United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-83-040 Sept. 1983
4>EPA Project Summary
Control of Criteria and Non-
Criteria Pollutants from Coal/Oil
Mixture Combustion
M. E. Kelly, R. M. Parks, and J. H. E. Stalling
As the availability and cost of oil have
become uncertain in recent years, the
need for the U.S. to reduce its depend-
ence on oil has prompted significant
efforts by government and industry in
finding alternate fuel sources. This
posture has been strengthened by the
Powerplant and Industrial Fuel Use Act
of 1978 that prohibits the use of gas
and oil in new boilers without special
exemption. The Department of Energy
(DOE) has taken an active role in
developing one such alternate fuel
technology: coal/oil mixture (COM)
combustion.
Recognizing that environmental
considerations must be made in any
evaluation of fuel conversion to COM,
DOE and EPA contracted with Radian
to identify and assess the effectiveness
of currently available methods of
controlling the release of criteria and
non-criteria (trace elements) pollutants
from the combustion of COMs. The
report presents this assessment and
compares the costs and effectiveness
of various control technologies found to
be applicable to emissions from boilers
firing COM.
Emissions from COM combustion
were characterized using data from
various tests. The pollutants examined
most closely were particulate matter,
SO2, and NO*. Trace element emissions
and emissions of polynuclear organic
material were also examined. Conven-
tional emission control techniques were
determined to be the most effective in
reducing emissions from COM com-
bustion.
Emission rates and associated costs
for emissions control of particulate
matter and SOz were assessed for four
different COM compositions and various
boiler sizes. Fabric filters and electro-
static precipitators were considered for
particulate matter control; wet flue gas
desulfurization (dual alkali), dry scrub-
bing, and dry injection techniques were
considered for three levels of SO2
control (50%, 70%, 90%). Low-sulfur
fuels were also examined as an addi-
tional alternative.
This Project Summary was developed
by EPA'3 Industrial Environmental
Research Laboratory. Research Tri-
angle Park. NC. to announce key find-
ings of the research project that is fully
documented in a separate report of the
same title (see Project Report ordering
information at back).
Introduction
The need for the U.S. to reduce its
dependence on oil and expand its use of
coal has prompted DOE to take an active
role in developing Coal/Oil Mixture
(COM) combustion technology. Sufficient
technical and economic information has
been developed to allow private sector
implementation of COM combustion, and
a number of industrial and utility energy
producers are assessing the use of COM
at their facilities.
As COM combustion technology be-
comes more widespread, DOE and EPA
recognize that certain environmental
considerations will have to be addressed
in order to expand the use of COM in an
environmentally acceptable way. Specif-
ically, it will be necessary to determine
the potential emissions from sources
burning COMs and evaluate, assess, and
compare the effectiveness of control
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technologies in controlling the criteria
and non-criteria pollutant emissions.
Radian has been under contract to EPA
and DOE to identify and assess the
effectiveness of currently available
methods of controlling the release of
criteria and non-criteria (trace elements)
pollutants from the combustion of COMs.
The report of this study contains
several chapters that focus on the various
considerations and assessments neces-
sary in making a conversion from oil or
gas to COM. Chapter 2 presents some of
the technical and economic factors that
determine the suitability of COM as a fuel
and identifies boilers that might be
candidates for COM conversion.
Chapter 3 discusses the emissions that
have been measured to date on combus-
tion units burning COM. The criteria
pollutant emissions that are discussed
are particulate matter, SO& and NO>.
Non-criteria pollutant emissions discus-
sed are the selected trace elements. As,
Be, Cd, Cr, Ni, Se, V, and Hg, as well as
polynuclear organic matter (POM) emis-
sions. Chapter 3 also briefly discusses
control technologies applicable to boilers
that could be converted to burn COMs.
Several of these control devices are
selected as most promising for further
technical and economic study in the
remainder of the report.
Chapter 4 presents the environmental
impacts of the selected control techno-
logies, including the primary pollutant
control capability and any secondary
environmental impacts. The potential for
multipollutant control is also discussed.
Chapter 5 addresses the cost impacts of
the technologies discussed in Chapter 4
in terms of capital costs, annual operation
and maintenance costs, annualized
costs, and cost effectiveness. Compar-
isons of multipollutant controls, add-on
controls, and low-sulfur COMs are also
presented in Chapter 5.
Use of COM in Existing Boilers
COMs typically consist of 20-50% by
weight coal dispersed in oil or in an
oil/water mixture (known as COW—
coal/oil/water). The coal is usually
ground to at least 70% minus 200 mesh.
A No. 6 heavy residual is typically chosen
over lighter distillate oils for COMs. In
addition to being less expensive than
distillate oil, heavy residuals reduce coal
settling problems with COM, relative to
lighter oils. Water is sometimes added to
the COM as a stabilizer; most commonly
the added water is 5-20% by weight.
The suitability of converting a boiler
currently firing oil or gas to COM depends
on several technical and economic
factors. Whether a specific boiler is a
likely candidate for COM depends on the
age of the boiler (remaining useful life),
boiler design, size and capacity factor,
geographical location (proximity to COM
fuel supply), site-specific boiler modifica-
tions required, existing emission control
equipment, if any, and emission controls
required by the applicable environmental
regulations.
Technical Considerations
Three factors must be evaluated in
determining the technical suitability of
converting existing oil- or gas-fired
boilers to COM: COM fuel properties,
COM combustion characteristics, and
boiler modifications required to accom-
modate COM-firing.
Other than combustion characteristics,
the most important COM fuel properties
to be considered are viscosity, stability,
and abrasiveness. The viscosity and
stability of the COM are interrelated:
generally, the more viscous the COM is
the less tendency there is for fuel
instability (settling of coal particles).
Chemical stabilizing additives (typically
emulsifying agents, gelling agents, or
surfactants) have been developed to
improve COM stability by keeping the coal
particles suspended in the oil. Although
maximum coal concentration is desirable
for economy and stability, there appears
to be an upper limit of about 60% coal in
the COM. Although 60% COM may be
possible, COM is typically available with
40-55% coal in oil. The increased
abrasiveness of COM relative to oil can
potentially cause erosion in pipe bends,
pumps, valves, and burners. These
potential problems can be minimized by
proper material selection, reduced fuel
velocities, and more finely ground coal.
The boiler modifications required in
converting from oil or gas to COM are
quite site-specific, and depend on such
boiler design factors as tube spacing,
burner design, furnace size, and bottom
ash removal capability. Boilers originally
designed for oil- or gas-firing commonly
have narrower tube spacings than boilers
originally designed for coal -f iri ng, maki ng
coal-fired boilers more ideally suited, in
that respect, for conversion to COM
combustion. The potential exists, in
converting to COM, for ash deposition
and ash slagging (if the furnace tempera-
ture is not maintained below the ash
fusion temperature). Bridging of molten
ash between the tubes leads to impaired
heat transfer and possible boiler derating.
Soot blowers will generally prevent these
problems; although some existing oil-
fired boilers have soot blowers, additional
soot blowing capacity may be needed to
accommodate COM combustion. Since
most COM combustion studies have
found air or steam atomization preferable
to mechanical atomization, the burners
may have to be modified or (in some
cases) replaced. Consideration in burner
design or modification is also likely to
facilitate switching from COM-to oil-
firing with maximum flexibility. Combus-
tion of COM requires a larger combustion
space relative to oil to allowforthe longer
residence time needed for complete
combustion of the coal particles. Refitting
for COM combustion will require provi-
sions for a bottom ash handling facility in
most cases since units designed for oil-
and gas-firing do not often have bottom
ash removal capability.
In addition to modifications made
directly to the boiler, other changes to the
facility may be required in converting to
COM. These changes are primarily
associated with the fuel handling system
(including pumps, piping, valves, and flow
measurement devices). Storage tanks for
COM received from a centralized off-site
preparation plant may have to be modi-
fied to include agitators and temperature
control. And new storage equipment will
be required if dual fuel capability (COM
and oil) is desired.
Economic Considerations
Several economic factors will also
affect the desirability of conversion to
COM firing. Paramount among these
considerations of the use of COM in
general is the cost of coal relative to the
cost of oil. Currently, widespread use of
COM is limited by the low price of oil. And
the increased use of COM may be limited
by the advent of coal/water mixtures as a
viable fuel option.
Although the economics of conversion
for a particular boiler may be somewhat
complex, particularly for utility applica-
tions, the following factors are important
in every case: capital availability; boiler
modifications required; difference be-
tween oil (or gas) and coal prices and the
predicted rates of escalation of the fuel
costs; security of oil or gas supply;
availability, composition, and price of
COM; boiler size and capacity factor;
remaining useful life of the boiler; and
emission controls required.
The economics of conversion are also
affected by the composition of the COM
(percent coal, sulfur content and ash
content), the COM fuel cost, and the
source of the COM (on- or off-site
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centralized preparation plant). COM fuel
cost is determined primarily by the cost of
coal and oil, which account for a bout 85%
of the fuel cost on a Btu basis.
COM Emissions
Generally, when an oil-fired boiler is to
be converted to COM combustion, the
uncontrolled emissions of particulates
and NO, will be greater for COM-firing
than for oil-firing. The increased emis-
sions result from the contribution of coal
ash and nitrogen to the combustion
emissions. Emissions of SO2 from COM
combustion may be less than or greater
than oil-only SOz emissions, depending
on the relative sulfur contents of the
COM and the oil. Trace element emissions
(except Ni and V) from COM combustion
may also be greater than those for oil-
only firing.
Paniculate Emissions
Measured emissions of particulates (fly
ash) from boilers firing COM are a
function of the ash content of the COM
and, to some degree, the amount of ash
deposition in the boiler. Since the ash
content of residual oil is negligible when
compared to the ash content of coal, the
COM ash content depends primarily on
the coal ash content and the percentage
of coal used in preparing the COM.
Although most test data suggest that
most of the COM ash (80-90% plus) is
emitted as fly ash, some COM combustion
tests have shown significantly lower fly
ash emissions. Ash deposition in the
boiler may cause the reduced measured
particulate emissions.
SOz Emissions
SO2 emissions from COM combustion
are a direct function of the fuel sulfur
content. The COM sulfur content is in
turn determined by the sulfur contents of
the coal and oil used to make the COM
and the relative percentage of each in the
COM. At least 95% of the fuel sulfur is
typically emitted as SO2. But COMs made
with coal that has highly alkaline ash may
emit slightly less than 95% of the fuel
sulfur, since the alkaline ash retains
some of the fuel sulfur. Depending on the
relative sulfur contents of the oil and coal,
and the percentage of each fuel in the
COM, SOz emissions from the COM may
be greater or less than SOz emissions
from the respective oil.
/VOx Emissions
Emissions of NOx from boilers firing
COM are more difficult to quantify for all
potential applications than are SOz and
particulate emissions. For any particular
boiler, NOx emissions can vary not only
with COM fuel composition, but also with
the amount of combustion air (excess air)
and, in some cases, with boiler load.
Properties of the COM fuel that influence
NOx emissions are: nitrogen content of
the fuels used to make the COM, percent
coal in the COM, and, possibly, the
presence of water in the COM. For a given
fuel composition, NOX emissions can vary
significantly from boiler to boiler due to
differences in burner and furnace design
and the use of combustion air preheat.
NOx emission data from several differ-
ent COM combustion tests indicate
several general trends:
• An increase in NOx emissions at
increased excess air levels.
• An increase in NOx emissions with
increased COM nitrogen content.
• Higher NOx emissions from COM
combustion than from combustion
of corresponding oil.
• NOx emissions of 172-301 ng/J (0.4-
0.7 lb/106 Btu) in most tests, al-
though some tests showed emissions
of 430 ng/J (1.0 lb/108 Btu) or
greater.
Trace Element Emissions
Trace elements i n the COM fuel exit the
boiler either with the bottom ash or with
the flue gas, if there is not significant ash
deposition in the boiler. Most of the trace
elements emitted with the flue gas are
associated with the fly ash, though some
may remain in the vapor phase.
The amount of trace elements emitted
from a particular boiler depends on:
combustion temperature, fuel feed
mechanism, characteristics of the flue
gas, and COM properties (trace element
concentration).
The combustion temperature deter-
mines the extent to which specific trace
elements are volatilized and thus the
extent to which they may be emitted with
the fly ash or flue gas. The fuel feed
mechanism influences the partitioning of
non-combustible trace elements be-
tween the bottom ash and the fly ash. The
temperature of the flue gas affects the
relative amounts of volatile trace elements
which are emitted condensed on the fly
ash particles compared to being emitted
as a vapor.
The concentration of trace elements in
the coal and oil and the relative amounts
of coal and oil used to prepare the COM
determine the concentration of trace
elements in the COM. Data on three coals
show that coal has higher concentrations
of As, Be. Cr, Hg, and Se. Residual oil has
higher concentrations of Cd. Ni, and V.
Pofynuclear Organic Material
(POM)
The amount of POM emitted from any
combustion source depends on the
formation and the transformation mech-
anisms of the POM. POM is formed in the
combustion zone either by the breakdown
of larger molecules or by the building up
of smaller ones. Evidence indicates that
POM forms in the vapor phase and later
condenses on flue gas particulates. POM
formation is related to combustion
efficiency, and POM transformations are
related to boiler and downstream flue gas
temperatures. When properly fired, oil-
only combustion has been shown to
contribute almost no POM emissions to
the environment, while coal-only com-
bustion produces POM emissions in
unpredictable patterns. Therefore, the
POM emissions from COMs cannot be
related to the fuel content of any
particular component.
Applicable Control
Technologies
Particulate Control
Technologies
Particulate control technologies used
on coal-fired boilers are: electrostatic
precipitators (ESPs), fabric filters, venturi
(wet) scrubbers, side stream separators,
and mechanical collectors. Side stream
separators and mechanical collectors are
used only on industrial coal-fired boilers.
Most industrial and utility oil-fired boilers
are equipped with ESPs or have no
particulate matter control device. ESPs
are primarily used on utility boilers, while
most oil-fired industrial boilers are
uncontrolled. Mechanical collectors and
venturi scrubbers are not often used to
control particulate emissions from oil-
firing due to the relatively small size of the
oil fly ash (generally less than 2 /jm) and
the inefficiency of these collectors in
removing small particles.
High particulate control efficiencies
(98% or greater) have been widely
demonstrated with ESPs, fabric filters,
and wet scrubbers. In general, these
technologies can reduce fly ash emissions
to 43 ng/J (0.1 lb/106 Btu) or less,
comparable to controlled and, in many
cases, uncontrolled fly ash emissions
from oil-fired boilers. Fabric filters are
generally the most effective of the three
technologies. Bag blinding (caking of
moist particulates on the filter bag),
mentioned in some literature as a
-------
potential problem due to the hygroscopic
nature of the fly ash, has not been
observed in limited COM experience. In
fact, the fly ash from COM combustion
appears to have characteristics similar to
coal fly ash. Coal fly ash has been shown
to be highly suitable for fabric filter
collection. With proper design (i.e.,
adequate specific collection plate area),
ESPs can be as efficient as fabric filters.
There is a lack of resistivity data on COM
fly ash, however; these data may be
particularly important for boilers firing a
COM made from low sulfur coal. It is likely
that the resistivity properties of the coal
fly ash will dominate the characteristics
of the COM ash.
Wet scrubbers are somewhat less
effective than fabric filters or ESPs,
especially for collecting submicron
particles. Venturi scrubbers are generally
the most efficient type of scrubber for
particulate removal. Wet scrubbers,
however, have two main disadvantages:
they result in wet solids sludge and may
have liquid waste impacts; and the flue gas
becomes saturated, reducing plume
buoyancy and adversely affecting disper-
sion of gaseous pollutants(SO2andNO,).
Combined SOz /Particulate
Control Technologies
The combined SO2/particulate control
technologies in use are: wet flue gas
desulfurization (FGD), spray drying FGD,
and fuel cleaning and blending prior to
combustion. Technologies still being
developed include: dry injection of
sodium-based compounds, and alkaline
fuel additives. Except for alkaline fuel
additives, these technologies can be used
to simultaneously control SOz and
particulates.
In general, the technology exists to
control SO2 from COM combustion to
levels equal to or lower than those from
existing oil-fired boilers. FGD systems,
capable of achieving at least 90% SOz
removal, are the most effective SOz
control technologies. Significant SOz
control can also be obtained by: dry FGD
(spray drying, dry injection) to achieve
50% or more SOz removal from a low-
sulfur COM; or COM prepared with
physically cleaned coals, hydrodesulfur-
ized oil, or naturally occurring low-sulfur
fuels. Blending cleaned fuels (or naturally
occurring low-sulfur fuels) to make the
COM avoids boiler-site solid or liquid
waste impacts associated with FGD
control.
Wet scrubbers are su itable for combined
SOa/particulate removal. Combined
SOz/particulate control with this system
favors venturi scrubbers, possibly pre-
ceded by a mechanical collector. Sub-
stantial combined SOz/particulate control
is also achievable with spray drying
systems (including a fabric filter or an
ESP) and with dry injection of sodium-
based alkali compounds into a fabric
filter. The disposal of highly soluble
sodium-based wastes from dry injection
may present more serious solid waste dis-
posal problems than the disposal of cal-
cium-based wastes from spray drying or
wet FGD systems.
Physical coal cleaning (PCC) can
reduce the ash content of the coal as well
as reducing its sulfur content. But,
depending on the percentage of coal in
the COM and the final ash content of the
cleaned coal, combustion of COM made
from PCC will still likely require additional
control to reduce particulate emissions to
levels typical of oil combustion.
/VOx Control Technologies
Control technologies for NOX can be
divided into: combustion modification
controls, and post-combustion controls.
Combustion modification includes: low
excess air (LEA) operation, staged
combustion, flue gas recirculation (FGR),
and low-NOx burners. Post-combustion
controls include ammonia injection
("thermal De-NOx") and flue gas treat-
ment.
Despite the use of what are generally
accepted as the most efficient techno-
logies applicable to COM units, NOX
emissions from COM combustion may
still be greater than those from combustion
of typical No. 6 residual oils. Low-NO*
burners are the most effective of the
candidate NO, control technologies
examined in this study. Limited data
indicate that low-NOx burners can reduce
NO, emissions to oil-only levels or less.
However, for high nitrogen content
COMs, NOX emissions may still be above
the levels prescribed in some emission
regulations, particularly in states like
California which have stringent NO,
regulations. In addition, the development
status of low-NOx burners for commercial
utility and industrial boilers firing COM is
questionable. Staged combustion is a
relatively effective NOx control technology.
This technique reduces fuel NOxformation
and is thus particularly suitable for high
nitrogen content COMs, which produce
substantial amounts of fuel NOx when
combusted. Staged combustion has
reduced NO, emissions 30-40% during
COM combustion tests. Operation at low
excess air (LEA) levels is primarily
effective in reducing thermal NO,.
Available data from LEA tests during
COM combustion show NOx reductions of
10-20%. Thus, more than just LEA
control should be required for high
nitrogen COMs to reduce NOx emissions
to the levels typical of oil combustion.
Note that the effects of variables (e.g.,
COM properties, the presence of water
in the COM, combustion air preheat
temperatures, and boiler heat release
rate) on NOx emissions from COM
combustion are not fully quantifiable
based on existing data. Also, boiler-to-
boiler variations in burner and furnace
design may significantly vary NO, emis-
sions from combustion of a given COM.
Trace Element Control
Technologies
Technologies with the greatest degree
of fine particulate control are the most
efficient for trace element collection,
since many of the trace elements tend to
be enriched on the smaller fly ash
particles. Thus, fabric filters achieve the
greatest degree of trace element control,
followed by ESPs and wet scrubbers. In
addition, physical coal cleaning and oil
hydrodesulfurization can reduce trace
element concentration in the fuel prior to
combustion.
Cost Impact of Control
Technologies
The cost impacts of various particulate,
SO2, and NOx control technologies for
boilers firing COM were evaluated in
terms of: capital costs, annual operating
and maintenance costs, annualized
costs, and cost effectiveness. (For this
study, cost effectiveness is defined as the
annualized cost of control divided by the
tons of pollutant removed.) The impacts of
various particulate and SOz control
technologies were evaluated for three
COM boiler sizes and four COM fuel
types. The boiler sizes examined were:
8.8, 73, and 205 MW (30, 250, and 700 x
106 Btu/hr). The COM fuel types for
which the control technologies were
costed were selected from typical coal
and oil compositions. Uncontrolled SOz
and particulate emission rates were
calculated assuming that: all of the fuel
sulfur is emitted as SOz, and 90% of the
COM ash is em itted as fly ash. Each COM
fuel was assumed to be a 50:50 mixture
of coal and oil. The costs of particulate
and SC>2 control technologies given in the
report are based primarily on the techno-
logy costs used in EPA's development of
Industrial Boiler New Source Performance
Standards (NSPS).
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Comparison of FGD System
Costs
The costs of various FGD systems are
compared for units firing low- and high-
sulfur COM. The costs are based on 70%
S02 removal [a controlled SOz emission
level of 168 ng S02/J (0.4 lb/106 Btu)]
and 60% annual capacity factor. The
relative costs of the three FGD systems
for specific applications may be altered
due to site-to-site variations in SOa
removal, boiler capacity, reagent costs, or
availability of existing equipment to
reduce retrofit costs.
For boilers firing low-sulfur COM, dry
injection FGD has the lowest capital costs
up to a boiler size of about 200 x 106
Btu/hr. However, wet FGD has the lowest
capital cost of the three systems for larger
boilers. The result is due primarily to the
increased paniculate matter collection
associated with the use of a fabric filter in
the spray dryer and dry injection systems.
The lower paniculate emission control
levels achievable with fabric filters,
relative to a wet FGD system used for
combined SOz/particulate removal,
result in higher waste disposal costs. An
ESP would likely be required upstream of
the wet FGD to achieve the same
particulate emission level. Similar findings
were made for high-sulfur COM.
In comparing the annualized costs for
three FGD systems, all processes were
relatively close for low-sulfur COM. Wet
FGD had the lowest annualized cost for
boilers above about 200 x 106 Btu/hr.
Wet FGD was also the least expensive
system for high sulfur COM, while dry
injection had the highest annualized
costs.
Cost Comparison of Low
Sulfur COM With Wet FGD
The annualized costs of using three
low-sulfur COMs were calculated relative
to the cost of using a 2.3% sulfur COM.
These costs are compared (in Figure 1) to
the costs of wet FGD at 70% SOz removal.
Emissions of SOz for each are less than
430 ng/J (1.0 lb/106 Btu}.
Wet FGD is more expensive than low-
sulfur COMs with 50% coal. However, the
40% coal COM (made with 0.7% S coal
and 0.5% S oil) is more expensive than
FGD for boilers larger than about 300 x
106 Btu/hr. Of course, the boiler size
where FGD is less costly than low sulfur
COM depends on boiler capacity factor.
Although both FGD and annual COM
costs depend directly on boiler capacity
factor, COM costs are generally affected
more strongly by changes in capacity
factor. FGD should be less costly than
low-sulfur COM only for large boilers
operated at relatively high annual capacity
factors (greater than about 0.6).
Low-sulfur COM and an ESP or a fabric
filter will also provide simultaneous
SOz/particulate control. The combined
annual cost of low-sulfur COM and a
fabric filter is compared to the costs of
wet and dry FGD in Figure 2. Emission
control levels achievable with these
systems are: SOz—nominal 430 ng/J (1.0
Ib SOz/106 Btu); and particulate—21.5
ng/J (0.05 lb/106 Btu) (dry FGD + fabric
filter), and 43 ng/J (0.1 lb/106 Btu) (wet
FGD). Figure 2 shows the 50% coal low-
sulfur COM/fabric filter combination to
be the least expensive combined S02/
particulate control technique up to a
boiler size of about 325 x 106 Btu/hr. For
larger boilers, wet FGD is the least
expensive alternative. Both wet FGD and
spray drying are less costly than the 40%
coal low-sulfur COM/fabric filter com-
bination.
3,500
3,000
2,500
CD
^ 2,000
»•»
«i
»
o
O
.§ 7,500
/,ooa
500
Wet FGD; 70% SO2 removal: 2.3% S COM IB-1)
0.92 Ib SOi/10* Btu
40% COM (0.7% S coal/0.5% S oil);
0.77 Ib SO2/10*Btu
50% COM 10.7% S coal/0.5% S oil);
0.83 Ib SOz/10*Btu
50% COM (0.7% S coal/0.87% S oil);
.0.99 Ib SO*/10* Btu
Note: Low sulfur COM costs calculated
relative to cost of 2.3% S COM
(B-1)
'COM
Wet FGD
COM
COM
60% Annual Boiler Capacity Factor •
Double Alkali Wet FGD System
(Combined 502 /Particulate Control)
0
(01
29
(100)
59
(200)
87
(300)
116
(400)
145
(500)
174
(600)
203
(700)
232
(800)
BoilerSize, MW(10*Btu/hr)
Figure 1.
Comparison of wet FGD and low-sulfur COM annualized costs.
5
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8
o
I
"
5500 r
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
Low-Sulfur COM/Fabric Filter
FGD
Based on 60% Boiler Capacity Factor
40% Coal Low Sulfur COM /
fO. 7% S Coal/0.5% S Oil) '
Wet FGD
70% SO2 Removal
- 50% Coal Low Sulfur COM
(0.7% S Coal/0.5% S Oil)
0 29 59 87 116 145 174 203 232
fO) (100) (200) (300) (400) (500) (600) (700) (800)
Boiler Size, MW (10* Btu/hr)
Figure 2. Comparison of annual/zed costs of alternatives for combined SOz /paniculate control.
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M. E. Kelly, R. M. Parks, andJ. H. E. Stellingare with Radian Corporation, Durham,
NC 27705.
Robert E. Hall is the EPA Project Officer (see below).
The complete report, entitled "Control of Criteria and Non-Criteria Pollutants from
Coal/Oil Mixture Combustion," (Order No. PB 83-247 247; Cost: $19.00.
subject to change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Postage and
Fees Paid
Environmental
Protection
Agency
EPA 335
Official Business
Penalty for Private Use $300
PS 0000329
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