PB82-109414
Emissions Assessment of Conventional Stationary
Combustion Systems: Summary Report
TRW, Inc.
Redondo Beach, CA
Prepared for
Industrial Environmental Research Lab
Research Triangle Park, NC
Sep 81
U.S. DEPARTMENT OF COMMERCE
National Technical Information Service
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EPA-600/7-81-003d
EMISSIONS ASSESSMENT OF CONVENTIONAL STATIONARY
COMBUSTION SYSTEMS: SUMMARY REPORT
by:
C.C. Shih and A.M. Takata
TRW Environmental Engineering Division
One Space Park, Redondo Beach, CA 90278
EPA Contract No.: 68-02-2197
Project Officer; Michael C. Osborne
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, N.C. 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D.C 20545
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-81-003d
2.
ORD Report
3. RECIPIENT'S ACCESSION-NO.
A i L
4. TITLE AND SUBTITLE
Emissions Assessment of Conventional Stationary
Combustion Systems: Summary Report
5. REPORT OATS'
September 1981
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
C.C. ShihandA.M. Takata
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2197
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE Of REPORT AND PERIOD COVERED
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND
Final; 9/76-7/81
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES iERL_RTp project officer is Michael C. Osborne. Mail Drop 61,
4113.Related reports are in the EPA-600/7-81-003 and EPA-600/7-79-029 series.
is. ABSTRACT
report gjves results of a. characterization of multimedia emissions
from 39 source categories of conventional stationary combustion systems. In the
assessment, existing emissions data were first examined to determine the adequacy
of the data base. This was followed by a measurement program to fill identified data
gaps. Emissions data obtained from the sampling and analysis program were com-
bined with existing emissions data to provide estimates of emission levels, and to
define the need for additional data. Study results indicate that flue gas emissions of
NOx, SOZ, and particulate matter from the 39 source categories account for approx-
imately 86, 66, and 36%, respectively, of the emissions of these pollutants from all
stationary sources. Additionally, flue gas emissions of sulfates and several trace
elements from coal- and Oil-fired combustion sources also require further attention.
POM compounds in flue gas emissions are mostly naphthalene, phenanthrene , and
pyrene. However, dibenz(a,h)anthracene and possibly benzo(a)pyrene, both active
carcinogens, were detected at a limited number of coal- and wood-fired sites.
Concentrations of iron, magnesium, manganese, nickel, and phosphorus in waste -
water streams are at levels that may be of environmental concern. Data on coal fly
ash and bottom ash show 11-16 trace elements at potentially harmful levels.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Assessments
Emission
Effluents
Combustion
Pollution Control
Stationary Sources
13 B
14 B
14G
21B
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGFS
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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DISCLAIMER
This report has been reviewed by the Industrial Environ-
mental Research Laboratory (RTF), U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the views
and policies of the Agency, nor does mention of trade names
or commercial products constitute endorsement or recommen-
dation for use.
ii
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ABSTRACT
Multimedia emissions from thirty-nine source categories of conventional
stationary combustion systems are characterized in this study. In the
assessment process, existing emissions data were first examined to determine
the adequacy of the data base. This was followed by the conduct of a measure-
ment program to fill the identified data gaps. Emissions data obtained from
the sampling and analysis program were combined with existing emissions data
to provide estimates of emission levels, and to define the need for additional
data.
The results of this study indicate that conventional stationary combustion
systems contribute significantly to the nationwide emissions burden. Flue
gas emissions of NO , SCL, and particulate matter from the thirty-nine source
/\ Cm
categories studied account for approximately 86 percent, 66 percent, and 36
percent, respectively, of the emissions of these pollutants from all stationary
sources. Additionally, flue gas emissions of sulfates and several trace elements
from coal- and oil-fired combustion sources also require further attention.
POM compounds in flue gas emissions are mostly naphthalene, phenanthrene, and
pyrene. However, dibenz(a,h)anthracene and possibly benzo(a)pyrene, both
active carcinogens, were detected at a limited number of coal-fired sites.
Also, dibenz(a,h)anthracene, and possibly benzo(a)pyrene and benzo(g,h,i)perylene,
another active carcinogen, were detected at one coal-fired and one wood-fired
underfeed stoker tested. The possible presence of benzo(a)pyrene in significant
amounts was indicated in the emissions of two other wood-fired boilers.
A second major source of air emissions in steam electric plants is vapors
and drifts from cooling towers. Air emissions of chlorine, magnesium, phos-
phorus, and sulfates from mechanical draft cooling towers were found to be
comparable to flue gas emissions of these pollutants from oil-fired utility
boilers.
Wastewater streams are generated from several operations in steam electric
plants, and in industrial and commercial/institutional facilities but to a much
"iii
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lesser extent. Overall, concentrations of iron, magnesium, manganese, nickel,
and phosphorus are at levels that may be of environmental concern. Average
organic levels ranged from 0.01 mg/1 for ash pond effluents to 6.0 mg/1 for
boiler blowdown. Also, no POM compound was detected in wastewater streams.
Data on coal fly ash and bottom ash show that from eleven to sixteen
trace elements are present at potentially harmful levels. The only POM
compounds detected, however, were naphthalene, alkyl naphthalenes, and
other relatively nontoxic compounds.
iv
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CONTENTS
Page
Abstract iii_
Figures vi ~
Tables j/ii~
1. Introduction 1
2. Assessment Methodology 6
3. Source Description 7
3.1 Gas- and Oil-Fired Residential Heating Sources 7
3.2 Internal Combustion Sources 8
3.3 External Combustion Sources for Electricity Generation. 9
3.4 Commercial/Institutional Combustion Sources 12
3.5 Industrial Combustion Sources 13
4. Existing Emissions Data Base 15
4.1 Gas- and Oil-Fired Residential Heating Sources 15
4.2 Internal Combustion Sources . 15
4.3 External Combustion Sources for Electricity Generation. 16
4.4 Commercial/Institutional Combustion Sources 17
4.5 Industrial Combustion Sources . 17
5. The Source Measurement Program 19
5.1 Gas- and Oil-Fired Residential Heating Sources 19
5.2 Internal Combustion Sources 19
5.3 External Combustion Sources for Electricity Generation. 20
5.4 Commercial/Institutional Combustion Sources 21
5.5 Industrial Combustion Sources 21
6. Sampling and Analysis 22
6.1 Level I Field Testing 22
6.2 Modified Level I Laboratory Analysis 24
6.2.1 Inorganic Analyses 27
6.2.2 Organic Analyses 27
6.3 Level II Sampling and Analysis 28
7. Results 30
7.1 Gas- and Oil-Fired Residential Heating Sources 30
7.2 Internal Combustion Sources 32
7.3 External Combustion Sources for Electricity Generation. 35
7.4 Commercial/Institutional Combustion Sources 45
7.5 Industrial Combustion Sources 49
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CONTENTS (Continued)
Page
8. Conclusions 55
8.1 Gas- and Oil-Fired Residential Heating Sources 55
8.2 Internal Combustion Sources 56
8.3 External Combustion Sources for Electricity Generation. 57
8.4 Commercial/Institutional Combustion Sources 62
8.5 Industrial Combustion Sources 63
References 66
FIGURES
Page
Figure 1. Schematic of Source Assessment
Sampling System (SASS) 23
Figure 2. Basic Level I Sample Flow and Analytical
Plan for Particulates and Gases 25
Figure 3. Basic Level I Sampling Flow and Analytical
Schematic for Solids, Slurries and Liquids 26
VI
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Table 1.
Table 2.
Table 3.
Table 4.
Table 5.
Table 6.
Table 7.
Table 8.
Table 9.
TABLES
Page
Combustion Systems Considered in the Study 5
Summary of Results of Emissions Assessment
for Residential Sources 31
Summary of Results of Emissions Assessment
for Gas-Fueled Internal Combustion Sources 33
Summary of Results of Emissions Assessment
for Oil-Fueled Internal Combustion Sources 34
Summary of Assessment Results for Flue Gas Emissions
from Bituminous Coal-Fired Utility Boilers 36
Summary of Assessment Results for Flue Gas Emissions
from Lignite-Fired Utility Boilers 37
Summary of Assessment Results for Flue Gas Emissions
from Residual Oil- and Gas-Fired Utility Boilers 38
Summary of Assessment Results for Cooling Tower
Slowdown, Boiler Slowdown, and Ash Pond Overflow 41
Summary of Assessment Results for Water Treatment
Wastewater, Chemical Cleaning Wastes, Wet Scrubber
Wastewater, and Coal Pile Runoff 42
Table 10. Summary of Assessment Results for Fly Ash and Bottom
Ash from Bituminous Coal-Fired and Lignite-Fired
Boilers 44
Table 11. Summary of Results of Emissions Assessment for
Commercial/Institutional Combustion Sources 46
Table 12. Summary of Results of Emissions Assessment
for Industrial Combustion Sources 50
Vll
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1. INTRODUCTION
The combustion of common fuels - coal, oil, gas, and wood - in conven-
tional stationary systems for heating and power generation is one of the
largest and most widespread sources of environmental pollution. Combustion
of these fuels affects air, water, and land. In a preliminary assessment of
the significance of stationary combustion systems as sources of pollution (1),
it was estimated that these combustion sources contribute a major portion of
the total man-made emissions of nitrogen oxides, sulfur dioxide, and particu-
late matter. Further, many of the combustion processes and associated pollu-
tion control technologies also produce solid wastes, in the form of ash and
sludge, that present disposal problems. Leaching of chemical compounds and
heavy metals from solid fuel or waste material, as well as direct discharges
of wastewater streams, may result in contamination of water resources.
Assessment of the environmental impacts is complicated by cross-media and
multi-media effects, as pollutants merge with or pass between environmental
media. For example, removal of sulfur dioxide and particulate matter from
flue gases significantly increases the amount of solid wastes requiring
disposal. .
The U.S. Environmental Protection Agency (EPA) has long been active in
regulating the release of pollutants from stationary conventional combustion
processes. The involvement has included characterization of emission streams,
research on the health and ecological effects of combustion pollutants,
development and demonstration of pollution control technologies, and setting
and enforcing of environmental standards. Much of the earlier work on com-
bustion pollutant characterization, however, was focused on the three major
air pollutants - sulfur dioxide, nitrogen oxides, and particulate matter - and
the subsequent development of control technologies and standards for these
pollutants. As a consequence, the early characterization work was limited in
scope and did not adequately address the emissions of other potentially
hazardous pollutants or the multi-media aspects of combustion emissions.
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These observations were confirmed in the preliminary assessment study (1),
which identified the inadequate characterization of flue gas emissions of
trace elements, sulfates, particulate matter by size fraction, and polycyclic
organic matter (POM). In addition, the same study also identified the general
inadequacy of the data base characterizing air emissions from cooling towers
and coal storage piles, and wastewater effluents and solid wastes from com-
bustion processes.
From the above discussion, it is apparent that much of the data describing
pollutant types and quantities released from stationary conventional combustion
processes were unavailable. A comprehensive characterization of emissions
from these processes, therefore, was needed as a basis for identifying the
pollutants of concern, for estimating the total quantities of pollutants
emitted, for assessing the impacts of pollutant emissions on health and the
environment, and for evaluating the need for control technology development.
In response to the need for a comprehensive characterization, the EPA's
Industrial Environmental Research Laboratory at Research Triangle Park (IERL-
RTP) in North Carolina established the Conventional Combustion Environmental
Assessment (CCEA) Program as the primary vehicle for filling the identified
data gaps. The component project under which this study was performed is
known as the Emissions Assessment of Conventional Combustion Systems (EACCS)
project, and the specified objectives of this project are:
Compilation and evaluation of all available emissions data on
pollutants from selected stationary conventional combustion
processes.
Acquisition of needed new emissions data from field tests.
t Characterization of air emissions, wastewater effluents, and
solid wastes generated from selected stationary conventional
combustion processes, utilizing combined data from existing
sources and field tests.
Determination of additional data needs, including specific
areas of data uncertainty.
Because of the comprehensive characterization requirement, the assess-
ment process in this project was based on a critical examination of existing
data, followed by a phased sampling approach to fill data gaps. In the first
phase, sampling and analysis procedures were used to provide results accurate
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to a factor of 3 so that preliminary assessments can be made and problem areas
identified. The methodology employed was similar to the Level I sampling and
analysis procedures developed under the direction of the Industrial Environ-
mental Research Laboratory of the U.S. Environmental Protection Agency (2),
the major addition being that GC/MS analysis for POM was performed on the
samples collected in this project. Evaluation of results from the first
phase was used to determine all waste stream/pollutant combinations requiring a
more detailed and accurate Level II sampling and analysis program. Level II
tests were subsequently conducted at a selected number of sites. In terms of
major potential benefits, the characterization of combustion source emissions
from this project will allow EPA to determine the environmental acceptability
of combustion waste streams and pollutants and the need for control of environ-
mentally unacceptable pollutants.
The combustion source types to be assessed in this project were
selected because of their relevance to emissions and because they are among
the largest, potentially largest, or most numerous (in use) of existing com-
bustion source types. A total of 39 source types were selected for study.
Selected source types were classified under the following principal cate-
gories:
1) Electricity generation - External combustion
2) Industrial - External combustion
3) Electricity generation and industrial - Internal combustion
4) Commercial/institutional - Space heating/internal combustion
5) Residential - Space heating
These five principal categories were further divided into subcategories
based on fuel type, furnace design, and firing method. The subcategorization
is needed because of the differences in the emission characteristics of com-
bustion source types.
This document provides an overall summary of the five group/category
reports published under the EACCS project. These five group/category reports
are:
a Volume I. Gas and Oil-Fired Residential Heating Sources (3).
Volume II. Internal Combustion Sources (4).
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Volume III. External Combustion Sources for Electricity
Generation (5).
Volume IV. Commercial/Institutional Combustion Sources (6).
Volume V. Industrial Combustion Sources (7).
These reports present and discuss data evaluation and test results, and
provide best estimates of emission factors or discharge stream concentrations
for effluents from each of the principal combustion source categories. These
emission estimates were derived utilizing combined data from existing informa-
tion sources and field tests conducted in the current project. Each report
also provides estimates of nationwide emissions from the specified combustion
source category, and identifies major gaps in emissions data. As such,
information contained in the reports can be used for:
Compilation of emission factors for pollutants and waste
streams for which no existing data were available.
Upgrading of existing emission factors for pollutants and
waste streams.
Performing environmental assessments of conventional stationary
combustion sources.
Determining the nationwide burden of emissions from conventional
stationary combustion sources.
Evaluating the need for control technology development,
based on analysis of the environmental impacts of uncon-
trolled and controlled emissions.
t Planning of future Level II field tests to provide critical
data needs.
0 Providing input to the development of emission standards.
Combustion system types which were considered in the five group/category
reports are indicated in Table 1.
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TABLE 1. COMBUSTION SYSTEMS CONSIDERED IN THE STUDY
Combustion
Source
Type
External Combustion
Coal
Bituminous
Pulverized dry
Pulverized wet
Cyclone
All stokers
Anthracite
Pulverized dry
All stokers
Lignite
Pulverized dry
Cyclone
All stokers
Petroleum
Residual oil
Tangential firing
All other
Distillate oil
Tangential firing
All other
Gas
Tangential firing
All other
Wood
Stoker
Internal Combustion
Electricity
Generation
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillate Oil
Gas turbine X
Reciprocating engine X
Gas
Gas turbine
Reciprocating engi
X
ne X
User
Industrial
X
X
X
X
X
X
X
X
X
X
X
Sector
Commercial/
Institutional
X
X
X
X
X
X
X
X
X
Residential
X
X
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2. ASSESSMENT METHODOLOGY
The assessment method employed in the project involved a critical exami-
nation of existing emissions data, followed by the conduct of a measurement
program to fill data gaps based on phased sampling and analysis strategy.
Data acquired as a result of the measurement program, in combination with the
existing data, were further evaluated. Data inadequacies identified at the
completion of the project are discussed with respect to the need for addi-
tional study.
Specifically, the phased approach to environmental assessment is designed
to provide comprehensive emissions information on all process waste streams
in a cost effective manner. To achieve this goal, two distinct sampling and
analysis levels were employed in the project. Level I utilizes semiquantita-
tive (± a factor of 3) techniques of sample collection and laboratory and
field analysis: 1) to provide preliminary emissions data for waste streams
and pollutants not adequately characterized; 2) to identify potential problem
areas; and 3) to prioritize waste streams and pollutants in those streams for
further, more quantitative testing. Using the information from Level I,
available resources can be directed toward Level II testing which involves
specific quantitative analysis of components of those streams that do contain
significant pollutant levels. The data developed at Level II are used to
identify control technology needs and to further define the environmental
hazards associated with emissions.
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3. SOURCE DESCRIPTION
3.1 GAS- AND OIL-FIRED RESIDENTIAL HEATING SOURCES
Residential space heating sources are defined as combustion units with
fuel input capacities below 422 MJ/hr (0.4 million Btu/hr) in accordance with
recent U.S. Environmental Protection Agency (EPA) sponsored studies. Resi-
dential combustion systems consume about 15 percent of the fuel used by
conventional stationary combustion systems. The residential sector accounted
for about 6800 PJ* of the 1978 estimated fuel consumption total of 45,000
PJ. This source uses primarily gas (58 percent) and oil (38 percent). It is
estimated that in 1974 there were about 34,000,000 gas-fired, 13,000,000 oil-
fired, 740,000 coal-fired, and 660,000 wood-fired residential space heating
systems in the United States.
Heating systems for residential sources are concentrated in areas of high
population density such as the Northeast, Midwest, and parts of California.
Oil consumption is most heavily concentrated in the northeast with the states
of Pennsylvania, New York, New Jersey, Massachusetts, and Connecticut consuming
53 percent of the U.S. total. Only very small amounts of oil are burned in
the west and south. Residential gas consumption for space heating is more
widely distributed than oil, but is still most heavily concentrated in the
upper midwest and northeast. States that account for more than 5 percent of
the U.S. total residential gas consumption include Illinois (8.9 percent),
New York (8.3 percent), Ohio (8.1 percent), California (7.8 percent), Michigan
(7.6 percent), and Pennsylvania (6.0 percent).
Residential gas- and oil-fired space heating equipment is subject to a
number of design variations related to burners, combustion chambers, excess
air, heating medium, etc. Residential systems generally operate only in an
on/off mode with no variation in fuel input rate in contrast to load modulation
encountered with larger commercial, industrial, and electric utility systems.
*1 PJ = TO15 joules.
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Gas-fired systems are inherently less complex and easier to maintain
than oil-fired units because the fuel is cleaner and atomization is not
required. Residential gas burners use natural aspiration and are very similar
in design, whereas several burner designs are used for oil atomization. How-
ever, high pressure (^100 psig) atomization burners account for about 90
percent of the total (8). Low pressure and rotary burners are being phased
out because of their complexity. Although air pollution control equipment is
not available for residential combustion systems, emission reduction measures
are being evaluated. The EPA is active in the development and evaluation of
residential gas- and oil-fired burners and furnaces.
3.2 INTERNAL COMBUSTION SOURCES
Stationary internal combustion sources for electricity generation and
industrial applications are grouped into two categories: gas turbines and
reciprocating engines. Gas turbines may be classified into three general
types: simple open cycle, regenerative open cycle, and combined cycle. Re-
generative type gas turbines constitute only a very small fraction of the
total gas turbine population. Emissions from identical gas turbines used in
the combined cycle and in the simple cycle are the same. Therefore, only
emissions from simple cycles need to be evaluated.
Reciprocating internal combustion engines may be classified into spark
and compression ignition (diesel) engines. All distillate oil reciprocating
engines are compression ignited, and all gasoline reciprocating engines are
spark ignited. Spark ignition gasoline engines have very limited use for
electricity generation and industrial application because of their poor part
load economy and cost of fuel. Gas reciprocating engines, with the exception
of the dual-fuel type, are spark ignited. Gas can only be used in a compres-
sion ignition engine if a small amount of diesel fuel is injected into the
compressed air/gas mixture to initiate combustion.
The principal application areas for gas turbines and reciprocating
engines are: electricity generation, oil and gas transmission, natural gas
processing, oil and gas production and exploration. For gas turbines, the
total 1978 installed capacity was 50,800 MW for electricity generation and
9,400 MW for industrial applications. For reciprocating engines, the total
8
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1978 installed capacity was 5,300 MW for electricity generation and 19,500 MW
for industrial applications.
The current average size of electricity generation gas turbines is
approximately 31 MW. As of December 31, 1976, the capacity average age for
electricity generation gas turbines was approximately 5 years. Industrial gas
turbines were estimated to have an average size of 2.2 MW. For reciprocating
engines, the average size unit for electricity generation is 1.9 MW (2,500
HP), and the average size unit for oil and gas transmission is 1.5 MW (2,000
HP). Average age for reciprocating engines is approximately 10 years.
Air pollution control equipment is generally not installed on gas turbines
or reciprocating engines. However, there is increasing recognition that water
and steam injection are valid techniques for controlling NO emissions from
/\
gas turbines. In addition, to reduce visible smoke emissions from oil-fueled
gas turbines, fuel additives such as soluble compounds of barium, manganese
and iron are often employed.
3.3 EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Stationary external combustion sources for electricity generation can be
classified according to the type of fuel used and furnace design. Fuels used
in utility boilers include bituminous coal, anthracite coal, lignite coal,
residual oil, and natural gas. For coal firing, furnace designs include four
major types: pulverized dry bottom, pulverized wet bottom, cyclone, and
stokers. The primary methods of firing pulverized coal, residual oil, and
natural gas are: tangential firing, front wall firing, and horizontally-
opposed firing.
In 1978, the total installed generating capacity for conventional steam
plants firing fossil fuels was 401,467 MW. Of the installed generating
capacity, 58.1 percent were coal-fired boilers, 25.5 percent were oil-fired
boilers, and 16.4 percent were gas-fired boilers. For coal-fired boilers,
the pulverized bituminous dry bottom category accounted for over 73 percent
of the installed generating capacity. During the 1979-1985 period, generating
capacity additions of approximately 80,000 MW are projected for pulverized
bituminous dry bottom boilers. The only other major generating capacity
additions will be 17,300 MW for pulverized lignite dry bottom boilers. Coal-
; 9-
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fired pulverized wet bottom and cyclone boilers are no longer being sold
because of their inability to meet NO standards, and coal-fired stokers are
X
being phased out by retirements. The projected 1985 installed generating
capacity also shows a small increase in generating capacity for oil-fired
utility boilers, and a small decrease in generating capacity for gas-fired
utility boilers. By 1985, 66.6 percent of the installed generating capacity
for utility boilers will be coal-fired, 20.9 percent will be oil-fired, and
only 12.5 percent will be gas-fired.
Fossil fuels consumed by electricity generation external combustion
sources in 1978 amounted to 120.4 Tg*of western bituminous coal (2,698 PJ),
316.6 Tg of eastern bituminous and anthracite coal (8,280 PJ), 31.1 Tg of
lignite coal (477 PJ), 94.1 x 106 m3 of residual oil (3,830 PJ), and 62.9 x
109 m3 of natural gas (2,399 PJ). From 1978 to 1985, the projected fossil
fuel requirements indicate a 47.6 percent increase and 16.4 percent increase
in coal and oil consumption, respectively, and a 40.6 percent decrease in
natural gas consumption. The increase in coal consumption will be mostly due
to significant increases in the consumption of western bituminous (119.0 per-
cent) and lignite coal (113.8 percent). The consumption in eastern bituminous
coal is only projected to increase by 20.6 percent during the same time period.
Air, water, and solid waste pollutants are emitted from a number of
operations within a steam electric plant. The major source of air emissions
is flue gas emissions from stacks. Other sources are emissions from ash
handling and storage, fuel handling and storage, and cooling systems in the
form of drifts and vapors.
Air pollution control on utility boilers is mainly directed at reducing
flue gas emissions of particulates, sulfur dioxide, and nitrogen oxides. For
control of particulate emissions, electrostatic precipitators and centrifugal
separators are the most common types of devices used.
To reduce emissions of sulfur dioxide to the atmosphere, there are five
flue gas desulfurization (FGD) processes sufficiently developed for full-
scale commercial application: lime/limestone scrubbing, magnesium oxide
scrubbing, sodium carbonate scrubbing, the double-alkali process, and the
Wellman-Lord process. By the end of 1978, there were 51 operating FGD systems
* : r?
1 Tg = 10 grams.
10
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on utility boilers totalling 17,888 MW in generating capacity, 14,309 MW of
which were on bituminous coal-fired boilers and the remaining on lignite coal-
fired boilers. On generating capacity basis, 92 percent of the operating FGD
systems utilize lime/limestone scrubbing. By 1985, the FGD systems scheduled
for operation will increase significantly, to a total representing 52,572 MW
in generating capacity.
The primary techniques for reducing NO emissions from utility boilers
/\
include: low excess air firing (LEA), flue gas recirculation (FGR), off-
stoichiometric combustion, reduced air preheat, and burner or furnace modifica-
tion. Low excess air firing is the only NOV control on utility boilers that
X
has been implemented on a large scale. The generating capacity of utility
boilers equipped with NO controls amounted to 43,756 MW in 1978, representing
/\
approximately 10.9 percent of the total utility fossil fuel-fired boiler
generating capacity.
Water usage in steam electric plants is complex and results in wastewater
streams from a number of operations. These include: discharge from once-
through cooling systems or blowdown from cooling towers, ash pond overflow,
wastewater from wet-scrubber systems, boiler blowdown, wastewater from water
treatment processes, chemical cleaning wastes, coal pile runoff, and miscella-
neous low volume wastes. The two principal methods of wastewater treatment
are controlled release to a waterway, and retention in a holding pond for
sedimentation and/or neutralization before controlled release.
Solid wastes are generated in fossil fuel-fired steam electric plants in
the form of fly ash, bottom ash, spent scrubber sludge, and water treatment
sludges. Disposal of fly ash and bottom ash involves either mechanically
conveying the dry ash to a landfill area, or by water sluicing and piping the
ash transport water to a settling pond. In ash disposal by water sluicing,
an intermediate stage of ash dewatering is sometimes involved, resulting in
disposal of the wet ash in landfills. The current trend, however, is away
from ash disposal and towards increased ash utilitization. Spent scrubber
sludges from nonrecovery FGD systems are currently disposed of by the use of
lined and unlined ponds, landfills, and mines, both with and without sludge
stabilization. Sludges from water treatment processes are disposed of by
11
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direct discharge to waterways or sewer systems, by transport to settling ponds,
and to landfills after dewatering.
3.4 COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
The commercial/institutional external combustion sources evaluated in
this study were sources used for space heating of trade establishments, health
and educational institutions, and government facilities. These application
areas are identical to those used by the Department of Energy (DOE) in com-
piling energy consumption data for the commercial sector (9). Commercial
combustion units have also been defined as units with heat inputs ranging from
0.42 to 13.2 GJ/hr (10,11). However, this definition excludes many smaller
and larger units used in the commercial/institutional sector. Institutional
units especially tend to be appreciably larger than 13.2 GJ/hr and account for
almost 20 percent of the commercial/institutional sector fuel consumption (1).
Commercial/institutional fuel consumption for space heating was 5100 PJ
in 1978 based on DOE data for total fuel consumption (9) and estimates of the
fraction of this fuel used for space heating (12). This consumption value, is
less than 10 percent of the estimated 1978 national fuel consumption figure of
54,000 PJ, excluding fuel used in the transportation sector (9). Commercial/
institutional external combustion sources for space heating primarily use oil
(52 percent) and gas (44 percent). Small amounts of coal and wood are also
used by the commercial/institutional sector. Internal combustion sources in
the commercial/institutional sector, primarily gas- and oil-fired reciprocating
engines, are used for pumping municipal water and sewage. Small amounts of
fuel may also be used by internal combustion sources for auxiliary power
generation.
Heating systems for commercial/institutional sources are concentrated in
areas of high population density such as the Northeast, Midwest, and parts of
California. Oil consumption is most heavily concentrated in the Northeast
with the States of New York, Massachusetts, New Jersey, and Pennsylvania
consuming about 25 percent of the U.S. total. Commercial gas consumption for
space heating is more widely distributed than oil, but is still most heavily
concentrated in the Midwest and Northeast (13).
12
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Commercial/institutional external combustion sources can be sold as
either packaged units or boilers to be constructed onsite. Most units in the
commercial sector are packaged units. Field-erected units, for the most part,
are restricted to larger institutional facilities. Estimates of the total
number of commercial external combustion sources have been reported (10,14)
and, according to these estimates, there are approximately 1.5 million commer-
cial sources. Most of the smaller units (<13.2 GJ/hr) are cast iron or fire-
tube units, and only 5 percent of these smaller units are of watertube design.
Watertube units, however, constitute 100 percent of all units above 50 GJ/hr
input (14).
Air pollution control equipment is generally not installed on the smaller
commercial external combustion sources, although new burner designs, atomiza-
tion methods and furnace constructions are being studied to reduce emissions
of NO and particulates. Burner modulation during periods of fluctuating
X
demand, instead of on/off cycling, also reduces particulate and hydrocarbon
emissions from oil-fired sources (11).
3.5 INDUSTRIAL COMBUSTION SOURCES
Stationary external combustion sources used within the industrial sector
for electricity generation, production of steam for process heating, and space
heating can be classified according to the type of fuel used and furnace and
boiler design. Fuels used in industrial combustion systems include bituminous
coal, anthracite coal, lignite coal, wood, residual oil, distillate oil, and
natural gas. Pulverized dry bottom furnaces and stoker furnaces are the major
furnace designs used by the industrial sector for the combustion of bituminous
coal. Stoker furnaces predominate for wood-fired combustion sources and for
the combustion of lignite and anthracite coals. Although a large percentage
of industrial boilers are cast iron systems, these systems constitute only
about 7 percent of total industrial boiler capacity. Firetube boilers, in
which the combustion gases pass through tubes submerged in water, make up
about 24 percent of total industrial capacity. These units generally are
smaller than about 21 GJ/hr input capacity. Watertube boilers constitute
about 69 percent of the industrial boiler capacity. In a watertube system
the combustion gases transfer heat to tubes into which water is fed to be
13
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converted to steam. Boiler systems larger than about 53 GJ/hr input capacity
and systems with steam pressures exceeding about 65 kPa are almost exclusively
watertube systems.
There are approximately 500,000 industrial boilers in the United States
with an estimated capacity of about 4,000 TJ/hr. Natural gas is the primary
fuel, accounting for about 63 percent of the total industrial fossil fuel use
in 1978, while oil and coal account for about 18 percent and 15 percent, res-
pectively. Wood and other miscellaneous fuels are minor fuel sources. Total
fuel consumption by the industrial external combustion sources considered in
this study was 8700 PJ/yr in 1978, about 22 percent of total national fuel
consumption by the stationary combustion sources studied in this project. The
overall growth rate during the 1978-1985 period should be about 3 percent per
year. Coal consumption by 1985 could account for 30 percent of industrial
fuel use in 1985, if provisions of the National Energy Plan are fully imple-
mented. This increase, however, could be a gross overestimate because of the
influence of regulatory actions limiting, for example, sulfur content of the
coal fuel.
Air, water, and solid waste pollutants are emitted from many sources
constituting an industrial boiler facility. The major source of air emissions
is flue gas emissions from stacks. Other potential sources of air emissions,
depending on the size of the facility and the type of fuel burned, are ash
handling and storage, fuel handling and storage, and drifts and vapors from
cooling systems. Wastewater emission streams and sources of solid wastes vary
in number and volume, depending again on facility size and type of fuel burned.
Emphasis in this study was placed solely on air emissions from stacks, with
the exception of the characterization of bottom ash and fly ash from the
wood-fired systems tested in this study.
Air pollution control on industrial boilers is mainly directed at reducing
particulate flue gas emissions from solid fuel-fired sources. The estimated
overall efficiency of particulate removal in the industrial sector, based on
data in the National Emissions Data System (NEDS), is 81 percent for pulverized
units and 53 percent for stokers. Application of control measures for SO and
X
NO is not extensive in the industrial sector, but will increase with the pro-
A
mulgation of regulations for control of such emissions from industrial boilers.
14
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4. EXISTING EMISSIONS DATA BASE
A major task in this project has been the identification of gaps and
inadequacies in the existing data base. Decisions as to the adequacy of the
data base were made using criteria developed by considering both the reliabi-
lity and variability of the data. Estimated environmental risks associated
with the emission of each pollutant were also considered in the determination
of the need for, and extent of, the sampling and analysis program.
4.1 GAS- AND OIL-FIRED RESIDENTIAL HEATING SOURCES
The sources of emissions data for residential gas- and oil-fired systems
are limited at the present time to early data used to generate EPA emission
factors and more recent data developed by EPA contractors for criteria pollu-
tants. For gas-fired systems, the existing data base for sulfur dioxide (SO^h
nitrogen oxides (NO ), total hydrocarbons (HC), and carbon monoxide (CO)
A
emissions was adequate. However, the existing data base for particulate and
specific organic emissions was inadequate. For oil-fired systems, the
existing emissions data base for particulate, S09, NO , HC, and CO was ade-
£ A
quate, but inadequate for SO,, particulate sulfate, trace element, and organic
emissions.
4.2 INTERNAL COMBUSTION SOURCES
Air emissions from the flue gas stacks are the only significant emissions
from electricity generation and industrial gas turbines and reciprocating
engines.
The evaluation of emissions data has indicated that the existing emissions
data base was adequate for gas-fueled turbines and reciprocating engines. For
distillate oil-fueled gas turbines, the existing data base for NO , total
A
hydrocarbons, CO, particulate, S02 and SO^ emissions was adequate. However,
the existing data base for trace elements and specific organic emissions is
inadequate. For distillate oil reciprocating engines, the existing data base
for NOV, total hydrocarbons, CO, and S09 emissions was adequate. The existing
X £
15
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data base for particulates, SCL, trace elements and specific organic emissions
was found to be inadequate.
4.3 EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
For flue gas emissions, the status of the existing data base can be
summarized as follows:
t The existing data base for criteria pollutants was generally
adequate.
t For sulfuric acid emissions, the existing data base was
adequate for bituminous coal-fired boilers, residual oil-
fired boilers, and gas-fired boilers, and inadequate for ^
lignite-fired boilers. For emissions of primary sulfates,
the existing data base was adequate for pulverized bituminous
dry bottom and wet bottom boilers, residual oil-fired
boilers, gas-fired boilers, and inadequate for other com-
bustion source categories.
For emissions of particulates by size fraction and trace
elements, the existing data base was adequate for gas-fired
boilers and inadequate for all other combustion source
categories.
For emissions of specific organics and polycyclic organic
matter (POM), the existing data base was inadequate for all
combustion source categories.
Two other sources of air emissions of environmental concern are cooling
tower emissions and emissions from coal storage piles. The existing data
bases characterizing air emissions from these two sources were considered to
be inadequate, because past studies were primarily focused on the measurements
of a limited number of chemical constituents and total particulates. Emis-
sions from ash handling and storage and fuel handling are not addressed here
because characterization of these emissions is outside the scope of this
study.
For wastewater effluents from external combustion sources for electricity
generation, the existing data base was considered to be adequate for waste-
water from water treatment processes, and inadequate for all other streams.
This is because past studies were limited to the characterization of gross
parameters such as pH and total suspended solids (TSS) and a few inorganic
constituents. Organic characterization data were generally not available.
Primary sulfate refers to the sum total of SO., expressed as sulfate,
metallic sulfates, and ammonium sulfate.
16
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The evaluation of existing emissions data for solid wastes indicated the
inadequacy of the organic data base for coal fly ash and bottom ash, and the
inadequacy of the inorganic and organic data bases for FGD sludges. On the
other hand, the inorganic data base for coal ash was considered to be adequate
because of the adequate characterization of the inorganic content of coal.
Similarly, the data base for water treatment wastes was considered to be
adequate because the waste constituents are inorganic and can be estimated
from the raw water constituents and the treatment method used.
4.4 COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
Gaseous and particulate emissions from the flue gas stacks are emphasized
in the study of commercial/institutional combustion sources. Although some
of the larger institutional external combustion systems are local sources of
water pollution and fugitive particulate emissions 'from coal pile storage and
ash disposal, their contribution to the national water pollution and fugitive
emission burden is negligible. It is estimated, based on the amount of coal
consumed by the commercial/institutional sector, that they contribute less
than 1 percent of such emissions from all stationary combustion sources.
Evaluation of existing emissions data has indicated that the data base
for gas- and oil-fired external combustion sources, although limited, was
adequate for NO , HC, CO, particulate, and SO?. However, the existing data
A £
base for specific organic emissions for these sources was inadequate, and,
for the oil-fired sources, the existing data base for SO., and trace elements
was inadequate. Emissions data from solid fuel-fired sources were generally
inadequate for al.l pollutants.
In the case of oil-fired internal combustion sources, data were inadequate
for SO-,, trace element, and specific organic emissions. Data for gas-fired
reciprocating engines are adequate; however, one unit was tested in this pro-
gram to confirm data adequacy.
4.5 INDUSTRIAL COMBUSTION SOURCES
As in the case of commercial/institutional sources, gaseous and particu-
late emissions from the flue gas stacks are emphasized in the study of indus-
trial sources. The status of the existing data base for these emissions can
be summarized as follows:
-.17
-------
t The existing data base for criteria pollutants was generally
adequate, with the exception of emissions from wood-fired
combustion sources.
The existing data base for particulate sulfate and sulfuric
acid emissions was inadequate for the oil- and solid fuel-fired
combustion source categories.
The existing data base for particulates by size fractions and
trace elements was adequate only for gas-fired sources.
The existing data base for specific organics was inadequate
for all industrial source categories.
As noted previously, industrial boilers are also sources of water pollu-
tion and solid waste. However, these sources, particularly in the case of
large industrial boilers used for electricity generation, are similar to those
at electric utilities. These sources of pollution were characterized for
electric utilities earlier in this project.
18
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5. THE SOURCE MEASUREMENT PROGRAM
Because of the deficiencies in the existing emissions data base, source
tests were conducted at a selected number of sites for each of the five prin-
cipal combustion source categories. These source tests are described in the
following sections.
5.1 GAS- AND OIL-FIRED RESIDENTIAL HEATING SOURCES
Five gas-fired and five oil-fired residential sources were initially
selected for testing. The choice of specific sites within the two source
categories was based on the representativeness of the sites with respect to
such important system characteristics as burner type and age, firing rate, and
heating medium (hot air, hot water, and steam). Upon review of the results
obtained from the testing of the 10 sites, one gas-fired and two oil-fired
systems were subsequently tested to study the effect of cycle mode on organic
emissions. Level II analyses for S02» S03, and particulate sulfate were also
conducted at the two oil-fired sites.
5.2 INTERNAL COMBUSTION SOURCES
Eleven internal combustion sites were selected for testing to provide a
better characterization of the emissions associated with these sources. The
sites tested included one gas-fueled gas turbine, five distillate oil-fueled
gas turbines, and five distillate oil reciprocating engines (diesel engines).
A gas-fueled gas turbine site was included to assure that previously un-
identified pollutants are not being emitted in environmentally unacceptable
quantities. Specific sites were chosen based on the representativeness of the
sites as measured against the important characteristics of systems within each
source category, including engine model, rated capacity, age and pollution
control method.
Test results from the first phase were evaluated to determine the need
for and type of additional sampling and analysis. These evaluations led to
the recommendation of additional tests to determine SO-, and organic emissions
19
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from electricity generation distillate oil reciprocating engines. Level II
tests were subsequently conducted at three of the diesel engine sites previous-
ly tested.
5.3 EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Forty-six sites were selected for sampling and analysis of flue gas
emissions, and six sites were selected for sampling and analysis of air emis-
sions from cooling towers. The forty-six sites selected for flue gas sampling
and analysis include: three pulverized dry bottom, seven pulverized wet bottom,
six cyclone, and three stoker bituminous coal-fired boilers; three pulverized
dry bottom, two cyclone, and two spreader stoker Lignite-fired boilers; four
tangentially-fired and eight wall-fired boilers fueled with residual oil; and
three tangentially-fired and five wall-fired boilers fueled with natural gas.
At a selected number of these sites, wastewater streams and solid wastes
were also sampled and analyzed. Wastewater streams sampled and analyzed
included cooling tower blowdown, once-through cooling water, boiler blowdown,
fly ash pond overflow, bottom ash pond overflow, and combined ash pond over-
flow. Intermittent wastewater streams such as chemical cleaning wastes and
coal pile runoff were not sampled. Solid waste streams sampled and analyzed
included fly ash, bottom ash, and FGD scrubber sludge.
In addition to the modified Level I tests, comprehensive Level II tests
were also conducted for a bituminous coal-fired cyclone boiler, two bituminous
coal-fired pulverized dry bottom boilers, and an oil-fired boiler. All these
coal-fired boilers were equipped with flue gas desulfurization (FGD) systems.
The oil-fired boiler tested used off-stoichiometric firing and flue gas
recirculation for NOV control.
/\
Because direct measurements of chemical constituents present in cooling
tower exhausts have not been made except for a limited number of trace elements,
six cooling towers were selected for testing in this project. Cooling tower
streams sampled and analyzed included air emissions as evaporation and drift,
and blowdown.
20
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5.4 COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
Twenty-two external combustion systems were tested. These include: five
gas-fired, three distillate oil-fired, five residual oil-fired, three anthra-
cite stokers, three bituminous stokers, two bituminous pulverized dry units,
and one wood-fired stoker. Four oil-fired, one gas-fired, and one dual-fired
internal combustion reciprocating engines were also tested. Specific sites
were chosen based on the representativeness of the sites as determined by the
important system characteristics within each source category, including system
design, size, and age. Many of the sites tested fall within the commercial
size classification range, although some, particularly the pulverized
bituminous-fired units, greatly exceed the upper commercial size limit of
13.2 GJ/hr input capacity.
5.5 INDUSTRIAL COMBUSTION SOURCES
Twenty-two external combustion systems were tested. These include: ten
gas-fired, three distillate oil-fired, and five residual oil-fired boilers;
three bituminous pulverized wet bottom and two bituminous pulverized dry
bottom units; three bituminous stokers; and five wood-fired stokers. Specific
sites were chosen based on the representativeness of the sites as measured
against the important system characteristics within each source category,
including system design, size, and age.
21
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6. SAMPLING AND ANALYSIS
6.1 LEVEL I FIELD TESTING
The Source Assessment Sampling System (SASS) train, developed by EPA,
was used to collect both vapor and particulate emissions in quantities
sufficient for the wide range of analyses needed to adequately characterize
emissions from external combustion sources. Briefly, the SASS train (Figure
1) consists of a conventional heated probe, three cyclones and a filter in
a heated over which collect four particulate size fractions (>10ym, 3-10ym,
l-3ym, and S02 by GC
using a thermal conductivity detector. Detailed procedures for sampling and
analysis are described in the Methods and Procedures Manual for Sampling and
Analysis prepared for this project (15).
Water samples were generally taken by either tap sampling or dipper
sampling. Tap samples were obtained on contained liquids in motion or static
liquids in tanks or drums. This sampling method was generally applicable to
cooling tower blowdown or boiler blowdown. The method involved the fitting
of the valve or stopcock used for sample removal with a length of pre-cleaned
Teflon tubing long enough to reach the bottom of the container. The dipper
sampling procedure, applicable to sampling ponds or open discharge streams,
was used in the acquisition of ash pond discharge samples. The method in-
volved the use of dipper with a flared bowl and attached handle, long enough
22
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STACK
THERMOCOUPLE
ro
CO
FILTER
GAS COOLER
1
i
i
i
AJ .
GAS
TEMPERATURE
THERMOCOUPLE
DRY GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
OVEN
THERMOCOUPLE
XAD-2 / *£S/
CARTRIDGE ** ^
/^=l I
lUPLE/^/f
/ VWy
CONDENSATE
COLLECTOR
IMP/COOLER
TRACE ELEMENT
COLLECTOR
10 CFM VACUUM PUMPS
IMPINGER
THERMOCOUPLE
Figure 1. Schematic of Source Assessment Sampling System (SASS)
-------
to reach discharge areas. After sample recovery, water analyses using the
Hach kit were performed in the field to determine pH, conductivity, total
suspended solids (TSS), hardness, alkalinity or acidity, ammonia nitrogen,
cyanide, nitrate nitrogen, phosphate, sulfite and sulfate.
For solids sampling, the fractional shovel grab samples procedure was
used unless the plant had an automatic sampling system. The concept of
fractional shoveling involves the acquisition of a time-integrated grab
sample representative of overall process input or output during a given run
time period. A standard square-edged shovel, 12 inches wide, was used. For
streams entering or exiting a process operation, a full cross-stream cut
sample was taken from the belt on an hourly basis. Each hourly shovel sample
was added to a pile to eventually form a run time period composite. At the
conclusion of the run, this pile was coned and quartered to form a final
representative sample weighing from 2.3 to 4.5 kilograms. When plants were
equipped with automatic samplers to remove representative cross sections of
a stream while automatically forming a homogeneous composite, these were
used in preference to the shovel technique.
In addition to the above sampling methods, sampling for air emissions
from cooling towers was performed using a modified EPA Method 5 train with-
out the filter assembly.
6.2 MODIFIED LEVEL I LABORATORY ANALYSIS
The basic Level I schematic outlining flow of samples and analysis plans
for particulate and gaseous emissions is depicted in Figure 2. The corres-
ponding schematic for solid, slurry, and liquid samples is presented in
Figure 3. These schematics provide a general idea on the apportionment of
samples for analysis. For example, it is shown in Figure 2 that the probe
and cyclone rinses combination will only be subjected to inorganic analysis
if the dried sample exceeds 10 percent of the total cyclone and filter sample
weight. Details of the sample handling, transfer, and analysis procedures
can be found in the IERL-RTP Procedures Manual: Level I Environmental
Assessment (2). A brief description of inorganic and organic analyses
performed and the deviations from the basic Level I procedure follows.
24
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PROBE AND
CYCLONE
RINSES
SASS TRAIN GAS
CONDITIONER
CONDENSATE
SASS TRAIN
IMPINGERS
EXTRACTION
EXTRACTION
SAME AS ABOVE
NOV CHEMILUMINESCENCEI
.N.r^rAM.rcl ELEMENTS (SSMS) AND
INORGANICS] SELECTED ANIONSt
ONE-SITE GAS
CHROMATOGRAPHY
XAD-2
ABSCXBER,
MODULE RINSE
WEIGH
INDIVIDUAL
CATCHES
t IF INORGANICS
ARE GREATER THAN
10% OF TOTAL CATCH
ON-SITE GAS
CHROMATOGRAPHY
PHYSICAL SEPARATION
INTO LC FRACTIONS,
IR/LRMS
ELEMENTS (SSMS) AND
SELECTED ANIONS
ELEMENTS AND
SELECTED ANIONS
ELEMENTS (SSMS) AND
SELECTED ANIONS
PHYSICAL SEPARATION
INTO LC FRACTIONS. IR/LRMS
ORGANICS
PHYSICAL
SEPARATION
INTO LC FRACTIONS,
IR/LRMS
J INORGANICS I ELEM£NTS (SSMS) AND
*j INORGANICS | SELECTED ANIONS
ALIQUOT FOR GAS
CHROMATOGRAPHIC
ANALYSIS
PHYSICAL SEPARATION
INTO LC FRACTIONS, IR/LRMS
Figure 2. Basic Level 1 Sampling Flow and Analytical
Plan for Participates and Gases
-------
SOLIDS
SOURCE
SLURRIES
ro
CTi
LIQUIDS
LEACHABLE
MATERIALS
ORGANICS
INORGANICS
PHYSICAL SEPARATION
INTO LC FRACTIONS, IR/LRMS
ELEMENTS (SSMS) AND
SELECTED ANIONS
INORGANICS
ORGANICS
ELEMENTS (SSMS) AND
SELECTED ANIONS
PHYSICAL SEPARATION
INTO LC FRACTIONS, IR/LRMS
SUSPENDED
SOLIDS
H INORGANICS I CEMENTS (SSMS) AND
iNUKOANiibj SELECTED ANIONS
ORGANICS
PHYSICAL SEPARATION
INTO LC FRACTIONS, IR/LRMS
INORGANICS I ELEMENTS (SSMS) AND
INORGANICS I SELECTED ANIONS
SELECTED
WATER
TESTS
ORGANIC
EXTRACTION
OR DIRECT
ANALYSIS
ORGANICS
>C16
ORGANICS
-------
6.2.1 Inorganic Analyses
Level I analysis was used for all inorganic analyses. It was designed
to identify all elemental species in the SASS train fractions and to provide
semi quantitative data on the elemental distributions and total emission fac-
tors. The primary tool for Level I inorganic analysis is the Spark Source
Mass Spectrometry (SSMS). SSMS data were supplemented with Atomic Absorption
Spectrometry (AAS) data for Hg, As, and Sb and with specific ion electrode
determinations for chlorides.
The following SASS train fractions were analyzed for their elemental
composition: 1) the particulate filter, 2) the XAD-2 sorbent, and 3) a
composite sample containing portions of the XAD-2 module condensate and HNO-
rinse, and the first impinger solution. Analyses of the carbon, hydrogen,
nitrogen, oxygen, and trace element contents and heating values of the fuel
were also performed for the coal-fired and oil-fired sources.
6.2.2 Organic Analyses
Level I organic analyses provides data on volatile (boiling point range
of 90 to 300°C, corresponding to the boiling points of C7 - C,g n-alkanes and
reported as Cy - C,g) and non-volatile organic compounds (boiling point >300°C,
corresponding to the boiling points of >C,g n-alkanes and reported as >C,g)
to supplement data for gaseous organics (boiling point range of -160 to 90°C,
corresponding to the boiling points of C, - Cg n-alkanes and reported as C, -
Cg) measured in the field. Organics in the XAD-2 module condensate trap and
XAD-2 resin were recovered by methylene chloride extraction. SASS train
components including the tubing were carefully cleaned with methylene chloride
or methylene chloride/methanol solvent to recover all organics collected in
the SASS train.
Because all samples are too dilute to detect organic compounds by the
majority of instrumental techniques employed, the first step in the analysis
was to concentrate the sample fractions from as much as 1000 ml to 10 ml in
a Kuderna-Danish apparatus in which rinse solvent is evaporated while the
*
organics of interest are retained . Kuderna-Danish concentrates were then
evaluated by gas chromatography (GC), infared Spectrometry (IR), liquid
chromatography (LC), and gravimetric analysis, low resolution mass spectroscopy
Kuderna-Danish is a glass apparatus for evaporating bulk amounts of solvents.
27
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(LRMS), and sequential gas chromatography/mass spectrometry (GO/MS)*. The
extent of the organic analysis is determined by the stack gas concentrations
found for total organics (volatile and non-volatile). If the total organics
3
indicate a stack gas concentration below 500 yg/m , a liquid concentration
below 0.1 mg/1, or a solid concentration below 1 mg/kg, further analysis
is not conducted. If the concentrations are above these levels, a class
fractionation by liquid chromatography is conducted followed by GC and IR
analyses. Additionally, if the concentrations in a LC fraction are above
these levels, LRMS is conducted for that particular LC fraction.
6.3 LEVEL II SAMPLING AND ANALYSIS
In addition to the modified Level I tests, Level II tests were also
conducted at a selected number of sites. Level II sampling and analysis
techniques that have been employed for these sites included:
Continuous monitoring of NO emissions by chemiluminescent instrumen-
tation.
t Continuous monitoring of SOo emissions by pulsed fluorescent analyzer.
Determination of sulfate emissions by the Goksoyr-Ross Controlled
Condensation System.
t Determination of particle size distribution by Polarized Light Micro-
scopy (PLM) and MRI cascade impactor.
Determination of trace element concentrations by Atomic Absorption
Spectroscopy (AAS) and Inductively Coupled Plasma Optical Emission
Spectroscopy (ICP).
Identification of inorganic compounds from specific infared band
correlations by Fourier Transform IR (FTIR).
Identification of crystalline material in solid samples by X-ray
Diffraction (XRD).
Determination of the surface and sub-surface sulfur concentrations
and oxidation state of bulk samples by Electron Spectroscopy for
Chemical Analysis (ESCA).
Determination of the surface and sub-surface composition of bulk
samples by Secondary Ion Mass Spectrometry (SIMS).
Determination of elemental composition of single particles by Scanning
Electron Microscope with Energy Dispersive X-ray Fluroescence (SEM-
EDX).
The major modification in the Level I sampling and analysis procedure was
the addition of GC/HS analysis for POM.
28
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t Identification and quantification of non-POM organic compounds by GC/
MS.
Detailed discussions of these techniques and their applications could be found
in the group/categorty reports (3, 4, 5, 6, 7) and the following environmental
assessment and source test and evaluation reports:
Environmental Assessment of Coal-and Oil-firing in a Controlled
Industrial Boiler (16).
0 Environmental Assessment of a Coal-fired Controlled Utility Boiler (17)
Environmental Assessment of an Oil-fired Controlled Utility Boiler (18)
0 Source Test and Evaluation Report: Dean H. Mitchell Unit No. 11,
Northern Indiana Public Service Co. (19).
Source Test and Evaluation Report: Cane Run Unit No. 6, Louisville
Gas and Electric Co. (20).
29
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7. RESULTS
7.1 GAS-AND OIL-FIRED RESIDENTIAL HEATING SOURCES
The results of the field measurement program along with supplementary
values for certain pollutants obtained from the existing data base are sum-
marized in Table 2. Ambient severity factors, defined as the ratio to an
ambient air quality level or hazard factor, are also listed in Table 2. The
hazard factor for noncriteria pollutants is a reduced threshold limit value
(TLV), while for criteria pollutants it is the ambient air quality standard.
The TLV is reduced by a factor of 300 (24/8 x 100) to account for length of
exposure (24 hrs vs 8 hrs) and an added safety factor of 100 due to the higher
susceptibility of the general' population to exposure effects. A severity factor
of greater than 0.05 is indicative of a potential problem requiring further atten-
tion. The "greater than 0.05" criterion reflects an uncertainity factor of 20 in
the calculation of ambient severity, because of potential errors introduced in the
application of the dispersion model, and in Level I sampling and analysis.
Severity factors calculated from emission data acquired in this project
or, in the case of pollutants not measured in this project, from EPA (AP-42)
emission factors (21) are shown for a single source and for multiple sources.
Maximum ground level concentrations for multiple sources were determined using
a dispersion model for an array of 1000 sources. The model assumes a Class C
stability (slightly unstable) and a windspeed of 4.5 m/sec (10 mph). Using a
grid of houses 80 x 80 m and the average stack parameters found in this study,
the maximum ground level concentrations determined by the model were about
25 times greater than those from a single source. As shown in Table 2,
multiple source severity factors for several pollutants (NO for gas-fired
J\
sources and NO , SOV and Ni for oil-fired sources) exceed 0.05, a value which
A
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TABLE 2. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT FOR RESIDENTIAL SOURCES
Gas-fired Sources
Pollutant Emission Ambient Multiple
Factor Severity Source
(ng/J) Factor Severity
Factor
NO 33 2.8 x 10"3 7.0 x 10"2
x
Total , 2.6 1.0 x 10"4 2.5 x 10"3
Hydrocarbons
CO 8.4 1.6 x 10"6 4.0 x 10'5
Particulate 1.0 1.7xlO'5 4.3xlO"4
SO,* 0.26 3.2 x 10'6 8.0 x 10"5
2
SO, ND ND ND
Trace
Elements
Lead - - -
Cadmium -
Copper -
Nickel -
Chromium
Organics
Total Volatile 1.7 NA NA
(crc16)
Total Nonvolatile 0.8 NA NA
Emission
Factor
(ng/J)
55
9.2
15
3.1
106
5.9
7.5 x 10"2
o
2.2 x 10
0.25
0.49
5.5 x 10"2
7.7
1.5
Oil-fired
Sources
Ambient
Severity
Factor
6.2 x
5.3 x
4.2 x
7.7 x
1.9 x
1.6 x
1.0 x
1.0 x
2.4 x
10 x
1.0 x
NA
NA
io-3
ID'4
io-b
io-b
io-3
10"2
io-3
10
io-3
ID'3
io-3
Multiple
Source
Severity
Factor
1.6 x 10"1
1.3 x IO"2
1.1 x 10"4
1.9 x 10"3
4.8 x 10"2
4.0 x 10"1
17 x 10"3
_T
23 x 10 J
12 x 10"3
250 x 10"3
25 x 10"3
NA
NA
Based on fuel sulfur content of 3.2 ppmv (2000 grains/10 ft ) for gas and 0.25 weight percent
for oil.
Multiple source severity factors for all elements dashed (-) or not listed were less than 0.01.
Upper bound values of emissions were used to calculate severity for oil-fired sources.
ND - No Data.
NA - Not applicable. Seventy factors for C.-C., and >C1fi organics were not computed because
there is no representative TLV for either group.
-------
nitude below levels that are considered hazardous. Compounds considered
particularly hazardous, such as benzo(a)pyrene and dibenz(a,h)anthracene, were
3
not found above the detection limit of 0.05 yg/m .
In contrast with earlier studies, a change in the on/off cyclic mode of
burner operation from a 50 minute on/10 minute off cycle to a 10 minute on/
20 minute off cycle did not result in increased hydrocarbon (or POM) emissions.
7.2 INTERNAL COMBUSTION SOURCES
The results of the field measurement program along with supplementary
values for certain pollutants obtained from the existing data base are summa-
rized in Tables 3 and 4.
Tables 3 and 4 also list ambient severity factors, defined as the ratio
of the calculated maximum ground level concentrations of the pollutant species
to the level at which a potential environmental hazard exists. As can be seen
from tables 3 and 4, the most significant pollutant from internal combustion
turbines and reciprocating engines is nitrogen oxides. For reciprocating engines,
emissions of total hydrocarbons are also significant, especially in the case
of gas-fueled engines. Ambient severity factors for S02 emissions from diesel
engines, and for S03 emissions (in the form of sulfuric acid vapor and aero-
sols) from oil-fueled gas turbines and reciprocating engines are all greater
than 0.05, indicating the environmental significance of emissions of sulfur
species.
Trace element emissions from the gas-fueled gas turbine tested were in--
significant. For oil-fueled gas turbines and reciprocating engines, sodium,
calcium, nickel, copper, iron, zinc, silicon-were the trace elements
emitted in the largest quantities. Nickel, copper and phosphorus were found
to be the only trace elements with severity factors greater than 0.05.
Data for polycyclic organic matter (POM) emissions obtained by GS/MS are
not reported in the summary tables. POM was not detected in the emissions
from the one gas fueled gas turbine and the five distillate oil-fueled gas
turbines tested. POM emissions from the five diesel engines tested were found
to be mostly naphthalenes and substituted naphthalenes. Emissions of these
organic species resulted in calculated ambient severity factors which were all
32
-------
CO
CO
TABLE 3. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT
FOR GAS-FUELED INTERNAL COMBUSTION SOURCES
Gas-Fueled Gas Turbines
Pollutant
NOX
*
Total Hydrocarbons
CO
Particulate
S02
Elec.
Emission
Factor
(ng/J)
168
23.2
64.8
5.1
0.26
Gen.
Ambient
Severity
Factor
0.17
0.020
0.0003
0.0019
<0.0001
Industrial
Emission
Factor
(ng/J)
130
8.6
48.8
5.1
0.26
Ambient
Severity
Factor
0.52
0.025
0.0007
0.0062
<0.0001
Gas Reciprocating Engines
Elec.
Emission
Factor
(ng/J)
1549
528
340
5.7
0.26
Gen.
Ambient
Severity
Factor
7.1
1.7
0.0051
0.0068
0.0002
Industrial
Emission
Factor
(ng/J)
1549
528
340
5.7
0.26
Ambient
Severity
Factor
5.7
1.3
0.0040
0.0055
0.0002
*0ne single data point indicates that 90% of the organics emitted from gas-fueled gas turbines are
volatile (Ci-Cjc) and only 10% are nonvolatile (>C,g).
-------
TABLE 4. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT
FOR OIL-FUELED INTERNAL COMBUSTION SOURCES
CO
Distillate Oil-Fueled Gas Turbines
Pollutant
NOX
Total Hydrocarbons
CO
Particulate
so2
so3
'Trace Elements
Copper
Nickel
Phosphorus
Organics
Total Volatile
(crc16)
Total Nonvolatile
(>c16)
Elec.
Emission
Factor
(ng/J)
311
17.5
43.8
13.0
33.1
1.5
0.58
0.53
0.13
12.1
5.4
Gen.
Ambient
Severity
Factor
0.32
0.015
0.0002
0.0049
0.0089
0.056
0.085
0.16
0.037
NA
NA
Industrial
Emission
Factor
(ng/J)
207
3.6
101
13.0
33.1
1.5
0.58
0.53
0.13
ND
ND
Ambient
Severity
Factor
0.83
0.010
0.0014
0.016
0.029
0.18
0.28
0.51
0.12
NA
NA
Distillate Oil Reciprocating
Elec.
Emission
Factor
(ng/J)
1392
52
266
14.1
101
1.8
0.45
0.56
0.097
18
34
Gen.
Ambient
Severity
Factor
6.4
0.16
0.0040
0.019
0.097
0.23
0.23
0.60
0.10
NA
NA
Engines
Industrial
Emission
Factor
(ng/J)
1392
52
266
14.1
101
1.8
0.45
0.56
0.097
ND
ND
Ambient
Severity
Factor
5.1
0.13
0.0032
0.015
0.077
0.18
0.20
0.48
0.082
NA
NA
ND- No Data
NA - Not Applicable. Severity factors for C,-Cjg and >C-,g organics were not computed because there is
!l no representative TLV for either group.
-------
well below 0.05. Again, POM compounds known to be carcinogenic were not found
o
above the detection limit of 0.05 yg/m .
7.3 EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Air Emissions
The results of the field measurement program for flue gas emissions from
utility boilers, along with supplementary values for certain pollutants
obtained from the existing data base, are presented in Tables 5, 6, and 7.
Also listed in these tables are ambient source severity factors, defined as
the ratio of the calculated maximum ground level concentrations of the
pollutant species to the level at which a potential environmental hazard
exists.
As can be seen from Tables 5, 6, and 7 the major criteria pollutants of
concern are nitrogen oxides from all combustion source categories, and sulfur
dioxide from all but gas-fired combustion sources. Ambient severity factors
are also greater than 0.05 for controlled particulate emissions from bitumi-
nous coal-fired and lignite-fired sources, uncontrolled particulate emissions
from residual oil-fired sources, and total hydrocarbon emissions from bitumi-
nous coal-fired boilers, lignite-fired pulverized dry bottom and
cyclone boilers, residual oil and gas tangentially-fired boilers, indicating
the environmental significance of the emissions of these pollutants. Emis-
sions of carbon monoxide from utility boilers do not appear to be a problem.
Additionally, ambient severity factors for emissions of SO., (in the form of
sulfuric acid vapor and aerosols) and particulate sulfate from all coal-fired
and oil-fired utility boilers are greater than 0.05. The environemental
problems associated with emissions of nitrogen oxides, sulfur dioxide, and
particulate from utility boilers are well known. On December 23, 1971, EPA
issued the original New Source Performance Standards (NSPS) to limit emissions
of these pollutants from power plants. The Clean Air Act Amendments, enacted
August 7, 1977, required EPA to reivse its 1971 standards for power plants to
reflect advances in control technology. On June 11, 1979, EPA promulgated
the revised NSPS to further limit emissions of nitrogen oxides, sulfur dioxide,
and particulate matter from power plants.
35
-------
TABLE 5. SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS
FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
OJ
Pollutant
NO
X
Total Hydrocarbons
CO
Participates (Controlled)
S02 (Uncontrolled)
so3
Participate Sulfate (Controlled)
Trace Elements*
Aluminum
Beryl 1 ium
Calcium
Chlorine
Fluorine
Iron
Lead
Lithium
Nickel
Phosphorus
Silicon
POM
Dibenz(a ,h)anthracene
Benzo( a ) pyrene/Benzo ( e ) py rene
Total POM
Organics
Total Volatile (C -C ,)
Total Nonvolatile (=£,(;)
Pulverized
Emission
Factor
(ng/J)
259*, 379f
4.5
17
251
1,407
13.9
0.72
8.5
0.0022
5.6
33.9
4.1
8.4
0.039
0.024
0.062
0.11
15.2
0.00022
BD
0.0039
2.1
2.4
Dry Bottom
Ambient
Severity
Factor
1.95*, 2.85t
0.027
0.0005
0.66
2.64
3.50
0.15
0.53
0.23
0.12
1.03
0.34
0.22
0.053
0.23
0.13
0.22
0.31
0.50
NA
NA
NA
NA
Pulverized
Emission
Factor
(ng/J)
380
4.5
86
213
1,407
13.9
2.9
6.9
0.0018
4.6
33.9
4.1
6.8
0.031
0.020
0.050
0.086
12.4
BD
0.0035
0.042
3.8
0.8
Wet Bottom
.Ambient
Severity
Factor
1.70
0.016
0.0015
0.33
1.57
2.09
0.37
0.16
0.11
0.056
0.61
0.20
0.11
0.026
0.11
0.06
0.11
0.15
NA
21
NA
NA
NA
Cyclone
Emission
Factor
(ng/J)
678
9.5
82
57
1,407
14.1
10.8
1.4
0.00037
0.95
33.9
4.1
1.4
0.0066
0.0041
0.011
0.018
2.6
BO
BD
0.0059
8.3
1.2
Ambient
Severity
Factor
6.36
0.072
0.0030
0.19
3.29
4.45
2.84
0.071
0.048
0.025
1.28
0.42
0.047
0.011
0.048
0.027
0.046
0.066
NA
NA
NA
NA
NA
Stokers
Emission
Factor
(ng/J)
241
11
157
603
1,407
13.9
10.5
2.6
0.0055
2.6
33.9
4.1
20.9
0.61
0.011
1 .4
0.55
8.7
BD
BD
0.015
5.8
5.2
Ambient
Severity
Factor
0.13
0.0048
0.0003
0.12
0.19
0.26
0.16
0.008
0.041
0.004
0.075
0.024
0.040
0.061
0.008
0.211
0.083
0.013
NA
NA
NA
NA
NA
BD - Below detection limit. Detection limit for POM was 0.3 ug/m or approximately 0.001 ng/J.
NA - Not applicable.
*For tangentially-fired pulverized bituminous dry bottom boilers.
For wall-fired pulverized bituminous dry bottom boilers.
TFor pulverized dry bottom, pulverized wet bottom, and cyclone boilers, the trace element factors presented are for units equipped
with electrostatic precipitators. For stokers, the trace element emission .factors presented are for units equipped with multiple
cyclones.
-------
TABLE 6. SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS FROM LIGNITE-FIRED UTILITY BOILERS
- CO
--J
Pollutant
NOX
Total Hydrocarbons
CO
Particulates (Controlled)
S02 (Uncontrolled)
S03
Particulate Sulfate (Controlled)
*
Trace Elements ,
Aluminum
Barium
Beryllium
Calcium
Copper
Fl uori ne
Magnesium
Nickel
Phosphorus
POM
Biphenyl
Trimethyl propenyl naphthalene
Organics
Total Volatile (Cj-Cjg)
Total Nonvolatile (>C,g)
Pulverized
Emission
Factor
(ng/J)
. 260
9.0
33
62
628
ND
0.82
0.068
<0.025
<0.001
0.39
<0.030
0.24
<0.22
<0.068
<0.034
BD
0.0033
7.1
1.9
Dry^ Bottom
Ambient
Severity
Factor
4.28
0.12
0.002
0.36
2.57
ND
0.38
0.006
<0.023
<0.23
0.017
<0.068
0.044
<0.016
<0.31
<0.16
NA
0.0001
NA
NA
Cyclone
Emission
Factor
(ng/J)
333
4.7
33
132
628
ND
0.49
<0.067
<0.037
<0.0003
<1 .5
0.013
0.80
. <0.16
<0.047
<0.013
0.00002
0.00034
4.1
0.6
Ambient
Severity
Factor
5.33
0.061
0.002
0.74
2.50
ND
0.22
<0.006
<0.032
<0.066
<0.067
0.029
0.14
<0.011
<0.21
<0.055
<0.0001
<0.0001
NA
NA
Stokers
Emission
Factor
(ng/J)
195
3.2
65
615
628
ND
47.6
15.2
2.0
0.0059
< 140
0.083
0.42
< 27
0.28
1.5
BD
0.0032
2.3
0.9
Ambient
Severity
Factor
0.14
0.002
0.0002
0.15
0.11
ND
0.93
0.056
0.076
0.057
<0.27
0.008
0.003
<0.085
0.053
0.30
NA
<0.0001
NA
NA
ND - No data.
BD - Below detection limit. Detection limit for POM was 0.3 pg/m or approximately 0.0001 ng/J. However,
lower detection limits were obtained for less complex samples with fewer interferences or closely
eluting GC peaks.
NA - Not applicable.
*
For pulverized dry bottom and cyclone boilers, the trace element emission factors presented are for
units equipped with electrostatic precipitators. For stokers, the trace element emission factors
presented are for units equipped with multiple cyclones.
-------
TABLE 7 SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS
FROM RESIDUAL OIL- AND GAS-FIRED UTILITY BOILERS
co
CO
Residual Oil
Pollutant
NOX
Total Hydrocarbons
CO
Parti culates
SO? (Uncontrolled)
S03
Particulate Sulfate
Trace Elements
Beryllium
Chlorine
Copper
Lead
Magnesium
Mercury
Nickel
Phosphorus
Selenium
Vanadium
POM
Benzopyrenes/
perylenes
Total POM
Organics
Total Volatile
(c,-c16)
Total Nonvolatile
Tangential
Emission
Factor
(ng/J)
114
4.6
56
30
448
13.8
3.3
0.0024
3.1
0.35
0.034
2.4
0.0015
0.43
0.13
0.025
3.7
6. 25x1 O"7
0.0047
4.2
0.4
Firing
Ambient
Severity
Factor
1.90
0.060
0.0035
0.17
1.79
7.43
1.48
0.52
0.20
0.77
0.098
0.18
0.013
1.90
0.57
0.056
3.22
0.014
NA
NA
NA
Wall
Emission
Factor
(ng/J)
190
4.6
56
30
448
13.8
3.3
0.0024
3.1
0.35
0.034
2.4
0.0015
0.43
0.13
0.025
3.7
6.25xlO"7
0.0047
4.2
0.4
Fi ri ng
Ambient
Severity
Factor
1.17
0.022
0.0013
0.061
0.66
2.76
0.55
0.19
0.072
0.29
0.036
0.065
0.005
0.71
0.21
0.021
1.19
0.005
NA
NA
NA
Tangential
Emission
Factor
(ng/J)
124
2.4
33
0.25
0.25
ND
ND
BD
2.9
0.021
BD
BD
0.0049
0.042
0.070
BD
BD
BD
BD
2.1
0.3
Natural Gas
Fi ri ng
Ambient
Severi ty
Factor
3.21
0.047
0.0031
0.0021
0.0015
ND
ND
NA
0.29
0.069
NA
NA
0.064
0.28
0.46
NA
NA
NA
NA
NA
NA
Wall
Emission
Factor
(ng/J)
233
2.4
33
0.25
0.25
ND
ND
BD
2.9
0.021
BD
BD
0.0049
0.042
0.070
BD
BD
BD
BD
2.1
0.3
Firing
Ambient
Severi ty
Factor
2.94
0.024
0.0015
0.0010
0.0007
ND
ND
NA
0.14
0.034
NA
NA
0.031
0.14
0.23
NA
NA
NA
NA
NA
NA
BD - Below detection limit. Detection limit for POM was typically 0.3 pg/m or approximately 0.0001
ng/J. However, lower detection limits were obtained for less complex samples with fewer inter-
ferences or closely eluting GC peaks.
NA - Not applicable.
-------
Participate size distribution data acquired in the current study showed
that for bituminous coal-fired utility boilers equipped with electrostatic
precipitators, the >10 ym fraction accounted for 1.4 to 82 percent of the
total particulate emissions. For lignite-fired utility boilers equipped with
multiclones the >10 ym fraction contributed from 50 to 59 percent of the
total particulate emissions. An average of less than 15 percent of the
particulate emissions from uncontrolled residual oil-fired utility boilers
were >10 ym in size.
Trace element data summarized in Tables 5, 6, and 7 are for elements
associated with ambient severity factors greater than 0.05 in at least one
of the source subcategories (e.g., pulverized dry bottom boilers firing
bituminous coal).* Among the trace elements, emissions of beryllium, nickel,
and phosphorus appear to be a common concern for bituminous coal-fired,
lignite-fired and residual oil-fired sources. An unusual result is that for
gas-fired utility boilers, chlorine, copper, mercury, nickel, and phosphorus
were found to have ambient severity factors greater than 0.05. The validity
of these observations will require confirmation by Level II tests.
Data for polycyclic organic matter (POM) indicated the presence of
dibenz(a,h)anthracene in pulverized bituminous dry bottom boilers, and
benzo(a)pyrene/benzo(e)pyrene in pulverized wet bottom boilers. Both
dibenz(a,h)anthracene and benzo(a)pyrene are active carcinogens. A benzo-
pyrene, possibly benzo(a)pyrene, was also detected at a residual oil-fired
site. The only POM compounds detected at lignite-fired sites were biphenyl
and trimethyl propenyl naphthalene, neither of which is known to be
carcinogenic. No POM was detected at gas-fired utility sites. The detection
3
limit for POM was typically 0.3 yg/m , or approximately 0.1 pg/J.
Air emissions of chlorine, phosphorus, and magnesium from cooling towers
are of the same order of magnitude as those from residual oil-fired utility
boilers and of environmental concern. Based on thermal energy input to the
associated power plants, the mean emission factors for chlorine, phosphorus,
and magnesium were determined to be 2.4 ng/J, 0.22 ng/J, and 0.56 ng/J,
*
Data for 55 to 60 additional trace elements were available from SSMS analysis,
39
-------
respectively. The high emission rates for chlorine and phosphorus were due
to the use of chlorine and phosphate additives. The high emission rate for
magnesium was due to the high solids content in the source of cooling water
at one site.
All six cooling towers tested employed sulfuric acid as an additive.
Sulfate emissions from these cooling towers ranged from 3 to 41 ng/J. By
comparison, controlled sulfate emissions from coal-fired utility boilers and
sulfate emissions from oil-fired utility boilers are typically in the 20 to
30 ng/J range.
Wastewater Effluents
The results of sampling and analysis for cooling tower blowdown, boiler
blowdown, and ash pond overflow in this program were combined with existing
data and summarized in Table 8. Also listed in this table are discharge
severities, defined as the ratio of discharge concentration to the health
based water Minimum Acute Toxicity Effluent (MATE) value. A discharge
severity greater than 1.0 is indicative of a potential hazard requiring further
characterization or development of improved control technology. The "greater
than 1.0" criterion instead of the "greater than 0.05" criterion for ambient
severity was used because calculation of discharge severities was based on
conservative MATE values. Also, the uncertainty in the calculated values only
involved potential sampling and analysis errors. The error due to the applica-
tion of dispersion models was no longer a component.
Other wastewater effluents, including water treatment wastewater, chemical
cleaning wastes, FGD wet scrubber wastewater, and coal pile runoff, were not
sampled in this project. Characterization data for these wastewater streams,
based on results of previous studies reported in the literature, are summarized
in Table 9. In both Tables 8 and 9, data for wastewater constituents with
discharge severities less than 1.0 are not presented. Also, data for once-
through cooling water are not included in Tables 8 and 9, as discharge severities
for all constituents in this wastewater stream are extremely low.
Also known as Discharge Multimedia Environmental Goal (DMEG). MATE values are
given in Reference 22.
40
-------
TABLE 8. SUMMARY OF ASSESSMENT RESULTS FOR COOLING TOWER SLOWDOWN,
. BOILER SLOWDOWN, AND ASH POND OVERFLOW
Constituent
Gross Parameters
PH
Conductivity,
pinhos/cm
Hardness,
(as CaCOO, mg/1
Alkalinity
(as CaC07), mg/1
TSS, mg/1
BOD, mg/1
COD, mg/1
Trace Elements, mg/1
Arsenic
Calcium
Cadmium
Chromium
Iron
Magnesium
Manganese
Nickel
Phosphorus
Selenium
Silicon
Chloride, mg/1
Sulfate, mg/1
Phenols, mg/1
Organics, mg/1
Total volatile
(C7- C16)
Total nonvolatile
(>Ci6)
Cooling Tower
Effluent
Concentration
7.3
3,050
1,220
56
26
18
94
0.28
1,700
0.094
0.48
1.8
650
0.30
9.9
0.081
---
1,300
0.021
1.41
Blowdown
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
1.1
0.89
1.9
1.9
1.2
1.4
1.2
6.6
1.6
...
1.0
NA
NA
Boiler Blowdown
Effluent
Concentration
10.5
150
340
97
87
3.0
53
8.0
.--
0.026
1.3
4.7
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
5.3
.--
5.2
NA
NA
Fly Ash Pond
Effluent
Concentration
5.8
10,000
220
30
49
ND
NO
8.7
1.2
0.25
0.40
.-.
0
0.056
Overflow
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
35
0.80
1.0
1.8
--.
NA
NA
Bottom Ash Pond Overflow
Effluent
Concentration
7.4
6,000
205
62
41
ND
ND
2.2
2.5
410
0.19
0.007
0.090
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
8.9
1.7
0.85
0.76
---
NA
NA
Combined Ash Pond Overflow
Effluent
Concentration
9.2
480
185
81
33
ND
ND
0
0.070
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
NA
NA
ND - No data because analysis for these parameters was not performed.
NA - Not applicable because there are no MATE values associated with these parameters to compute discharge severities.
"-" . Data for constituents with discharge severities less than 1.0 are not presented.
-------
TABLE 9. SUMMARY OF ASSESSMENT RESULTS FOR WATER TREATMENT WASTEWATER, CHEMICAL CLEANING WASTES,
WET SCRUBBER WASTEWATER, AND COAL PILE RUNOFF
Hater Treatment Wastewater
Constituent
Gross Parameters
pH
Hardness
(as CaCOa), mg/1
Alkalinity
(as CaC03), mg/1
TSS. mg/1
BOO, mg/1
COO. mg/1
Trace Elements, mg/1
Aluminum
Beryllium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Selenium
Sod i utn
Zinc
Chloride, mcj/1
Sulfate, mg/1
Ammonia, mg/1
Hydrazine, mg/1
Phenols, mg/1
Ion Exchc
Effluent
Concentration
ND
1,000
560
32
36
18
0.27
4.2
3,200
__.
1,800
inge
Discharge
Severity
NA
NA
NA
NA
NA
NA
1.0
2.8
4.0
_._
1.5
...
Clarification
Effluent Discharge
Concentration Severity
ND NA
3,300 NA
340 NA
25,200 NA
20 NA
160 NA
160 1.1
0.61 2.4
350 233
0.32 1.5
...
Acid Phase C
Effluent
Concentration
1.1
ND
ND
45
ND
2,870
2.9
15
2,880
2.1
19
178
35
48
0.044
.omposite
Discharge
Severity
NA
NA
NA
NA
NA
NA
12
3.0
1,920
8.2
77
809
23
1.9
8.8
Chemical Cleaning Uastes
AUaline Phas<
Effluent
Concentration
ND
ND
ND
67
ND
90
530
2.4
1.6
143
...
2,740
...
! Composite
Neutral izati
Discharge Effluent
Severity Concentration
NA
NA
NA
NA
NA
NA
106
1.6
7.1
95
-__
10
...
11.4
ND
ND
47
ND
70
5.1
7.3
755
0.060
...
0.013
ion Drain
Discharge
Severity
NA
NA
NA
NA
NA
NA
1.0
4.8
503
1.3
...
5.7
Wet Scrubber Hastewater
Effluent
Concentration
7.5
ND
108
ND
NO
185
0.04
580
0.85
0.044
0.50
0.59
1,100
...
2.500
4,700
...
Discharge
Severity
NA
NA
NA
NA
NA
NA
1.3
1.2
3.4
4.4
2.3
12
1.4
...
2.1
3.6
...
Coal Pile Runoff
Effluent Discharge
Concentration Severity
2.7
ND
ND
330
ND
ND
150
0.03
660
33
1.5
...
___
NA
NA
NA
NA
NA
NA
1.0
1.0
440
131
6.6
...
...
Sludge liquor from lime/limes tone FGD scrubber.
ND - No data.
NA - Not applicable because there are no HATE values associated with these parameters to compute
discharge severities.
'« - Data for constituents with discharge severities less than 1.0 are not presented.
-------
The summary data presented in Tables 8 and 9 show that cooling tower
blowdown, clarification wastewater, chemical cleaning wastes, FGD wet scrubber
wastewater, and coal pile runoff all contain a significant number of consti-
tuents with discharge severities greater than 1.0. The pollutants of most
concern are copper, iron, manganese, nickel, and phosphorus. Based on dis-
charge severities, the boiler blowdown and ash pond overflow streams appear
to be less environmentally significant. Of all the wastewater streams
investigated, the ash pond overflows are the only streams which have been
subjected to treatment by sedimentation. If all the other wastewater streams
were also sent to settling ponds before release, their discharge severities
should also be considerably lower.
The average organic levels in the wastewater streams sampled were less
than 6 mg/1. POM compounds were not found above the detection limit of 2 ug/1.
Solid Wastes
A number of fly ash and bottom ash samples from bituminous coal-fired and
lignite-fired utility boilers were acquired and analyzed in this project. The
analysis results, supplemented by additional data from the existing literature,
are summarized in Table 10. Discharge severities presented in the same table
are defined as the ratio of concentration in the solid to the health based
solid MATE value. Data for ash trace element constituents with discharge
severities less than 1.0 are not presented.
The data on fly ash and bottom ash show that from 11 to 16 of the trace
element constituents in ash have discharge severities greater than 1.0. The
pollutants of most concern are aluminum, arsenic, calcium, chromium, iron,
manganese, nickel, potassium, and silicon. Also, the concentrations of
arsenic, barium, boron, calcium, and magnesium in lignite ash appear to be
substantially higher than the concentrations of these elements in bituminous
coal ash.
Most of the organics in fly ash and bottom ash are present as the >C,g
fraction. POM compounds were found in only two of the samples above the
detection limit of 2 ppm. Even for these two samples, the POM compounds
detected were naphthalene, alkyl naphthalenes and other compounds with high
MATE values and do not appear to pose a potential hazard.
43
-------
TABLE 10. SUMMARY OF ASSESSMENT RESULTS FOR FLY ASH AND BOTTOM ASH
FROM BITUMINOUS COAL-FIRED AND LIGNITE-FIRED BOILERS
Pollutant
Trace Elements
Al um1 num
Arsenic
Barium
Boron
Calcium
Chromium
Cobalt
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Potassium
Selenium
Silicon
Organ) cs
Total volatile
(C1-C16>
Total nonvolatile
(>C]g)
Bituminous
Concentration
(ppm)
4.300-100,000
3-240
280-640
25-700
1.100-121,000
19-300
7- 57
32.000-143,000
7-110
46- 86
820- 13,400
100-300
0.01 - 28
10-250
82- 5.100
2,900- 20,000
4- 32
17,000-276,000
<14- 87
0-420
Fly Ash
Discharge
Severity
0.27 -6.3
0.06 -4.8
0.28 -0.64
0.003 -0.075
0.023 -2.5
0.38 -6.0
0.047 -0.38
110 - 480
0.14 -2.2
0.66 -1.2
0.046 -0.74
2.0 -6.0
0.0005-1.4
0.22 -5.6
0.027 -1.7
0.69 -4.8
0.4 -3.2
0.57 -9.2
NA
NA
Bituminous
Concentration
(ppm)
3,700- 90.000
1- 18
220-450
5.5 -300
3.100- 93,000
15-220
4- 31
47,000-213,000
6-120
3- 60
1.300- 12,400
37-860
0.1 - 0.5
0.3 -100
120- 3,800
1,000- 15,800
<1- 5.6
7,500-276,000
<14- 87
0-900
Bottom Ash
Discharge
Seven ty
0.23 -5.6
0.02 -0.36
0.22 -0.45
0.0006-0.032
0.065 -1.9
0.30 -4.4
0.027 -0.21
160 - 710
0.12 -2.4
0.043 -0.86
0.072 -0.69
0.74 - 17
0.005 -0.025
0.007 -2.2
0.04 -1.3
0.24 -3.8
<0.1 -0.56
0.25 -9.2
NA
NA
L1qn1te Fly Ash
Concentration
(ppm)
3,500- 35,000
79-830
1,200- 15,000
320- 13.000
27.000-130,000
8.1 - 64
7.1 - 1,200
1,000- 11,000
9.3 -160
1.3 - 62
17,000- 32,000
200- 1,300
0.086- 2.0
21- 1,600
120- 4,600
1,200- 30,000
<2.1 - 19
34,000- 53,000
0.5 - 15
43-300
Discharge
Severity
0.22 -2.2
1.6 - 17
1.2 - 15
0.034 -1.4
0.56 -2.7
0.16 -1.3
0.047 -8.0
3.3 - 37
0.19 -3.2
0.019 -0.89
0.94 -1.8
4.0 - 26
0.0043-0.1
0.47 - 36
0.04 -1.5
0.29 -7.1
<0.21 -1.9
1.1 -1.8
NA
NA
Lignite Bottom Ash
Concentration
8.100- 27,000
22-400
2,100- 20,000
490- 6,300
63.000-130,000
5.1 - 22
6- 11
27,000- 71,000
4.3 -150
3.8 - 79
4,600- 35,000
310- 1,000
<0.017- 0.094
44-140
110- 5,200
660- 15,000
1.3 - 5.5
31,000- 50,000
0.9 - 11
150-300
Discharge
Severity
0.51 -1.7
0.44 -8.0
2.1 - 20
0.053-0.68
1.3 -2.7
0.10 -0.44
0.04 -0.073
90 - 240
0.086-3.0
0.054-1.1
0.26 -1.9
6.2 - 20
<0.001-0.0047
0.93 -3.1
0.037-1.7
0.16 -3.6
0.13 -0.55
1.0 -1.7
NA
NA
NA - Not applicable. Discharge severities for C]-C|g and >C]g organics were not computed because there Is no representative
MATE value for either group.
-------
Characterization for scrubber sludges in the current study was limited
to samples obtained from a single limestone FGO scrubber system. Analyses
for the samples indicated that concentrations of ten trace elements in the
scrubber sludge exceeded their respective health based solid MATE values.
These ten trace elements were: aluminum, arsenic, beryllium, calcium, cad-
mium, iron, manganese, nickel, lead, and zinc. Organics detected in the
scrubber sludge samples were limited to approximately 5 ppm of Cg and 2 ppm
of CIQ. Further, POM was not detected at the 2 ppm level.
7.4 COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
The results of the field measurement program for flue gas emissions from
commercial/institutional sources, along with supplementary values obtained
from the existing data base for certain pollutants, are presented in Table ll.
Also listed in this table are ambient source severity factors, defined as the
ratio of the calculated maximum ground level concentration of the pollutant
species to the level at which a potential environmental hazard exists.
The emission factors' shown in Table 11 are uncontrolled emission factors.
However, in the case of the solid fuel-fired combustion categories, some
degree of particulate control does exist in the commercial/institutional
sector. Overall particulate control efficiency is estimated to be 40 percent
for bituminous, pulverized dry bottom boilers and 20 percent for all stokers.
Gas- and oil-fired units are essentially uncontrolled. Control measures for
other criteria pollutants are not used by commercial/institutional combustion
sources.
As can be seen from Table 11, the criteria pollutants of concern are
particulates from all uncontrolled solid fuel-fired combustion sources, NO
/\
from all source categories with the exception of wood-fired stokers, SO- from
residual oil- and coal-fired sources, and total hydrocarbons from bituminous-
and wood-fired stokers and internal combustion reciprocating engines. Ambient
severity factors are all greater than 0.05 for these pollutant/source com-
binations. Emissions of CO from all combustion source categories do not appear
to represent an environmental problem. Emissions of particulate sulfate and
SO, from the solid fuel-fired combustion sources tested do appear to represent
a problem since ambient severity factors exceed 0.05.
45
-------
TABLE"11. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT FOR COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
Combustion Source Category
Pollutant*
NOX
Total Hydrocarbons
CO
Participates
so2
so3
Paniculate
Sulfate**
Trace Elements
Al
Ba
Be
Ca
Co
Cr
Cu
F
Fe
K
Li
Na
Ni
p
Si
V
Total POM
Organics
Total Volatile
(crc,6)
Total Nonvolatile
(>c,6)
Gas-fired
Boilers
Emission
Factor
(ng/J)
50
3
8
2
0.26
NO
NO
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
0.010
2.4
0.6
Ambient
Severi ty
Factor^
0.08
0.0026
<0.0001
0.0007
<0.0001
ND
NO
ND
NO
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NA
NA
NA
Distillate
Oil-fired Boilers
Emission
Factor
(ng/J)
68
3
8
6
106
ND
ND
0.015
0.0084
0.00004
0.845
0.0023
0.036
0.205
0.014
0.545
0.060
0.0015
0.101
0.112
0.0057
0.173
0.030
0.020
1.3
1.7
Ambient
Severity
Factor
0.11
0.0026
<0.0001
0.0022
0.028
NO
ND
<0.0001
0.0005
0.0005
0.0056
0.0013
0.0104
0.0059
<0.0001
0.0032
0.0009
0.0020
< 0.0001
0.0324
0.0002
0.0005
0.0002
NA
NA
MA
Residual
Oil-fired Boilers
Emission
Factor
(ng/J)
172
3
8
37
464
ND
0.03
0.156
0.0095
0.00007
0.780
0.023
0.050
0.093
0.085
0.379
0.213
0.001
0.418
0.804
0.107
1.610
3.66
0.044
2.2
0.8
Ambient
Severity
Factor
0.28
0.0026
<0.0001
0.014
0.12
ND
0.001
0.009
0.0006
0.0009
0.0050
0.0133
0.0144
0.0028
0.0003
0.0022
0.0031
0.0013
0.0022
0.236
0.0031
0.0047
2.05
NA
NA
NA
Bituminous,
Pulverized Dry Bottom
Emission
Fac tor
(ng/J)
352
6
20
3,406
766
1.0
2.1
27.5
4.24
0.132
40.7
0.430
0.825
0.605
3.245
16.5
10.5
1.155
20.35
1.045
4.675
78.0
1.375
0.002
4.4
1.6
Ambient
Severity
Factor
1.2
0.01
0.0002
2.6
0.42
0.07
0.12
0.323
0.517
4.026
0.497
0.534
0.563
0.037
0.079
0.201
0.320
3.203
0.248
0.637
2.852
0.476
0.167
NA
NA
NA
Bituminous
Stokerst
Emission
Factor
(ng/J)
117
59
195
1,075
766
12.2
3.5
8.7
1.33
0.04
12.8
0.14
0.26
0.19
1.02
5.21
3.31
0.36
0.42
0.33
1.48
24.6
0.43
0.5
26
33
Ambient
Severity
Factor
0.19
0.05
0.0008
0.43
0.2
0.44
0.10
0.048
0.077
0.62
0.074
0.079
0.084
0.006
0.012
0.030
0.048
0.477
0.036
0.095
0.425
0.071
0.025
NA
NA
MA
- Continued -
-------
TABLE 11 (Continued)
Combustion Source Category
Pollutant*
N0x
Total Hydrocarbons
CO
Participates
so2
so3
Paniculate
Sulfate**
Trace Elements
Al
Ba
Be
Ca
Co
Cr
Cu
F
Fe
K
Li
Na
Ni
P
Si
V
Total POM
Organics
Total Volatile
Total Nonvolatile
(>c,6)
Anthracite
Stokers
Emission
Factor
(ng/J)
145
5
15
145
314
19.3
27.2
29.5
0.278
0.005
0.872
0.028
0.376
0.175
0.270
6.00
2.856
0.070
0.825
0.355
2.11
33.8
0.170
0.003
1.9
3.1
Ambient
Severity
Factory
0.24
0.004
<0.0001
0.05
0.08
0.07
0.78
0.163
0.016
0.072
0.005
0.016
0.109
0.005
0.003
0.034
0.041
0.104
0.005
0.102
0.578
0.098
0.010
NA
NA
NA
Mood
Stokers
Emission
Factor
(ng/J)
10
100
100
215
65
NO
3.5
0.031
0.010
NO
0.627
0.001
0.004
0.004
0.015
0.205
1.48
0.001
0.024
0.004
0.137
1.03
0.0002
26
43
57
Ambient
Severity
Factor
0.017
0.09
0.0004
0.08
0.017
NO
0.10
<0.001
< 0.001
NO
0.004
<0.001
0.002
<0.001
<0.001
0.001
0.021
0.001
<0.001
0.001
0.039
0.003
<0.001
NA
NA
NA
Gas-fired
Reciprocating Engines
Emission
Factor
(ng/J)
1.390
400
300
5
0.26
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
[ID
NO
NO
NO
NO
NO
NO
364
36
Ambient
Severity
Factor
1.66
0.25
0.0009
0.001
0.0001
NO
ND
NO
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NA
NA
NA
Oil-fired
Reciprocating Engines
Emission
Factor
(ng/J)
1,420
300
400
40
97
NO
ND
0.288
0.011
NO
0.107
0.0005
0.006
0.174
ND
0.110
0.144
0.0003
0.091
0.020
0.016
0.945
0.004
0.430
206
94
Ambient
Severity
Factor
1.7
0.18
0.001
0.01
0.017
ND
ND
0.001
<0.001
ND
<0.001
<0.001
0.001
0.004
ND
<0.001
0.001
<0.001
<0.00)
0.004
0.003
0.002
<0.001
NA
NA
NA
ND - No data. NA - Not applicable.
Uncontrolled emissions.
Emission factors for criteria pollutants adjusted to reflect a capacity weighted distribution of stoker types.
Ambient severity factor is defined as the ratio of the calculated maximum ground level concentration of the pollutant species
to t.'.e level at which a potential environmental hazard exists. A value greater than 0.05 indicates a potential problem.
Determined turbimetrlcally following hot water extraction of sulfate from the collected particulate.
-------
The trace element data shown in Table 11 indicate that many trace elements
emitted by uncontrolled fossil fuel-fired combustion sources are of concern.
Chlorine emissions, although not shown in the table, should also be of concern
for residual oil and coal burning sources based on the chlorine content of
these fuels. Ambient source severity factors are generally greatest for
bituminous, pulverized dry bottom boilers because of the larger capacity of
these units. However, ambient severity factors exceed 0.05 for many trace
elements emitted by the smaller stoker-fired units. Elements of greatest
concern appear to be aluminum, barium, beryllium, chromium, lithium, nickel,
phosphorus and silicon. In addition, emissions of nickel from distillate oil
sources, and nickel, chromium, and vanadium from residual oil sources are
significant. Ambient severity factors based on the upper limit emission
factor exceed 0.05. Information found in the existing data base would also
indicate that ambient severity factors can exceed 0.05 for chlorine, cobalt,
and magnesium emissions from residual oil combustion. Because many commercial/
institutional fossil fuel-fired sources are totally uncontrolled or only
partially controlled, further consideration of trace element emissions from
these sources appears warranted.
POM emissions from some of the commercial/institutional sources tested
are of significance. Of most concern were POM emissions from an underfeed
stoker unit burning wood fuel during one test and bituminous coal during a
second test. POM emission factors were extremely high for these tests, 15,000
and 26,000 pg/J, respectively, for coal and wood combustion. In addition, at
least one active carcinogen, dibenz(a,h)anthracene, was identified, and the
presence of other carcinogens, e.g., benzo(a)pyrene and benzo(g,h,i)perylene,
was indicated. Level II analysis is needed to provide positive identification
of the POM compounds emitted by this stoker. It should be noted that this
unit was operated at low heat input levels during both test periods. This
operating condition would result in lower furnace temperatures and probably
inefficient combustion, factors that would favor formation of POM compounds.
Emissions of POM compounds from all other external combustion sources were not
significant; levels were low (0 to 50 pg/J) and the compounds identified were
primarily naphthalene and its derivatives.
48
-------
POM emissions from the oil-fired (and dual-fired) reciprocating engines
were relatively high, in the range of 100 to 800 pg/J. However, these emis-
sion levels were similar to those found in the existing data base for oil-fired
engines, and ambient severity factors did not exceed 0.05 for any of the com-
pounds detected. The high POM emissions measured for the dual-fired engine
were somewhat surprising because the quantity of oil used represented only 5
percent of the total thermal input. No POM emissions were detected from the
engine fired solely by gas.
7.5 INDUSTRIAL COMBUSTION SOURCES
The results of the field measurement program for flue gas emissions from
industrial sources, along with supplementary values obtained from the existing
data base for certain pollutants, are presented in Table 12. Results of
analyses of ash samples from wood-fired systems are also presented in the
table. Also listed in Table 12 are ambient source severity factors, defined
as the ratio of the calculated maximum ground-level concentration of the
pollutant species to the level at which a potential environmental hazard exists.
For the ash samples collected during tests of the wood-fired sources, discharge
severity, the ratio of the elemental concentration in the ash to the health
MATE value of the element, was used as a measure of potential hazard. A dis-
charge severity exceeding one is considered to warrant concern regarding the
impact of emissions on health.
The particulate, elemental, and particulate sulfate emission factors
shown in Table 12 are the mean values of those measured in this study. One
bituminous, pulverized wet bottom unit and one bituminous stoker were con-
trolled by electrostatic precipitators. Multiclones were used on the remaining
bituminous coal-fired units, with the exception of one pulverized dry unit,
which was controlled by a double alkali flue gas desulfurization (FGD) unit
(measured particulate efficiency - 99.47 percent). Two wood-fired boilers
were controlled by particulate scrubbers; the remaining three wood-fired units
were uncontrolled. Emission factors for gas- and oil-fired units presented in
the table represent uncontrolled emission factors. As noted previously, the
overall efficiency of particulate control in the industrial sector is 81 per-
cent for pulverized units and 53 percent for stokers. Gas- and oil-fired
49
-------
TABLE 12. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT
FOR INDUSTRIAL COMBUSTION SOURCES
Pollutant
NOX
Total Hydrocarbons
CO
Participates
so2
so3
Particulate
Sulfatef
Trace Elements
Al
As
Ba
Be
Ca
Cd
Co
Cr
Cu
Fe
K
Li
Hn
Na
Ni
p
Pb
Si
V
Total POM
Organics
Total Volatile
Total Nonvolatile
Gas-fired
Boilers
Emission Ambient
Factor* Severity
(ng/J) Factort
70
1
8
2
0.26
ND
ND
ND
ND
NO
ND
NO
ND
NO
NO
NO
ND
ND
NO
NO
ND
ND
ND
ND
ND
NO
ND
0.9
0.1
0.35
<0.01
<0.01
<0.01
<0.01
ND
ND
ND
NO
ND
ND
NO
ND
NO
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NO
NO
NO
NA
NA
Distillate'
Oil-fired
Boilers
Emission
Factor*
(ng/J)
70
3
15
6
106
NO
ND
180
4
1
1
75
1
4
24
38
380
85
<1
42
62
265
46
24
725
195
0.015
1.5
1.5
Ambient
Severity
Factort
0.35
0.01
<0.01
<0.01
0.11
NO
NO'
<0.01
-------
TABLE 12 (Continued)
en
Combustion Source Category
Pollutant
NOX
To ta 1 Hydroca rbons
CO
so,
so3
Particulate
Sulfatef
Trace Elements
Al
As
Ba
Be
Ca
Cd
Co
Cr
Cu
Fe
K
Li
Mn
Na
Ni
P
Pb
Si
V
Total POM
Organics
Total Volatile
(c,-c16)
Total Nonvolatile
Coal -fired
Bituminous
Stokers
Emission
Factor*
(ng/J)
290
20
40
84
766
ND
4.5
890
144
66
2.8
820
<1
34
58
270
2,660
1,370
13
37
990
184
810
127
1,875
54
0.18
19
1
Ambient
Severi ty
Factort
1.1
0.05
<0.01
O.I
0.64
ND
0.38
0.02
0.35
0.02
0.13
<0.01
<0.01
0.08
0.14
0.03
0.06
0.08
0.07
-------
units are essentially uncontrolled. Control measures for criteria pollutants
other than particulates are not widespread in the industrial sector.
As can be seen from Table 12, the major criteria pollutants of concern
are: particulates from residual oil sources and all uncontrolled solid-fuel-
fired units; NO from all source categories; S0? from oil- and solid-fuel-fired
A w
sources, including wood-fired units for which the ambient severity factor
exceeds 0.05 for those burning wood with a sulfur content of 0.1 percent; and
total hydrocarbons from bituminous stokers and wood-fired boilers. Ambient
source severity factors are all greater than 0.05 for these pollutant/source
combinations. Emissions of CO from all the combustion source categories tested
do not represent an environmental problem.
Particulate sulfate and SO^ emissions from the solid fuel-fired sources
tested are associated with ambient source severity factors in excess of 0.05
and, thus, represent a potential environmental hazard. Also, S03 emissions,
measured in one test of a unit burning residual oil, are significant despite
the use of a double alkali FGD unit to control emissions from this source.
Although the SOp removal efficiency of this FGD unit was 97.5 percent, only
28.5 percent of the SO^ was removed from the flue gas.
The trace element data shov/n in Table 12 indicated that many trace ele-
ments emitted by controlled bituminous coal-fired sources are of concern.
Elements of greatest concern appear to be arsenic, beryllium, cobalt, chromium,
iron, potassium, lithium, sodium, nickel, phosphorus, lead, and silicon.
Chlorine, on the basis of its concentration in coal, and other elements, in
addition to those listed above, may also be of concern because of variations
in the elemental content of bituminous coals. Because many industrial sources
are totally uncontrolled or only partially controlled, further consideration
of the emission of trace elements are warranted.
Trace element emissions of concern from the wood-fired sources tested
include barium, calcium, potassium, and phosphorus. Ambient source severity
factors calculated from the mean of the emission factor from these sources
exceed 0.05 for these elements. Overall removal efficiency of particulates
and nonvolatile trace elements from the five wood-fired units tested is estima-
ted to be 36 percent.
52
-------
Chromium, nickel, phosphorus, and vanadium emissions from distillate oil-
fired sources, and chromium, sodium, nickel, silicon, and vanadium emissions
from residual oil-fired sources are significant. Ambient severity factors,
based on mean emission factors measured in this study, exceed 0.05. In addi-
tion, information in the existing data base indicates that ambient severity
factors can exceed 0.05 for chlorine, cobalt, fluorine and magnesium emissions
from residual oil-fired boilers.
POM emissions from bituminous stokers and wood-fired boilers are poten-
tially significant. Mean emission factors for total POM were 180 and 210
pg/J, respectively, for these sources. Although no active carcinogens were
positively identified and ambient severity factors for most compounds were
less than 0.05, the possible presence of benzo(a)pyrene in significant amounts
was indicated in the emissions of two wood-fired boilers and one bituminous
stoker. Level II testing is needed to provide positive identification of the
POM compounds emitted from these sources.
The samples of ash collected from the wood.-fired sources were analyzed
for trace elements by SSMS and for organics, total chromatographic organics
(TCO), gravimetric organics, and POM. Three types of samples were collected;
bottom ash, cinder ash collected downstream of the combustion chamber, and fly
ash collected by a particulate scrubber control device. Discharge severity,
the ratio of the elemental concentration in the ash to the elemental health
MATE value for solids, was used to evaluate the impact of ash disposal. A
value in excess of one indicates that a potential environmental problem exists.
As shown in Table 12, the discharge severity is in excess of one for
several trace elements. Elements of concern in bottom ash are barium, calcium,
chromium, iron, potassium, manganese, nickel, phosphorus, and silicon. For
cinder ash, discharge severities in excess of one were found for arsenic,
barium, calcium, iron, potassium, manganese, nickel, phosphorus, and silicon.
Fly ash elements of concern include calcium, chromium, iron, potassium, manga-
nese, nickel, phosphorus, and silicon. If ecological effects are considered,
several other elements will warrant concern because the ecology MATE values
are generally lower than those for health.
53
-------
As anticipated, volatile and gravimetric organics were not present in signifi-
cant amounts in bottom ash. Organics were generally found in greater amounts
in cinder ash and fly ash, but are not of environmental concern. Although
POM compounds were not found in the samples of bottom ash and cinder ash, they
were found in the one sample of fly ash collected by a particulate scrubber.
The POM compounds were identical to POM compounds collected downstream of the
scrubber by the SASS train at this site. Further, the relative distribution
of these compounds in the scrubber ash and in the SASS samples was similar.
Based on this, wood fly ash will present a definite hazard at sites emitting
POM compounds such as benzo(a)pyrene. The compound benzo(a)pyrene was tenta-
tively identified in the flue gas emissions of two uncontrolled wood-fired
boilers during this study.
54
-------
8. CONCLUSIONS
Evaluation of the results from the field tests and the emission data
from the existing data base has led to a number of significant conclusions.
These conclusions are presented in the sections which follow.
8.1 GAS- AND OIL-FIRED RESIDENTIAL HEATING SOURCES
Based on the use of multiple source severity factor, emissions of NO
A
from gas-fired sources and NO , SO., and Mi from oil-fired sources have been
X w
identified as environmentally significant. Emissions of trace elements from
gas-fired sources and trace elements other than Ni from oil-fired sources,
on the other hand, are not of environmental concern. Additionally, no POM
was detected from gas-fired sources. Multiple source severity factors for POM
emissions from oil-fired sources are generally two to five orders of magni-
tude below levels considered hazardous.
In terms of contributions to the nationwide emissions burden, emissions
of particulates, S09 and NO from gas-and oil-fired residential sources
£ /\
account for about 0.2, 0.9 and 2.5 percent, respectively, of emissions from
all stationary sources. Emissions of CO from residential sources account
for about 0.5 percent of the total CO emissions from stationary sources,
with gas- and oil-fired sources contributing equally. Hydrocarbon emissions
from residential sources account for about 0.2 percent of the total hydro-
carbon emissions from stationary sources, with oil-fired sources contributing
62 percent of the gas- and oil-fired residential total.
The average emissions factors for criteria pollutants measured in this
project, despite large source-to-source variations, are in good agreement
with EPA AP-42 emissions factor. A singular exception is the hydrocarbon
emission factor for oil-fired sources which is 3.1 times greater than the
corresponding EPA emission factor. However, the multiple source severity
factor for hydrocarbon emissions from oil-fired sources is only 0.013,
indicating the insignificance of this pollutant from residential sources.
The SO, emission factor for oil-fired sources measured in this project
55
-------
is three times greater than the corresponding EPA emission factor. Since SO,
emissions from oil-fired residential sources have been identified as a potential
problem, it is recommended to conduct further work to determine SO, emission
factors from these sources.
Additional work to characterize emissions is also recommended in two
other areas because of data uncertainity. First, although POM emissions were
determined for the sources tested in this study, the data base is still sparse
and additional sampling and analysis efforts to determine emission factors
for POM should be undertaken. Second, within the accuracy limitations of
Level I (+ a factor of three), a change in burner cycle mode in the operation
of oil-fired sources from 50 minutes on/10 minutes off to 10 minutes on/20
minutes off had no effect on hydrocarbon and POM emissions. This result is
not consistent with the effect of cycle on emissions noted in other studies
and merits further investigation.
8.2 INTERNAL COMBUSTION SOURCES
Emissions of NO from stationary internal combustion sources are a
J\
potential environmental problem. NO emissions from these sources account
A
for approximately 18 percent of the total NOV emissions from stationary
/\
sources. Of the NO emissions from internal combustion sources, more than
A
80 percent are contributed by the industrial reciprocating gas engine category.
Ambient severity factors for NO emissions from gas turbines and reciprocating
A
engines range from 0.17 to 7.1.
In addition to NO emissions, emissions of hydrocarbons from stationary
X
internal combustion sources also contribute significantly to the national
emissions burden. These emissions account for approximately 4 percent of the
total hydrocarbon emissions from stationary sources. More than 80 percent of
the hydrocarbon emissions from internal combustion sources are contributed
by the industrial reciprocating gas engine category. Ambient severity factors
for hydrocarbon emissions range from 0.01 for industrial gas-fueled gas
turbines to 1.7 for industrial reciprocating gas engines.
Emissions of CO, S02 and particulates from stationary internal combustion
sources contribute only an insignificant fraction of the emissions of these
pollutants from stationary sources. Further, ambient severity factors for CO,
56
-------
SOp and participate emissions are well below 0.05, with the exception of SO^
emissions from diesel engines. Ambient severity factors for S0? emissions
from industrial and electricity generation diesel engines are 0.08 and 0.10,
respectively.
For distillate oil-fueled gas turbines, an average of 3.8 percent of the
sulfur present in the fuel is converted to SO.,. For diesel engines, an
average of 1,4 percent of the fuel sulfur is converted to SO.,. The percent
of fuel sulfur converted to SO- is lower for diesel engines because of the
lower oxygen level in reciprocating engines. Ambient severity factors for
S03 emissions range from 0.05 to 0.23 for oil-fueled internal combustion
sources. For distillate oil reciprocating engines, the data base for SO.,
emissions is marginal and could be improved by additional field tests.
Emissions of trace elements from gas-fueled internal combustion sources
are negligible when compared with emissions of trace elements from oil-
fueled sources. For oil-fueled internal combustion sources, emissions of
copper, nickel and phosphorus are associated with ambient severity factors
greater than 0.05.
Emissions of individual organic species from stationary internal
combustion sources are environmentally insignificant. Analysis results
indicated that organic emissions from oil-fueled internal combustion sources
consist mainly of saturated and unsaturated aliphatic and aromatic hydrocarbons.
The most prevalent organic species present are saturated straight chain and
branched hydrocarbons. Substituted benzenes are the second most abundant
organic species emitted. Ambient severity factors for these organic emissions
are well below 0.05. Additionally, POM emissions from gas- and oil-fueled gas
turbines were at levels too low to be differentiated from blank values. For
diesel engines, the POM emitted were mostly naphthalenes and substituted
naphthalenes, with ambient severity factors well below 0.05. POM compounds
known to be carcinogenic, such as benzo(a)pyrene and dibenz(a,h)anthracene,
were not found above the detection limit of 0.05 yg/m .
8.3 EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Characterization of Flue Gas Emissions
External combustion sources for electricity generation are well known as
57
-------
major contributors of NOX> SOg, particulates, and total hydrocarbons to the
environment. Emissions of NO from these sources account for approximately
A
50 percent of the total NO emissions from all stationary sources. Of the
A
NOV emissions from external combustion sources for electricity generation, 77
A
percent are contributed by burning of bituminous coal. Ambient severity
factors for NO emissions from utility boilers range from 0.13 for bituminous
A
coal-fired stokers to 6.4 for bituminous coal-fired cyclone boilers.
Emissions of SOo from external combustion sources for electricity genera-
tion contribute significantly to the national emissions burden. These emis-
sions account for approximately 57 percent of the total S0? emissions from
all stationary sources. Approximately 88 percent of the S02 emissions from
external combustion sources for electricity generation are contributed by burn-
ing of bituminous coal. Ambient severity factors for uncontrolled SOo emis-
sions range from 0.0007 for natural gas, wall-fired boilers to 3.3 for bitumi-
nous coal-fired cyclone boilers.
As with emissions of NO and S09, emissions of particulates from external
X L-
combustion sources for electricity generation, despite the widespread applica-
tion of control devices, are still significant environmental problems. These
emissions account for approximately 25 percent of the total particulate emis-
sions from all stationary sources. Almost all (^95 percent) particulate
emissions from external combustion sources for electricity generation are
contributed by burning of bituminous coal. Ambient severity factors for
particulate emissions range from 0.001 for natural gas, wall-fired boilers to
0.74 for lignite-fired cyclone boilers.
Emissions of total hydrocarbons from external combustion sources for
electricity generation contribute approximately 0.6 percent of the total emissions
of these pollutants from all stationary sources. Ambient severity factors for
emissions of total hydrocarbons range from 0.005 to 0.12.
Emissions of CO from external combustion sources for electricity genera-
tion are not an environmental concern. Ambient severity factors for CO
emissions are all well below 0.05. Total CO emissions from these sources account
for approximately 4 percent of CO emissions from all stationary sources.
Aside from the criteria pollutants, flue gas emissions of 50^ (in the form
58
-------
of sulfun'c acid vapor and aerosol) and participate sulfate from bituminous
coal-fired, lignite-fired, and residual oil-fired utility boilers require
further attention. Ambient severity factors for known SOo emissions range from
0.26 to 7.4. Ambient severity factors for controlled emissions of particulate
sulfate range from 0.15 to 0.93. Thus, emissions of both S03 and particulate
sulfate are environmentally important.
Of the trace elements present in bituminous coal, flue gas emissions of
aluminum, beryllium, chlorine, cobalt, chromium, iron, nickel, phosphorus, lead,
and silicon from most coal-fired boilers are of environmental significance.
For residual oil-fired utility boilers, flue gas emissions of beryllium, chlorine,
copper, magnesium,nickel, phosphorus, lead, selenium, and vanadium with
ambient severity factors greater-than 0.05, warrant special concern. Measure-
ments of flue gas emissions from gas-fired utility boilers indicate that the
average emissions of chlorine, copper, mercury, nickel and phosphorus
associated'with ambient severity factors greater than 0.05. This is a
surprising result requiring further characterization studies for
confirmation.
Analysis of organic emissions from utility sites indicated that the
principal organic constituents in flue gas are glycols, ethers, ketones, and
saturated and aliphatic hydrocarbons. The most prevalent species appear to
be the glycols and ethers which have MATE values in the range of 10 to 1100
mg/m . Ambient severity factors calculated using these MATE values indicated
that emissions of specific organics (excluding POM) are probably not of concern
with respect to human health.
POM compounds emitted at the highest concentrations in flue gas streams
from bituminous coal-fired sources include naphthalene, phenanthrene, and
pyrene. Dibenz(a,h)anthracene and possibly benzo(a)pyrene, both active carcin-
ogens, were detected at a limited number of sites at levels of environmental
concern. The only POM compounds identified in flue gas emissions from lignite-
fired sources were biphenyl and trimethyl propenyl naphthalene. Carcinogenic
POM compounds were not detected. For residual oil-fired sources, POM compounds
emitted at the highest concentrations in flue gas streams are naphthalene and
biphenyl. Again, carcinogenic POM compounds were not detected. No POM was
detected in flue gas streams from gas-fired utility boiler sites.
59
-------
Characteristics of Air Emissions from Cooling Towers
Two potential environmental problems associated with the air emissions
from cooling towers have been identified. First, air emissions of chlorine,
magnesium and phosphorus from mechanical draft cooling towers with high drift
rates are comparable to flue gas emissions of these elements from residual
oil-fired utility boilers and of environmental significance. Second, sulfate
emissions from mechanical draft cooling towers employing sulfuric acid as an
additive, and with design drift losses in the 0.1 to 0.2 percent range, are
of the same magnitude as sulfate emissions from coal-fired and oil-fired
utility boilers.
Characteristics of Wastewater Discharges
The major sources of wastewater discharges from external combustion sources
for electricity generation are: once-through cooling water, blowdown from
recirculating cooling systems, wastes from water treatment processes, chemical
cleaning wastes, and coal pile runoff. Discharges from once-through cooling
system amount to 7,780,000 I/sec and account for approximately 99.8 percent
of the total wastewater from conventional utility power plants. Of the remain-
ing sources, blowdown from recirculating cooling systems is the largest con-
tributor to wastewater discharge.
From an environmental standpoint, the pollutants of most concern in waste-
water effluents from conventional utility power plants are iron, magnesium,
maganese, nickel, and phosphorus. The average organic levels in the ash pond
effluents sampled were less than 0.1 mg/1. Average organic levels in the
cooling tower blowdown and boiler blowdown sampled were 1.5 mg/1 and 6.0 mg/1,
respectively. POM compounds were not found above the detection limit of 2 ng/1.
Based on discharge severities, the once-through cooling water and ash pond
overflow streams appear to be of lesser environmental significance than the
other wastewater streams from conventional fossil-fueled steam electric plants.
Total pollutant loading from wastewater streams will, however, depend on
individual discharge flow rates.
Characteristics of Solid Wastes
Solid waste streams generated by conventional utility power plants consist
primarily of coal ash and sludge from FGD systems. In 1978, total ash product-
60
-------
ion was 63.6 Tg and total FGD sludge production was 2.1 Tg (on ash-free basis).
Leaching of trace elements from coal ash may result in environmental con-
tamination. Concentrations of 11 to 16 trace elements in bituminous coal ash
and lignite ash exceed their health based solid MATE values. The pollutants
of most concern are aluminum, arsenic, calcium, chromium, iron, manganese,
nickel, potassium, and silicon.
Organics in bituminous coal ash and lignite ash are mostly present as the
>C,g fraction. POM concentrations in fly ash and bottom ash are not at levels
of environmental concern. The only POM compounds detected were naphthalene,
alkyl naphthalenes, and other compounds with high MATE values.
Key Data Needs
The combination of emissions data from this measurement program and the
existing data base provides adequate characterization of flue gas emissions
of criteria pollutants from most external combustion sources for electricity
generation. The notable exception is the lack of emissions data for pulver-
ized dry bottom boilers firing Texas Lignite. This is a serious data defi-
ciency because approximately 16,000 MW of added generating capacity are planned
for this source category in the 1978-1985 period.
In addition to the general data needs to characterize flue gas emissions
from pulverized dry bottom boilers fired with Texas lignite, a number of
specific data needs have been identified, These are listed as follows:
Size distribution data for flue gas emissions of particulates are
inadequate for bituminous coal-fired, lignite-fired, and residual
oil-fired utility boilers.
For bituminous coal-fired and residual oil-fired utility boilers,
the data base for S03 emissions is adequate. However, 803 emissions
data for lignite-fired sources are presently unavailable.
The data base for uncontrolled particulate sulfate emissions from
residual oil-fired sources is adequate. The data base for controlled
particulate sulfate emissions from bituminous coal-fired and lignite-
fired sources, however, is inadequate.
For bituminous coal-fired boilers equipped with electrostatic
precipitators, the data base characterizing flue gas emissions is
adequate for most trace elements. Similar data bases characterizing
flue gas emissions of trace elements from sources equipped with wet
scrubbers and mechanical precipitators, however, are inadequate.
61
-------
Existing data for flue gas emissions of trace elements from lignite-
fired utility boilers are generally not available. Analysis of the
data acquired in this program indicated the need for additional
characterization studies.
The data base characterizing flue gas emissions of trace elements
from residual oil-fired utility boilers appears to be adequate
except for beryllium, calcium, chlorine, copper, fluorine, magnesium,
lead, selenium, and vanadium. The emissions data base for these
trace elements can be improved by analysis of additional residual
oil samples.
Although current data indicated that flue gas emissions of specific
organics (excluding POM) are probably not of concern with respect
to human health, more detailed Level II organic analysis would be
required to conclusively determine the significance of organic
emissions.
The data base characterizing flue gas emissions of POM from bituminous
coal-fired sources is adequate except for dibenz(a,h)anthracene and
benzo(a)pyrene. Emissions of these specific POM compounds will require
further characterization.
The data bases characterizing cooling tower blowdown, ash pond over-
flow, chemical cleaning wastes, wet scrubber wastewater, and coal
pile runoff are inadequate. The present study has been instrumental
in applying Level I techniques to identification of wastewater con-
stituents which pose potential environmental problems. Since potential
problems were detected by Level I techniques, further studies using
Level II techniques will be required to adequately characterize waste-
water effluents from utility boilers.
Data on FGD scrubber sludge are limited. Needed data will be
provided by extensive scrubber sludge characterization studies
currently in progress under the direction of EPA and the Electric
Power Research Institute (EPRI).
8.4 COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
Flue gas emissions of particulates, NOV, S09, CO and total hydrocarbons
X L.
from commercial/institutional sources represent approximately 1.7 percent,
5(0 percent, 3.0 percent, 0.5 percent and 0.3 percent, respectively, of total
emissions of these pollutants from stationary sources. Despite this relatively
minor contribution to national emissions, criteria pollutant emissions from
individual combustion sources can have a significant local impact.
Based on calculated ambient severity factors, criteria pollutants and
sulfur compounds of environmental concern in flue gas emissions include NO
/\
from all commercial/institutional sources except wood-fired stokers, S02
62
-------
from coal- and residual oil-fired sources, SO, and particulate sulfate from
coal-fired sources, particulates from uncontrolled coal- and wood-fired sources,
and total hydrocarbons from bituminous stokers, wood stokers, and recipro-
cating engines. Specifically, particulate emissions from the coal- and wood-
fired sources are of particular concern, because moderate-to-high efficiency
control devices are required to reduce ambient severity factors to 0.05 and
particle size distribution data are presently inadequate. Flue gas emissions
of CO, on the other hand, do not appear to be a problem as ambient severity
factors for all source categories are 0.001 or less.
Flue gas emissions of trace elements from several source categories are
of concern. For uncontrolled coal-fired combustion sources, elements with
ambient severity factors in excess of 0.05 include aluminum, barium, beryllium,
calcium, chlorine, cobalt, chromium, copper, fluorine, iron, potassium, lithium,
sodium, nickel, phosphorus, lead, silicon and vanadium. Emissions of other
elements also could be of significance given the variability of the elemental
contents of coals. In addition, emissions of nickel from distillate oil
combustion sources, as well as nickel, chlorine, chromium, and vanadium from
residual oil combustion sources, are also associated with ambient severity
factors in excess of 0.05.
Emission levels for POM compounds from gas- and oil-fired commercial/
institutional sources are generally low and the compounds that were detected
from coal- and wood-fired combustion sources, however, are still inadequate.
The effect of heat input levels, on/off operating modes, excess air levels,
and other operating parameters on POM emissions need to be studied in more
detail. If these factors are found to contribute significantly to POM
emissions, studies to determine the prevalence of contributory source oper-
ating parameters in the commercial/institutional sector should be undertaken
to establish the magnitude of the problem.
8.5 INDUSTRIAL COMBUSTION SOURCES
Flue gas emissions of particulates, NO , S02> CO and hydrocarbons from
industrial external combustion sources represent approximately 9.0 percent
10.1 percent, 5.7 percent, 1.7 percent and D.4 percent, respectively, of
total emissions of these pollutants from stationary sources. With the excep-
tion of CO emissions, emissions of all other criteria pollutants are environ-
63
-------
mentally significant for at least some of the industrial external combustion
source categories. The major criteria pollutants of concern are NO from
A
all industrial boilers, SQ* ^rom residual oil- and bituminous coal-fired
sources, total hydrocarbons from bituminous coal-fired stokers and wood-fired
stokers, and uncontrolled particulates from bituminous coal- and wood-fired
sources. Ambient severity factors are highest for NO emissions, which range
/\
from 0.25 for wood-fired stokers to 2.9 for pulverized bituminous coal-fired
wet bottom units.
Ambient source severity factors are also greater than 0.05 for SO., emis-
sions from the two source categories tested - pulverized bituminous coal-
fired wet bottom boilers and residual oil-fired boilers, and for emissions
of particulate sulfate from bituminous coal and wood combustion.
Flue gas emissions of trace elements from controlled bituminous coal-fired
boilers are of concern. Bituminous coal-fired stokers, probably because of
less efficient control of particulates, were the largest emitters of trace
elements and particulates. Elements of principal concern are arsenic, beryl-
lium, chlorine, cobalt, chromium, iron, potassium, lithium, sodium, nickel,
phosphorus, and lead. Emissions of trace elements from uncontrolled wood-,
distillate oil-, and residual oil-fired boilers are also of concern. Elements
with ambient severity factors in excess of 0.05 include barium, calcium,
potassium, and phosphorus from wood-fired boilers, chromium, nickel, phos-
phorus, and vanadium from distillate oil-fired boilers, and chlorine, chromium,
sodium, nickel, silicon and vanadium from residual oil-fired boilers.
Analysis of organic emissions from industrial sites indicated that the
principal organic constituents are esters, ethers, glycols and aliphatic and
aromatic hydrocarbons. The most prevalent constituents are generally assoc-
iated with MATE values in the 10 to 1000 mg/m range. Ambient severity factors
will not exceed 0.05 at these MATE levels.
POM emissions of potential environmental significance may be present in
the flue gas emissions from bituminous stokers and wood-fired boilers. A
compound, tentatively identified as benzo(a)pyrene, was found at some of these
sites. Phenanthrene was also emitted in significant amounts from one of the
wood-fired boilers. POM emissions from pulverized bituminous coal-fired wet
bottom boilers, oil-fired boilers, and gas-fired are not considered to be a
64
-------
problem. POM compounds identified in highest concentrations include naphtha-
lene and phenanthrene from pulverized bituminous coal-fired wet bottom boilers,
biphenyl from oil-fired boilers, and naphthalene and phenanthrene from gas-
fired boilers.
Because of inadequacies in the data base that characterizes emissions,
it is recommended that additional studies be conducted to provide the identified
data needs. The primary data needs include particle size distribution data and
POM data for flue gas emissions from coal- and wood-fired industrial boilers.
65
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029c. February 1979.
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