United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-84-001 Mar. 1984
&ERA Project Summary
Control of Criteria and Non-
Criteria Pollutants from
Coal/Liquid Mixture Combustion
J.H.E. Stalling and S.J. Call
As the availability and cost of oil has
become uncertain in recent years, the
need for the United States to reduce its
dependence on oil has prompted signifi-
cant 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 two such alternate fuel
technologies: coal/oil mixture (COM)
and coal/liquid mixture (CLM) combus-
tion.
Recognizing that environmental con-
siderations must be addressed in any
evaluation of fuel conversion to COM or
CLM, DOE and the EPA's Industrial
Environmental Research Laboratory-
RTP (IERL-RTP) contracted with Radian
Corporation 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 and CLMs. This report gives
results of this assessment and compares
the costs and effectiveness of various
control technologies found to be appli-
cable to emissions from boilers firing
CLM. A previous report (EPA-600/7-
83-040) gave results of a similar
assessment of boilers firing COM.
To date, the combustion of coal/wa-
ter mixtures (CWMs) has received the
most attention, and is thus the focus of
this report. Coal/alcohol mixtures
(CAMs) represent another fuel alternative
which could potentially replace oil or
natural gas in existing boilers, although
there is currently limited activity in the
development of CAMs as fuels. This
report briefly summarizes activities and
advances made in the development of
CAMs as fuels.
Emissions from CLM combustion
were characterized using data from
various tests. In the absence of data for
CLM-firing, the discussion focuses on
data from coal- and COM-firing, with
corollaries to CLM combustion. The
pollutants examined most closely were
paniculate matter, sulfur dioxide (SO2),
and nitrogen oxides (NO,). Trace element
emissions and emissions of polynuclear
organic material (POM) were also
examined. Conventional emission con-
trol techniques were determined to be
the most effective in reducing emissions
from CWM combustion. Cleaned coal
must be used in the preparation of
CWMs, and it has been determined that
coal cleaning can also significantly
reduce particulate matter and SOz
emissions from CWM combustion.
Emission rates and associated costs
for emissions control of particulate
matter and SO2 were assessed for four
CWM compositions and various boiler
sizes. Physical coal cleaning was
considered for pre-combustion control
of particulate matter and SO2.
This Project Summary was developed
by EPA's Industrial Environmental
Research Laboratory, Research Triangle
Park, NC, to announce key findings of
the research project that is fully docu-
mented in a separate report of the same
title (see Project Report ordering
information at back).
Introduction
Coal/water mixtures (CWMs) have
been combusted successfully in Depart-
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ment of Energy (DOE) research in small,
test combustion units, and full-scale
testing is planned for the near future.
Coal/alcohol mixtures (CAMs)arenotyet
well-developed as a slurry fuel; further-
more, they are still more expensive than
CWMs or coal/oil mixtures (COMs).
As CLM combustion technology becomes
more widespread, DOE and the Environ-
mental Protection Agency (EPA) recognize
that certain environmental considerations
will have to be addressed in order to
expand the use of CLM in an environmen-
tally acceptable way. Specifically, it will
be necessary to determine the potential
emissions from sources burning CLMs
and evaluate, assess, and compare the
effectiveness of control technologies in
limiting criteria and non-criteria pollutant
emissions. Radian Corporation has been
under contract to EPA and DOE to
conduct a study aimed at identifying and
assessing the effectiveness of currently
available methods of controlling the
release of criteria and non-criteria (trace
elements) pollutants from the combustion
of CLMs.
The report generated from this study
contains several chapters that focus on
the various considerations and assessments
necessary in making a conversion from
oil or gas to CLM. This report focuses
primarily on CWM combustion in existing
oil- or gas-fired boilers. The report also
briefly discusses CAMs and their potential
advantages and disadvantages. Chapter
2 presents some of the technical and
economic factors that determine the
suitability of CWM as a fuel and identifies
boilers that might be candidates for CWM
conversion.
Chapter 3 discusses the emissions that
have been measured to date on combustion
units burning CWMs. The criteria pollutant
emissions that are discussed are panicu-
late matter, sulfur dioxide (SO2>, and
oxides of nitrogen N0«). Non-criteria
pollutant emissions discussed are the
selected trace elements, arsenic (As),
beryllium (Be), cadmium (Cd), chromium
(Cr), nickel (Ni), selenium (Se), vanadium
(V), and mercury (Hg), as well as polynuclear
organic matter (POM) emissions. Chapter
3 also briefly discusses control technologies
that are applicable to boilers that could be
converted to burn CWMs. Several of
these control techniques, as discussed
later in this Summary, were the subject of
further technical and economic study
presented in the remainder of the report.
Chapter 4 presents the environmental
impacts of the selected control technologies,
including the primary pollutant control
capability and any secondary environmental
impacts. The potential for multipollutant
control is also discussed. Chapter 5 address-
es the cost impacts of the technologies
discussed in Chapter 4 in terms of capital
costs, annual operation and maintenance
(O&M) costs, annualized costs, and cost
effectiveness. Multipollutant controls,
add-on controls, and low-sulfur CWMs
are also compared in this chapter.
Use of CWMs in Existing
Boilers
CWMs, also referred to as coal/water
slurries, consist of 65-75 weight percent
coal in water with minor percentages of
additives. Bituminous coals are most
frequently used in the preparation of
CWMs, but some lignite and subbitumi-
nous coals may also be used. Because
coals vary widely in ash and sulfur
content, only cleaned coals or low-sulfur,
low-ash coals are used in the preparation
of CWMs to ensure a more consistent fuel
quality. Due to the economics of CWM
preparation facilities, it is most likely that
these mixtures will be prepared in
centralized off-site facilities rather than
at the boiler site.
The suitability of converting a boiler
currently firing oil or gas to CWM de-
pends on several technical and economic
factors. The likelihood of a specific
boiler's being a candidate for CWM will
depend on the age of the boiler (remaining
useful life), boiler design, size and
capacity factor, geographical location
(proximity to CWM fuel supply), site-
specific boiler modifications required,
existing emission control equipment, if
any, and emission controls required by
applicable environmental regulations.
Technical Considerations
Three basic factors must be evaluated
in determining the technical suitability of
converting existing oil- or gas-fired
boilers to CWM: CWM fuel properties,
CWM combustion characteristics, and
boiler modifications required to accommo-
date CWM-firing.
Other than combustion characteristics,
the most important CWM fuel properties
to be considered are viscosity, stability
and abrasiveness. Viscosities of CWMs
range from about 450 to 2,000 cP, or from
a paint-like consistency to that of a thick
gel. The desired high solids loading and
decreased viscosity can be brought about
by utilizing bimodal particle size distribu-
tions and/or by the use of additives in the
preparation of CWMs. Generally, conven-
tional pumping methods are adequate to
handle CWMs, although there may be
potential erosion problems. Chemical
stabilizing additives, typically emulsifying _
agents, gelling agents, or surfactants, M
have been developed to improve COM ^
stability by keeping the coal particles
suspended in the oil. The increased
abrasiveness of CWM relative to oil can
poteritially cause erosion in pipe bends,
pumps, valves, and burners. These
potential problems can be minimized by
selecting proper materials, reducing fuel
velocities, and using more finely ground
coal.
The boiler modifications required in
converting from oil or gas to CWM are
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 spacmgs than boilers
originally designed for coal-firing, making
coal-fired boilers more ideally suited, in
that respect, for conversion to CWM
combustion. In converting to CWM, the
potential exists for ash deposition and
slagging (if the furnace temperature is
not maintained below the ash fusion
temperature). Bridging of molten ash
between the tubes leads to impaired heat
transfer and, possibly, boiler derating.
Soot blowers would generally be required
to prevent these problems; although ^
some existing oil-fired boilers have soot fl
blowers, additional soot blowing capacity ~
may be needed to accommodate CWM
combustion. Since most CWM combustion
studies have found air or steam atomiza-
tion preferrableto mechanical atomization
burners may have to be modified or, in
some cases, replaced. To facilitate
switching from CWM- to oil-firing with
maximum flexibility, careful consideration
of burner design or modification is
necessary. Combustion of CWM requires
a larger combustion space relative to oil
to allow for the longer residence time
needed for complete combustion of the
coal particles. Refitting for CWM combus-
tion will require provisions 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
CWM. These changes are primarily
associated with the fuel handling system
(including pumps, piping, valves, and flow
measurement devices). Storage tanks for
CWM received from a centralized off-site
preparation plant may have to be modified
to include agitators and temperature
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controls. New storage equipment will be
required if dual fuel capability (CWM and
oil) is desired.
Economic Considerations
Several economic factors will also
impact the desirability of converting to
CWM firing. Paramount among these
considerations of the use of CWM in
general is the cost of coal relative to that
of oil. Currently, widespread use of CWM
is limited by the low price of oil.
The economic considerations of convert-
ing a particular boiler to CWM firing may
be somewhat complex, particularly for
utility applications. However, the econom-
ic impacts of the following factors are
important in every case: capital availabili-
ty; boiler modifications required; difference
between 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
CWM; 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 CWM
(percent coal, sulfur content, and ash
content), the CWM fuel cost, and the
source of the CWM (on-site or off-site
centralized preparation plant). CWM fuel
cost is determined primarily by the cost of
coal, although coal cleaning costs and
CWM preparation costs also impact fuel
cost.
CWM Emissions
Most often, when an existing oil-fired
boiler is to be converted to CWM
combustion, the uncontrolled emissions
of particulate matter (PM) and nitrogen
oxides (NOx) will be greater for CWM-
firing than for oil-firng. The increased
emissions result from the contribution of
coal ash and nitrogen to the combustion
emissions. Emissions of SOz from CWM
combustion may be less than or greater
than oil-only SOa emissions, depending
on the relative sulfur contents of the
CWM and the oil. Trace elements
emissions (except Ni and V) from CWM
combustion may also be greater than
those for oil-only firing.
PM Emissions
Measured emissions of PM fly ash
from boilers firing CWM are a function of
the percentage of coal in the CWM, the
ash content of the coal used, and, to some
degree, the amount of ash deposition in
the boiler. Although test data on small
test boilers suggest that most of the CWM
ash (75 to 95 percent) is emitted as fly
ash, some combustion tests on coal
slurries have shown significantly lower
fly ash emissions. Ash deposition in the
boiler may cause the reduced measured
PM emissions.
SO2 Emissions
Emissions of SOzfrom CWM combustion
are a direct function of the fuel sulfur
content. The CWM sulfur content is in
turn determined by the sulfur content of
the coal used to make the CWM and the
percentage of coal present in the CWM.
At least 95 percent of the fuel sulfur is
typically emitted as S02. But CWMs made
with coal that has highlyalkalineash may
emit slightly less than 95 percent of the
fuel sulfur since the alkaline ash retains
some of the fuel sulfur.
/VOx Emissions
Emissions of NOX from boilers firing
CWM are more difficult to quantify for all
potential applications than are SOz and
PM emissions. For any boiler NOx
emissions can vary not only with CWM
fuel composition, but also with the
amount of combustion air (excess air)
and, in some cases, with boiler load.
Properties of the CWM fuel that influence
NOx emissions are the nitrogen content of
the coal used to make the CWM and the
percent coal in the CWM. 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.
Although limited test data are available
for NOx emissions from CWM-f iring, they
indicate that emissions from CWM
combustion should follow the same
trends as those noted for the parent coal.
Trace Element Emissions
Trace elements in the CWM fuel exit
the boiler either with the bottom ash or
with the flue gas, if ash deposition in the
boiler is not significant. 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 CWM properties (trace element
concentration).
The combustion temperature determines
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 between
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.
Data on three coals show that coal has
higher concentrations of As, Be, Cr, Hg,
and Se than does oil. Residual oil has
higher concentrations of Cd, Ni, and V.
Thus, combustion of CWMs would likely
result in higher emissions of As, Be, Cr,
Hg, and Se, but lower emissions of Cd, Ni,
and V, than would the combustion of oil
alone.
Polynuclear Organic Material
(POM)
The amount of POM emitted from any
combustion source is dependent on the
formation and the transformation mecha-
nisms 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 is available to
indicate that POM forms in the vapor
phase and later condenses on flue gas
particulate matter. POM formation is
related to combustion efficiency, and
POM transformations are related to boiler
and downstream flue gas temperatures.
POM emissions from CWM combustion
were not quantified in the recent studies.
However, when properly fired, oil-only
combustion has been shown to contribute
almost no POM emissions to the environ-
ment while coal-only combustion produces
POM emissions in unpredictable patterns.
Applicable Control
Technologies
Pre-combustion Techniques for
PM/SOz: Physical Coal
Cleaning
Physical coal cleaning is a pre-combus-
tion control technique employed by
coal/CWM producers to reduce the ash
and sulfur content of coals used to
prepare CWMs, and consequently reduce
the PM and SO2 emissions resulting from
CWM combustion. It is expected that
physical coal cleaning will be applied to
all coals used in CWMs.
Physical coal cleaning can be defined
generally as the separation of waste or
unwanted "refuse" materials from coal
by techniques based on differences in the
physical properties of coal and refuse.
Each coal cleaning facility is unique in its
treatment of coal. Each cleaning process
depends on the characteristics of the coal
to be treated and the desired specifications
for the cleaned coal. The sulfur removal
-------
efficiencies of physical coal cleaning
processess range from about 13 percent
for simple crushing and screening
separation processes to about 70 percent
for the most intensive cleaning processes.
The sulfur removed by these processes is
pyritic sulfur. The organic sulfur can only
be removed by chemical modification of
the coal structure. Thus, the amount of
sulfur removal possible by physical coal
cleaning is limited by the presence of
organic sulfur. Similarly, ash removal
capabilities range from about 10 to 75
percent.
It is unlikely that physical coal cleaning
alone will reduce ash content to levels
such that no post-combustion PM controls
are required to meet air pollution regulations.
In many cases, however, physical coal
cleaning can reduce the sulfur content of
the coal to a level such that no additional
controls for SO2 emissions are required.
Even if physical coal cleaning alone
cannot achieve adequate PM and SC>2
control, it can substantially reduce the
amount of costly post-combustion control
required. It also reduces the variability of
the CWM composition, permitting tighter
boiler and control design specifications.
One disadvantage of physical coal
cleaning is that, although it reduces the
quantity of fly ash/bottom ash and wet
sludge generated at the boiler site, it has
a net effect of increasing the amount of
solid waste generated. In any cleaning
process, some valuable combustible
matter is lost as refuse, along with
undesired inorganic materials. The
amount of valuable coal lost as refuse
ranges from about 5 to 50 percent,
depending on the cleaning process and
coal composition. Liquid waste impacts
are also associated with physical coal
cleaning processes; some facilities are
minimizing liquid waste disposal require-
ments by recycling process water.
Physical coal cleaning facilities are
subject to EPA standards for air (fugitive
emissions) and water quality, and MSHA/
OSHA regulations for refuse disposal.
Combustion Modifications for
NOX Reduction
Combustion modification techniques
for N0« control include: low excess air
(LEA) operation, staged combustion, flue
gas recirculation (FGR), and low-NO*
burners. Limited data are available on the
effectiveness of these combustion modifi-
cation techniques in reducing NOX
emissions from CWM combustion. How-
ever, NOx emissions from CWM combus-
tion are expected to be similar to those
from combustion of moist coal.
Low-NOx burners are the most effec-
tive of the candidate NOX control techno-
logies examined in this study. Low-NOx
burner designs typically incorporate LEA,
staged combustion, and/or internal FGR.
Low-NO, burners available for pulverized
coal service can potentially reduce
uncontrolled NO* emissions by 65 to 90
percent. Staged combustion is a relatively
effective NOx control technology. The
effectiveness of staged combustion in
reducing NOx emissions results from the
formation of localized fuel-rich conditions
in the primary combustion zone which
minimize formation of both thermal and
fuel NOX. Staged combustion has been
shown to achieve 40 to 50 percent
reductions in NOx emissions when
applied to coal units. Operation at low
excess air (LEA) levels is primarily
effective in reducing thermal NOX. LEA is
generally incorporated as a design and
operating feature in new boilers since it
increases boiler efficiency and thus
reduces fuel consumption. FGR is most
effective in reducing thermal NOx and is
therefore not a very effective NOx control
technique for coal firing due to the high
fuel nitrogen content of coal relative to
other fuels. FGR will likely be ineffective
for CWM firing as well.
Post-Combustion Control
Techniques for PM
The emission reduction capabilities of
two PM control technologies were
examined in this study: electrostatic
precipitators (ESPs), and fabric filters.
High paniculate matter control efficiencies
(98 percent or greater) have been widely
demonstrated with ESPs and fabric
filters. In general, these technologies can
reduce fly ash emissions to 43 ng/J (0.1
lb/108 Btu), and in most cases to 21.5
ng/J (0.05 lb/106 Btu) or less. Fabric
filters, generally more effective than
ESPs, are not as sensitive to changes in
fly ash resistivity, particle size distribution,
or inlet grain loading.
Post-Combustion Control
Techniques for PM/SOz
Two post-combustion control techniques
for combined PM/S02 removal evaluated
in this study are: wet flue gas desulfuriza-
tion (FGD), and spray drying FGD. These
control technologies are used primarily
for S02 control, but also achieve moderate
to substantial reductions in PM emissions.
Wet FGD systems can achieve 90 per-
cent removal of SOz or greater if they are
designed and maintained properly. Two
types of dry FGD systems appear to be
promising for CWM applications: spray
drying FGD and dry injection of sodium-
based compounds. Although these systems ^
are not as widely demonstrated as wet •
FGD systems, SOa removal efficiencies of
up to 90 percent have been reported for
coal-fired boilers.
Wet FGD systems are quite suitable for
combined SOa and PM removal. Combined
SOa/PM control with this system favors
venturi scrubbers, possibly preceded by a
mechanical collector. Substantial combined
SO2/PM control is also achievable with
dry scrubbing systems; e.g., spray drying
(since they include a fabric filter or an
ESP) and 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 disposal prob-
lems than the disposal of calcium-based
wastes from spray drying or wet FGD sys-
tems.
Post- Combust/on
Techniques for NO* Control
Post-combustion control techniques
for NOx include ammonia injection (e.g.,
Exxon's "thermal De-N0x") and flue gas
treatment (FGT) techniques. These
control techniques have not been applied
widely to sources in the U.S. since
existing emission limits can be met by fuel ^
switching or by combustion modification. •
NOx FGT is, however, well developed in
Japan where NOX emission limits are
more stringent.
NOX FGT processes can be classified as
either dry or wet. The major wet FGT
processes include absorption-reduction,
absorption-oxidation, and oxidation-
absorption; the major dry FGT processes
are selective catalytic reduction (SCR) and
selective non-catalytic reduction with
ammonia (or thermal De-NOx, as developed
by Exxon). NOx emission reductions of up
to 90 percent may be achievable with
these FGT processes.
Trace Element Control
Technologies
The technologies that achieve the
greatest degree of fine paniculate 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 and ESPs achieve the greatest
degree of trace element control. In
addition, physical coal cleaning can
reduce emissions by reducing trace
element concentrations in the fuel prior
to combustion.
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Cost Impact of Control
Technologies
The cost impacts of various PM, SO2,
and NOx control technologies for boilers
firing CWM were evaluated in terms of (1)
capital costs, (2) annual operating and
maintenance (O&M) costs, (3)annualized
costs, and (4) cost effectiveness. The
impacts of various PM and SO2 control
technologies were evaluated for three
CWM boiler sizes and four CWM fuels.
The boiler sizes examined were: 8.8 MW
(30 x 10s Btu/hr), 73 MW (250 x 106
Btu/hr), and 205 MW (700 x 106
Btu/hr).The CWM fuels for which control
technology costs were calculated were
selected from typical cleaned coal.
Uncontrolled SC>2 and PM emission rates
were calculated assuming that (1) all of
the fuel sulfur is emitted as SO2, and (2)
80 percent of the CWM ash is emitted as
fly ash. Each CWM fuel was assumed to
be a 70:30 mixture of coal and water. The
costs of PM and S02 control technologies
presented in the report are based
primarily on the technology costs used in
the EPA's development of Industrial
Boiler New Source Performance Standards
(NSPS).
Comparison of FGD System
Costs
The costs of dual alkali, spray drying,
and dry injection FGD systems are
compared in Figure 1 as a function of
boiler size for units firing various CWM
fuels. The costs are based on a 70percent
SO2 removal efficiency and a 60 percent
annual capacity factor. The relative costs
of the three FGD systems for specific
applications may be altered due to site-to
site variations in SO2 removal, boiler
capacity, reagent costs, or availability of
existing equipment to reduce retrofit costs.
Dry injection FGD has the lowest
capital costs up to a boiler size of about
100 x 106 Btu/hr. However, wet FGD has
the lowest capital cost of the three
systems for boilers larger than this size.
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 PM emission control
levels achievable with fabric filters,
relative to a wet FGD system used for
combined SOz/PM removal, result in
higher waste disposal costs. An ESP
would likely be required upstream of the
wet FGD to achieve the same PM
emission level.
In comparing the annualized costs for
three FGD systems, wet FGD had the
lowest annualized cost for boilers above
4,000
5 3,ooo
«>
$
t>
I
"5
c
2,000
7,000
60% Annual Capacity Factor
70%SOzFtemoval
(NOTE: Costs shown here are
for specific CWMs and do not
represent all possible
control system costs.
Control costs may
differ from other CWMs.
combustion systems, and
control techniques.)
Dry Injection .
Dual Alkali
Figure 1.
59 116 174 232
(200) (400) (600) (800)
Boiler Size. MW (10s Btu/hr)
Annualized costs of three FGD systems applied to boilers firing a high ash, high
sulfur CWM.
about 100 x 106 Btu/hr. Below 100 x 106
Btu/hr, dry injection is the least expensive
alternative, but its costs increase rapidly
as a function of boiler size and it is the
most costly alternative at the larger boiler
sizes.
J. H. E. Stalling and S. J. Call are with Radian Corp., 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/Liquid Mixture Combustion," (Order No. PB 84-137 231; Cost: $20.50.
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, NC 27711
-------
United States
Environmental Protection
Agency
Official Business
Penalty for Private Use $300
Center for Environmental Research
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