
60
50
40
30
20
10
0
-
-
-
-
49%
10%
3 fit
70
1 — 1
38%
PULVERIZED PULVERIZED CYCLONE STOKER
DRY BOTTOM WET BOTTOM
Figure 3.
Distribution of coal-fired industrial boiler designs
2
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SECTION 2
SUMMARY
This document characterizes and assesses the potential impact of
air emissions, wastewater effluents, and solid residues released
to the environment by dry bottom industrial boilers firing pul-
verized bituminous coal. This source is defined as all boilers
(steam generators) that meet each of the following criteria:
• The primary fuel is pulverized bituminous coal.
• The operating temperature of the furnace is kept below the
ash fusion temperature so that ash remaining in the furnace
can be removed as a dry powder (dry bottom) .
• The boiler is owned and operated by the industrial sector to
produce steam for use at an industrial site.
The source category consumes 685 x 106 GJ/yr (approximately
2.3 x 107 metric tonsa/yr) of bituminous coal and represents
about 9% of the total steam-generating capacity of U.S. industry
and approximately 49% of the industrial steam generated by coal
combustion. States containing >5% of the boiler population are
listed in Table 1. Capacities of the individual boilers considered
;^S/vaSSeSSment range from 1 GJ/nr to 1'900 GJ/yr and average
GJ/nr.
Over 99% of the air emissions result from coal combustion in the
furnace and are emitted from the boiler stack. Other emissions
arise from coal storage and handling, cooling towers when used,
and ash handling and disposal. Major emissions are the criteria
pollutants; particulates, sulfur oxides (SOX) , nitrogen oxides
(NOx) , hydrocarbons, and carbon monoxide (CO) . Polycyclic organ-
ic materials (POM) are among the hydrocarbon species emitted In
addition trace elements are emitted as part of " the particulate
or in the vapor phase. The percent contribution of this source
to the total state emission burdens of criteria pollutants are
shown in Table 2 for the states included in the National Emis-
sions Data System (NEDS) file.
1 metric ton = 106 grams; conversion factors and metric system
prefixes are presented at the end of this report. system
-------
TABLE 1. STATES CONTAINING >5% OF THE TOTAL NUMBER
OF BOILERS AS DEFINED FOR THIS SOURCE CATEGORY
State
Percentage
of boilers
Percentage of
fuel consumption
Ohio
Pennsylvania
North Carolina
Michigan
New York
Illinois
Tennessee
Virginia
Indiana
Iowa
19
13
9.5
6.6
6.6
6.4
5.9
5.5
5.0
5.0
15
9
2
10
4
7
3
4
8
2
Total
82.5
64
TABLE 2. PERCENT CONTRIBUTION OF THIS SOURCE TO TOTAL
STATE EMISSIONS OF CRITERIA POLLUTANTS
]
State
Alabama
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Massachusetts
Michigan
Minnesota
Missouri
New York
North Carolina
Ohio
Oregon
Pennsylvania
Tennessee
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Percent contribution
Particulate
matter
<0.01
0.5
4.7
2.6
0.2
1.8
<0.01
0.3
0.1
0.7
0.8
0.2
3.7
4.3
2.4
2.6
0.3
2.0
3.6
7.8
8.5
0.2
0.7
1.8
0.5
S0x
0.2
1.2
3.3
2.0
1.0
9.1
0.3
0.6
4.1
0.06
2.1
0.2
0.6
7.7
4.9
2.8
3.5
2.5
1.9
1.1
10.5
0.1
0.9
1.1
3.6
N0x
0.3
0.2
3.2
0.8
0.5
3.6
0.02
0.4
2.3
0.03
0.9
0.08
0.4
1.1
2.3
1.7
0.6
0.4
2.9
1.6
5.1
0.05
1.0
0.3
2.5
Hydro-
carbon
<0.01
<0.01
0.02
<0.01
0.2
0.1
<0.01
<0.01
0.02
<0.01
0.2
<0.01
<0.01
<0.01
0.09
0.01
<0.01
0.05
0.08
0.03
0.09
<0.01
0.08
0.02
0.01
CO
<0.01
<0.01
<0.01
<0.01
0.01
0.01
<0.01
<0.01
<0.01
<0.01
0.04
<0.01
<0.01
<0.01
0.04
<0.01
<0.01
0.06
0.04
0.02
0.05
<0.01
0.04
0 .02
<0.01
-------
Particulate emissions are controlled on approximately 62% of the
sources according to the NEDS file for this source type. Partic-
ulate controls applied to these boilers are centifugal collectors
(57% of controls), electrostatic precipitators (26%), fabric
filters (7%), gravity collectors (6%), and wet scrubbers (4%).
Collection efficiencies of these devices reported to NEDS by
industry are shown in Table 3. It should be noted that the upper
.range limits reported for centrifugal and gravity collectors
appear to be unrealistically high, and thus may be in error.
About 14% of the boilers use multiple particulate controls, and
about 1% are equipped with SOX controls. Controls for NO* emis-
sions are under development.
TABLE 3. EFFICIENCIES OF PARTICULATE CONTROL DEVICES APPLIED
TO DRY BOTTOM INDUSTRIAL BOILERS FIRING PULVERIZED
BITUMINOUS COAL, AS REPORTED IN NEDS
Collection efficiencies, %~
Control device
Centrifugal collector
Gravity collectors
Electrostatic precipitator
Fabric filters
Wet scrubbers
Range
25.
25.
71.
46.
60.
0
0
9
5
0
to
to
to
to
to
99.
85.
99.
99.
99.
39
0
5
5
0
Average
79
56
96
91
81
Upper end of range is high and may be in error.
In order to evaluate the potential environmental effect of air
emissions from an average source in this category, a source
severity, S, was defined as the ratio of the time-averaged
maximum ground level concentration_(x"max^ to an aPPr°priate
hazard factor (F). The values of xmax were calculated from
accepted plume dispersion equations and controlled emission
factors determined by sampling an industrial boiler equipped
with an electrostatic precipitator. The hazard factor is de-
fined as the primary ambient air quality standard in the case of
criteria pollutants (particulate matter, SOX, NOX, CO, and hydro-
carbons) and as a reduced threshold limit value (TLV®), F = TLV
x 8/24 x 1/100, for other pollutants. The factor 8/24 corrects
for a 24-hr exposure while 1/100 is a safety factor.
Controlled emission factors and source severities calculated for
an average size unit in this category (222 GJ/hr) are shown in
Table 4. No CO was found at a detection limit of 1 ppm and no
polychlorinated biphenyl (PCB) compounds were found in any of the
air, water, or solid samples at a detection limit of 2.5 ug/kg.
-------
TABLE 4. CONTROLLED EMISSION FACTORS, SOURCE SEVERITIES,
AND AFFECTED POPULATIONS FOR THE AVERAGE SOURCE
(222 GJ/hr)a
Emission species
Particulate matter
NOx
SOx
Sulfate
Hydrocarbons
POM (total)
POM (carcinogenic)
Elements :
Aluminum
Arsenic
Antimony
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holumium
Iodine
Iridium
T 1_ 1-l-L
Iron
Lanthanum
Lead
Lithium
Lutenium
Magnesium
Manganese
Mercury
Molybdenum
Neodymium
Nickel
Niobium
Controlled
emission
factor,
g/kg of coal
0.16Ab
8.2C
19Sc»d
1.8 x 10-a
2.5 x 10-ac
1.5 x 10-3
1.1 x lO-3
2.2 x 10-1
1.5 x 10-3
1.6 x 10-a
4.1 x lO-3
2.5 x lO-8
* f
2.9 x 10-af
1.1 x 10-af
4.8 x 10-*
4.5 x 10-a
1.4 x 10-*e
2.5 x 10-**
7.3 x 10~if
2.0 x 10-39
1.7 x 10-3
2.8 x 10-3
1.4 x 10~3f
2.6 x I0~*f
5.9 x 10-8$
7.8 x 10-a*
1.0 x lO-3*
6.5 x 10-3*
4.8 x 10-3*
<1.0 x 10~*
1.2 x 10-8?
2.1 x 10-**
1.1 x 10-3*
<2.0 x 10-**
1.9 x 10-if
9.3 x 10-»e
2.0 x lO-3,
2.7 x 10-a*
1.2 x 10-**
2.0 x 10-a
1.6 x 10-a
5.0 x lO-9
3.1 x 10-3*
1.2 x 10-a*
1.5 x 10-39
5.4 x 10-8e
Source
severity
1.2 x 10-1
1.7
2.2
9.8 x 10-a
4.0 x 10-3
4.1 x 10-a
6.0
1.2 x 10-1
1.6 x 10-a
1.7 x 10-1
4.4 x 10-a
6.8 x 10-a
5.4 x lO-7
1.6 x 10-a
8.5 x 10-a
5.2 x 10-a
4.9 x 10-a
7.6 x 10-8
6.8 x 10~*
5.7 x 10-i
1.1 x 10-1
9.2 x 10-a
1.5 x 10-a
7.6 x 10-*
1.4 x 10-*
3.2 x 10-«
2.1 x 10-1
5.4 x 10-*
3.5 x 10-3
2.6 x 10-3
5.4 x lO-5
1.3 x 10-*
1.1 x 10-*
6.0 x 10-3
1.1 x 10-*
2.1 x 10-1
5.0 x 10" °
7.2 x 10-a
1.5 x 10-a
6.5 x lO-8
1.1 x 10-a
1.7 x 10-a
5.4 x 10-3
3.4 x 10-3
6.5 x 10-3
8.1 x 10-a
2.9 x 10-8
Affected population
for Sa>1.0
cl
0
1,200
2,200
0
0
0
7,500
0
0
0
o
o
0
o
o
0
o
V
n
\J
o
\J
0
o
o
0
0
0
0
0
0
0
o
0
0
0
0
o
0
0
0
0
0
0
0
0
0
0
0
for Sa>0.05
2,500
42,000
63,000
1,900
0
0
190,000
2, 500
0
3, 900
0
1,000
0
o
1, 500
560
o
0
\J
o
15,000
2,200
1,700
0
0
0
0
5,000
0
0
o
0
0
0
0
o
5,000
1,200
0
0
0
0
0
0
0
1,400
0
(continued)
-------
TABLE 4 (continued)
Emission species
Osmium
Palladium
Phosphorus
Platinum
Potassium
Praeseodymium
Rhenium
Rodium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
Controlled
emission
factor ,
g/kg of coal
<2
<1
1
<3
2
2
<2
<1
3
<1
1
5
1
2
8
5
4
9
3
3
1
4
<1
1
9
2
1
4
9
1
4
4
.0
.0
.7
.0
.3
.1
.0
.0
.7
.0
.9
.1
.6
.7
.5
.5
.4
.5
.4
.2
.0
.8
.0
.3
.9
.8
.4
.0
.8
.1
.2
.0
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10-*
10-*
10-2
10-*
10-2
10-3
10-*
10-*
io-a
10-*
10-9
10-»
10-3
10-1
10-*
IO-2
lO-3
10-o
10-*
10-*
10-*
10-*
10-*
io-a
lO-3
10-*
10-3
10-3
10-*
10-*
lO-3
10-*
f
f
f
i
f
i
e
e
e
e
e
e
t
i
e
e
e
Soui
sevex
5
5
9
8
6
1
1
5
2
5
1
2
4
1
4
1
2
1
1
1
5
2
5
7
5
1
3
4
5
6
4
5
.4
.4
.2
.1
.2
.1
.1
.4
.0
.4
.0
.8
.3
.5
.6
.5
.4
.0
.8
.7
.4
.6
.4
.0
.4
.5
.8
.3
.3
.0
.6
.4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Affected population
SJy f°r V1'0
10-1
10-*
10-2
10-1
10-a
10-3
10-*
lO-3
10-*
io-8
10-s
10zs
10~a
10-1
10-1
10-1
10-3
io-»
lOra
10-*
lO-3
10-s
10-°
lO-3
lO-3
lO-3
ID'2
IO-3
10-*
10-*
ID"3
10-*
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
for S >0.05
ci
14,000
0
I, 700
22,000
870
0
0
0
0
0
0
0
0
3,200
12,000
3,200
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Based on MRC sampling measurements made at a 130 GJ/hr industrial boiler
and on literature data.
'percent ash content of coal.
'Uncontrolled.
Percent sulfur content of coal.
Estimate based on the partitioning behavior of these elements, value = 1%
of the average concentration in U.S. bituminous coal.
Estimate based on 100% emission of the average concentration of this
element in U.S. bituminous coal.
-------
Another measure of potential environmental impact is the popula-
tion which may be affected by emissions from an average source.
The affected population is defined as the number of persons living
in the area around an average size boiler where x~ (time-averaged
ground level concentration) divided by F is greater than 1.0 or
greater than 0.05. A x/F value of 1.0 indicates exposure to a
potentially hazardous concentration of a pollutant; the value of
0.05 allows for inherent uncertainties in measurement techniques,
dispersion modeling, and health effects data. Plume dispersion
equations are used to find this area, which is then multiplied
by an average population density to determine the affected popu-
lation. The average population around an industrial boiler in
2
-/° Persons/k*2 - The populations affected by
than
*"
one nii are
through cooling water for steam condensation and equipment
^.^^^
pneumatic ash transport systems, and runof? f^oTcoafstSrage
in
gu fo -
source severitv
-------
TABLE 5. EFFLUENT FACTORS, EFFLUENT CONCENTRATIONS,
AND EFFLUENT SOURCE SEVERITIES FOR A
COMBINED WASTE STREAM FOR AN AVERAGE SOURCE
(222 GJ/hr)a
Pollutant
Effluent factor,
g/kg of coal
Concentration
in effluent,
g/m3
Effluent source
severity
Acidity (as CaCO3)
Alkalinity (as CaCO3)
Ammonia
Hardness (as CaC03)
Nitrate
Phenol
PCB
POM
Sulfate
Sulfite
TDS
TSS
TS
Elements:
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
7.
5.
1.
1.
8.
2.
9.
2.
2.
7.
2.
2.
2.
8.
1.
6.
2.
1.
3.
7.
1.
4.
8.
6.
2.
1.
1.
4.
4.
1.
5.
4.
3.
4.
3
1
1
4
8
0
2
1
5
1
8
4
6
1
1
2
8
0
4
2
1
5
5
1
8
8
5
0
2
5
5
9
4
4
x
xb
0D
4.
x
x
OK
ob
xb
0D
x
x
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
x.
ob
X
X
X
X
X
X
4.
X
X
X
X
xb
0D
IO-3
10"1
2
io-2
10"*
io-1
IO1
io-1
IO1
io-2
10-*
10-*
io-3
io-5
10-*
io-5
io-1
10-*
10-*
10-*
io-3
io-3
io-1
io-5
10-*
io-3
io-2
io-5
10-*
10-*
5
IO-2
10-*
10-*
10"3
10-*
3.
<5.
2.
9.
4.
<
1.
6.
1.
1.
4.
1.
1.
5.
7.
4.
1.
6.
2.
7.
3.
5.
<2.
4.
1.
9.
2.
2.
3.
1.
3.
3.
2.
<
4.
3
0
8
7.
0
8
3
1
4
6
7
8
1.
7
3
3
1
8
7
2
4.
0
0
6
0
0
1.
2
9
6
8
0
0
4
2
2.
9
. b •
8
x
x
X
3
X,.
c
_c
X
0
X
X
X
X
X
X
6
X
X
X
X
X
X
X
7
X
X
X
X
X
9
X
X
X
X
X
X
X
X
2
X
0
IO2
io-2
IO3
io-3
IO2
10*
IO2
10*
10 1
io-1
io-1
io-2
io-1
io-3
IO2
io-1
io-2
io-1
io-1
IO2
io-2
io-3
io-1
IO1
io-3
IO1
io-1
IO3
IO1
io-1
io-1
io-1
2.
2.
4.
8.
1.
2.
6.
3.
6.
2.
2.
4.
1.
1.
8.
8.
3.
4.
1.
2.
1.
1.
7.
1.
1.
1.
1.
1.
1.
6.
1.
5.
4.
5.
4.
7.
9 x
0 x
0
5 x
9 x
1 x
0
0
8 x
0
5 x
0 x
2 x
4 x
5 x
5 x
9 x
9 x
7 x
9 x
1 x
5 x
0 x
7 x
9 x
7 x
0 x
4 x
0
7 x
8 x
4 x
2 x
3 x
8 x
5 x
0 x
4 x
2 x
9 x
1 x
0
io-°
10-*
10-*
10~6
10-*
io-5
10-*
10-*
10-*
io-5
io-=
io-5
io-5
10~5
io-6
io-6
io-3
io-5
10-*
io-6
10-*
10-*
io-3
io-5
io-5
io-=d
10"1
io-5
io-=
10"5
10-*
io-7
10-*
io-6
io-5
io-7
Based on MRC sampling measurements made at a 130 GJ/hr industrial boiler.
Not detected in any of the waste streams.
Detection limits vary depending on the compound of interest but are in
the microgram per liter range.
Based on the hazard factor for elemental phosphorus, although the most
likely form is relatively nontoxic phosphate.
-------
are es-
source type is dependent Sn thJ STS of solid wastes from this
characteristics of the disposal si^i •I^th°d US6d and the
Studies show that the potential eff^i- Whl$h1are variable.
due to the ion exchange «£cUy ^f most°L ^achi^ are minimal
controls are available in the for™ «? u ls and that adequate
and/or the use of linld Sisposf? arefs? ^ SlUdge fixation
in this assessment
1990. Forecasts beyond thi 0 4*°%
10
-------
SECTION 3
SOURCE DESCRIPTION
The source type covered in this assessment is entitled dry bottom
industrial boilers firing pulverized bituminous coal. This
section defines the source type, characterizes the United States
population of the source, and describes the processes of steam
generation and combustion as they relate to the source.
SOURCE DEFINITION
For the purposes of this study, dry bottom industrial boilers
firing pulverized bituminous coal are defined as all boilers
(steam generators) which meet each of the following criteria:
• The primary fuel is pulverized bituminous coal.
• The operating temperature of the furnace is kept below
the ash fusion temperature so that ash remaining in the
furnace can be removed as a dry powder (hence the term
dry bottom).
• The boiler is owned and operated by the industrial sector
to produce steam for use at an industrial site.
Bituminous coals include both bituminous and subbituminous coal
ranks as defined by the American Society for Testing and Mate-
rials (2). Both coal types are considered together because the
coal production and consumption data utilized in this report are
generally reported as bituminous coal.
Feed coal for this source type is pulverized into a fine powder,
70% of which will pass through a 200-mesh screen (3). Pulveriz-
ing coal facilitates injection into the boiler and mixture with
combustion air for better combustion. For systems of this type,
secondary fuels such as natural gas or fuel oil are often used
during start-up to maintain stable ignition until operating
temperatures are reached.
(2) Standard Specification for Classification of Coals by Rank,
Designation D 388-66 (Reapproved 1972). In: 1976 Annual
Book of ASTM Standards, Part 26: Gaseous Fuels; Coal and
Coke; Atmospheric Analysis. American Society for Testing
and Materials, Philadelphia, Pennsylvania, 1976. pp. 211-214
(3) The Study of Electricity, Your Trip Through Frank M. Tait
Station. The Dayton Power and Light Co., April 1964. 22 pp.
11
-------
The word "boiler" refers, in a strict sense, to the pressure ves-
sel in which water is heated and/or converted to steam. In this
study, the term is used to denote a complete system including all
of the process operations and onsite facilities involved in the
operation of external combustion, dry bottom industrial boilers
firing pulverized bituminous coal, with one exception. Coal
storage piles have already been assessed as an emission source
(4) and therefore are not considered here. Support facilities
and operations addressed in this source assessment include:
boiler feedwater treatment, fuel and ash conveying, air and water
pollution control, and solid waste disposal.
Source Inventory
A complete national inventory for industrial dry bottom boilers
firing pulverized bituminous coal, as defined in this study,
is not available. Consequently, the boiler population must be
estimated from the available data using various assumptions.
This is a difficult task because of the conflicting information
in the literature.
Industrial boiler populations have been estimated in a number of
reports; however, the estimates have varied because of the dif-
ferent assumptions used (1,5-7). In addition, these current
population estimates contain many inconsistencies. For example,
an EPA report prepared by GCA/Technology Division (1) estimates
a fuel consumption of 79 TJ/hr with a design capacity of
348 TJ/hr steam for industrial bituminous pulverized dry bottom
boilers. If the boiler efficiency is 90%, then the utilization
(4) Blackwood, T. R., and R. A. Wachter. Source Assessment:
Coal Storage Piles. EPA-600/2-78-004k (PB 284 297), U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina, May 1978. 98 pp.
(5) NEDS Condensed Point Source Listing for Particulate for all
Values Greater than or Equal to 100 Short Tons of Emissions
Per Year: SCC 1-02-002-02, SCC 1-02-002-08, SCC 1-02-002-12.
Generated by U.S. Environmental Protection Agency, Durham,
North Carolina, May 20, 1977.
(6) Barrett, R. E., A. A. Putnam, E. R. Blosser, and P. W. Jones.
Assessment of Industrial Boiler Toxic and Hazardous Emis-
sions Control Needs, Draft Report. Contract 68-02-1323,
Task 8, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, August 1974. 18 pp.
(7) Putnam, A. P., E. L. Krapp, and R. E. Barrett. Evaluation
of National Boiler Inventory. EPA-600/2-75-067 (PB 248 100)/
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, October 1975. 54 pp.
12
-------
factor must be 20%. Based on a study by Ehrenfeld, et al (8),
a utilization of 20% is typical of industrial boilers firing less
than 106 GJ/hr. However, another reference (9) states that
below 106 GJ/hr, stokers are more economical than pulverizers.
Thus one report predicts a 20% utilization for this source cate-
gory, while other evidence contradicts it.
A report prepared for the EPA by Battelle (7) estimates an indus-
trial pulverized coal capacity of 259 TJ/hr, and fuel consumption
of 139 TJ/hr, or a utilization of 60%, assuming 90% boiler effi-
ciency. These estimates are based on extrapolation of NEDS data
which assumes that with decreasing source size, NEDS misses a
greater percentage of sources. This procedure magnifies the
number of small industrial pulverized coal boilers and yields an
estimate that approximately 25% of boiler capacity and 85% of
boilers on a number basis are below 106 GJ/hr. This conclusion
is likewise inconsistent with that of Babcock & Wilcox who state
that stokers are more economical in the small size range.
Furthermore, a 1974 Bureau of Mines Mineral Industrial Survey
(10) estimates an allotment of 64 x 106 metric tons/yr of coal
to "Retail Dealers and All Others" (excluding electricity gener-
ation, coke plants, and railroad fuel), which corresponds to
191 TJ/hr (using a heating value of 26.1 GJ/metric ton).
Battelle's estimated pulverized industrial coal consumption of
139 TJ/hr accounts for nearly all of this coal, and their esti-
mate of industrial stoker firing (198 TJ/hr) by itself exceeds
the Bureau of Mines estimate.
Personal communication with the authors of the above references
did not resolve the inconsistencies. In order to proceed with
this assessment, available information was compiled and a range
of possible populations was generated. Derivation of the
extremes of the ranges follows. Other populations within the
range can be derived by utilizing various combinations of the
estimates and assumptions.
(8) Ehrenfeld, E. R., R. H. Bernstein, K. Carr, J. C. Goldfish,
R. G. Orner, and T. Parks. Systematic Study of Air Pol-
lution from Intermediate Size Fossil-Fuel Combustion
Equipment, Final Report. APTD 0924 (PB 207 110), U.S.
Environmental Protection Agency, Cincinnati, Ohio, July
1971. 241 pp.
(9) Steam/Its Generation and Use, 38th Edition. Babcock &
Wilcox, New York, New York, 1972.
(10) Mineral Industry Surveys, Bituminous Coal and Lignite Dis-
tribution, Calendar Year 1974. U.S. Department of the
Interior, Bureau of Mines, Washington, D.C., April 18, 1975.
53 pp.
13
-------
Boiler Population—
The number of industrial bituminous pulverized dry bottom boilers
is generated based on extrapolation of NEDS data, and ranges from
560 sources to 3,270 sources. A NEDS output of 20 May 1977 (5)
listed 440 industrial bituminous pulverized dry bottom boilers.
Because NEDS is not complete, fuel consumption data were used to
estimate the total number of sources. One reference estimated
that 21% of the industrial bituminous coal is consumed in states
having no listings in NEDS (1). If it is assumed that NEDS
missed 21% of the sources, the total boiler population is 560.
Battelle's estimate of NEDS inadequacies as a function of
capacity yielded an estimated 3,847 industrial pulverized coal
sources (7). The GCA/Technology Division report assumed that all
industrial pulverized coal fired is bituminous (1). Estimates of
the split between wet and dry bottom boilers range from 80% to
92% dry. A value of 85% was used to arrive at an upper limit of
3,270 industrial bituminous pulverized dry bottom boilers.
Fuel Consumption—
Fuel consumption estimates range from 686 PJ/yr to 1,815 PJ/yr,
with the lower number taken directly from the GCA Technology
Division report for industrial bituminous pulverized dry bottom
boilers (1). The high estimate is derived from GCA and Battelle
input. GCA/Technology Division estimated (based on Battelle and
Research Triangle Institute estimates) that coal fired industrial
boiler capacity is 750 TJ/hr (see Table 6). Battelle estimated
the percentage of this industrial coal fired capacity that is
pulverized (7) (see Table 6). Combining both estimates yields
an industrial pulverized coal capacity estimate of 454 TJ/hr.
Assuming that all industrial pulverized coal fired is bituminous,
«b% of it in dry bottom furnaces, as before, yields an industrial
pulverized bituminous dry bottom boiler capacity of 380 TJ/hr.
TABLE 6. COAL CAPACITY OF INDUSTRIAL BOILERS (1,7)
Boiler size,
GJ/hr
Coal capacity,3 Percent
TJ/hr
Pulverized
coal
capacity,
11 to 21
21 to 53
53 to 106
106 to 211
211 to 528
>528
Total
11
32
74
137
306
56
306
120. 77 148
750 454
Includes boilers capable of burning a secondary fuel.
14
-------
Efficiency and load estimates from Table 7 were used to obtain
fuel consumption (8).
TABLE 7 EFFICIENCY AND LOAD ESTIMATES
OF INDUSTRIAL BOILERS (8)
Boiler size,
- • " Load/ %
<106
106 to 264
>264
77
83
89
21
35
55
. _____ •
The resulting fuel consumption represents the high end of the
consumption estimates, or 1,815 PJ/yr.
Average Boiler Size
Because the source population is defined by a range, the Average
boiler size can also be expressed as a range depending on which
population is used. For this study, the average size was deter
mined from the boiler listing in NEDS, and was found to be
222 GJ/hr. The average stack height, based on a report by
Paddock and McMann (11), was 45.7 m.
Geographical Distribution
Estimated geographical distributions of industrial dry bottom
boilers firing pulverized bituminous coal according to fuel
usage and boiler population were obtained from References 1 and
5, respectively. These are shown in Table 8 as a percentage of
the total fuel usage and boiler population for this source type
on a state-by-state basis. The two listings do not agree com-
pletely because the NEDS list does not include all of the smaller
boilers, as discussed earlier in this section.
A listing of individual source sites from NEDS is. 9^ in
Appendix A. industrial boilers are concentrated in the major
industrial states, and they tend to be located in large cities
and along major waterways.
(11) Paddock R E., and D. C. McMann. Distributions of Indus-
tritl and Commercial-Institutional External Combustion
BoUers? EPA-650/2-75-021 (PB 241 195), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
February 1975. 455 pp.
15
-------
TABLE 8. ESTIMATED GEOGRAPHICAL DISTRIBUTION OF SOURCE TYPE
Percent of source
State population (5)
Alabama 0.2
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia 1.4
Idaho 1.8
Illinois 6.4
Indiana 5.0
Iowa 5.0
Kansas 0.2
Kentucky 1.6
Louisiana
Maine
Maryland 0.9
Massachusetts 0.2
Michigan 6.6
Minnesota 0.5
Missouri 1.8
Montana
Percent of fuel Percent of source Percent of fuel
consumption (1) State population (5) consumption (1)
4
1
0.2
<0.1
<0.1
1
<0.1
1
1
1
0.5
7
8
2
1
3
<0.1
<0.1
1
<0.1
10
2
2
0.5
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York 6.6
North Carolina" 9.5
North Dakota
Ohio 19
Oklahoma
Oregon 0.7
Pennyslvania 13
Rhode Island
South Carolina
South Dakota
Tennessee 5 . 9
Texas
Utah 1.4
Vermont
Virginia 5.5
Washington 0.2
West Virginia 4.3
Wisconsin 2.0
Wyoming 0.5
1
0.2
<0.1
0.1
<0.1
4
2
1
15
<0.1
_,
9
<0.1
2
1
3
0.2
1
<0.1
4
0.4
7
4
0.4
Note.—Blanks indicate no sources were included in the NEDS file for these states.
-------
STEAM PRODUCTION PROCESS
A simplified process schematic of an industrial dry bottom boiler
firing pulveruzed bituminous coal is presented in Figure 4. In
general, coal is pulverized, mixed with primary combustion air,
and fed to a burner. Secondary combustion air is introduced via
the burner, and the resulting mixture is injected into the fur-
nace where it is ignited and burned. Heat generated by combus-
tion is transferred to boiler feedwater through tubes that make
up the furnace walls. Steam is removed from the boiler tubes
for industrial usage. Heat may be further extracted from the
flue gases after they leave the furnace and used to raise the
temperature of the steam, boiler feedwater, and/or combustion
air. Combustion gases are treated to reduce pollution and then
exhausted to the atmosphere.
A more detailed description of the unit operations and equipment
involved in steam generation follows, except for emissions/
effluent control and ash disposal, which are discussed later
in the report. The following description is only an overview
because numerous references have been published with the sole
purpose of examining combustion and combustion equipment
(9, 12-17).
At industrial locations, coal is fed from storage piles or
directly from transporting equipment to bunkers that supply the
pulverizers. In a pulverizer, coal is reduced in size by impact,
attrition, and crushing to the desired degree of fineness. Com-
monly used grinding mechanisms include ball and race mills, roll
and race mills, ball (tube) mills, and impact (hammer) mills.
(12) Edwards, J. B. Combustion: The Formation and Emission of
Trace Species. Ann Arbor Science Publishers, Inc., Ann
Arbor, Michigan, 1974. 240 pp.
(13) Combustion-Generated Air Pollution, E. E. Starkman, ed.
Plenum Press, New York, New York, 1971. 355 pp.
(14) Field, M. A., D. W. Gill, B. B. Morgan, and
P. G. W. Hawksley. Combustion of Pulverized Coal. The
British Coal Utilization Research Association, Leatherhead,
1967. 413 pp.
(15) Combustion Engineering, A Reference Book on Fuel Burning
and Steam Generation, 0. de Lorenzi, ed. Combustion
Engineering, Inc., New York, New York, 1957. 1025 pp.
(16) Potter, P. J- Steam Power Plants. The Ronald Press Com-
pany, New York, New York, 1949. 503 pp.
(17) Shields, C. D. Boilers - Types, Characteristics, and
Functions. FW Dodge Corporation, New York, New York, 1961.
559 pp.
17
-------
STEAM
CD
COOLING
WATER*
UTILIZATION
BOILER FEED-
WATER TREATMENT
ECONOMIZER
BOILER
FEEDPUMP
AIR PREHEATER
PURGE' MAKEUP
WATER
MORCED
DRAFT FAN
COOLING
WATER*
COMBUSTION BURNER
ZONE ""^
AIR POLUTION
CONTROL DEVICE
BOTTOM ASH
S:WATER USED IN ASH
TRANSPORT SYSTEM
BITUMINOUS CONTROL
PULVERIZER COAL DEVICE
CATCH *
WASTE STREAMS
Figure 4. Simplified process schematic for industrial
pulverized bituminous coal-fired boiler.
-------
Pulverizing serves to increase the surface area that can be
directly exposed to oxygen thereby increasing the rate of the pri-
mary combustion reactions. This results in decreased combustion
tine, increased throughput of coal, and increased heat output.
Coal is pulverized to the extent that 70% will pass a 200-mesh
screen. Larger particles may be separated from the coal-air
stream by a cyclone and returned to the pulverizer.
Durina pulverizing, the coal is dried by a strear. of hot air that
may be either forced or induced through the unit. Air is heated
prior to entering the pulverizer by an air heater (boiler waste
heat recovery unit) or by an auxiliary heater. The air flow
through the pulverizer is additionally reponsible for entrain-
ing and thus transporting the crushed coal to a storage vessel
(indirect feed) or to the burners (direct feed) where it becomes
the primary combustion air. Finely divided coal is explosive in
nature; thus, direct feed systems are generally preferred for
safety reasons, even though indirect feed systems require less
energy.
Pulverizers used in direct feed systems have automatic controls
to adjust the coal and air flow rates to compensate for vari-
ations in boiler load. Boiler loads from 40% to 60% of capacity
can be obtained by adjusting the fuel and air flow rates to the
burners. Firing at loads less than 401 requires that burners
and possibly pulverizers be taken out of service.
A burner receives the primary air-coal mixture, dilutes it with
secondary air, and injects it into the furnace. Burners are
designed to promote stability of ignition, completeness of com-
bustion, uniform distribution of temperature and excess air
leaving the furnace, and freedom from localized slag deposits.
These objectives are partially met through the creation of tur-
bulence and effective adjustment of the ignition point and flame
shape. A secondary function of some burners is to fire an alter-
nate fuel concurrently with pulverized coal in order to sustain
ignition during start up and periods of low load.
Burners designed to handle pulverized coal are generally classi-
fied according to their firing geometry. Figure 5 (18) illus-
trates the three basic orientations; i.e., vertical, horizontal,
and tangential.
Heat released from the combustion of coal is transferred by radi-
ation and convection to the boiler tubes where it is conducted
to the boiler feeder.
(18) Chemical Engineers' Handbook, Fifth Edition, J. H. Perry
and C. H. Chilton, eds. McGraw-Hill Book Company, New York,
New York, 1973.
19
-------
PRIMARY AIR
AND COAL
SECONDARY-
AIR
TERTIARY AIR
SECONDARY
PRIMARY AIR AND COAL
€
!i\\\li\»\
PRIMARY AIR AND COAL-
FANTAIL
MULTIPLE INTERTUBE
SECONDARY AIR
PLAN VIEW OF FURNACE
(a) VERTICAL FIRING
(W TANGENTIAL FIR ING
ro
o
PRIMARY AIR
AND COAL
SECONDARY AIR
MULTIPLE I NTERTUBE
PRIMARY AIR
AND COAL
SECONDARY AIR
CIRCULAR
(c) HORIZONTAL FIRING
Figure 5. Various methods of firing pulverized bituminous coal (18)
Reprinted from Chemical Engineers' Handbook, Fifth Edition, J. H. Perry and
C. H. Chilton, eds., p. 9-21, by permission of McGraw-Hill Book Company.
-------
Boiler feedwater is composed of recycled condensed steam and make-
up water. Makeup water must be treated prior to use to remove
suspended and dissolved solids. A characterization of typical
makeup water is presented in Table 9 (19). Concentrations of
the listed species in boiler water can result in reduced effi-
ciency and eventually in boiler tube failure. Specific problems
caused by these materials are summarized in Table 10 (20).
TABLE 9. TYPICAL CHARACTERISTICS OF
BOILER WATER SUPPLIES (19)
Constituent
Calcium, as CaCO3
Magnesium, as CaC03
Alkalinity, as CaC03
Sulfate, as SOa
Chloride, as Cl
Silica, as Si02
Iron, as Fe
Manganese, as Mn
Oil
Suspended solids
Concentration, g/m3
40
10
20
10
2
0.2
0.1
<1
10
to
to
to
to
to
to
to
to
to
to
200
50
50
140
150
15
2.0
1.0
. 0
200
PH 5.5 to 7.5
The level of treatment needed to alleviate these problems is a
function of both the feedwater composition and the quality or
the steam generated (higher temperature, higher pressure steam
requires more treatment). Although some high pressure industrial
boilers have severe feedwater Duality requirements similar to
those for electric utilities, most industrial boiler^operate at
pressures below 4 MPa, and the raw water is usually only treated
(19) Nichols, C. R. Development Document for Effluent Limita-
tions Guidelines and New Source Performance Standards for
the Steam Electric Power Generating Point Source Category.
EPA-440/1-74-029-A (PB 240 853), U.S. Environmental Protec-
tion Agency, Washington, D.C., October 1974. 865 pp.
(20) Betz Handbook of Industrial Water Conditioning. Betz Labora-
tories, Inc., Trevose, Pennsylvania, 1976. pp. 18-19.
21
-------
TABLE 10. WATER IMPURITIES, PROBLEMS, AND TREATMENT (20)
Reprinted from Betz Handbook of Industrial Water Conditioning, pp 18-19,
by permission of Betz Laboratories, Inc., Trevose, Pennsylvania.
Constituent
Difficulties caused
Means of treatment
Turbidity
Color
Hardness
Alkalinity
Deposits in water lines,
process equipment, boilers,
etc.
May cause foaming in boilers.
Hinders precipitation
methods such as iron re-
moval and softening.
Chief source of scale in
heat exchange equipment,
boilers, pipe lines, etc.
Foaming and carryover of
solids with steam. Embrit-
tlement of boiler steel.
Bicarbonate and carbonate
produce CO2 in steam, a
source of corrosion in
condensate lines.
Free mineral acid Corrosion.
Carbon dioxide
PH
Sulfate
Chloride
Nitrate
Corrosion in water lines
and particularly steam
and condensate lines.
pH varies according to
acidic or alkaline solids
in water. Most natural
waters have a pH of 6-8.
Adds to solids content of
water, but, in itself, is
not usually significant.
Combines with calcium to
form calcium sulfate scale.
Adds to solids content and
increases corrosive
character of water.
Adds to solids content, but
is not usually signifi-
cant industrially. Use-
ful for control of boiler
metal embrittlement.
Coagulation, settling and
filtration.
Coagulation and filtration.
Chlorination. Adsorp-
tion by activated carbon.
Softening. Demineraliza-
tion. Internal boiler
water treatment. Surface
active agents.
Lime and lime-soda soften-
ing. Acid treatment.
Hydrogen zeolite soften-
ing. Demineralization.
Dealkalization by anion
exchange.
Neutralization with
alkalies.
Aeration. Deaeration.
Neutralization with
alkalies.
pH can be increased by
alkalies and decreased
by acids.
Demineralization.
Demineralization.
Demineralization.
(continued)
22
-------
TABLE 10 (continued)
Constituent
Difficulties caused
Means of treatment
Silica
Iron
Manganese
Oxygen
Ammonia
Dissolved solids
Suspended solids
Total solids
Scale in boilers and cool-
ing water systems. Insol-
uble turbine blade deposits
due to silica vaporization.
Source of deposits in water
lines, boilers, etc.
Same as iron.
Corrosion of water lines,
heat exchange equipment,
boilers, return lines, etc.
Hydrogen sulfide Corrosion.
Corrosion of copper and zinc
alloys by formation of
complex soluble ion.
Dissolved solids is measure
of total amount of dis-
solved matter, determined
by evaporation. High con-
centrations of dissolved
solids are objectionable
because of process interfer-
ence and as a cause of
foaming in boilers.
Suspended solids is the
measure of undissolved
matter, determined gravi-
metrically. Suspended
solids plug lines, cause
deposits in heat exhcange
equipment, boilers, etc.
Total solids is the sum of
dissolved and suspended
solids, determined gravi-
metrically.
Hot process removal with
magnesium salts. Adsorp-
tion by highly basic
anion exchange resins, in
conjunction with deminer-
alization.
Aeration. Coagulation and
filtration. Lime soften-
ing. Cation exchange.
Contact filtration. Sur-
face active agents for
iron retention.
Same as iron.
Deaeration. Sodium sulfite.
Corrosion inhibitors.
Aeration. Chlorination.
Highly basic anion
exchange.
Cation exchange with hy-
drogen zealite. Chlori-
nation. Deaeration.
Various softening processes,
such as lime softening
and cation exchange by
hydrogen zeolite, will
reduce dissolved solids.
Demineralization.
Subsidence. Filtration,
usually preceded by
coagulation and settling,
See "Dissolved Solids" and
"Suspended Solids."
23
-------
to remove hardness, insoluble residues, excess silica, and alka-
linity (17). Detailed descriptions of water treatment technology
are readily available in the literature (15, 20, 21, 22).
As water is converted to steam in the boiler, trace impurities
still present, such as dissolved solids, are concentrated in the
boiler water When sufficiently high concentrations are reached,
these materials precipitate and coat the inner sides of the heat
transfer surfaces. This impairs the transfer of heat in the
boiler unit and reduces boiler efficiency. in order to prevent
deposition of these materials, a portion of the boiler water is
usually drawn off and replaced by feedwater. The blowdown (thlt
portion of the boiler water removed to maintain an acceptable
dissolved solids concentration) then becomes a wa£tewa?er stream.
Steam is generated primarily in the waterwalls of the furnace for
-
rxi
dry saturated steam proceeeds to utilization or +„ *™ t wh
heating when appropriate. utilization or to additional
ln tndustrial dr* bottom boilers firing pulver-
coal may be used to generate electricitv to
eat
genera
supply process heat, as a power source for nurtri ient
-
(21) Industrial Water Treatment Practice P Ham^r- T T ,
and E. F. Thurston, eds. Butterworth »rS n ' Jackson'
London, England, 1961. 514 pp nd ComPany Ltd-
(22) Nordell, E Water Treatment for Industrial and Other Uses
10
24
-------
As mentioned earlier, additional heat may be Covered from
combustion gases before they are discharged. This waste heat
recovery is accomplished in economizers and air heaters, which
use the low tirade heat to increase boiler efficiency. Econo-
mizers heat ?ne reedwater and thereby reduce the amount of energy
required to generate steam in the boiler. Air .heat^s P
the combustion air, which increases boiler efficiency by
ing combustion conditions.
the
If high pressure, high temperature steam is required fo:
operation of a turbine (not typical for industrial size -
additional heat can be extracted by steam suPe£hea^s and
reheaters, which are banks of heat transfer ^Jr^ located near
the furnace outlet. The use of superheaters and reheaters does
not affect the overall efficiency of the boiler.
COMBUSTION PROCESS
In the basic combustion process, carbon and hydrogen in coal
react with oxygen to form carbon dioxide and water H^e^_
because of the complex nature of coal and the many other reac
tions occurring under actual combistion conditions in a boiler^
a wide assortment of other emission species are P??aucea. ±
materials (e.g., sulfur oxides) are formed from °^her constitu
ents in the coal; others (e.g., carbon monoxide) a« products ot
incomplete combustion reactions. This section Characterizes the
bituminous coal consumed by this source type and describes the
combustion process.
Coal Characterization
The American Society for Testing and Materials (ASTM) has clas-
sified coals into the 4 classes and 13 groups shown in Table 11
(2). Each class and group is defined by a range of fixed caroo
volatile matter, and calorific value. For tnis
v. , . -n j__ ^_^i,,^Q ail HI •huminous
volatile matter, and calorc va
nous coal is assumed to include all bituminous anu
coal types.
Based on distribution of bituminous and lignite P
dealers and all others (excluding that consumed by
utilities and by coke and gas plants, fcf % usedas^lroad coal
and that sold to mines or mine employes), 67% °£ Jitumi n°£ st£°al
for industrial pulverized dry bottom boilers ?"93.nates xn the
Appalachian regSon (23). ^/^' °
Producing districts 1 to 8 and 13 as
Minerals Yearbook 1974 Volume
Fuels. U.S. Department of the
Washington, D.C., 1976. p.
25
-------
NJ
TABLE 11. CLASSIFICATION OF COALS BY RANK (2)
Reprinted from 1976 Annual Book of ASTM Standards, p. 213,
by permission of American Society for Testing and Materials.
Fixed carbon
limits,
%
(dry, mineral-
Coal rank
Anthracitic :
Meta-anthracite
Anthracite
Semianthricite
Bituminous :
Low volatile bituminous coal
Medium volatile bituminous coal
High volatile A bituminous coal
High volatile B bituminous coal
High volatile C bituminous coal
matter- free
Equal or
greater
than
98
92
86
78
69
basis)
Less
than
98
92
86
78
69
Volatile matter
limits, %
(dry, mineral-
matter-free basis)
Equal or
Greater less
than than
2
2 8
8 14
14 22
22 31
31
Calorific value limits,
Btu per pound (moist.
mineral -matter-
free basis)
Equal or
greater Less
than than
14, 000 j
13,000 14,000
rll,500 13,000
110,500 11,500
Subbituminous:
Subbituminous A coal
Subbituminous B coal
Subbituminous C coal
Lignite:
Lignite A
Lignite B
10,500 11,500
9,500 10,500
8,300 9,500
6,300
8,300
6,300
This classification does not include a few coals, principally nonbanded varieties, which have unusual
physical and chemical properties and which come within the limits of fixed carbon or calorific value
of the high-volatile bituminous and Subbituminous ranks. All of these coals either contain less than
48 percent dry, mineral-matter-free fixed carbon or have more than 15,500 moist, mineral-matter-free
British thermal units per pound.
b
Moist refers to coal containing its natural inherent moisture but not including visible water on the
surface of the coal.
If agglomerating, classify in low-volatile group of the bituminous class.
d
Coals having 69 percent or more fixed carbon on the dry, mineral-matter-free basis shall be classi-
fied according to fixed carbon, regardless of calorific value.
-------
Coal Act of 1937. Table 12 presents a characterization of Appa-
lachian bituminous coal from the literature (24-27). Although
average concentrations are given for elemental composition, levels
can vary significantly from state to state, mine to mine, and even
within the thickness of a coal seam. The concentration of a par-
ticular element in coal can range over two orders of magnitude
(24-27).
Pulverized Coal Combustion
Coal burns in a diffusion flame because the solid nature of the
fuel prohibits mixing of the fuel and oxidant on a molecular
scale. Processes involved in the combustion of a solid fuel are
shown in Figure 6 (12). With the addition of radiant energy
from an ignition device or the combustion zone, volatile com-
Ponents are vaporized and flow away from the solid surface, and
the solid portion of the fuel begins to pyrolyze. At this point,
no oxidation of the fuel at the surface occurs due to lack of
intimate contact with the oxidant. A diffusion flame is estab-
lished where the mixing of combustibles and oxidant forms a
combustible mixture. This is noted as the primary combustion
zone in Figure 6. Additional transfer of heat results in addi-
tional vaporization of volatiles, pyrolysis, and a rise in
surface temperature of the solid to the incandescent range.
Radiant energy from incandescence promotes additional pyrolysis
of the vapors. After the depletion of volatiles, oxidation of the
solid commences. Oxygen diffuses to the solid surface and oxida-
tion of the nonvolatiles occurs, resulting in the release of more
heat. carbon monoxide and dioxide, water, hydrogen, nitrogen
oxides, sulfur oxides, particles from noncombusted vapors, and
impurities may form or begin to form in the combustion zone.
(24) Swanson, V. E., J. H. Medlin, J. R. Hatch, S. L. Coleman,
G. H. Wood, S. D. Woodruff, and R. T. Hildebrand. Collec-
tion, Chemical Analysis, and Evaluation of Coal Samples in
1975. Open-File Report 76-468, U.S. Department of the
Interior, Denver, Colorado, 1976. 503 pp.
(25) Ruch, R. R., H. J. Gluskoter, and N. F. Shimp. Occurrence
and Distribution of Potentially Volatile Trace Elements in
Coal. EPA-650/2-74-054 (PB 238 091), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
July 1974. 96 pp.
(26) Kessler, R., A. G. Sharkey, Jr., and R. A. Friedel.
Analysis of Trace Elements in Coal by Spark-Source Mass
Spectrometry. Report of Investigations 7714, U.S. DeP"^
ment of the Interior, Pittsburgh, Pennsylvania, 1973. 8 pp.
(27) Magee, E. M., H. J. Hall, and G. M. Varga, Jr. Potential
Pollutants in Fossil Fuels. EPA-R2-73-249 (PB 225 039),
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, June 1973. 223 pp.
27
-------
TABLE 12.
ARITHMETIC MEAN OF PROXIMATE AND ULTIMATE ANALYSES AND
ELEMENTAL COMPOSITION FOR APPALACHIAN COAL REGION SAMPLES
Constituent
Moisture, %
Volatile matter, %
Fixed carbon, %
Ash, %
Hydrogen , %
Carbon, %
Nitrogen , %
Oxygen , %
Sulfur, %
Heating value, J/kg
Elements , ppm :
Aluminum
Arsenic
Antimony
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
Lanthanium
Lead
Arithmetic
mean
2.8
31.6
54.6
11.0
4.9
72.6
1.3
7.8
2.3
30 x 106
1.8 x 10-
2.6 x 101
1.2
1.0 X 102
2.1
<1.0 x 10-'
2.9 x 101
1.1 x 101
6.8 x 10-1
1.3 x 103
1.4 x 101
2.5 x 101
7.3 x 10Z
2.0 x IQi
6.8
2.2 x 101
1.4
2.6 x 10-1
5.9 x 10-1
7.8 x 101
1.0
6.5
4.8
4.0 x 10-i
1.2
2.1 x 10-1
1.1
<2.0 x 10-1
1.9 x 10*
9.3
1.5 x 1Q1
Number
of
samples
158
158
158
158
158
158
158
158
158
158
350
350
350
341
426
10
413
19
350
350
10
10
19
426
426
426
10
10
10
350
10
426
95
10
10
10
10
10
350
350
350
Reference
24
24
24
24
24
24
24
24
24
24
24-26
24-26
24-26
24,26
24-27
25
24-27
24,25
24-26
24-26
25
25
24,25
24-27
24-27
24-27
25
25
25
24-26
25
24-27
24,25,27
25
25
25
25
25
24-26
24-26
24-26
Constituent
Elements (continued) :
Lithium
Lutenium
Magnesium
Manganese
Mercury
Molybdenum
Neodymium
Nickel
Niobium
Osmium
Palladium
Phosphorus
Platinum
Potassium
Praseodymium
Rhenium
Rhodium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
Arithmetic
mean
2.7 x 1Q1
1.2 x 101
6.9 x 10*
5.9 x 10*
1.4 x 10-1
3.1
1.2 x 103
1.5 x 101
5.4
<2.0 x 10-1
<1.0 x 10-1
9.2 x 10-1
0.0 x 10-1
2.3 x 103
2.1
<2.0 x 10-1
<1.0 x 10-1
3.7 x 101
4.0 x 10-1
1.9
5.1
4.5
2.7 x 10*
2.5 x 10~3
3.3 x 103
1.0 x 10a
9.5 x 10-1
3.4 x 10-1
3.2 x 10-i
1.0 x 10-1
4.8
<1.0 x 10-1
2.4
8.1 x 10a
2.8 x 10-1
1.4
2.0 x IQi
9.8 x 10-1
1.1 x 101
1.8 x 101
5.0 x 101
Number
of
samples
341
10
350
350
350
426
10
426
341
10
10
19
10
350
10
10
10
10
10
10
341
350
350
10
350
341
10
10
10
10
341
10
95
415
10
341
426
341
426
426
350
Reference
24,26
25
24-26
24-26
24-26
24-27
25
24-27
24,26
25
25
24,25
25
24-26
25
25
25
25
25
25
24,26
24-26
24-26
25
24-26
24,26
25
25
25
25
24,26
25
24,25,27
24-27
25
24,26
24-27
24,26
24-27
24-27
24-26
-------
-—SOLID
PYROLYSIS
CONDENSED PHASE
REACTION,
ZONE
I I
Ij
GAS "1
PHASE I ,
REACTION! !
OXIDATION
PRIMARY
COMBUSTION
NONREACTING
SOLID
PRIMARY AIR
SECONDARY
POST-FLAME
REACTIONS
RECEDING INTERFACES
Figure 6. Combustion of a solid (12).
Reprinted from the Formation and Emission of Trace
Species by J. B. Edwards, p. 151, by permission of
Ann Arbor Science Publishers, Inc.
Directly downstream of the combustion zone is the postflame
region. This region may be luminous, and therefore it is often
considered as part of the flame itself. Many chemical and phy-
sical processes may occur in the postflame region because the
reactants may be both gaseous and solid. Radical recombination
(chain termination) reactions such as the recombination of
atomic oxygen and the formation of water from atomic hydrogen
and the hydroxyl radical occur as the combustion gases cool.
Reaction of fuel components and their combustion products with
other hydrocarbons, dehydrogenation of hydrocarbons to species
of greater unsaturation, and the cracking of hydrocarbons are
among the pyrolytic postflame reactions.
29
-------
SECTION 4
AIR EMISSIONS AND CONTROL TECHNOLOGY
SOURCE AND NATURE OF AIR EMISSIONS
Air emissions emanating from this source originate primarily
from the combustion of pulverized bituminous coal in the boiler
furnace. Other potential air emission sources are coal and ash
handling and cooling towers when present.
Airborne emissions resulting from coal combustion include partic-
ulate matter, sulfur oxides, nitrogen oxides, carbon monoxide,
hydrocarbons, polycyclic organic materials, and most elements.
Mass emissions of particulate matter, sulfur oxides, and the
elements found in combustion product gases as either particulate
matter or vapors are directly related to the ash, sulfur, and
individual elemental concentrations in the fuel. Nitrogen oxides
arise from nitrogen compounds in coal and the nitrogen component
of the combustion air. Carbon monoxide, hydrocarbons, and poly-
cyclic organics are all products of incomplete combustion.
During combustion in a coal-fired furnace the inorganic constitu-
ents (ash) of the coal are entrained in the effluent gas stream
*n Xnf8^ °r r(fmoved as Bottom ash. In a dry bottom furnace 60%
are n<. t0 85%) of these noncombustible materials
enrai ln the effluent gas stream (18, 28) and, unless
he r™n ' 6mitted fc° th* atmosphere
.
remove h coliects in th* furnace and is periodically
ranaeT from 4* ?n ??*' *** SSh content of "ost bituminous coals
ranges from 4% to 15% and averages about 11% (29).
(28) cuffe , S. T., and R. W. Gerstle. Emissions from Coal-Fired
Power Plants: A Comprehensive Summary. Public Health
Educatfon^andVi;35
-------
There are several mechanisms by which particulate matter, includ-
ing aerosol mists, is formed during the combustion process and
the subsequent flow of combustion products through the flue gas
system. The inorganic species that are not volatile at combus-
tion temperatures coalesce in the combustion zone to form a
heterogeneous melt in which a small portion of the volatile
inorganic and combustible materials are trapped. This material
becomes the bottom ash and the bulk of the fly ash. As the
combustion gases move away from the furnace and cool, the vola-
tile inorganic species and any high molecular weight organics
which escaped combustion condense either onto the particles
present in the gas stream or through self-nucleation. This
process is essentially complete by the time the gases reach the
electrostatic precipitator (ESP), the driving force being a
1,000°C plus temperature drop over 6 seconds or less which
results in supersaturated conditions. Some additional material
is added to the particles through adsorption of gaseous materials
such as chlorine, bromine, fluorine, and mercury, and by gas
phase reactions in the flue gas that produce additional conden-
sable materials. Sulfuric acid mists are produced in the latter
manner by the fly ash catalyzed conversion of sulfur dioxide
to sulfur trioxide and the rise in flue gas dew point caused by
the presence of sulfur (30) .
Fly ash generally occurs as fine spherical particles. A typical
coal ash particle size distribution has a bimodal distribution,
with peaks in the regions of 0.07 ym and 0.6 ym for particle size
diameter (31). Chemical and physical descriptions of pulverized
coal ash are found in Section 6.
Concentrations of trace elements emitted as either particles or
vapors are closely related to the elemental composition of the
coal. However, the concentrations found in fly ash are affected
by the partitioning of elements between the fly ash and bottom
ash. Concentrations of elements found in fly ash emitted after
passing through particulate controls are further influenced by
a mechanism known as particulate enrichment.
(30) Hillenbrand, L. J., R. B. Engdahl, and R. E. Barrett.
Chemical Composition of Particulate Air Pollutants from
Fossil-Fuel Combustion Sources. EPA-R2-73-216 (PB 219 009),
U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina, March 1973.
(31) Ragaini, R. C., and J. M. Ondov. Trace-Element Emissions
from Western U.S. Coal-Fired Power Plants. Journal of
Radioanalytical Chemistry, 37:670-691, 1977.
31
-------
Three distinct classes of elements have been identified according
to their partitioning behavior (32-34). First are the elements
that show no preference for bottom or fly ash. These elements are
not volatilized in the combustion zone but form a melt of hetero-
geneous composition that becomes both bottom and fly ash. The
second class consists of elements that partially volatilize in the
combustion zone and condense onto fly ash particles in the flue
gas as it cools. Elements belonging to this group are thus pref"
erentially depleted from the bottom ash and concentrated in the
fly ash. The third class is made up of elements that are volatil'
tilized and essentially remain in the vapor state. These elements;
are thus emitted directly to the atmosphere as gases; their mass
emission rate is directly proportional to their concentration in
the coal and is independent of any particulate control device.
It should also be noted that a number of elements do not fit well
into any of the above clases but exhibit behavior intermediate
between Classes I and II. The elements belonging to each class
are listed in Table 13 (32-34).
TABLE 13. CLASSIFICATION OF ELEMENTS ACCORDING
TO THEIR PARTITIONING BEHAVIOR (32-34)
Partitioning class Elements
Class I - Elements equally distri- Aluminum, barium, bismuth, calcium,
between bottom and fly ash cerium, cobalt, europium, hafnium,
iron, lanthanum, magnesium, man-
ganese, niobium, potassium, rubid-
ium, samarium, scandium, silicon,
strontium, tantalum, thorium, tin,
titanium, yttrium, zirconium
Class II - Elements concentrating in Antimony/arsenic, cadmium, copper,
y ash gallium, lead, molybdenum, polo-
nium, selenium, thallium, zinc
Class III - Elements remaining in gas Bromine, chlorine, fluorine, mercury
phase
Elements intermediate between cesium, chromium, nickel, sodium,
Classes I and II uranium, vanadium
(32) Davison, R. L., D. F. S. Natusch, J. R. Wallace, and C. A.
Evans, Jr. Trace Elements in Fly Ash - Dependence of
Concentration on Particle Size. Environmental Science and
Technology, 8(13):1107-1113, 1974.
(33) Kaakinen, J. W., R. M. Jorden, M. H. Lawasani, and R. E.
West. Trace Element Behavior in Coal-Fired Power Plant.
Environmental Science and Technology, 9(9):862-869, 1975.
(34) Klein, D. H., A. W. Andren, J. A. Carter, J. F. Emery,
C. Feldman, W. Fulkerson, W. S. Lyon, J. c. Ogle, Y. Talmi/
R. I. VanHook, and N. Bolton. Pathways of Thirty-Seven
Trace Elements Through Coal-Fired Power Plant. Environ-
mental Science and Technology, 9 (10):973-979 1975.
32
-------
Particulate enrichment is a result of the volatilization and sub
sequent condensation of the Class II elements mentioned above.
Because smaller fly ash particles present a larger surface area
per unit mass for condensation, they are the ones on which the
class II elements are preferentially concentrated. This is of
particular interest because the smaller particles are harder to
remove from the flue gas and therefore make up a high percentage
of the ash emitted after controls.
Sulfur oxide (SOX) emissions result from the oxidation of the
pyritic and organic sulfur found in coal. Since no more than
a small percentage of the sulfur is converted to particulate
sulfates (35) , the emission rate is almost totally dependent on
the fuel sulfur content and the fuel feed rate to the boiler.
Thus, SOX emissions can be closely approximated by the following
equation (36) :
SOX = 2(R)
-------
are slow, equilibrium SOa-SOs concentrations are not reached in
the final exhaust gas. The initial S03 concentration is rela-
tively independent of excess air at levels above 5% excess air.
However, reducing excess air to a few tenths of 1% causes SOa
concentrations to fall to nearly zero (40). The SO3 formed may
react with moisture in the flue gas to produce sulfuric acid if
stack temperatures drop below the acid dew point.
The nature of nitrogen oxide emissions is somewhat more complex
than that of sulfur oxides because both the fuel and the combus-
tion air are sources of nitrogen in the combustion zone. Com-
bustion air is about 79% nitrogen, and coal contains from 0.5%
to 2% nitrogen by weight in the form of pyrroles, pyridines,
quinolines, carbazoles, and amines (41). Nitrogen oxide emis-
sions usually represent less than 0.1% of the nitrogen entering
the furnace (36), indicating that very little atmospheric nitro-
gen is converted to NOX in the furnace. This is partially be-
cause the conversion of atmospheric nitrogen to nitrogen oxides
(thermal NOX formation) is highly temperature dependent and pro-
ceeds slowly at the relatively low flame temperatures (<1,530°C)
encountered in a typical fuel-lean coal flame. On the other hand*
fuel nitrogen conversion is readily accomplished at lower temper-
atures and contributes from 60% to 100% (averaging about 80%) of
the nitrogen oxides formed at 730°C to 1,530°C. This is because
the bond energies in coal are typically 80 kcal/mole to 100 kcal/
mole compared to the 225 kcal/mole required for thermal nitrogen
oxide formation (41). The amount of fuel nitrogen oxidized depends
(continued)
(38) Vogel, R. F., B. R. Mitchell, andF. e. Massoth, Reactivity
of S02 with Supported Metal Oxide-Alumina Sorbents.
Environmental Science and Technology, 8(5):432-436, 1974.
(39) Wilson, J. S. and M. W. Redifer. Equilibrium Composition
of Simulated Coal Combustion Products: Relationship to
Fireside Corrosion and Ash Fouling. Journal of Engineering
for Power. Transactions of the ASME, 96(A-2):145-152, 1974-
(40) Barrett, R. E., J. D. Hummell, and W. T. Reid. Formation of
S03 in a Noncatalytic Combustor. Journal of Engineering
Power, Transactions of the ASME, 88(4):165-172, 1966.
(41) Vogt, R. A., and N. M. Laurendeau. Nitric Oxide Formation
in Pulverized Coal Flames. PURDU-CL-76-08 (PB 263 277),
National Science Foundation, Washington, D.C., September
1976.
34
-------
on the excess air present; for low excess air levels «5%) it is
generally between 20% and 50% (42-45).
Nitrogen oxides are formed in the combustion zone, the primary
constituent (approximately 95% of total NOX) being nitric oxide
(NO) . The NO concentration attained depends on the flame temper-
ature and the residence time in the furnace as NO dedeomposition
reactions are rapidly quenched by the lower temperature at the
furnace outlet. Further oxidation of NO continues with time but
at a very slow pace compared to that for the time spent in the
boiler system. Therefore, the concentrations of nitrogen oxides
reached in the furnace remain relatively unchanged at the point
of discharge. Other oxides of nitrogen include nitrogen dioxide
(N02), which accounts for about 5% of the total NOx , and trace
amounts of nitrogen pentoxide (N2O5) and nitrous oxide (N20)
(39, 46).
Incomplete combustion is responsible for the formation of carbon
monoxide and hydrocarbons, including polycyclic organic materials
(POM). Thus, the coal combustion efficiency is the controlling
factor in the production and emissions of these pollutants.
Conditions necessary for the conversion of hydrocarbon fuels to
carbon dioxide and water are sufficient time for the completion
of the chemical reactions, sufficient temperature to heat the
42) snna Y H J~ M. Beer, and A. F. Sarofim. Fate of Fuel
Fundamental Combustion Research. EP^6^/7':ch Triangle
029), U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, July 1977. pp. 79-100.
M. D. Shuman, and V. H.
Environmental Protection A^ncy, Resear ch Triangle Park,
North Carolina, February 1976. 365 pp.
(44) Sterling, C.
Governing the
in Combultion. EPA-650/2-74-017 (^ f ^ °!J''^North
mental Protection Agency, Research Triangle Park, North
Carolina, August 1972. 144 pp.
(45) Pershinq D W., G. B. Martin, and E. E. Berkau. Influence
of Design variables on the Production of Thermal and Fuel
NO from Residual Oil and Coal Combustion. ^;.^J1^ "."'
Control of NOx and SOX Emissions, AIChE Symposium Series
No. 148:71:19-29, 1975.
(46) Environmental Control Technology, TID-26758-P7U.S Atomic
Energy Commission, Washington, D.C., November 11, 1974.
35
-------
fuel through its decomposition stages and to ignite it, and suf-
ficient turbulence to thoroughly mix the fuel and oxygen. In a
furnace firing pulverized coal the major limiting factor is the
ability of the burner to provide sufficient turbulence in the
very short time allowed for combustion.
Carbon monoxide (CO) formation is directly related to the fuel-
air ratio. Fuel rich conditions stimulate CO formation with
maximum CO concentrations occurring at minimum oxygen concentra-
tions. CO emissions are generally low (<1 ppm) for dry bottom
boilers (47, 48).
Like CO, hydrocarbon emissions are dependent on the fuel-air
ratio, and they appear in small concentrations even though excess
oxygen is available in the furnace. Either incomplete mixing or
variations of reactant concentrations in time permit isolated
oxygen-deficient volumes of gas to escape combustion.
Polycyclic organic materials result from the combination of free
radical species formed in the flame. The synthesis of these
molecules is dependent on many combustion variables, including
the presence of a chemically reducing atmosphere. Under this
condition, radical chain propagation is enhanced, allowing the
buildup of a complex POM molecule. A list of POM species encoun-
tered during sampling is presented later in Table 17. Because
POM compounds melt/sublime at about 200°C, which is approximately
50°C higher than most stack temperatures (47), they should be in
the condensed phase when emitted.
Emissions from industrial boilers caused by coal and ash handling
and by evaporation and aerosol formation in cooling towers do not
approach the magnitude of the combustion-related emissions. In
fact, the sum of the mass emissions from these sources totals
less than 1% of the combustion mass emissions.
(47) Cato, G. A. Field Testing: Trace Element and Organic Emis-
sions from Industrial Boilers. EPA-600/2-76-086b (PB 261
263), U.S. Environmental Protection Agency, Research Triangl6
Park, North Carolina, October 1976. 156 pp.
(48) B'artz, D. R., and S. C. Hunter. Field Testing: Application
of Combustion Modifications to Control Pollutant Emissions
from Industrial Boilers, Phase II. in: Proceedings of the
Second Stationary Source Combustion Symposium; Volume I:
Small Industrial, Commercial, and Residential Systems.
EPA-600/7-77-073a (PB 270 923), U.S. Environmental Protection
Agency Research Triangle Park, North Carolina, Julv 1977.
pp. 207-245.
36
-------
Emissions resulting from the handling of coal include particulate
emissions of coal dust from wind entrainment, and gaeous emis-
sions of carbon monoxide, methane, and other highly volatile
hydrocarbons. These emissions arise primarily from coal storage
piles. Ash handling emissions result from wind entrainment of
exposed ash particles during ash conveying, transport, and
disposal. Emissions from coal storage piles have been previously
assessed (4), and emissions from ash handling are discussed in
Section 6.
Cooling tower emissions are divided into two categories, fog
and drift, with 20 ym particle size as the dividing point. Fog
«20 ym) results from condensation and consists of relatively
Pure water. Drift droplets have the composition of the cooling
liquor, which has a total dissolved solids content on the order
of 1,000 ppm, consisting mainly of calcium sulfate (CaSO*) (49).
Drift deposition is controlled by many atmospheric variables,
but typically, approximately 70% deposits within about 122 m (1).
EMISSIONS DATA
There are limited .data in the literature characterizing airborne
emissions from industrial dry bottom boilers burning pulverized
bituminous coal. Most emissions data in the literature do not
attach all of the descriptors used to define this category when
identifying the source of the sampling data. Commonly, a source
is identified only as a coal-fired industrial boiler, or by size
rather than application, and in order to use the data it was
necessary to assume that the coal used was bituminous, or that
the industrial boiler was dry bottom. This is a reasonable as-
sumption because dry bottom boilers firing pulverized bituminous
coal are the most common (47%) unit in this general category ot
coal-fired industrial boilers (1). Moreover, pulverized boilers
Predominate in the larger boilers that are generally tested.
Emissions data were compiled from actual test data, calculated
based on material balance considerations using literature re-
sources, and generated from a sampling program that measured
the emissions from a typical boiler in this source category.
(49) Carson, J. E. Atmospheric Impacts of Evaporative Cooling
Systems. ANL/ES-53, Argonne National Laboratory, Argonne,
Illinois, October 1976. 48 pp.
37
-------
The resulting emission factors are presented in Table 14 (50, 51)-
Due to the variability in analyses of different bituminous
coals, elemental emissions could vary by several orders of
magnitude from the reported values.
A discussion of the emissions data collected during field sam-
pling and that reported in the literature follows. A description
of the boiler sampled and the sampling and analytical techniques
used is found in Appendix C.
Particulate Emissions
The average particulate matter emission factor (in terms of coal
ash content) determined by the MRC source assessment field
sampling effort was over 1.5 times the value given in AP 42 (52)-
It is believed that this was due to the fact that coal fired
during the particulate loading measurements had an ash content
in excess of the average value determined from coal samples
taken at the site. This is likely because only three coal
samples were taken over a 2-week sampling period to determine
the physical and chemical characteristics of the coal.
The field sampling data collected by MRC for controlled and un-
controlled emission factors listed in Table 14 show that the ESP
effected a 98.3% reduction in particulate emissions. Particulate
size distributions measured for uncontrolled and controlled emiS"*
sions are listed in Table 15, which illustrate how the efficiency
of the ESP decreases with decreasing particle size.
(50) Gibbs, L. L. , C. E. ZJmmer, and J. M. Zoller. Source
Inventory and Emission Factor Analysis, Volume I. EPA-450/
3-75-082-a (PB 247 743), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, September
1974. 276 pp.
(51) Cato, G. A. , H. J. Buening, C. C. DeVivo, B. G. Morton,
J. M. Robinson. Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrie
Boilers, Phase I. EPA-650/2-74-078-a (PB 238 920), U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina, October 1974. 213 pp.
(52) Compilation of Air Pollutant Emission Factors, Second Edi-
tion. AP-42 (PB 264 194), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, February
1976.
38
-------
TABLE 14.
EMISSION FACTORS FOR INDUSTRIAL DRY BOTTOM
BOILERS FIRING PULVERIZED BITUMINOUS COAL
Emission
Particulate
NO,
SO, .
Sulfate1
CO
Hydrocarbon
POM (total)
POM (carcinogenic)
PCB
Elements:
Aluminum
Antimony
Arsenic *
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
Lanthanum
Lead
Lithium
Lutetium
Magnesium
Manganese
Mercury
Molybdenum
Neodymium
Nickel
Niobium
Osmium
Palladium
Phosphorous
Platinum
Potassium
Praeseodymium
Rhenium
Rhodium
Literature data
confidence
Uncontrolled Controlled limit,
emission emission % of
factor,* factor, emission
q /kg q/kg factor
9.2Ad
8-2 h e
19. 2Sn
-e 1.6 x 10-*
0 -e
6 x 10-» -I
n 2.5 x 10-* -,
0 B . e
Ie _e
n
1.8 x 10' 1.8 x'J.0-';!
1.2 x 10-
2.6 x 10-
1.0 x 10-
2.1 x 10-
<1.0 x 10-
2.9 x 10-
1.1 x 10-
6.8 x 10-
1.3
1.4 x 10-
2.5 x 10-
7.3 x 10-
2.0 x 10-
6.8 x 10-
2.2 x 10-
1.4 x 10-
2.6 x 10-
5.9 x 10-
7.8 x 10-
1.0 x 10-
6.5 x 10-
4.8 x 10-
<1.0 x 10-
1.2 x 10-
2.1 x 10-
1.1 x 10-
<2.0 x 10-
1.9 x 101
9.3 x 10-
1.5 x 10-
2.7 x 10-
1.2 x 10-
6.9 x 10-
5.9 x 10-
2.4 x 10-
3.1 x 10-
1.2 x 10-
1.5 x 10-
5.4 x 10-
<2.0 x 10-
<1.0 x 10-
9.2 x 10-
<3.0 x 10-
2.3
2.1 x 10-
<2.0 x 10-
<1.0 x 10-
1.2 x 10-*
2.6 x 10-2
1.0 Xe10-3^
- „
<1.0 x 10"e
s
1.1 x 10-a*
6.8 x 10-»*
1.3 x 10"l
1.4 X 10-*^
2.5 x io-»;
7.3 x 10-'*
2.D x 10-3"
6.8 x 10-»;
2.2 xe!0-a
-
q
5.9 x 10-oj
7.8 x^lO-»
-e s
6.5 X.10-3
_e
-
1.2 x 10-«q
-
-e
-• „
1.9 x 10-'^
9.3 x 10-SJ
1.5 x 10-a
6
a
6.9 x 10-'J
5.9 x 10-**.
2.4 x ID-"*
3.1 x 10-*
— C
1.5 x 10-3"
5.4 x 10-»q
-e
IB
A
2.3 x 10-a()
-
—
-
9.6
13
".e
-
130_n
"e
Ie
_r
"r-
IT
Ul
r*'
~r
~r
-r
-^
-j."
"r
~r
~r
~r
~r
~r
~r
~r
"r
"r
"r
~r
~r
"r
"r
~r
"r
"r
"r
~r
"r
"r
~r
"r
"r
~r
"r
"r
~r
~r
"r
-
MRC ti<
Coal
composition.
Reference gA
50 (8.23)
50 ~
50 (0.91)
51 "f
, _*
1 f
If
5.8
1.7 x 10-2
6.9 x 10-3
5.4 x 10-a
4 A v 1 0~3
• ^ * n
' 1 1 V 10-a
9
1.4 x 10-3
7 2 v 10~1
/ •• * K _ A.W
Ig
1.6 x 10-2
7.2 x 10-2
«M v TO-2
.4 XglU
~g
Ig
_g
g
g
_g
_g
_g
Ig
_g
'g
1.2 x 10"2
g
"g
3.2 x 10-1
1.3 x 10-2
5.0 x 10-*
8 5 » in-3
0 xglu
4.2 x 10-a
_g
g
_g
8.8 Xg10-a
"g
_g
Ig
Id SBjiiDlxnq ds
Uncontrolled
emission
factor , b
a/kg
14.6Ad
2.3 xkl°~a
2.5 XulO"2
_k
~k
op
4.0 ..
4.2 x 10-2t
8.6 x 10-»
3.6 x 10-2
1.9 x 10-»
g
2.9 X 10-at
g
3.6 x 10-3t
9 1 x 10"'
3.J. *g
-------
TABLE 14 (continued)
Emission
species
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
ytterbium
Yttrium
Zinc
Zirconium
Uncontrolled
emission
factor,*
q/kg
3.7 x 10-a
<1.0 x 10-»
1.9 x 10~3
5.1 x 10-»
4.5 x 10~3
2.7 x 101
2.5 x 10-»
3.3 x 10-1
1.0 x 10-1
9.5 x 10-»
3.4 x 10~»
3.2 x 10-»
1.0 x 10-*
4.8 x 10-3
<1.0 x 10"*
2.4 x 10-3
8.1 x 10-1
2.8 x 10-*
1.4 x 10~3
2.0 x 10-a
9.8 x 10-»
1.1 x 10-a
1.8 x 10~a
5.0 x 10-a
Literature data MRC field samolinq data __ •
confidence .
Controlled limit, Uncontrolled Controlled
emission % of Coal emission emission
factor, emission composition, factor," factor,
g/kg factor Reference q/kq (%) q/kg 9Y*9 — •
3.7 xe!0—q
1.9 x 10-»q
5.1 x 10-oj
4.5 x 10-3*
2.7 x 10-iq
-e
3.3 x 10-*"
1.0 x lO-3^
9.5 x 10— q
_e
_e
1.0 x 10-**
4.8 x,10-»q
_e
2.4 x 10~52
8.1 xe!0-=>q
~e
2.0 xD10-3"
_e
1.1 x 10-»q
1.8 x 10-2*
5.0 x 10-«q
_p
r
_r
_r
*•
— r
-
r
-r
I"
_r
_r
_r
r
r
_r
IT"
_r
~r
_r
_r
_r
~r
_r
_9
_9
_9
_g
1.0 x 10-3
1.1 x 10-1
6.2 x 10-2
3.4 x 10-1
6.8 Xn10-2
— 9
_9
_9
_9
_g
_g
1.2 x 10-1
3.7 x.10-1
_g
_9
7.8 x 10"a
XgJ-U
_9
1.9 x 10-z
_g
_9
_g
_9
+
3.4 x 10-jX
3.1 x 10-*..
1.2 x 10-1'
1.9 x 10-i
1.0 x.lO-i1
_9
_9
_g
_g
_g
_g
2.0 X 10-lt
2.6 xn10~1
_g
_g
6.4 x 10"2
_g
_g
1.6 x 10-2
_g
Ig
1.6 x 10 ^^
5.1 x 10
8.5 x ID"*
5-5 x J2"!
4.4 Xg10
9"
_
9~
_
9~
_
1.3 x 10"*
9.9 xg10
~_
Uncontrolled emission factors for elemental emissions are based on average elemental concentrations in coal
(see Table 12) assuming 100% of each element is emitted.
No confidence limits are applied because only one source was sampled. Most values are averages of two meas»r
ments. Blanks indicate no emission measurement made.
References for uncontrolled elemental emission factors are given in Table 12.
Ash content of coal as percent by weight.
eNo information -available.
Not applicable because these species are products of combustion.
No coal or emission measurements were made for these species during the field sampling effort.
Sulfur content of coal as percent by weight.
Water soluble sulfate.
JThree samples, all zero at a detection level' of 1 ppm.
Measurements of these species were obtained for controlled emissions only.
""six samples, all zero at a detection level of 1 ppm,
Estimate of unknown accuracy, estimated to be order of magnitude.
°POM compounds which are known to be carcinogenic or are in a class of POM's that contain known
carcinogens.
pTwo samples each of uncontrolled and controlled emissions, all zero at the detection levels shown in
Table IB .
"These elements are equally distributed between the bottom ash and fly ash according to Table 13 and
therefore occur in the larger fly ash particles. On this basis it il assumed that the controlled
emissions of these elements are 1% of the concentrations found in coal.
•"confidence limits for these numbers are not available but the number of measurements upon which each
value is based is found in Table 12. "
Elements having partioning behavior in Classes II or III according to Table 13. Controlled emissions
are assumed to be equal to uncontrolled emissions.
values are higher than those measured for the coal feed either because of the variability in
the concentration of this element in coal or because of the accuracy of the measurement method.
Values for the elements B, Cr, Pe, Mo, and Hi are suspected of being high due to contamination from
the sampling train.
"Elements with partioning behavior intermediate between Class I and Class II. Controlled emissions
are assumed to be 101 of uncontrolled emissions.
40
-------
TABLE 15. SASS3 PARTICLE SIZE DATA REPORTED AS A PERCENT
OF. THE TOTAL PARTICULATE MASS EMISSIONS
Particle
size
urn
<1
1 to 3
3 to 10
>10
Weight percent or
uncontrolled
emissions
1.3
12.9
39.3
46.6
Weight percent of
controlled
emissions
3.9
41.2
36.3
18 .8
SSource assessment sampling system.
Nitrogen Oxides Emissions
Emissions of nitrogen oxides were not measured during the MRC
sampling effort because of the extensive work done in this area
by KVB, inc. (51, 53), and because such data do not provide an in
sight into any of the other less characterized pollutants, as is
the case with particulate data and trace elements, or f^*?*
ides data and particulate sulfates. In general, emission factors
for nitrogen oxides vary greatly from boiler to boiler (54) and
are not significantly dependent on boiler size (48). The reason
on, if used (55). On the basis of boiler heat
gen oxides emission factors for industrial coal-fired units have
been measured in the range of 100 ng/J to 562 ng/J (48).
"(53~Tcato, G. A., L. J. Muzio, and D. E. Shore. Field Besting:
Application of Combustion Modifications to C1***
Emissions from Industrial Boilers, Phase II.
<54)
* •« • wld J_ L1.C? v* O *A> A • ^4 ^* ~* *^* *^^ _ *^^\
neers, New York, New York, November 1960. 7 pp.
<55) Rawdon, A. H., and R. S. Sadowski. An Experimental Corel-
lation of Oxides of Nitrogen Emissions from Power Boilers
Based on Field Data. Journal ofvE"fJne^in?Q^°r power'
Transactions of the ASME, 95(A-3):165-170, i»/J.
41
-------
Sulfur Oxides and Particulate Sulfate Emissions
Emission factors calculated from the sampling data for sulfur
dioxide (SO2), sulfur trioxide (S03), and particulate sulfate
(SOi;) are listed in Table 16 for each of the runs made. The
sulfur dioxide concentrations measured ahead of the ESP show
little variance, and the average emission factor of 17.0 g/kg
agrees well with the published (45) emission factor (19.2 x
0.91% S = 17.5 g/kg). The emission measurements made after the
ESP show considerable variance among themselves and, when aver-
aged, are about 30% lower than measurements at the inlet. The
inlet and outlet measurements were not made simultaneously, and
the observed differences could be the result of variations in
the sulfur and trace element content of the coal. A statistical
analysis of the average emission factors for all three sulfur
species, before and after the ESP, reveals no significant differ"
ence in the values. The number of data points is too small to
draw any conclusions.
TABLE 16.
SULFUR OXIDES AND PARTICULATE
SULFATE EMISSION FACTORS
Sampling
run number
Emission factors, g/kg of coal
Particulate
sulfate
S02 SO3 as S0i+
Inlet to ESP
SI
S2
S3
Inlet averages
16.8
17.4
16.9
17.0
0.019
0.017
0.018
0.018
0.019
0.021
0.027
0.022
Outlet of ESP
S4
S5
S6
S7
Outlet averages
14.1
6.1
9.9
16.5
11.7
0.023
0.079
0.119
0.031
0.063
0.024
0.0076
0.025
0.0031
0.015
The particulate sulfate measurements made at the ESP outlet also
show more variance than those taken at the inlet. However, on
the average there appears to be a 35% reduction after the control
unit. This reduction is much lower than expected, particularly
when compared to the 98% reduction observed for total particulate_
matter, indicating that the sulfate may concentrate on the small6
particles.
42
-------
Carbon Monoxide Emissions
No carbon monoxide was measured at a detection level of 1 ppm.
This agrees with other emission measurements made under steady-
state baseload operation (47) .
Hydrocarbon Emissions
Analyses of two integrated gas samples provided an average total
gaseous hydrocarbon emission factor of 0.025 g/kg with less than
10% deviation between samples. A gas chromatographic analysis
for Ci through C6 hydrocarbons showed no measurable peaks at a
detection limit of 1 ppm.
A C7 through Ci6 gas chromatographic analysis performed on an
organic extract of the particulate matter collected by the SASS
train and the XAD2 resin from the organic module for each SASS
run revealed the presence of four to seven organic compounds in
each sample. These appeared to be in the C7 - C9 and Cm - Ci6
ranges. Concentrations were estimated for each compound, from
which an average total organic emission factor for the C7 - Ct6
range was calculated to be 0.068 g/kg.
POM and PCB Emissions
A number of POM compounds were detected and are listed in
Table 17 along with their individual emission factors and car-
cinogenic potential (56). Values represent the average of two
measurements. The uncontrolled POM measurements were determined
to be in error3 and were discarded; therefore, the emission fac-
tors presented are for controlled emissions only. However, it
has been reported in the literature that effluent POM concentra-
tions do not display significant changes on passage through
particulate controls, including precipitators (29). This was
recently verified by Monsanto Research Corporation (MRC) when
sampling POM emissions from utility boilers (57).
One measurement showed unrealistically high POM concentrations
while the other showed very low POM levels. These differences
could not be resolved, so the uncontrolled measurements were
discarded in favor of the uncontrolled measurements which showed
good agreement between the two runs.
(56) Biologic Effects of Atmospheric Pollutants - Particulate
Polycyclic Organic Matter. National Academy of Sciences,
Washington, D.C., 1972. 361 pp.
(57) Personal communication with D. G. DeAngelis, Monsanto
Research Corporation, Dayton, September 1977.
43
-------
TABLE 17. CONTROLLED POM EMISSION FACTORS3
DetectionEmission
limit, factor,
POM yg/kg yg/kg
Dibenzothiophene 0.8 4
Anthracene/phenanthrene 0.8 159
Methylanthracenes/phenanthrenes 1.7 10
Dimethylanthracenes/phenanthrenes 0.8 3
Fluoranthene 0.8 1^4 u
Pyrene 0.8
Methylfluoranthenes/pyrenes 0.8 19
Benzo(c)phenanthrene 0.8 5
Chrysene/benz(a)anthracene 0.8 ^17c
Dimethylbenz(a)anthracenes 5.0 29
Benzofluoranthenes 0.8 32^b c
Benzopyrenes (and perylene) 0.8 ~c'
Methylcholanthrenes 5.0 85
Indeno(l,2,3-c,d)pyrene 0.8 3Q
Dibenz(a,hji anthracene (or isomers) 0.8 13^ c
Dibenzo(c,g)carbazole 3.3 ~c'
Dibenzopyrenes 3.3 22
Methylchrysenes (or isomers) 1.7 37^
Anthanthrene/benzo(ghi) perylene 1.7
Total POM 1,499
Total carcinogenic POM 1,103
Average of duplicate analyses of two measurements.
Not detected.
These groups contain known carcinogens (56).
It is difficult to compare the POM values obtained by sampling
with previously published emission values due to recent advances
in analytical techniques. Using the only set of quantitative
POM values found in the literature for industrial boilers (58)
and some utility data (59), such a comparison indicates that
(58) Hangebrauck, R. P., D. J. vonLehmden, and J. E. Meeker.
Emissions of Polynuclear Hydrocarbons and Other Pollutants
from Heat-Generation and Incineration Processes. Journal °l
the Air Pollution Control Association, 14 (7) :267-278, 1964.
(59) Hangebrauck, R. P. D. J. vonLehmden, and J. E. Meeker.
Sources of Polynuclear Hydrocarbons in the Atmosphere.
Public Health Service Publication 999-AP-33 (PB 174 706)/
U.S. Department of Health, Education, and Welfare,
Cincinnati, Ohio, 1967. 44 pp.
44
-------
emissions from industrial boilers are an order of magnitude
higher than those from utilities, as has been suggested in the
literature (1). This is also supported by preliminary data
obtained for the Source Assessment on dry bottom utility boilers
firing pulverized bituminous coal (57).
No PCB emissions were found. Table 18 lists the analytical
detection limits for the method used in the PCB analysis.
TABLE 18. DETECTION LIMITS FOR PCB COMPOUNDS EXPRESSED
AS MINIMUM DETECTABLE EMISSION FACTORS
Detection limit,
PCB
Chlorobiphenyls
Dichlorobiphenyls
Trichlorobiphenyls
Tetrachlorobiphenyls
Pentachlorobiphenyls
Hexachlorobiphenyls
Heptachlorobiphenyls
Octachlorobiphenyls
Nonachlorobiphenyls
Decachlorobiphenyls
2.5
0.3
1.5
1.5
0.3
2.5
0.7
0.7
1.0
0.8
Elemental Emissions
Uncontrolled elemental emission factors for this source category
as defined are not available in the literature. Therefore, the
the emission factors listed in Table 14 under the heading of
Literature Data were estimated based on the average coal compo-
sition data in Table 12 (24-27). It was assumed that 100% of
each element was emitted on combustion.
Although one set of measurements has been reported for elemental
emissions after controls, the data are not considered representa-
tive of best control because the control device was a cyclone ot
65% efficiency (47). Therefore, to supplement data gathered in
MRC's test program, controlled elemental emission factors were
estimated based on partitioning behavior (see Table 13). Those
elements not enriched in the fly ash (Class I) were assigned a
controlled emission factor of 1% of the uncontrolled valve. For
elements falling between Class I and Class II, controlled emis-
sions were estimated to be 10% of the uncontrolled figures. For
Classes II and ril, it was assumed that controlled and uncon-
trolled emissions were equal.
45
-------
Elemental emission factors from the MRC sampling program are also
reported in Table 14. In general the uncontrolled emission
factors are comparable to the corresponding concentrations in the
feed coal, although several elements have values that differ by a
factor of two or more. In regard to the low uncontrolled emis-
sion factor for silicon (relative to its concentration in coal)/
it should be noted that when the ash samples were digested for
analysis an insoluble residue remained after repeated attempts
at a rigorous acid digestion. The undigested material was
assumed to be largely silicon, although it may have contained
other elements. Also, the concentrations measured for chromium,
nickel, molybdenum, and boron may be high due to contamination
of the samples by the sampling train. This is further discussed
in Section 8.
An average element control efficiency of 75% was measured for
the ESP. This is somewhat lower than the measured particulate
control efficiency (98.3%), indicating that many of these ele-
ments are concentrating on the smaller particles.
Table 19 shows the percentage of each of the measured elements
entering the boiler in the feed coal that was found in the
uncontrolled and controlled emissions during the MRC sampling
program. The percent reduction in concentrations of the ele-
ments in the flue gas achieved by the ESP is also shown.
TABLE 19.
PERCENTAGE OF EACH ELEMENT ENTERING THE BOILER
FOUND IN THE FLUE GAS BEFORE AND AFTER CONTROLS
Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron"
Cadmium
Calcium
Chromium
Cobalt
Copper
Irona
Lead
Magnesium
Manganese
Mercury
Molybdenum"
Nickel3
Phosphorus
Selenium
Silicon a
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Percent of
element in
uncontrolled
emissions
69
250
120
67
4.3
220
260
120
260
21
89
190
150
100
120
84
130
110
180
340
28
190
56
150
170
70
82
84
Percent of
element in
controlled
emissions
3.8
94
22
7.6
0.57
120
34
6.3
230
2.4
6.4
15
17
6. 3
120
93
32
55
19
160
4C
. w
14
16
6.4
11
2.7
51
. j.
22
Percent reduction
in flue gas
concentration
after the ESP
95
83
62
89
87
45
07
o /
95
12
go
o y
Q'l
y o
QO
y f>
OQ
oy
QA
y *t
0
75
A O
3 y
ft rt
89
53
84
99
71
96
94
Q £
96
94
74
due to
contamination. See
46
-------
POTENTIAL ENVIRONMENTAL EFFECTS
Air emissions released during the combustion of pulverized bitu-
minous coal in dry bottom industrial boilers enter the atmos-
phere and are dispersed throughout the environment. These
emissions have an adverse impact on the quality of air, water,
and land resources, property, vegetation, and animal and human
health. While the fate and environmental effects of many trace
pollutants are not known, those of the major species are well
documented (60-62).
The purpose of this segment is to evaluate the potential envi-
ronmental effects due to air emissions from an average plant in
this source category and from all boilers in the category. This
is done by defining an average source and the range of actual
sources and then comparing the expected maximum ground level con-
centrations of emitted pollutants (based on the emission factors
in Table 14) with air quality standards. In addition, the per
cent contributions of this source category to the state and
national emission burdens of criteria pollutants are presented.
Average Plant and Range of Actual Plants
A range of plants can be defined as discussed in Section 3. For
this report, the average source is defined as an industrial dry
bottom boiler firing pulverized Appalachian bituminous coal at a
rate of 222 GJ/hr. The stack height of the boiler is 45.7 m (11).
The firing rate is based on an average firing capacity value
calculated from a National Emissions Data System (NEDS) listing
for this source type (5), and the stack height is based on an
average obtained from Reference 11.
Sources in the NEDS listing (see Appendix A) range from a
capacity of 1 GJ/hr with a stack height of 6.7 m to a capacity
of 1,900 GJ/hr with a stack height of 67.1 m.
Source Severity
The potential environmental effects of air emissions from a
Point source can be measured in several ways. The method usea
here is to determine the maximum ground level concentration or
(60) Air Pollution; Volume I: Air Pollution and Its Effects,
Second Edition, A. C. Stern, ed. Academic Press, New York,
New York, 1968. 694 pp.
(61) Leighton, P. A. Photochemistry of Air Pollution. Academic
Press, New York, New York, 1961. 300 pp.
(62) Seinfeld, J. H. Air Pollution - Physical and Chemical
Fundamentals. McGraw-Hill Book Company, New York, New York,
1975. 523 pp.
47
-------
each emission species downwind from the average plant and compare
this value to the primary ambient air quality standard for cri-
teria emissions (63) or to a reduced threshold limit value (TLV)
(64) for the noncriteria emission species.
The comparison is called source severity, S , and is defined as
s _ xmax (2)
where 7.. = maximum time-averaged ground level concentration
for each emission species, g/m3
F = primary ambient air quality standard for criteria
pollutants (particulate matter, sulfur oxides,
nitrogen oxides, carbon monoxide, and hydrocar-
bons) , g/m3
or
F = TLV x 8/24 x 1/100, for noncriteria emission
species, g/m3 (3)
where TLV = threshold limit value for each species, g/m3
8/24 = correction factor to adjust the TLV to a 24-hr
exposure level
1/100 = safety factor
The value of xmax for an average source is calculated from
/t \°.17
X = x (— ) <4)
Amax Amax \ t /
where xm.,v = for elevated point sources
ma A. ~%To
TreuH2
and
Q = emission rate, g/s
TT = 3.14
e = 2.72
u = average wind speed, 4.5 m/s (national average)
t0 = short-term averaging time, 3 min
t = averaging time, min
H = height of emission release, m
(63) Code of Federal Regulations, Title 42 - Public Health,
Chapter IV - Environmental Protection Agency, Part 410 -
National Primary and Secondary Ambient Air Quality Stand-
ards, April 28, 1971. 16 pp.
(64) TLVs® Threshold Limit Values for Chemical Substances and
Physical Agents in the Workroom Environment with Intended
Changes for 1976. American Conference of Governmental
Industrial Hygienists, Cincinnati, Ohio, 1976. 97 pp.
48
-------
The equation for XmaX (Equation 5) is derived from the general
Plume dispersion equation for an elevated point source for
average U.S. atmospheric stability conditions (65).
The maximum severity of pollutants may be calculated using the
mass emission rate, Q, the height of the emissions, H, and the
TLVs (used for noncriteria pollutants). The equations summarized
in Table 20 are developed in Appendix D.
TABLE 20. POLLUTANT SEVERITY EQUATIONS
FOR ELEVATED SOURCES
Pollutant
Particulate matter
sox
NOX
Hydrocarbons
CO
Others
Severity equation
c 70 Q
p ~ H2
e _ 50 Q
bSOx H2
315
^NOX H2-
„ _ 162
"HC H2
0.78
"CO ~ H2
5.
"a TLV
Q
1
Q
Q
5 Q
• H2
The ambient air quality standards used for criteria pollutants
and the TLVs used for noncriteria pollutants are listed in
Tables 21 and 22 respectively.
Emission factors used for the severity calculations were se-
lected from Table 14 using the following priority: 1) MRC field
sampling data for controlled emissions, 2) literature data for
controlled emissions (estimated), or 3) literature data for un-
controlled emissions. Certain deviations from this order of
Priorities occurred as noted below:
(65) Turner, D. B. Workbook of Atmospheric Diversion Estimates
Public Health Service Publication 999-AP-26 PB 191 482),
U.S. Department of Health, Education, and Welfare,
Cincinnati, Ohio, 1969. 62 pp.
49
-------
Because the particulate emission factor as a function of
coal ash content was anomolously high for the MRC test
results, the literature value from Table 14 was used instead-
The uncontrolled particulate emission factor of 9.2A g/kg
was multiplied by the ESP collection efficiency observed in
the MRC tests (i.e., 98.3%) to give a controlled emission
factor of 0.16A g/kg.
The controlled SOX emission factor from the MRC tests was
not used because this behavior (i.e., a decrease in SOx
following an ESP) has not been reported previously in the
literature. An uncontrolled value of 19S g/kg was used to
calculate severity.
Literature values were used for the elements boron, chromi-
um, iron, molybdenum, nickel and silicon because the test
results were suspect, as noted previously.
TABLE 21. AMBIENT AIR QUALITY STANDARDS
FOR CRITERIA POLLUTANTS (63)
Ambient air
quality standard,
_ Emission _ mg/m3 _
Particulate matter 0.260
NOX 0.100
SOX 0.365
CO 40.0
Hydrocarbons 0.160
There is no primary ambient air quality
standard for hydrocarbons. The value of
160 y/m3 used for hydrocarbons in this
report is a recommended guideline for
meeting the primary ambient air quality
standard for oxidants.
Emission rates, Q, were calculated from emission factor data.
For example, the average plant generates 222 GJ/hr; therefore
= 222 Gj/hr . „£! — . kg coal . EF g
3,600 s 30 x 10 J Kg coal
Q = 2.06 • EF
where EF = emission factor, g/kg
50
-------
Similarly, the emission rates from the smallest (1 GJ/hr) and
largest (1,900 GJ/hr) sources reported in NEDS were calculated:
Q ... = 0.00976 • EF
wsmall
,
large
= 17.5 • EF
This provides a range of severities for the whole source cate-
gory. The severities for the average, smallest, and largest
Plants, and the values used to calculate them, are presented in
Tables 23, 24, and 25, respectively. For the average plant, the
only emissions with severities greater than 1.0 are NOX , SOX, and
carcinogenic POM's.
For source types with significant plume rise, the value of H in
Equation 5 must be corrected to include the plume rise. An
examination of NEDS data for this source shows that the increase
in emission height for a typical plant is ^35%. However, for
boilers that do not recover heat from the stack gas, the plume
rise may exceed the stack height.
Affected Population
Dispersion equations predict that the average ground level con-
centration, )f, varies with the distance, x, downwind from a
source. For elevated sources, x~ is zero at the source (where
x = 0) , increases to some maximum value, x~max' as x increases,
and then falls back to zero as x approaches infinity. Therefore,
a plot of X/F vs x will have the following appearance.
DISTANCE FROM SOURCE
affected population is defined as the number of nonplant
Persons around an average dry bottom industrial boiler firing
Pulverized bituminous coal who are exposed to x/F ratio greater
than 0.05 or 1.0. A severity of >1.0 indicates exposure to a
Potentially hazardous concentration of a pollutant. The severity
value of 0.05 allows for inherent uncertainties in measurement
techniques, dispersion modeling, and health effects data. The
Mathematical derivation of the affected population calculation
ls Presented in Appendix D. The number of persons within the
exposed area was calculated using a population density of 470
Persons/km2. This value was calculated by weighting the county
Population densities of the sources listed in NEDS by the number
51
-------
TABLE 22. THRESHOLD LIMIT VALUES USED
FOR NONCRITERIA POLLUTANTS (64)
Emission
TLV,
mg/m3
Compound used for TLV
POM 0. 2
POM (carcinogenic) 0.001
PCB 0.5
Sulfate 1.0
Elements:
Aluminum 10
Arsenic 0.5
Antimony 0.5
Barium 0.5
Beryllium 0.002
Bismuth 10
Boron 10
Bromine 0. 7
Cadmium 0.05
Calcium 5
Cerium 10
Cesium 2
Chlorine 7
Chromium 0.1
Cobalt 0.1
Copper 1
Dysprosium 10
Erbium 10
Europium 10
Fluorine 2
Gadolinum 10
Gallium 10
Germanium 10
Gold 10
Hafnium 0.5
Holmium ' 10
Iodine 1
Iridium 10
Iron 5
Lanthanum 10
Lead 0.15
Lithium 10
Lutetium 10
Magnesium 10
Manganese 5
Mercury 0.05
POM
Carcinogen
Chlorodiphenyl (54% chlorine) skin
Sulfuric acid, H2S04
Alundum, A12O3
Arsenic and compounds
Antimony and compounds
Barium (soluble compounds)
Beryllium
_b
Boron oxide
Bromine
Cadmium oxide fume
Calcium oxide
_b
Cesium hydroxide
Hydrogen chloride
Chromic acid and chromates
Cobalt .metal, dust and fume
Copper, dusts and mists
_b
b
~b
Fluorine
_b
_b
_b
_b
Hafnium
_b
Iodine
_b
Iron oxide fume
_b
Lead, inorganic fumes and dusts
~b
Magnesium oxide fume
Manganese and compounds
All forms except alkyl
(continued)
52
-------
TABLE 22 (continued)
Emission
TLV,
mg/m3
Compound used for TLV
Molybdenum
Neodymium
Nickel
Niobium
Osmium
Palladium
Phosphorus
Platinum
Potassium
Pr ae seodymium
Rhenium
Rhodium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
5
10
0.1
10
0.002
10
1
0.002
2
10
10
0.1
10
10
10
10
0.2
10
0.01
2
10
5
0.1
10
0.1
10
10
10
10
1
0.2
0.5
10
1
5
5
• .
Soluble compounds
_b
Soluble compounds
_b
Osmium tetoxide
_b
Phosphoric acid
Soluble salts
Potassium hydroxide
Metal fumes and dusts
b
~b
~b
Ib
Selenium compounds
Silicon
Metal and soluble compounds
Sodium hydroxide
_b
Tantalum
Tellurium
Thallium soluble compounds
Tin oxide
Titanium dioxide
Tungsten and compounds, soluble
Soluble and insoluble compounds
Vanadium pentoxide dust, V2O5
_b
Yttrium
Zinc oxide fume
Zirconium compounds
Value for carcinogenic compounds corresponds approximately to
the minimum detectable limit.
W elements not having an appropriate TLV, the TLV for nuisance
Particulate, 10 mg/m3, was used.
53
-------
TABLE 23. EMISSION RATES AND SOURCE
SEVERITIES OF AN AVERAGE PLANT
Pollutant
Particulate
NOx.
SOXC
CO
Hydrocarbons
POM (total)
POM (carcinogenic)
PCB
Sulfate
Elements :
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
Lanthanum
Lead
Lithium
Lutetium
Magnesium
Emission
g/s
1.
9.
5.
3.
2.
3.
4.
3.
3.
8.
5.
2.
6.
2.
9.
9.
2.
5.
4.
3.
5.
2.
5.
1.
1.
2.
1.
9.
2.
2.
4.
2.
4.
3.
1.
4.
5.
2.
4.
7
0
0
2
1
3
0
7
5
3
1
4
2
1
0
3
9
3
9
2
1
1
5
8
9
4
2
6
1
3
9
1
5
3
3
1
9
9
1
6
5
1
3.
x
x
.0
x
X
X
.0
X
X
X
X
X
X
X
X
X
X
X
X
X
.5
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
rate,
6
101
101
10-
10-
10-
10-
10-
10-
10-
10-
10-
2
3
3
2
1
2
3
3
5
io-6
10-
10-
10-
10-
10-
10-
2
2
-------
TABLE 23 (continued)
Emission rate,
Pollutant
Severity
„ .
Neodymium
Palladium
Potassium
Praeseodymium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
.
Strontium
Tantalum
m , -, .
Tellurium
Thorium
Thulium
-
Titanium
Tungsten
Vanadium
Ytterbium
Yttrium
3.3
1.0
6.4
2.5
3.1
1.1
2.1
3.5
6.2
4.7
4.3
4.1
7.6
2.1
3.9
1.1
3.3
5.6
1.8
1.1
x IU-"
x ID"3
x 10-2
x 10-3
x 10"*
x 1Q—*
x 10~2
x 10-*
x 10-2
x 10"3
x 10"*
x 10"*
x 10-*
x 10"*
x 10"5
x 10-*
x 10~3
x IQ-1
x ±0-3
x 10~1
^ i n —3
x
0 x
0 x
-
Zirconium
7 n v
7.0 x
2*1 x
2.1 x
9.9 x
2.1
2*
2.
5.8 x
82 x 10-3
8.2 x 10
2.0 x 10_^
8*7 x 10-3
I Q x
-1-0 x
-2
5.4 x 10-J
3.4 x 10-3
6.5 x 10~3
8.1 x 10~2
2.9 x 10~5
5.4 x 10-1
5.4 x 10-5
9.2 x 10-2
6.2 x 10~2
1.1 x ID'3
5.4 x 10"3
2'.0 x 10-*
5.4 x 10~5
2.8 x 10~5
4.3 x 10-2
1.5 x 10-1
-3
1-5
2.4
5.4
5.4
4.3
4.6
5.4
x 10-
x 10-3
x 10-s
v 10-2
x iu
^^
x 10-3
1Q_3
x 10-3
x 1Q_3
^ 1Q_2
x lO-^
10_^
x i().lt
x 10-3
x 10-*
'Emission height, H = 45.7 m;
design firing capacity = 222 GJ/hr.
'Based on an average ash content of 11.0% for
Appalachian coal.
:Based on an average sulfur content of 2.3% for
Appalachian coal.
55
-------
TABLE 24.
EMISSION RATES AND SOURCE SEVERITIES
OF THE SMALLEST PLANT3 ,
Pollutant
Particulate
NOX
soxc
CO
Hydrocarbons
POM (total)
POM (carcinogenic)
PCB
Sulfate
Elements :
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
Lanthanum
Lead
Lithium
Lutetium
Magnesium
Manganese
Emission rate,
g/s
1.7 x 1C-2
8.0 x 10-2
4.3 x 10-1
0.0
2.4 x 10-*
1.5 x 10~5
1.1 x 10~5
0.0
1.8 x 10-*
2.1 x 10~3
1.6 x 10-*
1.5 x 10~5
4.0 x 10~5
2.4 x 10~7
1.0 x 10~8
2.8 x 10-*
1.1 x 10-*
4.7 x 10-6
4.4 x 10-*
1.4 x 10~6
2.4 x lO-6
7.1 x lO-3
2.0 x 10~5
1.7 x lO-5
2.7 x 10-5
1.4 x 10-5
2.5 x 10~6
5.8 x 10-8
7.6 x 10-*
9.8 x 10~6
6.3 x 10-s
4.7 x 10~7
9.8 x 10~7
1.2 x 10~7
2.1 x 10~6
1.1 x 10~5
2.0 x 10~6
1.8 x 10-3
9.1 x 10~7
2.0 x 10-5
2.6 x 10-*
1.2 x 10~6
2.0 x 10-*
1.6 x 10-*
Severity
2.6 x 10-2
4.6 x 10~1
4.7 x 10-1
0.0
8.8 x 10-*
8.9 x lO-3
1.3
0.0
2.1 x 10-2
2.6 x 10-2
3.8 x 10-2
3.6 x 10-3
9.8 x lO-3
1.5 x 10-2
1.2 x 10-7
3.4 x 10-3
1.9 x 10~2
1.1 x 10-2
1.1 x 10-2
1.7 x 10-5
1.5 x 10-*
1.2 x 10~1
2.4 x 10-2
2.0 x 10-2
3.3 x lO-3
1.7 x 10-*
3.1 x 10-5
7.0 x 10-7
4.6 x 10-2
1.2 x 10-4
7.7 x 10-*
5.7 x 10-5
1.2 x 10-5
2.9 x 10-5
2.5 x 10-s
1.3 x lO-3
2.4 x 10-5
4.5 x 10-2
1.1 x 10-5
1.6 x 10-2
3.2 x lO-3
1.4 x 10-5
2.4 x lO-3
3.8 x lO-3
(continued)
56
-------
TABLE 24 (continued)
Pollutant
Emission rate/
Molybdenum
Neodymium
Niobium
Osmium
Palladium
Phosphorus
Platinum
Potassium
Praeseodymium
Rhodium
RubldlUm
Ruthenium
Samarium
Scandium
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
4.9 x 10-7
3.0 x 10~5
1.5 x 10"5
5.3 x 10-7
2.0 x 10~6
9.8 x 10-7
1 7 x
2.9 x
2.2 x
2. 0 x
2.0 x
9.8 x
3.6 x
_g
-7
5.0 x 1U~'
2.6 x ID"3
8.3 x 10~6
5.4 x 10-*
4.3 x 10~5
9.3 x 10-8
s!l x 10-6
9.8 x 10-7
4.7 x 10-7
9.8 x 10-7
9.7 x 10-5
l".4 x 10-5
3.9 x 10-5
9.6 x 10-6
1.1 x 10~6
6.7 x 10"5
4.9 x 10~6
1.2 x 10-3
7.4 x 1Q-*
1.4 x 10~3
1.8 x 10-2
6.4 x 10~6
1.2 x 10-1
1.2 x 10-5
2.0 x 10-2
2.4 x 10-5
1.2 x 10-3
4.4 x 10-5
1.2 x 10-5
x 10
10
1.0 x 10-1
3.3 x 10-2
5.3 x 10-*
2.3 x 10~6
4.0 x 10-3
3 8 x 10~"5
l'.2 x 10-3
5.7 x 10-6
1.2 x 10-5
1.5 x 10-3
1.2 x 10-3
8^3 x 10-3
9.5 x 10-3
1.2 x 10-*
1.3 x 10"*
1.0 x ID-3
1.2 x 10-*
Emission height, H - 6.71 m'
design firing capacity = 1 GJ/nr.
DBased on an average ash content of 11.0% for
Appalachian coal.
'Based on an average sulfur content of 2.3%
Appalachian coal.
for
57
-------
TABLE 25. EMISSION RATES AND SOURCE SEVERITIES
OF THE LARGEST PLANT
,a
Pollutant
Particulate
NOX
SOXC
CO
Hydrocarbons
POM (total)
POM (carcinogenic)
PCB
Sulfate
Elements:
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluroine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
Lanthanum
Lead
Lithium
Lutetium
Magnesium
Manganese
Emission rate,
g/s
3.1 x 101
1.4 x 102
7.6 x 102
0.0
4.4 x 10-1
2.6 x ID"2
1.9 x lO-2
0.0
3.2 x 10-1
3.9
2.8 x 10~1
2.6 x lO-2
7.2 x lO-2
4.4 x 10-*
1.8 x 10-5
5.1 x 10-1
1.9 x 10-1
8.4 x 10-3
7.9 x 10-1
2.5 x 10~3
4.4 x 10-3
1.3 x 102
3.5 x lO-2
3.0 x lO-2
4.9 x lO-2
2.5 x lO-2
4.6 x 10~3
1.0 x 10-*
1.4
1.8 x lO-2
1.1 x 10~1
8.4 x lO-2
1.8 x 10~3
2.1 x 10-*
3.7 x 10~3
1.9 x lO-2
3.5 x 10~3
3.3
1.6 x 10~3
3.5 x 10~2
4.7 x 10~1
2.1 x 10~3
3.5 x 10~1
2.8 x 10-1
Severity
4.7 x 10-1
6.6
8.5
0.0
1.6 x lO-2
1.6 x 10-1
2.4 x 101
0.0
3.8 x 10-1
4.5 x 10-1
6.8 x 10-1
6.4 x lO-2
1.7 x 10-1
2.7 x 10-1
2.1 x 10-6
6.2 x lO-2
3.3 x 10-1
2.0 x 10-1
1.9 x 10~1
3.0 x 10~*
2.7 x 10-3
2.2
4.3 x 10-1
3.6 x 10-1
6.0 x ID"2
3.0 x 10-3
5.5 x 10-*
1.3 x 10-5
8.3 x 10-1
2.1 x 10~3
1.4 x ID"2
1.0 x ID"2
2.1 x 10-*
5.1 x 10-*
4.5 x 10-*
2.3 x lO-2
4.3 x 10-*
8.1 x 10-1
2.0 x 10-*
2.8 x 10-1
5.8 x 10-2
2.6 x 10-*
4.3 x lO-2
6.8 x lO-2
(continued)
58
-------
TABLE 25 (continued)
Pollutant
Mercury
Molybdenum
Neodymium
Nickel
Niobium
Osmium
Palladium
Phosphorus
Platinum
Potassium
Praeseodymium
Rhenium
Rhodium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thallium
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
Emission rate,
q/s
8.8 x 10-"
5.4 x 10~2
2.1 x 10-1
2.6 x lO-2
9.5 x 10-*
3.5 x 10-3
1.8 x 10-3
3.0 x 10~1
5.3 x 10~3
4.0 x 10-1
3.7 x 10~2
3.5 x 10-3
1.8 x 10-3
6.5 x 10-3
1.8 x 10-3
3.3 x 10-*
8.9 x 10-*
2.8 x 10-2
4.7
1.5 x 10-2
9.6 x 10-1
7.7 x 10-2
1.7 x 10-*
6.0 x 10-3
5.6 x 10-3
1.8 x ID"3
8.4 x 10-*
1.8 x 10-3
2.3 x 10~1
1.7 x 10-1
4.9 x 10-3
2.5 x ID"2
7.0 x 10-2
1.7 x 10-2
1.9 x 10~3
7.4 x 10-2
8.8 x 10-3
— •
;
Severity
2.1 x 10~2
1.3 x 10-2
2.6 x 10-2
3.2 x 10-1
1.2 x 10 *
2.1
2.1 x 10 *
. 6 x 10 1
3.2
2.4 x 10-1
.5 x 10 3
4.3 x 10-*
.1 x 10 2
7.9 x 10-*
.1 x 10 *
.0 x 10 5
1.1 x 10-*
.7 x 10 1
5.8 x 10~1
. 8
5.9 x 10-1
9.4 x 10-3
4.0 x 10-5
7.2 x 10-2
6.8 x 10-*
2.1 x 10~2
1.0 x 10-*
2.1 x 10-*
2.8 x 10-2
2.1 x 10-2
6.0 x 10-3
1.5 x 10-1
1.7 x 10-1
2.1 x 10-3
2.3 x 10-3
1.8 x ID-2
2.1 x ID'3
—
• —
aEmission height, H = 67.1 m;
design firing capacity = 1,900 GJ/hr.
bBased on an average ash content of 11.0% for
Appalachian coal.
CBased on an average sulfur content of 2.3% for
Appalachian coal.
59
-------
of sources in that county (see Appendix A). Values for the
affected population around the average plant are listed in
Table 26 for pollutants with severities greater than 0.05
and 1.0.
TABLE 26. AFFECTED POPULATION FOR EMISSIONS WITH A
SOURCE SEVERITY GREATER THAN 0.05 AND 1.0
Emission speclea
Particulate
TJOu
HU X
SOx
Sulfate
POM (carcinogenic)
Elements:
Aluminum
Antimony
Beryllium
Bromine
Cadmium
Chlorine
Chromium
Cobalt
Fluorine
Iron
Lead
Nickel
Osmium
Phosphorus
Platinum
Potassium
Silicon
Silver
Sodium
Affected population, pereono
Sa >6.&5 Sa >1-0
2.500
42,000
63,000
1,900
190,000
2,500
3,900
1,000
1,500
560
15,000
2,200
1,700
5,000
5,000
1,200
1,400
14,000
1,700
22,000
870
3,200
12,000
3,200
0
1,200
2,200
0
7,500
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Contribution To Total State And National Emissions
The contributions of emissions from industrial dry bottom boi e
firing pulverized bituminous coal to the total emission ^ur
-------
TABLE 27.
TOTAL EMISSIONS AND PERCENT CONTRIBUTIONS TO STATE EMISSION BURDENS
FROM DRY BOTTOM INDUSTRIAL BOILERS FIRING PULVERIZED BITUMINOUS COAL
Total annual emissions from source
type (5), metric tons/yr
Partic- Hydro-
State ill an- S0v NO* carbons
Alabama
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Massachusetts
Michigan
Minnesota
Missouri
New York
North Carolina
Ohio
Oregon
Pennsylvania
Tennessee
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
U.S.
93
1,997
2,599
29,868
1,714
3,878
13
1,865
668
650
5,319
559
7,525
6,864
11,352
46,509
574
35,245
14,603
5,601
40,571
264"
1,482
7,535
380
228,788
1,900
5,665
1,815
40,378
20,342
25,703
275
7,244
17,293
380
30,318
655
7,083
26,477
23,003
83,155
1,278
72,677
22,243
1,670
46,808
328
5,831
7,646
2,515
452,682
1,373
669
1,558
7,377
6,576
8,725
37
1,497
6,036
94
20,764
246
1,805
6,327
9,613
19,192
865
12,918
12,206
1,304
16,771
92
2,299
1,334
1,802
141,480
23
10
19
142
106
300
1
11
57
6
1,319
4
31
105
397
165
2
466
287
34
330
5
90
88
6
4,004
CO
71
32
58
409
324
183
2
2
5
13
1,187
15
101
352
691
481
0
2,233
618
99
831
21
193
261
0
8,184
•TiM-al omissions from all sources (66), metric
Partic-
ulate
1,178,642
404,573
55,499
1,143,027
784,405
216,493
348,351
546,214
494,920
96,159
705,921
266,230
202,435
160,044
481,018
1,766,056
169,449
1,810,598
409,704
71,692
477,494
161,934
213,715
411,558
75,427
18,566,748
SOx
882,730
472,418
54,387
2,043,020
2,050,541
283,416
86,974
1,202,827
420,037
636,466
1,466,935
391,633
1,152,373
345,979
473,020
2,980,333
36,776
2,929,137
1,179,982
152,526
447,393
272,991
678,348
712,393
69,394
32,023,487
SOx
397,068
369,817
48,552
974,372
1,371,233
242,524
233,987
419,142
265,203
334,379
2,222,438
311,834
448,300
572,451
412,599
1,101,470
135,748
3,017,344
426,454
80,998
329,308
187,923
229,598
408,525
72,572
24,051,210
Hydro-
carbons
643,410
458,010
84,230
1,825,913
600,477
316,617
309,633
326,265
295,866
440,481
717,891
410,674
413,130
1,262,206
477,238
1,153,493
234,669
891,763
362,928
98,282
369,416
344,643
116,155
523,930
55,319
26,632,852
tons/yr
CO
1,885,657
2,036,010
343,720
6,412,718
2,933,780
1,440,621
1,002,375
1,189,932
1,261,804
1,682.218
3,243,525
1,760,749
1,854,901
4.881,922
1,734,397
5,205,718
929,247
3,729,830
1,469,253
402,527
1,548,031
1,659,117
494,214
1,582,869
303,297
101,693,648
Percent
Partic-
ulate
<0.01
0.5
4.7
2.6
0.2
1.8
<0.01
0.3
0.1
0.7
0.8
0.2
3.7
4.3
2.4
2.6
0.3
2.0
3.6
7.8
8.5
0.2
0.7
1.8
0.5
1.2
of total emissions burden
SOx
0.2
1.2
3.3
2.0
1.0
9.1
0.3
0.6
4.1
0.06
2.1
0.2
0.6
7.7
4.9
2.8
3.5
2.5
1.9
1.1
10.5
0.1
0.9
1.1
3.6
1.3
nyo.ro-
NOx carbons
0.3
0.2
3.2
0.8
0.5
3.6
0.02
0.4
2.3
0.03
0.9
0.08
0.4
1.1
2.3
1.7
0.6
0.4
2.9
1.6
5.1
0.05
1.0
0.3
2.5
0.5
<0.1
<0.01
0.02
<0.01
0.2
0.1
<0.01
<0.01
0.02
<0.01
0.2
<0.01
<0.01
<0.01
0.09
0.01
<0.01
0.05
0.08
0.03
0.09
<0.01
0.08
0.02
0.01
0.02
CO
<0 . 001
<0.01
<0.01
<0.01
0.01
0.01
<0.01
<0.01
<0.01
<0.01
0.04
<0.01
<0.01
<0.01
0.04
<0.01
<0.01
0.06
0.04
0.02
0.05
<0.01
0.04
0.02
<0.01
<0.01
-------
AIR EMISSIONS CONTROL TECHNOLOGY
Data from the National Emissions Data System (NEDS) for this
source shows that centrifugal collectors (cyclones) and electro-
static precipitators (ESP's) are the principal controls used
for air emissions (5). Treating the NEDS data as a random
sample of 440 dry bottom industrial boilers burning pulverized
bituminous'coal, it can be determined that approximately 50% o£
such boilers (both controlled and uncontrolled) are equipped
with either cyclones or ESP's, and that together these two
devices represent over 80% of the controls used. Table 28
provides a state-by-state summary of the NEDS data which shows
the percentage of boilers controlled and the distribution of
controls according to device type. The overall percent distri-
bution of control devices used for this source is shown in
Table 29 (5); as shown in the table, approximately 14% of the
sources included in the NEDS listing use more than one parti-
culate control device, usually a cyclone-ESP combination.
The remainder of this section discusses the current and future
emission control technologies for this source type. Because
little data exists in the literature for this source as defined/
information on emission controls for the more general category
of coal-fired industrial boilers (see Figure 3) is used. As a
result, some of the efficiencies presented may have been derive
from testing boilers that are not included in this specific
source (e.g., cyclone boilers, wet bottom boilers, or stokers)-
Particulate Controls
Almost every industrial boiler in use today is required to mee
local and/or state air pollution regulations (67). Design
efficiencies of commercially available equipment capable of
meeting the particulate regulations are listed in Table 30 (o) •
The efficiency values given in the table refer to intermediate
size coal combustion equipment including most industrial boil®
(stokers, pulverizers, cyclone, etc.), small utility boilers,
and large commercial/institutional units. Actual efficiencies
achieved by a given control device depend on the characteristi
and quantity of the particulate matter in the flue gas, which
turn depends on many factors including the operating and desi9
(67) Quillman, B., and C. W. Vogelsang. Control of Particulat
and SO2 Emissions from an Industrial Boiler Plant. Comb"
tion, 45(4):35-39, 1973.
62
-------
TABLE 28.
STATE-BY-STATE SUMMARY OF EMISSION CONTROLS DATA IN NEDS FOR DRY
BOTTOM INDUSTRIAL BOILERS BURNING PULVERIZED BITUMINOUS COAL (5)
U)
Total number
State of sources
Alabama
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Massachusetts
Michigan
Minnesota
Missouri
New York
North Carolina
Ohio
Oregon
Pennsylvania
Tennessee
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Totals
1
6
8
28
22
22
1
7
4
1
29
2
8
29
42
85
3
55
26
6
24
1
19
9
2
440
Number of
controlled
sources
1
6
5
17
11
14
1
4
4
0
17
1
8
19
26
39
3
32
17
3
21
0
19
3
2
273
• - • N
Number of control devices
Percent
controlled
100
100
63
61
50
64
100
57
100
0
59
50
100
66
62
46
100
58
65
50
88
0
100
33
100
62
Gravity Centrifugal Wet Fabric
collector collector ESP scrubber filter
1 4
1
6 3
2 8
3 12
4
3
15
3
18
1 19
29
3
26
3 14
3
16
3 8
19 191
1
2
2*\
&
31 5
1 1
6
1
3
2
7
5 2
8
10 1
18 3 1
2
5 2
5
4 3
9 7
2
88 15 23
umber of sources
with more than
one particulate
control device
1
1
2
12
1
5
8
63
Note.—Blanks indicate that no devices of the type specified appeared in the NEDS listing for that state.
-------
characteristics of the boiler, the composition (particularly ash
content) and nature of the coal, and the degree of coal pulver-
ization (68) .
Table 31 also presents particulate collection efficiencies as
reported in NEDS. These values demonstrate that actual operating
efficiencies are generally lower than design efficiencies.
Centrifugal Collectors —
As shown in Table 29, dry cyclones are used extensively to col-
lect fly ash generated by this source type. In the basic cyclone
™;;?Ct?r: ? entire mass of the gas stream with the entrained
m^ni ofafCS is.forced into a constrained vortex, achieved by
OVMO u .internal vanes, in the cylindrical portion of the
the *vT; JM^TS °f Sheir rotation with the carrier gas around
the axis of the tube and their higher density with respect to the
gas the entrained particulates are forced toward the wall by
centrifugal force and carried away by gravity and/or secondary
eddies toward the outlet at the b^ttoVor the ?Sbe ?he riow
most^f^heT^ ^ the 10W6r P°rtion of the tube, leaving
Sass throu^ ?hfainCd partlculate behind. The cleaned gases then
pass through the central, or exit, tube and out of the collector.
orceon™ ***?*' and the 9as f^ rate affect the
coUect!Sn elfic^^i68 fnterin9 the collector and thus affect
to collect higher ??;„ Lafger.and dens*r Particles are easier
For boiler; b^?n?n Y ra*es increase collection efficiency.
effic!ency8isUa£oC? l$Kl%? C°a1' the average collection
reli^le pr^arv"^!^^160^"."6 the least expensive and most
no longer fcceDLb?in devices f°* particulates, they are
efficiencies Pino?hin many areas °^ng to their low collection
1 thev can be «ed as pre-
J' Pilch«' ^- Varga, Jr., B. Gorser, and
™ces? Modifications for Control of Partic
an el « ^om Stationary Combustion, Incineration,
mental lro;ect^»/74'100 ' "-S. Environ-
"
1691 BoUeraA' ?i. AiLE1JUtlon C°ntro1 f°* industrial Coal-Fi
and control K ? L?fner^tlOn: Air Pollution Monitoring
Science Publishers ££ "L"-/^0"13' eds' *"" Arbor
pp. 529-542 ' *"" Arb°r, Michigan, 1976.
-------
TABLE 29. DISTRIBUTION OF CONTROL TYPES FOR
THOSE DRY BOTTOM INDUSTRIAL BOILERS
BURNING PULVERIZED BITUMINOUS COAL
HAVING CONTROLS (5)
Percent of
Type of control device controls in use
Gravity collectors 6
Centrifugal collectors 57
Electrostatic precipitators 26
Wet scrubber 4
Fabric filters 7
Dual controls3 14
Breakdown of dual controls used
Percent of dual
Dual control system controls in use
Centrifugal collector and
centrifugal collector 14
Centrifugual collector and
fabric filters 10
Centrifugal collector and
wet scrubbers 8
Gravity collector and
centrifugal collector 5
Centrifugal collector and
ESP 57
ESP and ESP 2
ESP and wet scrubber 3
Gravity collector and ESP 2
Two separate control devices used in series.
TABLE 30. DESIGN AND REPORTED EFFICIENCIES OF COMMERCIAL
PARTICULATE CONTROLS APPLIED TO INDUSTRIAL
SIZED BOILERS (5,8)
Design Ffficiency as
efficiency, reported in NEDS, *
Collector type
Centrifugal collectors
Gravity collector
Electrostatic precipitators
Fabric filters
Wet scrubbers
(low pressure drop)
Wet scrubbers
(high pressure drop)
%
94b
99.5
99.5
94 /
}
98 )
Range
25 to 99. 33
25 to 85
71.9 to 99.5
46.5 to 99.5
60 to 99
Average
79
56
96
91
SI
aupper end of range is high and may be in error.
Not reported.
65
-------
Electrostatic Precipitators—
An electrostatic precipitator (ESP) separates particles and mists
from gases by passing the gas stream between two electrodes
across which a unidirectional, high-voltage (20 kV to 80 kV DC)
potential is effected. The particles pass through this field*
becoming charged and migrating to the oppositely charged elec-
trode. Collected particles remain on the charged electrode
until removed, and the gas which has thus been cleaned moves
on to recovery or exhaust. Periodic vibration of the collecting
electrode surface causes the dust to drop into hoppers for
removal.
Very high collection efficiences can be achieved using ESP's;
most new units are rated at 99% or higher. However, many pre-
cipitators operate at 0.5% to 5% below the rated efficiency
because of adverse flue gas characteristics or mechanical/
electrical maintenance problems (8). Generally, collection
efficiencies are reduced as particle size decreases and gas fl°w
rate increases. The electrical resistivity of the fly ash is
also important; decreased resistivity improves collection
efficiency. In the temperature range characteristic of flue
gases, fly ash resistivity decreases with increasing tempera-
ture and with increasing sulfur and carbon content (70).
Fabric Filters—
In fabric filters, particles in the flue gas are mechanically
filtered out by tube-like cloth bags located in a baghouse
(enclosing structure). Removal of the trapped particles is
accomplished by shaking the bag, reversing the air flow, or
rapidly expanding the bags using compressed air. Chief draw-
backs of fabric filters are the high pressure drop required and
the short life-span of many bag materials.
Fabric filters are the most promising technology for controllin9
small (submicron) particulate matter. They can be extremely
efficient; removal efficiencies have been reported in the range
of 99.9% (71).
(70) Baxter, W. A. Electrostatic Precipitator Design for Weste •
Coals. In: Power Generation: Air Pollution Monitoring a ^
*c
Control, K. E. Noll and W. T. Davis, eds. Ann Arbor
Publishers, Inc., Ann Arbor, Michigan, 1976. pp. 415-423-
(71) Forester, W. S. Future Bright for Fabric Filters. Envir°D*
mental Science and Technology, 8(6):508, 1974.
66
-------
Wet Scrubbers—
Wet scrubbers use water or other liquids as the scrubbing agent
to remove particles and absorb gaseous emissions from combustion
gases. The liquid containing the pollutants is then separated
from the gas stream.
There are two categories of scrubbers: low energy (pressure drop
of 750 Pa to 3,700 Pa) and high energy (pressure drop of 3,700 Pa
to 25,000 Pa). Numerous scrubber configurations are used for
low energy units. Venturi type scrubbers are used in installa-
tions requiring high-energy collection of submicron particles.
The unique shape of the Venturi offers 98% velocity head (power
consumption) recovery, thereby allowing efficient introduction
of fluid to meet the gas crossflow in the throat region.
Scrubbers applied to coal-fired boilers typically operate in the
2,000 Pa to 3,700 Pa pressure drop range (69). Currently, few
wet scrubbers are used for this source type; such units may gain
Popularity if they are shown to be effective in reducing SOX
and/or NOX emissions.
Sulfur Oxides Control
Industrial boilers producing less than 264 x 10* GJ/hr are not
covered by federal SOx regulations but may be subject to state
standards which vary considerably. Two options are available
currently for meeting SOx emission limitations: use °* iow,-
sulfur coal, or installation of flue gas desulfurization (FDG)
systems.
SQx Control by Use of Low-Sulfur Coal—
Sulfur emissions from coal-fired boilers are directly related to
the sulfur content of the coal. A decrease in sulfurn^°n^f^r
results in a corresponding reduction in emissions. Low-suirur
°oal can be obtained from naturally occurring deposits or
through the physical cleaning of coal high in pyritic
Supplies of low-sulfur, high quality, eastern coal are
While low-sulfur western coal is available, its use in
industrial boilers will be limited. Western coal, ^th_its
generally lower heating value and higher moisture cont
Eastern coal, must be used in greater tonnage to meet a giv
stream output Boilers operating near design capacity and
burning alternate western coal could not meet orl^na^ ±_
requirements without extensive modification. It has been e
jated that supplies of low-sulfur coal will meet only 44% or tne
Demands in 1980 (72) .
^reen, R. Utilities Scrub Out SOX. Chemical Engineering,
84(11):101-103, 1977.
sulfur.
67
-------
Physical cleaning (beneficiation) of coal removes up to 80% of
the inorganic pyritic and sulfate sulfur; however, it does not
remove the organic sulfur which can account for 20% to 85% of
the sulfur present (72). Beneficiation is accomplished by crush-
ing the coal and separating the heavier pyrite-bearing particles
using techniques which utilize particle density differences.
This procedure is applicable to only about 17% of the coal
presently mined in the United States (73). In the remaining
coal, either the ratio of organic sulfur to inorganic sulfur is
too high or the sulfur content is too low to permit economic
handling.
SOX Control by Use of Flue Gas Desulfurization—
Sulfur oxides are removed from flue gas by absorption and/or
chemical reaction using a solid or liquid phase. Presently,
about two dozen FGD processes at various stages of development
are being evaluated in the United States. These processes are
classified as nonregenerable or regenerable, depending on the
fate of the reactive component of the absorbent. Nonregenerable
processes produce a sluge consisting of fly ash, water, and
sulfate/sulfite salts which must be discarded. In regenerable
processes, the sulfur is recovered and converted into marketable
products such as elemental sulfur, sulfuric acid, or concentrated
sulfur dioxide; the absorbent is regenerated and recycled.
The nonregenerable processes, which are developed farther and
used more than the regenerable processes, account for 90% (by
capacity) of all FGD systems applied to industrial boilers (74,
75). Lime scrubbing, sodium alkali scrubbing and the dual alkali
process represent the nonregenerable processses in commercial
use on industrial boilers. Regenerable processes under con-
struction or being planned include the Wellman-Lord and the
Citrate processes. Table 31 summarizes the results of a recent
survey of FGD systems applied to industrial boilers (74).
(73) Davis, J. C. Coal Cleaning Readies for Wider Sulfur-Removal
Role. Chemical Engineering, 83(5):70-74, 1976.
(74) Kaplan, N., and M. A. Maxwell. Removal of S02 from Indus-
trial Waste Gas. Chemical Engineering, 84(22):127-135, 1977.
(75) Tuttle, J., A. Patkar, and N. Gregory. EPA Industrial
Boiler FDG Survey: First Quarter 1978. EPA-600/7-78-052a
(2PB 279 214), U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, March 1978, 158 pp.
68
-------
Numerous process descriptions of the various FGD systems being
marketed or under development are available in the literature
(8, 76-78). Descriptions of the industrial boiler SOX scrubbers
currently in use or under construction are given in Table 32.
Available operating experience is also presented (70).
TABLE 31.
U.S. INDUSTRIAL-BOILER SO2
CONTROL SYSTEMS (74)
Reprinted by special permission from CHEMICAL ENGINEERING (October 17,
1977) Copyright (c) 1977, by McGraw-Hill, Inc., New York, N.Y. 10020.
Control system
Sodium alkali
scrubbing
Dual alkali
Lime/limestone
scrubbing
Wellman-Lord
Water scrubbing
Citrate process
Total
No. of
systems
12
2
1
4
2
1
1
1
1
1
1
27
Approximate
total output
capacity,
GJ/hr
2,820
623
72
396
720
43
36
72
360
4
180
5,326
Status
Operational
Under construction
Not operating
Operational
Under construction
Planned
Not operating
Operational
Planned
Not operating
Under construction
<76) Choi, P. s. K., E. L. Krapp, W. E. Ballantyne, M. Y. Anastas,
A. A. Putnam, D. W. Hissong, and T. J. Thomas. SO2 Reduction
in Non-Utility Combustion Source — Technical and Economic
Comparison of Alternatives. EPA-600/2-75-073 (PB 248 051),
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, October 1975. 316 pp.
(?7) Flue Gas Desulfurization and Sulfuric Acid Production via
Magnesia Scrubbing. EPA-625/2-75-007 (PB 258 817), U.S.
Environmental Protection Agency, Washington, D.C., iy/s.
24 pp.
(78) Shore, D., J. J. O'Donnell, and F. K. Chan. Evaluation of
R & D Investment Alternatives for SOx Air Pollution Control
Processes. EPA-650/2-74-098 (PB 238 263), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
September 1974. 288 pp.
69
-------
TABLE 32. DESCRIPTIONS OF INDUSTRIAL S02 SCRUBBERS (75)
Scrubber type
Sodium alkali
sodium alkali
Sodium alkali
Sodium alkali
Sodium alkali
sodium alkali
Plant and location
FMC (soda ash plant)
Green River, HY
Operational since
1976.
General Motors,
Chevrolet Motor
Division
Tonovanda, NY
Operational since
1975.
General Motors
St. Louis, MO
Operational since
1972.
General Motors,
Truck and Coach
Division
Pontiac, MI
Operational since
1976.
General Motors,
Delco Moraine
Dayton, OH
Operational since
1974.
MCR - Appleton
Roaring Springs, PA
Operational since
1977.
process description
System consists of two FMC
FMC sodium scrubbing
units to remove SOa from
the flue gas of two coal-
fired boilers (200 MW) .
The pH is maintained at
6.5 by addition of soda
ash (NaaCOa) liquor from
the plant.
System consists of four
GM sodium scrubbing
units equipped with
venturi scrubbers on
four coal-fired boilers
(32 MW) . The pH is main-
tained at 7.0 by addition
of caustic soda (NaOH) .
System consists of two
GM sodium scrubbing units
operable on two or four
coal-fired boilers
(25 MW) . The 3-stage
impingement tower is
followed by a Chevron
mist eliminator.
System consists of two
GM sodium scrubbing
units on two coal-fired
boilers (40 MM1 . The
pH is controlled by
addition of BaOH.
System consists of two
GM sodium scrubbing
units on two coal-fired
boilers (24 MM) .
System (installed by
Airpol) consists of a
a venturi followed by
an absorber i controls
Removal efficiency
of SO*
95* (800 ppm at inlet) .
Preceded by ESP to
remove particulates.
90* to 95* (1,000 ppm
at inlet) .
90% removal "of
particulates.
9O+* (2,000 ppm at
inlet) .
Preceded by cyclone
and ESP to remove
particulates .
Undetermined for SOa.
85* removal of
of particulates.
80*
85* removal of
particulates.
80 to 85*
Waste disposal1
Holding pond for
evaporation of
NaaSO3/S04 liquor, {
with no prior
aeration. Landfill
in future.
Fly ash and NaaSOi/SO*
waste liquor de-
watered and sent to
sanitary landfill.
Effluent discharged
to waste treatment
plant.
Wastewater is treated
(NaaSOl oxidiced to
(taaSOn; pH neutral-
ized) and dis-
charged to city
sewer system.
Neutralized scrubber
effluent is pumped
to clarifier and
recycled. Dewater-
ed sludge is land-
filled.
Hastewater is treated
and discharged to
city sewer system.
Dewatered sludge is
landfilled.
Hastewater is treated
and discharged to
city sewer system.
Operational experience
Successful operation. Scrub-
ber lining corroded as a result
of faulty installation. Foam-
ing and sedimentation in
scrubber occurred due to
impurities in liquor.
Successful operation. Major
problem areas have been pH
control, recycle pipe
erosion, and stack lining
corrosion. The pH control-
ler was replaced and cast
iron piping installed in-
stead of stainless steel.
Successful operation. Main
problem has been stack
corrosion.
Successful operation. Only
problem has been flyash
abrasion in pumps and
piping.
Successful operation, problem
areas have been fan bear-
ings (replaced three tiaes)
and stack corrosion.
Some liner problems.
SOi and particulate
from a coal-fired
boiler (12 MW.) . The
pH is controlled in
the 5 to 7 range by
addition of NaOH to
the recycle tank.
-------
TABLE 32 (continued)
Scrubber type
Sodium alkali
Sodium alkali
Sodium alkali
Sodium alkali
sodium alkali
Sodium alkali
Plant and location
Texasgulf
Granger , WY
Operational since
1976.
Sheller Globe Corp.
Norfolk, VA
Operational since
1975.
American Thread
Marion. HC
Operational since
1973.
Georgia-Pacific
Paper Co.
Crossett, AH
Operational since
1975.
Great Sourthern
paper Co.
Cedar Springs, GA
Operational since
1975.
Nekoosa Papers,
Inc.
Ashdovn, AR
Operational since
1976.
Process description
System, designed by Swej&co,
controls two coal-fired
boilers (65 HH) . The pH
is controlled by addition
of sodium carbonate.
System is a W. W. Sly
Impingjet scrubber that
controls SO? and partic-
ulates on a coal-fired
bailer (3.5 KM) . The
pH is controlled by
addition of NaOH.
System consists of two
W. H. Sly scrubbers
operating on two coal-
fired boilers (8 HH) .
The pH is controlled
at 6.5 by addition of
dilute NaOH solution.
Open loop system, de-
signed by Airpol, uses
•black water- from the
pulp mill as the
scrubbing liquor.
Installed on a coal/
bark-fired boiler
(100 MM).
TWO open loop scrubbers,
designed by Airpol, on
two coal/bark-fired
boilers (100 HH) .
Caustic waste stream
used for pH control.
System consists of two
Airpol scrubbers on
a coal-fired boiler
(50 MW). The pH is
controlled at 5.5 to
6.0 by addition of
sodiun hydroxide.
Removal efficiency
of SO*
90+%
Preceded by ESP to
to reoove partic—
ulates.
Not determined.
90%
97% removal of
particulates .
60% (500 ppm at
Inlet).
Preceded by cyclones
for paniculate
control .
B5% to 90% (1,000 ppm
at inlet) .
99% removal of partic-
ulates .
90+% (600 ppra at
inlet) -
93% to 99% removal
of particulates.
Waste disposal8
Holding pond for
evaporation.
Recycle tank super-
natant is neutral-
ized and discharged
to city sewer
system. Flyash and
sediment are sent
to landfill.
Haste slurry is pumped
to a clay-lined ash
basin for evapo-
ration.
wastewater is neutral-
ized and discharged
to city sewer
SYS tea.
Hastevater is ponded
and clarified water
ia discharged to
the river.
Ash alurry goes to a
settling pond.
Scrubber effluent
is treated and dis-
charged to the
river.
Operational experience
Corrosion of piping in the
recirculating lines.
Ho problems reported.
Main problem has been cor-
rosion of fans, stack, and
piping. Installation of
fiberglass lining has
placed a strain on fans
and resulted in severe
vibrations.
Successful operation with no
major problem. Fiber-
glass linings fail
frequently and are
replaced.
Problems include erosion and
plugging of pa probes i in-
ternal wear on pumps i and
erosion in the recirculat-
ing lines.
Original intent was to
recover NaaSOi* from
scrubber liquor for use
at the plant. This has
not yet been achieved.
The scrubber itself
operates well: major
problem has been lack
of adequate pH control
and resulting corrosion.
-------
TABLE 32 (continued)
Scrubber type plant and location
Process description
al efficiency
of SO*
Waste disposal
Operational experience
Sodium alkali Great Western
Sugar
Findlay, OH
Operational since
197*.
Sodium alkali Great Western
Sugar
Freemont, OH
Under
construction.
Sodium alkali
Kerr-HcGee
Chemical Corp.
Trona, CA
Under
construe tion.
Amco Steel
Middletown, OH
Operational since
1975.
Limestone
Rickenbacker
Air Force Base
Columbus, OH
Operational since
1976.
St. Joe Minerals
Corp.
Monaca, PA
tinder
construction.
Proprietary design using
sodium carbonate for pH
control.
proprietary design using
sodium carbonate for pB
control.
System consists of two
scrubbers using end
liquor from soda ash
(HaaCOa) plant on two
coal-fired boilers
(64 MM) . The pH is
maintained at 6 to
6.5 in the recircu-
lating liquor.
System consists of A
venturi scrubber fol-
lowed by an absorber
module, and serves
two coal-fired boilers.
System was changed
from recirculating to
once-through because
of abrasion. The pH
is maintained at 6 to
6.5 by addition of a
lime slurry.
System consists of a BABCO
scrubber serving seven
coal-fired boilers.
System developed by
Bureau of Mines uses
uses sodium citrate/
citric acid solution
to scrub SOa. Control
for a coal-fired
boiler (60 MM) .
Not reported.
Not available.
98*% (estimated)
Preceded by ESP for
for particulate
removal.
Nat available.
Hastewater is treated
and discharged to
city sewer system.
Wastewater will be
treated and dis-
charged to city
sewer system.
Scrubber bleed strea*
is clarified and
sent to salt ponds.
Holding pond for
evaporation.
Hot reported.
Not available.
Hot available.
90% (average) .
98* removal of
(articulates.
Not available.
Unstabilized slurry
(CaSOVSO.) sent
to holding pond.
This regenerable
system will produce
elemental sulfur as
a byproduct.
High excess air rates in the
the boilers have resulted
in poor performance.
Abrasion in piping has
been a problem. Mist
eliminator failed because
of creep in plastic con-
struction material.
Successful operation) problems
have been of a mechanical
nature, primarily with the
fan.
Not available.
-------
TABLE 32 (continued)
Scrubber type
Double alkali
Double alkali
Double alkali
Double alkali
Double alkali
Double alkali
Plant and location
Canton Textiles
Canton, GA
Operational since
1974.
Caterpillar Tractor
Co.
Joliet. IL
Operational since
1974.
Caterpillar Tractor
Morton, IL
Operational since
1973
Caterpillar Tractor
Hossville, IL
Operational since
1975.
Firestone Tire and
Rubber Co.
Pottsdown, PA
Operational since
1974.
General Hotors
Parma, OH
Operational since
1974.
Process description
System is an FMC venturi
scrubber using a caustic
plant waste stream for
SOa removal on1 a coal-
fired boiler (10 MU) .
Liquor is regenerated
with lime or limestone.
clarified, and then
either recycled or
discharged to waste-
water treatment
facility.
System consists of two Zurn
scrubbers on two coal-
fired boilers (18 MH) .
Scrubbing liquor is re-
generated by addition of
line (to precipitate
CaSO3/SO») and soda ash.
System consists of two Zurn
scrubber on two coal-
fired boilers (12 MM) .
Scrubbing liquor is re-
generated by addition of
line (to precipitate
CaSOi/SOo) and soda ash.
System consists of four
FMC scrubbers serving
four coal-fired boilers
(57 MB) .
Deskonstration systen con-
sists of FMC double
alkali scrubber control-
ling slip stream from a
coal-fired boiler.
System consists of four
SH/Koch scrubbers serving
four coal-fired boilers
(32 HH) . scrubbing
liquor is regenerated
with line and soda ash.
Removal efficiency
of SOx Haste disposal
70t (1,500 ppm at Treated scrubber
at inlet) . liquor and non-
80% to 901 removal "M"j flufryj"
, , diposed to l^ned
particulates. ^.^ ^^
9O+\ Dewatered slurry is
sent to landfill;
effluent is recycled-
Not available. Dewatered slurry is
sent to landfill;
effluent is recycled.
90+% Dewatered slurry is
landfilled.
90% (1,000 ppm at Dewatered slurry is
inlet} landfilled;
effluent recycled .
90% Dewatered slurry is
sent to a drying
pond and then
landfilled.
Operational experience
Ho major problems after
initial startup. At that
tiae plugging and foaming
occurred because of mate-
rials in the plant waste-
water used for scrubbing.
Successful operation.
Filter cloth in vacuum
filters lasts only 2 to
3 weeks.
Mo Major problems since
startup.
Major problems have teen
wear and erosion due to
flyash in recirculating
slurry and sludge.
No problems due to scaling
or plugging. Downtime
du« to parts failure or
uiatenance . Some
erosion encountered .
A nusiber of pro-blew have
occurred since startup,
primarily mechanical, but
soste plugging does occur*
Double alkali
Double alkali
Caterpillar Tractor
CO.
Mapleton, IL
Under construction.
Caterpillar Tractor
CO.
East Peoria, IL
Under
construction.
Systen will consist of
three FMC scrubbers
serving three coal-
fired boilers (100 KM).
System will consist of
four FMC scrubbers
serving four coal-fired
boilers (100 MW).
Not available.
Hot available.
Dewatered slurry will
be landfilled.
Dewatered slurry will
be landfilled.
Not available.
Not available.
comon practice is to recycle sc
before discharge.
rubber liquor; a portion is withdrawn to prevent too high a buildup of dissolved solids. This purge stream i, treated
-------
Nitrogen Oxides Control
Current applications of NOX controls to industrial boilers are
almost nonexistent; however, such controls are expected to in-
crease in view of impending local standards for some existing
units and planned New Source Performance Standards (NSPS) for
new units. Combustion modification and flue gas treatment (79)
are NOx control technologies presently in the demonstration
stage; each of these is briefly described below.
NOx Control by Combustion Modification
Current stationary source NOX emission standards and those envi-
sioned for the near future are based on combustion modification
techniques. In the temperature range used in dry bottom boilers,
thermal formation of NOX from atomspheric nitrogen does not make
a large contribution to total NOx emissions. Therefore, the most
effective combustion modification techniques focus on reducing
the oxidation of fuel nitrogen. The major factors influencing
the formation of NOX from fuel nitrogen are oxygen concentration,
fuel nitrogen content, temperature, and residence time (41-45,
80, 81).
Reduction of NOX from fuel bound nitrogen can be accomplished by
providing a fuel rich environment for combustion to occur. A
simple model of the nitrogen to NOX conversion process was devel-
oped, based on experimental data in which 1) the conversion
efficiency is inversely proportional to the weight fraction of
nitrogen in the fuel and 2) the conversion efficiency is linearly
proportional to the local air-fuel ratio, with zero NOX occurring
(79) Mason, H. B., and L. R. Waterland. Environmental Assessment
of Stationary Source NOX Combustion Modification Technolo-
gies. In: Proceedings of the Second Stationary Source Com-
bustion Symposium; Volume I: Small Industrial, Commercial,
and Residential Systems. EPA-600/7-77-073a (PB 270 923),
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, July 1977. pp. 37-82.
(80) Armento, W. J., and W. L. Sage. Effect of Design and Opera-
tion Variables on NOX Formation in Coal-Fired Furnaces:
Status Report. In: Air - II. Control of NOX and SOX Emis-
sions, AIChE Symposium -Series No. 148, 71:63-70, 1975.
(81) England, C. and J. Houseman. NOX Reduction Techniques in
Pulverized Coal Combustion. In: Proceedings, Coal Combustion
Seminar. EPA-650/2-73-021 (PB 224 210), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
September 1973. pp. 173-190.
74
-------
when there is just sufficient oxygen present to oxidize the fuel
carbon to carbon monoxide and the fuel hydrogen to water (82, 83).
Two successful approaches have been used to achieve fuel rich com-
bustion, thereby lowering NOx emissions from coal-fired boilers.
These are 1) the reduction of the amount of excess air fired and
2) staged combustion. Excess air refers to air added to a fur-
nace in excess of that required for stoichiometric combustion.
Various studies on industrial coal-fired boilers have shown that
reduction in the amount of excess air being fired is the best
method for changing primary flame zone conditions considering
such factors as ease of implementation, emission reduction, and
effect on boiler efficiency (51, 53, 80). NOx emissions decreased
an average to 50 ppm for each 1% reduction in excess airy a total
reduction of 38% from the baseline NOX emissions was found to be
attainable. Low excess-air operation improves boiler efficiency
and does not increase particulate emissions as do some other
Codifications.
Staged combustion describes a combustion modification technique
m which the lower level (or upstream) burners in a furnace are
fired with a fuel rich air/fuel mixture. The remainder of the
combustion air necessary to achieve complete combustion is then
added via the upper level (or downstream) burners. Combustion
thus occurs in two distinct stages, the first one being a fuel
rich stage where very little NOX can form from the fuel nitrogen.
The second stage attains a stoichiometric fuel/air ratio, but
the fiame temperature and residence time are conducive to lower
levels of NOx production. It has also been postulated that, in
the fuel rich region, fuel nitrogen is initially converted to NO.
However, in the presence of unreacted carbon and hydrogen, NO is
reduced to stable nitrogen compounds such as N2 (83). f^agea
combustion has been shown to yield substantially lower NOX levels
(50% decrease or more from baseline conditions, achieving below
2°0 ppm NOX in the exit gas concentration). However, fuel rich
Deration may create problems of combustion instability and
Boiler corrosion, if carried out to excessive levels (40% or
m°re of the combustion air diverted to the second stage) (83).
(82> Dykema, 0. W. Analysis of Test Data for NOx Control in
Coal-Fired Utility Boilers. EPA-600/2-76-274 (PB 261 066K
U.S. Environmental Protection Agency, Research Triangle Park
North Carolina, October 1976. 100 pp.
(83> Dykema, 0. W. Combustion Modification Effects on
Emissions from Gas-, Oil-, and Coal-Fired utlll^1,
EPA-600/2-78-217 (PB 289 898). U.S. Environmental Protec
tion Agency, Research Triangle Park, North Carolina,
December 1978. 97 pp.
75
-------
NOx Control by Flue Gas Treatment—
Should standards be promulgated that are more stringent than
those predicted, flue gas treatment may be required for NOX
emission reduction. Hence, experimental flue gas treatment
projects are progressing toward full-scale demonstration of
highly efficient control technology for NOX and NOX/SOX emis-
sions. These technologies, imported from Japan, are classified
as wet or dry processes.
Dry flue gas treatment processes being developed include the
following (84): 1) selective catalytic reduction, 2) selective
noncatalytic reduction, 3) adsorption, 4) nonselective catalytic
reduction, 5) catalytic decomposition, and 6) electron beam
radiation. Of these, only selective catalytic reduction has
achieved notable success in treating flue gas and progressed
to the point of being commercially applied (84). Selective
catalytic reduction is based on the reduction of NOX compounds
to N2 by reaction with ammonia. Two variations of selective
catalytic reduction are capable of removing both SOX (^90% ef-
ficient) and NOX (70% to 90% efficient). The other dry processes
are much less attractive at present due to their low NOX removal
efficiencies, nonapplicability to combustion sources, or early
stage of development.
Wet flue gas treatment processes under development include the
following (84): 1) oxidation-absorption, 2) absorption-oxidation,
3) oxidation-absorption-reduction, and 4) absorption-reduction.
The first two processes listed are generally used only for NOX
control. In oxidation-absorption, relatively insoluble nitrogen
oxide (NO) is oxidized in the gas phase to nitrogen dioxide (NOz)
which is absorbed into the liquid phase. In absorption-oxidation,
NO is absorbed directly into the liquid phase and then oxidized.
The last two processes listed above are designed to remove SOX
and NOX; they are basically modifications of existing flue gas
desulfurization processes. Due to their complexity, limited
applicability, and water pollution problems, wet processes can
not compete economically with the dry selective catalytic
reduction process.
(84) Mobley, J. D., and R. D. Stern. Status of Flue Gas Treat-
ment Technology for Control of NOX and Simultaneous Control
of SOX and NOX. In: Proceedings of the Second Stationary
Source Combustion Symposium; Volume III: Stationary Engine,
Industrial Process Combustion Systems, and Advanced Proc-
esses. EPA-600/7-77-073C (PB 271 757), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
July 1977. pp. 299-251.
76
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SECTION 5
WASTEWATER EFFLUENTS AND CONTROL TECHNOLOGY
SOURCES AND CHARACTERISTICS
Water usage in an industrial steam generating facility is complex
and results in a number of wastewater effluents. Most of _ the
required water is used for steam generation, cooling, equipment
cleaning, and ash transport. Effluents linked with these uses
contain: 1) ash and other coal combustion products; 2) chemicals
added on site as biocides, corrosion inhibitors, cleaning agents,
etc-; and, 3) water treatment wastes containing treatment chemi-
cals and the pollutants present in the water supply. Total
suspended solids (TSS) , iron, copper, hardness, and sulfate are
the principal pollutants found in coal-fired boiler effluents (1) .
Wastewater quantities and, to a lesser extent, wastewater
Dualities associated with the operation of industrial coal-fired
filers vary with the operating practices employed. The ma^or
factors responsible for this variation are listed below:
• Cooling water for steam condensation may be used once and
discharged, recirculated, or not used at all.
• Ash may be handled dry, or water slurried and sent to ash
ponds .
fv-UiUS .
• Depending on the quality of the water supply, a number of
water treatment processes are available for preparing
boiler feed water; each process generates different quan-
tities and qualities of wastewater.
• Numerous chemical additives (shown in Table 33) containing a
wide variety of active ingredients are available for use as
oxygen scavengers, scale and corrosion inhibitors, biocides,
water treatment chemicals, dispersing agents, cleaning
agents, and for pH control (19).
le 34 summarizes various boiler wastewater effluents and the
Or Pollutants and pollutant parameters applicable to each
eam (19). A brief description of each waste stream is pre-
te<* in the following paragraphs. Because very little informa-
n exists in the literature describing water usage or effluents
cific to this specific source type, the bulk of the information
sented was drawn from references describing effluents from
•••"fired utility boilers.
77
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TABLE 33. CHEMICAL ADDITIVES USED IN STEAM PLANTS FOR VARIOUS APPLICATION (19)
Use
Chemical
Use
Chemical
oo
Coagulant in clarification
water treatment
Regeneration of ion exchange
water treatment
Lime soda softening water
treatment
Corrosion inhibition or scale
prevention in boilers
pH control in boilers
Sludge conditioning
Oxygen scavengers in boilers
Boiler cleaning
Aluminum sulfate
Sodium aluminate
Ferrous sulfate
Ferric chloride
Calcium carbonate
Sulfuric acid
Caustic soda
Hydrochloric acid
Common salt
Soda ash
Ammonium hydroxide
Soda ash
Lime
Activated magnesia
Ferric salts
Dolomitic lime
Disodium phosphate
Trisodium phosphate
Sodium nitrate
Ammonia
Cyclohexylamine
Tannins
Lignins
Chelates such as ethylene-
diaminetetraacetic acid,
nitrilotriacetic acid
Hydrazine
Morphaline
Hydrocloric acid
Citric acid
Formic acid
Hydroxyacetic acid
Potassium bromate
Phosphates
Thiourea
Hydrazine
Ammonium hydroxide
Sodium hydroxide
Sodium carbonate
Nitrates
Regenerants of ion exchange
for condensate treatment
Corrosion inhibition or scale
prevention in cooling towers
Biocides in cooling towers
pH control in cooling towers
Dispersing agents in cooling
towers
Biocides in condenser cooling
water systems
Additives to house service
water systems
Numerous uses
Caustic soda
Sulfuric acid
Organic phosphates
Sodium phosphate
Chromates
Zinc salts
Synthetic organics
Chlorine
Hydrochlorous acid
Sodium hypochlorite
Calcium hypochlorite
Organic chromates
Organic zinc compounds
Chlorophenates
Triocyanates
Organic sulfurs
Sulfuric acid
Hydrochloric acid
Lignins
Tannins
Po lyacryloni.tr ile
Polyacrylamide
Polyacrylic acids
Polyacrylic acid salts
Chlorine
Hypochlorites
Chlorine
Chromates
Caustic soda
Borates
Nitrates
Numerous proprietary
chemicals
-------
TABLE 34. POLLUTANTS AND POLLUTANT PARAMETERS ASSOCIATED WITH
VARIOUS BOILER WASTEWATER EFFLUENTS (19)
Condenser
cooling
systems
Once-
Parameter through
Alkalinity X
BODa
CODb
TSC X
TDsd X
TSSe
Anmonia
Nitrate
Phosphorous
Turbidity
Acidity
Hardness
Sulfate
Sulfite
Bromide
Chloride
Fluoride
Aluminum
Boron
Chromium
Copper X
Iron
Lead
Magnesium
Mercury
Nickel
Selenium
Vanadium
Zinc
Oil and grease
Phenols
Surfactants
Algicides X
Chlorine X
Manganese
Recircu-
latlng
X
X
X
X
' X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Water
treatment Chemical
processes cleaning
Clarifi- Ion-
cation exchange
wastes wastes
X X
X X
X X
X X
X X
X X
X X
X X
X X
X
X X
X X
X
X X
X
X X
X X
X X
X X
X
X X
X X
X
X
•Evaporator Boiler Boiler Air
blowdown blowdown tubes preheater
X XXX
X XXX
X XXX
X XXX
X XXX
X XXX
X XXX
X XX
X XX
X XXX
X X
X XX
X XXX
X
X XXX
X
X XX
X XXX
X XXX
X XXX
X XXX
XV
*
X XXX
X XX
x
X
XY
**
X XX
Air pollution
Boiler Ash pond Coal pile Floor devices SOa
fireside overflow drainage drains removal
XX X
X XX
XX X
X X X X X
X X X X X
X X X X X
XXX
X X
XX *
X X X X X
X X X X X
v XX
A A A
X X X X X
V V
XX A A
XXX
X
XXX *
XXX
XXX
XXX X
X XX
X X X X X
X X
XXX
X X
XX x
XV
A
X XX
x x
x x
XXX X
3BOD = biochemical oxygen demand.
COD » chemical oxygen
CTS = total solids.
TDS « total dissolved
6TSS = total suspended
demand.
solids.
solids.
-------
Engineering judgment was exercised in determining the information
pertinent to this source type.
Waste Streams from Cooling Water
Because the relatively small average size of industrial boilers
(as compared to utility boilers) precludes the economical produc-
tion of electricity, it is assumed that most such boilers produce
low-grade steam for process and space heating, and that the steam
condenses as it is used, thus allowing it to be returned directly
to the boiler as feedwater. However, industrial units that prod-
uce high-temperature, high-pressure steam for electricity genera-
tion or other use must use cooling water to condense the spent
steam for reuse in the boiler to recover the heat and to
the cost of meeting feedwater quality requirements. Two 'types oi
cooling systems are commonly used: once through and recirculatinS'
Once-through cooling systems use cooling water only one time and
then discharge it. Because of the large volume of water used,
treatment of the influent is minimized, and the effluent is not
usually treated prior to discharge. Treatment of influent water
for once-through cooling usually entails intermittent doses of *
biocide such as chlorine or a hypochlorite. The frequency and
duration of biocide treatments vary from plant to plant; they ^"
be applied from once per day up to as many as ten times per day? .
and the duration of treatment varies between 5 minutes and 2 hour
resulting in residual chlorine concentrations in the range of
0.1 g/ms to 1 g/m3 (19) . in addition to any chemicals added to
the system, the cooling-water discharge will contain particles
resulting from corrosion and erosion of the condenser tubes.
If the steam generating plant is not located near a large body °*
water, a once- through cooling system is impractical, and a
recirculating system must be installed to minimize water costs
and discharges. Recirculating systems discharge their waste
heat through evaporation of some of the recirculating water in *
cooling tower or pond. During evaporation, water vapor is f.<
removed and some entrainment of droplets in the air draft (drift;
occurs; hence, the salts dissolved in the cooling water become
more concentrated. To limit the concentrations of dissolved
solids and to prevent their deposition on heat transfer surfaces/
some water must be removed as blowdown. The rate of blowdown
depends on the quality of the make-up water and the permissible
concentration factor for a particular system. Unless limited W
a specific discharge permit, the concentration factor is based °*
that required to protect plant equipment from scaling, fouling •
corrosion, or excessive deposits. Blowdown rates range from
0.1% of the circulating water flow for high-quality, make-up
80
-------
water to as much as 5.0% for brackish water (85). Pollutants
found in cooling water blowdown consist of a concentration of
the species found in the water source, 2) air pollutants absorbed
or entrained in the cooling water while in the tower, which acts
as a wet scrubber for the ambient air, and 3) chemicals added for
various purposes. Condenser materials are generally chosen to
resist corrosion; thus special chemicals for corrosion control
are not required unless the influent is high in chlorides.
Waste Streams from Water Treatment Processes
Because all water supplies contain some suspended solids and
dissolved chemical salts, water intended for boiler use must be
treated prior to use. Treatment processes include clarification,
softening, ion exchange, and evaporation.
In the clarification process, used in the treatment of surface
waters, suspended solids (turbidity) are removed through an
agglomeration and settling process followed by filtration. The
waste streams produced consist of a sludge and filter £a^wau£
water. The wastewater loading and the concentration of pollutants
in the filter wash are both low; hence, this stream can be
returned to the start of the process thus eliminating the genera
tion of wastewater.
In the softening process, ions causing hardness are
and removed as a sludge; no wastewater stream is Jfe
fudges resulting from softening and clarif lca^n treatments
WH1 be discussed in Section 6 which covers solid waste control
technology.
In the ion-exchange process, resins selectively rf^ Cations
^d anions from feed water and replace them with hydrogen and
hydroxyl ions. When the exchange capacity of a fesin has been of
**t, the resin must be regenerated resulting in Jhe production of
wastewater. Regeneration is a three-stage process Consisting ot
J backwash to remove solids from the bed, a chemica 1 contact step
that releases the impurities from the resin, and a rinse to
r^ove the impurities and regenerating chemicals The ch emical
Characteristics of the wastewater produced depend on the type of
and the influent water quality. However , such wa stewater
contains suspended solids, regenerants ™"""
(85) Assessment of the Costs and Capabilities of Water Pollution
Control Technology for the Steam Electric Power Industry.
NCWQ 75/86 (PB 251 372), National Commission on Water
Quality, Washington, D.C., March 1976. 1164 pp.
81
-------
volume of wastewater produced depends on the size and design of
the ion-exchange unit. Typically, the bed is washed for 10 min
to 15 min at a flow rate of 3.4 x 10~3 m3/s to 4.1 x 10~3 m3/s
per square meter. The cation resins are then contacted for
approximately 30 min by passing the regenerant, containing two
to four times the stoichiometric exchange capacity of the resin/
through the bed at a controlled rate. Approximately 8 m3 of
water per cubic meter of resin is used to rinse the bed after
regeneration of the cation resin. The anion resin is contacted
for approximately 90 min with sodium hydroxide at a concentration
of about 4% followed by a rinse of about 10 m3 of water per cut>ic
meter of resin (19). The frequency of regeneration depends on
the influent water quality and the bed volume.
In the evaporation process, used occasionally for boiler water
treatment, feed water is purified using vaporization followed t>V
external condensation and collection. During the evaporation
process, a blowdown stream is maintained to prevent dissolved
solids from scaling the heat transfer surfaces. The blowdown is
similar in composition to that of influent water except that the
impurity concentration is several times as large and the pH val^e
is between 9 and 11 owing to the decomposition of bicarbonate
ions into carbon dioxide, which comes off with water vapor, and
carbonate ions.
Waste Streams from Boiler Blowdown
In addition to feedwater treatment, internal treatment of boiier
waters is performed to prevent scale formation, to precipitate
dissolved solids as a sludge, and to maintain the sludge in a
fluid state for removal as blowdown. Blowdown, the controlled
discharge of a portion of the boiler water, can be either
continuous or intermittent. The quantity of blowdown wastewater
varies up to 0.02 m3 per 450 kg of steam generated (19).
Boiler blowdown characteristics vary with the quality of the
feedwater and the chemicals used for internal treatment. Some
of the chemicals used for scale prevention, corrosion inhibit
pH control, and oxygen scavenging are included in Table 33 (s
earlier). Generally, blowdown is an alkaline waste with a
value of 9.5 to 11.
Blowdown from medium-pressure boilers has a total dissolved
solds (TDS) concentration in the range of 100 g/m3 to 500 g
while that from high-pressure boilers is in the range of 10 Q™
to 100 g/m3. If phosphate treatment is used for scale or corro
sion control, the waste will contain from 5 g/m3 to 50 g/m3 °f
phosphate and from 10 g/m3 to 100 g/m3 of hydroxide alkalinity-
Blowdown from boilers in which hydrazine is used for oxygen
scavenging contains up to 2 g/m3 of ammonia (19)
82
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Waste Streams from Equipment Cleaning
Periodically, boiler equipment must be removed from service and
cleaned to maintain the heat transfer surfaces and other miscel-
laneous parts. Because each cleaning operation is tailored to
the needs of particular equipment, the major operations involved
are briefly reviewed on an individual basis in the following
Paragraphs.
Water Side Boiler Cleaning—
Because of differences in boiler scale composition, no set proc-
ess exists for the internal cleaning of boiler tubes. Normally,
the cleaning chemicals and procedure are based on the analysis of
a boiler-scale sample. The nature of the resultant wastewater
depends on the cleaning agents used, but it may contain alkalin-
ity, organic compounds, phosphates, ammonium compounds, and
Scale components such as copper, iron and hardness. The fre~
quency of boiler-tube cleaning varies considerably, in one study,
the average time between cleanings was thirty months with a
standard deviation of eighteen months, and its range was one
cleaning every seven months to one cleaning every 100 months (19).
lg_ij.er Fireside Cleaning— , ^--K^,™
BoTle^ tube exteriors are cleaned to remove ash and Corrosion
Products. Cleaning may be accomplished using a hl^"PreJ^s
hose or chemicals such as soda ash or other alkalin*,m^"1£^h
to enhance the cleaning action. The waste stream may show high
values for pH and hardness, and will contain suspended solids
and some metals.
Qondensor Cleaning—
i^i»aensor Cleaning— . -,
fetnoug'h the steam side of a condenser rarely requires cleaning,
1nhibited HC1 is usually used for water side cleaning.
j^ULreheater Cleaning— . .,_«.„ 4_h-,4- noPd
?riHia-Eers are generally cleaned in a manner similar to that used
ja boiier firesides. Soda ash and phosphates or detergents may
be added to the high-pressure water stream. Depending on the
Sulfur content of the fuel, effluents are more or less a"dic
*» nature. Waste stream constituents include fly ash, soot, rust,
[SST^M £££trpS2S£ ^aninfis W-
°.n the average about once each month, although the frequence
range varies between four and 180 times per year.
'ment Cleaning— . ^v,,-- -in^i HH^Q
f Cuus equipment also requires cleaning; this Deludes
feedwater heaters stacks, cooling-tower basins, air-compressor
c°olers, and other units. The cleaning processes, chemicals, and
characteristics are similar to those described above.
83
-------
Waste Streams from Ash Handling and Ash Pond Wastewaters
Bottom ash and fly ash may be handled and transported on site
using wet (sluicing) or dry (pneumatic) methods depending on the
ash volume, type of collection system (i.e., wet scrubbers or
ESP), availability of land, cost of water, and other factors.
While no data is available on the percent usage of the wet or
dry methods for the specific source type being studied, one
report assumes that boilers with design capacities less than
530 GJ/hr handle their ash using a dry method (1) .
Handling and transport water usage ranges from 5 to 17 mVmetric
ton of ash conveyed for fly ash, and from 10 to 170 ma/metric ton
of ash conveyed for bottom ash. Ash pond discharge rates for the
utility sector, which should approximate those for industry, vary
from approximately 0.005 ma/s per million metric tons of coal
burned per year to approximately 0.8 m3/s per million metric tons
of coal burned per year, with the median value being approximately
0.2 mys per million metric tons of coal burned per year (19).
SJiiJJ ^ ln the dischar
-------
Other Waste Streams
A number of minor miscellaneous waste streams may be present at a
9iven industrial steam plant; these include sanitary wastes,
floor drains, and laboratory drains. Because such sources
usually feed into a sanitary sewer system, they will not be
covered in this assessment report.
EFFLUENT DATA
The literature related to industrial boilers contains no data
that characterize the effluents from this specific source type in
sufficient detail to permit the calculation of effluent factors
°r the full description of water usage and wastewater handling
Practices. Therefore, the effluent data presented are derived
totally from the field sampling effort conducted as part of this
Program (see Appendix C) .
iption of Waste Streams Sampled
Jhere were five wastewater streams related to the operation of
the boiler at the site sampled. These streams consisted of
•"•' a continuous boiler blowdown, 2) wastes resulting from the
^generation of an ion-exchange bed used in feedwater treatment,
*> cooling water for the induced-draft fan bearings, 4) wash
water from cleaning the steam used to operate the pneumatic ash
transport system, and 5) wastewater from equipment cleaning
operations. Equipment cleaning wastes were not sampled because
m°st cleaning operations are conducted only once per year.
Sfe^ggL.Quality Parameters and Elemental Concentrations of Waste
Sampled
*he sampled waste streams, which exclude condenser cooling water
no ash sluicing water (which are major effluents in utility
oilers), and the water and effluent practices employed (e.g.,
rje use of municipal drinking water supplies, and the discharge
.o a municipal sewer system) are assumed to be typical of boilers
n the source type studied. Measured water quality parameters
£d elemental concentrations are shown in Tables 35 and 36,
espectively, for the various wastewater s. An analysis of the
ater supply is also shown in each table for comparison.
— Qjent Factors for Combined Wastewater Stream
Vetimates of effluent flows as a function of coal consumption
maj;e Derived from plant records, data supplied by equipment
jjnufacturers, and observation of wastewater flows. These values,
^sted in Table 37, were used in conjunction with the data
tjjntained in Tables 35 and 36 to calculate effluent factors for
e combined wastewater flow which are shown in Table 38 .
85
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TABLE 35.
CO
MEASURED VALUES FOR POLLUTANT CONCENTRATIONS AND WATER QUALITY
PARAMETERS FOR WATER SOURCE AND WASTEWATER STREAMS
Water quality
parameter
Acidity f
Alkalinity
Ammonia
COD
Hardness
Nitrate
pH
Phenol
PCS
POM
Sulfate
Sulfite
TDS
TSS
Total solids (TS)J
Units
g/m3 as CaCO3
g/m3 as CaCOa
g/m3
g/m3
g/m3 as CaCOa
g/m3
pH units
g/m3
g/m3
g/m3
g/m3
g/m3
g/m3
g/m3
g/m3
a
Water source
1
2
<0.059
13
138
1.25
8.04
0.011
_h
-
71
<2.09
276
2
302
Boiler
blowdown
_e
872
<0.059
84
168
17.0
11.18
0.01J
•j
1,360
<2.09
4,210
11
4,300
Wastewater streams
Feed water
treatment^
16
2
<0.059
3,670
19,200
1.08
7.40
0.007
_n
-
109
<2.09
88,400
82
86,900
Fan bearing
cooling water
1
2
<0.059
12
138
1.18
8.00
0.007
_h
-
72
<2.09
160
4
238
Wash from c
ash transport
29
8
<0.059
1,360
297
2.70
4.69
0.008
_n
•j
199
<2.09
601
7,500
9,750
aMunicipal drinking water supply.
Composite of backwash, regeneration, and rinse waste streams from an ion-exchange unit.
GWaste stream from wash of steam used to operate the pneumatic ash transport system; wastewater contains
precipitator ash.
dTaken to pH 8.3.
eNot analyzed due to high pH.
DTaken to pH 4.5.
9concentration below the given detection limit.
^Not detected at the detection levels shown in Table 17.
^Not detected at the detection levels shown in Table 17.
•^TS is not equal to the sum of TDS and TSS because each value was determined independently.
-------
TABLE 36. ELEMENTAL CONCENTRATIONS MEASURED IN WATER SOURCE AND WASTEWATER STREAMS
oo
Wastewater streams
Element Water source
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
0.0537
0.0406
<0.002d
0.0397
<0.005d
0.0612
0.0039
23.9
0.0140
0.0100
0.0106
0.0165
0.0612
19.4
0.0007
<0.002d
0.0329
0.111
0.205 .
<0.010
3.61
0.0302
23.2
0.464
0.0309
0.0006
0.127
0.0369
<2.0d
Boiler
blowdown
0.570
0.0589
0.004 d
<0.0002
<0.005d
0.911
0.0051
2.32
0.0195
0.0124
0.107
0.564
0.110
2.32
0.0363
<0.002d
0.104
0.147
22.3 d
<0.010a
51.2
0.0375
827
0.0563
0.0416
0.0162
0.0347
0.0551
<2.0d
Feedwater. Fan-bearing
treatment cooling water
46.0
2.92
<0.002d
11.14
<0.005d
<0.001d
<0.002d
2,970
1.07
0.170,
<0.004
0.120
4.39
2,180 j
<0.0005
<0.002d
2.42
9.92
15.7 d
<0.010
9.53
1.74
20,240
72.1
2.38
0.01
14.1 d
-------
TABLE 37.
ESTIMATED DISCHARGE RATES
OF WASTEWATER STREAMS
Wastewater stream
Discharge rate,
Boiler blowdown
Feedwater treatment
Fan-bearing cooling water
Wash from ash transport
Total wastewater flow
5
2
6
1
1.
'*-*3
.8
.0
.2
.2
52
x
X
X
X
X
L w*_ra j_
10-*
10~*
TABLE 38. EFFLUENT FACTORS FOR COMBINED WASTE STREAM*
Effluent species
Acidity (as CaC03)
Alkalinity (as CaC03)
Ammonia
LUL)
Hardness (as CaC03)
Nitrate
Phenol
PCB
POM
Sulfate
Sulfite
TDS
TSS
Total solids (TS)
Elements:
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Includes boiler blowdo
operate pneumatic ash
treatment ion-exchange
Effluent factor,
g/kg coal
7.3 x 10-*
5.1 x 10-1
0
9.5 x 10-1
4.1
1.1 x 10~3
1.4 x 10-3
0
8.8 x 10-1
2.0 x 101
9.2 x 10-1
2.1 x 101
2.5 x 10-»
7.1 x 10-*
2.8 x 10-*
2.4 x 10-3
2.6 x 10-s
8.1 x 10-*
« J. X 10s
wn, fan-bearing cooling
transport system, and w
unit.
Eff
Effluent species
Elements (continued) :
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
q/kg^coai^—
6? x 10"
• * ** u
- • 1 ::
7:2 x io:;
1:1 * }Q'\
8'n v IS-'
3.0 X 10 .
6.1 x 10 3
2.2 X 10
1.8 x 1J-«
1.5 X 1:J_3
4.0 x 10 u
4.2 x 10
4.5
1.5 x 10".
5.5 x 10^
4.9 x 10 3
3.3 x 10
1.6 x 10.
3.0 x 1 ° _^,
_ __ -—^: — "^
water, water wash of steam used to dwat«r
iste stream from regeneration of *ee
88
-------
POTENTIAL ENVIRONMENTAL EFFECTS
!ndustrial wastes discharged to a river or lake can have a detri-
mental effect on aquatic life and on other animals, including
nan, that use the water for recreational purposes (fishing, swim-
ming, etc.) or for drinking. Information on the environmental
effects and eventual fate of most pollutant species is readily
avaiiable in the literature (87, 88).
Potential for environmental damage resulting from the dis-
9e of effluents from the operation of pulverized bituminous
-fired dry bottom industrial boilers is evaluated in a manner
An ~0gous to that used to evaluate the effects from air emissions.
d*LaVerage source is defined, and pollutant concentrations are
^termined for the effluent after dispersion into an average
cnVer at mininmm flow. The pollutant concentrations are then
spared to water quality criteria.
Th
wj? average source, as defined in Section 4, consists of a boiler
t,tn a design capacity of 222 GJ/hr. The wastewater streams from
ofe operation of this boiler are assumed to be the same as those
boii boiler sampled. This is a reasonable assumption for
ter in this size range. Major deviations should be encoun-
hav °nly for the largest boilers in this source type which may
3e e Discharges of ash sluicing water and/or once-through con-
&isv!r co°ling water or recirculating cooling water blowdown.
thos ges from these large units should closely approximate
e from utility sources.
Th
sigtreceiving water for discharges from the average source con-
min,s of a river with an average flow rate of 725 m3/s and a
-• lmum flow rate of 267 m3/s. These values are averages for the
's flowing through or near cities in which the boilers in
source type are located according to the NEDS listing. The
0 and flow rates used in these calculations are listed in
B (89-115)
Klein, L. River Pollution II: Causes and Effects. Butter-
*orth and Co., Limited, London, England, 1962. 456 pp.
88) Quality Criteria for Water. EPA-440/9-76-023 (PB 263 943),
U.S. Environmental Protection Agency, Washington, D.C.,
July 1976< 5Q1 pp<
9) Water Resources Data for Alabama, Water Year 1975. USGS/WRD/
HD-76/003 (PB 251 854), U.S. Geological Survey, Water
Resources Division, University, Alabama, January 1976.
391 PP.
(continued)
89
-------
(continued)
(90) Water Resources Data for Georgia, Water Year 1975. USGS/
WRD/HD-76/006 (PB 251 856), U.S. Geological Survey, Water
Resources Division, Dorsville, Georgia, February 1976.
378 pp.
(91) Water Resources Data for Idaho, Water Year 1975 USGS/WRD/
HD-76/034 (PB 263 998), U.S. Geological Survey, Water
Resources Division, Boise, Idaho, July 1976. 698 pp.
(92) Water Resources Data for Illinois, Water Year 1975. USGS/
WRD/HD-76/013 (PB 254 434), U.S. Geological Survey, Water
Resources Division, Champaign, Illinois, April 1976.
408 pp.
(93) Water Resources Data for Indiana, Water Year 1975. USGS/
WRD/HD-76/010 (PB 251 859), U.S. Geological Survey, Water
Resources Division, Indianapolis, Indiana, March 1976.
368 pp.
(94) Water Resources Data for Iowa, Water Year 1975. USGS/WRD/
HD-76/009 (PB 251 858), U.S. Geological Survey, Water
Resources Division, Iowa City, Iowa, February 1976. 303 pP'
(95) Water Resources Data for Kansas, Water Year 1975 USGS/WRD/
HD-76/008 (PB 251 857), U.S. Geological Survey, Water
Resources Division, Lawrence, Kansas, February 1976. 401 PP'
(96) Water Resources Data for Kentucky, Water Year 1975. USGS/
WRD/HD-76/002 (PB 251 853), U.S. Geological Survey, Water
Resources Division, Louisville, Kentucky, January 1976.
348 pp. J J
(97) Water Resources Data for Massachusetts, Water Year 1975.
USGS/WRD/HD-76/056 (PB 262 801), U.S. Geological Survey,
V?^fr Reisources Division, Boston, Massachusetts, December
1976. 296 pp.
(98) 5£n/£nRSSC5«?;$es Data for Michigan, Water Year 1975. USGS/
WRD/HD-76/037 (PB 262 807), U.S. Geological Survey, Water
Resources Division, Okemos, Michigan, August 1976. 579 PP'
(99) Water Resources Data for Minnesota, Water Year 1975. USG"
WRD/HD-76/039 (PB 259 952), U.S. Geological ISrvey, Water
Resources Division, St. Paul, Minnesota, August 1976.
(100) Water Resources Data for Missouri, Water Year 1975
WRD/HD-76/031 (PB 256 765), U.S. Geo^caTsurvIy! Water
Resources Division, Rolla, Missouri, August 1976. 378 pP-
(101) Water Resources Data for New York, Water Year 1975 USGS/
WRD/HD-76/029 (PB 256 669), U.S. Geological Survey Water
Resources Division, Albany, New York, June 1976. 755 PP-
(continue"
90
-------
(continued)
(102) Water Resources Data for North Carolina, Water Year 1975.
USGS/WRD/HD-76/011 (PB 251 860), U.S. Geological Survey,
Water Resources Division, Raleight, North Carolina, March
1976. 441 pp.
(1Q3) Water Resources for Ohio, Water Year 1975; Volume 1,
Ohio River Basin. USGS/WRD/HD-76/041 (PB 261 782), U.S.
Geological Survey, Water Resources Division, Columbus,
Ohio, 1975. 555 pp.
(1°4) Water Resources Data for Ohio, Water Year 1975; Volume 2,
St. Lawrence River Basin. USGS/WRD/HD-76/042 (PB 261 783),
U.S. Geological Survey, Water Resources Division, Columbus,
Ohio, 1975. 249 pp.
(1°5) Water Reosurces Data for Oregon, Water Year 1975. USGS/
WRD/HD-76/017 (PB 257 153), U.S. Geological Survey, Water
Resources Division, Portland, Oregon. May 1976. 607 pp.
(1°6) Water Resources Data for Pennsylvania, Water Year 1975;
Volume 1, Delaware River Basin. USGS/WRD/HD-76/047
(PB 261 436), U.S. Geological Survey, Water Resources
Division, Harrisburg, Pennsylvania, October 1976. 399 pp.
(1°7) Water Resources Data for Pennsylvania, Water Year 1975;
Volume 2, Susquehanna and Potomac River Basins. USGS/WRD/
HD-76/048 (PB 261 437), U.S. Geological Survey, Water
Resources Division, Harrisburg, Pennsylvania, October 1976.
374 pp.
108) Water Resources Data for Pennsylvania, Water Year 1975;
Volume 3, Ohio River and St. Lawrence River Basins.
USGS/WRD/HD-76/049 (PB 261 438), U.S. Geological Survey,
Water Resources Division, Harrisburg, Pennsylvania,
October 1976. 209 pp.
°9) Water Resources Data for Tennessee, Water Year 1975. USGS/
WRD/HD-76/005 (PB 254 462), U.S. Geological Survey, Water
Resources Division, Nashville, Tennessee, March 1976.
46? PP.
U°) Water Resources Data for Utah, Water Year 1975. USGS/WRD/
HD-76/028 (PB 259 783), U.S. Geological Survey, Water
Resources Division, Salt Lake City, Utah, July 1976.
(11 529 PP'
U) Water Resources Data for Virginia, Water Year 1975. USGS/
WRD/HD-76/035 (PB 259 196), U.S. Geological Survey, Water
Resources Division, Richmond, Virginia, September 1976.
(11 363 PP-
2) Water Resources Data for Washington, Water Year 1975. USGS/
WRD/HD-76/033 (PB 259 197), U.S. Geological Survey, Water
Resources Division, Tacoma, Washington, August 1976. 700 pp.
(continued)
91
-------
Source Severity
Effluent source severities represent a comparison of the pollut-
ant concentrations occurring in a natural water system as a
result of wastewater discharges to the water quality criteria
(88) when available or to aquatic toxicity data. The effluent
source severity, Se/ is defined as follows:
V C
S = D D (6)
e (VD + VFe -
where VD = effluent discharge rate, m3/s
CD = concentration of a pollutant in the effluent g/m3
VR = minimum river flow rate, m3/s
FQ = Hazard factor - water quality criterion when
available
or otherwise =0.01 LC50 (96 hr) for the organism
with the least tolerance
(where LC5o[96-hr] is the concen-
tration of a chemical specie that
is lethal to 50% of the test
organisms in a 96-hr test period) i
g/m3
A derivation and explanation of the severity term is presented in
Appendix D. Hazard factors used in determining severities are
listed in Table 39 together with the references from which they
were derived. Effluent source severities calculated for the
average source are shown in Table 40. These source severities
aff based on effluent factors for uncontrolled discharges
although it is suspected that most discharges are treated either
on site or off site before discharge into natural waters.
Because very little data exist on treatment practices used and no
data were found on the nature of these streams after treatment,
MC^A, ,°UrCeS Data for West Virginia, Water Year 1975.
USGS/WRD/HD-76/052 (PB 262 742), U.S. Geological Survey,
Water Resources Division, Charleston, West Virginia,
November 1976. 299 pp.
(114) Water Resources Data for Wisconsin, Water Year 1975. UsG
WRD/HD-76/045 (PB 259 825), U.S. Geological Survey, Water
Resources Division, Madison, Wisconsin, October 1976.
580 pp.
(115) Water Resources Data for Wyoming, Water Year 1975. USGS/
WRD/HD-76/038 (PB 259 841), U.S. Geological Survey, Water
Resources Division, Cheyenne, Wyoming, October 1976.
664 pp.
92
-------
TABLE 39.
EFFLUENT HAZARD FACTORS FOR WATER POLLUTANTS
AND WATER QUALITY PARAMETERS
Pollutant
Acidity
Alkalinity
Ammonia
COD
Hard nee*
Nitrate
PH
Phenol
PCB
POM
Suit ate
Sulfite
IDS
TSS
TS
Elements:
Aluminum
Antimony
Araenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
Hazard
factor (r.) ,
«/»'
20
20
0.02
.a
75 to ISO
10
.a
1 x 10-»
1 x 10r«
0.02b
250
0.3
250
25
275
8.33bh
0.225b
0.050
1.0
0.011
0.75
0.010
1.6
0.05 h
0.008°
1.0
0.3
0.050.
0.518b
0.05
0.002.
0.281°
0.0013
0.1
0.010
25«
0.05
250d
250° h
0.01?
0.75b
0.55
5.0
1.15
Reference
88
88
88
88
88
88
88
88
64, 118
88
116, 117
88
88
88
116, 117
116, 117
88
88
88
88
88
116, 118
88
64, 116
88
88
88
116, 117
88
88
116, 117
88
88
88
88
88
88
88
64, 116
116, 119
116, 118
88
116, 118
Comments
A* CaCO,
AS CaCOi
As CaCOj
6.5 to 9.0 is considered acceptable
(;
g
For aluminum chloride
_c
From LCso (96-hr) Mosquito fish for
CaOH or C«0e
Q
£
_c
Value for phosphate phosphorus
Value for total suspended solids
Value for total dissolved solids
Value for organic tinc c
Value for titanium oxide
prom LC.o (96-hr) fathead minnow
value for Vao.e
From LC.o (96-hr) fathead minnow
value for ZrSO. in hard water
(U7)
(U8)
Not appropriate.
bDerived from toxicity data other than LC.o as explained in Reference 116.
cHaiard factor is derived in Reference 116 from toxicity data found in
iterances 61, 117, 118, 119.
dNo water quality criteria or toxicity data available.
1 -- • -- , _
Reznik, R. B., E. C. Eimutis, J. L. Delaney, S. R. Archer,
J- C. Ochsner, W. R. McCurley, and T. W. Hughes. Source
Assessment: Prioritization of Stationary Water Pollution
Sources. EPA-600/2-78-004q (PB 285 421), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
July 1978. 137 pp.
The Toxic Substances List— 1974.
HSM 99-73-45, National
c usances — .
Institute for Occupational Safety and Health, Rockville
Maryland, June 1974. 904 pp.
Supplement to Development Document: Hazardous Substances
Regulations. Section 311 of the Federal Water Pollution
Control Act as Amended 1972. EPA-440/9-75-009 (PB 258 514),
U-S. Environmental Protection Agency, Washington, D.C.,
November 1975. 783 pp.
Registry of Toxic Effects of Chemical Substances, 1975
Edition. Publication No. CDC 99-74-92, National Institute
for Occupational Safety and Health, Rockville, Maryland,
June 1975. 1296 pp.
93
-------
it is assumed that these sources discharge directly into natural
waters. This approach provides a worst case analysis based on
the average minimum river flow rate. The flow rates for rivers,
listed in Appendix B, vary by more than five orders of magnitude-
However, considering the low severity values for most pollutants
as listed in_Table 40, the deviation in river flow rates will
not have a significant impact on the number of severity values
exceeding the evaluation criteria.
TABLE 40. EFFLUENT SOURCE SEVERITIES FOR AN AVERAGE SOURCE
Concentration in
combined effluent
Pollutant (Cn) , g/m3
Acidity
(as CaC03)
Alkalinity
(as CaC03)
Ammonia
Hardness
(as CaC03)
Nitrate
Phenol
PCB
POM
Sulfate
Sulfite
TDS
TSS
TS
Elements:
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
4.8
3.
2.
4 x
_a
7 x
7.2
IO3
IO3
9.2
5.
1.
6.
1.
1.
4.
1.
1.
5.
7.
4.
1.
6.
2.
7.
3.
5.
4.
1.
9.
2.
2.
3.
3.
3.
1.
_a
a
8 is
3 x
1 x
4 x
6 x
7 x
8 x
1.6
7 x
3 x
2 x
1 x
8 x
6 x
2 x
4.7
2 x
0 x
6 x
_a
0 x
1.4
2 x
9 x
6 x
8 x
0 x
9.9
6 x
2 x
2.2
1 x
_a
1C2
10"
103
10"
101
10-
10-
1
1
10-3
10-
10-
103
10-
1
3
1
10-1
10-3
10-
101
10-
101
10-
103
10-
10-
10-
1
3
1
1
1
1
Pollutant discharge
rate for average
source (Vn • Cn) , a/s Severity (S0)
1
<5
2
2
4
4
5
1
5
5
5
1
2
5
2
6
1
2
9
1
<2
1
4
3
3
8
8
3
1
1
6
3
.5 x
1.
.0 x
8.
.2 x
.9 x
~
1.
.1 x
1.
.4 x
.0 x
.5 x
.6 x
.0 x
.3 x
.7 x
.2 x
1.
.6 x
.1 x
.9 x
.5 x
.2 x
.4 x
.7 x
0 x
• U Jt
.2 x
.4 x
.7 x
.1 x
.1 x
.7 x
.
.1 x
.1 X
.0 x
.9 x
.4 x
v»1
10-3
1
lo-3*5
4
10-3
10-3
c
c
80b
101
9
101
ID"3
io-3
10-"
10~3
10-a
IO-3
10-s
3
io-*
10-"
10-"
10~3
10-1
io-*b
io-3
10~3
10-3
io-s
10-3
10-"
10-3
io-3
io-3
io-3
io-*
n n
2.
2.
2.
8.
1.
2.
6.
2.
5.
2.
2.
4.
1.
1.
8.
8.
3.
4.
9.
2.
1.
1.
6.
1.
1.
1.
1.
1.
1.
6.
1.
4.
4.
5.
4.
2.
8
0
9
4
1
7
1
9
9
2
4
2
9
8
3
4
0
2
6
6
8
7
8
3
7
3
4
2
2
5
4
6
2
0
7
6
x
X
0
x
x
X
0
o
X
n
\j
x
X
x
X
x
X
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
A
10-
10-"
10-"
10"*
io-1
io-5
io-*
10-"
10-"
10"5
io-s
10~a
io-s
io-s
M M M I-" Ml
O 0 OO 0
i i i i i
« w u « «
10 —
10-"
io-3
10 —
io-5
io-2
io-3
io-5
io-5
io-5
io-7
10-"
io-5
ischarge rate is based on the detection limit for this compound.
aretheicr depfndin9 on the compound of interest, but
are in the microgram per liter range.
94
-------
WASTEWATER TREATMENT
Because wastewater handling practices for industrial boilers are
not well defined in the literature, it is assumed that wastewater
treatment practices for boilers with design capacities exceeding
530 Gj/hr parallel those for utility sources (1). Sources of the
capacity specified account for approximately 7% of the dry
om, pulverized, coal-fired boilers in the industrial category
. it is estimated that these boilers generate about
12 x 10« m3 of wastewater annually from ash transport (sluicing)
operations (1) .
Neutralization is the principal method of wastewater treatment
^ed for these larger boiler sources; it is followed by con-
polled release to a waterway to achieve a dilution of 5,000:1
to 10,000:1 (19). Depending on the space available and the
nature of other wastewater streams generated at the site, a
n°lding pond may be used to permit sedimentation; if climatic
conditions are favorable, an evaporation pond may be utilized
*•{• ^natively. Other options include off -site treatment and
aisposal by a commercial waste-disposal firm, ocean dumping, and
solidification of wastes by an outside vendor for land disposal.
however, these methods are costly and not often employed.
J°Uers with a design capacity below 530 GJ/hr are assumed to
JJandle their ash dry (1) and thus have a much lower, total waste
™ater volume. in addition, if the steam from these units is
ped Primarily for process or space heating, no condenser or
Doling water is required because the steam condenses in the
stern and the hot water may be returned directly to the boiler.
efore, the primary wastewater streams are the relatively low
e effluents from feedwater treatment, boiler blowdown,
in9 water for fan bearings, steam condensate from the pneu-
c ash transport system, and miscellaneous equipment cleaning
most plants these wastes are either discharged to a municipal
er system or sent to the plant wastewater treatment facility
h"fre they are mixed with process waste streams. In plants
|gvlng their Qwn treatment systemsf the unit operations are
^er by the nature of the process wastes.
95
-------
SECTION 6
SOLID WASTES AND CONTROL TECHNOLOGY
SOURCES AND COMPOSITION
Coal ash generated in the furnace by combustion constitutes the
major source of solid wastes from industrial boilers. GCA
Corporation has estimated that 2.1 x 106 metric tons of ash are
collected annually from this source (1). other potential solid
waste sources are the sludges created by the softening of boiler
feed water using lime and soda ash, and by the operation of some
SOX scrubbers.
Coal Ash
Bituminous coal contains 4% to 15% inorganic ash. On combustion.
the ash content is distributed between bottom ash and fly ash.
Bottom ash consists of the heavier particles which fall to the
bottom of the furnace. Such ash either accumulates on the floor
ot the furnace for periodic removal or is collected in a hopper
titted to the furnace bottom. The remaining ash is entrained
lnu JCOmbuStlon gas stream. The distribution between bottom
ash and fly ash is a function of boiler type. Table 41 (1)
presents the average distribution of bottom ash to fly ash for
the defined source type and for other boiler types for comparison-
TABLE 41. DISTRIBUTION OF COAL ASH BY BOILER TYPE (1)
Percent distribution of
————^— -f *- »-»«-»
Pulverized dry bottom
Pulverized wet bottom
Cyclone
Stoker
>- »_v-/iii qoii L.U i. ±y aaii
15:85
35:65
90:10
65:35
dry.bott°m boilers produce primarily fly ash, it is
^rrfQmK°r f!Ct?r influen<=ing the quantity of ash to be
5SSs daia it ?f en^'° PartiGUlate Control. From an analysis
NEDS data it is estimated that 62% of the boilers in the categ°«
being studied are equipped with controls which have collection
efficiencies ranging from 25% to 99+% (?) coixe
96
-------
physical properties of coal ash from pulverized coal-
fj-red plants are presented in Table 42 (120). Differences in the
Physical properties of bottom ash and fly ash are minor; these
"from slight differences in trace metal content due to
partioning and from a higher carbon content in the
ash.
TABLE 42. TYPICAL PHYSICAL PROPERTIES OF FLY ASH
FROM PULVERIZED COAL FIRED PLANTS (120)
Constituent Range
pH 6.5 to 4.5
Particle size range, ym O-5 to 10°
Average percent of particles
passing 325-mesh sieve,
(44 ym), % 60 to 90
Bulk density (compacted), kg/m3 1,100 to If3°j>
Specific gravity 2.1 to 2.6
Specific area per gram, cm2/g 3,300 to 6,400
he specific chemical composition of a coal ash is dictated by
ie geology of the coal deposit and the boiler operating param-
ers- Coal ash is primarily an iron-aluminum silicate with
tions of lime, magnesia, sulfate, sodium and potassium oxides,
'?n' and traces of heavy metals. A detailed listing of the
Sit,'1031 constituents of coal ash, showing the average compo-
Beri and the composition range is provided in Table 43 (121).
cause of high temperature at which most coal ash is formed, a
ash Y phage is produced which can account for up to 90% of the
in istructure other crystal phases often encountered in ash
Ci e mullite, quartz, hematite, and magnetite. The distri-
10n of these mineral phases is shown in Table 43 (121).
Jiime - c
^""~ goga Ash Softening Sludge
Wat-
ash r destined for boiler use is treated using the lime - soda
HOWfSfoftening process which produces a solid sludge waste.
theT*' the extent to which this softening process is used for
e treatment of boiler feedwaters for the source type being
12°> Ash Utilization. Bureau of Mines information Circular
IC8488, U.S. Department of the Interior, Washington, D.C.,
(l 1970. 351 pp.
*•> Hecht, N. L., and D. S. Duvall. Ch"3?^""^" 2JJL.
Utilization of Municipal and Utility Sludges and Ashes,
Volume III - utility Coal Ash. EPA-670/2-75-033c
(PB 244-312), U.S. Environmental Protection Agency,
Cincinnati, Ohio, May 1975. 74 pp.
97
-------
TABLE 43. CHEMICAL CONSTITUENTS OF COAL ASH (121)
Constituents
Silica
Alumina
Ferric Oxide
Calcium Oxide
Magnesium Oxide
Titanium Dioxide
Potassium Oxidea
Sodium Oxide9
Sulfur Trioxide
Carbon
Boron
Phosphorus
Manganese
Molybdenum
Zinc
Copper
Mercury
Uranium and
thorium
Composition
Range, % Averaae. %
20 to 60
10 to 35
5 to 35
1 to 20
0.25 to 4
0.5 to 2.5
1.0 to 4.0
0.4 to 1.5
0.1 to 12
0.1 to 20
0.01 to 0.6
0.01 to 0.3
0.01 to 0.3
0.01 to 0.1
0.01 to 0.2
0.01 to 0.1
0.0 to 0.02
0.0 to 0.1
48
26
15
5
2
1
2
1
2
4.
_b
Alkalies.
Blanks indicate average not reported.
TABLE 44. MINERAL PHASES FOUND
IN COAL ASH (121)
Phase Percent
Quartz 0 to 4
Mullite o to 16
Magnetite 0 to 30
Hematite 1 to 8
Glass 50 to 90
98
-------
studied is unknown. The softening process reduces hardness^y
Precipitating calcium and /a^-- carbonate /calcium'bicarbon-
containing calcium su^t 'd maanesium carbonate as principal
ate, magnesium hydroxide, and*af^ adsorbed onto the solids or
constituents. ^^^/^nncludeLy material present in the
entrained in them and may Jn^u^ea"enerated by the softening
raw water. The quantity of sl^rg^qe and the hardness of
depends on the rate of boiler-water usage ana
the influent water.
glue Gas Desulfur.i y.ation Sludge
Boilers equipped with nonregenerable flue gas
(FGD) processes for controlling SOx ^^aSO*) sludge.
waste stream consisting of a W3™:^6^}?* gently to indus-
Because FGD processes have been a?P^d °nl^trol is limited and
trial boilers, their Current usage for SOx control^^^ ^
includes only about 30 systems rePrese_nting, source type as
1.5% of the total U.S. firing ^^^f^Ln standards become more
Defined (1, 122). However, as SOx J^s^°n *nt control method.
stringent, 'this process ^ ^°m|G^ rocesses could potentially
v^lumf ^rated by industrial boilers.
Waste products from FGD systems
the particular process used but fm ly 4 kg to 6 kg
calcium sulfite, and coal *?\™
g
, &» removed. Additional
sludge are produced for each kilogram °* *d b various proces-
informationPon the nature of ^ewa^esented in Section 4.
Ses is contained in Table 32 which was pi.
DISPQSAL OF WASTE SOLIDS
and Dispo^l practices
^ large utilities, the disPosai/fa^f desigofheowe •
Considerable attention during *£e eariy ^ a primary
giant, m fact, the need for waste aisp c gite wnere im-
f actor in locating a power plant " a P ^ Qther nand/
Poundment of ash and sludge is P?"J°A®;ar population centers
Austria! plants are generally ^J1^ expensive to justify its
^ere land is either ^ava^abl?h^efo?e? most solid industrial
,Use as a waste disposal site. ™??? sitis.
Bastes are hauled to remote landfill sites.
icaton of Flue Gas
*, F-eraf f er ^inistration, Washington,
D.C., December 22, 1976. 100 pp.
99
-------
Coal ash collected in an electrostatic precipitator, baghouse,
bottom hopper, or other unit is moved to on-site facilities for
temporary storage using water sluicing, gravity flow, or pneu-
matic transport. From the storage facilities, which usually
consist of an ash holding pond or hopper, the ash is loaded onto
trucks using dredging, pumping, or gravity flow and removed for
disposal or resource recovery.
Coal ash is usually discarded in landfills. Depending on the
type of ash collection devices and the on-site ash handling and
storage facilities, the ash may be delivered to the disposal area
either wet or dry. Generally, the ash is not treated per se
prior to disposal. However, ash stored in a holding pond receives
some treatment in that a portion of the soluble materials is
removed thus lessening the potential leaching effects.
Sludges resulting from water softening processes can be discarded
by direct discharge to rivers or sewer systems; however, these
disposal methods are regulated and limited by NPDES permits and
agreements with the local wastewater treatment authorities,
respectively. A more acceptable disposal practice consists of
either sending the sludge to a pond as it comes from the process
containing about 5% solids, or sending it to a landfill site
after filtering, drying or other thickening operations have
been performed.
The use of ponds and landfills presently represent the major ,
options for FGD sludge disposal. Both methods are being utilized
with and without sludge fixation. Lined and unlined ponds are
being used (123). In anticipation of the large FGD sludge
volumes expected in the future, the government is currently
evaluating the possibility of using mine and ocean disposal for
these materials (124).
(123) Jones, J. w. Environmentally Acceptable Disposal of Flue
Gas Desulfurization Sludges; The EPA Research and Develop"
n«« t1^ro?ram! In: Proceedings: Symposium on Flue Gas
Slo/? 741^1£n7;Atlanta' Nove^er 1974, Volume II. EPA'
A™™ i b ^PB 242 573)' U's- Environmental Protection
1974? 511Se Tr"ngle Park, North Carolina, December
(124) Lunt, R R C. B Cooper, S. L. Johnson, J. E. Oberho
D±™J? i^Si' W> *' Watson- An Evaluation of the
Ocean TnfJ^\GaS Desulfurization Waste in Mines and t
Ocean Initial Assessment. EPA-600/7-77-051 (PB 269 270)
Pa?k SorthT^?1 Protection Agency, Research Triangle
Park, North Carolina, May 1977. 318 pp.
'
100
-------
M°st sludges generated in SOX scrubbers contain calcium sulfite
hemihydrate (CaSO3-l/2 H2O) , which is reponsible for the moisture
Staining character and thixotropic behavior of the sludge. Be-
cause sludges are difficult to dewater and have little or no
compressive strength, they are unsuitable for landfill unless
chemically treated (via fixation). Three companies currently
^arket sludge fixation technologies (125). These processes
involve treatment of sludges with various chemicals to produce
a material with sufficient compressive strength for landfill use
ar*d to chemically and/or physically bind up the soluble constitu-
ettts of the sludges. Table 45 indicates the differences in
elemental concentrations observed for raw sludge and for leachate
from fixed sludge (126).
TABLE 45. TRACE ELEMENTS PRESENT IN RAW SOX SCRUBBER SLUDGE
AND IN LEACHATE FROM SLUDGE AFTER FIXATION (126)
Constituents
Arsenic
Cadmium
Chlorides
Chromium (total)
Copper
Iron
Lead
Mercury
Nickel
Zinc
Phenol
Cyanide
Sulfate
Leachate from
Raw sludge, conditioned sludge,
ppm PPm
2.2
0.30
2,000
2.8
1.5
120
26
<0.10
3.5
16
<0.25
<0.10
<10,000
<0.10
<0.10
64.0
<0.25
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
400
Rossoff, J., R. C. Rossi, L. J. Bornstein, and J. W. Jones.
Disposal of By-Products from Non-Regenerable Flue Gas
Desulfurization Systems - A Status Report. In: Proceed
ings: Symposium on Flue Gas Desulf^riZation--Atlant a,
November 1974, Volume I. EPA-650/2-74-126-a (PB 242 572) ,
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, December 1974. 661 pp.
Rossoff, j., and R. C. Rossi. Disposal of By-Products from
Non-Regenerable Flue Gas Desulfurization Sy^f;.^1*1
Report! EPA-650/2-74-037-a (PB 237 114), U.S. Environ
Cental Protection Agency, Research Triangle Park, North
Carolina, May 1974. 318 pp.
101
-------
Resource Recovery
Stimulated by the large quantities of coal ash generated annually*
research efforts in resource recovery have led to the development
of numerous potential applications. At the present time, how-
ever, the supply greatly exceeds the demand although there is a
trend toward increased utilization (121).
Appreciable quantities of coal ash are used currently as fill
material for roads and other construction projects and as a
partial replacement for cement in concrete and concrete products-
Ash usage in concrete is expected to increase significantly
because it offers technical advantages such as improved mechani-
cal strength and improved resistance to sulfate leaching.
Applications currently considered to have the potential for
utilizing large quantities of ash include various agricultural
uses, land recovery, road base stabilization, structural fill.
and cement and concrete products.
After dewatering and treatment, sludge from the lime - soda ash
^olSening process can be reused as a water-softening reagent or
TrSf f^n^f1CUltural.lime suitable for direct application.
Treatment for reuse involves calcining in a furnace, removal of
me?Sod1UT2lf ° ^ Centrifu^9' ^ a combination of the two
SlUd?6 a??lications have been identified for po- ,
wool r rC"i utlllzation; these include its use in mineral
Darklno tn£8' Jln^ed concrete products, road base materials,
aate LJ Lr£eS ' artificial aggregate, lightweight aggre-
directfv al - ated concr;te. In addition, FGD sludge may be used
recoverv or if ^endment and/or for sulfur and mineral
Potential SroJL^n converted into gypsum. Although many .
to those currfn^ are Anticipated , some of which may be superior
hibit JLSe a«?iy ^ ' several factors exist which could in-
chemical Ind nh • ? gS USage including its highly variable
colts Mue toPr^iCai pr°Perties< substantial transportation
«ter?als, , and
sludgfis converted IZV*** re°eive wi^spread use, most scrubber
1
the volume 0! for Sae landfi^ ^dium,
102
-------
POTENTIAL ENVIRONMENTAL EFFECTS
^r this study, the hazard potential of the ^Jd™^* *ener~
*ted by industrial boilers is assessed by Considering that
Potion of the waste which eventually reaches the open environ
*«nt as water pollution or air pollution. Water P^1^™ J£°m
solid wastes is the result of leaching of pollutants at Dispo
^tes by runoff to groundwater or surface waters A^J^fS1
r?sult from handling operations, transportation to disposal
Sltes, and wind erosion at disposal sites.
f A/Technology Division has estimated that air fissions result-
l? from dry ash handling and disposal are 0.5 k9/met ton of
h landfill (1) . This estimate was based on wind
data
.
showed that the erosion of soils .
than 50 ym is minimal due to the attractive
des and consideration of landfill erosion
. Using the GCA estimate, the hazard Pot!n^ *"0"a
air emissions from this point source was detemined tobe
r in comparison to stack fly-ash emissions. _B;"d °"J*al
estimates of fly ash and bottom ash collected for disposal
of stack emissions of noncollected fly ash, and Assuming
100% of the industrial ash is used as ^fill xn dry *£"'
emissions of ash from handling and disposal total less th an
of the stack ash emissions. In addition, most fugitive ash
ions occur at landfills which are, in ^eral , located more
ely than industrial sites and at ground level over a l«ge
area; hence, the ash has a higher probability of redeposit
on the landfill site.
tamination of ground water and surface water by P™d seepage
rUnoff containing landfill leachates presents a Potential
**d. Leaching studies and ash pond liquor ™lysiB (126, 127)
icate that coll ash and flue gas desulfurization sludges both
tain sufficient quantities of soluble toxic Aerials to pose
threat to the Quality of ground water and nearby surface waters
i results of an asn leachate measurement for a bottom ash and
Mash composite from the source sampled are presented in
Dle 46.
of the environmental impact of
e o e env o
Pollution from leachates depends on a number of ^tors
include the chemical and physical nature of the ash and/or
Holland, w., K. Wilde, J. Parr, P. Lowell, and R.
Environmental Effects of Trace Elements from Ponded Ash
and Scrubber Sludge. EPRI 202 (PB 252 090) Electric Power
Research Institute, Palo Alto, California, September 1975.
403 pp.
103
-------
TABLE 46. RESULTS OP THE ASH LEACHATE MEASUREMENT
Ash composition,
a 9/k9
Element of ash
Aluminum
Barium
Boron
Calcium
Magnesium
Molybdenum
Sodium
Silicon
Strontium
Vanadium
a
170
3.6
1.0
49
13
0.34
11 h
2.5b
6.2
2.7
Amount of
element leached
mg/kg of ash
45
2.2
24
800
27
5.3
210
9.5
24
4.2
, Percent
leached
0.026
0.059
2.3
1.8
0.22
1.6
1.8
0.38
0.39
0.16
Elements monitored but not found in leachate include
antimony, cadmium, chromium, cobalt, copper, iron, lead,
manganese, nickel, phosphorus, silver, tin, titanium and
zinc.
Value probably low due to an inability to completely
digest silicon for analysis.
sludge, local weather conditions, distance from the disposal site
to natural waters, design of the landfill or sludge pond, and the
geology of the disposal site and surrounding areas. Most of
these factors are site specific and probably unique for a given
location Therefore, no attempt will be made to quantify the
potential effects for the average plant. A brief discussion of
sentedbelow ° ^searchers working in this area is pre-
characteristics most likely to create a potential hazard
en rand (due t0 sulfite ^n), total dissolved
' and concentrations of toxic elements (123, 126-129)'
^ Y aff*cting the Deceiving water, the PH value i*
factor in determining the species and concentrations
solids
wpT' L' The Potential Trace Metal Contamination of
P?orLrfeSOUr°;S ?hrou9h the Disposal of Fly Ash. In:
Proceedings of the Second National Conference on Complete
rMrL£eU?^— 6rS Interfa<=e with Energy, Air and Solif '
S££?£i' £lllnois' Ma* 4-8 • 1975. American Institute of
Chemical Engineers, New York, New York, 1975. pp. 219-224-
Ponn??A/' £• Analvzin9 the Effect of Fly Ash on Water
Pollution. Power, August 1971. pp. 76-77;
104
-------
°f toxic elements in the leachate (130). Elements most likely to
create a hazard because of their high toxicities and appreciable
leaching rates are arsenic, barium, boron, chloride, chromium,
lead, mercury, and selenium (124, 126, 127). On the whole,
elemental concentrations actually observed in leachates are low,
usually near the analytical detection limits, and the ion-
exchange capacities of most soils are adequate for controlling
m°st toxic elements for an extended period (>10 years for 10 m
of soil) (127). In addition, these wastes tend to be self
Sealing due to* the plugging of soil voids by the small particles
which are characteristic of ash and sludge.
CONTROL OF EMISSIONS AND EFFLUENTS AT DISPOSAL SITES
Js stated above, air and water pollution may result from the
handling and disposal of waste solids. The optimum solution for
c°ntrolling environmental contamination from solids disposal is
*° eliminate contaminants through recovery for reuse as previous-
ly discussed. Emission and effluent abatement methods for the
Dandling and disposal of solids are briefly presented below.
£u9itive emissions from the loading of coal ash onto trucks can
£e minimized by wetting the coal ash and/or enclosing the trans-
ter point to eliminate losses by wind entrainment and immediately
Cleaning up any spills that occur. Losses of waste materials
ng transport to a disposal site can be reduced by covering
ash or sludge after it is put on the truck, this practice is
d in some areas. At disposal sites, emissions from wind
can be eliminated by adequately covering the disposed
with earth as soon as possible.
Several methods exist for preventing pollution by leachates and
cunoff at pond and landfill sites. These methods include the use
liner materials, the construction of a perimeter ditch to
nect leachate or runoff for treatment, and chemical fixation
stabilization of solid wastes prior to disposal.
Dreesen, D. R., E. S. Gladney, J. W. Owens, B. L. Perkins,
c- L. Wienke, and L. E. Wangen. Comparison of Levels of
Trace Elements Extracted from Fly Ash and Levels Found in
Effluent Waters from a Coal-Fired Power Plant. Environ-
mental Science and Technology, 11(10):1017-1019, 1977.
105
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SECTION 7
FUTURE GROWTH AND TECHNOLOGY
Since the technological developments of the 1920's which made the
use of pulverized coal practical, boilers firing pulverized coal
have become the largest source of coal-derived, industrial energy'
During this same period, the percentage of industrial energy
supplied by coal has decreased dramatically because of the wide-
spread availability of inexpensive gas and oil. However, a
renewed interest in the use of coal has resulted from the oil
producing and exporting countries' (OPEC's) oil embargo of late
1973 which sharply increased oil prices, the recent natural gas
shortages, and the inception of government policies directed
towards making the United States self-sufficient in energy.
Known coal reserves in this country are capable of meeting our
energy needs for the next 300 years at the current level of
consumption, and coal prices are expected to remain relatively
stable over the next several decades (131).
The extent of conversion to coal in the industrial sector during
the 1980's can not be predicted. Major physical and economic
constraints which limit rapid increases in coal usage include
the following:
• A low equipment inventory of boilers capable of burning
coal, coal and ash handling equipment, and pollution
control equipment
• The time required to design and build a new boiler
1^5 years), although package boilers are available for
smaller sizes
• The capital cost of converting units to burn coal
• The capital cost of installing pollution control equipment
• Fuel penalties for operating pollution control equipment
• The higher unit cost for handling coal in small quantities
L' ,Techn°logical Feasibility of Alternative
CeS ^A° A°°5 549)- u-s' Army War College,
Barracks, Pennsylvania, October 1974. 31 PP-
106
-------
• Potential irregularities in coal supply owing to strikes by
f^OA 1 m *i »-» f±*-£•
coal miners
Even under the limitations listed above, industrial coal usage is
to increase at a rate of 3% to 4% per year. These
^creases are not expected to change the relative mix of coal-
t;Lred units (e.g., the ratio of pulverizers to stokers, and other
e<3uipment combinations) (1) . Total air emissions and wastewater
^fluents during this period are expected to remain constant or
e slightly due to increased controls; the volume of solid
is expected to increase for the same reason.
federal government could accelerate industry's conversion to
by relaxing emission limitations and encouraging states to
the same. However, that approach is contrary to current long-
. ,
**nge objectives. In addition, it is doubtful that the government
°uld justify any increased rate of environmental degradation,
specially considering that the preponderence of such boilers are
£°cated in or around urban areas which are already suffering from
° air quality. Other forms of government induced incentives,
as deregulation of natural gas and oil prices, reductions in
freight rates for coal, and tax breaks for conversion to
' may appreciably stimulate the growth rate of this source
should they be enacted.
tjj i-s not possible to predict the growth of this source type for
8JJ Period beyond 1990 because of our rapidly changing energy
fur^ation and the current rate of energy research and development
Deling. If commercial size plants designed to convert coal into
th« and liquid fuels are proven to be economical before 1985,
ifie coal-fired boiler population could begin to decline; however,
theC°al cleaning plants are shown to be economically preferred,
SomJL°pulation may continue to increase at least for a while.
othe 6 after 1990, the contribution from solar, geothermal and
is ®r alternative energy sources will begin to be felt, and it
inch edicted that these sources may supply a major share of the
UVJstrial energy consumed after 2050 (132).
, R. F., J. S. Miller, and D. L. Meadows. The Transi-
to Coal. NSF-RA-N-74-289 (PB 256 445), National
Science Foundation, Washington, D.C., November 1974. 51 pp
107
-------
SECTION 8
UNUSUAL RESULTS
The preparation of this report involved the evaluation of a con-
siderable amount of literature and sampling data. During this
process, several unusual or unexpected items were observed
H*?* i?g- 2 !126 range °f the boilers studied and the field
data obtained for sulfur oxides and elemental emissions.
BOILER SIZE DISTRIBUTION
A previous study defined the lower capacity limit for pulverized,
va?ue ifh' SY b°tt0m industrial boilers as 210 GJ/hr (1) . ™iS
value is based on economic considerations (i.e., the cost of
SnedlTn Yersus.thf additional efficiency and throughput ob-
this friV i?lng) * Values near or eve" substantially above
o re?uen"y used in the literature for describing the
s of pulverized coal-fired units in aeneral (1 29, 133)'
' '
cawcitv
The
^ tO S-NEDS ^^ing ofboispecific to this
' a?Proximately 62% by number and 29% by total
^ T* llSted had caPacities below this value-
4?^.™?^ ^wnward to 1 GJ/hr. Figure 7
distri S-
. .
the distribution of boiler capacities found in NEDS
POST-ESP SULFUR OXIDE EMISSIONS
measurements showed a reduction in the
sPth e
flow directlv from +->, * ' that 1S' the combustion gases
directly from the furnace to the precipitator and then to
(133) Exhaust Gases from r-^^u
APTD-0805 (PB 204 O" and Ind""rial Processes.
Center, <°
108
-------
70
65
60
55
50
S 45
S 40
LL.
o
S 35
CO
1>
25
20
15
10
5
1-50 51-100 101-150 151-200 201-250 251-300 301-350 351-400 401-450 451-500 501-550 551-600 601-650 651-KB 701-750 751-800 801-850 851-WO «OI-«0
DESIGN CAPACITY,GJ/h
Figure 7. Distribution of boilers in this
source type by design capacity (5).
heat recovery equipment. (Precipitators are used in this config-
uration for boilers firing low-sulfur coal as is the case for
many western, coal-fired units.)
Two potential conversion mechanisms are postulated based on the
input of energy from the ESP to the combustion gases via the
corona discharges (electrical arcing across the electrodes). As
one postulated conversion mechanism, consider that arcing in a
precipitator may cause localized "hot spots" in which the conver-
sion of S02 to S03 and/or SO^ would occur quite rapidly because
temperature is a dominant rate controlling factor. Because the
gases are already hot in comparison to those encountered in an
ESP in a conventional configuration, it is plausible that this
additional heat input could cause the observed results. As a
second postulated conversion mechanism, note that corona dis-
charges have been also shown to produce ozone (03) which could
readily react with S02 to yield SO3 and 02. This second mechan-
ism was presented earlier to explain the apparent conversion of
109
-------
N2 to NO in an ESP (134). The variability of SO2 emissions
observed after the ESP can be explained by both of the above
mechanisms because the degree of arcing is a function of the
ash buildup on the electrodes.
SASS TRAIN TRACE METAL RESULTS
Analysis of the various SASS train components for elemental
emissions showed that certain relatively nonvolatile elements
were collecting beyond the particulate filter in the back half
of the impinger series. Through a literature search, it was
determined that some of these elements may partially exist in
gaseous forms (32, 135); however, it was also determined that
these elements were all components of the materials used in the
construction of the train (i.e., iron, chromium, molybdenum and
nickel from 316 stainless steel, and boron and silicon from the
glass used for the impingers). From this information and the
failure of a stainless steel tube leading to the first impinger
during recent sampling of a gas stream containing chlorine (36),
it was concluded that an unknown portion of the measured masses
of these elements was due to contamination from corrosion of the
train components.
(134) Cuffe, S. T. , R. W., Gerstle, A. A. Orning and
C. H. Schwartz. Air Pollutant Emissions from Coal-Fired
Power Plants; Report No. 1. Journal of Air Pollution
Control Association, 14 (9):353-362, 1964.
(135) Ulrich, G. D. An Investigation of the Mechanism of Fly-Ash
Formation in Coal-Fired Utility Boilers—Interim Report for
the Period February - May 1976. FE-2205-1, U.S. Energy
Research and Development Administration, Washington, D.C.,
May 28, 1976. 9 pp.
(136) Personal communication with D. L. Harris, Monsanto Research
Corporation, Dayton, Ohio, November 1977.
110
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REFERENCES
1. Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and
C. Young. Preliminary Environmental Assessment of Conven-
tional Stationary Combustion Systems; Volume II, Final Re-
port. EPA-600/2-76-046b (PB 252 175)3, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
March 1976. 557 pp.
2. Standard Specification for Classification of Coals by Rank,
Designation D 388-66 {Reapproved 1972). In: 1976 Annual
Book of ASTM Standards, Part 26: Gaseous Fuels; Coal and
Coke; Atmospheric Analysis. American Society for Testing
and Materials, Philadelphia, Pennsylvania, 1976.
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3. The Story of Electricity, Your Trip Through Frank M. Tait
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20- Betz Handbook of Industrial Water Conditioning. Betz Labora-
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82. Dykema, 0. W. Analysis of Test Data for NOX Control in
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85« Assessment of the Costs and Capabilities of Water Pollution
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89- Water Resources Data for Alabama, Water Year 1975. USGS/WRD/
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391 pp.
9°- Water Resources Data for Georgia, Water Year 1975. USGS/WRD/
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91• Water Resources Data for Idaho, Water Year 1975. USGS/WRD/
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119
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92. Water Resources Data for Illinois, Water Year 1975. USGS/
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93. Water Resources Data for Indiana, Water Year 1975. USGS/
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94. Water Resources Data for Iowa, Water Year 1975. USGS/WRD/
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95. Water Resources Data for Kansas, Water Year 1975. USGS/WRD/
HD-76/008 (PB 251 857), U.S. Geological Survey, Water
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96. Water Resources Data for Kentucky, Water Year 1975. USGS/
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348 pp.
97. Water Resources Data for Massachusetts, Water Year 1975.
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98. Water Resources Data for Michigan, Water Year 1975. USGS/
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Water Resources Data for Minnesota, Water Year 1975. USGS/
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523 pp.
100. Water Resources Data for Missouri, Water Year 1975. USGS/
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101. Water Resources Data for New York Water Year 1975. USGS/
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102. Water Resources Data for North Carolina, Water Year 1975.
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99,
120
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103. Water Resources Data for Ohio, Water Year 1975; Volume 1,
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104. water Resources Data for Ohio, Water Year 1975; Volume 2,
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U.S. Geological Survey, Water Resources Division, Columbus,
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105. water Resources Data for Oregon, Water Year 1975. USGS/
WRD/HD-76/017 (PB 257 153), U.S. Geological Survey, Water
Resources Division, Portland, Oregon, May 1976. 607 pp.
106. Water Resources Data for Pennsylvania, Water Year 1975;
Volume 1, Delaware River Basin. USGS/WRD/HD-76/047
(PB 261 436), U.S. Geological Survey, Water Resources
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107 • Water Resources Data for Pennsylvania, Hater Year 1975;
Volume 2, Susquehanna and Potomac River Basins. USGS/WRD/
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374 pp.
108. water Resources Data for Pennsylvania, Water Year 1975;
Volume 3, Ohio River and St. Lawrence River Basins.
USGS/WRD/HD-76/049 (PB 261 438), U.S. Geological Survey,
Water Resources Division, Harrisburg, Pennsylvania, October
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1Q9. Water Resources Data for Tennessee, Water Year 1975. USGS/
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467 pp.
110 - Water Resources Data for Utah, Water Year 1975.
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529 pp.
111 • Water Resources Data for Virginia, Water Year 1975. USGS/
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Resources Division, Richmond, Virginia, September 19 /t.
363 pp.
ll2' Water Resources Data for Washington, Water Year 1975. USGS/
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700 pp.
121
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113. Water Resources Data for West Virginia, Water Year 1975.
USGS/WRD/HD-76/052 (PB 262 742), U.S. Geological Survey,
Water Resources Division, Charleston, West Virginia,
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114. Water Resources Data for Wisconsin, Water Year 1975. USGS/
WRD/HD-76/045 (PB 259 825), U.S. Geological Survey, Water
Resources Division, Madison, Wisconsin, October 1976.
580 pp.
115. Water Resources Data for Wyoming, Water Year 1975. USGS/
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664 pp.
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117. The Toxic Substances List — 1974. HSM 99-73-45, National
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119. Registry of Toxic Effects of Chemical Substances, 1975
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J-23. Jones, J. W. Environmentally Acceptable Disposal of Flue
Gas Desulfurization Sludges; The EPA Research and Develop-
ment Program. In: Proceedings: Symposium on Flue Gas
Desulfurization—Atlanta, November 1974, Volume II. EPA-
650/2-74-126-b (PB 242 573), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, December
1974. 511 pp.
24- Lunt, R. R., C. B. Cooper, S. L. Johnson, J. E. Oberholtzer,
G. R. Schimke, and W. I. Watson. An Evaluation of the
Disposal of Flue Gas Desulfurization Wastes in Mines and
the Ocean: Initial Assessment. EPA-600/7-77-051 (PB 269
270), U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, May 1977. 318 pp.
12^
°- Rossoff, J., R. c. Rossi, L. J. Bornstein, and J. W. Jones.
Disposal of By-Products from Non-Regenerable Flue Gas
Desulfurization Systems - A Status Report. In: Proceed-
ings: Symposium on Flue Gas Desulfurization—Atlanta,
November 1974, Volume I. EPA-650/2-74-126-a {PB 242 572),
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, December 1974. 661 pp.
l2fi
Rossoff, j., and R. C. Rossi. Disposal of By-Products from
Non-Regenerable Flue Gas Desulurization Systems: Initial
Report. EPA-650/2-74-037-a (PB 237 114), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
May 1974. 318 pp.
127
*'• Holland, W., K. Wilde, J. Parr, P. Lowell, and R. Pohler.
Environmental Effects of Trace Elements from Ponded Ash
and Scrubber Sludge. EPRI 202 (PB 252 090), Electric Power
Research Institute, Palo Alto, California, September 1975.
403 pp.
\2o
Theis, T. L. The Potential Trace Metal Contamination of
Water Resources Through the Disposal of Fly Ash. In:
Proceedings of the Second National Conference on Complete
Water Reuse; Waters Interface with Energy, Air and Solids;
Chicago, Illinois, May 4-8, 1975. American Institute of
Chemical Engineers, New York, New York, 1975. pp. 219-224.
l29
Rohrman, F. A. Analyzing the Effect of Fly Ash on Water
Pollution. Power, August 1971. pp. 76-77.
l3n
• Dreesen, D. R., E. S. Gladney, J. W. Owens, B. L. Perkins,
C. L. Wienke, and L. E. Wangen. Comparison of Levels of
Trace Elements Extracted from Fly Ash and Levels Found in
Effluent Waters from a Coal-Fired Power Plant. Environ-
mental Science and Technology, 11 (10):1017-1019, 1977.
123
-------
131. Zweigle, M. L. Technological Feasibility of Alternative
Energy Sources (AD A005 549). U.S. Army War College,
Carlisle Barracks, Pennsylvania, October 1974. 31 pp.
132. Naill, R. F., J. S. Miller, and D. L. Meadows. The Transi-
tion to Coal. NSF-RA-N-74-289 (PB 256 445), National
Science Foundation, Washington, D.C., November 1974. 51 PP'
133. Exhaust Gases from Combustion and Industrial Processes.
APTD-0805 (PB 204 861) , Office of Air Programs Technical
Center, Durham, North Carolina, October 2, 1971. 436 PP-
134. Cuffe, S. T., R. W. Gerstle, A. A. Orning, and C. H.
Schwartz. Air Pollutant Emissions from Coal Fired Power
Plants; Report No. 1. Journal of the Air Pollution Control
Association, 14 (9) : 353-362, 1964.
142.
135. Ulrich, G. D. An Investigation of the Mechanism of
Formation in Coal-Fired Utility Boilers— Interim Report for
the Period February - May 1976. FE-2205-1, U.S. Energy
Research and Development Administration, Washington, D.C./
May 28, 1976. 9 pp.
136. Personal communication with D. L. Harris, Monsanto Research
Corporation, Dayton, Ohio, November 1977.
137. 1970 Census and Areas of Counties and States. In: The
World Almanac & Book of Facts, 1976. Newspaper Enterprise
Association, Inc., New York, New York, 1975. pp. 239-257-
138. Method 5 - Determination of Particulate Emissions from Sta-
tionary Sources. Federal Register, 41 (111) : 23076-23083,
1976.
139. Hamersma, j. w. , S. L. Reynolds, and R. F. Maddalone.
™* ?™C,^dure Manual: Level r Environmental Assessment.
EPA-600/2-76-160-a (PB 257 850), U.S. Environmental
tion Agency, Research Triangle Park, North Carolina,
June 1976. 131 pp.
140. Lentzen, D. E., D. E. Wagoner, E. D. Estes, and W. F.
Gutknecht. IERL-RTP Procedures Manual: Level 1 Environ
mental Assessment (Second Edition). EPA-600/7-78-201, u'
M^K0^611^1 Protection Agency, Research Triangle Park,
North Carolina, October 1978. 279 pp.
141 ' ^^ l~ Determination of Stack Gas Velocity and
Method 4 - Determination of Moisture in Stack Gases. Fed-
eral Register, 41 (111) : 23072-23076 , 1976.
124
-------
!43. Method 8 - Determination of Sulfuric Acid Mist and Sulfur
Dioxide Emissions from Stationary Sources. Federal Regis-
ter/ 41 (111):23087-23090, 1976.
144. Method 3 - Gas Analysis for Carbon Dioxide, Oxygen, Excess
Air, and Dry Molecular Weight. Federal Register, 41(111):
23069-23070, 1976.
145• Standard Methods of Sampling and Testing Fly Ash for Use as
an Admixture in Portland Cement Concrete, Designation
C 311-68. In: 1972 Annual Book of ASTM Standards, Part 10;
Concrete and Mineral Aggregates. American Society for
Testing and Materials, Philadelphia, Pennsylvania, 1972.
PP. 220-226.
146• Standard Methods of Collection of a Gross Sample of Coal,
Designation D 2234-72. In: 1973 Annual Book of ASTM Stand-
ards, Part 19: Gaseous Fuels; Coal and Coke. American
Society for Testing and Materials, Philadelphia,
, Pennsylvania, 1973. pp. 355-371.
147- Standard Methods for the Examination of Water and Waste-
water, 13th Edition; M. J. Taras, A. E. Greenberg, R. D.
Doak, and M. C. Rand, eds. American Public Healtn
Association, New York, New York, 1971. 874 pp.
148• Standard Method of Test for Proximate Analysis of Coal and
Coke, Designation D 3172-73. In: 1973 Annual Book of ASTM
Standards, Part 19: Gaseous Fuels; Coal and Coke. American
Society for Testing and Materials, Philadelphia,
Pennsylvania, 1973. p. 434.
l49' Standard Method of Test for Forms of Sulfur in Coal,
Designation D 2492-68. In: 1973 Annual Book of ASTM Stand-
ards, Part 19: Gaseous Fuels; Coal and Coke. American
Society for Testing and Materials, Philadelphia,
Pennsylvania, 1973. pp. 380-384.
150• Parker, C. R. Water Analysis by Atomic Absorption. Varian
Techtron Pty. Ltd., Springvale, Victoria, Australia,
Reprint 1976. 78 pp.
151 • Fernandez, F. G. Atomic Absorption Determination of Gaseous
Hydrides Utilizing Sodium Borohydride Reduction. Atomic
Absorption Newsletter, 12(4):93-97, 1973.
152• Brodie, K. G. Determining Arsenic and Selenium by AAS.
American Laboratory, 9 (3):73-79, 1977.
125
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153. Martin, D. 0., and J. A. Tikvart. A General Atmospheric
Diffusion Model for Estimating the Effects on Air Quality
of One or More Sources. Presented at the 61st Annual Meet-
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Minnesota, June 23-27, 1968. 18 pp.
154. Eimutis, E. C., and M. G. Konicek. Derivations of Continu-
ous Functions for the Lateral and Vertical Atmospheric
Dispersion Coefficients. Atmospheric Environment,
6(11):859-863, 1972.
155. Tadmor, J., and Y. Gur. Analytical Expressions for the t
Vertical and Lateral Dispersion Coefficients in Atmospheric
Diffusion. Atmospheric Environment, 3(6):688-689, 1969.
156. Gifford, F. A., Jr. An Outline of Theories of Diffusion in
the Lower Layers of the Atmosphere. In: Meteorology an .n,
Atomic Energy 1968, Chapter 3, D. A. Slade, ed. Publicatl
No. TID-24190, U.S. Atomic Energy Commission Technical
Information Center, Oak Ridge, Tennessee, July 1968.
p. 113.
157. Standard for Metric Practice. ANSI/ASTM Designation
E 380-76e, IEEE Std 268-1976, American Society for Testing
and Materials, Philadelphia, Pennsylvania, February 1976.
37 pp.
126
-------
APPENDIX A
SUMMARY OF NEDS DATA
Table A-l presents selected data from the NEDS files for
Standard Classification Codes SCC 1-02-002-02, SCC 1-02-002-08,
and SCC 1-02-002-12 which correspond to external combustion of
Pulverized bituminous coal in dry bottom industrial boilers with
design capacities >105 GJ/hr, 10.5 GJ/hr to 105 GJ/hr, and
^10.5 GJ/hr, respectively. Obvious entries for utility and
commercial/institutional units listed in these files have been
omitted. The NEDS files do not list all boilers in this source
category; many smaller boilers are not entered in the system.
This point is discussed further in Section 3. Besides the NEDS
data, county population densities calculated from population and
land area information obtained from the 1970 census (137) are
listed in the third column ofthe table.
Conversion factors used to provide metric values are shown at
the end of this report. Abbreviations used in the eleventh
column (Pollution Control Equipment) are as follows:
GC - gravity collector
CC - centrifugal collector
ESP - electrostatic precipitator
FP - fabric filter
WS - wet scrubber
The letter "C" is used to denote confidential information.
(137) 1970 Census and Areas of Counties and States. In: The
World Almanac & Book of Facts, 1976. Newspaper Enterprise
Association, Inc., New York, New York, 1975. pp. 239-257.
127
-------
TABLE A-l. SUMMARY OF NEDS DATA (5, 137)
to
00
<=.-;...» county
Alabama Morgan
Georgia chattooga
Floyd
Idaho Bonneville
Canyon
Minidoka
Twin Falls
Illinois Cook
Franklin
Fulton
Grundy
Knox
LaXe
Ha con
Madison
Peoria
County
population
density,
51.8
24.5
54.7
10.9
40.2
8.0
e.i
2,196.5
33.5
18.3
23.0
32.1
316.9
83.1
130.0
120.0
t Owner
Monsanto Textiles
Riegel Textile Corp-
Georgia Kraft Co.
Celanesa Fibers Co.
Utah Idaho Sugar Co.
Amalgamated Sugar Co.
Ford Motor Co.
Inland Steel Co.
Ayreshire Coal Co.
Morris Paper Mills
Galesburg Malleable
Abbott Laboratories
Staley Mfg. Co.
Alton Box Board Co.
Walker and Son
Design
capacity,
GJ/hr
C
211
63
63
105
1,194
109
C
C
227
c
C
53
53
32
140
162
189
40
47
186
103
191
191
190
195
195
223
180
469
258
Annual
operating
rate, Steck
metric height,
tons m
13,154
3,946
3,946
6,577
26
15,513
C
C
18,144
43,999
c
C
c
c
10,900
10,900
10,900
10,400
700
49,900
4,400
19,100
41,700
29.800
43,000
44,900
50,700
50,300
47,000
58,600
37,200
113,400
o
67,100
58
66
66
66
66
55
69
15
49
76
30
39
30
69
46
24
24
24
32
24
12
49
102
102
76
76
102
102
102
102
59
59
71
71
Gas
flow Fuel Fuel
rate , sulfur ash
actual content, content,
mVs » *
5.7
42.5
11.8
11.8
18.9
169.7
19.3
0.7
51.1
49.0
60.5
53.4
68.5
46.3
14.7
14.7
14.7
5.0
-
27.9
169.8
20.8
41.5
0.64
0.89
0.89
0.89
0.89
1.00
0.85
0.72
0.80
0.72
0.46
0.72
0.72
0.75
0.53
0.80
0.80
0.80
0.60
2.70
2.60
0.07
1.20
2.80
2.80
2.80
2.80
2.80
2.80
3.50
3.50
2.30
2.30
7.0
10.0
10.0
10.0
10.0
10.0
12.0
4.5
7.5
8.0
8.0
8.0
8.0
8.0
5.0
8.5
8.5
8.5
12.0
5.2
6.0
2.6
8.7
8.7
8.7
8.7
8 7
8.7
87
8.7
8.7
12.0
12.0
8.6
8.6
.^_^_^«-^^^«^
Pollution
control
equipment
type
ESP
CC
CC
CC
CC
ESP
ESP-GC
FF
WS
HS
CC
FF
FF
FF
FF
cc-ws
ESP
GC
GC
GC
GC
GC
GC
ESP
ESP
CC
CC
ulate
control
effi-
ciency,
99.0
40.0
40.0
40.0
40.0
99.5
95.0
99.0
99.0
79.0
99.5
90.0
90.0
90.0
99.0
99.0
50.0
50.0
50.0
50.0
50.0
50.0
98.9
98.7
86.3
90.8
(continued)
-------
TABLE A-l (continued)
to
County
population
density.
State County persons/tan3 Owner
Illinois (cont.)
St. Clair 159.4 Car ling Brewing Co.
Charles Meyer Co.
Will 275.1 Statesville Pen
Uniroyal J-A-A-P
Williamson 43.0 21 Egler Coal Co.
Indiana Clark 75.8 U.S. Army Ammunition Plant
^
Colgate Palaolive
Lake 408.8 Inland Steel
Youngs town Sheet 6 Tube
Marion 104.5 FMC Corp.
Stokely-Van Camp
St. Joseph 201.5 Uniroyal, Inc.
Tippecanoe 83.6 Alcoa-Lafayette
Iowa Black Hawk 90.1 Rath Packing Co.
John Deere
Cerro Gordo 32.7 Lehigh Portland Cement
Annual
operating
Design rate. Stack
capacity, metric height,
GJ/hr tons m
20
20
4
28
105
105
105
13
221
221
221
221
221
81
460
480
480
480
980
7
7
25
25
25
74
74
161
161
161
42
C
.
74
-
6,800
6,800
500
9,100
25,800
25,800
25,700
2,100
0
0
0
0
0
48
98,000
98,000
98.000
98,000
71,500
100
100
1,500
1,500
1,500
6,500
6,500
4,800
4,800
4,800
6,400
C
250
440
0
69
69
21
67
36
36
36
47
47
47
47
47
58
69
69
69
69
52
53
S3
53
53
53
61
61
76
76
76
61
59
9
50
13
Gas
flow Fuel
rate, sulfur
actual content,
- m3/s *
14.8
14.8
1.0
-
-
_
-
12.8
12.8
12.8
12.8
12.8
26.9
91.1
91.1
91.1
91.1
459.6
_
-
-
-
-
24.5
20.2
3.4
3.4
3.4
16.8
29.3
2.7
2.2
143.8
3.30
3.30
4.00
2.50
1.80
1.80
1.80
3.00
.30
.30
.30
.30
.30
2.80
2.53
2.53
2.53
2.53
0.73
0.70
0.70
0.70
0.70
0.70
0.97
0.97
1.00
1.00
3.00
2.41
2.31
1.40
1.40
-
Fual Pollution
ash control
content, equipment
% tvoe
10.0
10.0
9.8
6.1
10.2
10.2
10.2
9.5
10.2
10.2
10.2
10.2
10.2
11.0
10.9
10.9
10.9
10.9
9.0
6.0
6.0
6.0
6.0
6.O
15.0
5.0
5.5
5.5
8.0
10.3
7.7
9.4
9.4
-
FT
ff
CC
cc
CC
cc
cc-ws
GC
GC
CC
CC
CC
ESP
CC
FT
Partic-
ulate
control
effi-
ciency ,
%
46.5
46. 5
_
85.0
85.0
85.0
85.0
85.0
85.0
85.5
85.5
85.5
99.0
80.0
99.5
(continued)
-------
TABLE A-l (continued)
State
Iowa (cont.)
Kansas
Kentucky
Maryland
Massachusetts
Michigan
County
population
density.
County persons/Ion* Owner
Design
capacity,
GJ/hr
Clinton 31.4 Clinton Corn
Des Hoines
Lee
Muscatine
Scott
Cherokee
Boyd
Meade
Muhlenburg
Allegany
Washington
Merrimack Valley APCO
Calhoun
Genesee
44.0 IA Army Ammunition Plant
30.7 Consolidated Packaging
32.0 Grain Processing
120.0 Linwood Stone Prod.
Oscar Mayer 6 Co.
14.0 Gulf Oil Chemicals
122.7 Ashland Oil, Inc.
Pittsburgh Act. Carbon
22.7 Olin Corp.
21.7 Island Creek Coal Co.
74.1 West Virginia Pulp s Paper
85.2 Western Md. RR
277.5 Boston £ Maine
76.3 General Foods Corp.
General Service Admin.
265.6 Chevrolet Division, CMC
Buick Motor Division, GMC
499.1 Michigan Army Hissile Plant
_
_
_
47
38
119
119
105
105
_
95
104
35
95
C
218
82
229
229
229
3
1
622
827
42
42
87
182
145
22
153
506
506
105
Annual
operating
rate , Stack
metric height,
tons ra
3,100
11,300
14,100
83,700
109,800
23,400
1
970
4,600
3,400
2,950
9.100
9,100
9,100
14,200
14,200
3,500
14,500
C
25,700
0
57,700
57,700
57,700
180
90
152,400
196,000
4,870
4,870
12,400
18,100
2,300
5,000
17,100
50,000
48,000
19.100
17
17
17
17
17
21
69
56
56
30
27
0
0
0
43
43
27
43
34
46
37
38
38
30
21
9
53
69
34
34
53
60
60
69
46
76
76
-
Gas
flow Fuel
rate, sulfur
actual content,
m3/s %
0.5
0.2
0.2
1.1
2.9
0
0
28.1
28.1
21.4
21.4
22.7
22.7
22.7
23.6
23.6
6.6
23.6
-
10.1
7.1
34.5
33.0
34.9
6.0
1.5
-
7.8
7.8
8.3
84.9
14.9
98.6
98.6
-
2.60
2.60
2.60
2.60
2.60
3.30
4.00
2.63
2.63
2.63
2.63
2.70
2.70
2.70
2.70
2.70
2.70
0.70
3.50
0.90
0.50
2.02
2.02
2.02
3.20
3.20
2.70
2.40
2.60
2.60
1.56
1.00
1.00
2.30
1.00
1.08
1.08
1.10
Fuel
ash
content,
%
8.0
8.0
8.0
8.0
8.0
9.2
10.4
8.1
8.1
8.1
8.1
5.4
5.4
5.4
7.6
7.6
7.6
7.9
12,0
8.0
2.2
14.3
14.4
14.4
6.4
6.4
15.0
15.0
6.8
6.8
8.0
5.8
5.8
5.5
6.0
8.7
8.7
6.0
Pollution
control
equipment
type
CC-FF
CC-FF
CC-FF
CC-FF
FF
CC
CC-GC
CC-GC
CC-GC
CC
CC
CC
ESP
CC
CC-ESP
CC-ESP
CC-ESP
ESP
CC-ESP
CC
CC
CC
CC
CC
CC
ESP
ESP
CC
Partlc-
ulate
control
effi-
ciency,
%
99.0
99.0
99.0
99.0
99.0
65.0
95.0
95.0
95.0
90.0
90.0
90.0
97.0
52.0
97.0
99.2
99.2
99.0
96.0
92.0
92.0
93.5
93.3
85.0
94.0
98.8
98.7
90.0
Macorob
(continued)
-------
TABLE A-l (continued)
u>
County
population
density.
State County persons/km2 owner
Michigan (cont.)
Midland 46.8 Dow Chemical Co.
Muskegon 120.3 s.O. Warren Paper Co.
Ontonagon 3.0 Hoerner Waldorf
White Pine Copper Co.
Mill Division - Paper Mill
"a*06 1,686.3 Allied Chemical
American Motors Corp.
Dearborn Glass Plant
Cadillac Motor Car Division
Minnesota Anoka i39.8 Honeymead Products Co.
Freeborn 20.7 Wilson Sinclair
Missouri Pike 9.4 Hercules, Inc.
St. Louis 742.8 Anheuser Busch
GMAD Chassis Side
Design
capacity,
GJ/hr
822
126
126
348
282
215
234
395
1,887
22
885
885
1.012
632
1012
632
632
126
126
126
126
126
82
126
194
194
194
C
C
C
C
C
Annual
operating
rate,
metric li
tons
84,400
19,200
17,900
75,800
54,400
16,800
6,960
28,700
497,000
1,810
71.600
71,600
71,600
89,400
71,600
89,400
89,400
6,050
6,320
8,920
6,680
7,310
3,600
14,700
52,900
52,900
52,900
C
C
C
C
C
Stack
eight,
ro
55
-
46
46
46
46
67
46
95
95
95
95
95
95
95
38
38
38
38
38
46
34
36
36
36
69
69
69
69
69
Gas
flow
rate,
actual
mVs
-
-
40.7
94.4
35.3
6.5
-
-
-
-
-
_
39.6
39.6
39.6
39.6
19.8
15.6
12.8
15.6
15.6
15.6
20.4
30.5
17.6
28.5
28.5
Fuel
sulfur
content,
%
3.80
1.70
1.70
1.70
2.71
1.32
1.32
3.50
0.62
0.70
0.78
0.78
0.78
0.78
0.78
0.78
0.78
0.64
0.64
0.64
0.64
0.64
0.90
2.10
1.70
1.70
1.70
3.65
3.65
3.60
2.92
2.92
Fuel
ash
content,
^
11.8
7.0
7.0
7.0
7.9
8.9
8.9
9.2
6.5
7.5
11.
11.
11.
11.
11.
11.4
11.4
14.1
14.1
14.1
14.1
14.1
6.0
8.5
7.1
7.1
7.1
10.6
10.6
10.6
10.2
10.2
Pollution
control
equipment
^vnA
cc
CC-ESP
CC
CC
cc
CC
ESP-CC
ESP-CC
ESP-CC
ESP-CC
CC
CC
CC
CC
ESF
ESP
ESP
ESP-WS
ESP-WS
Partic-
ulate
control
effi-
ciency,
%
85.6
98.1
85. 0
89.6
90.8
75.5
93.7
94.1
95.8
94.4
65.0
25.0
25.0
25.0
90.0
90.0
91.7
99.4
90.0
99.4,
Percent SOx control efficiency.
90.0°
(continued)
-------
TABLE A-l (continued)
ro
State County
New York Cattaraugus
Erie
Essex
Genesee
Jefferson
Kings
Monroe
Niagara
Onondaga
St. Lawrence
Schuyler
Wayne
North Carolina Avery
Buncombe
Cabarrus
County
population
density,
persona An2 Owner
23.4 Moench Tanning
402.7 Anaconda America
7.2 Maclntyre Development
44.9 U.S. Gypsum Co.
26.0 Crown Zellerbach
14,132.7 Brooklyn Naval Shipyard
404.2 Clark Stek-O Co.
Flower City Tissue
Gleason Works
CMC Rochester Plant
169.2 Frestolite Division.
226.8 Allied Chemical
15.4 Norwhey Division
19.3 International Salt
50.2 Gar lock. Inc.
19.0 Harris Mining Co.
81,1 American Enka Co.
79.1 Kerr Bleach & Finishing
Cannon Hills Co.
Annual
operating
Design rate,
capacity, metric
GJ/hr tons
19
19
74
35
83
189
158
158
158
158
158
158
22
27
90
153
78
28
28
295
262
262
262
262
262
401
19
110
94
16
143
143
215
258
C
C
C
3,400
3,400
12,500
4,700
19,900
5
7,560
7,560
7,560
7,560
7,560
7,560
-
2,900
6,350
10,900
7,260
-
1
83,500
74,800
74,800
74,800
74,800
74,800
113,000
0
12,000
1.800
3,200
36,500
36,500
54,700
54,400
C
C
C
Stack
height,
m
17
17
38
41
41
15
-
-
-
-
-
-
40
24
53
53
15
18
21
46
46
46
46
46
46
64
26
69
30
40
69
69
53
53
23
53
53
Gas
flow
rate,
r actual
mVs
3.6
3.3
12.1
13.8
30.8
19.2
-
-
-
-
-
-
-
1.8
9.1
5.1
4.4
6.6
<0.1
51.9
51.9
51.9
51.9
51.9
51.9
-
4.2
26.5
8.5
1.7
34.8
32.9
40.0
17.7
21.2
1.4
2.0
Fuel
sulfur
content,
%
2.00
2.00
1.60
2.30
2.80
2.10
2.50
2.50
2.50
2.50
2.50
2.50
1.90
2.60
1.30
1.00
1.00
2.80
2.80
3.00
3.00
3.00
3.00
3.00
3.00
3.00
2.30
2.40
1.50
0.80
1.04
1.04
1.04
1.04
0.80
0.84
0.84
Parti c-
ulate
Fuel Pollution control
ash control effi-
content, equipment ciency,
% type %
9.4
9.4
12.1
8.0
7.5
7.1
10.0
10.0
10.0
10.0
10.0
10.0
7.2
7.0
6.9
9.8
9.8
7.5
7.5 •
13.0
13.0
13.0
13.0
13.0
13.0
13.0
9.0
7.0
10.0
5.0
7-5
7.5
7.5
7.5
5.3
5.5
5.5
CC
CC
CC-CC
CC-CC
CC
CC-CC
CC-CC
CC-CC
CC
CC
ESP
ESP
ESP
ESP
ESP
ESP
ESP-ESP
CC-CC
CC
CC-CC
CC
CC-CC
CC-CC
CC
CC
67.0
67.0
92.8
90.0
88.0
91.0
85.0
90.0
92.0
97.0
99.0
96.5
96.5
96.5
96.5
96.5
96.9
96.0
94.5
99.9
99.0
83.5
91.0
89.0
89.0
(continued)
-------
TABLE A-l (continued)
OJ
U)
County
population
density,
state County persons/tan2 Owner
North Carolina (cont.)
Davidson 66.7 Thomasville Furn. Ind.
Forsyth 189.3 R. J. Reynolds Itobaoco Co.
_
Guilford 168.0 Cone Mills
Balifax 27.7 Albenarle Paper Co.
J. P. Stevens
Hay«°od 28.2 U.S. Plywood
Iredell 45.8 Mooresville Mill
McDowell 24.3 Broyhill
Old Fort Finishing
Drexel
Burlington Industries
P"1* 18.6 Southern Mercerizing
Rockingham 48.1 American Tobacco Co.
Rowan 67-0 Fieldcrest Mills
Transylvania 18.9 Olin Corp.
Annual
operating
Design rate. Stack
capacity, metric height,
GJ/hr tons m
18
28
C
C
C
C
131
131
123
218
C
C
C
316
316
337
360
95
95
40
39
39
48
19
22
18
93
39
156
156
95
C
C
C
1,130
930
C
C
C
C
0
0
0
0
C
C
C
90,700
90,700
99,800
19,600
120
120
330
8,500
8,500
10,300
860
24
1,050
0
0
25
24
11,300
C
C
C
23
23
70
70
70
70
53
53
53
53
64
30
27
76
76
46
46
15
15
38
24
24
27
15
23
41
67
67
67
67
24
36
37
37
Gas
flow Fuel Fuel
rate, sulfur ash
actual content, content,
m3/B » »
2.1
3.4
48.6
48.6
46.8
46.8
14.8
14.8
14.0
24.6
102
11.8
10.9
288
288
38.3
54.6
38.2
38.2
61.4
10.8
10.8
13.1
7.6
2.1
18.8
7.9
30.6
30.6
30.7
41.3
26.4
54.fr
1.00
1.00
0.70
0.70
0.70
0.70
1.00
1.00
1.00
1.00
1.25
1.10
1.40
1.30
1.30
1.30
1.30
0.97
0.87
0.88
1.60
1.60
1.60
1.00
0.70
0.76
1.20
1.20
1.20
1.20
0.90
1.60
1.60
1.60
•»
6.0
6.0
9.0
9.0
9.0
9.0
6.0
6.0
6.0
6.0
10.0
6.9
5.5
18.0
18.0
18.0
18.0
4.0
4.0
6.6
8.6
8.6
8.6
6.0
6.0
4.8
11.0
11.0
11.0
11.0
9.0
10.0
10.0
10.0
Pollution
control
equipment
typa
cc
cc
CC-ESP
CC-ESP
ESP
ESP
CC
CC
CC
CC
WS
GC
ESP
ESP
ESP
CC
CC
ESP
ESP
ESP
Partlc-
ulate
control
effi-
ciency ,
%
99.3
93.9
97.7
97.7
97.7
97.7
80.0
80.0
BO.O
80.0
9fi a
9O. V
25.0
99.0
99.0
71.9
90.0
90.0
99.0
99.0
99.0
(continued)
-------
TABLE A-l (continued)
County
population Design
density , capacity ,
State County persons/km3 Omar GJ/hr
Ohio Butler 178.9 Crystal Tissue Co.
Diamond International Corp.
Sorg Paper Co.
v
Hamilton Mil-Champ Papers
Cuyahoga 1,440.8 Aluminum Co. of America
Republic Steel Corp.
Franklin 591.3 Naval Weapons Ind. Res. Plant
Hamilton 853.7 Emery Industries, Inc.
Fox Paper, Inc.
General Electric
Diamond International Corp.
Procter 6 Gamble Co.
Sherwin Williams Chemicals
Jefferson 89.4 Wheeling Pittsburg Steel
148
139
203
105
105
105
442
79
79
79
79
79
354
354
354
486
242
242
353
83
83
83
187
162
263
162
263
102
116
156
160
292
70
84
84
84
Annual
operating
rate. Stack
metric height
tons m
20,900
27,600
39,100
10,900
16,200
13,400
114,000
7,300
7,300
7,300
7,300
7,300
43,100
43,100
43.100
119,000
16,300
16,300
85,000
2,470
2,100
3,760
5,250
40,800
14,100
45,100
69,600
18,100
246
26.400
36,000
34,000
3,970
12,700
12,700
1,520
20
21
61
61
61
61
67
61
61
61
46
46
51
44
44
69
46
46
37
23
23
23
23
24
24
24
24
53
18
23
18
53
55
84
84
77
Gas
flow
rate,
, actual
»3/S
18.9
25.0
42.6
19.1
19.1
19.1
118
11.5
11.5
11.5
11.5
11.5
86.8
86.8
86.8
81.2
170
170
82.4
17.5
17.5
17.5
35.4
14.5
32.1
14.5
32.1
35.4
17.9
17.8
23.6
51.9
6.5
44.6
44.6
44.8
Fuel
sulfur
content,
%
0.70
0.70
0.90
0.90
0.90
0.90
0.87
2.50
2.50
2.50
2.50
2.50
2.00
2.00
2.00
2.00
2.00
2.00
1.00
3.50
3.50
3.50
3.50
0.89
0.89
0.70
0.70
0.75
1.25
1.25
0.70
0.70
0.78
3.00
3.00
3.00
Fuel
ash
content ,
%
7.5
6.0
8.7
8.7
8.7
fl. 7
11.0
7.0
7.0
7.0
7.0
7.0
15.0
15.0
15.0
1S.O
15.0
15.0
10.0
6.7
6.7
6.7
6.7
7.3
7.3
6.6
6.6
6.5
10.0
10.0
11.0
13.0
5.9
8.5
8.5
8.5
Pollution
control
equipment
type
ESP
ESP
ws
FF
WS
cc
cc
cc
cc
cc
ESP-CC
ESP-CC
ESP-CC
BSP-CC
CC
CC
CC
CC-ESP
ESP
CC
Partic-
ulate
control
effi-
ciency,
%
98.0
92.5
99.0
99.0
99.0
75.0
85.0
85.0
85.0
91.4
*
96.8
96.8
96.8
96.8
85.0
88.0
82.0
90.0
90.0
85.0
(continued)
-------
TABLE A-l (continued)
u>
- . ^ _^^^_^^_^_ .
County
population
State county persons/km^ owner
Ohio (cont.) Jefferson 89.4 Wheeling Pittsburg Steel
L*Jte 326.4 Diamond Shamrock Chemicals
Uniroyal chemicals Division
Lawrence 46.9 Allied Chemical Corp.
H»honing 277.8 Youngstown Sheet & Tube
Republic Steel Corp.
U.S. Steel Corp.
Montgomery 498.2 Inland Division
Frigidaire
Miami Paper Corp.
st«k 248.5 Wean United, Inc.
Republic Steel Corp
Annual
operating
rate,
Stack
capacity, metric height,
GJ/hr tons in
84
84
84
84
222
222
222
447
491
135
135
184
184
497
497
297
297
297
297
430
430
327
327
327
327
99
103
139
103
103
103
103
137
3
3
59
1,520
1,520
1,520
1,520
5,900
5,480
6,070
112,500
117,000
12,300
12.300
27,900
27,900
18,500
18,500
11,100
11,100
11,100
11,100
9,890
9,890
4,130
4,130
4,130
4,130
10,100
10,400
14,200
12,400
12,400
12,400
12,400
32,700
950
0
5,600
77
77
77
77
36
36
36
49
54
53
53
38
38
41
41
41
41
41
41
48
48
43
43
43
43
53
53
53
61
61
61
61
67
24
24
90
Gas
flow
rate.
— • i.^~— ^
Fuel
sulfur
actual content,
•Va *•
44.8
44.8
44.8
44.8
26.9
26.9
26.9
77.9
97.2
59.0
59.0
34.4
34.4
118
118
73.8
77.8
77.8
73.8
89.7
89.7
21.8
21.8
21.8
21.8
35.9
35.9
27.4
27.2
20.9
23.1
22.5
26.0
13.2
13.2
15.2
3.00
3.00
3.00
3.00
3.00
3.00
3.00
3.44
3.44
4.00
4.00
3.30
3.30
2.79
2.79
2.79
2.79
2.79
2.79
3.50
3. SO
1.00
1.00
1.00
1.00
0.76
0.76
0.76
0.60
0.60
0.60
0.60
0.80
0.71
0.71
3.00
Fuel
ash
content.
8.5
8.5
8.5
8.5
8.5
8.5
8.5
12.8
12.8
11.0
11.0
14.0
14.0
11.9
11.9
11.9
11.9
11.9
11.9
13.8
13.8
13.3
13.3
13.3
13.3
12.3
12.3
12.3
13.7
13.7
13.7
13.7
8.6
8.6
8.6
4.8
Partic-
ulate
Pollution control
control effi-
equipment ciency.
type %
ESP 95.0
ESP 95.0
CC 90.0
CC 90.0
CC-ESP 99.0
CC-ESP 99.0
ESP 99.0
CC-ESP 98.4
CC-ESP 98.7
CC-ESP 99.5
CC-ESP 99.5
CC-WS 95.7
(continued)
-------
TABLE A-l (continued)
UJ
County
population Design
density, capacity,
state County persons /km2 Ouner GJ/hr
Ohio (cont.) Stark 248.5 Republic Steel Corp. 59
59
59
59
Summit 514.4 Firestone Tire & Rubber Co. 577
577
Goodyear Tire S Rubber Co. 201
173
347
347
Trumbull 144.2 Republic Steel Corp. 587
Tuscarawas 53.7 U.S. Concrete Pipe Co. 28
Oregon Malheur 0.9 Amalgamated Sugar Co.
^
_
Pennsylvania Adams 41.1 P. H. Glatfelter 148
37o
271
Allegheny 841.6 U.S. Steel 223
223
223
Westinghouse electric 196
Koppars Pittsburg Co. 113
U.S. Steel 151
151
151
676
530
507
Annual
operating
rate , Stack
metric height
tons m
5,600
5.600
5,600
5,600
88,100
102,000
47,400
40,600
81,600
81,600
25,500
4,200
2,200
37,000
36,300
22,300
34,700
58,700
66,000
7,950
7,950
7,950
7,950
16,500
17,300
2,860
2,860
2,860
7,950
7,960
135,000
90
90
90
90
69
69
76
72
76
76
46
53
53
46
_
46
61
61
61
46
46
46
46
32
50
50
SO
43
43
50
Gas
flow
rate,
, actual
m3/s
15.2
15.2
15.2
15.2
88.8
88.8
16.7
23.2
46.0
46.0
89.7
-
_
-
32.4
67.7
49.7
38.5
38.5
38.5
38.5
35.0'
36.0
36.0
36.0
202
155
73.1
Fuel
sulfur
content ,
%
3.00
3.00
3.00
3.00
3.10
3.10
3.70
3.70
3.70
3.70
2.80
3.01
3.01
-
-
-
3.50
3. SO
3.50
2.00
2.00
2.00
2.00
1.75
2.20
1.48
1.48
1.48
1.97
1.97
1.62
Fuel
ash
content ,
%
4.8
4.8
4.8
4.8
9.9
9.9
12.9
12.9
12.9
12.9
13.0
5.6
5.6
-
-
-
8.0
8.0
8.0
9.0
9.0
9.0
9.0
13.1
9.0
5.9
5.9
5.9
8.3
8.3
6.7
Pollution
control
equipment
type
CC
cc
ESP
CC
CC
CC
CC
cc-rr
CC
CC-FF
CC
CC
ws
CC
CC
CC
CC
CC
CC
CC-ESP
Partic-
ulate
control
effi-
ciency,
%
91.0
91.0
99.0
85.0
85.0
85.0
65.0
94.0,
99. 7B
94.0
94.0
99.7
90.7
88.0
92.7
92.0
92.0
92.0
92.0
85.0
85.0
96.0
Percent SOx control efficiency.
(continued)
-------
TABLE A-l (continued)
u>
-4
Annual
County operating
population Design rate. Stack
density, capacity, metric height.
State County persons/Ion2 Owner GJ/hr tons m
Pennsylvania (cont . )
Allegheny 841.6 Pittsburg Brewing Co. 23
23
Union Carbide Corp. 177
177
177
Beaver 180.4 Sinclair-Hoppers Co. 495
495
495
495
Crucible, Inc. 105
Blair 97.5 Hestvaco Corp. 116
116
Buttler 60.6 Sonneborn Diviaion-Witco Chem. 50
85
85
131
Crawford 29. B FMC Corp. 181
181
181
181
Cumberland 109.3 C. H. Masland s Sons 101
Dauphin 163.4 Hershey Foods Corp. 163
163
163
163
190
Elk 17.7 Penntech Papers, Inc. 74
Erie 122.6 Hanmennill Paper Co. 130
130
217
217
4,350
4,350
55,600
55,600
55,600
95,300
95,300
95,300
43,700
31,800
23,900
23.900
15.900
23,900
23.900
31,800
45,700
45.700
45,700
45,700
6,390
11,100
11,100
6,060
15,200
24,200
19,400
5,150
5,150
46.500
46,500
63
63
48
48
48
61
61
61
61
44
72
72
61
61
61
61
62
62
62
62
46
76
76
76
76
76
37
67
67
67
67
Partic-
Gas ulate
flow Fuel Fuel Pollution control
rate, sulfur ash control effi-
actual content, content, equipment ciency,
m^/s * % type *
17.0
17.0
174
174
174
134
134
134
134
47.7
24.0
24.0
20.3
33.3
33.3
45.4
104
104
104
104
28.2
64.1
64.1
34.8
42.4
84.8
61.6
20.2
20.2
33.9
37.2
2.80
2.80
2.75
2.75
2.75
3.12
3.12
3.12
3.12
2.20
2.00
2.00
2.50
2.50
2.50
2.50
2.00
2.00
2.00
2.00
3.30
2.25
2.25
2.25
2.25
2.25
2.25
2.70
2.70
2.70
2.70
7.5
7.5
14.0
14.0
14.0
16.9
16.9
16.9
16.9
15.0
10.0
10.0
9.0
9.0
9.0
9.0
13.0
13.0
13.0
13.0
7.7
11.8
11.8
11.8
11.8
11.8
10.5
12.0
12.0
12.0
12.0
CC
CC
CC
ESP
ESP
ESP
ESP
ESP
CC
CC
CC
CC
CC
CC
CC
CC
CC
CC
CC
81.5
81.5
81.5
98.6
98.6
98.6
98.6
98.0
86.0
86.0
88.0
85.0
85.0
85.0
85.0
83.5
87.2
93.0
93.0
(continued)
-------
TABLE A-l (continued)
u>
oo
County
population Design
density, capacity.
State county persons/to3 Owner GJ/hr
Pennsylvania (cent.)
KcKean 19*7 Quaker State Oil 106
96
96
Washington 94.3 Wheeling Pittsburg Steel Corp. 53
53
53
53
154
154
Tennessee Davidson 401.9 DuPont 586
2(>7
269
286
415
Heuhoff Packing 15
Hanblen 92.4 American Enka 190
190
190
190
190
290
Hamilton 170.4 DuPont 6'
Hawkins 26.8 Holsten Army Anno. Plant 250
270
Sullivan 116.4 Tennessee Easnan Co. 584
584
584
584
Holsten Army Anrao. Plant 271
Head Corp. 1(>5
105
105
Annual
operating
rate,
metric
tons
25,900
24,000
24,000
900
900
900
900
2,850
2,850
7,330
2,140
2,140
2.280
3,310
0
31,900
31,900
31,900
31,900
31,900
31,900
51,300
12,500
0
0
186,000
186,000
186,000
186,000
158.000
20,600
0
0
21 ,000
Stack
height ,
m
46
61
61
34
34
34
34
34
34
61
61
61
61
61
63
76
76
76
76
76
76
76
30
35
35
76
76
76
76
76
35
54
54
54
Gas
flow
rate,
actual
«Vs
27.1
33.0
33.0
6.1
6.1
6.1
6.1
10.3
10.3
103
152
-
-
78.8
168
168
168
168
168
168
95.5
11.2
21.1
26.4
56.6
56.6
56.6
56.6
56.6
28.7
47.0
47.0
47.0
Fuel
sulfur
content ,
%
1.16
1.16
1.16
2.01
2.01
2.01
2.01
2.01
2.01
2.50
3.00
3.00
3.00
3.00
0.90
0.90
0.90
0.90
0.90
0.90
0.90
2.40
0.62
0.60
0.75
0.75
0.75
0.75
0.89
0.60
0.94
0.94
0.94
Fuel
ash
content,
%
11.2
11.2
11.2
7.9
7.9
7.9
7.9
7.9
7.9
8.0
8.0
8.0
8.0
8.0
15.0
15.0
15.0
15.0
15.0
15.0
15.0
14.0
8.0
10.0
18.5
18.5
18.5
18.5
14.7
6.5
13.0
13.0
13.0
Pollution
control
equipment
type
cc
cc
cc
cc
cc
cc
cc
cc
cc
cc
cc
CC-ESP
CC-ESP
CC-ESP
CC-ESP
CC-ESP
CC
GC
GC
CC
Partic-
ulate
control
effi-
ciency,
%
88.0
90.0
90.0
62.5
62.5
62.5
62.5
62.5
62.5
62.5
97.0
99.2
99.1
99.0
28.4
99.0
85.0
85.0
85. 0
85.0
(continued)
-------
TABLE A-l (continued)
u>
State County
Tennessee (cont.)
Washington
Utah Salt Lake
Utah
Virginia Alleghany
Augusta
Bedford
Buckingham
Campbell
Chesterfield
Giles
Henry
Montgomery
Pittsylvania
Pulaski
warren
Wise
Washington Yakima
County
population
density,
persons/tan3
86.0
235.8
26.4
10.7
17.0
13,2
6.7
31.1
63.7
17.6
50.1
45.2
22.0
34.1
26.5
31. 6
12.9
Annual
operating
Design rate, Stack
capacity, metric height,
Owner GJ/hr tons m
Varsity Cleaners
Kennecott Copper
D.S. Steel Corp.
Westvaco Corp.
DuPont
Owens-Ill inoi a
Stolite Corp.
Head Corp.
DuPont
Celanese Fibers Co.
DuPont
Hooker Furniture Corp.
Hercules (Radford Amy Arsenal)
Dan River, Inc.
Pulaski Furniture Co.
FMC Corp.
Coal Processing Corp.
U & I Sugar
1
C
c
C
434
434
434
544
764
207
220
220
'186
193
295
C
276
752
207
417
548
333
527
19
1,054
158
612
21
892
631
1
211
43
C
C
C
11,600
11,600
11,600
46,300
198,000
46,400
23,000
26,900
36,100
15,800
112,500
C
85
32,700
45,400
98,000
472
287
63,500
230
195,000
20,200
44,000
726
176,000
117,000
154
34,500
7
44
44
44
61
61
61
98
56
76
76
76
76
46
61
-
42
76
43
43
43
46
47
30
15
49
76
27
58
58
13
61
Gas
flow Fuel Fuel Pollution
rate, sulfur ash control
actual content, content, equipment
«Vs % * tvoe
0.3
14.2
14.2
14.2
87.3
87.3
87.3
17.1
44.2
89.2
89.2
89.2
89.2
44.2
198
84.3
16.3
78.9
21.6
25.5
59.0
38.0
64.8
-
52.6
12.1
122.0
„
57.0
57.0
-
27.3
0.88
0.86
0.86
0.86
0.60
0.60
0.60
1.30
1.30
1.22
1.22
1.22
1.22
1.22
1.00
2.85
1.56
1.14
1.15
1.15
1.15
1.15
1.40
-
1.20
0.70
1.20
0.60
1.20
1.20
0.67
1.00
3.7
8.0
8.0
8.0
6.7
6.7
6.7
10.0
10.0
12.2
12.2
12.2
12,2
12.2
8.5
12.0
9.9
9.9
11.0
11.0
11.0
11.0
9.6
-
12.0
12.0
7.1
4.1
11.0
11.0
2.1
6.0
cc
cc
cc
cc-ws
ESP
CC
cc
cc
cc
cc
cc
us
cc
cc
ESP
ESP
ESP
CC
cc
cc
cc
cc
cc
cc
Partie-
ulate
control
effi-
ciency,
%
25.0
25.0
25.0
88.0
95.0
83.7
88.8
88.0
83.4
74.1
87.0
60.0
65.3
84.0
90.0
90.0
90.0
99.0
90.0
75.0
85.6
50.0
34.0
70.0
(continued)
-------
TABLE A-l (continued)
County
population Design
density, capacity,
state county persons/tan-2 Owner GJ/hr
West Virginia Brooke 129.0 Koppers, Co. 47
74
74
Kanawha 95.4 Union Carbide Corp. 137
211
211
211
211
211
348
227
227
227
227
227
227
227
227
Wisconsin Chippewa 17.9 St. Regis Paper Co. 110
Eau Claire 38.8 Uniroyal, Inc. 149
149
Marinette 9.8 Niagra-Wisc. Paper Co. 106
106
106
Hacine 196.2 Young Radiator 2
Wood 31.3 Nekoosa Edwards Paper C
Wyoming Sweetwater 0.7 Allied Chemical 563
Annual
operating
rate. Stack
metric height ,
tons m
4,230
11,700
8,490
9,800
9,800
15,100
15,100
15,100
15,100
15,100
21,500
15,900
15,900
15,900
15,900
15,900
15.900
15,900
15,900
8,290
20,200
17,600
21,600
19,300
21,600
380
C
C
116,000
122,000
61
61
44
46
46
46
46
46
47
47
46
38
38
38
38
38
38
38
38
46
55
55
47
47
47
24
65
65
48
48
Gas
flow
rate,
, actual
m3/s
18.1
18.1
7.3
35.4
35.4
54.3
54.3
54.3
51.9
51.9
89.7
47.2
47.2
47.2
47.2
47.2
47.2
47.2
47.2
20.8
10.8
10.8
80.2
8.0
8.0
99.1
99.1
118
191
Fuel
sulfur
content ,
%
1.97
1.97
1.97
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.10
2.50
2.50
2.60
2.60
2.60
0.70
2.10
2.10
0.64
0.55
Fuel
ash
content ,
»
9.2
9.2
9.2
12.2
12.2
12.2
12.2
12.2
12.2
12.2
12.2
13.0
13.0
13.0
13.0
13.0
13.0
13.0
13.0
9.9
11.0
11.0
9.8
9.8
9.8
8.2
9.1
9.1
2.9
3.0
Pollution
control
equipment
type
GC
GC
GC
ESP
FF
FF
FF
FF
FF
FF
FF
CC-ESP
CC-ESP
CC-RSP
CC-ESP
CC-ESP
CC-ESP
CC-ESP
CC-ESP
CC
ESP
ESP
ESP
ESP
Partic-
ulate
control
effi-
ciency,
%
40.0
40.0
40.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.7
99.7
99.7
99.7
99.7
99.7
99.7
99.7
-
98.5
98.5
98.1
98.0
Note.-Blanks indicate no control device listed, dashes M indicate that the information is not available.
-------
APPENDIX B
RIVER FLOW RATE DATA
Because information on wastewater treatment practices is unavail-
able, it is assumed that effluents generated by boilers in the
source type studied are discharged directly to a river. The
receiving river for discharges from the average plant (see
Sections 4 and 6) was characterized by averaging the flow rates
of rivers located near the boilers in the NEDS listing (7).
Boiler locations were identified by city, and nearby rivers were
located using area road maps and U.S Geological Sur^* J^GS)
data (88-115). Average and minimum flow rates were also obtained
from the USGS reports using data from gaging stations located in
or near the cities of interest, or by averaging data from gaging
stations located above and below these cities. When two or more
rivers were found in the same city, the river with the largest
average flow rate was selected as the most likely receiving body.
Table B-l summarizes the river flow rate data on a at^e-by-state
basis. Table B-2 lists the cities, rivers, and flow rates used
in calculating the average river characteristics. Values
Presented for average flow and minimum flow are averages of data
for two years (1974 and 1975). Blanks in Table B-l and B-2
indicate that no data were found.
The average of the minimum river flow rates "as used in the
source severity calculations. Average river flow rates are
Presented for comparison.
141
-------
TABLE B-l. SUMMARY OF RIVER FLOW RATE DATA (88-115)
State
Alabama
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Massachusetts
Michigan
Minnesota
Missouri
New York
North Carolina
Ohio
Oregon
Pennsylvania
Tennessee
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
U.S. average
Number of
rivers
averaged
0
1
4
8
2
7
0
2
0
1
7
1
1
4
5
9
1
13
4
1
7
0
3
5
1
85
Average river
flow rate,
m3/s
94.9
182.5
1,360
139.3
1,135
4,904
248.6
32.7
373.8
5,012
1,736
85.6
718.6
538.3
440.7
764.3
5.64
51.7
719.4
53.8
55.9
724.9
Average minimi
river fl°w
rate, m3/^
- j\ f
19.6
4 A r\
0 . U
. — M ^
407.7
_ • rt
20.9
_. _ A
389.4
1,756
Ui
. J-
r\ *> 1
8. 31
er l il
51. ^
2,299
1,266
16.6
__ * x*
374.6
442.2
106.0
0.294
o e O
8.53
91 ^
1.4
11 "7
12. /
18.4
266.9
— , _ — — .--
Note.—Blanks indicate no data were found.
142
-------
TABLE B-2. RIVER FLOW RATE DATA (88-115)
Alabama
Georgia
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Matyland
"assachuaetts
Miehigan
Morgan
Chattooga
Floyd
Bonneville
Canyon
Hinidoka
Twin Palls
Cook
Franklin
Fulton
Grundy
Xnox
Lake
Ha con
Madison
Peoria
St. Clair
Will
Williamson
Clark
Clark
Lake
Marion
St. Joseph
Tippecanoe
Black Hawk
Cerro Gordo
Clinton
Des Moines
.Lee
Muscat ine
Scott
Cherokee
Boyd
Meade
Muhlenberg
Allegany
Washington
Calhoun
Genesee
Macomb
Midland
Muskegon
Ontonagon
Wayne
Wayne
City
Trion
Rome
Idaho Falls
Narapa
Rupert
Twin Falls
Chicago Heights
Seaser
Vermont
Morris
Galesburg
North Chicago
Decatur
Alton
Peoria
Belleville
Joliet
Johnson City
Charlestown
jeffersonville
E. Chicago
Indianapolis
Mishawaka
Lafayette
Waterloo
Mason City
Clinton
Burlington
Fort Madison
Muscatine
Davenport
Riverton
Leach
Cattlettsburg
Brandenburg
Madiaonville
Luke
Hagerstown
Billerica
Battle Creek
Flint
Midland
Muskegon
Iron Mountain
Detroit
Dearborn
Number
of
boilers
1
4
2
2
2
2
2
3
1
1
1
1
1
8
2
2
3
4
1
5
1
5
7
3
1
3
1
5
1
1
4
7
1
1
1
3
2
2
2
1
3
3
1
1
3
4
7
7
Rivers
Etowah
Snake
Boise
Snake
Snake
Deer Creek
Big Muddy
Illinois
Sangamon
Mississippi
Illinois
Mississippi
Hickory Creek
White
Wabash
Cedar
Winnebago
Mississippi
Mississippi
Mississippi
Mississippi
Mississippi
Ohio
Ohio
Merrimack
Battle Creek
Flint
Tittubawassee
Muskegon
Menominee
River Rouge
River Rouge
Average
river flow
rate, ms/s
94.9
239.6
61.6
263.0
165.9
0.73
27.4
329.9
32.2
3,714
573.1
6,199
3.85
52.6
225.9
101.7
8.55
1,392
1,392
2,268
1,392
1,392
4,357
5,450
248.6
8.16
27.1
65.8
69.5
50.5
2.83
4.67
Minimum
river flow
rate, m»/s
19.6
71.5
2.8
76.5
9.0
0.0096
1.13
81.0
5.83
843.8
58.0
2,272
0.17
4.05
33.7
20.5
0.694
516.8
516.8
637.1
516.8
516.8
433.2
3,079
41.1
1.90
5.24
9.77
29.9
10.4
0.481
0.453
(continued)
Note Blanks indicate no data were found.
143
-------
TABLE B-2 (continued)
Minnesota
Missouri
New York
North Carolina
Ohio
Anoka
Freeborn
Pike
St. Louis
Cattaraugus
Erie
Essex
Geneaee
Jefferson
Kings
Monroe
Niagra
Onondaga
St. Lawrence
Schuyler
Wayne
Avery
Buncombe
Cabarrus
Davidson
Porsyth
Guilford
Halifax
Haywood
Iredell
McDowell
McDowell
Polk
Roc king ham
Rowan
Transylvania
Butler
Cuyahoga
Franklin
Hamilton
Jefferson
Lake
Lawrence
Mahoning
Montgomery
Stark
Summit
Trumbull
Tuscarawas
City
Minneapolis
Albert Lea
Louisiana
St. Louis
Gowando
Buffalo
Tahawus
Oakfield
Carthage
New York
Rochester
Niagara Falls
Solvay
Heuvelton
Watkins
Palmyra
Spruce Pine
Enka
Concord
Thomasville
Hinston-Salem
Greensboro
Roanoke Rapids
Canton
Mooresville
Marion
Old Fort
Tryon
Reidsville
Salisbury
Hamilton
Cleveland
Columbus
Cincinnati
Steubenville
Painesville
Ironton
Young s town
Dayton
Canton
Akron
Warren
Dover
Number
of
boilers
1
1
3
5
2
1
1
1
1
6
5
2
7
1
1
1
1
4
3
2
4
4
3
4
2
3
3
1
4
1
3
7
12
4
10
10
4
2
12
e
7
6
1
2
Rivera
Mississippi
Mississippi
Cattaraugus Cr.
Niagra
Geneeee
Oswegatchie
N. Buffalo Cr.
Roanoke
Catawba
Catawba
Yadkin
Great Miami
Cuyahoga
Scioto
Ohio
Ohio
Ohio
Mahoning
Great Miami
Nihishillen Cr.
Little Cuyahoga
Mahoning
Tuacarawas
Average
river flow
rate. mVs
373.8
5,012
21.7
6,780
90.8
50.7
2.39
292.3
12.9
12.9
107.7
116.5
49.5
6,075
41.4
77.9
1.70
17.2
26.5
61.9
river fl°*
_ratetJSf/S
51.4
2->ao
fly*
2.93
e nJO
5 , u* v
13.3
7.76
0.680
•>Q 8
i 7 • w
4.50
4.50
43.7
19.9
3.96
i 108
3 f JUff
8.69
11.4
0.283
2.89
6.17
9.71
Oregon
Pennsylvania
Malheur
Adams
Allegheny
Allegheny
Allegheny
Allegheny
Allegheny
Nyssa
McKeesport
Trafford
Bridgeville
Braddock
Homestead
3
4
1
1
3
2
Snake
Monongahela
Chartiers Cr.
Monongahela
Monongahela
538.3
420.1
10.2
420.1
420.1
Note.—Blanks indicate no data were found.
(con
442.2
56.6
2.21
56.6
56.6
tinned)
144
-------
TABLE B-2 (continued)
— — — '
Pennsylvania
(continued)
Tennessee
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Allegheny
Allegheny
Armstrong
Beaver
Beaver
Blair
Butler
Crawford
Cumberland
Dauphin
Elk
Erie
HcKean
Washington
Davidson
Davidson
Harablen
Hamilton
Hawkins
Washington
Salt Lake
Utah
Allegheny
Augusta
Bedford
Buckingham
Campbell
Chesterfield
Giles
Henry
Montgomery
Pittsylvania
Pulaski
Warren
Wise
Yakima
Brooke
Kanawha
Kanawha
Chippewa
Eau Clair
Marinette
Racine
Wood
Sweetwater
City
Clairston
Pittsburgh
Kittanning
Monaca
Midland
Tyrone
Meadville
Carlisle
Hershey
Johnsonburg
Erie
Bradford
Monessen
Old Hickory
Nashville
Lowland
Chattanooga
Kingsport
Johnson City
Hagna
Geneva
Covington
Waynesboro
Arvonia
Lynchburg
Richmond
Narrows
Martinsville
Danville
Pulaski
Front Royal
Norton
Toppenish
Follansbee
South Charleston
institute
Cornell
Eau Clair
Niagra
Racine
Nekoosa
Green River
Number
of
boilers
1
2
3
4
1
2
4
4
1
5
1
4
3
6
5
1
7
1
11
1
3
3
2
a
i
i
i
i
4
2
2
1
1
2
1
1
3
8
8
1
2
3
1
2
2
Rivers
Monongahela
Ohio
Allegheny
Ohio
Ohio
Bald Eagle Cr.
French Cr.
Clarion
Monongahela
Cumberland
Cumberland
Tennessee
S. Fork, Hols ton
Coggin Drain
Jackson
South
Slate
James
Wolf Creek
Smith
Dan
Ohio
Kanawha
Kanawha
Chippewa
Chippewa
He nominee
Root
Ten Mile Cr.
Green
Average
river flow
rate, mVs
305.8
1,084
519.0
1,084
1,084
2.05
€0.6
13.6
305.8
794.1
794.1
1,355
113.8
5.64
23.6
4.02
9.20
216.9
10.8
14.6
83.1
1,084
536. 9
536.9
44.2
137.7
80.8
4.98
1.50
55.9
Minimum
river flow
rate, m'/s
21.7
139.9
70.8
139.9
139.9
0.0850
5.75
4.13
21.7
48.6
48.6
304.4
22.2
0.294
3.31
0.934
1.87
28.5
1.08
2.75
21.3
139.9
67.1
67.1
16.4
14.4
32.0
0.153
0.651
18.4
••—Blanks indicate no data were found.
145
-------
APPENDIX C
DESCRIPTION OF THE SAMPLING PROGRAM
Emissions data in the literature for this source are often
presented under titles such as industrial boilers, pulverized
coal fired boilers, intermediate size combustion equipment, etc./
thus obscuring the relationship of the data to this source type
as defined in Section 3. In order to verify the literature_data
and emissions estimates in this report, and to determine emis-
sion values for species previously unaddressed in sufficient
detail for this source type, a program was designed to provide
the necessary information by conducting sampling of one typical
source.
SITE DESCRIPTION
The boiler chosen for sampling was a horizontally fired, dry
bottom unit burning pulverized Appalachian bituminous coal to
produce steam for process and space heating at an industrial s
— 4. -—----•—•—- — — M — • w ik« £>«_4. >»* ^^ i A ^. ^4, ^ ^ i4^ ^4 \^ \j\ 1 A -^* * Vrf* w« «•» »• -
The boiler has a rated firing capacity of 130 GJ/hr (123 — -
and an output capacity of 45,000 kilograms of steam per hour
(100,000 Ib steam/hr). This value is somewhat below the mini
capacity limit for economic utilization of pulverized coal wl
is frequently cited in the literature (200 MBTU/hr).a Our
reasons for choosing a boiler in this size range are twofold:
1) approximately 64% of the industrial boilers included in this
source type are smaller than the above mentioned limit according
to NEDS data (5), and 2) boilers in this size range have the
potential for higher emission levels than do larger units owing
to decreased usage of environmental controls and decreased com-
bustion efficiency.
Air emissions from coal combustion are controlled by a high
efficiency electrostatic precipitator and are discharged through
a 3-5 TTl Rrar'k' T1!-!/^ r-,^-*-v» —£ j_i r-t . . . c..-*-naC<2
- '—--^ f j-c^j-fj-u-ctuur ana are aiscnarqeu
t ^m ?cn * The ?ath of the flue 9as flow is from the furna
to the ESP, to an air preheater, to the stack. The boiler is
fired with a low-sulfur Appalachian bituminous coal. Ultimate
and trace element analysis conducted on coal samples obtained
during the sampling period are shown in Table C-l.
At the site sampled, there are additional pulverized coal f*
boilers sharing the auxiliary equipment necessary for pulver
coal usage and resulting in a total capacity above the given
1 niAjoY- 1 i mi -H .
146
-------
TABLE C-l. ANALYSIS OF COAL FIRED IN BOILER SAMPLED
Analysis
Moisture
Ash .
Heating value
Carbon
Nitrogen
Hydrogen
Sulfur
Sulfate
Elements :
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Unit
%
%
MJ/kg
%
%
%
%
%
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
Average
value3
8.4
8.2
28.78
71.6
1.6
5.0
0.91
0.09
5.8
0.016
0.0069
0.054
0.0044
0.013
0.0014
0.72
0.016
0.072
Analysis
Elements (cont'd)
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Vanadium
Zinc
Zirconium
Unit
*
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
g/kg of coal
Average
value3
0.044
1.8
0.012
0.32
0.013
0.0005
0.0085
0.0042
0.088
0.001
0.11
0.0062
0.34
0.068
0.02
0.37
0.078
0.019
Average of two to three analyses on each of three samples.
On as-received basis.
"Not detected.
-------
On-site water requirements are met using municipal drinking water
Daily wastewater streams result from boiler blowdown, feedwater
treatment using ion exchange, and once-through cooling water for
fan bearings. Fly ash from the ESP is pneumatically conveyed to
a hopper by a vacuum created by condensing steam. The resultant
wastewater discharge consists of the condensate and any material
picked up or leached from contacting the fly ash. Fireside and
waterside boiler cleaning, which result in an additional waste-
water stream, are performed once each year. All wastewaters are
discharged to a municipal sewer.
The bottom ash and precipitation ash are both handled dry, and
they constitute the only source of solid waste. Air emissions
from ash handling are controlled by wetting the ash prior to its
transport to a landfill site.
AIR SAMPLING PROCEDURE
Air emissions from the inlet and outlet ducts of the ESP were
sampled for particulate loading, particulate size, PCB, POM,
carbon monoxide, hydrocarbons, sulfur oxides, particulate sulfat,
and trace metals.
Particulate mass emission rates were determined using the EPA
Method 5 procedure (138) . Each duct was sampled at 33 points on
three levels. Samples were collected isokinetically for five
minutes at each point. Before each run, the sampling train was,
checked for leaks by plugging the inlet to the filter holder an
pulling a vacuum. A leakage rate of less than 9.4 x 10-6 m3/s
at a vacuum of 50.8 kPa was considered acceptable. After each
run, the probe and nozzle were handled in accordance with
appropriate sample recovery procedures .
Particle size data and samples for PCB, POM, and elemental
ses were collected using a Source Assessment Sampling System
(SASS) train. This train, depicted in Figure C-l, employs a s&
of three cyclones for particulate size fractionation, a solid
sorbent trap utilizing XAD-2 resin for organic collection, an
impinger collection trap for trace inorganics, and a system f°rf
flow measurement and gas pumping (139). The impinger portion o
the train consists of four impingers whose order, contents,
purpose are shown in Table C-2 (139). The sampling and ana
(138) Method 5 - Determination of Particulate Emissions from
tionary Sources. Federal Register, 41 (111) : 23076-23083,
1976.
(139) Hamersma, J. w. , s. L. Reynolds, and R. F. Maddalone. IE
RTP Procedure Manual: Level I Environmental Assessment.
EPA-600/2-76-160a (PB 257 850), U.S. Environmental Protec
tion Agency, Research Triangle Park, North Carolina,
June 1976. 131 pp.
148
-------
.K T.C.
HEATER
CON-
TROLLER
SS PROBE
i h
CONVECTION
OVEN
FILTER
GAS COOLER
VO
I £&L
DRY GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
XAD-2
CARTRIDGE
IMP/COOLER
TRACE ELEMENT
COLLECTOR
CONDENSATE
COLLECTOR
10 CFM VACUUM PUMP
Figure C-l. Source Assessment Sampling System train (139).
-------
procedures used on this project, as described in Reference 139
have since been modified (140).
TABLE C-2. SASS TRAIN IMPINGER SYSTEM REAGENTS (139)
Impinger
Reagent
Quantity
Purpose
6M H202
0.2M (NH<,)2S20B
+ 0.02M AgN03
0.2M
+ 0.02M AgN03
750 ml
750 ml
750 ml
Drierite 750 g
(color indicating)
Trap reducing gases such as
S02 to prevent depletion
of oxidative capability
of trace-element collec-
tion impingers 2 and 3.
Collect volatile trace
elements by oxidative
dissolution.
Collect volatile trace
elements by oxidative
dissolution.
Prevent moisture from
reaching pumps.
Prior to operating the SASS train, a velocity traverse and
ture determination were completed at each sampling location
EPA Method 2 (141) and Method 4 (142) . These methods were
employed to determine the point of average velocity and to char-
acterize the source to an extent sufficient for operating the
sampling system as close to isokinetic conditions as possible
within the available nozzle sizes and operating parameters.
Preparation and operation of the SASS train was conducted as
lined in the IERL-RTP Procedures Manual (139). In brief, the
presampling cleaning included passivation of all sample surfa
with aqueous nitric acid (50% by volume). All samples asat
with the collection of organics were subsequently cleaned
(140) Lentzen, D. E., D. E. Wagoner, E. D. Estes, and W. F.
Gutknecht. IERL-RTP Procedures Manual: Level 1 Environ ^
mental Assessment (Second Edition). EPA-600/7-78-201, u*
Environmental Protection Agency, Research Triangle ParK,
North Carolina, October 1978. 279 pp.
(141) Method 2 - Determination of Stack Gas Velocity and Volu*
metric Flow Rate (Type S Pitot Tube). Federal Register/
41(111):23063-23069, 1976.
(142) Method 4 - Determination of Moisture in Stack Gases. Fe
eral Register, 41(111):23072-23076, 1976.
150
-------
distilled water, isopropyl alcohol, and methylene chloride, in
succession. The impinger portion, used for inorganic collection,
was cleaned with distilled water followed by isopropyl alcohol.
At the sampling site, the SASS train was assembled and checked
for leak after heating the oven to 205*0 while maintaining the
organic resin trap at 20°C. A leak rate of less than
2.36 x lO-s m3/s at 67.6 kPa was considered acceptable. Alter
Passing the Teak check! the probe tip was attached the fingers
were filled, and sampling was begun using a «£e ofl. * * !°
to 2.4 x 10-3 mVs at the dry test meter. Each SASS train run
was conducted for a period in excess of five hours in order to
collect approximately 30 m» . Cleanup procedures used after each
run were those specified in the procedures manual (139) and shown
graphically in Figures C-2 through C-4.
Sulfur dioxide, sulfur trioxide (acid mist) , ^particulate
aulfate emissions were measured using a Pr°c?dure based on EPA
Method 8 (143). The Method 8 train was modlf ^^/i^ween ithe
lection of particulate sulfate by inserting a filter Between the
Probe and the first impinger and maintaining it at a ^P^ature
S ^s^-c^rjt- Er F
- 5 h
in Method 8.
.
Carbon monoxide was determined by the direct analysis of the gas
stream using a Bendix tube calibrated for 0 PP» *> JO ppm of co.
Low-molecular-weight hydrocarbons d to Ca) were ^P1^ *>Y
Collecting integrated gas samples in Tedlar bags ^J^°aph
tents were then analyzed within 24 hours using gas ^romatograpn
^tegrated gas samples were also collected fo* ^bonjioxide,
e*cess air, and dry molecular weight determinations using EPA
Method 3 (144).
PROCEDURE FOR SAMPLING EFFLUENTS
S^pies of the wastewater streams from boiler blowdown, cooling
?* th^fSn bearing boiler feedwater treatment pneuma tic ash
transport steam wash, and the water source were composited
~<^T^ethod 8 - Determination of Sulfuric Acid Mist and Sulfur_
Dioxide Emissions from Stationary Sources. Federal Regls
ter, 41(111) -.23087-23090, 1976.
{144) Method 3 - Gas Analysis for Carbon Dioxide Oxygen Excess
Air, and Dry Molecular Weight. Federal Register, 41(111).
23069-23070, 1976.
151
-------
PROBE AND
NOZZLE
CH Cl • CH,OH
RINSE INTO AMBER
GLASS CONTAINER
ADD TO 10/<
CYCLONE RINSE
i
to
3 * CYCLONE
10 r CYCLONE
STEP1: TAP AND BRUSH
CONTENTS FROM WALLS
AND VANE INTO LOWER
CUP RECEPTACLE
STEP 2: RECONNECT LOWER CUP
DC/-CDTA/-I f Akin PIK19F ADHERED
MATERIAL ON WALLS AND VANE
INTO CUP (CH2CI2 : CH3OH)
REMOVE LOWER CUP
RECEPTACLE AND
TRANSFER CONTENTS
INTO A TARED NALGENE
CONTAINER
REMOVE LOWER CUP RECEPTACLE
A Kin TPAKKFFR fCH Cl • CH«OH)
INTO PROBE RINSE CONTAINER
KOMI
i
STEP 1: TAP AND BRUSH CON-
TENTS FROM WALLS INTO
LOWER CUP RECEPTACLE
STEP 2: RECONNECT LOWER CUP
RECEPTACLE AND RINSE ADHERED
MATERIAL WITH CH-CU: CH.jOH
INTO CUP
STEP 3: RINSE WITH CH2CI2:CH3OH
INTERCONNECT TUBING JOINING
10,4 TO 3M INTO ABOVE CONTAINER
REMOVE LOWER CUP RECEP-
TACLE AND TRANSFER CON-
TENTS INTO A TARED NAL-
GENE CONTAINER
REMOVE LOWER CUP RECEPTACLE
AND TRANSFER CONTENTS INTO
AN AMBER GLASS CONTAINER
COMBINE
ALL RINSES
FOR SHIPPING
AND ANALYSI
Figure C-2. Sample handling and transfer: nozzle, probe, cyclones, and filter (139)
-------
1 M CYCLONE
STEP I: TAP AND BRUSH
CONTENTS FROM WALLS
INTO LOWER CUP RECEP-
TACLE
STEP 2: RECONNECT LOWER CUP
RECEPTACLE AND RINSE ADHERED
MATERIAL WITH CH9CL:CH,OH
INTO CUP 223
STEP 3: RINSE WITH CH2CI2:CH3OH
INTERCONNECT TUBING JOINING
3i-TO IM INTO ABOVE CONTAINER
REMOVE LOWER CUP RECEPTACLE
AND TRANSFER CONTENTS INTO
A TARED NALGENE CONTAINER
REMOVE LOWER CUP RECEPTACLE
AND TRANSFER CONTENTS INTO
AN AMBER GLASS CONTAINER
FILTER
HOUSING
STEP1: REMOVE FILTER AND
SEAL IN TARED PETRI DISH
STEP 2: BRUSH PARTICULATE FROM
BOTH HOUSING HALVES INTO A
TARED NALGENE CONTAINER
NOTES: ALLCH2CI2:CH3OH
MIXTURES ARE 1:1
ALL BRUSHES MUST HAVE
NYLON BRISTLES
ALL NALGENE CONTAINERS
MUST BE HIGH DENSITY
POLYETHYLENE
STEP 3: WITH CH2CI2:CH3OH
RINSE ADHERED PARTICULATE
INTO AMBER GLASS CONTAINER
STEP 4: WITH CH2CI2:CH3OH
RINSE INTERCONNECT TUBE
JOINING IM TO HOUSING
INTO ABOVE CONTAINER
Figure C-2. (continued) (139).
-------
STEP NO. 1
COMPLETE XAD-2 MODULE
AFTER SAMPLING RUN
STEP NO. 2
RELEASE CLAMP JOINING XAD-2
CARTRIDGE SECTION TO THE UPPER
GAS CONDITIONING SECTION
REMOVE XAD-2 CARTRIDGE FROM
CARTRIDGE HOLDER. REMOVE FINE
MESH SCREEN FROM TOP OF CART-
RIDGE. EMPTY RESIN INTO WIDE
MOUTH GLASS AMBER JAR
REPLACE SCREEN ON CARTRIDGE, RE-
INSERT CARTRIDGE INTO MODULE.
JOIN MODULE BACK TOGETHER.
REPLACE CLAMP.
OPEN CONDENSATE RESERVOIR
VALVE AND DRAIN AQUEOUS
CONDENSATE INTO A 1 LITER
SEPARATORY FUNNEL. EXTRACT
WITH CH2CI2.
AQUEOUS PHASE
ORGANIC PHASE
BASIFY ONE HALF
= PH12
ACIDIFY ONE HALF
PH LESS THAN 2
CLOSE CONDENSATE RESERVOIR VAiV^
I
RELEASE UPPER CLAMP AND
LIFT OUT INNER WELL
WITH GOTH UN1TIZED WASH BOTTLE
(CH2CI2:CH3OH) RINSE INNER WELL
SURFACE INTO AND ALONG CON-
DENSER WALL SO THAT RINSE RUNS
DOWN THROUGH THE MODULE AND
INTO '-'"'Mr.cKicATt rni LECTOR _
I
WHEN INNER WELL IS CLEAN,
PLACE TO ONE SIDE
RINSt ENTRANCE TUBt
INTERIOR. RINSE DOWN THE CONDEN
SER WALL AND ALLOW SOLVENT TO
FLOW DOWN THROUGH THE SYSTEM
AND COLLECT IN CONDENSATE CUP
RELEASE CENTRAL CLAMP AND
SEPARATE THE LOWER SECTION
(XAD-2 AND CONDENSATE CUP)
FROM THE UPPER SECTION (CON-
DENSER)
THE ENTIRE UPPER SECTION l>
CLEAN.
RINSE'THE NOWEMPTY XAD-Z SEC-
TION INTO THE ^kinFMSATE CUP.
RELEASE LOWER CLAMP AND
REMOVE CARTRIDGE SECTION
ROM CONDENSATE
THE CONDENSATE RESHVOW NOW
CONTAINS ALL RINSESI FROM 1W
ENTIRE SYSTEM. DRAIN IN°
AMBER HQTTLE VIA DRAIN
Figure C-3. Sampling handling and transfer: XAD-2 module (I39'
154
-------
ADD RINSE FROM
CONNECTING LINE
LEADING FROMXAD-2
MOD TO FIRST IMPINGER
IMPINGER NO. 1
TRANSFER TO
NALGENE
CONTAINER
RINSE WITH 1:11 PA/
DIST. H2OAND ADD
_ J
IMPINGER NO. 2
TRANSFER TO
NALGENE
CONTAINER
RINSE WITH 1:1 IPA/
DIST. H2OAND ADD
IMPINGER NO. 3
TRANSFER TO
NALGENE
CONTAINER
RINSE WITH 1:1 IPA/
DIST. H«OAND ADD
IMPINGER NO. 4
DRIERITE
DISCARD
DETERMINE
S04 CONTENT
COMBINE AND
MEASURE TOTAL
VOLUME FOR
SINGLE ANALYSIS
Figure C-4. Sample handling and transfer: impingers (139)
155
-------
hourly basis for eight hours. Table C-3 provides information on
the bottles, preservatives, and sample volumes used in sampling
each stream.
PROCEDURE FOR SAMPLING SOLIDS
Bottom ash and precipitator ash samples were collected and com-
posited according to the procedure provided for fly ash sampling
in ASTM C 311-68 (145). Three samples of the coal feed were
obtained employing the procedure given in ASTM D 2234-72,
"Collection of a Gross Sample of Coal" (146).
ANALYTICAL PROCEDURES
Field samples which required laboratory analysis include those
from the EPA Method 5 train for particulate loading; the SASS
train for particle sizing, organic analysis (hydrocarbons greate
than C7, POM, and PCB), and trace element analysis; the modified
EPA Method 8 train for sulfur dioxide, sulfur trioxide, and
particulate sulfate; the integrated gas samples for Ci to Ce
hydrocarbons; and the wastewater, fly ash, and coal samples for
a variety of analyses. Handling and analytical procedures used
for these samples are described below; however, descriptions of
the procedures used for the organic and elemental analyses are
deferred until the end of this appendix because they involve air*
water, and solid samples.
Particulate Loading
Particulate loading was determined using the procedure described
in EPA Method 5 (138).
SASS Train Samples
The separation and analysis of the SASS train samples is depicte
in Figure C-5 and, in general, follows the methods employed for
Level I type analysis. These methods are briefly outlined below-
The procedures described here have since been modified, as noted
in Reference 140.
(145) Standard Methods of Sampling and Testing Fly Ash for Use
as an Admixture in Portland Cement Concrete, Designation
C 311-68. In: 1972 Annual Book of ASTM Standards,
Part 10: Concrete and Mineral Aggregates. American
Society for Testing and Materials, Philadelphia,
Pennsylvania, 1972. pp. 220-226.
(146) Standards Methods of Collection of a Gross Sample of Coal/
Designation D 2234-72. In: 1973 Annual Book of ASTM
Standards, Part 19: Gaseous Fuels; Coal and Coke.
American Society for Testing and Materials, Philadelphia'
Pennsylvania, 1973. pp. 355-371.
156
-------
01
TABLE C-3. BASIC INFORMATION FOR PREPARATION OF 8-HOUR COMPOSITE
SAMPLES OF WATER AND WASTEWATER STREAMS
Analysis to be performed:
Type of sample bottle:
Hourly period:
1
2
3
4
5
6
7
8
PCB;
POM
1 gal glass
add 470 ml
add 470 ml
add 470 ml
add 470 ml
add 470 ml
add 470 ml
add 470 ml
add 470 ml
seal
Trace elements
1/2 gal plastic
Sample size
add 240 ml
add 5 ml HNO3
add 240 ml
add 240 ml
add 240 ml
add 5 ml HNO3
add 240 ml
add 240 ml
add 240 ml
add 240 ml
seal
NH3;
COD;
NO3
TSS
TDS
TS
1/2 gal plastic 1/2 gal plastic
to be taken and
add 240 ml3
HzSOjt , pH<
add 240 ml
H2SOi», pH<2
add 240 ml
H2SO«, pH<2
add 240 ml
H2SO4, pH<2
add 240 ml
H2SO*i , pM<2
add 240 ml
H2SO£» , pH<2
add 240 ml
H2SOti , pH<2
add 240 ml
HaSOi,, pH<2
seal
preservatives to be
add 240 ml
add 240 ml
add 240 ml
add 240 ml
add 240 ml
add 240 ml
add 240 ml
add 240 ml
seal
Phenol
500 ml glass
added
add 62 ml
pH<4 w/H3POt»
add 62 ml
add 0.5g CuSO<»
add 62 ml
add 62 ml
pH<4 w/H3POi,
add 62 ml
add 62 ml
add 62 ml
add 62 ml
pH<4 w/H3POj»
seal
Sulfite
500 ml glass
add 62 ml
add 62 ml
add 62 ml
add 62 ml
add 62 ml
add 62 ml
add 62 ml
add 62 ml
seal
must be added to adjust the pH to a value <2.
-------
01
CO
— 1
H1HOCMI
1
WS
r1
»«i
— »
S«.*l 1*1
\
MUK
IWUSli
MTMOCIMIHS
Figure C-5. Separation and analysis scneme: SASS train samples.
-------
Cyclone Collected Material —
Cyclone materials were weighed separately to provide particulate
size data. After weighing, the cyclone contents were combined
into one sample and extracted for 24 hours with methylene chlo-
ride. This is a deviation from the Level I procedure in which a
portion is removed prior to extraction for trace element analysis
After extraction, the residue (unextractables) in the thimble was
reweighed and then digested for trace element analysis. For
this type sample, the solid was digested in a HNO3-perchloric
acid medium because fly ash is difficult to digest using the
normal Parr bomb technique. The volume of the liquid from the
Soxhlet extraction was measured and the liquid was combined with
the extracted portions of the filter.
Probe and Cyclone Washes —
The methylene chloride-methanol washings of the probe, cyclones,
and filter holder were evaporated to dryness and weighed. The
dry material was then dissolved in methylene chloride and trans-
ferred quantitatively to the Soxhlet extraction apparatus along
with the cyclone collected material.
Filter—
The filter from the SASS train was dried and weighed, and the
weight was combined with the cyclone collection and washing from
the "front" portion of the train. The filter was then Soxhlet
extracted for 24 hours with methylene chloride. The filter was
dried and weighed, and the volume of the extraction solution was
measured. This solution was combined with the cyclone extraction
solution, and a 1-ml to 10-ml portion was withdrawn for GC
analysis of C7 to Cie hydrocarbons. The remaining solution was
combined with the XAD-2 resin extract and the organic washing
°f the XAD-2 resin trap. The filter and nonextractable residue
were digested using Parr bomb and HN03-perchloric acid digestion.
The resulting solution was separated from the filter remains and
combined with the solution from the cyclone material digestion.
XAD— 2 Resin __
TnTlresin was stirred to mix the sample thoroughly, and a 2-gram
Portion was removed and digested in the Parr bomb with nitric
acid. Digested materials were diluted to a known volume and
divided for the various trace element analyses. Remaining XAD-2
resin (about 250 grams) was Soxhlet extracted for 24 hours with
Pentane. The volume was measured and a 1-ml to 10-ml portion
was withdrawn for GC analysis of the C7 to Cie hydrocarbons.
Remaining solution was combined with the methylene chloride
extraction material from the cyclones and filters, and the
organic wash from the resin trap.
Impinger Contents. XAD-2 Trap Organic Wash, and Aqueous
Condensate — , .J_. .,
s condensate from the resin trap was extracted with meth-
chloride, and the organic portion was combined with the
159
-------
methylene chloride wash of the trap. The volume was measured
and a 1-ml to 10-ml aliquot was removed for GC analysis of the
C7 to Cie hydrocarbons. The remaining solution was combined
with the XAD-2 resin, filter, and particulate extracts prior to
volume reduction and liquid chromatography fractionation. Re-
maining aqueous layers were combined with the liquid from the
first impinger, and the solution was acidified and divided for
trace element analysis.
Second and Third Impingers—
Contents of the second and third impingers were acidified and
analyzed using atomic absorption for mercury, antimony, arsenic,
selenium, beryllium, and zirconium.
Sulfur Oxides, Sulfuric Acid and Particulate Sulfate—
Samples for sulfur analysis, collected by the modified Method 8
sampling system, consist of the particulate filter, the first
impinger (isopropanol), the filter between the impingers, and
the second and third impingers (hydrogen peroxide). procedures
described in Method 8 were employed for the analysis of the
impingers and the filter between impingers; that is, titration
with barium perchlorate using Thorin indicator (143). Analysis
of the particulate filter required digestion of the material on
the filter using a combination of nitric and perchloric acids
in order to oxidize and dissolve the fly ash. Following di-
gestion, the sample was analyzed for sulfate content using a
gravimetric procedure involving barium nitrate to precipitate
the sulfate as barium sulfate.
C-i to C6 Hydrocarbons
Gaseous hydrocarbons in the Ci to C6 range were analyzed by 9aS
chromatography using a flame ionization detector (FID). A stal"
less steel column, packed with Poropak Q and operated isothermal
ly at 50°C, was used for the separation.
Determination of Water Quality Parameters
Laboratory determination of water quality parameters followed the
methods outlined in the APHA Standard Methods (147) with the
exception of ammonia, which was determined by an ion-selective
electrode method. Table C-4 lists the analyses, the method
selected, and the page number on which if may be found in the
reference cited.
(147) Standard Methods for the Examination of Water and Waste-
water, 13th Edition; M. J. Taras, A. E. Greenberg, R- D".
Doak, and M. C. Rand, eds. American Public Health Associ-
ation, New York, New York, 1971. 874 pp.
160
-------
TABLE C-4. METHODS FOR WATER QUALITY ANALYSIS (147)
Page no.
Parameter Method no. in Ref. 147
Acidity 101 50-52
Alkalinity 102 52-56
Hardness 122A 179
COD 220 495-499
pH 144A 276-280
Nitrate 133A 234-237
Total solids 224A and B 535-536
Total dissolved solids 224E 539
Total suspended solids 224C 537-538
Oil and grease 137 254-256
Sulfate 156 330-333
Sulfite 158 337-338
goal Samples
Three samples of the coal feed were analyzed for moisture content,
ash, heating value, carbon-hydrogen-nitrogen content, sulfur, sul-
fate and trace metals. These analyses were conducted employing
ASTM standard methods (148, 149). Trace metal analyses were
conducted after acid digestion employing the Parr 4745 Teflon-
lined bomb technique.
Samples
Samples of bottom ash and precipitator ash were composited and
artificially leached with distilled deionized water by shaking
the ash-water mixture for one week. The leachate was then
separated using filtration and analyzed for organics and trace
elements. Samples of both ashes were also digested separately
analyzed for trace metals.
(148) Standard Method of Test for Proximate Analysis of Coal and
Coke, Designation D 3172-73. In: 1973 Annual Book of ASTM
Standards, Part 19: Gaseous Fuels; Coal and Coke.
American Society for Testing and Materials, Philadelphia,
Pennsylvania, 1973. p. 434.
) Standard Method of Test for Forms of Sulfur in Coal,
Designation D 2492-68. In: 1973 Annual Book of ASTM
Standards, Part 19: Gaseous Fuels; Coal and Coke.
American Society for Testing and Materials, Philadelphia,
Pennsylvania, 1973. pp. 380-384.
161
-------
Trace Organic Analysis
Trace organic analysis was conducted on pentane extractions of
the water and leachate samples and on the organic components
from the SASS collection/ which were contained in the pentane
extractions of the cyclone and filter catch, the pentane extract
of the XAD-2 resin trap, and in the solid residue from the probe
washes. Portions of the pentane extracts were analyzed for
low-molecular-weight (C? to Cia) organic compounds with a flame
ionization gas chromatograph using a 1.5% OV-101 on Gas Chrom Q
100/120 mesh (3 mm x 1.8 m) stainless steel column. Following
chroma tography, the liquids were evaporated to ^2.5 x 10~5 m3
(^25 ml) using rotary evaporation. The residue from the probe
wash was dissolved in 2.5 x 10"5 m3 (25 ml) of pentane.
Following volume reduction, the samples were separated into
eight fractions, using the solvent systems shown in Figure C-6»
on a silica gel column. Each fraction was then reduced in vol-
ume using a Kuderna-Danish evaporator and transferred to a tare-
weighted, micro-weighing pan; the remaining solvent was
evaporated in air. Each dried fraction was weighed and then
redissolved in a minimum quantity of methylene chloride.
The second, third and fourth fractions (containing the POM and
PCB components) were combined and transferred to a Viton-septum
sealed vial which was covered with aluminum foil and refriger-
ated until required for analysis. Just prior to analysis, the
sample underwent one more volume reduction via the Kuderna-DaniS
method. The final volume was approximately 5 x 10~7 m3 (500 pi' •
This volume size has been found to be optimum for detecting the
POM peaks without them being obscured by the contamination peaKS-
POM Analysis Procedure —
The method used for POM analysis employs a peak-area quantitati°n
technique with computer reconstructed chromatograms from the
(HP 5982-A) gas chromatograph - mass spectrograph (GC-MS) . AlJ
data were collected in the electron impact (El) mode because or
the abundance of available El-mass spectra.
The gas chromatographic separation was achieved using a I-8"1"
Dexsil 400 glass column with temperature programming from 160 c
for 2 min, rising to 280°C at 8°c/min, and becoming isothermal
at 280°C. Helium, at a flow rate of 0.5 x lO"9 m/s (30 yl/m*n' '
was used as carrie
,
was used as carrier gas.
The mass spectrometer, operating in the electron impact mode, *a*
programmed to scan the 75-350 AMU range as the POM components
eluted from the gas chromatograph. The data system reconstructs
the chroma togram using the total ion mode. POM's were located °*
their molecular mass ions which are displayed using the selected
ion mode (SIM) . Their identity was confirmed by examination °£
their mass spectra and retention times.
162
-------
JANE
»»M£THVLENE
CHLORIDE IN
PENTANE
M*METHYIENE
CHLORIDE IN
PINT AM
METHYIENE
CHLORIDE
JtMCTHYL
AlCOMOttN
MCTHYLENC
CHLORIDE
20* METHYL
UCOHOl IN
MDHYLENE
CHLORIDE
50* METHYL
ALCOHOL IN
METHYLfW
CHLORIDE
1
MCI. C
CHjCljl 5
1
-------
Calibration curves were prepared for each POM of interest using
varying concentrations of the POM standards in methylene chloride,
plotting mass ion peak area vs. concentration, and determining
response factors. POM peaks in samples were compared with stan-
dard curves that have been obtained under the same conditions,
attenuation, injection volume (2 x 10~9 m3 or 2 yl) , and tuning
condition. Calibrations were made on the same day that the
samples were analyzed.
PCB Analysis Procedure —
The GC-MS technique was used for the analysis of PCB compounds.
Concentrated solutions from the second, third and fourth frac-
tions from the silica gel separations were examined. Samples
were injected into the GC and separated on a 3% Dexsil 400 column
operated isothermally at 250°C for SIM or 280°C SMS modes. Mass
spectra were obtained in the electron impact mode because the
fragmentations of a number of isomeric mono-, di-, tri-, tetra-,
bena-, octa- and decachloro-biphenyl has been studied in detail
using this procedure. Quantification of the data was performed
using standards of the various chlorinated biphenyls in methylene
chloride.
Trace Elmenent Analyses
The Jarrell-Ash Plasma Atomcomp (ICAP) and atomic absorption
methods were used for trace element analysis of the collected
samples.
Jarrell-Ash Plasma Atomcomp Analysis —
The Jarrell-Ash Plasma Atomcomp technique was used at the
Physical Science Center of Monsanto Company in St. Louis for the
analysis of aluminum, antimony, barium, boron, cadmium, calcium,
chromium, cobalt, copper, iron, lead, magnesium, manganese,
molybdenum, nickel, phosphorus, silicon, silver, sodium, tin,
strontium, titanium, vanadium and zinc. The Atomcomp employs an
inductively coupled argon plasma (ICAP) as an excitation source
to produce atomic emission which is relatively free of
J- JitS JL J. 6 JT SiiCG S *
Atomic Absorption Analysis —
Atomic absorption was employed to analyze for mercury, arsenic,
selenium, antimony, beryllium and zirconium. Mercury was analyzed
r^!£Ji J«C2i Va?°^ techni<3ue ^ which all of the mercury is
reduced to the metallic state with SnCl2 and then swept into the
anMmonvTtte f°? ** •"***!• ^0). Arsenic selenium and
antimony were analyzed via the hydride generation technique
(150) S^u?r' C- R" T^ter Analysis by Atomic Absorption. Varian
LE-ip?Prln*Vft1'' Victoria, Australia,
164
-------
developed and refined by Fernandez (151) and more recently by
Brodie (152). An aqueous solution was first reacted with a
reducing agent (e.g., potassium iodide), then the corresponding
gaseous hydride was generated with sodium borohydride which was
immediately swept into a nitrogen-hydrogen entrained-air flame
for analysis.
Beryllium and zirconium were analyzed using conventional air-
acetylene flame atomic absorption methods.
(151) Fernandez, F. G. Atomic Absorption Determination of Gaseous
Hydrides Utilizing Sodium Borohydride Reduction. Atomic
Absorption Newsletter, 12(4):93-97, 1973.
(152) Brodie, K. G. Determining Arsenic and Selenium by AAS.
American Laboratory, 9(3):73-79, 1977.
165
-------
APPENDIX D
DERIVATION OF SOURCE SEVERITY EQUATIONS
SUMMARY OF SEVERITY EQUATIONS FOR AIR POLLUTANTS
The severity (S) of pollutants may be calculated using the mass
emission rate (Q) , the height of the emissions (H) , and the
threshold limit value (TLV) (for noncriteria pollutants) (64).
The equations summarized in Table D-l are developed in detail in
this appendix.
TABLE D-l. POLLUTANT SEVERITY EQUATIONS
FOR ELEVATED POINT SOURCES
Pollutants Severity equation
Particulate
S = 70
P ~
SO
sso, • ^
NO
q - 315 Q
NOX H2•i
Hydrocarbon
162
CO
c _ 0.78 Q
CO ifa
Other
S =
A
A TLV»H2
DERIVATION OF Xmax FOR USE WITH U.S. AVERAGE CONDITIONS
The most widely accepted formula for predicting downwind ground
level concentrations from a point source is (60).
X =
Q
exp
1
2
exp
(D-D
166
-------
where x = downwind ground level concentration at reference
coordinate x and y with emission height of H, g/m3
Q = mass emission rate, g/s
IT = 3.14
a = standard deviation of horizontal dispersion, m
a = standard deviation of vertical dispersion, m
z
u = wind speed, m/s
y = horizontal distance from centerline of dispersion, m
H = height of emission release, m
x = downwind dispersion distance from source of emission
release, m
We assume that Xmax occurs when x is much greater than 0 and y
equals 0. For a given stability class, standard deviations of
horizontal and vertical dispersion have often been expressed as
a function of downwind distance by power law relationships as
follows (153):
cry = ax
(D-2)
az = ex
+ f
(D-3)
Values for a, b, c, d, and f are given in Tables D-2 (154) and
D-3. Substituting these general equations into Equation D-l
yields
X =
Q
b+d , ,. b
acTrux + airufx
exp
H2
. 2 (ex + f)2_
(D-4)
Assuming that Xmax occurs at x less than 100 m and the stability
class is C, then f equals 0 and Equation D-4 becomes
x = b+d
aCTTUX
exp
r
L
2c2x2d
(D-5)
For convenience, let
AR = Ic^I and BR = 553-
(153) Martin, D. O., and J. A. Tikvart. A General Atmospheric
Diffusion Model for Estimating the Effects on Air Quality
of One or More Sources.. Presented at the 61st Annual
Meeting of the Air Pollution Control Association, St. Paul,
Minnesota, June 23-27, 1968. 18 pp.
(154) Eimutis, E. C., and M. G. Konicek. Derivations of Continu-
ous Functions for the Lateral and Vertical Atmospheric
Dispersion Coefficients. Atmospheric Environment, 3(6):
688-689, 1969.
167
-------
TABLE D-2.
VALUES OF a FOR
THE COMPUTATION
OF a a (155)
A
B
C
D
E
F
0.3658
0.2751
0.2089
0.1471
0.1046
0.0722
a ~
For Equation D-2:
where
ax'
x
b
downwind distance
0.9031 (from
Reference 155)
TABLE D-3.
VALUES OF THE CONSTANTS USED TO
ESTIMATE VERTICAL DISPERSION3 (153)
>1,000
100 to 1,000
<100
For Equation D-3:
A
B
C
D
E
F
A
B
C
D
E
F
A
B
C
D
E
F
•• •
——•—•••^
o •
0.00024
0.055
0.113
1.26
6.73
18.05
C2
0.0015
0.028
0.113
0.222
0.211
0.086
C3
0.192
0.156
0.116
0.079
0.063
0.053
— — — . ___ _
2.094
1.098
0.911
0.516
0.305
0.18
d2
1.941
1.149
0.911
0.725
0.678
0.74
d3
0.936
0.922
0.905
0.881
0.871
0.814
-9.6
2.0
0.0
-13
.-34
-48.6
fz
9.27
3.3
0.0
-1.7
-1.3
-0.35
f 3
0
0
0
0
0
0
va
Diffusion
Diffusion.
n Expressions for the
Atmo^nh »ls*ersi°« Coefficients in Atmospheric
Atmospheric Environment, 3 (6) : 688-689, 1969.
168
-------
so that Equation D-5 reduces to
y = A x
X AX
-(b+d)
exp
R
(D-6)
Taking the first derivative of Equation D-6
-h-d/ f -2d~lV -2d-i\
cbd(exp|BRx JJ(-2dBRx )
+ exp[BRx~2d](-b-d)
- = A
x
-b-d-i
(D-7)
and setting this equal to zero (to determine the roots which give
the minimum and maximum conditions of x with respect to x) yields
= ARX
-b-d-i
-2d
explBDx
^ ,_ J
-2dBDx -b-d
K
(D-8)
Since we define that x * 0 or «> at Xmax, the following expression
must be equal to 0.
or
-ad
-2dBDx -d-b = 0
K.
(b+d)xad = -2dB.
or
-2dB
T,
R
2dH2
b+d 2c2(b+d)
or
x
C2(b+d)
Hence
/2d
at
""-
* ~ Ic2(b+d)
\ >
Thus Equations D-2 and D-3 (at f = 0) become
/ , 2 \b
a = af—
y \c
(D-9)
(D-10)
(D-ll)
(D-12)
(D-13)
(D-14)
169
-------
', • cb*&|d/3d • f") '
-------
For U.S. average conditions, u equals 4.47 m/s so that
Equation D-20 reduces to
_ 0.0524 Q (D_2i)
xmax H2
DEVELOPMENT OF SOURCE SEVERITY EQUATIONS
Source severity, S, has been defined as follows:
_ Xmax (D-22)
b F
where x = time-averaged maximum ground level concentration
^F = hazard factor; for criteria pollutants, F = AAQS;
for noncriteria pollutants, F = TLV • 8/24 • 1/100.
Noncriteria Emissions
The value of Xmax may be derived from Xmax, and undefined "short-
term" concentration. An approximation for longer term concen-
tration may be made as follows:
For a 24-hr time period,
/t \°-17
Y = Y — {D~23)
Amax Amax \t /
where t = instantaneous (i.e., 3-min) averaging time
t = averaging time period used (i.e., 24 hr or 1,440 min)
Hence
/ \°* 17
- = Y f 3 min (D-24)
xmax Amax \ 1,4 40 mm/
y = y (0.35) (D-25)
Amax
Since the hazard factor is defined and derived from TLV values as
follows:
F = (TLV) (£)(Tij) (D-26)
F = (3.33 x 10-3) TLV (D-27)
then the severity factor, Sa, is defined as
V 0 35 Y
S = Xmax = ma* (D-28)
ba F (3.33 x 1Q-3) TLV
171
-------
"a TLV
If a weekly averaging period is used, then
(D_29)
l
or
and
/ T \o. 17
= Y f £_ (D-30)
max Amax \10,080/
X = 0.25 y (D-31)
Amax Amax
F = (2.38 x 10-3JTLV (D-33)
and the severity factor, S , is
a
7 0.25 x
S = max _ Amax (D-34)
a F (2.38 x 10~3)TLV
or
S Xmax (D-35)
a TLV
which is entirely consistent, since the TLV is being corrected
for a different exposure period.
Therefore, the severity can be derived from Xmax directly without
regard to averaging time for noncriteria emissions. Thus, com-
bining Equations D-35 and D-21, for elevated sources, gives .
S = 5.5 Q m-36)
a TLV • H2
Criteria Emissions
For the criteria pollutants, established standards may be used
as F values in Equation D-22. These are given in Table D-4 (63).
However, Equation D-23 must be used to give the appropriate
averaging period. These equations are developed for elevated
sources using Equation D-21.
172
-------
TABLE D-4.
SUMMARY OF NATIONAL AMBIENT
AIR QUALITY STANDARDS (63)
Pollutant
Particulate matter
sov
X
CO
Nitrogen dioxide
Photochemical oxidants
Hydrocarbons (nonmethane)
Averaging time
Annual (geometric mean)
24-hrb
Annual (arithmetic mean)
24-hrb
3-hrb
8-hrL
l-hrb
Annual (arithmetic mean)
l-hrb
3-hr (6 a.m. to 9 a.m.)
Primary
standards,
pg/m3
75
260
80
365.
a
10,000
40,000
100
160
160e
Secondary
standards ,
pg/m3
60a
160
60c
260C
1,300
10,000
40,000
100
160
160
*The secondary annual standard (60 pg/m3) is a guide for assessing implementa-
tion plans to achieve the 24-hr secondary standard.
Not to be exceeded more than once per year.
GThe secondary annual standard (260 pg/m3) is a guide for assessing implementa-
tion plans to achieve the annual standard.
No standard exists.
eThere is no primary ambient air quality standard for hydrocarbons. The value
of 160 pg/m3 used for hydrocarbons in this report is an EPA-recommended guide-
line for meeting the primary ambient air quality standard for oxidants.
Carbon Monoxide Severity—
The primary standard for CO is reported for a 1-hr averaging
time. Therefore
t = 60 min
t = 3 min
o
60
0.17
(D-37)
•nreuH2 \60
0.17
(D-38)
2 0
(3.14) (2.72) (4.5)H2
0.6
(D-39)
X
max
(D-40)
(3.12 x 10-2)Q
H2
(D-41)
173
-------
Severity, S = " (D-42)
Setting F equal to the primary AAQS for CO or 0.04 g/m3 yields
S
- Xmax = (3.12 x 10-a)Q m-43)
F 0.04 H2
or
S = °'78 Q (D-44)
CO H2 V
Hydrocarbon Severity—
The primary standard for nonmethane hydrocarbons is reported for
a 3-hr averaging time.
t = 180 min
tQ = 3 min
0.17
- °-5 X*. (D-46)
Amax v
= (0.5) (0.052)Q ,D_47)
H2 l
v = °-026 Q (D-48)
xmax H2 ^u
For nonmethane hydrocarbons, the concentraiton of 1.6 x 10~4
has been issued as a guideline for achieving oxidant standards
Therefore,
S = Xmax = 0.026 Q m-49)
F 1.6 x 10~4 H2
or
Particulate Severity — •
The primary standard for particulate is reported for a 24-hr
averaging time.
174
-------
.0.17
xmax ~ xmax \1,440
.(0.35)^0.052)0 (D.52)
X - - (D-53)
A 2
max
For particulates, F equals the primary AAQS or 2.6 x 10~4 g/m3 ,
and
_ Xmax _ 0.0182 Q (D-54)
b F (2.6 x 10-<*)H2
Sp = ^ (D-55)
SOX Severity —
The primary standard for SOX is reported for a 24-hr averaging
time. Using t = 1,440 minutes and proceeding as before:
- 0.0182 Q {D_56)
xmax H2
The primary AAQS for SOX is 3.65 x 10-* g/m3. Therefore,
c _ xmax _ 0.0182 Q (D-57)
b ~ ~F (3.65 x 10-*)H2
or
c = 50_Q (D-58)
SSOX
NQX Severity— . . _
Since NOX has a primary standard with a 1-yr averaging time, the
xmax correction equation cannot be used. As an alternative, the
following equation is used:
- = 2.03 Q ex
A a ux ^
z
1 /_H
2 a_
(D-59)
A difficulty arises, however, because a distance x, from emission
point to receptor, is included; hence, the following rationale is
Used:
= 2 Q (D-20)
ireuH2
175
-------
Equation D-20, shown earlier is valid for neutral conditions or
when a approximately equals a .
z y
This maximum occurs when
H = /2a
and since, under these conditions,
(D-60)
az = ax
(D-61)
then the distance, x , where the maximum concentration occurs
is max
x
(D-62)
For class C conditions, a = 0.113 and b = 0.911. Substituting
these values into Equation D-62 yields:
x
098
max 0.16
=7.5
Since
and
and letting x =
a = 0.113 x o.9ii
z max
u = 4.5 m/s
xmax' E
-------
As noted above,
a = 0.113 x°'911 (D-64)
z
Substituting for x yields
or
a = 0.113(7.5 H1-1)0'911 (D-68)
Z
a = 0.71 H (D-69)
Z
Therefore,
\ 2
_ 0.085 Q
xmax ~ H2-1 exp " 2 I 0.71
r. I/_JL
L 2\°-r-
H
(D-70)
= ^a"^ (0.371) (D-71)
- = 3.15 x 10-2 Q (D_72)
xmax H2-1 * '
Since the AAQS for NOX is 1.0 x IQ-1* g/m3, the NOX severity
equation is
c - (3.15 x 10-2)Q ' fn_7^
bNOx ~ 1 x 10-* H2-1 ^ '
S = 315 Q (D-74)
bNOx H2-1
AFFECTED POPULATION CALCULATION
Another form of the plume dispersion equation is needed to calcu-
late the affected population since the population is assumed to
be distributed uniformly around the source. If the wind direc-
tions are taken to 16 points and it is assumed that the wind
directions within each sector are distributed randomly over a
period of a month or a season, it can be assumed that the efflu-
ent is uniformly distributed in the horizontal within the sector.
The appropriate equation for average concentration, X, in grams
Per cubic meter is then (for 100 m < x < 1,000 m and stability
class C) (65):
X = 2'03 Q exp I- i (— ) I (D-75)
O UX ' ^ \ rr II
Z
177
-------
To find the distances at which x/AAQS equals 1.0, roots are
determined for the following equation:
2.03 Q
(AAQS)a ux
z
exp
I /_H
2 o_
= 1.0
(D-76)
keeping in mind that
a = ax + c
where a, b, and c are functions of atmospheric stability and are
assumed to be selected for stability Class C.
Since Equation D-76 is a transcendental equation, the roots are
found by an iterative technique using the computer.
For a specified emission from a typical source, x/AAQS as a
function of distance might look as follows:
DISTANCE FROM SOURCE
The affected population is contained in the area
A = TT(x22 - X12) (D-77)
If the affected population density is D , the total affected
population, P1, is p
P1 = DpA (persons)
(D
-78)
EFFLUENT SOURCE SEVERITY
Various mathematical models can be conceived to describe the
impact of a discharge on a receiving body. Such systems are
complex and not fully understood. Pertinent factors deserving
consideration include the number of discharge streams? the f
rate and composition (chemical and physical characteristics)
178
-------
each discharge stream; the hazardous nature of the discharge;
the volume, flow rate, and water quality of the receiving body;
and the ability of the receiving body to detoxify the discharge
In an effluent stream containing many materials, each species
may have a different environmental impact; in addition, syner-
gestic interactions may occur.
For this assessment study, it was decided to adopt a simplified
approach in which the resultant concentration of a specific
pollutant is compared to an associated hazard factor. Three
simple models can be considered depending on the degree of mix-
ing with the receiving body. In the first case, the source
severity (S ) was defined for each discharge as follows:
BD
(D-79)
where
C =
F =
severity due to a pollutant in a discharge
stream before dilution
concentration of pollutant in effluent, g/m3
hazard factor, equal to a potentially hazardous
concentration, g/m3
Equation D-79 describes what may be termed the end-of-pipe
severity for the discharge stream. Once an effluent enters a
receiving body, it is diluted by the receiving body water and
the severity decreases. The severity within a mixing zone is
defined as follows:
v
p
where S.,,, = severity due to a pollutant in a mixing zone
MZ
V = effluent discharge rate, m3/s
vr = river flow rate, m3/s
F = fraction of river flow in mixing zone;
i.e., 1/3, 1/4
MZ
The severity after the mixing zone, SAM7, is given by:
/ V^
VVD + vr
where SAM? = severity due to a pollutant after a mixing zone
These relationships are shown in Figure D-l.
179
-------
-MIXING ZONE'
AFTERMIXWG ZONE-
POINT OF
DISCHARGE
DOWN STREAM 01 STANCE
Figure D-l. Change of concentration with distance.
If vr is much greater than V , then
AMZ
(D-82)
Equation D-82 defines the effluent source severity, Se, used in
this report with one exception. The term vr was replaced with
the minimum river flow rate, VR, to maximize the severity term.
It is important to note that this effluent source severity is
not an aggregate parameter; instead, it refers to one pollutant
within one discharge stream. A more detailed treatment of the
effluent source severity is available in the literature (108).
180
-------
GLOSSARY
air preheater: Device that preheats combustion air using waste
heat recovered from flue gas.
affected population: Number of persons around an average source
who are exposed to a source severity greater than 0.05 or
1.0, as specified.
ash sluicing: Transport of ash as aqueous slurry.
beneficiation: Physical cleaning of coal to remove mineral
matter.
bituminous: Coal covering a wide range of properties, but in
general having a fixed carbon content less than 80% and
volatile matter exceeding 20%.
blowdown: Boiler water or cooling water wasted from a closed
circulatory system to limit the buildup of dissolved solids.
boiler efficiency: Ratio of boiler heat output, measured as the
heat content of the steam produced, to boiler heat input,
measured as the heat content of the coal feed.
boiler tubes: Cylindrical tubes, located in convection passes
and on furnace side walls, in which heat from the furnace is
transferred to the boiler water.
bottom hopper: Container fitted to bottom of furnace to collect
ash that falls to furnace floor.
capacity: Maximum heat or maximum steam output for which boiler
is designed.
clarification: Removal of suspended solids from feedwater by
quiesent settling.
combustion zone: Layer surrounding each coal particle where the
mixing of combustibles and air forms a combustible mixture,
and a diffusion flame is established.
criteria pollutants: Pollutants for which ambient air quality
standards have been established.
181
-------
cyclone: Device that uses centrifugal forces to separate partic-
ulate matter from gas.
diffusion flame: Flame established around a solid where combus-
tible material must diffuse into the oxidant in order for
combustion to take place.
direct feed: Fuel supply system in which coal is fed directly
from pulverizers to burners.
dispersed concentration: Concentration of water pollutant in
receiving body after mixing.
dry bottom furnace: Furnace in which operating temperature is
kept below ash fusion temperature so that bottom ash can be
removed as dry powder.
economizer: Device that preheats boiler feedwater using waste
heat recovered from flue gas.
effluent factor: Quantity of effluent species discharged per
quantity of mass burned.
emission factor: Quantity of emission species emitted per
quantity of mass burned.
enrichment: Concentration of certain elements in fly ash due to
their partitioning behavior at furnace temperatures.
evaporator: Device used to purify boiler feedwater by thermal
vaporization.
excess air: Air added to furnace in excess of that required for
stoichiometric combustion. .•„
exchange capacity: Maximum quantity of dissolved ions that can
be adsorbed by an ion exchanger without breakthrough
occurring.
external combustion: Combustion which takes place outside of the
working fluid of a heat-to-work conversion device; all boil-
ers require external combustion.
firing capacity: Maximum amount of heat input for which a fur-
nace is designed.
fixation: Solidification of waste sludges by addition of
chemicals.
flue gas dew point: Temperature at which vapors in flue gas
begin to condense.
182
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fly ash: Portion of noncombustible residue from fuel, carried
out of boiler by flue gas.
hardness: Concentration of scale-forming ions in water.
hazard factor: Lowest concentration of pollutant which has been
shown to be detrimental to health or environment.
horizontally fired furnace: Furnace in which burners are located
in side walls.
indirect feed: Fuel supply system in which coal leaving pulver-
izers is fed to a storage hopper which supplies the burners.
ion exchange: Reversible interchange of ions between a liquid
and a solid with no radical change in the structure of the
solid; used for purification of boiler feedwater.
output capacity: Maximum quantity of steam at given pressure
which a boiler is designed to generate.
overfire air: Combustion air admitted to furnace just above
flame.
partitioning: Separation of a substance between two phases.
pulverized: Finely divided; at least 80% of pulverized coal will
pass through a 200-mesh sieve.
pulverizer: Device that crushes coal to fineness necessary for
combustion in a pulverized, coal-fired furnace.
pyrolysis: Chemical decomposition by application of heat in
oxygen-deficient atmosphere.
reheater: Heat exchange device for adding superheat to steam
which has been partially expanded in a turbine.
slag: Molten form of noncombustible fuel residue remaining in
furnace after combustion.
softening: Removal of hardness-causing ions from water using
chemical precipitation or ion exchange.
source severity: Indication of the hazard potential of an
emission source.
staged combustion: Fuel-rich combustion achieved by diverting
portion of combustion air to port near tip of flame.
state emission burden: Ratio of annual emissions from a specific
source in any state to the total state emissions from all
stationary sources.
183
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superheater: Device for heating steam to a temperature above
that corresponding to saturation at a specific pressure.
tangentially fired furnace: Furnace in which burners are located
in corners and directed toward the edges of an imaginary
circle in the center of the furnace, thus imparting a
swirling motion to the flames.
threshold limit value (TLV): Airborne concentrations of sub-
stances; represents conditions under which it is believed
that nearly all workers may be repeatedly exposed day after
day without adverse effect.
utilization factor: Ratio of actual output of boiler, as re-
quired by demand, to related output.
vertically fired furnace: Furnace in which burner is located
in furnace ceiling and directed downward.
water quality criteria: Concentrations of selected pollutants
at which damage to selected biological species has been
shown to occur.
water walls: Furnace walls composed of boiler tubes.
wet bottom furnace: Furnace in which operating temperature is
above ash fusion temperature so that portion of ash re-
maining in furnace is in molten form.
184
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CONVERSION FACTORS AND METRIC PREFIXES (157)
CONVERSION FACTORS
To convert from
Degree Celsius (°C)
Gram/kilogram (g/kg)
Joule (J)
Kilogram (kg)
Meter (m)
Meter (m)
Meter2 (m2)
Meter3 (m3)
Metric ton
To
Pascal
Second
(Pa)
(s)
Degree Fahrenheit (°F)
Pound/ton
Btu
Pound-mass (avoirdupois)
Foot
Inch
Mile2
Foot3
Ton (short, 2,000 pound
mass)
Inch of water (60°F)
Minute
Multiply by
tOF = 1.8 t0p + 32
F U2.000
9.478 x 10-**
2.205
3.281
3.937 x IO1
3.861 x IO-7
3.531 x IO1
1.102
4.019 x IO-3
1.667 x IO-2
PREFIXES
Prefix Symbol
Exa
Peta
Tera
Giga
Mega
Kilo
Milli
Micro
E
P
T
G
M
k
m
Multiplication
factor
1018
IO15
IO12
109
106
103
io-3
io-6
Example
1
1
1
1
1
1
1
1
Em =
Pm =
Tm =
Gm =
Mm =
km -
mm =
um =
1
1
1
1
1
1
1
1
x
x
X
X
X
X
X
X
IO1
IO1
IO1
IO9
IO6
IO3
8
5
2
io-3
10-
6
meters
meters
meters
meters
meters
meters
meter
meter
(157) Standard for Metric Practice. ANSI/ASTM Designation
E 380-76ef IEEE Std 268-1976, American Society for Testing
and Materials, Philadelphia, Pennsylvania, February 1976.
37 pp.
185
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
PA-600/2-79-019e
2.
TITLE AND SUBTITLE
SOURCE ASSESSMENT: Dry Bottom Industrial
Boilers Firing Pulverized Bituminous Coal
. REPORT DATE
June 1979
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
iV.R.McCurley, C.M.Moscowitz, J.C.Ochsner, and
R. B.Reznik __^^_^^___
. PERFORMING ORGANIZATION NAME AND ADDRESS
Monsanto Research Corporation
P.O. Box 8, Station B
Dayton, Ohio 45407
2. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
i. RECIPIENT'S ACCESSION-NO.
. PERFORMING ORGANIZATION REPORT NO.
MRC-DA-900
10. PROGRAM ELEMENT NO.
1AB015; ROAP 21AXM^071,
11. CONTRACT/GRANT NO.
68-02-1874
13. TYPE OF REPORT AND PERIOD -
Task Final: 8/74 -JZIi.
14. SPONSORING AGENCY CODE
EPA/600/13
5. SUPPLEMENTARY NOTESTJERL-RTP project officer is Ronald A. Venezia, Mail Drop 62,
919/541-2547.
Tlie rep0rt describes and assesses the potential impact of air emissions
wastewater effluents, and solid wastes from the operation of dry bottom industrial
boilers firing pulverized bituminous coal. Air emissions were characterized by a
literature survey and field sampling. Significant emissions resulting from coal com-
bustion were particulate matter, sulfur oxides (SOx), nitrogen oxides (NOx), hydro-
carbons, polycyclic organic materials (POM), and a number of elements. The poten-
tial environmental impact of each emission species after passing through state-of-
the-art controls was individually assessed using a calculated quantity known as the
source severity. Species determined to have source severities greater than 1.0 were
NOx (1.7), SOx (2.2), and POM (6.0). Pollutant concentrations were also measured
in wastewater and solid waste streams. Effluent source severities were found to be
significantly less than 1.0 for most species. The potential impact of solid waste dis-
charges on the quality of air and of ground and surface water was also found to be
minor when available controls were applied.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI
Pollution
Assessments
Boilers
Bituminous Coal
Pulverized Fuels
Combustion
Dust
Nitrogen Oxides
Sulfur Oxides
Hydrocarbons
Polycyclic Com-
pounds
Pollution Control
Stationary Sources
Dry Bottom Boilers
Particulate
13 B
14B
13A
21D
21B
11G
07B
07C
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF
199
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
186
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