x>EPA
United States Industrial Environmental Research EPA-600/7-78-164b
Environmental Protection Laboratory August 1978
Agency Research Triangle Park NC 27711
Environmental
Assessment of
Coal- and Oil-firing
in a Controlled
Industrial Boiler;
Volume II.
Comparative
Assessment
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7 Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect the
views and policies of the Government, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
-------
DISCLAIMER
This report has been reviewed by the Industrial Environmental
Research Laboratory, U. S. Environmental Protection Agency, and approved
for publication. Approval does not signify that the contents necessarily
reflect the views and policies of the U. S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
-------
ABSTRACT
The report gives results of a comparative multimedia assessment of
coal versus oil firing in a controlled industrial boiler. Relative
environmental, energy, economic, and societal impacts were identified.
Comprehensive sampling and analyses of gaseous, liquid, and solid emis-
sions from the boiler and its control equipment were conducted to identify
criteria pollutants and other species. Major conclusions include: (1)
While the quantity, of particulates from oil firing is considerably less
than from coal firing, the particles are generally smaller and more
difficult to remove, and the concentration of particulates in the treated
flue gas from oil firing exceeded that from coal firing. (2) NOX and CO
emissions during coal firing were about triple those during oil firing.
(3) Sulfate emissions from the boiler during coal firing were about
triple those during oil firing; however, at the outlet of the control
equipment, sulfate concentrations were essentially identical. (4) Most
trace element emissions (except vanadium, cadmium, lead, cobalt, nickel,
and copper) were higher during coal firing. (5) Oil firing produces
cadmium burdens in vegetation approaching levels which are injurious to
cattle. (6) The assessment generally supports the national energy plan
for increased use of coal by projecting that the environmental insult from
controlled coal firing is not significantly different from that from oil
firing.
This report was submitted in fulfillment of Contract Number 68-02-2613,
Task 8 by TRW Environmental Engineering Division under the sponsorship of
the U.S. Environmental Protection Agency. This report covers a period from
October 24, 1977 to May 5, 1978, and work was completed as of May 5, 1978.
11
-------
CONTENTS
Abstract i1"1"
Abbreviations v
Acknowledgments vi
1. Introduction 1-1
2. Summary and Conclusions 2-1
3. Test Setting 3-1
4. Comparative Assessment of Coal and Oil Firing in an
Industrial Boiler 4-1
5. Comparative Environmental Impact Assessment 5-1
IV
-------
LIST OF ABBREVIATIONS
acm/min -- Actual Cubic Meters Per Minute
ACFM Actual Cubic Feet Per Minute
DSCM -- Dry Standard Cubic Meters
ESCA -- Electron Spectroscopy for Chemical Analyses
FGD -- Flue Gas Desul furization
ICPOES -- Inductively Coupled Plasma Optical Emission Spectroscopy
MATE -- Minimum Acute Toxicity Effluent
NAAQS -- National Ambient Air Quality Standards
NSPS -- New Source Performance Standards
SSMS -- Spark Source Mass Spectrometry
TSP -- Total Suspended Particulate
-------
ACKNOWLEDGMENTS
The cooperation of the Firestone Tire and Rubber Company and FMC
is gratefully acknowledged. We are particularly indebted to Gary Wamsley
of Firestone and Carl Legatski of FMC, without whose cooperation this
assessment could not have been completed.
VI
-------
SECTION I
INTRODUCTION
A comparative multimedia assessment of coal firing and oil firing
In an industrial boiler was conducted. Extensive sampling and analysis
of all major gaseous, liquid, and solid emissions and effluents was done.
The test boiler was a dual fuel 10 MW equivalent unit that is capable of
burning both coal and oil. During the tests conducted for this study the
boiler burned either exclusively coal or oil, although it can burn both
fuels simultaneously if required. The boiler is equipped with a pilot
double-alkali flue gas desulfurization (FGD) unit designed to treat
approximately 30% of the total flue gas, approximately 3 MW equivalent.
During the tests, however, the FGD was processing only about 11-14% (13%
average) of the total when coal was fired and 23-32% (25% average) when
oil was burned. This corresponds to approximately 1.3 MW and 2.5 MW,
respectively. Because the FGD was operating at less than design capacity,
there is some question about the typical ness of the test results. That
is, the pilot unit may have been performing better than full size commercial
versions will.
The assessment consists of several parts. First, comprehensive
emissions assessments of each fuel were conducted. These assessments
consist of detailed examinations of gaseous, liquid and solid emissions
and effluents considering both pre- and post-scrubber emissions for each
fuel. The emissions to all three media were determined for the
case where no FGD was present and for the case where an FGD capable of
scrubbing 100% of the flue gas was present. The comprehensive emissions
assessment also consisted of an examination of the effects and
efficiencies of the scrubber for both fuels.
These comprehensive emissions assessments were used to develop a
comparative emissions assessment. This assessment examines the differences
in the quantities and character of the emissions resulting from the com-
bustion of each fuel. In this case the primary emphasis was on the
emissions and effluents resulting from the burning of each fuel where 100%
scrubbing capacity was available. This part of the project was concerned
with determining the emissions resulting from each fuel with emission
1-1
-------
controls in place. Of special concern was the cross-media impacts of
each fuel.
On the basis of the emissions assessments a comparative environ-
mental, societal and energy impact assessment was developed. The emphasis
here was on the relative impacts of each fuel assuming full flue gas
desulfurization. The uncertainties inherent in these types of analyses
dictated that the differences in, rather than the absolute magnitude of
these impacts, be considered.
The report consists of three volumes. Volume I is an Executive
Summary which summarizes the major results and conclusions of the study.
This volume, Volume II, presents the comparative assessments. Included
are a description of the test setting, the comparative emissions assess-
ment, and the comparative environmental societal and energy impact assessment
Volume III contains the comprehensive assessments and appendices and includes
detailed descriptions of the test site, the test protocol and a detailed
presentation of data.
1-2
-------
SECTION 2
SUMMARY AND CONCLUSIONS
A comparative assessment of coal and oil firing in a controlled indus-
trial boiler was conducted. The comprehensive emissions assessments for
each fuel were used to develop a comparative emissions assessment. On the
basis of the emissions assessment a comparative environmental assessment
was developed.
The following is a list of the major conclusions resulting from the
comparative and environmental assessments;
COMPARATIVE EMISSIONS ASSESSMENT
e Uncontrolled emissions of criteria pollutants produced during coal
firing correspond well with emission factors from AP-42. This
observation does not generally hold true for oil-fired emissions.
NOx emissions from oil firing were nearly 23% lower than the AP-42
emission factor, although they appear to be within the normal range
for similar industrial units. CO emissions from oil firing were
nearly 63% lower than the AP-42 emission factor. Oil-fired SO- and
total hydrocarbons correspond well with their respective AP-42
emission factors. Particulate emissions from oil firing, in the
absence of coal ash contamination, are approximately twice the value
tabulated in AP-42.
e NOx emissions increased with increasing load for both coal and oil
firing, as expected. Available data indicate that for boiler loadings
between 90 and 100%, NCx emissions from coal firing are
approximately three times greater than from oil firing.
e Observed reductions of NOx emissions for coal firing and early oil
firing tests appear to be due, at least in part, to air leakage into
the scrubber outlet sampling line. Data from later oil firing tests,
not known to be subject to leakage problems, indicate that NOx
removal across the scrubber is on the order of ?.%.
8 Uncontrolled CO emissions from coal firing were 15.9 ng/J (0.04 1b/
MM Btu) while those from oil firing were 5.47 ng/J (0.01 1b/MM Btu).
This factor of three difference is at variance with AP-42 data
indicating that CO emissions from oil firing are 23% lower than those
from coal firing. Apparent reductions in CO emissions across the
scrubber are not considered significant due to air leakage in the
sampling train and the low sensitivity of analysis at the measured
CO concentrations.
e Uncontrolled S02 emission rates during coal and oil firing were
2-1
-------
1112 ng/J (2.59 Ib/MM Btu) and 993 ng/J (2.31 1 b/MM Btu), respectively.
Removal data indicate an average scrubber removal efficiency of 97%
during both coal and oil firing. Controlled S02 emissions for coal
and oil firing were 36.3 ng/J (0.08 1b/MM Btu) and 26.8 ng/J (0.06
1b/MM Btu), respectively, which are lower than either existing or
proposed NSPS limitations.
i Particulate loadings prior to scrubbing were 2951 ng/J (6.86 1 b/MM Btu)
during coal firing and 59.0 ng/J (0.14 1b/MM Btu) during oil firing,
in the absence of coal ash contamination. Scrubbing removed 99% of
the coal-fired particulates and 75% of the oil-fired particulates.
The lower removal efficiency obtained during oil firing is attributed
to the increased fraction of particles smaller than 3 ym; at least
21% of the uncontrolled oil-fired particulates are less than 3 ym
while substantially less than 1% of uncontrolled coal-fired particulates
are under 3 ym in diameter.
There appears to be a net increase in emission rates across the
scrubber for coal-fired particulates less than 3 ym in size. This
net increase can be attributed to the poor removal efficiency of the
scrubber for fine particulates, and to the sodium bisulfate (NaHS04)
and calcium sulfite hemihydrate (CaS03-l/2 H20) particulates generated
by the scrubber. Both NaHS04 and CaS03-l/2 HgO have been identified
at the scrubber outlet but not at the inlet. Although a very slight
increase in oil-fired particulates in the 1-3 ym range was observed,
a net decrease in particulates less than 3 ym was observed during oil
firing. Based on the results of coal firing tests, it appears reason-
able that scrubber generated particulates were present in the scrubber
outlet stream during oil firing but that the high fine particulate
loading associated with oil firing masked detection of these materials.
Of the 22 major trace elements analyzed in the flue gas stream
during coal firing, 18 exceed their KATE values at the scrubber
inlet and 4 at the scrubber outlet. Similarly, for oil firing,
11 exceeded their MATE values at the scrubber inlet while 5 exceeded
their MATE values at the scrubber outlet. Elements exceeding their
MATE values at the scrubber outlet and which are common to both
fuels are arsenic, chromium and nickel. Additionally, iron exceeded
its MATE value at the scrubber outlet during coal firing as did
cadmium and vanadium during oil firing. The overall removal of
trace elements across the scrubber is 99% for coal firing and 87%
for oil firing.
Polycyclic organic material (POM) was not found in the scrubber
inlet or outlet at detection limits of 0.3 yg/rn^ for either coal or
oil firing. MATE values for most POM's are greater than this detec-
tion limit. However, since the MATE values for at least two POM
compounds - benzo(a)pyrene and dibenz(a,h)anthracene - are less than
0.3 yg/n,3, additional GC/MS analyses at higher sensitivity would be
required to conclusively preclude the presence of all POM's at MATE
levels.
Beryllium emissions after scrubbing were less than or equal to its
MATE value for coal and oil firing. At the measured emission concen-
trations the National Standard for Hazardous Air Pollutants limitation
2-2
-------
of 10 grams beryllium per day would only be exceeded by boilers of
50 MW capacity for coal firing and 100 MW capacity for oil firing.
t The combined waste water stream from the boiler operation may
not pose an environmental hazard in terms of organic materials
since the discharge concentrations of organics are well below their
MATE values for both coal and oil firing. The same conclusion may
be drawn for inorganic compounds with the exception of cobalt, nickel,
copper and cadmium for coal firing, and nickel and copper for oil
firing, since these metals may exceed their MATE values.
Organic emissions for coal and oil firing were very similar. Total
organic emissions were less than 9 ng/J (0.02 1b/MM Btu) for both
tests, and these emissions appear to be primarily C] to Cg hydrocarbons
and organics heavier then C-\§. hhile uncontrolled emission rates for
both coal and oil firing are low, emissions of these organics were
further reduced by about 85% in the scrubber unit.
e The organic compounds identified in the gas samples from both coal
and oil firing were generally not representative of combustion-
generated organic materials, but were compounds associated with
materials used in the sampling equipment and in various analytical
procedures. This again confirms the low level of organic emissions.
f The relatively poor removal efficiency (approximately 30% in both
oil and coal-fired tests) for $03 across the scrubber is an indication
that $03 is either present as very fine aerosols in the scrubber
inlet, or is converted to very fine aerosols in the flue gas stream
as it is rapidly cooled inside the scrubber-
o The fraction of fuel sulfur converted to $03 during oil firing was
50 to 75% higher than during coal firing. In contrast, the fraction
of fuel sulfur converted to sulfates during coal firing was twice
that during oil firing.
o Sulfates are more efficiently removed than S03 (60% removal for oil
firing and 88% for coal firing). This indicated that S0^= is probably
associated with the larger particulates which are more efficiently
removed than smaller particulates. The higher sulfate removal from
the coal flue gases is explained by the higher particulate loading
during coal firing.
Uncontrolled chloride and fluoride loadings were higher during coal
firing (5 and 0.2 ng/J, respectively) than during oil firing (0.2 and
0.02 ng/J, respectively). This was attributed, in the case of
chlorides, to a higher fuel chlorine content for coal than for oil.
Chlorides were removed with better than 99% efficiency from coal flue
gases and with about 51% efficiency from oil flue gases. This
difference was attributed to the higher particulate removal efficiency
for coal particulates. Fluorides were removed with greater than 86%
and about 87% efficiency for coal and oil firing, respectively.
Uncontrolled nitrate emissions were 0.08 ng/J during oil firing, and
nitrates were removed from oil flue gases with 57% efficiency.
2-3
-------
o The scrubber cake produced during coal firing contained 29% coal
fly ash; during oil firing it contained 1% oil fly ash. The
trace element concentrations in the coal-fired scrubber cake
exceeded their health based MATE values, with the exception of
boron. In the oil-fired scrubber cake, all trace elements except
antimony, boron, molybdenum and zinc exceeded their health based
MATE values. All ecology based MATE values were exceeded by
trace element concentrations during both oil and coal firing.
Because the trace elements may leach from the disposed scrubber
cake, these solid wastes must be disposed of in specially designed
landfills,
COMPARATIVE ENVIRONMENTAL ASSESSMENT
The difference in environmental insult expected to result between
coal and oil combustion emissions from a single controlled 10 MW
industrial boiler is insignificant. This is because: 1) there
are only slight differences in the emissions levels of the pollu-
tants, or 2) the absolute impact of either fuel use is insignifi-
cant .
The environmental impacts of emissions from a cluster of controlled
10 MW industrial boilers are potentially significant. The impacts
include health effects, material damages, and ecological effects
from high levels of S02, NOx and suspended particulate matter; health
effects and ecological damage due to trace metal accumulation in
soils and plants; and aesthetic degradation from visibility reduction
and waste disposal sites.
0 The risk of environmental damage from emissions of controlled in-
dustrial boilers, whether oil or coal-fired, is considerably less
than the risk posed by emissions from uncontrolled industrial
boilers. It should be noted that this finding is based on an ex-
ceptional facility. The reference facility is very well run and
maintained, and emissions are low.
The environmental acceptability of a cluster of controlled indus-
trial boiler emissions is more dependent on site specific factors
(e.g., background pollution levels, location and number of other
sources) than type of fuel utilized. Careful control of the site
specific factors can avert potential environmental damages and
generally compensate for any differential effects arising between
the use of coal or oil .
With the possible exception of ambient levels of NO, the risk of
violating the NAAQS due to operation of clusters of controlled
industrial boilers is essentially the same whether the fuel combusted
is coal or oil. Based on tests of the reference 10 MW boiler (which
was not controlled for NOx emissions), localized NOx concentrations
produced by coal firing are estimated to be twice the level of that
resulting from oil firing, and greater than the levels permitted by
the NAAQS for 24-hour and one year averaging periods.
2-4
-------
9 Short term C3 hour and 24 hour averaging times) maximum ambient
concentrations present the most significant air pollution problem
resulting from operation of controlled industrial boilers. Restric-
tions imposed by the NAAQS for short term ambient levels would be
most constraining to boiler operation in areas where air quality is
already only marginally acceptable. Expected long term concentra-
tions arising from boiler emissions would not appear to pose a risk
for violation of the NAAQS.
0 Coal firing appears to produce a greater enrichment of trace elements
in the flue gas desulfurization cake than oil firing produces. How-
ever, the scrubber cake resulting from either coal or oil firing
contains sufficient amounts of heavy metals and toxic substances to
pose difficult waste disposal problems.
The impact categories considered include public health, ecology,
societal, economic, and energy. The specific findings with respect to
the various impact categories are summarized briefly below.
Health Effects--
Based on the Lundy/Grahn Model for health effects associated with
suspended sulfate levels, regional emissions levels from controlled
oil or coal-fired industrial boilers would not be expected to cause
a significant impact on regional health. Emissions from uncontrolled
boilers would result in substantially greater levels of regional sus-
pended sulfate levels, and the associated health effects would be an
order of magnitude greater.
Emissions from clusters of controlled industrial boilers are expected
to cause significant adverse health effects in a localized area near
the plant cluster. Oil firing would be expected to result in local-
ized health effects about one third less severe than those resulting
from coal firing. The increase in mortality attributable to either
controlled coal or oil firing is appreciably less than that associ-
ated with uncontrolled industrial boilers emitting higher levels of
particulates and SOx.
The impact of solid waste generation on health is essentially the
same for controlled coal firing and oil firing, provided suitable
land disposal techniques are employed to assure minimal leaching
rates and migration of trace elements to groundwater and the ter-
restrial environment.
Addition of cadmium to a localized environment in the quantities
produced by clusters of controlled industrial boilers may
result in cadmium concentrations in plants approaching levels in-
jurious to man. Because cigarettes contain significant cadmium
levels, smokers are more apt to achieve thresholds of observable
symptoms for cadmium exposure when consuming additional cadmium via
the food chain.
2-5
-------
The concentration of metals in runoff waters due to controlled oil
firing is predicted to be slightly less than that occurring from
controlled coal firing; in either case, hazard to human health by
drinking water is remote.
Trace element emissions from clusters of controlled industrial
boilers may significantly increase local background levels in
drinking water, plant tissue, soil, and the atmosphere; however,
the expected increases in the levels of such elements are generally
several orders of magnitude less than allowable exposure levels.
Oil firing is estimated to cause cadmium burdens in plants approach-
ing levels injurious to man, and coal firing may produce plant
concentrations of molybdenum which are injurious to cattle.
Ecology--
e The potential for crop damage from either controlled coal firing
or oil firing depends greatly on ambient levels of NOx, S02, or
trace element soil concentrations. If such levels are presently
high, localized plant damage would be expected to occur within a
1 to 2 km range from a controlled boiler cluster. Leaf destruc-
tion from S02 exposure would be expected to be slightly more severe
in the vicinity of a cluster of controlled boilers which are coal-
fired as opposed to oil-fired. For boilers uncontrolled for NOx
emissions, plant damage would be expected to be significantly
greater in the vicinity of the coal-fired cluster, owing to higher
levels of ambient NOx produced. The likelihood of damage occurring
in plants due to emissions of trace elements from either controlled
oil or coal firing is remote, with the possible exception of injury
due to elevated levels of molybdenum and cadmium in plant tissue
resulting from coal firing and oil firing, respectively.
o The effect of emissions from industrial boilers on trace element
burdens in plants is greater via soil uptake than by foliar inter-
ception. This is because soil concentrations are the result of
accumulative long term exposure to boiler emissions whereas foliar
exposure is determined by the immediate deposition rate of emissions
on the plant surface and the lifetime of the leaf.
The impact of fossil fuel combustion in controlled oil or coal-
fired boilers on plant damage via acid precipitation would be
insignificant. The levels of suspended sulfate (the origin
of acid rain) would be essentially the same whether the controlled
boilers are coal or oil-fired.
ft Measurement and analyses of leaching rates at experimental waste
disposal sites indicate that landfills of untreated flue gas desul-
furization system scrubber cake can be constructed such that signi-
ficant adverse impacts will not occur.
2-6
-------
Societal--
The Impact of boiler emissions on corrosion in the local area near
a cluster of controlled industrial boilers would be significant.
The corrosion rate would be slightly greater when the boilers are
coal-fired. However, the extent of this overall impact (oil or coal)
is minor compared to that which occurs when industrial boilers are
uncontrolled.
The increase in annual TSP and soiling damages in the vicinity of a
cluster of controlled industrial boilers could result in additional
cleaning and maintenance costs about 10 to 15% greater than that
already experienced in a typical urban area. The cleaning costs
may-be slightly greater when the boilers are coal-fired.
Emissions of particulate matter from controlled industrial boilers
may result in visibi-lity reduction. This aesthetic degradation
would occur in a localized area near the boiler cluster, and would
occur to essentially the same extent whether the boilers are oil
or coal fired.
e Total land disposal requirements for scrubber cake waste generated
by controlled coal firing are three times greater than those for
controlled oil firing. Waste disposal of the scrubber wastes may
result in significant depreciation of property value and aesthetic
degredation in the area of the disposal site. These impacts would
5e more severe if boilers use coal rather than oil.
Economic--
o The differential direct economic impact between emissions from
coal firing and oil firing is generally insignificant with the
possible exception of some differences occurring in a limited
localized area near clusters of boilers. The extent of the
incremental direct economic impacts is proportional to the
extent of the incremental environmental damages.
o Differential second order economic impacts, such as changes in
hospital employment, alteration of taxes, or changes in income,
are expected to be insignificant between emissions from con-
trolled oil and coal-fired industrial boilers
Energy--
At the present time, the comparative assessment of the effects of
emissions from controlled oil and coal-fired industrial boilers
tends to support the national energy plan for intensified utilization
of coal. The fuel choice of oil or coal is a relatively minor issue
concerning the environmental acceptability of controlled industrial
2-7
-------
boilers; other site specific and plant design factors exert a great-
er effect on environmental damages. While it was shown that fuel
choice caused significant differences in impacts to occur when the
boiler is uncontrolled for NOx emissions, these differences may be
mitigated by the addition of NOx control technologies with minimal
overall cost impact.
As concern for environmental protection increases, the issue may
not be whether coal or oil use is more environmentally acceptable,
but whether the increasing use of fossil fuels can be continued at
the present levels of control technology without potential long-
term damages. If it is found that long-term effects of pollution
(e.g., trace metals accumulation, lake acidity from acid rains)
from fossil fuel combustion and other sources are environmentally
unacceptable, it is clear that energy use may be affected. Energy
cost will increase with increasing control requirements, possibly
to the level where other cleaner forms of energy become more
competitive.
-------
SECTION 3
TEST SETTING
The host for this assessment was the Pottstown, Pennsylvania plant of
the Firestone Tire and Rubber Company. Boiler No. 4, one of four used to
supply process steam to the plant, was tested. The boiler burns either coal
or oil and has a pilot FMC double alkali flue gas desulfurization system
designed to treat approximately one-third of the boiler's flue gas.
The excellent cooperation and assistance from the Firestone Tire and
Rubber Company and FMC was invaluable in performing this assessment.
The test boiler (No. 4) is one of four comprising a steam plant which
supplies process steam and heating steam for the facility. The boiler is
one of three which operates at a fairly constant rate of 45,400 kg/hr
(100,000 Ib/hr) of steam. Process steam demand is relatively steady, since
the plant operates 24 hours per day, seven days per week. Fluctuations in
heating load are satisfied by either boosting steam generation rates on
these boilers or by operating the fourth boiler (No. 1). The steam gener-
ation rate of Boiler No. 1 varies from zero to approximately 22,700 kg/hr
(50,000 Ib/hr) of steam. A schematic of the steam plant is shown in
Fi gure 3-1 .
Boiler No. 4 is a once-through Babcock and Wilcox Type P-22 EL, inte-
gral furnace. Installed in 1958 and originally designed as a coal-fired
unit, it was converted to fire either coal or fuel oil in 1967. The change-
over from one fuel to the other can be accomplished in less than thirty
minutes. (See Section 3, Volume III of this report for additional detail.)
The two fuels are usually not burned simultaneously except when con-
verting from oil to coal firing. The coal is ignited by continuing oil
firing until a stable coal flame is obtained. Oil and coal can be fired
simulataneously to maintain acceptable steam generation rates if coal with
a low heat content is burned.
The boiler uses either Number 6 fuel oil or Eastern bituminous coal.
Currently there are no fuel oil specifications. Therefore, sulfur and heat
content of the oil vary with supplier. The coal is required to meet CLASS
II, Group 2 of ASTM D388. Normally the coal used is mined in Pennsylvania.
3-1
-------
MANUFACTURING
AND WAREHOUSE
Figure 3-1. Industrial site plant layout.
3-2
-------
However, coal was purchased from a mine in Kentucky during the 1978 coal
strike.
An air preheater is located in the flue gas plenum directly downstream
of the boiler.. This gas-to-gas heat exchange recovers approximately 4.2
gigajoules/hr (4 million BTU/hr) when the boiler is operating at full load.
EXHAUST GAS CLEANING
The flue gases are treated by an air pollution control system. The
air pollution control equipment consists of multiclone units and a pilot
FGD unit. All of the flue gas passes through the multiclones. The stream
then is split and two-thirds of the flue gas ducted to the stack. The
other one-third is ducted to the pilot FGD system. The boiler has no NO
X
controls.
The characteristics and volume of fly-ash collected by the multiclone
unit vary significantly depending upon the type and composition of the fuel.
During oil firing, very little fly-ash leaves the boiler. During coal
firing, a large amount reaches the multiclones.
\
The collection efficiency of the multiclone varies as a function of
the particle size distribution and grain loading. Typically, multiclones
remove 90% of those particles with diameters 10y and greater, and 50% to
80% of those particles with diameters 3y and greater. The collection effi-
ciency of multiclones drops off rapidly for particles less than 3y diameter.
Fly-ash is periodically removed and transported to an on-site landfill
for final disposal.
FLUE GAS DESULFURIZATION SYSTEM
The flue gas desulfurization (FGD) system was designed and manufactured
by FMC Corporation. The FGD system is a pilot unit designed to handle 280
acm/min (10,000 ACFM) of flue gas, which is approximately one-third of
the volume of the flue gas produced by the boiler.
Figure 3-2 is the basic flow diagram of the FMC FGD system as it is
applied at this site.
The flue gas (Stream 1) is withdrawn downstream of the boiler on the
exit side of the multiclone dust collectors. During oil firing the partic-
ulate loading to the scrubber is low. During coal firing the multiclones
3-3
-------
MESH MIST EL
oo
I
SLURRY
THICKENER
LEGEND:
BOILER FLUE GAS TO SCRUBBER
SCRUBBER OUTLET TO ATMOSPHERE
SOLID WASTE TO LANDFILL
ABSORBENT SOLUTION TO SCRUBBER
ABSORBENT SOLUTION TO REGENERATION
SODIUM CARBONATE MAKEUP
REGENERATION SOLUTION
REGENERATED SCRUBBER SOLUTION
CONCENTRATED SLURRY
RETURNED SCRUBBER SOLUTION
Figure 3-2. Flow diagram of the FMC flue gas desulfurization unit.
-------
do not achieve complete fly-ash removal. Therefore, the fly-ash loading
in the gas stream inlet to the scrubber is substantially higher than
during oil-firing. The FGD system was designed to operate with or without
fly-ash, and can be operated without any mechanical changes on either fuel.
Upon entering the FGD unit the flue gases are contacted with a slightly
acidic scrubbing solution (stream 4) and the sulfur dioxide is absorbed.
The process utilizes a sodium sulfite-sodium bisulfite solution as the
absorbent. The particulate matter and sulfur dioxide are removed at the
scrubber throat and carried away in the scrubbing solution.
A bleed stream (stream 5) of the scrubbing solution is removed from
the system at a rate which will keep the pH of the solution in an acceptable
range. The bleed stream is reacted with calcium hydroxide in a short reten-
tion time, agitated vessel to regenerate the sodium sulfite.
The slurry of precipitated sulfur compounds (stream 8) is concentrated
and then pumped to a rotary drum filter where the essentially clear liquid
and solid waste products are separated. The clear liquid (stream 10) is
returned to the system for further utilization. The solid wastes, in the
form of filter cake containing 40% (by weight) water (stream 3). are
removed from the rotary drum filter and conveyed to a storage bin to await
transportation to the dump site. Because of the heavy particulate loading,
more filter cake is produced during coal firing than during oil firing.
The on-site landfill, which is the final disposal facility for all of
the solid waste generated at the facility, has several test wells from which
samples are collected every three months and sent to an independent labora-
tory for analysis. In addition, monthly tests are conducted by plant per-
sonnel to monitor sodium and specific conductivity. With permission of the
Pennsylvania Department of Environmental Resources, this site is being used
as an experimental disposal area for the filter cake from the FMC unit.
BOILER SLOWDOWN
There are two blowdown sources in the boiler system: the steam drum
and the mud drum. There is a continuous blowdown from the steam drum
which keeps the level of suspended solids in the boiler feedwater within an
3-5
-------
acceptable range. Tests of the steam drum blowdown effluent are made every
four hours and adjustments to blowdown rate are made accordingly. The mud
drum is blown once per shift.
The effluent from both blowdowns is sent to the same pit that collects
effluent from the water pretreatment unit.
TEST DESCRIPTION
Multi-media emission tests were conducted on Boiler No. 4 of the Fire-
stone Plant from 27 September through 8 October 1977. Solid, liquid and
gaseous emission streams were sampled during coal firing and during oil
firing to obtain data for the assessments. Flue gas sampling was
conducted before and after the pilot flue gas desulfurization
unit to establish which pollutants are removed, modified, or produced
by the control device.
Emissions were characterized using EPA's phased approach to sampling
and analysis. This approach utilizes two separate levels of sampling and
analytical effort (Level 1 and Level 2). Level 1 is a sampling and analysis
procedure accurate within a factor of about 3. This level provides pre-
liminary assessment data and identified problem areas and information gaps
which are then used to form the Level 2 sampling and analysis effort.
Level 2 provides more accurate detailed information that confirms and
expands the information gathered in Level 1. The methods and procedures
used for Level 1 sampling and analysis are documented in the manual, "Com-
bustion Source Assessment Methods and Procedures Manual for Sampling and
Analysis", September 1977. The Level 2 methods and procedures included
"state-of-the-art" techniques as adapted to the needs of this site.
They are delineated in Volume III Appendices B and C.
Normally all Level 1 samples are analyzed and evaluated before moving
to Level 2. Because of program time-constraints, the Level 1 and Level 2
samples were obtained during the same test period. However, analysis of
the samples did proceed in a phased manner except where sample degradation
was of concern. In those cases, Level 2 analyses were performed on
the samples prior to completion of Level 1 analyses.
The industrial boiler assessment tests were conducted during both coal
and oil firing. Figure 3-3, the system schematic for Boiler No. 4, includes
3-6
-------
EXHAUST
GAS TO STACK
EXHAUST GAS
TO STACK
FEEDWATER
FROM
PRETREATMENT
UNIT
TO MUNICIPAL
SEWAGE
TREATMENT
LEGEND
1 - FUEL
2 - SLOWDOWN
3- FLYASI
4 - EXHAUST GAS
FGD INLET
5 - EXHAUST GAS
FGD OUTLET
6 - SCRUBBER CAKE
7 - MAKE UPWATER
8 - SCRUBBER FEED SOI IDS
Figure 3-3. Boiler system schematic and sampling
locations.
3-7
-------
the pilot flue gas desulfurization unit and shows all sample locations.
Parameters sampled during coal and oil firing at each location are summarized
in Table 3-1. The table also identifies the sampling and analysis method
used to characterize each parameter. Volume III contains a more complete
description of the sampling and analysis activities.
The boiler exhaust gas was sampled at the inlet and outlet of the
desulfurization unit. Integrated bag samples were taken at both points in
each test.
Continuous monitors for CO, N0/N0x, S02, and total hydrocarbons (as
CH4) were installed in the system as shown in Figure 3-4 and operated during
all tests. A Thermal Electron Corporation (TECO) gas conditioner was used
to remove condensate and particulate from the flue gas prior to entering
the CO, NOX, and S02 analyzers. Model numbers for all analyzers are shown
in Table 3-1 .
The Source Assessment Sampling System (SASS) was used to collect both
gaseous and particulate emission samples at the inlet and outlet for Level 1
organic and inorganic analysis. The train was run for 6 to 8 hours until a
minimum of 30 cubic meters of gas had been collected.
Previous sampling and analysis efforts had indicated possible inter-
ference of SASS train materials on certain organic and inorganic analysis
when at the lower detection limits of Level 2 methods. To avoid this possi-
bility, all glass sampling trains were used to collect Level 2 samples.
Two Method 5 sampling trains were modified for Level 2 organic and inor-
ganic sample acquisition. Both trains sample approximately 10 cubic meters
of flue gas during a 6- to 8-hour run time. The Level 2 trains were run
at the inlet and outlet of the FGD unit for both coal and oil firing.
A controlled condensate train (Goksoyr-Ross) was used at each location
during coal and oil firing to obtain samples for S02, S03 (as H2S04), par-
ticulate sulfate, HC1 and HF .
During Level 2 test runs, Anderson Cascade impactors were used to
obtain particulate samples by particle size fraction.
3-8
-------
TABLE 3-1. PARAMETERS SAMPLED FOR COAL AND OIL FIRING
Location Parameter
Sampling Method
Analysis
4 & 5
FUEL (coal & oil)
C, H, N, S, ash,
moisture, heating
value
inorganics
COMBINED SLOWDOWN
alkalinity/acidity
PH
conducti vi ty
hardness
TSS
nitrate
sulfate
sulfite
phosphate
ammonia
nitrogen
organics
FLYASH
i norganics
organics
FLUE GAS (inlet & out!
CO
C02
NO/N02/NOX
N2,02
S02
S02/S03
H2S04 HCI HF
participate sulfate
total hydrocarbons
(as CH4)
C] - CG Organics
particulate and
vapor
particulate sizing
Grab
Composite dipper
Composite grab
Continuous, Beckman
Model 400
Grab (bag)
SASS
Method 5
Anderson impactor
SASS
Ultimate (lab)
Level II (lab)
On-site HACH kit
Level 1 & 2 (lab)
Level 1
Level 1
2 (lab)
2 (lab)
et)
Continuous, Beckman Direct reading
Model 865
Grab (bag)
Grab (bag)
Continuous, TECO
Model 10A
Grab (bag)
Continuous, TECO
Model 41
Goksoyr-Ross
GC (TCD) on site
GC (TCD) on site
Direct reading
GC (TCD) on site
Direct reading
Level 2 (lab)
Direct reading
GC (FID) on site
Level 1 (lab)
Level 2 (lab)
Level 2
Level 1
(continued]
3-9
-------
TABLE 3-1. (Continued)
-ocatlon Parameter Sampling Method Analysis
6 SCRUBBER CAKE Composite grab
inorganics Level 1 & 2 lab)
organics Level 1 & 2 (lab)
7 BOILER AND SCRUBBER Top grab
MAKEUP WATER
organics Level 1 (lab)
inorganics Not required
8 SCRUBBER MAKEUP Grab Not required
SOLIDS
The combined boiler blowdown was sampled using the composite dipper
method. Boiler and scrubber makeup water were sampled by the top grab
method. Samples from each location received the analyses shown in
Table 3-1 for combined blowdown. In addition, samples from each location
were extracted with methylene chloride and returned to the lab for further
analysis.
Composite samples of the fly-ash and scrubber filter cake were collected
per Level 1 procedures and returned to the lab for analysis. Grab samples
of the scrubber feed solids were also obtained.
3-10
-------
EXHAUST
GAS INLET
FGD UNIT
HEAT TRACED SAMPLE LINES,
CO
ANALYZER
NO/NOX
ANALYZER
EXHAUST
GAS OUTLET
THC
ANALYZER
GAS CONDITIONER
S02
ANALYZER
Figure 3-4, Flue gas continuous monitor setup.
3-11
-------
SECTION 4
COMPARATIVE ASSESSMENT OF COAL AND OIL FIRING CASES FOR AN INDUSTRIAL BOILER
This section provides a comprehensive multimedia assessment and
comparison of emissions/effluents associated with coal and oil firing in
an industrial boiler equipped with an FGD system. Data from Level I/
Level 2 sampling and analyses were utilized to quantitatively determine
and compare emissions in gas, solid and liquid waste streams generated dur-
ing coal and oil firing. The performance of pollution control equipment
during coal and oil firing was evaluated. Waste stream pollutant concen-
trations during coal and oil firing are compared.with Minimum Acute
Toxicity Effluent (MATE) values, when appropriate, to provide an indication
of risk to public health and ecology. Simplified air quality models were
used to determine the relative ground level air quality resulting from
uncontrolled and controlled emissions from both fuels.
TEST CONDITIONS
Five tests were performed on the industrial boiler at Firestone for
each of two fuels, a high volatile bituminous coal and a Number 6 fuel oil.
Unit loading ranged from 31,800 to 45,400 kg steam per hour (70,000 to
100,000 pounds per hour) which corresponds to between 70 and 100% of full
load operation for this boiler. Specific test conditions for both fuels
are summarized in Table 4-1. Tabulated fuel feed rates are nominal,
although their accuracies have been estimated from fuel analyses and steam
production data under the assumption of 90% thermal efficiency. Nominal
coal feed rates appear to be accurate to within 13%, while oil feed rates
are accurate to approximately 3%. Oxygen concentrations presented in
Table 4-1 were measured in flue gas samples drawn from the inlet of the
system's wet scrubber unit. Due to air leakage into upstream ducting
operating at sub-atmospheric pressure and possibly air leakage into the flue
gas bag sampling system, tabulated oxygen concentrations are not necessar-
ily representative of concentrations at the furnace outlet. Oxygen con-
centrations of 3 to 4% in the furnace after combustion are typical for this
unit during normal operation; this concentration range corresponds to an
excess air input of approximately 16 to 25%. Excess air estimates presented
4-1
-------
TABLE 4-1 . SUMMARY OF TEST CONDITIONS
Test
No.
200
201-1
201-2
201-3
201-4
202-1
202-2
202-3
202-4
203
Steam Production Rate
kg
steam/hr
39,700
44,200
43,100
34,000
40,800
45,400
45,400
44,200
42,200
31,800
Ibs.
steam/hr
87,500
97,500
95,000
75,000
90,000
100,000
100,000
97,500
93,000
70,000
% of Nominal Fuel
Maximum Feed Rate,
Load kg/hr gal/hr
COAL FIRING
87.5 3629
97.5 3629
95.0 3629
75.0 3175
90.0 3629
OIL FIRING
100 900
100 900
97.5 880
93.0 805
70.0 600
% 02 at
Scrubber
Inlet*
7.8
8.2 ,
8.4
8.3
6.7
5.8
6.3
6.1
4.0
Not
Measured
Estimated %
Excess Air,
to Furnace
20
20
20
20
20
21
21
21
21
21
Due to air leaks in ducting upstream of the scrubber inlet, tabulated 02 values are not
representative of combustion zone 02 concentrations. Combustion zone 02 concentrations
normally range from 3 to 4% for this unit.
02 - CO/2
0.264 N2 - (02 - CO/2)' where °2 was assumed to be
excess air is estimated to be 100 x
3.5% and other species concentrations were computed from fuel analyses.
-------
in the table were computed assuming an average oxygen concentration of 3.5%
in the furnace after combustion and utilizing ultimate analysis of the
respective fuels.
Test data relating to flue gas flow rates and scrubber loading are
summarized in Table 4-2. Flue gas flow rates measured at the scrubber
inlet (expressed as dry standard cubic meters per minute, or dscm/min) are
presented in the first column. For discussion in this report, standard
temperature and pressure are defined as 20°C and one atmosphere, respec-
tively. Typical inlet and outlet gas temperatures for the scrubber unit
were 300°F and 125°F, respectively. Measured flow rates correspond to the
scrubber loading listed in the second column of the table. An average
scrubber loading of 96 dscm/min or 54% of design load was maintained during
coal firing while a load of 180 dscm/min or 102% of design load was main-
tained during oil firing. Differences in scrubber loading for the two
fuels are due to multiclone malfunction during the test period which
resulted in an unusually high particulate loading at the scrubber inlet
during coal firing. This high particulate loading increased the scrubber
cake production rate per unit volume of flue gas processed and, owing to
fixed capacity scrubber cake disposal facilities, necessitated a reduction
in scrubber loading during coal firing.
Total flue gas flow rates presented in Table 4-2 were computed from
fuel analyses, fuel feed rate data and flue gas oxygen analyses utilizing
the following expression:
nFG
4.762 (nc + ns) + .9405 nR - 3.762 n
1 - 4.762 (02/100)
where:
nrr = gm moles of dry effluent/gm of fuel.
r b
n. = gm moles of element j in fuel per gm of fuel.
J
0~ - volumetric $2 concentration in percent.
4-3
-------
TABLE 4-2. FRACTION OF FLUE GAS PROCESSED BY
THE SCRUBBER DURING EACH TEST
Test No.
200
201-1
201-2
201-3
201-4
Average
202-1
202-2
202-3
202-4
203
Average
Flow Rate
at Scrubber
Inlet,
dscm/min*
99
91
89
98
102
96
193
192
189
155
171
180
% of Design
Load
COAL FIRING
56
51
50
55
58
54
OIL FIRING
109
109
108
88
97
102
Total
Flue Gas
Flow Rate,
dscm/min*
754
761
798
684
706
741
824
850
818
657
537
737
Fraction of
Total Flue Gas
Processed by
the Scrubber
0.13
0.12
0.11
0.14
0.14
0.13
0.24
0.23
0.23
0.24
0.32
0.25
-------
The scrubber is a pilot unit and, as such, was not sized to process
the entire flue gas output of the furnace. As indicated in Table 4-2, the
slipstream drawn for scrubber processing represented from 11 to 32% of the
total flue gas generated.
Ultimate analyses of the feed coal and oil, averaged over the five
tests run with each fuel, are presented in Table 4-3, along with standard
deviations associated with averaging. The fuel compositions were essential-
ly constant during the testing. The oil heat content is about 40% higher
for oil than for coal, 40,741 vs 29,485 kJ/kg. To compare ash, sulfur, and
nitrogen concentrations for the two fuels, these values are normalized to a
weight per heat content basis, yielding 3360 ng ash/J for coal vs 4.9 ng
ash/J for oil, 556 ng S/J for coal vs 481 ng S/J for oil, and 312 ng N/J
for coal vs 88 ng N/J for oil. Laboratory tests have shown that 30 to 60%
of the fuel nitrogen may be expected to be emitted as NO , as is d'iscussed
X
later (Reference 1).
Additional analyses were performed on fuel samples from tests 201-1
(coal) and 202-4 (oil) to determine concentrations of 20 trace elements
(Ca, Mg, Sb, As, B, Cd, Cr, Co, Cu, Pb, Mn, Mo, Ni, V, Zn, Se, Sr, Zr, Be,
and Hg) and two minor elements (Fe and Al). These data are presented in
Table 4-4. The method employed for analysis of most of these elements was
inductively coupled plasma optical emission spectroscopy (ICPOES) which
is generally considered to be more accurate than spark source mass spec-
trometry (SSMS). However, a feed coal sample from test 200 was analyzed
for the trace elements boron and beryllium by SSMS. Oil beryllium was also
analyzed by SSMS on a sample from test 203. Mercury was analyzed using
cold vapor analysis on samples from tests 200 (coal) and 203 (oil). Several
of the oil trace elements were below the ICPOES detection limit. Approxi-
mate values were calculated for these elements by using the concentrations
found at the scrubber inlet, assuming that essentially all of the oil
trace elements reach the scrubber. As no bottom ash was generated during
oil firing, this assumption should be valid. The value for oil arsenic
presented in the table, 2 ppm, was also calculated because the value
obtained from ICPOES analysis, 45 ppm, appeared to be unreasonable compared
to both the SSMS value (0.1 ppm) and the typical ranges found in the
1iterature.
4-5
-------
TABLE 4-3. SUMMARY OF ULTIMATE FUEL ANALYSES (5 TEST AVERAGES)
Component
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
kJ/kg
Coal
Weight %
7.15
72.10
4.28
0.92
0.12
1.64
9.90
3.89
29,485
a
0.86
1.07
0.06
0.07
0.02
0.23
0.85
0.23
459
Oil
Weight %
~o
86.28
10.92
0.36
N.A.X
1.96
0.02
0.46
40, 741 f
at
-
0.39
0.03
0.06
-
0.08
0.004
0.40
-
ta = one standard deviation.
M
n - not analyzed.
*The heat content of the oil burned is nearly constant at this value;
individual values were not available.
4-6
-------
TABLE 4-4. CONCENTRATION OF MAJOR TRACE ELEMENTS IN OIL AND COAL
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Be
Hg
ppm in
Fuel Oil*
5.50
<0.04
0.03**
2.0AA
<0.15
<3.5
2.2
<1 .25
1.40
12.3
2.6**
0.4**
2.9**
16.0
36.5
3.0
**
0.7
0.23
3.5
<0.05
<0.05>;
0.09*X
Typical
RangeA
No data
No data
0.002-0.8
0.0006-1.1
No data
No data
0.002-0.02
No data
No data
0.003-14
No data
0.001-6
<0.1-1 .5
14-68
15-590
No data
0.03-1
No data
No data
No data
No data
0.02-30
Reference
2
2
2
2,6
2
2
7
7
2
2
ppm in
Coalt
770
350
85
137
2.4f
3.5
48
127
72
12,250
85
12
293
37
47
56
73
68
14,000
270
2.3 f
0.1 4Y
Typical
Range'1"''
0-1600
0-959
0.2-8.9
0.5-93
4-115
0.1-65
4-144
0.5-43
3-61
0.3-40,000
4-218
6-181
0.4-30
2-80
2-147
6-5,350
0.4-74
No data
0.4-40,700
8-133
0.6-4.1
0.07-0.49
Reference
3,5
3,5
3
2,3
2,4
3
2,4
2,3
2,3
3,5
2,3
3
2,3
2,3
2,3,4
3
3,4
3,5
3
2
2
* Test 202-4 .
A Except for V and Ni, these ranges are for U.S. and foreign crude oils.
Ranges of V and Ni concentrations are for fuel oils.
t Average of two feed coal samples from test 201-1 .
tt Typical range for Appalachian and Eastern Interior Basin coals.
** Values were calculated from concentrations at the scrubber inlet when
ICPOES analysis provided upper limit data only.
AA Arsenic concentration calculated from concentration at the scrubber
inlet (see text).
x Performed by SSMS on a feed oil sample from test 203.
f Performed by SSMS on a feed coal sample from test 200.
xx Performed by cold vapor analysis on a feed oil sample from test 203.
Y Performed by cold vapor analysis on a fuel coal sample from test 200.
4-7
-------
Considering the uniformity of fuel ultimate analyses obtained during
the test periods, it appears reasonable to assume that tabulated trace and
minor element analyses are typical of the fuels fired during the five day
test period. Although analyses of other coal samples from the same source
(mine or cleaning plant) are not available for direct comparison, analyses
of most trace and minor elements presented in Table 4-4 appear to be con-
sistent with concentration limits typifying Appalachian and Eastern Interior
Basin coals. No coal strontium analyses were found for comparison. Trace
elements present in somewhat higher concentrations than are indicated to be
typical by the limited published data are antimony, arsenic, cobalt, copper,
molybdenum, and zirconium. Typical ranges of some trace and minor elements
in U.S. and foreign crude oils and for nickel and vanadium in fuel oils are
also presented in Table 4-4 for comparison. Analyses of most trace and
minor elements for which typical oil values are available appear to be con-
sistent with the literature values. Arsenic and molybdenum values are on
the high side, and chromium is quite a bit higher than the typical crude oil
values. However, the significance of these higher concentrations is not
apparent due to the limited quantity of published data and the complete
absence of source specific data.
STACK EMISSIONS
As discussed previously, the wet scrubber unit processed a slipstream
of the total flue gas generated, by the furnace. Analyses of the slipstream
have been used to estimate total boiler emissions on the basis of 100% of
the flue gas being processed by the scrubber. That is, it was assumed that
additional scrubber modules could be added to the system such that the total
flue gas output would be processed with a mean scrubber efficiency identical
to that obtained using the pilot scrubber. All emissions data presented in
the following sections are based on this assumption.
Criteria Pollutants
Federal New Source Performance Standards (NSPS) currently in effect
define allowable emission rates of NOX (as N02J, S0£ and total particulates
from fossil fuel fired utility boilers having 25 MW output or greater.
More stringent limitations have been proposed by EPA for NOX and total
particulate emissions and additional limitations on S02 emissions are being
4-8
-------
considered for proposal. Federal NSPS do not currently address either CO
or total hydrocarbon emissions. Existing NSPS and corresponding proposed
or potential emission standards for coal and oil-fired utility boilers are
summarized in Table 4-5.
Similar standards relating to industrial units have not been promul-
gated to date. Therefore, criteria pollutant emission data presented in
this section will be discussed in the context of existing and proposed
Federal NSPS for utility boilers.
As mentioned previously, 5 tests were performed on the Firestone
industrial boiler for each fuel. Criteria pollutant concentrations were
generally measured at frequent intervals during each test and averaged to
obtain the mean concentrations for each test. The 5-test averages of
criteria pollutant emissions data are presented in Table 4-6. Average
emissions data from the individual tests are presented in Tables 4-7 and
4-8 for coal and oil, respectively. Additionally, the 5-test averages
of scrubber inlet data are presented in Table 4-9 for comparison with the
EPA AP-42 (Reference 8) emission factors for uncontrolled sources. Tabu-
lated AP-42 emission factors are for 10 MW industrial boilers firing the
appropriate fuel Factors for coal-fired boilers are specific to dry
bottom units. The data are discussed by specific compound in the ensuing
sub-sections.
Nitrogen Oxide
Mean NO emission factors prior to FGD processing were 421 ng/J
(0.98 Ib/MM Btu) and 168 ng/J (0.39 Ib/MM Btu) for coal and oil, respec-
tively. The full load NO emission factors prior to FGD processing were
491 ng/J (1.14 Ib/MM Btu) for coal firing and 175 ng/J (0.41 Ib/MM Btu)
for oil firing. The full load emission factor for coal firing is nearly
43% higher than the average emission factor of 343 ng/J (0.80 Ib/MM Btu)
tabulated in AP-42. On the other hand, the emission factor for oil firing
is 19% lower than the tabulated AP-42 emission factor of 217 ng/J
(0.51 Ib/MM Btu). However, examination of published data from industrial
boilers indicates that each emission factor is well within the range typical
for the respective fuel (Reference 9). Average measured NO emission factors
A
4-9
-------
TABLE 4-5. EXISTING AND PROPOSED FEDERAL EMISSION STANDARDS
Compound
Coal-Fired Utilities
NSPS
Proposed or Potential
Standard
Oil-Fired Utilities
NSPS
Proposed or Potential
Standard
I
o
N0x (as
sc
Total
Participates
300 ng/J
(0.7 Ib/MM Btu)
520 ng/J
(1.2 Ib/MM Btu)
43 ng/J
(0.10 Ib/MM Btu)
220 ng/J (0.50 Ib/MM Btu)
max. with 65% reduction.
520 ng/J (1.2 Ib/MM Btu)
max. with 90%* reduction
to 85 ng/J (0.20 lb/
MM Btu)
13 ng/J (0.03 Ib/MM Btu)
max. with 99% reduction
129 ng/J
(0.30 Ib/MM Btu)
344 ng/J
(0.80 Ib/MM Btu)
43 ng/J
(0.10 Ib/MM Btu)
129 ng/J (0.30 Ib/MM Btu)
max. with 65% reduction
344 ng/J (0.80 Ib/MM Btu)
max. with 90%* reduction
to 85 ng/J (0.20 lb/
MM Btu)
13 ng/J (0.03 Ib/MM Btu)
*The 90% reduction is a potential standard.
-------
TABLE 4-6. CRITERIA POLLUTANT EMISSIONS FOR AN
INDUSTRIAL BOILER IN THERMAL UNITS
Pollutant
ng/J (Ib/MM Btu)
Coal Firing
Oil Firing
Before Scrubber
After Scrubber
Before Scrubber
After Scrubber
N0y (as NOJ
.p, X c
i co
S00
Organics (as CH.)
Total Particulates
421 (0.98)
15.9 (0.04)
1112 (2.59)
5.79 (0.01)
2951 (6.86)
372 (0.87)
14.3 (0.03)
36.3 (0.08)
6.29 (0.01)
18.6 (0.04)
168 (0.39)
5.47 (0.01)
993 (2.31)
2.49 (0.01)
113 (0.26)
161 (0.37)
5.31 (0.01)
26.8 (0.06)
2.74 (0.01)
17.6 (0.04)
-------
TABLE 4-7. SUMMARY OF CRITERIA POLLUTANT EMISSIONS - COAL FIRING
Test No.
200 Inlet
200 Outlet
201-1 Inlet
201-1 Outlet
201-2 Inlet
201-2 Outlet
201-3 Inlet
201-3 Outlet
201-4 Inlet
201-4 Outlet
Average Inlet
Average Outlet
NOY
A
(as NOJ
C
417
(0.97)
367
(0.85)
491
(1.14)
457
(1.06)
455
(1.06)
358
(8.33)
330
(0.77)
258
(0.60)
409
(0.95)
420
(0.98)
421
(0.98)
372
(0.87)
CO
20.7
(0.05)
18.5
(0.04)
16.5
(0.04)
15.7
(0.04)
17.7
(0.04)
15.9
(0.04)
16.2
(0.04)
12.7
(0.03)
8.56
(0.02)
8.95
(0.02)
15.9
(0.04)
14.3
(0.03)
so2
1009
(2.35)
25.4
(0.06)
1284
(2.99)
39.0
(0.09)
1295
(3.01)
35.5
(0.08)
1028
(2.39)
31.8
(0.07)
942
(2.19)
49.7
(0.12)
1112
(2.59)
36.3
(0.08)
ng/J
HC
(as ClU
*T
3.79
(0.01)
4.22
(0.01)
4.35
(0.01)
5.22
(0.01)
0.88
(0.00)
1.33
(0.00)
10.9
(0.03)
10.9
(0.03)
8.95
(0.02)
9.73
(0.02)
5.79
(0.01)
6.29
(0.01)
(Ib/MM Btu
Cl - C6
Organics
<5.49
(<0.01 )
<5.49
(<0.01)
<5.65
(<0.01 )
<5.65
(<0.01)
<5.75
(<0.01)
<5.75
(<0.01)
<5.69
(<0.01 )
<5.69
(<0.01)
<5.06
(<0.01 )
<5.06
(<0.01)
<5.53
(<0.01)
<5.53
(<0.01)
C7 - C16
/ i \j
Organics
0.34
{0.00)
0.27
(0.00)
--
--
--
--
__
--
--
--
0.34
(0.00)
0.27
(0.00)
Organics
Higher
Than
C16
2.28
(0.01)
0,33
(0.00)
--
--
--
--
--
--
--
--
2.28
(0.01)
0.33
(0.00)
Total
Participates
2361
(5.49)
14.3
(0.03)
3122
(7.26)
20.9
(0.05)
--
--
--
3370
(7.84)
20.6
(0.05)
2951
(6.86)
18.6
(0.04)
-------
TABLE 4-8. SUMMARY OF CRITERIA POLLUTANT EMISSIONS - OIL FIRING
I
CO
Test No.
202-1 Inlet
202-1 Outlet
202-2 Inlet
202-2 Outlet
202-3 Inlet
202-3 Outlet
202-4 Inlet
202-4 Outlet
203 Inlet*
203 Outlet*
Average
Inlet
Average
Outlet
N0y
/\
175
(0.41)
166
(0.39)
175
(0.41)
165
(0.38)
181
(0.42)
177
(0.41)
141
(0.33)
138
(0.32)
--
--
168
(0.39)
161
(0.37)
CO
5.08
(0.01)
4.70
(0.01)
5.30
(0.01)
5.03
(0.01)
6.22
(0.01)
5.92
(0.01)
5.30
(0.01)
5.60
(0.01)
--
--
5.47
(0.01)
5.31
(0.01)
so2
938
(2.18)
32.1
(0.07)
1075
(2.50)
29.2
(0.07)
1085
(2.52)
26.7
(0.06)
874
(2.03)
19.2
(0.04)
--
--
993
(2.31)
26.8
(0.06)
ng/J
HCf
(as CH4)
2.84
(0.01)
3.20
(0.01)
4.61
(0.01)
5.01
(0.01)
1.71
(0.00)
1 .98
(0.01)
0.82
(0.00)
0.76
(0.00)
--
--
2.49
(0.01)
2.74
(0.01)
(Ib/MM Btu)
C - C
Ll L6
Organics
<4.63
(< 0.01)
<4.63
(< 0.01)
<4.79
(< 0.01)
<4.79
(< 0.01)
<4.73
(< 0.01)
<4.73
(< 0.01)
<4.14
(< 0.01)
<4.14
(< 0.01)
--
--
<4.57
(< 0.01)
<4.57
(< 0.01)
C7 " C16
Organics
--
--
--
--
--
--
--
0.17
(0.00)
0.02
(0.00)
0.17
(0.00)
0.02
(0.00)
Organics
Higher
Than C-]5
--
--
--
2.61
(0.01)
0.43
(0.00)
2.61
(0.01)
0.43
(0.00)
Total
Particulates
166
(0.39)
- 20.2
(0.05)
--
--
59.0
(0.14)
15.0
(0.03)
--
--
113
(0.26)
17.6
(0.04)
Emission factors were computed assuming an 0-, concentration of 5.5%, the average concentration for test 202.
Total hydrocarbons as determined by FIP.
-------
TABLE 4-9. COMPARISON OF CRITERIA POLLUTANT EMISSIONS WITH
EMISSION FACTORS FOR UNCONTROLLED BOILERS
Dr\ 1 1 i if" a n t"
NO (as N00 at full
x 2
CO
so2
Organics (as CH^)
Total Participates
Coal
Test Data
Before
Scrubber
load) 491 (1.14)
15.9 (0.04)
1112 (2.59)
5,79 (0.01)
2951 (6.86)
ng/J (1
Fi ring
AP-42
Emission
Factor*
343 (0.80)
19 (0.04)
1189 (2.77)
5.72 (0.01)
3212 (7.47)
b/MM Btu)
Oil
Test Data
Before
Scrubber
175 (0.41)
5.47 (0.01)
993 (2.31)
2.49 (0.01)
113 (0.26)
Firing
AP-42
Emission
Factor*
217 (0.51)
14.7 (0.03)
904 (2.10)
2.94 (0.01)
29.4 (0.07)
Factors are computed from AP-42 values for uncontrolled sources using the national average
heating values of 11,263 Btu/lb for bituminous coal and 146,285 Btu/gal for fuel oil,[10].
-------
after FGD were 372 ng/J (0.87 Ib/MM Btu) for coal firing and 161 ng/J (0.37
Ib/MM Btu) for oil firing. As such, controlled NOX emission rates exceed
NSPS limitations by 23 to 25% (NSPS for N0v is 300 ng/J for coal and 129
A
ng/J for oil). Data presented in Tables 4-1, 4-7 and 4-8 indicate that
NO emission varied with boiler load for both fuels, as expected. NO
. ^
emission factors measured at the scrubber inlet are presented in Figure 4-1
as a function of boiler loading for both fuels. The straight line plots
presented in the figure were determined by linear regression analyses of
the data. It is interesting to note that these lines have very similar
slopes, 6.72 ng/j.% loading for coal firing and 4.79 ng/j-% loading for oil
firing. These data indicate that for boiler loadings between 90 and 100%,
NO emission factors from coal firing are approximately three times greater
X
than from oil firing. While this factor of three compares favorably with
the ratio of fuel nitrogen contents (312 ng N/J in coal and 88.4 ng N/J in
oil leads to a fuel nitrogen ratio of 3.5), total NO emissions are com-
X
posed of both thermal and fuel NO components. Laboratory data indicate
X
that for these fuel nitrogen concentrations, 30 to 60% of the fuel nitrogen
might be expected to form NO , [1]. Therefore, fuel nitrogen content may be
A
a principal factor in the difference between NO emissions from coal and
X
oil-fired units.
NO data generally indicate a reduction of NO emissions across the
X " A
scrubber for both fuels; the magnitude of this apparent reduction ranges
from approximately zero to 24% for coal firing and from 2 to 6% for oil
firing. However, NO reductions measured during coal firing could not be
X
correlated to variables monitored during testing (NO concentration,
X
flue gas temperature, flow rates). Further, NO reduction trends paral-
X
leled trends in CO reduction which suggested a sampling phenomenon rather
than chemical removal. Subsequent examination of the sampling train dur-
ing oil firing tests revealed a small air leak in the sampling line to the
scrubber outlet. This problem, associated with a faulty coupling, was
rectified prior to tests 202-3 and 202-4. Data from these latter tests
indicate NO removals of approximately 2% across the scrubber. Higher
A
removals obtained earlier during the test period are considered to be
reflective, at least in part, of air leak problems and must be held sus-
pect. NO removal in both wet and dry FGD systems has been reported in the
X
4-15
-------
40C
°> 300
of
o
h-
u
z
o
oo
oo
2
o
200
100
COAL FIRING
OIL FIRING
90
BOILER LOADING, %
100
Figure 4-1. The Effect of Boiler Loading on MO Emission Factors
A
4-16
-------
literature, although no information is available regarding the chemistry of
such occurences, [11], [12]. It is feasible that some degree of NOV removal
A
may be effected by dissolution of NCL in the slightly acidic scrubber
solution.
Carbon Monoxide
Emission rates of CO prior to FGD were 15.9 ng/J (0.04 Ib/MM Btu) and
5.47 ng/J (0.01 Ib/MM Btu) for coal and oil firing, respectively. Average
measured CO emissions for coal firing compare well with the AP-42 emission
factor of 19 ng/J (0.04 Ib/MM Btu). However, CO emissions for oil firing
are 63% lower than the respective AP-42 value of 14.7 ng/J (0.03 Ib/MM Btu).
Thus, while AP-42 data indicate oil firing CO emission factors to be 23%
lower than those for coal firing, measured data for coal and oil firing
differ by a factor of three. A slight reduction of CO emissions across
the scrubber was observed during most tests. Average CO reductions for
coal and oil firing were 10 and 3% respectively. As discussed previously,
CO reduction trends during coal firing and early oil firing tests are
reflective, to some extent, of air leaks in the flue gas sampling train.
Further, at these low CO concentrations, analytical sensitivity is in the
range of 7-15% of the measured value. Therefore, the slight reductions
are considered to be of little significance.
Sulfur Dioxide
Average S0? emission rates prior to scrubbing were 1112 ng/J (2.59
Ib/MM Btu) and 993 ng/J (2.31 Ib/MM Btu) for coal and oil firing, respec-
tively. These uncontrolled emission factors correspond well with the
respective AP-42 values of 1189 ng/J (2.77 Ib/MM Btu) for coal firing and
904 ng/J (2.10 Ib/MM Btu) for oil firing. Average S02 emission rates after
scrubbing were 36.3 ng/J (0.08 Ib/MM Btu) for coal firing and 26.8 ng/J
(0.06 Ib/MM Btu) for oil firing. A mean scrubber efficiency of 97% is
indicated for both fuels by these data. Measured SO,-, emission rates after
scrubbing are lower than either existing or potential NSPS limitations.
Hydrocarbons
Total organic emissions, expressed as methane, were analyzed with a
Flame lonization Detector (FID) during coal and oil firing tests. Average
4-17
-------
hydrocarbon emissions prior to scrubbing were 5.79 ng/J (0.01 Ib/MM Btu)
for coal firing and 2.49 ng/J (0.01 Ib/MM Btu) for oil firing. Measured
emissions rates correspond well with the AP-42 values of 5.72 ng/J
(0.01 Ib/MM Btu) for coal firing and 2.94 ng/J (0.01 Ib/MM Btu) for oil
firing. It should be noted that, during these tests, the analyzed flue
gas slipstream was processed through a gas conditioner situated ahead of
the FID in the analytical train. Therefore, higher molecular weight
organics may have been condensed or scrubbed from the flue gas prior to
analysis.
Hydrocarbon emissions measured by FID appeared, on the average, to
increase across the scrubber by approximately 10% for both fuels. These
data were evaluated in terms of real time scrubber inlet and outlet data
pairs obtained not more than 30 minutes apart. The average increase in
hydrocarbons across the scrubber is not statistically significant for coal
firing data due to concentration fluctuations during testing. However,
real time data pairs measured during coal firing do show a statistically
significant difference with scrubber outlet samples being biased high
relative to inlet samples. The magnitude of this bias is approximately
5 ppm (1.5 ng/J at the excess oxygen levels measured). The cause of the
observed bias is not known at the present time although the possibility
of moisture interference, improper FID calibration or variable sample gas
flow rate has been evaluated and subsequently discarded. Real time data
pairs measured during oil firing indicate that hydrocarbon emissions at
the scrubber inlet and outlet are not statistically different. Whether
the absence of significant bias for oil firing results from the lower
emission factor associated with oil firing.or reflects differences in
combustion products from the two fuels cannot be determined from available
data.
In addition to FID analyses of total hydrocarbons, gas chromatograph
analyses were performed on limited bag' samples of flue gas and catches
from the Level 1 sampling (SASS train). Additionally, gravimetric analyses
were performed on Level 1 samples to quantify high molecular weight
organics. Each bag sample was collected over an interval of 30 to 45 min-
utes, with a single sample being collected per test. These samples were
4-18
-------
utilized to measure GI to Cg hydrocarbons. The SASS train collects approx-
imately 30 cubic meters of flue gas which are drawn isokinetically during
the test. Samples from the SASS train were analyzed to determine organics
higher than Cg. The C-, to C,g fraction was determined by gas chromatograph
while organics higher than C^, were determined gravimetrically.
Analytical results for scrubber outlet SASS train XAD-2 resin samples
were not available due to sample handling problems. However, data from
coal- and oil-fired utility boilers were utilized to obtain an average
ratio of resin-absorbed organics to all other organics collected by the
SASS train for each fuel. These ratios were used in conjunction with data
from the scrubber outlet probe rinse, resin module rinse, particulate
organics and other organic catches from the SASS train to estimate the
resin catch. Calculated outlet organic data from the C-, to C,, and higher
than C,g organic fractions are considered to be accurate to within a factor
of three to four.
Emissions of hydrocarbons higher than C,g and scrubber removal effi-
ciencies for this fraction appear to be similar for coal and oil firing
tests. As indicated in Tables 4-7 and 4-8, emission factors for organics
higher than C,fi for coal and oil firing differ by less than 15% with
2.28 ng/J (0.01 Ib/MM Btu) for coal firing and 2.61 ng/J (0.01 Ib/MM Btu)
for oil firing prior to scrubbing. Organics higher than C-,,. comprise
28 to 60% of the scrubber inlet hydrocarbons during coal firing and 35 to
94% during oil firing. Emissions of organics higher than C,fi were reduced
to 0.33 ng/J (85% removal) and 0.43 ng/J (83% removal) for coal and oil
firing, respectively.
Emissions of C7 to C,fi fractions prior to scrubbing were 0.34 ng/J
for coal firing and 0.17 ng/J for oil firing. These emission rates indi-
cate that the C-, to C,r fraction represents less than 9% of the total
/ I b
organic emissions prior to scrubbing during coal firing and less than 6%
during oil firing. Emissions of the C-, to C,, fraction after scrubbing
were 0.27 ng/J and 0.02 ng/J for coal and oil firing, respectively. These
data appear to indicate that removal of the C-, to C,g fraction by scrubbing
was 20% for coal firing and 88% for oil firing. However, noting the uncer-
tainty in outlet organic levels described previously, the 20% removal
4-19
-------
observed for coal firing may actually be as high as 97% while the
removal for oil firing may be as low as 53%. Hence, while it appears
that some removal of C7 to C,c fraction was achieved for both fuels, defi-
nite conclusions regarding the relative removals for each fuel cannot be
drawn.
Chromatographic analyses performed on the C^ to Cg hydrocarbon frac-
tions did not indicate the presence of these organics at the detection
limits indicated in Tables 4-7 and 4-8, namely 5.53 ng/J for coal and
4.57 ng/J for oil. However, note that the emissions of C-, and higher
organics prior to scrubbing are essentially the same for coal and oil
firing and that removal of these organics by scrubbing is between 2.02 ng/J
and 2.33 ng/J. Further, FID data do not show a decrease in organics across
the scrubber. These observations appear to indicate that the flue gas
slipstream analyzed by FID contained light hydrocarbon fractions but did
not include higher molecular weight organics. This may be attributed to
processing the flue gas through a gas conditioner prior to FID analysis.
As such, FID data may be reflective of C-, to Cfi hydrocarbon emissions and
indicate that the coal firing produces more C, to Cfi hydrocarbons than does
oil firing.
Total Particulates
Average emission rates of total particulates prior to scrubbing were
2951 ng/J (6.86 Ib/MM Btu) for coal firing and 113 ng/J (0.26 Ib/MM Btu)
for oil firing. A mass balance of the coal ash indicates that approxi-
mately 75% of the total ash was processed by the scrubber and that multi-
clones located upstream of the scrubber removed little or no particulate.
This observation was verified by site operators who noted that the multi-
clone unit was subject to mechanical failure during both coal and oil
firing. Hence, particulate loadings measured at the scrubber inlet appear
to be representative of uncontrolled emissions. Mean particulate loadings
at the scrubber inlet during coal firing are approximately 8% lower than
the value of 3212 ng/J (7.47 Ib/MM Btu) presented in AP-42, which repre-
sents rather good agreement. On the other hand, the average particulate
emission factor for oil firing is nearly a factor of four greater than the
4-20
-------
tabulated AP-42 value of 29.4 ng/J (0.07 Ib/MM Btu). However, data pre-
sented in Table 4-8 show that the oil firing particulate loading prior to
scrubbing was substantially larger during test 202-1 than during test 202-4,
indicating that coal ash from previous testing may have been emitted during
early oil firing tests. If particulate data from test 202-4 are assumed
to be representative of oil firing emissions, the particulate emission rate
of 59 ng/J (0.14 Ib/MM Btu) measured at the scrubber inlet exceeds the AP-42
value by a factor of two. This assumption appears to be valid since data
from Polarized Light Microscopy analyses (PLM) indicate that particulates
from test 202-4 are composed primarily of oil soot and sulfate compounds
(refer to the Inorganic subsection for analysis).
Total particulate emissions after scrubbing were 18.6 ng/J (0.04 Ib/MM
Btu) for coal firing and 17.6 ng/J (0.04 Ib/MM Btu) for oil firing. These
controlled particulate emission rates correspond to 99% and 84% removal
efficiencies for coal and oil firing, respectively. However, based on the
oil firing particulate catch known to be free of coal ash contamination, the
scrubber efficiency appears to be 75%. Controlled particulate emissions for
both coal and oil firing are well below the NSPS limitation of 43 ng/J
(0.10 Ib/MM Btu) although they are slightly higher than the proposed limi-
tation of 13 ng/J (0.03 Ib/MM Btu).
Particulate Size Distribution
Size distributions of particulates at the scrubber inlet and outlet
were determined by two methods. Due to the high particulate loading at the
scrubber inlet during coal firing, PLM analyses were utilized to obtain a
size distribution in terms of optical diameter and number of particles per
size range. All other particulate size distribution determinations involved
streams with substantially lower solids loadings and, therefore, an Anderson
cascade impactor was used. The cascade impactor data differs from PLM
analyses in that size distributions are determined in terms of aerodynamic
diameter and weight percent in each size range. Thus, data from the two
methods cannot be directly compared. For this reason, the PLM data have been
converted to the same basis as the impactor data by assuming that particulate
density is independent of particle diameter. This is a reasonable assumption
4-21
-------
because the major components of the particulates generated from coal com-
bustion, the aluminosilicates and iron oxides, are known to partition equally
among small and large particulates. With the constant density assumption,
the weight distribution in each size range would be proportional to the
product of the number distribution and the particulate volume representing
the size range. The particulate volume was calculated based on the geometric
mean diameter for the size range.
Particulate size distribution data from coal and oil firing tests are
summarized in Table 4-10. These data show a significant change in parti-
culate size distribution before and after scrubbing for both fuels. The
increase in the fraction of finer particulates across the scrubber indi-
cates that coarse particulates were removed more efficiently than fine par-
ticulates for both coal and oil firing tests. This is further indicated by
emission rate data presented in Table 4-11 which shows that particulates
larger than 3ym were removed with efficiencies of at least 97% while par-
ticulates smaller than 3ym showed little or no removal.
As discussed previously, particulates from early oil firing tests
collected prior to scrubbing appear to contain residual particulate from
coal fired tests. Since coal particulate is generally coarser than oil
particulate, contaminated oil particulate would appear to be somewhat coarser
than pure oil particulate. Thus, while data in Table 4-10 show that oil
particulate is substantially finer than coal particulate, the difference in
size distributions is probably not as great as would have been found if a
pure oil particulate sample had been sized.
It is also interesting to note that for coal-fired particulates less
than 3 ym in size, there is a net increase in emission rates across the
scrubber (Table 4-11). This net increase indicates that the venturi scrubber
is probably not effective in removing the fine particulates present in the
flue gas, and that fine particulates may be generated within the scrubber.
Based on the analysis of S03 and S04= emission data, it has been estimated
that up to 40% of the fine particulate emissions at the scrubber outlet
could be contributed by scrubber generated NaHS04. The remaining portion of
the net increase in fine particulates across the scrubber can probably be
attributed to the uncertainties associated with the assumptions used in
4-22
-------
TABLE 4-10. SCRUBBER INLET AND OUTLET
PARTICULATE SIZE DISTRIBUTION
Aerodynamic
Diameter Size
Range, Microns
< 1
1 - 3
3 - 10
> 10
Coal Firing
Scrubber
Inlet
0.0017
0.041
2.24
97.7
Weight %
(Test 201-1) Oil Firing (Test 202-1)
Scrubber Scrubber Scrubber
Outlet Inlet Outlet
62 20 83
30 1 12
7 74 5
1 5 0
TABLE 4-11. EMISSION RATES OF PARTICULATES
Aerodynamic
Diameter
Size Range,
Microns
< 1
1 - 3
3 - 10
> 10
Total
Coal Firing (Test
ks/hr
Scrubber Scrubber
Inlet Outlet
0.0055 1.30
0.13 0.63
7.3 0.15
316.5 0.021
324.0 2.10
201-1) Oil Firing (Test 202-1J
Removal kg/hr Removal
Efficiency Scrubber Scrubber Efficiency
Inlet Outlet
<0 4.48 2.27 49.2
<0 0.22 0.33 <0
97.9 16.6 0.14 97.4
>99.9 1.12 0.00 100
99.3 22.4 2.74 87.8
4-23
-------
converting PLM number size distribution data to weight size distribution,
and to calcium sulfite hemihydrate (CaS03«l/2 H20) particulates generated
by the scrubber.
Although a very slight increase in l-3ym oil-fired particulates was
observed, a net decrease in particulates less than 3ym was observed for oil
fired testing. Also, compounds associated with scrubber solution were not
conclusively identified in the oil-fired particulates at the scrubber out-
let. However, based on the results of coal-fired testing, it appears
reasonable that scrubber generated particulates were present in the scrub-
ber outlet stream during oil firing but that the high fine particulate
loading associated with oil firing masked detection of these materials.
Sulfur Compounds: SO,,, SO,, and SO.
A pulsed fluorescent analyzer was used to continuously monitor SCL
emissions for the coal and oil tests. SCL was determined as FUSO, using
the Goksoyr-Ross controlled condensation system, and SO, was determined
by anion analysis of the particulate extracts from the Method 5 sampling
train. A summary of these analytical results is presented in Table 4-12.
As can be seen from the sulfur balance, 90 to 94% of the input sulfur is
emitted as S02 when emissions are uncontrolled. The removal efficiency
for S02 is high: 95 to 97% for coal firing and 97 to 98% for oil firing.
About 30% of the SO., was also removed by the scrubber. The relatively poor
removal efficiency for S03 is an indication that SO, is either present as
very fine aerosols in the scrubber inlet, or is converted to very fine
aerosols as the flue gas stream is rapidly cooled inside the scrubber. The
higher S04~ removal efficiency indicates that S04" is probably associated
with larger particulates, which are efficiently scrubbed.
A comparison of the sulfur oxide emissions is best made by comparing
emission rates which are normalized to the amount of fuel sulfur available.
These are listed in the column "% of fuel sulfur found in flue gas at
inlet" in Table 4-12. For S02> these values are almost the same for coal
and oil. For S03, the values for oil were 50 to 75% higher than for coal.
This result is generally attributed to the fact that vanadium and nickel,
which catalyze the oxidation of S02 to S03, are usually present in higher
concentrations in oil than in coal. For sulfates, the normalized emission
4-24
-------
TABLE 4-12. S02, S03, and S04 EMISSIONS FROM COAL AND OIL FIRING
ro
en
Pnl 1 ut=mt
r u i i tj uu 1 1 u
Test
S02 201-1
201-4
S03 201-1
201-4
S04= 201-1
Total 201-1
Scrubber
Inlet
ng/J
1280
937
7.2
4.9
66.3
Oi
U 1
Scrubber
Outlet
ng/J
37.8
47.8
4.9
3.3
8.0
'
% of Fuel
Sulfur Found
in Flue Gas
at Inlet
92
94
0.4
0.4
3
95
Removal
Effi-
ciency
%
97
95
33
32
88
Test
202-1
202-4
202-1
202-4
202-4
202-4
Scrubber
Inlet
ng/J
940
874
7.5
8.4
22.9
Hi
U J
Scrubber
Outlet
ng/J
32.2
19.2
5.3
6.0
9.1
i
i
% of Fuel
Sulfur Found
in Flue Gas
at Inlet
92
90
0.6
0.7
1.6
92
Removal
Effi-
ciency
%
97
98
29
28
60
-------
rate for coal is twice that for oil. Because the S03 concentration levels
are lower than the S04= levels, this cannot be satisfactorily explained by
simply assuming a higher rate of reaction of gaseous S03 with ash particu-
lates to form metallic sulfates. A possible mechanism of metallic sulfate
production is as follows: the metal oxides in the ash may serve as cata-
lysts for the reaction of SCL to S03- The S03, which is adsorbed on the
ash surface, may then react with the surface to form a metallic sulfate,
or may desorb and then collide with ash particulates and form the sulfate.
It is thus proposed that in the coal-fired case the reaction is catalyzed
by metallic ash constituents, and SO- is formed as an adsorbed intermediate,
which then usually reacts with the ash on which it is adsorbed. In the
oil-fired case, mainly gaseous SO- is formed, the reaction being catalyzed
by Ni and V.
A comparison of scrubber efficiencies shows that for the gaseous
sulfur oxides, the removal efficiency does not depend upon the fuel used.
However, sulfates are not removed with equal efficiency from flue gases
from coal and oil firing. The higher sulfate removal from the coal flue
gases is explained by the fact that the particulates from coal firing are
larger than those from oil, and the scrubber removes larger particulates
more efficiently than smaller particulates.
Table 4-13 shows the breakdown of the sulfate emissions into the
water and acid soluble fractions before and after the scrubber. While both
types of sulfates were removed by the scrubber, the fraction of water solu-
ble sulfates increased from 56 to 88% during oil firing and from 24 to 97%
during coal firing. One explanation is that the acid soluble fraction is
more efficiently removed than the water soluble fraction. This cannot
be checked by comparing the removal efficiencies of the major element
cations (Tables 4-16 and 4-17) as a function of the solubility of their
sulfates because the types of sulfates present are not known. A second
explanation may be that the water and acid soluble fractions are removed
with comparable efficiency, and that the scrubber contributes shall quan-
tities of water soluble sulfate to the gas stream passing through. Because
of this possibility, an analysis effort utilizing Fourier Transform Infrared
4-26
-------
TABLE 4-13, SUMMARY OF SULFATE EMISSIONS
DURING COAL AND OIL FIRING
Emission Rate, nq/J
Coal - Test
Scrubber
Inlet
Water Soluble 16.0 (24%)
Acid Soluble 51.2 (76%)
Total 67.2
201-1
Scrubber
Outlet
8.1 (97%)
0.2 ( 3%)
8.3
Oil - Test
Scrubber
Inlet
12.9 (56%)
10.0 (44%)
22.9
202-4
Scrubber
Outlet
8.0 (88%)
3.5 (12%)
9.1
Analysis (FTIR) and X-Ray Diffraction (XRD) analysis was initiated to deter-
mine the nature of SQ~ emissions. For the dual alkali system, possible
sulfate species would be CaSO. and Ca(HSO.)2 from the scrubber regeneration
step, NaHSO. and Na^SO, from oxidation of NaHS03 and Na2S03- Calcium sul-
fate and bisulfate are ruled out because of the low calcium concentration
at the outlet (see Tables 4-14 and 4-15). In the coal test, FTIR and XRD
confirmed the presence of sodium bisulfate at the scrubber outlet, but not
at the scrubber inlet. This is positive proof that sulfates are generated
within the scrubber and emitted in the scrubber effluent gas in the coal-
fired test. Based on these findings, it is believed that NaHS04 emissions
from the scrubber are on the order of 1 ng/J (the difference between total
sulfate and H?S04 emissions determined as S03). Furthermore, if one
assumes that only a small fraction of the H2S04 was collected on the filter
because of the high filter temperature, then the measured sulfate emissions
could be almost totally metallic sulfates, indicating that the scrubber
contribution could be as high as 8 ng/J. This amount of scrubber generated
NaHSO, could account for 40% of the fine particulate (<3 urn) emissions at
the scrubber outlet.
In the oil-fired test, FTIR confirmed the presence of NaHS04 at both
the inlet and outlet of the scrubber, but XRD results indicated that
NaHSO, made up less than 1% of the particulate matter in the gas stream
4-27
-------
TABLE 4-14. EMISSION CONCENTRATIONS OF TRACE ELEMENTS
DURING COAL FIRING - TEST 201-1
Trace
Element
__
*
Be
Hg1"
Ca
Mg
Sb
As
*
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Scrubber
Inlet
mg/m
0.1
0.011
74
19
3.7
7.8
0.2
0.47
2.6
3.6
9.6
450
8.5
0.78
10
1.4
3.1
2.3
3.2
11
480
1.6
1100
Scrubber
Outlet
mg/m
0.002
0.005
0.036
0.011
0.025
0.22
0.03
0.0010
0.13
0.012
0.020
2.4
0.021
0.015
0.027
0.063
0.058
0.048
0.099
0.058
2.6
0.018
6.2
MATE
Value
, 3
mg/m
0.002
0.05
16
6.0
0.050
0.002
3.1
0.010
0.001
0.050
0.20
1.0
0.15
5.0
5.0
0.015
0.50
4.0
0.200
3.1
5.2
5.0
Degree
Scrubber
Inlet
1 -
50
0.22
4.6
3.2
74
3900
0.07
47
2600
72
48
450
57
0.16
2.0
93
6.2
0.58
16
3.5
92
0.32
of Hazard
Scrubber
Outlet
1.0
0.10
0.002
0.002
0.5
no
0.01
0.1
130
0.24
0.10
2.4
0.14
0.003
0.005
4.2
0.12
0.012
0.50
0.019
0.5
0.004
Approximate values as determined by Spark Source Mass Spectrometry (SSMS)
The other values presented are determined by Inductively Coupled Plasma
Optical Emission Spectroscopy (ICPOES) analysis.
Mercury was determined by cold vapor analysis of SASS train.
*Degree of hazard is defined as the ratio of the discharge concentration
to the MATE value.
4-28
-------
TABLE 4-15.
EMISSION CONCENTRATIONS OF TRACE ELEMENTS
DURING OIL FIRING - TEST 202-4
Element
*
Be
Hgf
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Scrubber
Inlet
mg/m
<0.001
0.0016
0.41
0.31
0.062
0.15
0.53
0.28
0.17
0.10
0.54
4.8
0.20
0.03
0.22
1.1
2.7
0.61
0.050
0.043
5.7
0.015
18
Scrubber
Outlet
mg/m
0.001
0.0002
0.070
0.030
0.006
0.030
0.039
0.066
0.018
0,012
0.007
0.28
0.013
0.004
0.025
0.20
0.82
0.065
0.006
0.001
0.48
0.001
2.5
MATE
Value
mg/m
0.002
0.05
16
6.0
0.050
0.002
3.1
0.010
0.001
0.050
0.20
1.0
0.15
5.0
5.0
0.015
0.50
4.0
0.200
3.1
5.2
5.0
Degree
Scrubber
Inlet
<0.50
0.032
0.026
0.052
1.24
75.0
0.171
28.0
170
2.0
2.70
4.8
1.333
0.006
0.044
73.3
5.40
0.153
0.25
0.014
1.096
0.003
of Hazard
Scrubber
Outlet
0.50
0.004
0.004
0.005
0.120
15.0
0.013
6.60
18.0
0.24
0.035
0.28
0.087
0.001
0.005
13.33
1.640
0.016
0.03
0.0003
0.092
0.0002
Beryllium was determined by Spark Source Mass Spectrometry (SSMS). The
other values, with the exception of mercury, are determined by Inductively
Coupled Plasma Optical Emission Spectroscopy (ICPOES) analysis.
Mercury was determined by cold vapor analysis of SASS train samples taken
during test 203.
4-29
-------
whereas sulfates accounted for 40% of the participate matter at the
inlet and 60% at the outlet. It is possible that scrubber generated
Na?SO. was added to the scrubber effluent gas, but this has not been
confirmed. It would be expected that generation of sulfates by the
scrubber would be independent of the type of fuel, other operating
conditions being the same. It is not presently known why these results
differed in the coal- and oil-fired tests.
Inorganics
Concentrations of 22 major trace elements present in the flue gas
during coal and oil firing are presented in Tables 4-14 and 4-15. To
assess the hazard potential of these emissions, the emission concentrations
are compared with the Minimum Acute Toxicity Effluent (MATE) values. The
MATE values are emission level goals developed under direction of EPA, and
can be considered as concentrations of pollutants in undiluted emission
streams that will not adversely affect those persons or ecological systems
exposed for short periods of time, [13]. Tabulated MATE values
represent air concentrations which were derived from human health consider-
ations. Analysis of the flue gas generated during coal firing indicates
that 18 elements exceeded their respective MATE values at the scrubber inlet
and 4 exceeded their MATE values at the scrubber outlet. These four elements
which pose a potential hazard are arsenic, chromium, iron and nickel.
During oil firing, 11 elements exceeded their respective MATE values at the
scrubber inlet and 5 exceeded their MATE values at the scrubber outlet.
The 5 elements exceeding their MATE values at the scrubber outlet are
arsenic, cadmium, chromium, nickel and vanadium. Elements exceeding their
MATE values at the scrubber outlet and which are common to both coal and
oil firing are arsenic, chromium and nickel.
The MATE value for arsenic is extremely low because arsenic is a
cumulative poison producing chronic effects in humans. MATE values for
nickel and chromium are extremely low due to considerations for potential
human carcinogenic!ty. Similarly, the low MATE value for cadmium results
from considerations of potential carcinogenic, oncogenic and teratogenic
effects upon humans. The MATE value for vanadium is comparatively higher
4-30
-------
since vanadium has been associated with eye and bronchial irritation with-
out indication of chronic effects. Emissions of arsenic and chromium after
scrubbing are below their TLV's which are each 0.5 mg/m3. And, for coal
firing, emissions of nickel after scrubbing are below the TLV value of
3
0.1 mg/m . Hence, if TLV's were used as the basis for comparison, emis-
sions of arsenic, chromium and nickel would be considered less hazardous.
For oil firing, emissions of cadmium, nickel and vanadium after scrubbing
exceed their TLV values of 0.05, 0.1 and 0.5 mg/m3, respectively, in addi-
tion to exceeding their respective MATE values.
D
Beryllium emissions after scrubbing were 0.002 mg/m for coal firing
and 0.001 mg/m for oil firing. These concentrations may be compared to
the beryllium MATE value of 0.002 mg/m . At these emission concentrations,
the National Standard for Hazardous Air Pollutants limitation of 10 grams
beryllium per day would only be exceeded by boilers of 50 MW capacity or
greater for coal firing and 100 MW capacity or greater for oil firing.
Emission factors and mass emission rates for the 22 trace elements
analyzed are presented in Tables 4-16 and 4-17. Also presented in these
tables are scrubber removal efficiencies for each element. An overall
removal efficiency of 99% was obtained for coal firing and 87% was obtained
for oil firing. However, some elements were removed with less than the
average removal efficiency for their respective fuel. It is interesting
to note that, with the exception of iron, all elements which exceeded their
MATE values at the scrubber outlet during coal firing were removed with
lower than average efficiency. With the exception of chromium, the same
observation may be made regarding oil-fired data.
Enrichment factors across the scrubber have been computed for each
element and are presented in the last columns of Tables 4-16 and 4-17.
The enrichment factor is defined as the ratio of the concentrations of
trace elements to aluminum at the scrubber outlet divided by the corres-
ponding ratio at the scrubber inlet. Aluminum is selected as a reference
material because it is known to partition equally among particulates of
4-31
-------
TABLE 4-16. EMISSION FACTORS AND MASS EMISSION RATES OF
TRACE ELEMENTS DURING COAL FIRING - TEST 201-1
Trace
Element
*
Be
Hgf
Ca
Mg
Sb
As
*
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Emission Factor, ng/J
Scrubber
Inlet
0.04
0.08
32
8.2
1.6
3.4
0.1
0.20
1.1
1.6
4.1
190
3.7
0.34
4.3
0.60
1.3
0.99
1.4
4.7
210
0.69
470
Scrubber
Outlet
0.001
0.037
0.015
0.0046
0.010
0.092
0.01
0.00042
0.054
0.0050
0.0084
1.0
0.0088
0.0063
0.026
0.026
0.024
0.020
0.041
0.024
1.1
0.0075
2.6
Emission Rate, g/hr
Scrubber
Inlet
5
0.50
3300
860
170
350
10
21
120
160
430
20,000
380
35
450
61
140
100
140
500
22,000
72
50,000
Scrubber
Outlet
0.09
0.23
1.6
0.48
1.1
9.7
1.2
0.044
5.7
0.53
0.88
no
0.92
0.68
1.2
2.8
2.5
2.1
4.3
2.5
no
0.79
270
Removal
Efficiency
98
55
99
99
99
97
88
99
95
99
99
99
99
98
99
95
98
98
97
99
99
99
99
Enrich-
ment
Factor
3.7
84
0.09
0.11
1.2
5.3
2.1
0.4
9.5
0.6
0.4
0.99
0.5
3.4
0.5
8.6
3.6
3.9
5.8
0.9
1.0
2.1
Appropriate values as determined by SSMS. The other values, with the
exception of mercury, were determined by ICPOES analysis.
Mercury was determined by cold vapor analysis of SASS train samnlP*
taken during test 200. train samples
4-32
-------
TABLE 4-17. EMISSION FACTORS AND MASS EMISSION RATES OF
TRACE ELEMENTS DURING OIL FIRING - TEST 202-4
Element
*
Be
Hgf
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Emission Factor,
ng/J
Scrubber
Inlet
<0.0003
0.0006
0.13
0.10
0.02
0.049
0.17
0.091
0.055
0.033
0.18
1.6
0.065
0.010
0.072
0.36
0.88
0.20
0.016
0.014
1.9
0.0049
6.0
Scrubber
Outlet
0.0003
0.0001
0.022
0.0094
0.0019
0.0094
0.012
0.021
0.0057
0.0038
0.002
0.088
0.0041
0.0013
0.0079
0.063
0.26
0.02
0.002
0.0003
0.15
0.0003
0.78
Emission
cmi/h»
Scrubber
Inlet
<0.04
0.05
16
12
2.5
5.9
21
11
6.7
3.9
21
190
7.9
1.2
8.7
43
110
24
2.0
1.7
220
0.59
710
Rate,
Scrubber
Outlet
0.04
0.006
2.7
1.1
0.23
1.1
1.5
2.5
0.69
0.46
0.27
11
0.50
0.15
0.95
7.7
31
2.5
0.23
0.038
18
0.038
96
Removal
Efficiency
Unknown
87
83
91
91
81
93
77
90
89
99
95
94
87
89
83
71
90
87
98
92
94
87
Enrichment
Factor
>n.9
1.48
2.03
1.15
1.15
2.37
0.87
2.80
1.26
1.43
0.15
0.69
0.77
1.58
1.35
2.16
3.61
1.27
1.43
0.28
1.0
0.79
Beryllium was determined by SSMS. The other elements, except fluorine,
were determined by ICPOES.
Mercury was determined by cold vapor analysis of SASS train samples taken
during test 203.
4-33
-------
different size*. Enrichment factors presented in the tables indicate that
beryllium, antimony, arsenic, chromium, manganese, nickel, vanadium, zinc,
selenium and mercury are enriched across the scrubber for both fuels. Addi-
tionally, boron and zirconium are enriched during coal firing and calcium,
magnesium, cadmium, cobalt and molybdenum are enriched during oil firing.
Trace element enrichment is principally due to the partitioning of
trace elements as a function of particulate size, and the greater collection
efficiency of the scrubber for large size particulates.
To better characterize combustion generated solids in terms of trace
element distribution, the Electron Spectroscopy for Chemical Analysis
(ESCA) technique was used to determine surface and subsurface concentra-
tions of elements in the particulates. ESCA results for particulates from
both fuels are presented in Tables 4-18 and 4-19 as normalized atom per-
centages for each particulate catch and penetration. Scrubber inlet data
indicate that coarser particulate matter collected by the cyclone differs
somewhat from the finer particulates collected on the filter. In the case
of coal-fired particulates, the principal difference is the lower silicon
content of the coarser particulate. For oil-fired particulate, the prin-
cipal difference is the higher carbon and lower silicon and oxygen contents
of the coarser particulates. It is interesting to note that the filter
catch particulates at the scrubber inlet and outlet yielded very similar
o
ESCA analyses at the particle surface and at a 76 A penetration for oil
fired particulates. That this does not hold true for coal-fired particu-
lates may reflect the higher coarse particulate fraction generated and
subsequently higher particulate removal efficiency obtained for coal
firing. That is, the compositions of coal fired particulates at the scrub-
ber inlet and outlet might be expected to differ more significantly than
in the case of oil fired particulates due to the higher coarse particulate
loading at the inlet and, consequently, the higher particulate removal
efficiency during coal firing.
Silicon, iron and scandium have also been used by other investigators as
a reference element in the computation of enrichment factors. Notice
that iron has no enrichment in this study while silicon and scandium
were not measured.
4-34
-------
TABLE 4-18.
DEPTH PROFILE ANALYSIS OF COAL PARTICULATE WITH CONCENTRATIONS
EXPRESSED AS NORMALIZED ATOM PERCENT* - TEST 201-1
Inlet Level II cyclone catch
Level II filter catch
Level II filter catch; 76 A
0
57
56
54.2
Na S SI Al
4 11 6 7
2.4 11.5 14.1 8
2.1 4.0 17.9 12.6
Fe Cl P
2 2 1
1.4 1.5 1.2
2.1 1.3 2.2
V Ca C K
2
1.0 2.7
Outlet Level II
Level II
Level II
Level II
Level II
Level II
filter
filter
filter
filter
filter
filter
catch
catch;
catch;
catch;
catch;
catch;
0
75 A^
150 A
300 A
e
500 A
O
700 A
45.7
48
48.3
48.3
47.9
47
5.5
7.4
9.1
8.8
7.3
7 3
13.2
11.5
10.0
8.0
6.7
6.1
7.1
9.0
10.1
10.6
10.8
11.6
2.2
5.2
7.7
9.6
13
11.0
1.2
1.2
2.1
1.7
? 3
1.2
1.1
1.2
1.0
1.2
n 9
1.1 0.7
1.1
1.2
1.2 0.5
1.1
1.5 0.5
1.3
1.1
1.2
1 0
14.9
12.1
10.0
8.0
8.1
8.8
7.1
1.8
1.2
1.8
1.1
1 6
The atom percent of the 12 elements presented here adds up to 100 percent. Other elements present In
the cyclone and filter catches were not studied 1n ESCA. Hence, the atom percents 1n this table are
normalized atom percents and not absolute atom percents.
TABLE 4-19. DEPTH PROFILE ANALYSIS OF OIL PARTICULATE WITH CONCENTRATIONS
EXPRESSED AS NORMALIZED ATOM PERCENT* - TEST 202-4
Inlet
Level
Level
Level
Outlet
Level
Level
II Cyclone Catch
II Filter Catch
II Filter Catch; 76A
II Filter Catch
II Filter Catch; 76A
0
38.5
48.6
46.3
45.5
53.5
Na
3.2
4.2
4.7
5.7
3.2
S
12.9
10.7
6.5
9.7
6.8
S1
2.6
11.8
17.1
14.6
22,0
Al Fe
2.3
3.1
3.3 0.8
3.4 1.3
4.0
Cl
1.4
1.3
1.4
2.3
1.3
P
0.6
1.5
1.1
1.6
1.0
V Ca
1.2
1.7
3.3 0.9
1.7
2.0
C
37.4
17.2
12.9
14.1
6.2
K
117
The atom percent of the twelve elements presented here adds up to 100 percent. Other elements
present 1n the cyclone and filter catches were not studied 1n ESCA. Hence, the atom percepts 1n
this table are normalized atom percents and not absolute atom percents.
4-35
-------
As indicated in Table 4-18, some elements, most notably sulfur and
carbon, appear to be enriched at the particle surface and somewhat depleted
in the bulk of the particle. The opposite trend is observed for aluminum
and silicon which are enriched in the bulk of the particulate. These obser-
vations indicate that some degree of surface coating of the particle has
occurred. Assuming that the bulk of the particulate is homogeneous with
respect to aluminosil icates, the thickness of the surface coating can be
most readily estimated by considering the concentration of coating elements
relative to the concentration of aluminum or silicon. The relative con-
centration may be plotted as a function of penetration to enable a graphical
estimation of coating thickness. Aluminum was selected as the reference
element here rather than silicon because the ESCA analyses were run directly
on the filter and the silicon content of the filter would interfere with
interpretation of the data.
Depth profiles for six major elements in coal-fired particulates at
the scrubber outlet are depicted graphically in Figure 4-2. These profiles
show that sulfur and carbon are more concentrated near the surface than
deeper inside the particles. Both the sulfur and the carbon curves, how-
o
ever, level off after 275 A. Hence, the thickness of the deposited layer
o
of sulfur and carbon compounds appears to be approximately 275 A. For
sulfur, these data indicate that v,r ° there may be higher surface concen-
tration of sulfur containing compounds in the particulates emitted from
the scrubber, some of these compounds are probably deposited on particles
composed of solid sulfate or sulfite. This would be the case if sulfuric
acid condensed on the sodium bisulfate (NaHSCL) or calcium sulfite hemi-
hydrate (CaS03'l/2 H20) particles that have been found to be present. For
carbon, the depth profile data indicate that a fraction of the carbon,
either as oil soot*, or as a carbon containing compound (such as carbonate
or bicarbonate), could be deposited on the surface of the fine particulates
emitted. The leveling off of the carbon curve, however, indicates that
another fraction could be emitted as solid oil soot particles or solid
Oil soot deposited in the duct-work downstream of the boiler durinq
J
oil firing.
4-36
-------
-pa
I
CO
CQ
ro
i
ro
fa fD
-5 T3
r+ r+
' -5
O
i ro
I cu
ns ^
ro oo
CD ->
' 01
i
' O
O
c
r+
fD
O
O
DJ
<
QC
UJ
CJ
z
O
O
? 44-
CO
Q
UJ
Q
O
Z
O
QC
I-
z
UJ
O
8
h-
z
UJ
s
LU
_J
UJ
D CARBON
OSULFUR
VANADIUM
A CHLORINE
IRON
CALCIUM
100
-------
carbonate/bicarbonate particles. The depth profile for iron, vanadium,
chlorine, and calcium is reasonably flat and indicates that the relative
concentrations of these elements remain approximately constant.
Although only low penetration analyses were performed on oil-fired
particulates, available data indicate trends similar to those observed
with coal fired particulates. Elements which appear to be enriched on
the particulate surface include sulfur, phosphorous and carbon. On the
other hand, vanadium and the typical ash components aluminum and silicon
appear to be more concentrated in the bulk of the particulate matter.
The composition of particulate at the scrubber inlet and outlet has
also been determined by PLM analyses. Estimated weight percentages of
coal- and oil-fired particulate components are presented in Table 4-20.
It may be noted that a substantial fraction of the coal-fired particulates
at both the scrubber inlet and outlet is composed of oil soot. This is
attributed to particulates deposited in the boiler during previous oil-
fired operation and subsequent attrition during coal firing. The increase
in weight percent of oil soot across the scrubber is consistent with
results of ESCA analyses, as discussed previously. Both the PLM analysis
and the ESCA analysis have shown that oil soot could be emitted as fine,
solid particulates. Oil-fired particulates at the scrubber inlet are
composed primarily of oil soot, various sulfate/sulfite compounds and
fused ash while the outlet particulate is composed largely of sulfates
and sulfites. Noting that the total quantity of particulate emissions
after scrubbing is comparable for coal and oil firing, these data indicate
that oil soot present during coal firing is finer than that generated
during oil firing and is, therefore, not as efficiently removed by the
scrubber. This is consistent with the observation made during PLM analyses
that oil soot in coal particulate was fragmented while soot in oil partic-
ulates was present as cenospheres with only partial fragmentation.
Calcium sulfite hemihydrate and unknown sulfates comprise a principal
portion of scrubber outlet sample for both fuels, 50 to 65% for coal
particulate and 80 to 90% for oil particulate. These materials were also
found to comprise 20 to 39% of the scrubber inlet particulates from oil
firing. The CaS03'l/2 H20 and unknown sulfates identified at the scrubber
4-38
-------
TABLE 4-20. MAJOR PARTICULATE COMPONENTS
DETERMINED BY PLM ANALYSIS*
Component
CaS03-l/2 H20 and
Unknown Sulfate
Approximate Weight
Scrubber Inlet
Coal
Oil
20-39
Scrubber Outlet
Coal
50-65
Oil
Ash1"
Fused
Unfused
Minerals
Fe2°3
Fe304 (Magnetite)
Si02
CaC03
Oil Soot
Coke
15-30
50-65
1-5
10-15
< 2
10-20
< 2
13-23
1-4
< 1
< 1
5 3
43-57
_ .. _
15-25 8-16
1-5
25-40 2-8
_ _ _ M « _
80-90
Coal-fired samples were taken from test 201-1. Oil-fired samples were
taken from test 202-4.
t
This is primarily composed of iron-aluminum silicates.
outlet during coal firing are mostly generated by the scrubber*. As dis-
cussed previously, the unknown sulfates may be composed primarily of
sulfuric acid aerosol and sodium bisulfate. Sulfate data presented pre-
viously indicate that scrubber inlet oil particulates contain approxi-
mately 40% sulfate ion. Hence, the PLM estimate for CaSOs-1/2 H20 and
unknown sulfates weight percentages of 20 to 39% appear to be somewhat
Strictly speaking, CaS03»l/2 H20 is formed in the regeneration of
Na2S03 and a fraction of it is carried over with the regenerated
into the scrubber.
4-39
-------
low. Further, the CaSCL-1/2 H?0 would appear to be present only as a
0 £
minor constituent. This may indicate that tabulated inlet weight percent-
age of oil soot, the most difficult particulate component to quantify,
is high with respect to the true particulate composition. Similarly,
sulfate data indicate that outlet particulates are approximately 63%
sulfate ion. Assuming that sulfate ions are combined with calcium or
sodium, outlet particulates may consist of up to 92% sulfate compounds.
Hence, CaSO,-1/2 H20, if present in either the scrubber inlet or outlet,
appears to be a minor constituent of particulates generated during oil
firing.
Chloride, Fluoride, and Nitrate Emissions
Specific anion analysis was performed on extracts from particulate
catches from the Method 5 sampling train. Emissions data for chloride,
fluoride, and nitrate are presented in Table 4-21. In the coal-fired
test, chlorides and fluorides are removed with high degrees of efficiency,
at greater than 99% and greater than 85%, respectively. These are to be
expected because the overall removal efficiency of the trace element
cations is greater than 99%. In the oil-fired case, the fluoride removal
efficiency is high, 85 to 89%, and also corresponds to the trace element
cation removal efficiency of 87%. The lower removal efficiencies for
chlorides and nitrates in the oil fired test, about 51% and 57%, respec-
tively, suggest that these anions may be associated with the finer partic-
ulate matter which is not efficiently removed by the scrubber.
Comparison of the coal and oil tests shows that considerably higher
chloride and fluoride levels were emitted during coal firing. In the
case of chloride, this is as expected, because of the higher chlorine
level in the coal fuel. However, in the coal test, only 14% of the fuel
chlorine was analyzed in the particulate extract from the scrubber inlet.
It is possible that some of the chlorine is emitted in the form of acid
vapors, which would not be detected by analysis of particulate extracts.
The lower removal efficiency of chlorides in the oil fired test as com-
pared to coal firing can be explained as resulting from the lower partic-
ulate removal efficiency for oil particulates.
4-40
-------
TABLE 4-21. CHLORIDE, FLUORIDE, AND NITRATE
EMISSIONS FROM COAL AND OIL FIRING
Fuel Test
Inlet
ng/J
Coal 201-1 4.7
011 202-4 0.15
cr
Outlet
ng/J
<0.004
0.072-0.075
Remova 1
Efficiency,
t
>99
50-52
Inlet
ng/J
0.22
0.017
F"
Outlet
ng/J
<0.03
0.002-0.003
Removal
Efficiency,
*
>86
85-89
Inlet
ng/J
<0.48
0.076
N03"
Outlet Removal
ng/J Efficiency,
<0.25
0.033 57
Comparison of fluoride and nitrate removal efficiencies for the coal
and oil tests is not possible because several of the fluoride and nitrate
concentrations were below the detection limit.
Organics
Four methods of analysis were utilized in determining flue gas
organic loadings. Continuous FID analyses were performed to determine
total organic concentrations assuming all carbon to be present as methane.
Bag samples of gas were collected over a 30 to 45 minute period and were
analyzed for organics in the C, to Cg range using a field chromatograph.
A laboratory chromatograph was employed to determine hydrocarbons in the
C-, to C,6 range in samples obtained from the SASS train (GC/TCO). SASS
train samples were also analyzed gravimetrically for higher molecular
weight organics. For identification of organic compounds, infrared
spectroscopy analysis (IR) and low resolution mass spectrometry (LRMS)
were performed on residues from gravimetric analysis, and samples from a
modified Method 5 sampling train (with an XAD-2 resin module) and from gas
bags were analyzed by gas chromatography/mass spectrometry (GC/MS).
For C, to C,g organics, the subscripted carbon number refers to a
boiling range rather than a specific molecular structure. The approximate
boiling ranges corresponding to each carbon are presented in Table 4-22.
A comparison of organic determinations for the coal- and oil-fired tests
is presented in Table 4-23. Analytical results for the outlet resin
4-41
-------
samples from the SASS train were not available, so these were calculated
using data from four oil-fired and ten coal-fired boiler tests which used
similar sampling trains, and assuming the proportion of organic material
in the resin sample to the rest of the material trapped in the sampling
train to be constant. These calculated values are good to a factor of 3
to 4.
Total organics determined as methane by FID show a slight increase
across the scrubber for both oil and coal firing. As mentioned previously,
this increase was determined to be statistically significant during the
coal-fired test but insignificant during the oil-fired test. The reason
for the increase is not known at this time, Organics in the C, to Cfi
range were present, if at all, at sufficiently low concentrations that in
TABLE 4-22. APPROXIMATE BOILING RANGES CORRESPONDING
TO EACH CARBON NUMBER
Carbon
Number
Cl
C2
C3
C4
C5
C6
C7
C8
Approximate
Boiling Range
-160 to
-100 to
- 50 to
0 to
30 to
60 to
90 to
110 to
-100°C
- 50°C
0°C
30°C
60°C
90°C
no°c
140°C
Carbon Approximate
Number Boiling Range
Cg 140 to 160°C
C1Q 160 to 180°C
C^ 180 to 200°C
C12 200 to 220°C
C13 220 to 240°C
C]4 240 to 260°C
C15 260 to 280°C
C16 280 to 300°C
both tests they were not detected by the field chromatograph. In the
range of C-, and above, the concentration of higher molecular weight
organics was greater than the concentration of volatiles.
4-42
-------
-P=>
CO
TABLE 4-23. COMPARISON OF ORGANIC DETERMINATIONS
DURING COAL AND OIL FIRING
Method
Total as CH4
(Continuous FID)
CT - Cg (GC on Bag
Samples)
C7 - CIG (GC on SASS
Train Samples)
>C16
(Gravimetric on
SASS Train Samples)
Coal Fired
Test Inlet Outlet % Change
Not
200 3.8 4.6 Significant
200 <5.4 <5.4
200 0.34 0.27* -20
200 2.3 0.33* -85
Oil Fired
Test Inlet Outlet % Change
Not
202-1 2.9 3.3 Significant
202-1 <4.6 <4.6
203 0.17 0.02* -85
203 2.6 0.43* -83
The values for the resin sample are calculated (see text).
-------
Comparison of the oil and coal-fired results shows essentially
no difference in the organic loadings from the two fuels. The rough
distributions of molecular weights are also very similar. The scrubber
removal efficiencies show some variation: 20% for the Cy to C-|6 fraction,
coal fired, and 83 to 85% for the other fractions for which efficiencies
could be calculated. However, since the outlet concentrations for the Cy
and above fractions are good within a factor of 3 to 4, the efficiencies
presented actually represent rather wide ranges. Because the outlet
value for coal organics in the C7 to C,g range is 80% of the inlet value,
the factor of 3 to 4 uncertainty means that the 20% efficiency actually
represents a range of 0 to 97%. Since the outlet values for the other
fractions are much lower, their uncertainty affects the calculated
removal efficiency less: 85% actually represents a range of 50 to 98%.
Hence, a conclusive comparison of the C-, to C,g removal efficiencies for
coal and oil firing cannot be made.
Results of IR analysis on the fractionated XAD-2 resin extracts from
SASS train samples are presented in Table 4-24. As can be seen, the
blank contained many organic materials presumably released by the resin.
This was a source of difficulty in interpreting analytical results,
especially because the amount of resin-generated material seemed to vary
from sample to sample. IR analysis of several of the LC fractions did
not identify any compounds which could be directly associated with
combustion.
Table 4-25 summarizes the organics that were identified in gas bag
samples by GO/MS analysis. Again, none of the compounds is directly
associated with combustion. They are, however, representative of the
types of compounds that are used in the manufacture of the sample bags
and the solvents used in the analysis. This finding is consistent with
GC, gravimetric, and FID analyses indicating low organic emissions.
4-44
-------
TABLE 4-24. SUMMARY OF THE INFRARED ANALYSIS OF ORGANICS
FROM OIL AND COAL COMBUSTION
Total Organlcs,
mg/m
Category
Aliphatic Hydrocarbons
Aromatic Hydrocarbons
Chlorinated Hydrocarbons
S11 1 cones
Heterocycllc Sulfur
Compounds
TMocarbonyl Compounds
N1tro Compounds
Ethers
Esters
Amides
Alcohols
Glycols
Phenols
Carbox/Hc Adds
Sulfontc Adds
Silicates
»
Not Analyzed.
LCI LCZ LC3 LC4 LC5 LC6 LC7 Total
Coal 011 Blank Coal 011 Blank Coal 011 Blank Coal 011 Blank* Coal 011 Blank Coal 011 Blank Coal 011 Blank Coal 011 Blank
0.14 0.09 0.02 0.06 0.05 0.03 0.12 0.03 0.01 0.37 0.04 0.02 0.95 0.28 0.10 0.06 0.02 1.70 0.51 0.18
Intensity
XM XM XM XM XM XM Xm Xm Xm Xm Xm
Xm Xm Xm XM XM XM XM Xm Xm Xm Xm Xm Xm
Om
Xm Xm Xm Xm Xm
Xm Xm Xm Xm Xm
Xm
XM Xm OM Om On Om
XM
Xm XM XM XM XM XM XM XM XM XM XH Xm
Xm Om OM Om
Xm Xm
XM XM XM XM
Xm OM
Xm XM XM XM XM XM XM
XM
XM
0 = At least one species suspected present. M = Major Component.
X At least one species present. m Minor Component.
-------
TABLE 4-25. COMPARISON OF ORGANIC COMPOUNDS IDENTIFIED BY GC/MS
IN THE FLUE GAS DURING COAL AND OIL FIRING
Compound
Propionaldehyde
Nitromethane
Ethyl -n-butyl ether
Ethyl acetate
Hydrocarbon (CgH..)
Chloropropanol
4-methyl-3-pentene-2-one
Unidentified alcohol
Octanol
Ketone (MW 138)
Ketone (MW 140)
Phthalic anhydride
Amy! benzoate
Glycerol triacetate
Emission Rate, ng/J
Coal Fired Oil Fired
201-2 201-3 202-2 202-3
Inlet Outlet Inlet Outlet Inlet Outlet Inlet Outlet
0.075 0.17 0.024 0.075 0.052
0.023
0.88 0.66 0.400 0.66 0.64 -- 0.37
0.85
0.17
0.0017
0.21 0.13 0.01
0.0018
0.017
0.0074
0.0017 0.003 0.0053
0.011
0.0006
0.016
Methyl substituted
aromatic
0.00075
-------
Polycyclic Organic Material
Polycyclic organic material (POM) was not found in the scrubber inlet
or outlet samples at detection limits of 0.3 yg/m during either coal or
oil firing. This observation is consistent with the findings to date from
the EPA sponsored project "Emissions Assessment of Conventional Combustion
Sources". However, two POM compounds for which MATE values are below
2
0.3 yg/m are b°nzo(a)pyrene and dibenz(a ,h)anthracene. The MATE values
3 3
for benzo(a)pyrene and dibenz(a.h) anthracene are 0.02 yg/m and 0.09 yg/m .
respectively. While available data indicate that many POM compounds are
not present at concentration greater than or equal to their MATE value
during oil firing, additional analyses at higher GC/MS sensitivity would
be required to conclusively preclude the presence of all POMs at concentra-
tions above their MATE values.
Scrubber Efficiency
Flue gas analyses indicate that scrubber processing removes significant
percentages of flue gas sulfur oxides (S02> S03, and SO^"), total particulates
and organics in the boiling range of C^ and higher. Scrubber removal
efficiency dat; for these flue gas components are summarized in Table 4-26.
The average removal efficiencies for both coal and oil fired tests have
been discussed and compared in previous subsections. However, it is important
to note that it is the C7 and higher hydrocarbons which are removed with the
efficiencies listed. These fractions comprise 38 to 96% and 32 to 69% of
the organics measured at the scrubber inlet for the oil- and coal-fired
tests, respectively. Hence, based on the total organics generated, removal
efficiencies of 32 to 84% for oil and 25 to 53% for coal were obtained.
Although the average values for coal were lower than 1 -r oil, these values
were calculated using the 20% removal figure for coal Cy to C^g organics.
As discussed previously, this 20% efficiency for rc?l firing has a higher
uncertainty than the 85% value for oil firing and, therefore, these effi-
ciencies cannot be reasonably compared. Other than the inconclusive removal
efficiency for C to C,g coal-fired organics, the data indicate that
removal efficiency of organics greater than C7 is 83-85% and is essentially
identical for coal and oil firing.
4-47
-------
TABLE 4-26. SCRUBBER EFFICIENCY DURING COAL AND OIL FIRING
I
-P>
CO
Fuel Test
Number
Coal 200
201-1
201-2
201-3
201-4
Average
Oil 202-1
202-2
202-3
202-4
203
Averaqe
so2 so3
97
97 33
97
97
95 32
97 32
97 29
97
97
98 28
__
97 29
S04= Total
Particulates
99
88 99
__
99
88 99
88
--
--
60 75
--
60 82
Cy to C"16
Organics
20
--
--
--
--
20
--
--
85
85
C-)7 and Higher
Organics
85
--
--
--
--
'85
--
--
--
83
83
-------
It is not known by what process organics are so efficiently removed.
There are, however, at least three possible mechanisms:
Sorption - Some organics could adsorb on participates.
Condensation - High-boiling organics could condense
and be removed as "particulates".
t Dissolution - Some organics are partially water
soluble. These compounds could be removed by dis-
solving in the slurry.
One or any number of these mechanisms may account for the high
removal efficiency of organics.
LIQUID WASTE
As discussed previously, only one significant waste water stream is
produced. The stream is a combination of water treatment waste, boiler
blowdown, and acid waste water from elsewhere in the manufacturing facility.
The quality of this combined stream is such that it is acceptable for
disposal into the municipal sewer system. Liquid streams from the scrubber
operation are passed to the thickener and recirculated to the scrubber after
the filtration step. There is no direct wastewater discharge from the
scrubber operation, as the process is designed to dispose of all of the
water that enters its system through evaporation and moisture entrained in
the scrubber cake.
Because several streams are mixed together, it is not possible to
accurately determine what part of the effluent is attributable to the boiler,
However, the flow rate of the combined stream is approximately 10,000
liters/hr (40 gallons/min).
Hater Quality Parameters
Table 4-27 summarizes the waste water parameters for the combined
waste water streams analyzed during coal and oil firing. Note that these
values do not represent water produced solely by the boiler but also
include process waste.
4-49
-------
Inorganics - Combined Waste Water Stream
Analyses of major inorganic cations in the combined waste water stream
during coal and oil firing are presented in Tables 4-28 and 4-29. These
data are based on the SSMS technique which is accurate to within a factor
of approximately 3. Of the elevn elements analyzed, none exceeds its MATE
value for either fuel based on health considerations. However, based on
the factor of 3 uncertainty in SSMS analyses, cobalt, nickel, copper and
cadmium may exceed their respective ecological MATE values during coal
firing. Similarly, nickel and copper may exceed their ecological MATE
values during oil firing.
Test
200
201-1
201-2
201-3
201-4
Average
202-1
202-2
202-3
202-4
203
Average
TABLE 4-27.
pH
7.9
7.5
8.2
8.0
7.3
7.8 + 0.4
7.5
6.5
7.5
6.5
6.9
7.0 + 0.5
COMBINED STREAM WASTE
Hardness
(as CaC03) ,
mg/1
COAL FIRING
210
158
135
145
100
150+40
OIL FIRING
105
140
155
150
110
132 + 23
WATER PARAMETERS
Alkalinity
(as CaCOJ ,
mg/1
115
125
130
125
145
128 + 11
135
65
120
50
140
102+42
Cyanide,
mg/1
0
0
0
0
0
0
0
0
0
0
0
0
1-50
-------
TABLE 4-28. WASTE WATER INORGANICS FOR COAL FIRING
Trace
Element
Be
F
V
Cr
Co
Ni
Cu
Sr
Cd
Sb
Pb
*
Flow rate
Element
Be
F
V
Cr
Co
Ni
Cu
Sr
Cd
Sb
Pb
mg/1
<0.001
0.8
0.003
0.002
0.1
0.005
0.02
0.5
<0.001
<0.001
0.01
of 10,000 1
TABLE 4-29
mg/1
<0.001
4
0.002
0.02
0.007
0.02
0.02
0.3
<0.001
0.001
0.006
9/hr
<0.01
8
0.03
0.02
1
0.5
0.2
5
<0.01
<0.01
0.1
MATE Value
Health
0.030
38
2.5
0.25
0.75
0.23
5.0
46
0.050
7.5
0.250
iters per hour, combi
WASTE
g/hr*
<0.01
40
0.02
0.02
0.07
0.2
0.2
3
<0.01
0.01
0.06
, mq/1
Ecology
0.055
--
0.15
0.25
0.25
0.010
0.050
--
0.001
0.20
0.050
ned waste
WATER INORGANICS - OIL
MATE Value, mg/1
Health
0.030
38.0
2.50
0.250
0.750
0.230
5.0
46.0
0.050
7.50
0.250
Ecology
0.055
.
0.150
0.250
0.250
0.010
0.050
--
0.010
0.200
0.050
Degree of
Health
<0.033
0.021
0.0012
0.008
0.13
0.022
0.004
0.011
<0.02
<0.0001
0.04
water.
FIRING
Degree
Health
0.033
0.100
0.001
0.080
0.009
0.087
0.004
0.007
<0.02
0.0001
0.024
Hazard
Ecology
<0.018
--
0.02
0.008
0.40
0.50
0.40
--
<1.0
<0.005
0.20
of Hazard
Ecology
0.018
0.013
0.080
0.028
2.00
0.400
--
<0.004
0.005
0.005
Flow rate of 10,000 liters per hour.
4-51
-------
Organics - Combined Haste Water
Concentrations of C7 to Clg organics measured in the combined waste
water stream are summarized in Table 4-30. High molecular weight organics
(>C,.-) were detected at a concentration of 0.21 mg/liter during coal firing,
1 6
but these are probably attributable to process wastes generated at the
manufacturing site. High molecular weight organics were not detected during
oil firing. The only organics detected were the C-|g, C^> C^ and C^g
fractions during coal firing and the CIQ, C14 and C15 fractions during oil
firing. Each of these fractions was detected at or below the 0.1 mg/liter
level yielding a total output of Cj to C,g organics of 0.4 mg/liter during
coal firing and less than 0.3 mg/liter during oil firing. As a basis for
comparison, the water MATE values for alkanes, alkenes and alkynes are in
the 500 to 14,000 mg/liter range based on human health considerations and
in the 1.0 to 100 mg/liter range based on ecological considerations. Dis-
charge concentrations of organics in the combined waste water stream are
well within these MATE values for both coal and oil firing.
SOLID WASTE
Three solid waste streams are produced by the system:
0 Bottom ash;
Fly ash;
Scrubber cake.
Approximate quantities of bottom ash and scrubber cake produced during
coal and oil firing are presented in Table 4-31. Only small quantities of
fly ash were collected during the test period due to malfunction of the
multiclone. The quantity of bottom ash produced during coal firing is at
least a factor of 80 larger than that produced during oil firing due to the
difference in fuel ash contents (9.9% for coal versus 0.02% for oil).
Similarly, the quantity of scrubber cake generated during coal firing is up
to 3 times greater than was produced during oil firing. This difference
would be reduced by proper multiclone operation and the attendant reduction
in solids content of the scrubber cake during coal firing.
4-52
-------
TABLE 4-30. SUMMARY OF C? - Clg ORGANICS IN THE WASTE WATER
Carbon
Number
C7
C8
C9
C10
cn
C12
mg/1
Coal Firing Oil
*
ND
ND
ND
0.1 <
ND
ND
Firing
ND
ND
ND
0.1
ND
ND
Carbon
Number
C13
C14
C15
C16
Total
C7 " C16
mg/1
Coal Firing Oil
ND
0.1 <
0.1 <
ND
0.4 <
Firing
ND
0.1
0.1
ND
0.3
ND means none detected.
TABLE 4-31. SOLID WASTE PRODUCTION RATES
Test
200
201-1
201-2
201-3
201-4
202-1
202-2
202-3
202-4
203
Bottom
kg/hr
^80
^80
^80
^80
v-80
< 1
< 1
< 1
< 1
< 1
Ash
yg/J
COAL FIRING
^753
^763
^735
^857
v738
OIL FIRING
< 7.4
< 7.4
< 7.6
< 8.3
<11.1
Scrubber Cake
kg/hr
1100
1100
1200
850
840
400
550
380
Not
Not
pg/J
10.2
10.5
11 .0
9.1
7.8
2.9
4.1
2.9
Measured
Measured
*
15 tons per week
^Scaled up to represent scrubbing of 100% of the flue gas for boiler No. 4
4-53
-------
The scrubber cake produced after filtration has the appearance of a
clayey silt. Its grain size is quite uniform and characteristic of silty
soils, but its behavior closely resembles a clay in many respects. As
obtained from the vacuum filter, the scrubber cake consists of small lumps
and appears to be relatively dry; in actuality, however, the water content
generally ranges from about 30 to 50%.
Assuming that calcium sulfite hemihydrate (CaS03'l/2 h^O) is the
principal product from S02 scrubbing and Na2$03 regeneration, data presented
in Table 4-32 represent the estimated composition of scrubber cake produced
during coal and oil firing. Scrubber cake produced during coal firing
appears to be composed of 29% fly ash, 24% CaS03-l/2 H20 and 39 to 46% of
unbound water. However, if the multiclone had been functioning properly
during the test period, more fly ash would be removed upstream of the
scrubber and the fly ash content of the scrubber cake would be lowered pro-
portionally. The amount of cake produced could be reduced to 600-750 kg/hr,
on a wet basis, assuming a multiclone efficiency of approximately 60 to 80%.
Although the scrubber cake production rate was not measured for test
202-4, it has been estimated as the average of production rates determined
for other oil-fired tests performed. Data presented in Table 4-32 indicate
that the scrubber cake produced during oil firing is composed of 44 to 50%
unbound water and at least 47% calcium sulfite hemihydrate. These data
reflect the low particulate emissions which are characteristic of oil firing
Only 1% of the scrubber cake is estimated to be particulate. Assuming the
percentage of unbound water associated with scrubber cake particulate to
be the same as the percentage for scrubber cake as a whole, reduction of
the particulate content of the coal firing scrubber cake to 1% yields
approximately 500 kg/hr of low particulate cake. This corresponds well
with the oil firing scrubber cake production rate of 443 kg/hr.
Although the scrubber cake material is composed predominantly of
relatively insoluble solids (calcium sulfite, calcium sulfate, and some
calcium carbonate), the intersititial water does contain soluble residues
of lime, sulfate, sulfite and chloride salts. Trace elements in the fly
ash may also contribute to the leachate from the disposed scrubber cake
and are of special concern. The concentrations of 20 trace elements in the
scrubber cake during coal and oil firing are presented in Tables 4-33 and
4-54
-------
TABLE 4-32. ESTIMATED SCRUBBER CAKE MASS BALANCE
Contribution to Scrubber
Component
Fly Ash Removed by Scrubber
CaS03'l/2 H20 Formed from SC"2
Scrubbing and Na2S03 Regeneration
CaS04, CaCOs, NazSOs, Ca(OH)2
NaHS04 and Na2SC>4 Losses (Estimated)
Water
Total
kq/hr
Coal*
324
262
10-85
429-504 1
1,100
Oil*
5
210
6-35
93-222
4431"
Wei
Coal*
29
24
1-8
39-46
100
Cake
qht %
Oil*
1
47
1-8
44-50
100
Coal firing data are from test 201-1 and oil firing data are from test 202-4,
Total cake production rate was estimated from the average of tests 202-1,
202-2 and 202-3.
4-34. With respect to human health based MATE values for solids, boron is
the only trace element from coal firing which does not exceed its MATE
value, and antimony, boron, molybdenum and zinc do not exceed MATE values
during oil firing. With respect to ecology based MATE values for solids,
all trace elements from coal and oil firing exceeded their MATE values
with the exception of boron and molybdenum which did not exceed their MATE
values during oil firing. This is a consequence of transforming a high
volume, low concentration pollution stream to a low volume, high concen-
tration stream which can be more readily contained. The degree of hazard
for most of the trace elements in these scrubber cakes is sufficiently high
to warrant the disposal of these solid wastes in specially designed
landfills.
The concentrations of 20 trace elements present in the coal firing
fly ash are presented in Table 4-35. Again, in almost every case, the
trace element concentration in the fly ash has far exceeded its MATE value
for solids. Trace element concentrations in the bottom ash would be
similar to those of the fly ash, except that the more volatile elements
and the elements that form volatile compounds would be more enriched in
4-55
-------
TABLE 4-33 INORGANIC CONTENT OF SCRUBBER CAKE FROM
COAL-FIRING (DRY BASIS) - TEST 201-1
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Concentration
ug/g
60,715
1,458
315
532
88
13
141
424
112
47,241
297
51
1,117
114
195
282
256
642
45,310
106
159,409
MATE Va
Health
4SO
180
15
0.5
93
0.1
0.5
1.5
10
3.0
0.5
0.5
150
0.45
5.0
50
0.10
92
160
15
lue, yg/g
Ecology
32
174
0.4
0.1
50
0.002
0.5
0.5
0.1
0.5
0.1
0.2
14
0.02
0.3
0.2
0.05
__
2.0
_-
Degree
Health
126
8.1
21
1,064
0.9
130
282
283
11
15,738
594
102
7.4
253
39
5.6
2,560
7.0
283
7.1
of Hazard
Ecology
1,897
8.4
788
5,320
1.8
6,500
282
848
1,120
94,482
2,970
255
80
5,700
650
1,410
5,120
--
22,655
--
4-56
-------
TABLE 4-34. INORGANIC CONTENT OF SCRUBBER CAKE
FROM OIL FIRING (DRY BASIS) - TEST 202-4
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Concentration
yg/g
200,000
3,799
*
3
*
15
40
*
1
15
*
19
16
2,164
*
6
6
*
14
132
203
36
*
9
239
1,684
37
208,450
MATE Val
Health
480
180
15
0.5
93
0.1
0.5
1 .5
10
3.0
0.5
0.5
150
0.45
5.0
50
0.10
92
160
15
ue, yg/g
Ecology
32
174
0.4
0.1
50
0.002
0.5
0.5
0.1
0.5
0.1
0.2
14
0.02
0.3
0.2
0.05
--
2.0
--
Degree
Health
417
21
0.2
30
0.4
10
30
13
2
721
12
32
0.1
293
41
0.7
90
2.6
11
2.5
of Hazard
Ecology
6,250
22
7.5
150
0.8
500
30
38
160
4,328
60
80
1
6,600
677
180
180
--
842
--
*SSMS analyses were utilized where ICPOES analysis provided upper limit
data only.
4-57
-------
TABLE 4-35. INORGANIC CONTENT OF FLY ASH FROM
COAL-FIRING - TEST 201-1
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Total
Concentration
pg/g
378
2,478
438
1,015
20
18
434
408
320
129,330
438
121
1,288
165
376
179
378
728
109,450
187
248,149
MATE Val
Health
480
180
15
0.5
93
0.1
0.5
1.5
10
3.0
0.5
0.5
150
0.45
5.0
5.0
0.10
92
160
15
ue, ug/g
Ecology
32
174
0.4
0.1
50
0.002
0.5
0.5
0.1
0.5
0.1
0.2
14
0.02
0.3
0.2
0.05
--
2.0
--
Degree
Health
0.8
14
29
2,030
0.2
180
868
272
32
43,110
876
242
9
367
75
36
3,780
8
684
12
of Hazard
Ecology
12
14
1,095
10,150
0.4
9,000
868
816
3,200
258,660
4,380
605
92
8,250
1,253
895
7,560
__
54,725
--
4-58
-------
the fly ash. Thus, the concentrations of arsenic, antimony, boron,
chromium, manganese, nickel, vanadium, zinc, selenium and zirconium would
all be lower in the bottom ash. Oil firing produces little or no fly ash
and bottom ash. As such, insufficient material was available to warrant
analysis.
An overall mass balance for the 20 trace elements has been performed
for coal and oil firing tests. Mass balance results are presented in
Tables 4-36 and 4-37 for coal and oil firing, respectively. The percent
of the trace element In the fuel feed that could be located in the
effluent streams (i.e., scrubber cake and scrubber effluent gas for oil
firing) is used as a measure of mass balance closure. With the exception
of boron, copper, strontium and zirconium, very good mass balance closure
was obtained for trace elements from coal firing. These data support the
reliability and accuracy of sampling and analysis of trace elements and
flow rate measurements.
Although good mass balance closure was obtained for many trace
elements from oil firing, closure was not generally as good as was observed
during coal firing. This is not entirely unexpected since concentrations
of most trace elements in fuel and effluent streams are substantially lower
during oil firing than during coal firing (Refer to Tables 4-4, 4-33 and
4-34). Good mass balance closure was obtained for arsenic, boron,
chromium, cobalt, copper, molybdenum, nickel, vanadium, zinc and selenium.
Elements for which effluent flow rates substantially exceeded input feed
rates, such as iron and aluminum, may show inordinately high concentrations
in the scrubber cake due to the extremely high levels attained during coal
firing and subsequent contamination of the recycle scrubber solution.
Magnesium is the only element for which a poor mass closure cannot be
attributed to either very low element concentrations or possible contami-
nation of the scrubber solution during coal firing. Available analysis
indicate that magnesium was discharged in the scrubber cake at a constant
rate during both coal and oil firing. Although this observation may result
from changes in the scrubber lime feed, a conclusive explanation is not
available based on existing data.
4-59
-------
TABLE 4-36. MASS BALANCE ON TRACE ELEMENTS - TEST 201-1
Element Coal Feed Scrubber Scrubber Bottom and Percent
Cake Effluent Gas Fly Ash Recovery
g/hr g/hr g/hr g/hr
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
N1
V
Zn
Se
Sr
Al
Zr
2,794
1,270
308
497
8.7
12.7
174
46.1
261
44,455
308
44
1,063
134
171
203
265
247
50,806
980
40,072
962
208
351
58
8.6
93
280
74
31,179
196
34
737
75
151
186
169
424
29,905
70
1.6
0.5
1.1
9.7
1.2
0.04
5.7
0.53
0.88
no
0.92
0.68
1.2
2.8
2.5
2.1
4.3
2.5
no
0.79
30
198
35
81
1.6
1.4
35
33
26
10,346
35
9.7
103
13
30
14
30
58
8,756
15
*
91
79
89
700
79
77
68
39
94
75
100
79
68
107
100
77
196
76
9
*
For mass balance calculations, bottom ash has been assumed to have the
same trace element concentrations as fly ash. This is an approximate
assumption, as some trace elements are enriched in the fly'ash.
Percent recovery is defined as the ratio of the sum of the emissions for
a trace element to the trace element in the coal feed.
Percent recovery for calcium is not calculated because most of the
calcium in the scrubber cake is from the lime slurry.
4-60
-------
TABLE 4-37. MASS BALANCE OF TRACE ELEMENTS - TEST 202-4
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Oil Feed
g/min
16.4
(12. 2)1"
( 2.4)
( 5.9)
(20.9)
(n.o)
3.6
( 3.9)
4.2
36.7
( 7.9)
( 1.2)
( 8.7)
47.7
108.8
8.9
( 2.0)
0.7
10.4
( 0.6)
Scrubber
Cake
g/min
50,000
950
*
0.8
3.9
10.0
0.2
3.9
*
4.7
4.1
541
*
1 .5
4.0
*
3.5
33.0
50.7
9.1
*
2.4
59.8
421
9.2
Scrubber
Outlet
g/min
2.8
1.2
0.2
1.2
1.5
2.6
0.7
0.5
0.3
n.o
0.5
0.2
1.0
7.9
32.3
2.7
0.2
0.04
18.9
0.04
Percent
Recovery
**
>1 ,000
42
68
55
25
125
133
105
>1,000
25
350
52
91
76
133
136
>1 ,000
>1 ,000
>1 ,000
SSMS data were utilized where ICPOES analysis provided upper limit
data only.
ICPOES data from the analysis of scrubber inlet particulates were
utilized when fuel analysis provided upper limit data only-
Percent recovery of a trace element is 100 times the ratio of its total
emission rate (scrubber cake plus scrubber outlet) to its feed rate.
Percent recovery for calcium is not calculated because most of the
calcium in the scrubber cake is from the lime slurry.
4-61
-------
Scrubber cakes from coal and oil firing were also analyzed for
organics but none were detected. This is to be expected since the con-
centration of organics in the flue gas streams was extremely low.
ANNUAL EMISSIONS
Estimated annual controlled and uncontrolled emissions of the major
pollutants are presented in Table 4-38 for both fuels. These estimates
were computed assuming that the boiler operates at 100% load for 87% of the
year (7,560 hours/year) and that either coal or oil is the only fuel
burned.
AIR QUALITY ASSESSMENT - COAL AND OIL FIRING
Simplified air quality models were used to determine relative air
quality resulting from uncontrolled and controlled emissions. The ambient
air quality values are approximate only. The emphasis should be placed on
the relative values for each case as opposed to their absolute values.
Worst case weather conditions and typical weather conditions were
considered. The worst case was assumed to be plume trapping. An equation
proposed by Bierly and Hewson [14] was used with the following assump-
tions: inversion height 100 meters, wind speed 1.0 meter/second, D class
stability (neutrally stable) in the mixing layer, and effective stack
height of 50 m (1640 ft). The typical case was assumed to correspond to
the standard Gaussian convective diffusion equation, [15]. The following
conditions were used: wind speed 4.0 meters/second and D class stability.
These conditions could reasonably be expected to occur almost anywhere in
the country. Typical does not mean average. It was assumed that all
species were inert. No photochemical reactions were considered. (See
Appendix A for details).
Figures 4-2 through 4-9 present plots of approximate ambient air
quality as a function of distance downwind from a single 10 MW equivalent
source. Data for N0x, CO, S02 and particulates are presented. The purpose
of these figures is not to attempt to accurately predict air quality but
to compare the effects of controlled and uncontrolled emissions under an
4-62
-------
TABLE 4-38. ANNUAL EMISSIONS
TABLE 4-38. ANNUAL EMISSIONS
-pa
oo
Pollutant
Gaseous N0x (as N02)
so2
so3
so4
CO
Organics (as CH.)
C7 " C16
>C16
Total Participates
10y
Scrubber Inlet
Coal Firing
500,810
1,127,300
6,184
67,214
16,119
5,870
<5,606
345
2,311
2,991,700
--
--
--
Oil Firing
164,230
906,202
7,249
20,894
4,991
2,272
<4,164
155
2,381
53,832
--
--
--
--
kg/year
Coal/011 Coal Firing
3.05 442,520
1.24 36,800
0.85 4,157
3.22 8,110
3.23 14,497
2.58 6,377
<5,606
2.22 274
0.97 335
55.6 18,856
11,691
5,657
1,320
188
Scrubber Outlet
Oil Firing
157,390
24,453
5,183
8,303
4,845
2,500
<4,164
18
392
13,686
11,359
1,642
634
0J
Coal/Oil
2.81
1.51
0.80
0.98
2.99
2.55
--
15.2
0.85
1.38
1.03
3.45
1.93
--
m /year
Liquid Blowdown/Uaste Water
Cooling Water
-v.76,000
^86,000
v76,000
v.86,000
x. 1 -v.76,000
v. 1 -x-86,000
x-76,000
-x.86,000
v- 1
x. 1
kg/year
Sol id Bottom Ash
Fly Ash
Scrubber Cake
x- 778,600
-x.1,800,000
0
x, 7,600
x-15,000
0
^103 -x. 778,600
x-120 x-1,800,000
8,054,100
x. 7,600
-x-15,000
3,011 ,000
x-103
v.120
2.67
Assuming 100% load, 45 weeks per year (7,560 hrs/year).
These values represent the detection limit of the instrument used.
These values represent oil firing particulate with a minimum of coal ash contamination.
-------
COAL. INLET
- COAL. OUTLET
_ OIL. INLET
OIL, OUTLET
PRIMARY AND SECONDARY
STANDARD: ANNUAL
ARITHMETIC MEAN
100
'"^"""VWhrT^
**imjtijtr.i
8
T^
10
I
12
DISTANCE FROM STACK, km
Figure 4-2. Comparison of NOX Air Quality Resulting From Coal
and Oil Firing Under Worst Case Weather Conditions
(Tests 201-1 and 202-1)
4-64
-------
COAL. INLET
- COAL, OUTLET
OIL, INLET
OIL, OUTLET
PRIMARY AND SECONDARY
STANDARD: ANNUAL
ARITHMETIC MEAN
T ' 1 T
6 8 10
DISTANCE FROM STACK, km
Figure 4-3.
Comparison of NOX Air Quality Resulting From Coal
and Oil Firing Under Typical Weather Conditions
(Tests 201-1 and 202-1)
4-65
-------
24
22-
20-
18-
16-
THE MOST RESTRICTIVE CO
STANDARD IS 10 mg/m3
(8-HOUR AVERAGE)
COAL, INLET
- COAL, OUTLET
OIL. INLET
« OIL. OUTLET
CO
"* 14-
12-
10
I
5 8 --
CD
6 -
4 - -
2 - -
6
I
10
12
DISTANCE FROM STACK, km
Figure 4-4. Comparison of CO Air Quality Resulting From Coal and
Oil Firing Under Worst Case Weather Conditions
(Tests 201-1 and 202-1)
4-66
-------
m
~
o
e
in
1-
ui
THE MOST RESTRICTIVE CO
STANDARD IS 10 mg/m3
(8-HOUR AVERAGE)
COAL. INLET
COAL. OUTLET
OIL, INLET
OIL, OUTLET
1- -
DISTANCE FROM STACK, km
Figure 4-5.
Comparison of CO Air Quality Resulting From Coal
and Oil Firing Under Typical Weather Conditions
(Tests 201-1 and 202-1)
4-67
-------
1800
1800- -
1400 -
n
cc
i
8
1200 - -
1000
800 - -
600 ' '
400 . .
200- -
COAL. INLET
COAL. OUTLET
OIL. INLET
OIL. OUTLET
SECONDARY STANDARD:
MAXIMUM 3-HOUR AVERAGE
PRIMARY STANDARD:
MAXIMUM 24-HOUR AVERAGE
PRIMARY STANDARD:
ANNUAL ARITHMETIC
MEAN___ ___ ___
6
10
I
12
14
DISTANCE FROM STACK, km
Figure 4-6. Comparison of S02 Air Quality Resulting from Coal
Oil Firing under Worst Case Weather Conditions
(Tests 201-1 and 202-1)
and
4-68
-------
400- -
COAL, INLET
__-,_«. COAL, OUTLET
- OIL, INLET
OIL, OUTLET
SECONDARY STANDARD:
MAXIMUM W-HOUR AVERAGE
PRIMARY STANDARD:
ANNUAL GEOMETRIC MEAN
___ . -i«
DISTANCE FROM STACK, km
Figure 4-7- Comparison of S02 Air Quality Resulting From Coal
and Oil Firing Under Typical Weather Conditions
(Tests 201-1 and 202-1)
4-69
-------
3000-
]
1
Ul
o
8
= 2000
00
1000-
COAL. INLET
COAL. OUTLET
OIL. INLET
OIL. OUTLET
ALL PRIMARY AND SECONDARY
STANDARDS ARE IN THE RANGE
60
6 8
DISTANCE FROM STACK, km
10
12
14
Figure 4-8. Comparison of Participate Air Quality Resulting from Coal
and Oil Firing under Worst Case Weather Conditions
(Tests 201-1 and 202-1)
4-70
-------
1000-
COAL. INLET
COAL. OUTLET
___ OIL. INLET
OIL. OUTLET
PRIMARY STANDARD:
MAXIMUM 24-HOUR AVERAGE
SECONDARY STANDARD:
MAXIMUM 24-HOUR AVERAGE
SECONDARY STANDARD:
ANNUAL GEOMETRIC MEAN
SECONDARY STANDARD:
ANNUAL GEOMETRIC MEAN
100-
Figure 4-9.
6 8 10
DISTANCE FROM STACK, km
Comparison of Participate Air Quality Resulting From
Coal and Oil Firing Under Typical Weather Conditions
(Tests 201-1 and 202-1)
4-71
-------
arbitrary but realistic set of meteorological conditions. It is implicit
in this approach that each set of meteorological conditions remains con-
stant for a sufficient length of time for the ambient air quality to reach
steady state conditions at each distance. Note also that the plots re-
present a single line extending directly downwind from the source.
Table 4-39 presents a summary of the federal ambient air quality
standards for each pollutant. The standards were also shown on each plot.
TABLE 4-39 NATIONAL AMBIENT AIR QUALITY STANDARDS
FOR CRITERIA POLLUTANTS
Pollutant
Pollutant Standard
Primary* Secondaryt
Nitrogen Dioxide
Carbon Monoxide
Sulfur Dioxide
Total Suspended
Particulate
100 yg/m (0.005 ppm)
annual arithmetic mean.
10 mg/m3 (9 ppm)
maximum 8-hour average;
40 mg/m3 (35 ppm)
maximum 1-hour average.
80 yg/m3 (0.03 ppm)
annual arithmetic mean;
365 yg/m3 (0.14 ppm)
maximum 24-hour average,
3
75 yg/rrf' annual geo-
metric mean: 260 yg/m
maximum 24-hour average.
Same as primary
Same as primary
1300 yg/m3 (0.05 ppm)
maximum 3-hour average
60 yg/m annual geo- .,
metric mean: 150 yg/m
maximum 24-hour average.
k
Primary, necessary to protect the public health.
Secondary, necessary to protect the public welfare.
-------
Keeping in mind the caveats mentioned above, several observations can
be made:
The NOX standard is exceeded under both weather conditions
during coal firing. Peak concentrations at 1.2 km from
the stack were 3 to 4 times greater during coal firing than
during oil firing. During oil firing, the NOX standard was
exceeded under worst case weather conditions but not under
typical weather conditions. Since the scrubber does not
remove significant amounts of NOX, there is no substantial
difference between the air quality resulting from inlet
and outlet emissions. (The boiler has no NOX controls.)
CO standards are not exceeded under any conditions. The
most restrictive standard is 10 mg/m3 (10,000 yg/m3) and
the maximutr, predicted level is only about 0.2% of this
value. As with NOX there is no substantial difference
between the inlet and outlet concentrations. Peak con-
centrations at 1.2 km from the stack were 3.5 to 4 times
greater during coal firing than during oil firing.
All primary S02 standards are exceeded under both weather
conditions for uncontrolled emissions from coal firing.
Peak uncontrolled S02 concentrations were 1.7 times
greater during coal firing than during oil firing. Un-
controlled emissions from oil firing exceeded both primary
standards under worst case conditions. Under typical
conditions only the annual primary standard is exceeded
by uncontrolled emissions. For controlled emissions
during both coal and oil firing, no standards are exceeded.
During coal firing, all particulate standards are exceeded
under both weather conditions for uncontrolled emissions.
Peak concentrations at 1.2 km from the stack were approxi-
mately 23 times greater for coal firing than for oil
firing. During oil firing, one primary and both secondary
standards are exceeded by uncontrolled particulate
emissions under worst case weather conditions. No
standards are violated under typical weather conditions
during oil firing. Controlled emissions for all cases
are less than all particulate standards.
4-73
-------
CONCLUSIONS
1) Uncontrolled emissions of criteria pollutants produced during coal
firing correspond well with emission factors from AP-42. This
observation does not generally hold true for oil fired emissions.
Full load NO emissions from oil firing were 19% lower than the AP-42
A
emission factor, although they appear to be within the normal range
for similar industrial units. CO emissions from oil firing were
nearly 63% lower than the AP-42 emission factor. Oil-fired S02 and
total hydrocarbons correspond well with their respective AP-42
emission factors. Particulate emissions from oil firing, in the
absence of coal ash contamination, are approximately twice the value
tabulated in AP-42.
2) NO emissions increased with increasing load for both coal and oil
A
firing, as expected. Available data indicate that for boiler loadings
between 90 and 100%, NO emissions from c<
X
three times greater than from oil firing.
between 90 and 100%, NO emissions from coal firing are approximately
X
3) Observed reductions of NO em^-ions for coal firing and early oil
A^
firing tests appear to be due, at least in part, to air leakage into
the scrubber outlet sampling line. Data from later oil firing tests,
not known to be subject to leakage problems, indicate that NO
A
removal across the scrubber is on the order of 2%.
4) Uncontrolled CO emissions from coal firing were 15.9 ng/J (0.04 lb/
MM Btu) while those from oil firing were 5.47 ng/J (0.01 Ib/MM Btu).
This factor of three difference is at variance with AP-42 data
indicating that CO emissions from oil firing are 23% lower than those
from coal firing. Apparent reductions in CO emissions across the
scrubber are not considered significant due to air leakage in the
sampling train and the low sensitivity of analysis at the measured
CO concentrations.
4-74
-------
5) Uncontrolled S02 emission rates during coal and oil firing were
1112 ng/J (2.59 Ib/MM Btu) and 993 ng/J (2.31 Ib/MM Btu), respectively.
Removal data indicate an average scrubber removal efficiency of 97%
during both coal and oil firing. Controlled S02 emissions for coal
and oil firing were 36.3 ng/J (0.08 Ib/MM Btu) and 26.8 ng/J (0.06
Ib/MM Btu), respectively, which are lower than either existing or
proposed NSPS limitations.
6) Particulate loadings prior to scrubbing were 2951 ng/J (6.86 Ib/MM Btu)
during coal firing and 59.0 ng/J (0.14 Ib/MM Btu) during oil firing,
in the absence of coal ash contamination. Scrubbing removed 99% of
the coal fired particulates and 75% of the oil-fired particulates.
The lower removal efficiency obtained during oil firing is attributed
to the increased fraction of particles smaller than 3 ym; at least
21% of the uncontrolled oil-fired particulates are less than 3 ym
in diameter while substantially less than 1% of uncontrolled coal-
fired particulates are under 3 ym.
7) There appeared to be a net increase in emission rates across the
scrubber for coal fired particulates less than 3 ym in size. This
net increase can be attributed to the poor removal efficiency of the
scrubber for fine particulates, and to the sodium bisulfate (NaHSO^)
and calcium sulfite hemihydrate (CaS03*l/2 H20) particulates generated
by the scrubber. Both NaHS04 and CaSCyi/2 H20 have been identified
at the scrubber outlet but not at the inlet. Although a very slight
increase in oil-fired particulates in the 1-3 ym range was observed,
a net decrease in particulates less than 3 ym was observed during oil
firing. Based on the results of coal firing tests, it appears reason-
able that scrubber generated particulates were present in the scrubber
outlet stream during oil firing but that the high fine particulate
loading associated with oil firing masked detection of these materials.
4-75
-------
8) Of the 22 major trace elements analyzed in the flue gas stream
during coal firing, 18 exceed their MATE values at the scrubber
inlet and 4 at the scrubber outlet. Similarly, for oil firing,
11 exceeded their MATE values at'the scrubber inlet while 5 exceeded
their MATE values at the scrubber outlet. Elements exceeding their
MATE values at the scrubber outlet and which are common to both
fuels are arsenic, chromium and nickel. Additionally, iron exceeded
its MATE value at the scrubber outlet during coal firing as did
cadmium and vanadium during oil firing. The overall removal of
trace elements across the scrubber is 99% for coal firing and 87%
for oil firing.
9) Polycyclic organic material (POM) was not found in the scrubber
3
inlet or outlet at detection limits of 0.3 ug/m for either coal or
oil firing. MATE values for most ROM's are greater than this detec-
tion limit. However, since the MATE values for at least two POM
compounds - benzo(a)pyrene and dibenz(a,h)anthracene - are less than
3
0.3 yg/m , additional GC/MS analyses at higher sensitivity would be
required to conclusively preclude the presence of all POM's at MATE
levels.
10) Beryllium emissions after scrubbing were less than or equal to the
beryllium MATE value during coal and oil firing. At the measured
emission concentrations, the National Standard for Hazardous Air
Pollutants limitation of 10 grams beryllium per day would only be
exceeded by boilers of 50 MW capacity for coal firing and 100 MW
capacity for oil firing.
11) The combined waste water stream from the boiler operation may
not pose an environmental hazard in terms of organic materials
since the discharge concentrations of organics are well below their
MATE values for both coal and oil firing. The same conclusion may
be drawn for inorganic compounds with the exception of cobalt, nickel,
copper and cadmium for coal firing and nickel and copper for oil firing
since these metals may exceed their MATE values.
4-76
-------
12) Organic emissions for coal and oil firing were very similar. Total
organic emissions were less than 9 ng/J (0.02 Ib/MM Btu) for both
tests, and these emissions appear to be primarily C, to Cg hydrocarbons
and organics heavier than C^. While uncontrolled emission rates for
both coal and oil firing are low, emissions of these organics were
further reduced by about 85% in the scrubber unit.
13) The organic compounds identified in the gas samples from both coal
and oil firing were generally not representative of combustion-
generated organic materials, but were compounds associated with
materials used in the sampling equipment and in various analytical
procedures. This again confirms the low level of organic emissions.
14) The fraction of fuel sulfur converted to SO-, during oil firing was
50 to 75% higher than during coal firing. In contrast, the fraction
of fuel sulfur converted to sulfates during coal firing was twice
that during oil firing.
15) The relatively poor removal efficiency (approximately 30% in both
oil and coal-fired tests) for SO- across the scrubber is an indication
that $03 is either present as very fine aerosols in the scrubber
inlet, or is converted to very fine aerosols in the flue gas stream
as it is rapidly cooled inside the scrubber.
16) Sulfates are more efficiently removed than S03 (60% removal for oil
firing and 88% for coal firing). This indicates that S04~ is probably
associated with the larger particulates, which are more efficiently
removed than smaller particulates. The higher sulfate removal from
the coal flue gases is explained by the higher particulate loading
during coal firing.
4-77
-------
17) Uncontrolled chloride and fluoride loadings were higher during coal
firing (5 and 0.2 ng/J, respectively) than during oil firing (0.2 and
0.02 ng/J, respectively). This was attributed, in the case of
chlorides, to a higher fuel chlorine content for coal than for oil.
Chlorides were removed with better than 99% efficiency from coal flue
gases and with about 51% efficiency from oil flue gases. This
difference was attributed to the higher particulate removal efficiency
for coal particulates. Fluorides were removed with greater than 86%
and about 87% efficiency for coal and oil firing, respectively-
Uncontrolled nitrate emissions were 0.08 ng/J during oil firing, and
nitrates were removed from oil flue gases with 57% efficiency.
18) Mass closure for most trace elements from coal firing has been found
to be in the 75 to 107% range. Mass closure for half of the trace
elements from oil-firing is in the 50 to 136% range; closure for the
remainder of oil firing trace elements is poorer due to the extremely
low elemental concentrations measured and/or contamination of the
recycle scrubber solution during coal firing tests.
19) Scrubber cake production during coal firing was 3.3 times greater
than during oil firing. Had the multiclone unit been functioning
properly, this ratio would be reduced to 2.7, assuming 60% multiclone
efficiency. Available data indicate that the principal difference
between scrubber cake production rates from coal and oil firing is
the particulate loading and associated unbound moisture.
20) The scrubber cake produced during coal firing contained 29% cpal fly
ash; during oil firing it contained 1% oil fly ash. The trace ele-
ment concentrations in the coal-fired scrubber cake exceeded their
health based MATE values, with the exception of boron. In the oil-
fired scrubber cake, all trace elements except antimony, boron, moly-
bdenum and zinc exceeded their health based MATE values. All ecology
based MATE values were exceeded by trace element concentrations during
both oil and coal firing. Because the trace elements may leach from
the disposed scrubber cake, these solid wastes must be disposed of in
specially designed landfills.
4-78
-------
REFERENCES FOR SECTION 4
1. Sarofim, A.F. and R.C. Flagan. NOX Control for Stationary Combustion
Sources Prog. Energy Combust. Sci., Volume 2, 1976.
2. Magee, E.M., H.J. Hall and G.M. Varga, Jr. Potential Pollutants in
Fossil Fuels. Report prepared by ESSO Research and Engineering Co.
for EPA under contract No. 68-02-0629. June 1973.
3. Ruch, R.R., H.J. Gluskoter and N.F. Skimp. Occurrence and Distribution
of Potentially Volatile Trace Elements in Coal: A Final Report.
Illinois State Geological Survey Environmental Geology Notes. Number
72. August 1974.
4. Hamersma, J.W. and M.L. Kraft. Applicability of the Meyers Process
for Chemical Desulfurization of Coal: Survey of Thirty Five Coals.
Report prepared by TRW Systems Group for EPA under contract No.
68-02-0647. September 1975.
5. Koutsoukos, E.P., M.L. Kraft, R.A. Orsini, R.A. Meyers, M.J. Santy,
and L.J. Van Nice. Meyers Process Development for Chemical Desul-
furization of Coal, Vol. I. Report prepared by TRW Systems Group for
EPA under contract No. 68-02-1336. May 1976.
6. R.A. Woodle and W.B. Chandler, Jr. "Mechanism of Occurrence of
Metals in Petroleum Distillates". Industrial and Engineering Chemistry
44: 2591 , November 1952.
7. R.L. Bennett and K.J. Knapp. "Particulate Sulfur and Trace Metal
Emissions from Oil-fired Power Plants". Presented at AIChE meeting.
June 1977.
8. Compilation of Air Pollution Emission Factors, AP-42, Part A. Third
Edition. U.S. Environmental Protection Agency. August 1977.
9. Cato, G.A. , L.J. Muzio and D.E. Shore. Field Testing: Application
of Combustion Modifications to Control Pollutant Emissions from
Industrial Boilers - Phase II. Report prepared by KVB for EPA under
contract No. 68-02-1704. April 1976.
10. Steam-Electric Plant Air and Water Quality Control Data. Federal
Power Commission. March 1975.
11. Kircher, J.F., A.A. Putnam, D.A. Ball, H.H. Krause, R.W. Coutant,
J.O.L. Wendt and A. Levy. A Survey of Sulfate, Nitrate and Acid
Aerosol Emissions and their Control. Report prepared by Battelle-
Columbus Laboratories for EPA under contract No. 68-02-1323. April
1977.
4-79
-------
12. Proceedings: Symposium on Flue Gas Desulfurization. Hollywood,
Florida. November 1977.
13. Cleland, J.G. and G.L. Kingsbury. Multimedia Environmental Goals
for Environmental Assessment, Volume^ 1 and II, EPA-6GO//-/7-I36a,
November 1977.
14. Bierly, E.W. and E.W. Hewson. Some Restrictive Meteorological
Conditions to be Considered in the Design of Stacks, J. Appl. Meteor.,
1,3, Pages 383-390. 1962.
15. Turner, D.B. Workbook of Atmospheric Dispersion Estimates. U.S.
Department of Health, Education and Welfare. 1969.
4-80
-------
SECTION 5
COMPARATIVE ENVIRONMENTAL IMPACT ASSESSMENT
Future energy policies will affect the social, economic, energy, and
physical environments. One of the major policy issues involves intensifi-
cation of coal utilization and the effects of end use of coal relative to
fuel oil. It is essential that these effects be determined so that national
energy policies involving the alternative energy systems may be developed.
This section evaluates the difference in impacts resulting between
emissions from coal and oil combustion in industrial boilers. Absolute im-
pacts resulting from either oil or coal combustion are also analyzed to the
extent necessary to evaluate the significance of the differential impacts.
The analysis is conducted in five parts. The first part introduces back-
ground information pertinent to the development of the environmental assess-
ment, including a review of relevant studies, plant emissions, and air
quality forecasts. In the succeeding parts, the major health, ecological,
societal, and economic impacts resulting from oil and coal-firing in well-
controlled boilers are estimated. The final section assesses the implica-
tions of the impacts for energy development by considering: 1) the addi-
tional controls which may be needed to mitigate the expected damage levels,
and 2) the potential effect of such control needs on energy cost and
energy resource development.
INTRODUCTION
Economic and environmental concerns over the nation's energy develop-
ment policies have precipitated several research efforts to evaluate the
consequences of the various energy system alternatives. These efforts deal
with all phases of energy development, from fuel production to fuel end use.
To organize the various efforts into a systematic, coordinated, environ-
mental assessment structure, the Environmental Protection Agency is imple-
menting a Comprehensive Combustion Environmental Assessment (CCEA) Program.
This program has been established for the purpose of integrating together
separate data generated by past and current studies into a complete environ-
mental assessment of conventional combustion processes. The integration
procedure involves coordination and information exchange between EPA related
studies to: 1) determine the extent to which the total environmental,
-------
economic, and energy impacts of conventional combustion process can be
assessed, 2) identify additional information needed for complete assessment,
3) define the requirements for modifications or additional developments of
control technology, and 4) define the requirements for modified or new
standards to regulate pollutant emissions. The CCEA Program coordinates
and integrates current and future studies encompassing a wide spectrum of
environmental assessment areas and conventional combustion processes. Inte-
gration of these studies, including the present effort, will provide the
basis for energy policies which result in the expanded use of conventional
combustion processes at reasonable environmental, economic, and energy
costs.
A major research program of particular significance to the industrial
combustion assessment activities is the Integrated Technology Assessment
(ITA) Program. One current study [12] under the ITA Program will examine growth,
impacts, and characteristics of the industrial boiler sector under alter-
native energy, economic, and environmental policies. This study is to be
coordinated under the CCEA Program and will accept the range of data
available from CCEA program outputs, including data from the present study.
Ultimately, the ITA study will develop an industrial combustion environmental/
economic model and combine this with the simulation model of the electric
utility system (already under development in a related ITA study) to permit
interactive examination of economics and energy policies, and regulations for
each combustion sector.
Various studies of the CCEA/ITA Program are relevant to the present
study. While there are major uncertainties associated with the findings of
the various studies, and many improvements in the analyses are needed before
the extent of environmental effects can be determined with certainty, the
conclusions and findings are important and the methodologies used in the
analyses are valuable tools which are considered and utilized in the present
effort. This study contributes to reducing the uncertainties by alleviating
two major drawbacks common to previous studies. First, previous studies
evaluated the effect of coal combustion on an absolute basis, without com-
parison to the effects of alternative fuel uses or a "business as usual"
fuel use scenario. If coal is to be used instead of other fuels, the real
impact of this use is the difference between the effects of the coal use and
the other probable alternatives. The present study addresses this issue by
5-2
-------
developing a comparative environmental assessment between the emissions
resulting from coal combustion and the most probable alternative, oil
combustion. Second, the previous analyses rely on limited emissions data
and numerous assumptions regarding the probable magnitude of the "regulated
pollutants" and especially the trace contaminants. The present study avoids
the need for these assumptions by generating actual emissions test data
for both coal firing and oil firing at a representative industrial boiler
site using typical fuels. The tests are plant and fuel specific, and
caution should be used in extrapolating study results to the continuum
of probable boiler and fuel scenarios.
Plant Emissions
Emissions data from the previous chapters reveal there are significant
differences between emissions from 'controlled oil and coal-fired boilers
of 10 MW capacity. Table 5-1 reviews the distinctions for the various
pollutant species. Emissions of nitrogen oxides (NO ) from coal firing are
/\
twice the level produced during oil firing. For both oil and coal firing,
the total NO emission rate exceeds the rates permitted by the New Source
A
Performance Standards (NSPS) for larger utility boilers. However, this is
not surprising since the boiler was not equipped with NO control equipment.
P\
The emissions rates for particulates and sulfur oxides (SO ) are essentially
X
the same for both oil and coal firing, and the level of these emissions is
relatively low considering the level which is permitted by the NSPS for
larger utility boilers. The particularly low level of S02 emissions (despite
the use of high sulfur fuels) observed in tests was due to the high effi-
ciency (greater than 95%) of the flue gas desulfurization system. This
system, plus mechanical separators, is also effective in removing particulate
matter. Emissions of carbon monoxide (CO) during both oil and coal firing
are relatively insignificant, and coal firing produces about two to three
times the amount of CO as oil-firing.
Emissions of trace elements (as particulates) during controlled
coal firing are not significantly different from that occurring during oil
firing (Table 5-1). This occurs despite the fact that, prior to control,
combustion flue gases contained appreciably greater concentrations of trace
elements than the oil-fired flue gases.
5-3
-------
TABLE 5-1 EMISSION RATES FROM A WELL-CONTROLLED
OIL- AND COAL-FIRED INDUSTRIAL BOILER
en
Pollutant
so2
NOX
Particulates
CO
As
Cd
Co
Cr
Cu
Mo
Ni
Pb
Se
Emissions, gm/sec for 10 MW Boiler9
Coal Firing'3
1.10 (15.8)
12.8 (8.8)
.59 (1.4)
.44
2.7 X ID'3
1.2 X 10"5
1.5 X 10"4
1.6 X 10~3
2.4 X 10"4
3,3 X 10-4
7.7 X ID'4
2.6 X KT4
1.2 X 10-3
Oil Firingb
1.17 (13.1)
6.06 (4.8)
.73 (1.6)
.17
3.2 X 10-4
7.0 X 10"4
1.3 X 10~4
1.9 X 10"4
7.4 X 10"5
2.6 X 10-4
2.2 X lO-3
1.4 X 10-4
6.4 X 10-5
Data are based on 2 separate tests of nearly equivalent boiler loading (100% capacity during oil burn-
ing and 97.5% during coal burning). The composition of the fuels which were used in the test burns is
discussed in Chapters 5 and 6.
Figures in parentliesis are emission levels corresponding to new source performance standards for utility
boilers to a 10 MW industrial boiler.
-------
Impact on Air Quality
The duration of exposure is important in determining effects of
changing air quality. The highest concentrations occur for short periods
(usually less than one hour) under meteorological conditions causing plume
fumigation. The stack emissions are trapped under an inversion layer, with
the plume spreading downward. The frequency of occurrence and the severity
of such fumigation conditions varies depending on the site. As a conser-
vative worst case estimate in this study, fumigation conditions were
assumed to persist for periods as long as three hours. Typical 24 hour
maximum concentrations were estimated assuming Gaussian steady state plume
dispersion under conditions of low wind speed and stable atmosphere.
Typical 24 hour levels were translated to annual expected concentrations
by applying ratios for the one day maximum and annual mean as empirically
derived from the Continuous Air Monitoring Project [18,19,20,21], Effective
stack heights were estimated based on assumed meteorological conditions and
actual stack parameters measured during the oil and gas-firing tests.
Table 5-2 shows the maximum predicted levels for "criteria pollutants"
in the vicinity of an industrial plant. The short term maximum concentra-
tions present the most significant air pollution problem. Of the present
ambient air quality standards, the 24 hour NO standard appears to be the
J\
most difficult for either coal or oil-fired facilities to meet. Coal-firing
is more apt to produce violations of the federal ambient standards for NO
/\
as the forecasted maximum incremental increase in ambient NOX from a
single plant alone is more than one-half the ceiling level imposed by the
NAAQS ceiling value. The next most difficult air quality standards for the
coal and oil-fired boiler to meet are short term standards for S0£ (3 hour
average). Coal-firing and oil-firing are estimated to cause maximum incre-
ments of 50 and 33 g/m , respectively, directly downward of the source.
For the case of CO and total suspended particulates, the estimated short
term increases from both oil and coal combustion are appreciably less than
the ambient standards. For any of the pollutants, it should be noted that
the short term maximum concentrations generally occur infrequently (depending
on site meteorology) and are usually of very brief duration (usually about 1
hour or less).
5-5
-------
TABLE 5-2. COMPARISON OF FEDERAL AIR QUALITY STANDARDS WITH AIR QUALITY PREDICTED
TO RESULT FROM OIL AND COAL COMBUSTION IN A 10 MW INDUSTRIAL BOILER
S02
Single plant, coal
Single plant, oil
Cluster of plants,0 coal
Cluster of plants,0 oil
MAAQS
PSD Class I incrementd
PSD Class II increment01
Total Suspended Participates
Single plant, coal
Single plant, oil
Clustered plants,0 coal
Clustered plants,0 oil
NAAQS
PSD Class I increment
PSD Class II increment
3
Maximum Concentration, ug/m
1-3 Hour9
50
33
225
150
1300 (3 hrs.)
25 (3 hrs.)
700 (3 hrs.)
26
21
118
95
24 Hourb
12
8
50
33
365
5
100
7
5
29
21
260
10
30
Annual Average6
3
2
13
8
80
2
15
2
1
7
5
75
5
10
-------
TABLE 5.2. (Continued)
en
I
NOX
Single plant, coal
Single plant, oil
Clustered plants,0 coal
Clustered plants,0 oil
NAAQS
CO
Single plant, coal
Single plant, oil
Clustered plants,0 coal
Clustered plants,0 oil
NAAQS
582
170
2640
770
20
5
400
157
40,000 (1 hr).
1,000 (8 hrs)
146
43
400
180
250
5
1.2
21
5
39
11
100
45
100
1
0.3
5
1
Based on worst case meteorological conditions (plume fumigation).
Based on typical meteorological conditions for 24 hour period.
°As a crude means of approximating the effect of an aggregate of plants, the 3 hour and 24 hour levels
were adjusted by assuming the additive effect of a plant "cluster." A cluster of plants was assumed to
consist of a line of 5 industrial boilers (10 MW each) spaced equally at 200 m apart and aligned with
the prevailing wind direction.
Prevention of significant deterioration standards.
eThe expected annual average levels were estimated based on the conservative end of the range of typical
ratios for 24 hour maximum to annual averages as reported in the Air Quality Criteria Documents [18,19,20,21]
-------
z
UJ
O
Z
o
o
For example, Figure 5-1 shows that the short term peak resulting from coal
firing would be attained about 1000 m downwind and that ambient concentra-
tions would be diminished to one-half the peak level another 2000 m further
downwind. The maximum concentration due to oil firing occurs further down-
wind (due to a higher plume rise) at 'about 1200 m from the source, diminish-
ing to one-half this value about 2500 m further downwind.
50 -
40 - -
30 -
20 -
10 - -
12 16 20 24 28 32 36
DISTANCE FROM SOURCE, HUNDREDS OF METERS
40
Figure 5-1. Ground level concentration of S02 in vicinity of
industrial boiler under conditions of plume fumigation.
Federal standards limiting deterioration of air quality are generally
more restrictive than the NAAQS, Table 5-2 lists the allowable increment
of deterioration for the three classes of growth and development areas.
Based on the maximum concentrations of S02 and TSP resulting from either
coal or oil-firing, industrial boilers would not be permitted in Class I
areas (areas meant to be maintained pristine) but might be permitted in
5-8
-------
Class II or III areas, depending on the existing air quality. Consequently,
siting of the plants would be a major consideration in their environmental
acceptability, since areas which already experience marginally acceptable
air quality could not tolerate the increases projected to occur. In this
respect, it appears that the deterioration standards pose a slightly more
difficult attainment problem for coal-fired plants than for oil-fired plants.
Table 5-2 also shows the estimated impact on air quality for a cluster-
ed configuration of industrial plants. The estimates are based on the
additive result of ambient levels contributed by multiple sources for a
siting scenario in which five 10 MW industrial boilers are spaced 200
meters apart in a line. The scenario is by no means the most adverse case
probable for an industrial setting. Many industrial zones may contain a
greater concentration of sources, and sources of greater magnitude as well.
However, the siting scenario of the four clustered plants illustrates the
potentially high short term concentrations which may occur when well-con-
trolled oil or coal-fired industrial boilers are sited closely together,
and underscores the necessity for careful siting of sources to avoid poten-
tial violations of the NAAQS and Significant Deterioration Amendments.
Fuel selection exerts a significant role in the environmental accepta-
bility of the clustered array of plants. Table 5-2 shows that short term
ambient levels of NO in the vicinity of the cluster will violate the NAAQS
s\
when boilers are coal-fired but will meet standards when oil is burned.
This finding applies to a boiler operating without NO control. Burning
/^
of coal also produces concentrations of CO four times that estimated for
oil burning, however, the magnitude of the CO levels are inconsequential
with respect to the NAAQS. Coal-burning produces only slightly higher
levels of TSP and S02 than oil-burning.
COMPARATIVE HEALTH IMPACT
The health effects of exposure to high concentrations of the
various pollutants are well known and have been tabulated throughout the
literature, [4]. However, the specific extent to which health is affected by
ambient pollutant exposure levels (dose response relationships) is unclear.
Moreover, it is unclear how pollutant specific dose response curves may be
related to the over all health effects of the gas-aerosol complex associated
with fossil fuel combustion products.
5-9
-------
Most attempts to establish dose response functions for ambient pollu-
tion levels involve the formulation of some indicator which is then assumed
to represent the entire spectrum of primary and secondary pollutants present.
The indicator (usually sulfur dioxide, total particulates, or sulfates) is
then related to mortality or morbidity data for various areas by various
statistical approaches designed to factor out effects of other variables
(e.g., population age, climatology, etc.). Dose-response curves derived
from these studies are then employed to estimate health effects of air
quality changes resulting from proposed projects.
Recently the health effects model by Lundy and Grahn[5] has been
developed for application in the National Coal Utilization Assessment
Studies being conducted at Argonne National Laboratories. The model
combines mortality functions for suspended sulfates as developed by Morris
and Novak[6] and age-dependent and established response curves for cigarette
smoke. The mortality dose-response functions for suspended sulfates are
based on statistical studies of various populations experiencing different
sulfate exposures. Unlike the dose-response air pollution studies, inves-
tigations of smokers have been relatively well controlled with respect to
age, degree of exposure, and effect. Thus, to expand the predictability
of the sulfate dose-response curves to populations of different age distri-
bution (e.g., future populations), the cigarette response curves are adjusted
to fit the observed mortality/sulfate data, resulting in a model which pre-
dicts age-specific death rates. This elaboration is important because death
rates vary exponentially with age, and shifts in the age distribution of a
population will result in substantial shifts in total mortality. Accordingly,
the Lundy Grahn Model utilizes projections of the population age distribution
to estimate the age-specific and total death rates due to air pollution at
any specific time in the future. The basic relationship of the model is:
» bX
B(X, Xo) - ?e
where B is the number of excess deaths per year for the population of age
X which was exposed to the sulfate concentration S ( in M9/m3) since age Xo.
The constants a,b,c and d are coefficients to fit the model to cigarette
smoking mortality data and response data for a specific population subgroup
exposed to air pollution.
5-10
-------
The Lundy Grahn Model is being used in the ongoing National Coal Utili-
zation Assessment program to estimate excess mortality resulting from in-
creased coal utilization. Air diffusion modeling was conducted first to
predict a population-weighted exposure increase for suspended sulfates.
The Lagrangian Statistical Trajectory Model of Argonne National Laboratory[10]
which assumes a constant transformation of S02 to sulfate, is employed in
the estimation procedure. Then, based on the predicted exposure increase
and projections of the population age distribution, excess death rates are
calculated for each age and summed to yield the expected mortality associated
with coal combustion. Table 5-3 shows the estimated effects of an average
exposure increment of 8.95 Mg/m3 suspended sulfates predicted to result
from coal-firing of power plants throughout the Central United States.
(The degree of power plant coal firing is assumed to increase in the region
from the current level of 178 million tons per year to 820 million tons per
year in 2020). The projected levels of power plant coal utilization are
predicted to cause significant health effects in future years. These fore-
casts may be adjusted to approximate the additional health impact which can
be expected to result from coal combustion in industrial boilers. The
results of Table 5-3 are adjusted to reflect: 1) the emissions rate for
coal-fired industrial boilers relative to power plant boilers, and 2) the
relative amount of industrial boiler coal use relative to utility consumption.
TABLE 5-3. EFFECTS OF COAL COMBUSTION IN
POWER PLANTS IN CENTRAL U.S. [7]
Year
1985
2000
2020
Increase in Death
Rate, Number of
deaths/Million
persons/Year
28-130
181-809
150-665
Reduction In
Expectation of Life
At Birtha
17 - 79 days
136 days - 1.7 years
160 days - 1.8 years
a. The range of values represents the expected and upper
80% confidence limit given by Morris and Novak.[6] The
effects are calculated corresponding to3an expected
average exposure increment of 8.95 ^g/m suspended
sulfateSo
5-11
-------
Figure 5-2 presents the adjusted projections for the industrial boiler
scenario. No distinction is necessary between oil and coal firing, since
the emission rates for S02 were found to be essentially the same (see
Table 5-2). The lower emissions rate-from industrial boilers accounts for
suspended sulfate levels appreciably less than those projected for the
utilities. It is noted that the adjustments for industrial effects in
Figure 5-2 do not include an adjustment for the spatial aspect of popula-
tion exposure. Because the industrial boilers are typically located in
more urban areas than power plants, the population-weighted exposures under-
tr
o
z
UJ
CO
<
HI
CC
O
Z
X.
<
UJ
>
to
z
o
CO
-------
lying the estimates of Figure 5-2 are understated for the industrial sit-
uation. However, the understatement is probably minor, since the formation
and transport of airborne sulfates is a long range and region wide problem,
and effects of localized sulfate formation from the source are generally
minimal. It is also noted that the comparisons are applicable to the spe-
cific fuels and boiler types, and caution is advised in extrapolating the
results to fuels of different compositions.
Figure 5-2 shows that the expected health effects caused by air pollu-
tion (as indexed by suspended sulfates) from oil or coal-firing of well-
controlled industrial boilers are minimal compared to the effects which
might result from utility boilers emitting SOp at the rate prescribed by
the NSPS, and substantially less than that which would be expected under
current industrial boiler controls. The maximum impact is expected to
occur in the year 2000, when the proportion of population in the highest
risk age groups will be greatest. For each million persons, the number
of increased deaths expected to occur annually due to well-controlled
industrial boilers is 12 to 55 in the year 2000. Based on the tests of the
present study, and the sulfate health effects model, there is no indica-
tion that the difference in mortality rates resulting from well-controlled
coal-firing and well-controlled oil-firing would be significant. The test
data and the sulfate mortality model also indicate that relative mortality
effects would not be significantly different between uncontrolled coal and
uncontrolled oil firing. (See Volume II.) However, the absolute levels for
expected mortality rates due to uncontrolled coal or oil combustion would
be roughly 30 times greater than that expected from well-controlled
combustion.
Health effects caused by sulfate levels may also be expressed in terms
of morbidity. Table 5-4 presents data for increases in incidents of health
disorders due to ambient sulfate exposures. In those areas which already
experience high sulfate levels, respiratory diseases may increase signifi-
cantly with slight increases of suspended sulfates due to industrial boiler
3
emissions. For example, in areas where the threshold level 10 ug/m is
3
exceeded regularly, the increase of .6 yg/m of sulfate concentration as-
sociated with well controlled industrial boilers would be estimated to pro-
5-13
-------
TABLE 5-4. HEALTH IMPACTS OF SULFATE AEROSOL[11]
en
I
Pollutant and
Health Effect
Sul fates
" Mortality
Aggravation of
Heart and Lung
Disease in Elderly
Aggravation of
Asthma
Lower Respiratory
Disease in Children
Chronic Respiratory
Disease
Nonsmokers
Smokers
Population at Risk
Total Population
Same as above for
oxidants function
Same as above for
oxidants function
Same as above for
nitrogen dioxide
function
62 percent of
population age 21
or older
38 percent of
population age 21
or older
Assumed Baseline
Frequency of
Disorder within
Population at Risk
Daily death rate of
2.58 per 100,000
Same
Same
Same
Two percent
prevalence
Ten percent
preval ence
Pollutant
Concentration
Threshold
For Effect
25 vg/m3 for
one day or
more
9 vg/m3 for
one day or
more
6 vg/m3 for
one day or
more
13 vg/m3 for
several years
10 pg/tn3 for
several years
15 vg/m3 for
several years
Effect Increase as x
of Baseline Per
Pollutant Unit Above
Threshold
2.5% per 10 vg/m3
14. U per 10 vg/m3
33. 5% per 10 pg/m3
76.92 per 10 pg/m3
134% per 10 pg/m3
73.8% per 10 pg/m3
-------
duce an 8% increase in the incidence of chronic respiratory disease caused
at the threshold level. Once again, adverse effects are no more likely to
occur by oil-firing than by coal-firing in the well-controlLed boiler.
In addition to potential health effects created by long range sulfate
levels from industrial boilers, high concentrations of pollutants in the
range of the industrial complex pose a potentially serious health problem.
The Lundy-Grahn model may also be applied to estimate mortality effects
caused by ambient levels of SCL and total suspended particulates. The model
gives the following relationships when fitted to Lave and Seskin dose re-
sponse data[12] for S02 and TSP:
ir>6 -i 090 -064X
Per 10 males: 1^3^ (<835 Tsp + >?15 }
1 + 100e.12(X-Xo) 2
1A6 ,, , n(-c -088X
per 10 females: .056 e (.835 TSP + .715 S02)
1 + 100 e"-2(X-Xo)
If the model is applied to typical concentrations expected to occur in the
vicinity of a clustered array of industrial sources, the expected increase
in mortality is appreciable. (See Table 5-2.) Figure 5-3 illustrates the
estimated impact on mortality. For example, when boilers are coal-fired,
populations of the age 50 are predicted to experience increases in death
rates of 306 male and 200 female deaths per million persons per year. When
boilers are fired with oil, the increased death rate is about one-third
less that experienced under ambient exposures from coal-firing. The dif-
ference is attributable primarily to the higher plume rise of the oil-fired
boiler emissions which lends to greater dispersion and lower ambient con-
centrations of S02 and TSP in the vicinity of the sources. The absolute
impact of both the well-controlled oil-fired and coal-fired boilers is
relatively minor when compared to the anticipated impact of either current
industrial boiler emissions or even those emissions levels corresponding
to the NSPS. (See Figure 5-2.) It is reminded that the NSPS for utility
boilers permit an S02 emissions rate twelve times greater than the emission
rate measured for the reference well-controlled coal-fired boiler, and
eight times greater than the emissions for the reference oil-fired boiler.
Emissions at the rate associated with the NSPS would yield average ambient
5-15
-------
cc
UJ
DC
UJ
Q.
H 1
rf P"
" I
<
111 0.
0 Z
Z O
S d
2 5
CC DC
(J UJ
7 0-
UJ
Q
O
Z
600-
500-
400-
300-
200-
100- -
MALE RESPONSE
BOILERS
AT NSPS
MALE RESPONSE, COAL FIRING
MALE RESPONSE, OIL FIRING
FEMALE RESPONSE, COAL FIRING
f FEMALE RESPONSE, OIL FIRING
30 40 50 60
POPULATION AGE
Figure 5-3. Increase in mortality rates in vicinity* of clustered
industrial boilers0
*Based on the ambient air quality forecasts, the sphere of effect is assumed
to extend several km outside the clustered array of plants. (See Volume III)
The increased mortality rates are based on the maximum annual average concen-
tration of TSP and SCL expected in the vicinity of the industrial plant
cluster.
annual S09 levels between 60 and 160 ng/m , jeopardizing the primary stan-
o
dard of 80 yg/m .
Effect of Trace Elements--
Trace elements from coal combustion emissions enter the atmosphere
and are then dispersed to the upper atmosphere or deposited in the environ-
ment around the sources. The principal routes of entry to man are by in-
halation, drinking water and food.
Table 5-5 summarizes the annual average atmospheric concentrations of
various elements expected in the vicinity of a single well-controlled coal
or oil-fired industrial boiler of 10 MW capacity. The estimates are based
5-16
-------
TABLE 5-5. EXPECTED TRACE ELEMENT CONCENTRATIONS IN
VICINITY OF A 10 MW CONTROLLED INDUSTRIAL BOILER
Element
As
Cd
Co
Cr
Cu
Mo
Ni
Pb
Se
Annual Ambient
Concentration,
g/m3
Coal -Firing Oil -Fir ing
7.7 X 10"3
3.4 X 10"5
4.2 X 10"4
4.5 X 10"3
6.8 X 10"4
9.4 X 10"4
2.2 X 10"3
7.3 X 10"4
3.4 X 10"3
5.7 X TO"4
1.3 X 10"3
2.3 X 10"4
3.4 X 10"4
1.3 X 10~4
4.6 X 10"4
3.9 X 10"3
2.5 X 10"4
1.1 X 1Q"4
Typical
Urban Air
Concentration9
yg/m3
1 X 10~2
3 X 10"1
-4
2 X 10
1 X 10"2
5 X 10"2
1 X 10"1
1.4
2.4
2 X 10"4
Allowable
Exposure
Level b
ug/m3
50
20
10
50
100
500
100
20
20
Based on data reported in Reference 22.
Based on ambient air objectives proposed for hazardous waste management
facilities,[23].
on the assumption that trace elements exhibit the same relationships as
described earlier for estimation of total suspended particulates. Also
included in Table 5-5 is a listing of concentrations considered acceptable
for continuous ambient exposure. The allowable concentrations are based
on proposed regulations for control of air pollution from hazardous waste
management facilities, as required by Section 3004 of the Resource Conser-
vation and Recovery Act. It is clear that the air concentrations of
elements resulting from operation of the industrial boiler are several
orders of magnitude (4 to 6) below the "allowable exposure level." More-
over, the predicted maximum concentrations are also substantially below
typical urban ambient background levels with the exception of selenium and
cobalt concentrations which approach or slightly exceed the endogenous
levels. Considering the error bound of a factor of three associated with
the trace element analyses of this project, it is concluded there is only
5-17
-------
a slight difference between the expected ambient levels of trace elements
from either coal or oil-firing with the possible exception of cadmium.
Ambient cadmium levels from oil-firing are about 40 times greater than
that caused by coal-firing.
Clustering of plants or increases in amounts of trace elements in fuels
could increase the expected concentrations of trace elements by an order
of magnitude. However, even with such an increase, the concentration of
most elements listed in Table 5-5 would be an order of magnitude less than
typical urban maximum concentrations, and the concentration of all elements
would still be several orders of magnitude less than the "allowable exposure
level."
A primary concern in emissions of trace elements is the contribution
of these elements to body burden due to exposure to water and food. To
estimate this contribution, pollutant deposition rates are approximated
by the product of the ambient concentrations and the deposition velocity
of the pollutant. The deposition rate is dependent on particle size.
Table 4-10 (Vol. II) shows that particles emitted from the controlled oil
and coal-fired industrial boiler of this study are predominantly three
microns or less in diameter. The deposition velocity of particles this
size over grass surfaces is approximately 0.1 to 0.2 cm/sec,[13]. Accord-
ingly, the deposition rates of the various trace elements were approximated
and are shown in Table 5-6.
The significance of the deposition rates is evaluated by considering
the associated effect on drinking water and diet. The pathway to drinking
water is by run-off of soil particles containing deposits of trace elements,
and the pathway to the diet is by plant uptake from trace elements in the
soil. In either pathway, the incremental concentration of elements in the
soil determines the extent of the potential impact. Table 5-7 summarizes
the maximum predicted soil concentration in the vicinity of the scenario
of five clustered industrial boilers of 10 MW each. The concentrations
are estimated by assuming mixing of the deposited elements to a depth of
10 cm, and over a period of 40 years. For the majority of the trace elements,
only minor increases over the background soil levels would be expected.
However, the concentration of a few elements may increase significantly.
It is predicted that coal firing will cause a 60% increase in the selenium
5-18
-------
en
i
TABLE 5-6. ANNUAL DEPOSITION OF TRACE ELEMENRS IN
VICINITYb OF CONTROLLED INDUSTRIAL PLANTS
Element
As
Cd
Co
Cr
Cu
Mo
Ni
Pb
Se
2
Annual Deposition Rate,3 g/m -yr
Coal Firing
Single
Plant
2.4 X 10"4
1.1 X 10"6
1.3 X 10"5
1.4 X 10"4
2.1 X 10"5
3.0 X 10"5
6.9 X 10"5
2.3 X 10~5
1.1 X 10~4
Cluster
1.0 X ID"3
4.5 X 10"6
5.3 X 10"5
5.8 X 10"4
8.6 X 10"5
1.2 X 10"4
2.8 X 10~4
9.5 X 10"5 ,
4.5 X 10"4
Oil Firing
5 ingle
Plant
1.9 X 10"5
4.1 X 10"5
7.2 X 10"6
1.1 X 10"5
4.1 X 10"6
1.5 X 10"5
1.2 X 10"4
7.9 X 10"6
3.5 X 10"6
Cluster
7.8 X 10"5
1.7 X 10"4
3.0 X 10"5
4.5 X 10"5
1.7 X 10"5
6.2 X 10"5
4.9 X 10~4
3.3 X 10"5
1.4 X 10"5
Calculated by assunnng a particle deposition velocity of 0.2 cm/sec. The
deposition velocity is multiplied by the annual average concentration to
estimate the total deposition rate0
The deposition rate is calculated for the location where the maximum
average annual concentration occurs.
-------
en
o
TABLE' 5-7. LONG TERM EFFECT OF EMISSIONS FROM CLUSTER OF
CONTROLLED INDUSTRIAL BOILERS ON SOIL CONCEN-
TRATIONS OF TRACE ELEMENTS
Element
As
Td
Co
Cr
Cu
Mo
Ni
Pb
Se
Increased Soil
Concentration
After 40 years,9
Coal
2.7 X 10"1
1.2 X 10"3
1.4 X 10"2
1.5 X 10"1
2.3 X 10"2
3.2 X 10"1
7.5 X 10"2
2.5 X 10"2
1.2 X 10"1
Oil
2.1 X 10"2
4.5 X 10"2
8.0 X 10"3
1.2 X 10"2
4.5 X 10"3
1.7 X 10"2
1.3 X 10"1
8.8 X 10"3
3.7 X 10"3
Typi cal
Soil
Concentration^
ug/g
6.0
.06
8
40
20
2
40
10
.2
Increase Over
Average Soil
Concentrations, %
Coal Oil
4.5 .35
2.0 70
.2 .10
.4 .03
.1 .02
16 .80
.2 .4
.3 .08
60 1.8
aBased on deposition rate (Table 5-6), an assumed mixing depth of
10 cm and soil density of 1.5 g/cm^.
Based on data compiled in Reference 3.
-------
soil concentration and a 16% increase in molybdenum levels. Oil-firing is
apt to cause less impact on trace element soil levels, but is predicted to
cause a 70% increase in cadmium concentrations. The significance of the
elevated soil concentrations is evaluated by considering the associated
increase in trace element concentration in plant tissues and drinking water.
The concentration of elements in plant tissues is related to the
biologically available fraction of the elements in the soil. This is
often expressed as the soluble concentration in the soil, and is some
fraction of the total endogenous concentration reported in Table 5-7.
Plants possess the ability to concentrate elements from dilute soil
solutions. This ability is dependent on the concentration of elements in
the soil, and usually increases with decreasing soil concentration. The
ratio of concentration of elements in plants to the concentration in the
soil is known as the concentration ratio. Table 5-8 lists average plant
concentration ratios for various elements. The data are based on various
published data as complied in a study by Battelle,[3]. The effect of
increased trace element soil loadings (caused by 40 years of boiler cluster
emissions) on concentration of the elements in plants is then estimated by
assuming that the soluble portion of the loadings are available for plant
takeup (Table 5-8). The estimates reveal that seven of the nine elements
show incremental burden in plants amounting to one half to 1/700 the
typical plant concentration levels. Thus, for these seven elements, the
increase in plant concentration would appear to be insignificant in terms
of effect on human health by route of the food chain, or in terms of actual
plant life itself. For most elements, coal-firing appears to exert a
slightly greater impact on trace element plant burden, however, this dif-
ferential effect may be considered nearly insignificant in view of the
uncertainities associated with chemical analyses employed to determine
stack emissions rates. The elements predicted to produce the most notable
burdens in plant tissue are cadmium and molybdenum. Oil firing is pre-
dicted to result in plant concentrations of cadmium an order of magnitude
greater than the endogenous levels, and coal-firing is expected to produce
a thirty-fold increase in typical molybdenum concentrations.
Cadmium is considered highly toxic to plants and animals. Mammals
tend to absorb cadmium continually, accumulating high body levels which
5-21
-------
TABLE 5-8. LONG TERM EFFECT OF EMISSIONS FROM CLUSTER
OF CONTROLLED BOILERS ON CONCENTRATIONS
OF ELEMENTS IN PLANTS
'l Element
;
As
Cd
Co
Cr
Cu
Mo
Ni
Pb
Se
Concentration
Ratios9
4.2
222
87
250
1000
900
331
2
4
Solubility
Of Elements9
9
40
.4
.004
.1
9
.1
21
Typical Con-
centration
in plants,
yg/g
.08 - -55
.04 - .50
.05 - .25
.23
14
.9
3
2.7
.2
Increase in
Concentration
of plants,
Coal Oil
.1 .008
.1 4.0
.005 .003
.001 .0001
.02 .005
26 1.4
.03 .04
.05 .02
.1 .003
Extracted from Reference 3.
Calculated by multiplying concentration ratio by the incremental
increase in soil concentration (Table 105) by the concentration ratio
by the fraction of the element which is soluble.
adversely affect the respiratory, cardiovascular, nervous, and reproductive
systems, disrupt kidney and liver functions, and cause intestinal disorders.
Cadmium levels as low as 15 pig/g in plants may cause injury to man. [24]
Cadmium levels in some areas are believed to be approaching threshold
levels, and it is believed that cadmium concentrations in cigarettes might
cause smokers to exceed thresholds of observable symptoms of cadmium
poisoning if exposed to additional sources of cadmium,[25] . Consequently,
the addition of cadmium to the environment in significant quantities is a
serious concern. However, it should be noted that present day levels of
cadmium emissions from non-controlled industrial boilers are substantially
greater than those well-controlled levels discussed here.
In contrast to cadmium, molybdenum is considered to exhibit a low
order of toxicity. Molybdenum has been found to be a necessary trace
element in the body for the proper functioning of flavoprotein enzymes.[26]
5-22
-------
Still, incidents of animal injury have been reported in the vicinity of
steel plants where livestock were observed to develop inflammation of bowels
and degenerative changes in liver cells. The injury was associated with
high molybdenum levels in the cows' blood.[27] The threshold diet levels for
animals or man are unclear. The incident of cow injury was caused by
grazing in a pasture containing 20 to 100 yg/g of Mo. It should also be
noted that the occupational air exposure threshold for molybdenum is two
orders of magnitude greater than that for cadmium, and the potable water
standard for Mo is 40 times greater than the cadmium standard.
The actual impact of trace element emissions on plant burden depends
greatly on many site-specific variables, such as temperature, precipitation,
soil type, water chemistry, and plant species at a given site. Of major
concern are the endogenous concentrations of elements in soil, water, and
the atmosphere. Where trace element concentrations are approaching thres-
hold limits, emissions from industrial plants will exert a greater in-
fluence on health impacts. This consideration is particularly relevant
with respect to environmental buildup of cadmium because high background
levels of this element already exist in many areas. The impact on trace
element burdens in plants from controlled boilers, whether oil or coal-
fired, may be significantly less than that from existing boiler control.
Based on the present study, the major difference between trace element
buildup from oil versus coal firing of well-controlled boilers is the
higher cadmium levels associated with oil 'burning.
Trace elements also enter the plant via foliar absorption. Intake
from the leaf surface to the interior occurs through stomatal openings,
walls of epidemal cells, and leaf hairs. Although relatively little is
known regarding the efficiency of foliar intake, it would appear that the
plant burden produced by soils containing long term deposits is several
orders of magnitude greater than that which could be transferred from
foliar interception of trace elements in the atmosphere. Soil concentra-
tions are the result of accumulation of elements over the long-term, and
crops raised in these soils tend to concentrate the trace elements in the
plant tissue. By contrast, the foliar intake rate can be no greater than
the deposition rate on the plant surface, and there is much uncertainty
regarding the efficiency of the plant in absorbing the deposited particles.
5-23
-------
Thus, it is clear that the soil uptake scenario (Table 5-8) represents
the more adverse case for.pi ant uptake of trace elements. This scenario
assumes no interference (e.g., animal .or crop uptake) with trace element
buildup in soils over a 40 year period, and a fixed concentration of
elements in the soil despite crop uptake.
Trace element emissions also affect the quality of drinking water.
The impact of trace element particle deposition on runoff water concen-
tration will be related to the relative increase in soil concentration due
to long term atmospheric deposition of elements. The actual runoff con-
centrations may be estimated by applying average sediment burden rates for
representative runoff per unit of watershed area. The sediment is assumed
to carry the cumulative deposits of metals orginating from the boiler emis-
sions. Table 5-9 summarizes estimates of increased soluble metals con-
centrations for runoff waters in the vicinity of a cluster of industrial
plants. The estimated concentrations are three to seven orders of mag-
nitude less than the standards for livestock drinking water and potable
water. Two elements, selenium and molybdenum, are predicted to exceed
background concentrations for metals in runoff waters after 40 years of
coal-firing in the plant cluster. The concentration of metals in runoff
waters due to oil firing is predicted to be slightly less than that
occuring from coal firing; in either case, hazard to human health by
drinking water is remote.
IMPACT ON ECOLOGY
The ecological environment will be affected by air emissions and by
solid 'waste residuals generated by air pollution control equipment.
Operation of the controlled industrial boilers is not expected to produce
significant water pollution problems, since wastewaters produced are
generally acceptable to the municipal water treatment systems.
Effect of Air Emissions
A major ecological impact category most likely to be affected by
industrial boiler emissions is plant life. Of the major gaseous pollutants
emitted by fossil fuel combustion, plant life is most affected by S0? and
N0x in the concentration ranges expected. Concentrations of CO and hydro-
carbons produced by a single industrial boiler or a clustered arrangement
of boilers are considered to cause negligible impact on vegetation.[21 ,28]
5-24
-------
TABLE 5-9. TRACE ELEMENT CONCENTRATION IN RUNOFF WATER IN
VICINITY OF CLUSTERED CONTROLLED INDUSTRIAL BOILERS
Element
As
Cd
Co
Cr
Cu
Mo
Ni
Pb
Se
Typical
Background
Concentration
of Soluble
Metals In
Runoff Water3
yg/ml
4 X 10"4
1 X 10"4
3 X 10"5
1 X 10"5
2 X 10"5
1 X 10"6
1 X 10 "4
7 X 10"4
8 X 10"5
Increase In
Soluble Metals
Concentration
In Soil After
40 years"
yg/ml
Coal
2.4 X 10~2
.5 X 10"3
.6 X 10~4
,6 X 10"5
2.3 X 10"5
2.9 X 10"2
7.5 X 10"5
2.5 X 10"2
.2 X 10"1
Oil
1.9 X 10"3
1.8 X 10~2
3.2 X 10"5
.5 X 10"6
4.5 X 10"6
1.5 X 10"3
1.3 X 10~4
8.8 X 10"3
.7 X 10"3
Increase In
Soluble Metals
Concentration
In Runoff Water0
After 40 years
yg/ml
Coal
2.4 X 10"5
.5 X 10"6
.6 X 10"7
.6 X 10"8
2.3 X 10"8
2.9 X 10"5
7.5 X 10"8
2.5 X 10"5
.2 X 10"4
Oil
1.9 X 10"6
1.8 X 10"5
3.2 X 10"8
.5 X 10"9
4.5 X 10"9
1.5 X 10"6
1.3 X 10"7
8.8 X 10"6
.7 X 10"6
EPA Proposed
Maximum
Acceptable
Concentration
For Livestock
uQ/ml
2 X 10"1
5 X 10"2
1
1
5 X 10"1
^_
1 X 10"1
5 X 10"2
Standard
As Critical
Concentration
In Potable
Water
yQ/ml
1 X 10"2
1 X 10"2
5 X 10"2
2 X 10"2
1 X 10"2
5 X 10"1
5 X 10"2
1 X 10"2
1 X 10"2
en
I
ro
en
aBased on average soil particle runoff rate of 1000 yg/ml of runoff water, and soluble endogenous
concentration of metals in soils.3
bBased on increase in trace element concentration (Table 5-7) and solubility of elements (Table 5-8).
cBased on average soil particle runoff rate of 1000 yg/ml of runoff water, and increased soluble
metals concentration in soil after 40 years.
-------
The levels of NO and SCL expected to occur in the vicinity of industrial
A £
boilers approaches the threshold injury values for these pollutants. Only
very sensitive plants in the vicinity of a cluster of industrial boilers
are likely to suffer injury, and such injury would be limited to a downwind
sector and a range of about 2 km length beginning a few hundred meters from
the perimeter of the cluster.
While neither hydrocarbon or nitrogen oxides would be expected to
cause plant injury at the ambient doses predicted near the boilers, the
secondary pollutants (ozone and peroxyacylnitrates) formed by reaction of
these pollutants are considerably more toxic. The formation of secondary
compounds in boiler stack plumes and the impact of the boiler nitrogen
oxides emissions on urban photochemical smog depend on complex relation-
shops which are not yet totally understood. Therefore, it is not possible
to reliably estimate the effect of NO emissions levels to photochemical
X
compounds. However, based on typical regional emissions figures, it appears
that emissions from industrial fuel combustion provide a significant source
of the regional emissions of NO necessary for photochemical smog. Approxi-
A
mately 20% of the nation's NO emissions are produced by industrial fuel
A
combustion,[29].
If NO emissions from industrial boilers are a significant contributor
A
to photochemical smog, then there is valid concern that boiler emissions may
contribute to plant injury. Coal-firing presents the greatest concern.
NO emissions from coal-firing of the boiler of the present study were
A
measured to be twice the magnitude produced during oil-burning. The boiler
is not equipped with NO control. The effects of photochemical air pollution
A
on plant life have been observed frequently at various different severities
throughout the United States. In addition, the effect of the major consti-
tuents of photochemical smog (products of nitrogen oxides and organic
compounds) on plants has been investigated separately. The pigmentation of
small areas of palisade cells is characteristic of ozone injury, and a
bronzing of the undersurface of leaves is typical for peroxyacyenitrate
injury. Table 5-10 illustrates the relatively low levels of ozone which will
produce significant plant injury to crops. The concentrations shown are
typical of many areas experiencing photochemical air pollution, and suggest
the necessity for concern over sources emitting high levels of NOY.
A
5-26
-------
TABLE 5-10.
PROJECTED OZONE CONCENTRATIONS WHICH WILL PRODUCE, FOR
SHORT-TERM EXPOSURES, 20 PERCENT INJURY TO ECONOMICALLY
IMPORTANT VEGETATION GROWN UNDER SENSITIVE CONDITIONS, [30]
: . -
Concentrations producing injury in three types of plants, ppm
Time, Hr
0.2
0.5
I I-"
] 2.0
I 4.0
| 8.0
a
Sensitive
0.40-0.90
0.20-0.40
0.15-0.30
0.10-0.25
0.07-0.20
0.05-0.15
Intermediate
0.80-1 .10
0.35-0.70
0.25-0.55
0.20-0.45
0.15-0.40
: 0.10-0.35
i
Resistant
1 .00 and up
0.60 and up
0.50 and up
0.40 and up
0.35 and up
0.30 and up
Nitrogen oxides may also cause injury to vegetation by direct contact.
The significant oxides of nitrogen are NO and N02- The major oxide in com-
bustion emissions is NO. However, after residence in the atmosphere, NO is
converted to N02 by photolysis and by photochemical interaction with hydro-
carbons. The effect of N02 on plant life has been studied under controlled
laboratory conditions. Acute injury is characterized by collapse of cells
and subsequent development of necrotic patterns. Chronic injury, caused by
exposure to low concentrations over long periods, is characterized by
chlorotic or other pigmented patterns in leaf tissue. Such injury results
in reduction of growth and reproduction. Only limited data are available to
characterize the effect of NO on plants. Generally, it appears that NO leads
to effects somewhat similar to those observed for N02, but at slightly higher
threshold concentrations. Therefore, for worst case evaluations of the
impact of ambient NOX levels, it is assumed that NOX exists as N02, and that
the NO levels are not depleted by the photochemical reactions which typical-
A
ly occur in urban areas.
Figure 5-5 illustrates the threshold concentrations at which various
degrees of damage result from exposure to N02. Based on the expected con-
centration of NO in the vicinity of the coal-fired industrial plant cluster,
and the assumption it is converted entirely to N02, it appears that acute
leaf damage may be anticipated to occur as a result of short term plume
fumigations, and that chronic effects (including growth and yield reductions)
5-27
-------
1000-r
D_
D-
C\J
O
100- r
o
2 10
o
o
1.0- r
0.1
0.01
-h-
0.1
DAYS
1.0
I
10
100
: -1000
0.1
; -100
THRESHOLD FOR FOLIAR LESIONS
METABOLIC AND GROWTH EFFECTS
4
1.0
10
100
- '10
C\i
o
CD
: -1.0
1000
10,000
DURATION OF EXPOSURE (HOURS)
Figure 5-5. N02 threshold concentrations for
various degrees of plant injury,[31].
may be. noticed over the long term. The extent of the damages would
be localized within a one or two km range from the plant cluster, and would
be expected to occur to those plants most sensitive to N02 injury (e.g.,
cotton, navel orange, spinach, etc.). However, N02 injury to plants from oil
firing is not as likely to occur. Maximum short term ambient concentrations of
NO near the plant cluster are estimated to be about one third that result-
A
ing from coal-firing, or below the threshold levels which induce plant
injury0 (See Figure 5-5.)
5-28
-------
Acute (short term) injury to vegetation by SCU exposure is characterized
by damaged leaf areas which first appear as water soaked spots, and later
appear as bleached white areas or darkened reddish areas. Chronic S02
injury is usually characterized by chlorosis (yellowing) which develops
from lower concentrations over extended periods of time. Either acute or
chronic S02 injury may result in death or reduced yield of the plant if the
extent of the damaged tissue exceeds 5 to 30 percent of the total amount of
foliage.
The impact of the expected S02 concentrations varies with the plant
species. Threshold injury in sensitive plants may be caused by short-term
S02 levels as low as 30 ng/m3,[17]. Table 5-11 summarizes the broad cate-
gories of sensitivity for different plants. Grain, vegetable, pasture, and
forage crops are susceptible to S02 damage for most of the growing season.
These crops may suffer yield reductions in areas where industrial boilers
have been sited together in clusters. However, the damage would be highly
localized, and the extent of the most severe injury would probably result
in only minor yield losses. Figure 5-6 shows that peak S02 concentrations
expected to occur near the clustered network of controlled industrial
plants will probably cause only traces of leaf damage to occur in the
more sensitive plant species. However, certain adverse combinations of
frequent fumigations and boiler sitings could result in crop damage of
significant extent. If ambient levels of S02 are approaching plant damage
thresholds in the vicinity of the industrial boilers, the potential effect
of the type of fuel utilized could be significant. Based on the boiler
tested in the present study, and the dose-response relationships of Figure
5-7, it appears that once ambient S02 levels are equivalent to leaf des-
truction thresholds, coal-firing would result in total leaf destruction
rates significantly higher than that produced by oil firing.
It should be noted that the plant damage thresholds illustrated by
Figure 5-6 apply to conditions of temperature, humidity, soil moisture,
light intensity, nutrient supply, and plant age which cause maximum sus-
ceptibility to injury. The occurrence of such conditions are rare. In
fact, in the unlikely event that all such conditions are met, the dose-
response curves indicate that plant injury could occur without a violation
of the federal air quality standard for the 3 hour or 24 hour concentration
5-29
-------
TABLE 5-11. SENSITIVITY OF COMMON PLANTS TO S09 INJURY,[2]
Vegetation
Sensitive
White pine
Goldenrod
Cottonwood
Virginia creeper
Aster
Gooseberry
Elm
Wild grape
American elm
White ash
Virginia pine
Tulip tree
Intermediate Resistant
Maple Sugar maple
Virginia creeper Phlox
White oak Oak
Elm Maple
Shortleaf pine Shrubby willow
Aster
Linden
Crops
Sensitive
Alfalfa
Barley
Oats
Rye
Wheat
Sweet potato
Soybean
Sweet clover
Cotton Tobacco
Clover
Intermediate Resistant
Irish Potato Corn
Clover , Sorghum
Sweet clover
3.0-
2.5
I
-2.0
o
o
1.5
1.0
0.5
S02 DOSE-INJURY CURVES
FOR SENSITIVE PLANT SPECIES
DAMAGE LIKELY
INJURY OR DAMAGE
POSSIBLE
(THRESHOLD RANGE)
7860
6550
NO
INJURY
5240
3930
2620
1310
e
5.
z
o
o1
23456
DURATION OF EXPOSURE, h
Figure 5-6. S02 Dose-Injury Curves for Sensitive
Plant Species5[i7].
5-30
-------
period of exposure
(hrs.)
concentration of
gas (ppm)
100% LEAF DESTRUCTION
t (C - 2.6) = 3.2
50% LEAF DESTRUCTION
t (C- 1.4) = 2.1
TRACES OF LEAF
DESTRUCTION APPEAR
t (C - .24) = .94
1 2 3
TIME (t) OF FUMIGATION - HOURS
Figure 5-7. Dose-Response curves for Alfalfa exposed to
S02 under conditions of maximum absorption,[is],
of S02. Additional susceptibility may also result from synergistic effects
of sulfur dioxide and other pollutants. Particularly relevant to the urban
environment are combinations of sulfur dioxide and ozone. Moderate to
severe injury of tobacco plants have been observed for four hour exposures
to concentrations of 0.1 ppm (262 ug/m3) S02 in combination with 0.03 ppm
ozone. Because high ozone levels are a frequent problem in the vicinity of
urban areas, susceptibility to plant injury by SO- pollution is probably
greater in those areas where industrial boilers are typically sited. One
of the major concerns associated with fossil fuel utilization is acid pre-
cipitation resulting from wet deposition of suspended sulfur and nitrate
compounds Data show that there has been an intensification of acidity in
the northeastern region of the U.S. since the mid 1950's. Precipitation
in a large portion of the eastern U.S. averages between pH 4.0 and 4.2
annually. Values between pH 2.1 and 3.6 have been measured for individual
storms at distances several hundred miles downwind of industrial centers.
The areas experiencing highest acidity are typically downwind of the areas
5-31
-------
where sulfur emissions are highest ,[25], [31].
Acid rain affects plant life in varying degrees depending on the pH
and the type of plant species. Experiments show that the effects on plants
may include reduction in growth or yield, leaf damage, death, and chlorosis.
Acid rain also has been shown to affect aquatic organisms, and it is be-
lieved that thousands of lakes are now experiencing reductions in fish pop-
ulation due to acidification between pH 5.0 and 6.0,[31] .
The impact of fossil fuel combustion in controlled industrial boilers
boilers on acid precipitation and plant damage is relatively minor. Based
on stack tests as the reference boilers, the resulting levels of sulfates
would be essentially the same whether the controlled boilers are coal
fired or oil fired. In the previous discussion, it was estimated that
3
controlled industrial boilers would account for a level of .6 ug/m sus-
pended sulfate in the central region of the U.S. This level is substantially
below ambient sulfate concentrations associated with areas experiencing
significant acid precipitation. Typical ambient sulfate levels prevalent
in the U.S. are shown in Figure 5-8. However, it should be noted that the
NSPS for utility boilers permit a greater sulfur oxides emission rate
than that rate which was measured from the controlled industrial boiler.
Thus, typical (non-controlled) industrial boilers burning coal or oil and
emitting at rates equivalent or higher than that of the NSPS would cause
suspended sulfate levels an order of magnitude higher than that resulting
from control!ed boilers.
Plants may also sustain injury from elevated levels of trace elements.
As shown previously (Table 5-8), trace element concentrations in vegetation
near clustered industrial boilers would not be expected to exceed levels
observed to be toxic in plants. However, under conditions which would
cause the most adverse 40 year accumulations of trace elements in soils
e-ound the emission sources, it is possible that both molybdenum and cad-
mium could be concentrated in vegetation at levels causing plant injury.
The effects of cadmium toxicity in plants are wilting, chlorosis, necrosis,
and reduction of growth. Substantial declines in yield of the soybean,
wheat and lettuce have been observed when the tissue concentration of cad-
mium in foliar parts of these species was as low as 7, 3 and 11.5 ^g/g
respectively. Molybdenum is considered to be one of the least toxic of
5-32
-------
(A) Urban Levels
(B) Rural Levels
Figure 5-8. Geographical distribution of typical sulfate
levels in the United States ,[2].
.5-33
-------
trace elements. However, it is concentrated heavily by the uptake system
of most plants, and it is estimated it may be present in concentrations up
to 26 jug/g (i.e., 30 times the maximum background level) in the foliar tissue
of plants near an industrial boiler cluster. It is not clear if this Mo
level is destructive to vegetation, but dietary concentrations as low as
5 ,ug/g have been known to cause diarrhea in cows, and Mo levels from
20-100 jug/g in grazing pastures have resulted in death of cows, [32].
Based on tests of the reference industrial boiler, it appears that
emissions from oil firing will result in potentially high cadmium plant burdens
while coal firing is more apt to cause elevated levels of molybdenum. While the
evaluation is based on most adverse potential conditions, it does illustrate
the need to consider fuel use, as well as other site specific issues (e.g.,
magnitude and location of sources, stack heights, background levels of
trace elements), in planning for adequate protection of vegetation and
agriculture near industrial boiler plants.
Effect of Solid Wastes
A major environmental concern involving the use of fossil fuels is
the generation of coal ash and flue gas desulfurization (FGD) sludges. The
quantity of such wastes depends on the proportion of coal utilization and
the amount of S02 removed from stack gases. It has been estimated that by
1985 coal ash will be generated at a rate of 92 x 10 tons/year and FGD
sludges at a rate of 33 x 10° tons/year (dry basis). Landfill is the
common means of disposal for these wastes. By 1980 it is estimated that
0.4 to 0.7 acres of land per MW of boiler capacity will be required for
disposal purposes,[36]. The composition of the wastes will depend on the fuel
source, the boiler design, and the flue gas desulfurization system.
Most FGD processes generate a waste sludge consisting predominantly of
calcium sulfite and sulfate. Various_trace elements are also found in the
FGD sludge. The trace elements originate from reagents used in SO removal,
from process water, from trace elements in the combusted coal or oil, and
from fly ash (noncombusted portion of coal) which is collected by the FGD
scrubber system. Fly ash and bottom ash usually consist of about 80 per-
cent silica, alumina, iron oxide, and lime. The composition of trace ele-
ments found in bottom and fly ash is similar
5-34
-------
Table 5-12 shows the quantities of coal ash and FGD sludge collected
during operation of the reference 10 MW industrial boiler studied in this
project. Coal-firing of this controlled boiler produces approximately
three times more scrubber cake than oil firing produces; this is due to
the higher rate of particulate matter generated by coal combustion and the
subsequent collection of the particulate matter by the FGD scrubber system.
The quantities of bottom ash and fly ash generated by oil burning is
relatively insignificant. A portion of the fly ash generated by coal
burning is collected with the scrubber cake of the FGD system, while most
of the fly ash is recovered by cyclone collectors upstream of the scrubber.
Bottom ash generated by coal firing represents a significant waste disposal
problem, and is generally managed in conjunction with the scrubber cake
wastes.
Based on the test results of scrubber cake produced by the reference
boiler, it appears that coal firing produces a greater enrichment of trace
elements in the scrubber cake. Table 5-13 shows that only four elements
exhibited higher concentrations in the scrubber cake produced by oil firing.
However, either scrubber cake contains sufficient amounts of heavy metals
and toxic substance to pose difficult waste disposal problems.
TABLE 5-12. GENERATION RATE OF SOLID WASTE FROM
10 MW CONTROLLED INDUSTRIAL BOILER
Waste
Bottom ash
Fly ash
Scrubber cake
Rate of Production,
Coal Firing
80
240a
1100
kg/hr.
Oil Firing
1
2a
400
This is amount of fly ash recovered by cyclone collector.
Approximately 25% of the fly ash is recovered in scrubber
and removed with scrubber cake.
5-35
-------
TABLE 5-13. COMPOSITION OF F6D SCRUBBER CAKE
Element
Ca
Mg
Sb
As
B
Cd
Cr
Co
Cu
Fe
Pb
Mn
Mo
Ni
V
Zn
Se
Sr
Al
Zr
Concentration
Coal Firing
60715
1458
315
532
857
13
141
424
112
47241
297
51
1117
114
195
282
256
642
45310
106
» MQ/9
Oil Firing
192030
1776
122
135
2405
7
33
231
35
3867
104
15
666
148
161
19
128
163
4625
39
Relative
Concentrations,
Coal /Oil
.3
.8
2.6
3.9
.4
1.9
4.3
1.8
3.2
12.2
2.9
3.4
1.7
.8
1.2
14.9
2.0
3.9
9.8
2.7
F6D scrubber wastes and coal ash are usually disposed in impound-
ment ponds or landfills. The major concern in either disposal approach
is the release of trace elements to ecosystems in localized areas sur-
rounding the disposal sites. Lateral and upward movement of trace elements
through the soil to plant rooting zones may be possible, and contamination
of ground and surface waters may occur. Additional adverse consequences
include the diversion of land from other uses, and aesthetic degradation
at the disposal site.
5-36
-------
Because of the limited experience concerning land disposal of wastes,
and the long time lags preceding future potential adverse impacts, there
is significant uncertainty regarding the level of restrictiveness necessary
to assure the environmental adequacy of various land disposal methods.
Because of such uncertainty, it seems likely that stringent waste disposal
regulations will be proposed to stabilize waste sludges, preventing their
migration in the terrestrial environment and the movement of leachate to
underground water sources.
Disposal of FGD sludges and coal ash is already subject to regulations
at the state level. Recent federal legislation (the Resource Conservation
and Recovery Act) now requires that criteria be developed to classify
wastes and suitable disposal management techniques. Under the proposed
criteria, due in fall of 1978, it is plausible that FGD sludges and coal
ash may be classified as hazardous waste, and that disposal of these wastes
will be restricted by the stringent requirements now being proposed for
hazardous waste management facilities. Typically, these requirements would
restrict the land disposal of hazardous wastes to "secure landfills" designed
to provide protection for all-time of the quality of ground and surface
waters. By definition, the secure landfill would prevent significant adverse
impact to certain environmental sectors (i.e., public health and ecology).
Unfortunately, the secure landfill, is, by definition, an ideal design which
cannot be attained except at very great cost. There is, therefore, a need
to define reasonably attainable land disposal designs which offer a high
level of environmental protection.
Various recent efforts have been conducted to define appropriate land-
fill criteria. In one pertinent study,[16] the effectiveness of three
scenario landfill designs for the disposal of FGD scrubber cake were
evaluated. The scrubber cake considered is that generated by the Double
Alkali FGD system utilized at the reference industrial boiler of this
study. Migration of leachate to the groundwater and the loading rate of
dissolved solids into the groundwater were estimated by considering the
permeability of the landfill layers and the solubility of solids as deter-
mined from laboratory tests. Table 5-14 summarizes the analysis of the
three landfill cases. As indicated, permeability of the soils and the
scrubber waste is the primary factor in initiating leachate migration.
5-37
-------
TABLE 5-14. LEACHING RATES FOR THREE LANDFILL DESIGNS
Case
I
II
III
LI
(feet)
18
18
20
Lj
(feet)
2
2
1
L
(feet)
10
10
10
R
(cm/sec)
s
10
5
10
5
10
K
(cm/sec)
6
10
_6
10
9
10
K3
(cm/sec)
10
_8
10
it
10
K ff
(cm/sec)
_6
7.7 x 10
_a
1.5 x 10
_8
3.0 x 10
t
(years)
1
200
100
t
(years)
20
6000
3000
(Ib/fl /yr)
1.04
0.0033
0.0066
Liner or
Compacted
Filter Cake
i Double
Alkali
Filter Cake
V
^^;y.}?:'(::^::^ L2
y/'3'//^-//-s?//i://^//^/£z//2
\ Soil
/ '
1
?fr/A *
\ j
(
Ground
Water
Table
1^ = Depth of uncompacted filter cake (feet)
L£ = Depth of compacted filter cake or liner (Case III) (feet)
L, = Depth of soil (feet) -
KI( K2, K3 = Coefficients of permeability of layers I, 2, and 3, respectively
(cm/sec)
Keff Effective permeability of overall filter cake plus soil layers (cm/sec)
t^ = Time for migration of leachate to groundwater table (years)
t^ = Time for washout of major dissolved solids from filter cake (years)
Qg = Loading rate of total dissolved solids to groundwater (Ib/ft2/yr)
5-38
-------
In the first case, all net precipitation becomes leachate, and the time to
reach groundwater is about one year while the time to wash out the major
portion of the soluble solids is about 20 years. The overall washout rate
of soluble solids during the 20 year period is calculated to be 1 Ib/ft2/yr.
Contamination of ground water sources over significant landfill areas at
this washout rate is clearly unacceptable. In the second and third cases,
200 and 100 years elapse before leachate reaches groundwater, and leaching
of soluble substances occurs at the low loading rate of 003 x 10"3 Ib/ft2/yr
and 007 x 10" Ib/ft2/yr, respectively. The time for total washout of all
soluble solids would be 3000 and 6000 years, respectively. The extent of
impact of such a leaching rate would depend on the size of the landfill
and the flow of the underground aquifer. For example, for case II,
a 1 acre landfill over a small underground water source flowing at one
million gallons per year would cause an increase of 2 ppm in the dissolved
solids content of the underground water. Most of the 2 ppm increase woul"1
be composed of lime and sodium sulfate and sulfite salts. As indicated by
Table 5-13, trace elements would comprise a small fraction of the incre-
mental increase, and considering the low solubility of the trace elements,
their concentration in the underground water would be at least three orders
of magnitude less than the lime, sulfate, and sulfite concentrations, and
well below the standard for potable water (see Table 5-9). The rate >f
leaching can be minimized still further by mixing bentonite with a layer
of soil to provide a layer over the filter cake after it has been landfilled
to the desired level. The bentonite soil mixture achieves a low permeability
of 10"9 cm/sec. By contrast, the permeability of silty clay and permeable
soils is about 10"8 cm/sec, and 10~4 cm/sec, respectively. The permeability
of the double alkali scrubber cake is 10" cm/sec, whereas it is about
10 cm/sec for lime/limestone type scrubber sludges.
Estimated leaching rates can be confirmed by tracking the migration
of leachate in the experimental landfill at the reference industrial boiler
site. Analyses of this landfill, which contains no seal or barrier other
than the native clay silt (permeability of 10" cm/sec), shows that no
leachate has migrated as far as six inches below the disposal layer after
the first year of operation. The results and analyses indicate that land-
fills of untreated scrubber cake can be constructed such that significant
adverse impacts will not occur. Moreover, it is conceivable that a completed
5-39
-------
landfill can be reclaimed for use as a park or farmland, provided a
sufficient soil cover is applied and care is exercised not to disrupt the
stabilized waste or to permit its migration entry into the terrestrial
envi ronment.
The impact of landfill ing scrubber cake produced by coal firing is
clearly greater than the impact caused by oil firing due to higher concen-
trations of elements in the cake and larger quantities of cake produced.
However, analysis shows that if proper landfill design is employed, utilizing
impervious soils, the impact of leaching can be minimized to an insignificant
measure whether the scrubber cake orginates from a coal-fired or oil-fired
boiler. It is expected that such designs will become mandatory under the
rules established by the authority of the Resource Conservation and Recovery
Act.
COMPARATIVE SOCIETAL IMPACT
A major societal impact resulting from air pollution and solid waste
is aesthetic damage. Emissions of particulate matter and sulfur oxides
cause soiling of materials, visibility reduction, and corrosion damage.
Solid waste disposal sites are unattractive and generally result in
diversion of land use and depreciation of land values.
Effect of Air Emissions
The primary source of aethestic damage is suspended particulate matter.
One obvious esthetic effect of suspended particulates is soiling of property
(e.g., homes, automobiles). Soiling results in increased frequency of
cleaning and associated economic cost. Particles also cause corrosion of
metals. Hygroscopic particles such as sulfate and chloride salts and
sulfuric acid aerosol are responsible for accelerating corrosion of metals
exposed to the atmosphere. Reliable estimates of the cost of material
damage due to pollution are difficult to develop because adequate damage
functions are generally not available. However, some preliminary studies
have developed functions which may permit crude indications of the poten-
tial impact of increased air pollution. Most of these studies have been
concerned with the corrosive aspects of suspended particulates.
5-40
-------
A regression analysis[33] of the corrosion rate of low carbon steel
panels and ambient levels of S02 at various sites in the Chicago area
indicated high correlation between these variables. Similar high correla-
tion was found between sulfate levels and corrosion rates. The regression
equation fitting the data was given as:
y = .021 S + 9.5
where y = annual corrosion weight loss (g/100 g panel), S = average SCL
3
concentration, yg/m .
Other studies confirm the above findings. Zinc specimens were formed
to corrode more rapidly in industrial areas where total suspended parti-
culate levels were highest. Figure 5-9 illustrates the atmosphere of
cities with greater concentration of particulates and sulfur oxides -
produces the greater rates of corrosion.
NEW YORK CITY
(INDUSTRIAL)
KEARNY, N.J.
(INDUSTRIAL)
234
EXPOSURE, YEARS
Figure 5-9. Rate of corrosion caused by various levels of
TSP and S02 in the Atmosphere ,[20].
5-41
-------
The relationships developed from the studies above may be used to
evaluate in a gross sense the potential impact of industrial boiler
emissions on the corrosive properties of the atmosphere. The estimated
annual concentration of S02 in the vicinity of a cluster of industrial
coal-fired boilers is 13 yg/m3. (See Table 5-2.) In urban areas where the
annual S02 levels are 80 jug/m3 and TSP is 75 yg/m3 (the primary standards), the
boiler cluster could be expected to increase the corrosion rate of steel and zinc
by about 2.7% and 12% respectively. This impact would be localized within
a one or two km range of the industrial cluster, and would be reduced to one
forth the effect 5 km away. The expected impact when the industrial boil-
ers are fired with oil is reduced somewhat: the predicted maximum increases
in corrosion rates are 1.5% for steel and 8.5% for zinc. It should be
noted that the extent of this impact is minor compared to that which occurs
in the vicinity of typical non-controlled industrial boilers.
Soiling of structures is particularly noticeable in atmospheres bearing
high levels of particulates and sulfur oxides. Particles may soil painted
surfaces and cause staining and pitting. Soiling of textiles (clothing,
curtains, upholstery) also contributes to direct costs associated with
additional cleaning and replacement of damaged property. A soiling cost
study[34] of the Washington, D0C. area has determined the cost damage function
of residential soiling. The relation was derived by correlating time in-
tervals between cleaning and maintenance with levels of suspended particu-
lates in several areas within the Washington, D0C0 area. By translating the
frequency of cleaning and maintenance into cost, the following relationship
was developed:
y = (1.85 x ) -42
where y = cost per capita of soiling damage, x = particulate concentration,
This model may be used to estimate roughly the potential impact of
controlled boiler emissions on residential soiling damages. The in-
crease in annual TSP levels caused by a cluster of controlled industrial
coal fired boilers was estimated to be 7 ng/m3. This represents an annual
cost increase of $13 per person due to additional cleaning and maintenance'.
In an area currently experiencing particulate levels equivalent to the
5-42
-------
federal air quality standard, annual cleaning costs associated with air
pollution are $96 per person. Hence, it seems clear that particulate
emissions from a controlled industrial plant complex may cause sig-
nificant soiling damage, however, these damages are limited to a relatively
small area within 1 or 2 km of the industrial complex. According to the
emissions test data, the damage occurring in the localized "hotspot" of
air pollution is greater (40%) when the controlled boilers are coal-
fired as opposed to oil-fired. However, controlled firing of the boilers,
whether with coal or oil, results in significantly less soiling damage
than would occur from boilers emitting at typical (uncontrolled) levels.
One of the most obvious aesthetic effects of air pollution is decreased
visibility. Visibility reduction occurs as a result of absorption and
scattering of light by suspended particles. Visibility is affected most
dramatically by a narrow segment of the suspended particle size range, from
about 0.1 to 1.0 micron. Visual range through suspended particulate
matter is given as, [20]:
i _ 750
L C
3
where L = visual range in miles, C = concentration of particulates, yg/m .
3
For typical urban concentrations, such as 100 yg/m , the visibility is
3
7.5 miles, and for rural concentrations such as 30 yg/m , the visibility
would be 25 miles.
The visibility model may be applied to estimate the impact of the
cluster of industrial boilers on visibility. Figure 5-10 illustrates the
variation in particulate concentration downwind of a coal-fired boiler
cluster under plume fumigation conditions. The concentration profile is
constructed by superimposing the effect of a line of five single plants
which are spaced 2 km apart. Because the concentration is non-uniform,
application of the visibility model is somewhat awkward. In the vicinity
immediately downwind of the plant cluster, visibility would be reduced to
about one half an assumed background level of 7.5 miles. However, at a
distance 10 miles from the plant cluster, the concentration diminishes to
q
6yg/m , and visibility would not be impaired significantly. The impact on
visibility is not significantly different when the boilers are oil fired.
It should be noted that the plume fumigation conditions are short lived,
5-43
-------
Z
o
<
DC
I-
z
UJ
O
O °
J ^
UJ *1
> a
UJ
O
Z
o
oc
o
120T
100-
COAL FIRING
40-
20-
12
16
20
24
28
32
36
40
DISTANCE FROM SOURCES, Km
Figure 5-10. Ambient ground level concentration of suspended
particulates downwind of cluster of oil or coal-
fired industrial boilers.
and that the concentration downwind diminishes dramatically after reaching
a peak ground level concentration about 1 km from the end of the cluster.
It is also noted that the vertical plume spread is limited, therefore,
scattering and absorption of light do not occur throughout the atmosphere,
as assumed by the visibility model. Hence, the actual effect on visibility
is expected to be appreciably less than a 3.75 mile reduction in visual
range, and this effect would be highly localized. Under more typical
meteorological conditions, producing peak downwind levels of 29
suspended particulate, the visibility reductions occurring from an urban-
sited industrial cluster would not be noticeable.
The impact of visibility reductions depend greatly on the characteris-
tics of the existing environment. If an industrial boiler cluster is to be
sited in a scenic vista where visibility exceed 50 miles, the impact of
o
atmospheric concentrations which exceed 100 ug/m could be severe, although
highly localized and short-lived. The impact would be essentially the same
whether the controlled boilers were burning coal or oil.
5-44
-------
Effect of Solid Waste
The major difference between impacts associated with disposal of scrubber
cake from oil firing and coal firing concerns the overall land requirements.
Because coal firing produces three times more solid waste than oil burning,
diversion of land use for landfills will be more extensive for coal-fired
plants. Assuming landfill of waste to a depth of 20 feet, disposal of the
scrubber cake from the controlled 10 MW coal-fired boiler will require
approximately an acre of land area every 2 years while disposal of the
scrubber cake from oil firing will require one acre every 6 years. It may
be difficult to secure such land areas in the vicinity of many boiler sites,
and the threat of aesthetic degredation and depreciation of land values is
a major concern wherever disposal sites are chosen.
COMPARATIVE ECONOMIC IMPACT
The direct economic impacts associated with residuals of fuel combus-
tion involve the costs of damages (or benefits) sustained when the
residuals enter the environment. Second order economic impacts
associated with the residuals involve the alterations that occur
in employment, the tax base, energy prices, income, and land values
due to the damages (or benefits) resulting from combustion residuals.
The quantification of direct economic impacts involves the difficult task
of ascribing economic values to environmental changes. Quantification
of second order economic effects are yet more difficult because of gaps
in knowledge which make it impossible to determine the complex relation-
ships between cost and the numerous socio-economic factors involved.
A number of ongoing energy related studies are attempting to
develop sophisticated economic models which will predict the cost of
environmental damages,[2],[5],[41]. The models address the cost of visi-
bility reduction, health effects (morbidity and mortality), and certain
second order effects. Utilization of the models requires substantial
input data involving regional demography and emission source distributions.
The models require further refinement and are currently under continuing
5-45
-------
development. The data base or scope of the present program did not permit
the adaption and utilization of such models.
The comparative extent of the economic impacts resulting from residuals
of oil-fired and coal-fired boilers will be proportional to the extent of the
comparative environmental damages identified previously. The analyses have
shown that the differential impact of emissions from coal firing and oil
firing is generally insignificant with the possible exception of some
differences which occur in a limited localized area near clusters of boilers.
The localized mortality rate for coal firing is about 50% greater than
from oil firing, localized soiling damages may be 40% greater from
coal firing, localized crop damage may be significantly greater, and
land requirements for waste disposal are three times greater for coal
firing. The economic cost of these incremental differences will be
significant in the limited and affected areas. Medical costs and loss
of productivity will be experienced to a greater extent in the area
of coal-firing, annual cost of cleanup and maintenance for soiling
damages will be about $4 more per person in the most affected area,
revenue for crop crop sales will be reduced somewhat, and esthetic
blight in the area of landfills will diminish the value of land and
activities nearby. The extent of these economic effects is substan-
tially less than that which would be expected from a cluster of
either oil firing or coal firing of uncontrolled industrial boilers.
Because the significant differences in direct economic impacts occurring
from controlled oil-fired and coal-fired boiler emissions are limited
to a relatively small area near the source, the total costs of the
incremental environmental damages are apt to be insignificant on a
regional basis. Consequently, significant incremental second order
economic impacts, such as changes in hospital employment, alteration of
tax bases, or changes in income would be unnoticeable between controlled
oil and coal-fired industrial boilers.
IMPACT ON ENERGY
The comparative effect'of environmental residuals from controlled
coal combustion versus oil combustion will influence potential restrictions
5-46
-------
on the production and use of coal or oil. If additional controls are re-
quired to assure the environmental acceptability of coal or oil firing in
industrial boilers, these requirements will affect the economics of coal
utilization and the shaping of energy policy. If it is shown that coal
and oil-fired industrial boilers can be controlled adequately at reasonable
cost, then policies may be developed to support the use of either of these
fossil fuels. Presumably, the use of coal is desirable, given that the
associated degree of environmental insult is no worse than that of alter-
native fuels.
The results of this study tend to support the national energy plan
for the intensified utilization of coal. It was shown that both coal and
oil-fired industrial boilers may be controlled with reasonably available
technology and siting requirements to meet existing environmental standards,
and more importantly, that the difference in impact between oil and coal
firing in well-controlled boilers is relatively insignificant with the
possible exception of effects resulting from a threefold difference in the
amount of solid waste generated, as well as potential differences in NO
A
emissions levels. The reference boiler of this study was not controlled
for NO emissions, and the tests showed that coal firing produced two times
A
more NO emissions than oil firing. A twofold difference in the uncontrolled
A
NO emissions levels could translate to potentially significant differences
A
in ambient levels of photochemical air pollution, and the difference in solid
waste generation rates from controlled boilers would lead to greater
impacts on land use where waste disposal sites are selected. If additional
controls are employed for coal burning plants to mitigate these differences,
the cost of coal utilization will increase, and energy policy will be im-
pacted. Whether or not increased coal utilization will be economically
attractive will depend on the extent of the incremental control costs for
NO and solid waste disposal relative to the total cost of coal and oil
A
utilization in boilers.
5-47
-------
Table 5-15 illustrates the component costs for operation of a large
oil or coal burning boiler. The cost of NOY emissions control is relatively
/\
insignificant compared to SO and particulate control. The annualized cost
/\
of an FGD and particulate control system may increase the cost of a large
boiler by 20 to 30%; the relative increase is still greater for smaller
boilers. The annualized cost of FGD and particulate control systems is
significantly greater for coal-fired boilers than oil-fired boilers because
greater quantities of solid waste (scrubber cake) are generated during
TABLE 5-15. ANNUAL COST OF OPERATING UTILITY BOILERS,[38],[39],[40]
Cost Category
Capital cost of plant
Fuel
Fuel Storage
Flue Gas Desulfurization (wet
lime/limestone scrubber)
Solid Waste Disposal
NO control (low excess air
Tiring and staged combustion)
Operation and Maintenance
TOTAL
Cost in Mills/Kwhr. !
Coal
4.05
3.14
.08
1.6
1.4
.03
.39
10.69
Oil
3.38
4.04
.04
1.6
.4
.03
.21
9.70
5-48
-------
coal firing. Because landfill waste disposal methods for scrubber cake
appear to be environmentally acceptable, additional technology (such as
regenerative FGD systems) or special mitigation measures (such as special
landfill reclamation techniques) may not be required for either coal or oil
combustion. Whatever the comparative extent to which additional controls
may be required for oil versus coal-fired boilers, the comparative cost of
such controls will probably be relatively minor compared to the overall
operating cost of a boiler and other factors affecting the overall costs.
The most significant single factor affecting the operating costs of the
boiler is the cost of fuel. Any comparison of costs between coal and oil
utilization is difficult because of the financial uncertainities associated
with future fuel prices. At present, the total generation cost for a coal
plant are roughly competitive with those of an oil-fired plant, but may be
significantly different if fuel costs change markedly.
Oil prices are determined by a complex set of political and economic
considerations. Whether the relative coal prices remain the same, and
whether capital will be available to exploit the coal reserves, depends on
the existence of a long term market for coal. Unclear and changeable
issues such as air pollution regulations, levels of oil imports, natural
gas prices, and the cost of capital, create uncertainties for the future
coal market.
While the differential impact between combustion in well-controlled
coal-fired and oil-fired industrial boilers may pose a relatively minor
issue with respect to energy production or utilization, the absolute im-
pacts of fossil fuel combustion may produce serious concerns in the long
term. Although the predicted pollutant loadings may meet environmental
standards, it is not entirely clear whether the increasing use of fossil
fuels may be continued at the forecasted levels of control technology
without potential long term environmental damages. If it is found that
long term effects of pollution (e.g., trace metals accumulation, lake
acidity, land use) are unacceptable, then more stringent environmental
regulations can be expected, and it is clear that energy use may be affected.
Energy cost will increase with increasing control requirements, possibly
to the level where significant social impacts may occur, and other fuel
types may become more feasible alternatives.
5-49
-------
In conclusion, it appears that the comparative analyses of
this study support energy proposals to intensify coal utilization. The com-
bustion of either coal or oil in controlled industrial boilers produces.
similar environmental effects and the cost associated with mitigating any
significant differences in environmental insult are relatively minimal.
In supporting the policy for increased coal utilization, the comparative
impact of coal versus oil firing carries implications for many impact sectors
associated with the overall coal utilization policy. The impacts are
observed among all aspects of energy supply and use, including mining, fuel
production, transport, and fuel end use. The affected impact sectors of
the social and economic environment include employee demand at develop-
ment areas, services provided by affected communities, balance of revenues,
cost of living, demography, and quality of life. Major impact sectors
affected by energy policies in the physical environment include land use by
mining operations, water resources and their quality, and ecological
systems. The multi-faceted assessment of increased coal utilization poli-
cies in terms of the overall energy systems trajectories (e.g., mining-
production, etc.) is being conducted in various ongoing studies funded by
the federal government. The EPA is currently implementing the CCEA program
to coordinate many of these studies into an overall environmental assess-
ment structure. The present study comprises one element of the CCEA program,
and focuses specifically on fuel end use by assessing the comparative impact
of environmental residuals resulting between oil firing and coal firing in
controlled industrial boilers.
SUMMARY
Major general conclusions evolving from the environmental analysis are
as follows:
The difference in environmental insult expected to result between
coal and oil combustion emissions from a single controlled
10MVJ industrial boiler is insignificant. This is because: 1)
there are only slight differences in the emissions levels of the
pollutants, or 2) the absolute impact of either fuel use is insig-
nificant.
a The environmental impacts of emissions from a cluster of con-
trolled 10 MW industrial boilers are potentially significant.
The impacts include health effects, material damages, and eco-
logical effects from high levels of SCL, NO and suspended partic-
t- /\
5-50
-------
ulate matter; health effects and ecological damage due to trace
metal accumulation in soils and plants; and esthetic degradation
from visibility reduction and waste disposal sites.
The risk of environmental damage from emissions of controlled
industrial boilers, whether oil or coal-fired, is considerably less
than the risk posed by emissions from uncontrolled industrial
boilers. It should be noted that this finding is based on an ex-
ceptional facility. The reference facility is very well run and
maintained, and emissions are low.
The environmental acceptability of a cluster of controlled industrial
boiler emissions is more dependent on site specific factors
(e.g., background pollution levels, location and number
of other sources) than type of fuel utilized. Careful control of
the site specific factors can avert potential environmental damages
and generally compensate for any differential effects arising be-
tween the use of coal or oil.
t With the possible exception of ambient levels of NO, the risk of
violating the NAAQS due to operation of clusters of controlled
industrial boilers is essentially the same whether the fuel combusted
is coal or oil. Based on tests of the reference 10 MW boiler (which
was not controlled for NO emissions), localized NO concentrations
produced by coal-firing are estimated to be twice tne level of that
resulting from oil-firing, and greater than the levels permitted by
the NAAQS for 24 hour and one year averaging periods.
Short term (3 hour and 24 hour averaging times) maximum ambient
concentrations present the most significant air pollution problem
resulting from operation of controlled industrial boilers.
Restrictions imposed by the NAAQS for short term ambient levels
would be most constraining to boiler operation in areas where air
quality is already only marginally acceptable. Expected long term
concentrations arising from boiler emissions would not appear to
pose a risk for violation of the NAAQS.
Coal firing appears to produce a greater enrichment of trace elements
in the flue gas desulfurization cake than oil firing produces. How-
ever, the scrubber cake resulting from either coal or oil firing
contains sufficient amounts of heavy metals and toxic substances to
pose difficult waste disposal problems.
The above conclusions are supported by the data summary of Table 5-16 which
tabulates estimates of the of the comparative potential impacts resulting
from oil firing and coal firing of a clustered configuration of controlled
industrial boilers. The impact categories considered include public
health, ecology, societal impact, economic impact, and energy. The specific
findings with respect to the various impact categories are summarized
briefly below.
5-51
-------
TABLE 5-16 ESTIMATED ENVIRONMENTAL IMPACTS RESULTING FROM OIL FIRING AND COAL FIRING
OF A CLUSTER OF CONTROLLED INDUSTRIAL BOILERS
Analysis Tool
Ixtent or
Coal Firing
OilFiring
Comparative Assessment of Impacts
en
i
en
ro
Publ it Heal til
Mortality
Pub I 1L Heal th
MorLidi ty
Public Health -
effects from
plant takeup of
trace elements.
Public Health -
effects from trace
elements in runoff
waters.
Vegetation (crops)
lundy/Grahn Sulfate ModelJ
(regional effects3)
Lundy/Grahn S02 & TSP Model
fitted to Lave & Seskin data.
EPA Health Effects Estima-
tion Model 11
40 year deposition of atmos-
pheric trace element loadings
and plant concentration
ratios.3
Application of average
sediment burden rates for
representative runoff per
unit watershed to cumula-
tive soil deposits of metals
originating from the
joiler emissions.
Empirical data from NOX
laboratory studies'9
Jupirical data from SO,,
Laboratory Studjesl8
'valuation of acid rain
'rom SO^ washout.
[50 deaths/10 persons/yr.
Mn Central U. s.
550 deaths/106persons/yr.
in localized area near
bofler cluster.
5% increase in incidence of
chronic respiratory.disease
at threshold level .
Produces 30 times increase in
endogenous plant concentra-
tions for Mo. Incremental
burdens of other elements in
Same as coal-firing.
;370 deaths/106 persons/yr.
[in local ized area near
fcoiTer cluster.
Same as coal firing.
Produces lOx increase in
endogenous plant levels
for Cd and 1.5 x for Mo.
Incremental burdens of other
plant tissue are from 1/2 to (elements in plant tissue are
1/230 the typical plant
levels.
j from 1/10 to 1/2300 the
typical plant levels.
Se and Mo estimated to
exceed background levels for
metals in runoff waters.
However, levels of all ele-
ments are three to seven
orders of magnitude less than j
drinking water standards.
Levels of all elements are
three to seven orders of
magnitude less than drink-
ing water standards.
Localized acute leaf damage (Maximum short term concen-
may occur during short term Itrations of NOX expected to
plume fumigations. Localized Ibe below threshold level
growth and yield reductions
may be expected over the long
term.
Potential for localized plant
damage is remote except in
area where S02 levels already
approach plant damage tnresh-
hold (typical in areas, where
NAAQS are violated).
Insignificant effect on
plants due to relatively
insignificant levels of
suspended sulfates pre-
dicted from controlled
boilers
for plant damage.
Same as coal , although
slightly more remote chance
of leaf damage.
Same as coal firing.
No difference
Localized mortality rate from coal-
firing is about 505! greater than
from oil firing.
No difference
Both oil firing and coal firing
could produce elevated levels of a
trace element in plant tissue
approaching the injurious level to
man. Coal produces this increase
for Mo and oil produces it for Cd.
The effect from other trace ele-
ment burdens is believed to be
insignificant.
Concentration of metals in runoff
waters from oil firing expected to
be slightly less than that occur-
ring from coal firing. Hazard to
human health in either case is
remote.
Difference in localized crop
damage could be significant,
but isolated to about a range
of 1 to 3 km from the boiler
cluster.
Minor difference.
Ho difference.
-------
TABLE 5-16. (Continued)
Impact Category
Andlys i b Tuul
Extent of Impact.
Coal Firing
Oil Firintj
Comparative Assessment of Impacts
en
i
en
CO
Materials
Property
Visibility
Public Health
Drinking water,
crops
Land use
Compdrison of expected
i trace element concentrations
| In plants with acceptable
!levels.
Corrosion effects.
i Regression equation from ex-
perimental data33 using
SOj as determinant, and
i experimental data for
corrosion of zinc in TSP
laden atmosphere.
Soiling cost damage
function derived in
Washington D.C.
Reduction of visibility
based on relationships
determined from ambient
measurements. 20
Calculation of leaching
rates based on perme-
ability data and labora-
tory analyses of scrubber
cake.
I
[Calculation of leaching
I rates based on perme-
jability data and labora-
Uory analyses of scrubber
cake.
Calculations of landfill
acerage requirements based
on 20 ft solid waste layer.
Insignifii ant effect on
plants. Possible exception
would be localized plant
damage due to elevated levels
of Mo in plant tissue.
Localized increase in corro-
sion rate of steel and zinc
by 2.71 and 12% respectively
(in areas marginally in
compliance with NAAQS).
Annual cost of $13
per person.
Maximum potential visibility
reduction of 4 miles where
background visibility is
typically urban at 7.5 miles.
Effect is extremely
localized.
Insignificant impact when
proper landfill design
employed.
Insignificant impact when
proper landfill design
employed.
1/4 acre/year
otential reduction in
property value near
landfill.
Insigni ficant effect uit
plants wi th possible ex-
ception of localized plant
damage due to high Cd levels.
Localized increase in corro
sion rate of steel and zinc
by 1.5;-, and 8.5% respectively
(in areas marginally in
compliance with NAAQS).
Annual of $9
per person.
Same as coal-firing.
Same as coal firing.
Same as coal firing.
1/12 acre/yr.
otential reduction in
roperty value near
andfill.
Minor difference.
Slightly greater corrosion
damage expected from coal firing,
but difference is localized to
relatively small area near boiler
cluster
Localized soiling damages are
40i greater from coal firing.
No difference.
No difference.
No difference.
Coal firing requires three
times more land use for waste
disposal.
a. This application of the Lundy/Grahn model pertains to effects from suspended sulfate. The formation of airborne sulfates is a long
range and regionwide problem and is treated by considering emissions levels from industrial boilers throughout the region.
b. The incidence of disease would increase only in those areas where the threshold level of 10/jg/m3 sulfate is exceeded regularly.
c. The environmental impact of wastewater from the boiler operation was presumed insignificant. The wastewater is delivered to the
municipal sewage treatment facility.
-------
Health Effects
Based on the Lundy/Grahn Model for health effects associated with
suspended sulfate levels, regional emissions levels from
controlled oil or coal-fired industrial boilers would not be ex-
pected to cause a significant impact on regional health. Emissions
from uncontrolled boilers would result in substantially greater
levels of regional suspended sulfate levels, and the associated
health effects would be an order of magnitude greater.
Emissions from clusters of controlled industrial boilers are
expected to cause significant adverse health effects in a localiz-
ed area near the plant cluster. Oil firing would be expected to
result in localized health effects about one third less severe
than those resulting from coal-firing. The increase in mortality
attributable to either well-controlled coal or oil-firing is appre-
ciably less than that associated with uncontrolled industrial
boilers emitting higher levels of particulates and SO
/\
The impact of solid waste generation on health is essentially the
same for controlled coal firing and oil firing, provided suit-
able land disposal techniques are employed to assure minimal leach-
ing rates and migration of trace elements to groundwater and the
terrestrial environment.
Addition of cadmium to a localized environment in the quantities
produced by clustered controlled industrial boilers jnay cause
levels of cadmium concentrations in plants approaching levels in-
injurious to man. Because cigarettes contain significant cadmium
levels, smokers are more apt to achieve thresholds of observable
symptoms for cadmium exposure when consuming additional cadmium via
the food chain.
e The concentration of metals in runoff waters due to controlled
oil-firing is predicted to be slightly less than that occurring
from controlled coal firing; in either case, hazard to human
health by drinking water is remote
Trace element emissions from clusters of controlled industrial
boilers may significantly increase local background levels in drink-
ing water, plant tissue, soil, and the atmosphere; however, the ex-
pected increases in the levels of such elements are generally
several orders of magnitude less than allowable exposure levels.
Oil -firing is estimated to cause cadmium burdens in plants approach-
ing levels injurious to man, and coal firing may produce plant
concentrations of molybdenum which are injurious to cattle.
Ecology--
The potential for crop damage from either controlled coal
firing or oil firing depends greatly on ambient levels of NO , S0?,
or trace element soil concentrations. If such levels are presently
high, localized plant damage would be expected to occur within a 1
5-54
-------
to 2 km range from a controlled boiler cluster. Leaf destru-
tion from SO, exposure would be expected to be slightly more severe
in the vicinfty of a cluster of controlled boilers which are
coal-fired as opposed to oil-fired. For boilers uncontrolled for
NO emissions, plant damage would be expected to be significantly
griater in the vicinity of the coal-fired cluster, owing to higher
levels of ambient NO produced. The likelihood of damage occurring
in plants due to emissions of trace elements from either
controlled oil or coal firing is remote, with the possible ex-
ception of injury due to elevated levels of molybdenum and cadmium
in plant tissue resulting from coal firing and oil firing,
respectively.
9 The effect of emissions from industrial boilers on trace element
burdens in plants is greater via soil uptake than by foliar inter-
ception. This is because soil concentrations are the result of
accumulative long term exposure to boiler emissions whereas foliar
exposure is determined by the immediate deposition rate of emissions
on the plant surface and the lifetime of the leaf.
9 The impact of fossil fuel combustion in controlled oil or coal-
fired boilers on plant damage via acid precipitation would be rela-
tively insignificant. The levels of suspended sulfate (the origin
of acid rain) would be essentially the same whether the
led boilers are coal or oil-fired.
e Measurement and analyses of leaching rates at experimental waste
disposal sites indicate that landfills of untreated flue gas desul-
furization system scrubber cake can be constructed such that signi-
ficant adverse impacts will not occur.
Societal--
The impact of boiler emissions on corrosion in the local area near
a cluster of controlled industrial boilers will be significant.
The corrosion rate will be slightly greater when the boilers are
coal-fired. However, the extent of this overall impact (oil or coal)
is minor compared to that which occurs when industrial boilers are
uncontrolled.
The increase in annual TSP and soiling damages in the vicinity of
a cluster of controlled industrial boilers results in additi-
tional cleaning and maintenance costs about 10 to 15% greater than
that already experienced in a typical urban area. The cleaning
costs may be slightly greater when the boilers are coal-fired.
Emissions of particulate matter from controlled industrial
boilers will result in visibility reduction. This aesthetic
degradation will occur in a localized area near the boiler cluster,
and occurs to essentially the same extent whether the boilers are
oil or coal-fired.
Total land disposal requirements for scrubber cake waste generated
5-55
-------
by controlled coal firing are three times greater than those
for for controlled oil firing. Waste disposal of the scrubber
wastes may result in significant depreciation of property value
and aesthetic degredation in the area of the disposal site. These
impacts would be more severe if boilers use coal rather than oil.
Energy--
At the present time, the comparative assessment of the effects of
emissions from controlled oil and coal-fired industrial boilers
tends to support the national energy plan for intensified utilization
of coal. The fuel choice of oil or coal is a relatively minor
issue concerning the environmental acceptibility of controlled
industrial boilers; other site specific and plant design factors
exert a greater effect on environmental damages. While it was
shown that fuel choice caused significant differences in impacts
to occur when the boiler is uncontrolled for NOX emissions, these
differences may be mitigated by the addition of NOX control
technologies with minimal overall cost impact.
As concern for environmental protection increases, the issue may
not be whether coal or oil use is more environmentally acceptable,
but whether the increasing use of fossil fuels can be continued at
the present levels of control technology without potential long
term damages. If it is found that long term effects of pollution
(e.g., trace metals accumulation, lake acidity from acid rains)
from fossil fuel combustion and other sources are environmentally
unacceptable, it is clear that energy use may be affected. Energy
cost will increase with increasing control requirements, possibly
to the level where other cleaner forms of energy become more
competitive.
5-56
-------
REFERENCES FOR SECTION 5
1. Department of Health, Education, and Welfare, "Report of the Committee
on Health and Environmental Effects of Increased Coal Utilization,"
December 1977.
2. Argonne National Laboratory, "A Preliminary Assessment of the Health
and Environmental Effects of Coal Utilization in the Midwest,"
January 1977.
3. B. Vaughan, et al, Battelle Pacific Northwest Laboratories, "Review of
Potential Impact on Health and Environmental Quality from Metals
Entering the Environment as a Result of Coal Utilization," August 1975.
4. G. Waldbott, "Health Effects of Environmental Pollutants," 1973.
5. R. T. Lundy and D. Grahn, Argonne National Laboratory, "Predictions of
the Effects of Energy Production on Human Health," a paper presented at
the Joint Statistical Meetings of the American Statistical Association
Biometric Society, Chicago, Illinois, August 1977.
6. S. Finch and S. Morris, Brookhaven National Laboratory, "Consistency of
Reported Health Effects of Air Pollution," BNL-21808.
7. Argonne National Laboratory, "An Integrated Assessment of Increased Coal
Use in the Midwest: Impacts and Constraints, Volume II," National Coal
Utilization Assessment, October 1977.
8. Angonne National Laboratory, "An Integrated Assessment of Increased
Coal Use in the Midwest: Impacts and Constraints, Volume I," National
Coal Utilization Assessment, October 1977.
9. Synfuels Interagency Task Force, Department of Interior, "Synthetic Fuels
Commercialization Program Draft Environmental Statement," ERDA-1547,
December 1975.
10. C. Sheih, "Application of a Langrangian Statistical Trajectory Model to
the Simulation of Sulfur Pollution over North Eastern United States,"
Preprints of Third Symposium on Atmospheric Turbulence, Diffusion, and
Air Quality, 1976.
11. W. Nelson, J. Knelson, V. Hasselblad, Health Effects Research Laboratory
of Environmental Protection Agency, "Air Pollutant Health Effects
Estimation Model," EPA Conference on Environmental Modeling and Simula-
tion, Cincinnati, April 1976.
12. Teknekron , Ongoing program sponsored by Environmental Protection
Agency, "Cooperative Development of an Industrial Assessment Model
Under Existing Integrated Technology Assessment," Contract No. 68-
01-1921.
5-57
-------
13. G. Sehmel, Battelle Pacific Northwest Laboratories, "Pacific Northwest
Laboratory Annual Report for 1972," BNWL 1751, Vol II, 1973.
14. L. Wilson, "Seasonal Sediment Yield Patterns of U.S. Rivers," Water
Resources Res. 8:1470-1479, 1972.
15. John Hoover, Division of Energy and Environmental Systems, Argonne
National Laboratories, Personal Communication, Feburary 1978.
16. R. Krizek and J. Fitzpatrick, Northwestern University, "Double Alkali
Landfill Tests Evaluation," Technical Report 120, April 1976.
17. Argonne National Laboratories, "The Environmental Effects of Using Coal
for Generating Electricity," prepared for Nuclear Regulatory Commission,
Washington D.C., May 1977.
18. U.S. Department of Health, Education and Welfare, "Air Quality Criteria
for Sulfur Oxides," AP-50, March 1967.
19. U.S. Department of Health, Education, and Welfare, "Air Quality Criteria
for Nitrogen Oxides," January 1971.
20. U.S. Department of Health, Education, and Welfare, "Air Quality Criteria
for Particulate Matter," January 1969.
21. U.S. Department of Health, Education and Welfare, "Air Quality
Criteria for Carbon Monoxide," March 1970.
22. "Effects of Trace Contaminants from Coal Combustion," Proceedings of
a Workshop Sponsored by Division of Biomedical and Environmental
Research and Development Administration, August 1976, Knoxville,
Tennessee.
23. Draft of proposed rules for "Standards Applicable to Owners and
Operators of Hazardous Waste Treatment, Storage and Disposal Facili-
ties," Obtained from Office of Solid Waste, Environmental Protection
Agency, March 1978.
24. W. Berry and A. Wallace, "Trace Elements in the Environment - Their
Role and Potential Toxicity as Related to Fossil Fuels," University of
California Laboratory of Nuclear Medicine and Radiological Biology,
1974.
25. Argonne National Laboratory, "Assessment of the Health and Environ-
mental Effects of Power Generation in the Midwest," Vol. II Ecological
Effects, April 1977.
26. H. Thienes and T. Haley, "Clinical Toxicology," Published by Kimpton
Publishes, London 1972.
27. G. Waldbott, "Health Effects of Environmental Pollutants," Published
by Mosby Company, 1973.
5-58
-------
28. Department of Health Education, and Welfare, "Air Quality Criteria
for Hydrocarbons," March 1970.
29. U.S. Environmental Protection Agency, "1972 National Emissions Report,"
June 1974.
30. Department of Health, Education and Welfare, "Air Quality Criteria
for Photochemical Oxidants," March 1970.
31. N. Glass, Office of Health and Ecological Effects, "Ecological Effects
of Gaseous Emissions from Coal Combustion," November 1977.
32. Committee on Food Protection, Food and Nutrition Board, National
Research Council, "Toxicants Occurring Naturally in Foods," Published
by National Academy of Sciences, 1973.
33. J. Upham, "Atmospheric Corrosion Studies in Two Metropolitan Areas,"
Journal of Air Pollution Control Association, June 1967.
34. I. Michelson, "The Household Cost of Living in Polluted Air in the
Washington D.C. Metropolitan Area," a report to the U.S. Public
Health Service.
35. R. Wilson and D. Minnotte, National Air Pollution Control Administra-
tion, "A Cost Benefit Approach to Air Pollution Control," Journal of
the Air Pollution Control Association, May 1969.
36. Environmental Protection Agency, Office of Research and Development,
Office of Energy Minerals and Industry, "Health and Environmental
Impacts of Increased Generation of Coal Ash and FGD Sludges," Report
to the Committee on Health and Ecological Effects of Increased Coal
Utilization, November 1977.
37. Federal Energy Administration, "Project Independence,"
November 1974.
38. Argonne National Laboratory, "Environmental Control Implications of
Generating Electric Power from Coal," Technology Status Report
Volume I, Coal Utilization Program, December 1976.
39. TRW, "Evaluation of Emission Control Criteria for Hazardous Waste
Management Facilities," prepared for U.S. Environmental Protection
Agency, Office of Solid Waste, April 1978.
40. Science and Public Policy Program, University of Oklahoma, "Energy
Alternatives: A Comparative Analysis," May 1975.
41. Ford, A, and H.W. Lorber, Los Alamos Scientific Laboratory, "Metho-
dology for the Analysis of the Impacts of Electric Power Production
in the West," January 1977.
5-59
-------
5-60
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
, REPORT NO.
EPA-600/7-78-164b
3. RECIPIENT'S ACCESSION NO.
T.TLE AND SUBTITLE Environmental Assessment of Coal-
and Oil-firing in a Controlled Industrial Boiler;
Volume n. Comparative Assessment
5. REPORT DATE
August 1978
6. PERFORMING ORGANIZATION CODE
c> Leavitt, K. Arledge, C. Shih, R. Orsini,
W. Hamersma, R. Maddalone, R. Beimer, G. Richard, and
M. Yamada
8. PERFORMING ORGANIZATION REPORT NO.
PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2613, Task 8
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park. NC 27711
13. TYPE OF RE PORT AND PERIOD COVERED
Task Final; 5/77-7/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES jjERL-RTP project officer is Wade H. Ponder, Mail Drop 61, 919/
541-2915.
is. ABSTRACT
repOrt gives results of a comparative multimedia assessment of coal-
versus oil-firing in a controlled industrial boiler, to determine relative environmen-
tal, energy, economic, and societal impacts. Comprehensive sampling and analyses
of gaseous, liquid, and solid emissions from the boiler and its control equipment were
conducted to identify criteria pollutants and other species. Major conclusions include:
(1) While the quantity of particulates from oil-firing is considerably less than from
coal-firing, the particles are generally smaller and more difficult to remove, and the
concentration of particulates in the treated flue gas from oil-firing exceeded that from
coal-firing. (2) NOx and CO emissions during coal-firing were about triple those du-
ring oil-firing. (3) Sulfate emissions from the boiler during coal-firing were about
triple those during oil-firing; however, at the outlet of the control equipment, sulfate
concentrations were essentially identical. (4) Most trace element emissions (except
vanadium, cadmium, lead, cobalt, nickel, and copper) are higher during coal-firing.
(5) Oil-firing produces cadmium burdens in vegetation approaching levels which are
injurious to man; coal-firing may produce molybdenum levels which are injurious to
cattle. (6) The assessment generally supports the national energy plan for increased
use of coal by projecting that the environmental insult from coal-firing is not signif-
icantly different from that from oil-firing. -
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
3.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Assessments
Boilers
Combustion
Fuel Oil
noal
Dust
Nitrogen Oxides
Carbon Monoxide
Sulfates
Sulfur Oxides
Trace Elements
Chemical Analysis
Pollution Control
Stationary Sources
Environmental Assess-
ment
Industrial Boilers
Particulate
13B
14 B
13A
21B
2 ID
11G
07B
06A
07D
3. DISTRIBUTION STATEMENT
Unlimited
EPA Form 2220-1 (9-73)
19. SECURITY CLASS
Unclassified
168
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
------- |