Document ID: EPA-HQ-OAR-2008-0260-0149
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2009-10-08T04:00Z

MEMORANDUM

From:		Mary Johnson

To:		Coal Preparation NSPS Docket (EPA-HQ-OAR-2008-0260)

Date: 		September 2009

Subject:	Thermal Dryers at Coal Preparation and Processing Plants –
Revised

Introduction

There are four basic approaches to drying coal:  mechanical drying,
once-through thermal dryers, recirculation thermal dryers, and indirect
thermal dryers.  Mechanical drying is primarily used at coal mines and
involves either compressing the coal, spinning the coal in a centrifuge,
or using a vacuum to separate out the liquid moisture.  In once-through
and recirculation thermal dryers, a fossil fuel is combusted to create a
hot gas, and the coal is then dried through evaporation.  In both of
these types of dryers, the combustion gas is too hot to be used directly
and is tempered with either air or exhaust gas.  Once-though thermal
dryers use air to cool the combustion gases; recirculation dryers use
flue gases to cool the combustion gases prior to the drying chamber. 
Once-though and recirculation thermal dryers are used at coal mines and
end-use locations, and both are able to remove more moisture than
mechanical drying.  In an indirect thermal dryer, a transfer medium
supplies heat to the drying chamber and the exhaust gas never comes into
direct contact with the coal being dried.

The type of coal drying technology used at a given facility is
influenced by a variety of factors, including type of facility, coal
moisture reduction requirements, availability of waste heat sources at
the coal processing location, and drying process energy requirements
including electrical power consumption.  There are two basic types of
moisture in coal, free and inherent.  Mechanical drying techniques
(centrifuge, vacuum, compression, etc.) and chemical additives can
remove free moisture adsorbed onto the surface of the coal particles and
a portion of the hydroscopic moisture contained by capillary action
within microfractures in the coal particles, but are ineffective at
removing inherent moisture (and, thus, would only be applicable at
preparation plants utilizing coal washing).  Some type of thermal energy
is required to remove the interstitial and molecular (inherent) moisture
from the coal for applications where extremely low moisture content is
desirable.  Therefore, mechanical drying techniques are not suitable
replacements for thermal dryers under all circumstances, and because
waste heat is not available at all locations, thermal dryers using waste
heat are not a technically possible substitute for thermal dryers in all
situations.  It is typically less expensive for coal mines that employ
coal washing to use mechanical drying instead of thermal drying; in
fact, a new thermal dryer has not been installed at a bituminous coal
mine in the past decade.  We expect this trend to continue, and that few
new bituminous coal thermal dryers will be built at coal mines in the
future.  Instead, we anticipate that mechanical dryers will be built at
coal preparation plants using wet cleaning processes, and limited
numbers of small, natural gas-fired thermal dryers will be installed at
end-user facilities (e.g., metal manufacturing).  We further expect that
indirect thermal dryers will become more common at power plants as part
of an effort to improve efficiency and reduce greenhouse gas emissions.

Most existing thermal dryers located at mines are coal-fired and utilize
once-through technology, where the furnace gas is cooled with ambient
air prior to entering the drying chamber.  These designs have
approximately 17 to 18 percent oxygen in the drying chamber, and a
cyclone followed by a high-energy wet scrubber is typically used to
control particulate matter (PM) emissions.  The combination of coal
fires and higher oxygen content make a baghouse (fabric filter) or
electrostatic precipitator (ESP) subject to explosions.

New coal-fired thermal dryers could be designed as recirculation dryers
instead of once-through dryers.  Recirculation dryers could use flue gas
recirculation in which up to 90 percent of the exhaust gas is
recirculated back to the furnace for temperature tempering.  There are
several advantages to this approach.  First, recirculation thermal
dryers operate at between 1 and 3 percent oxygen concentration, and a
baghouse can be used because the inert environment (i.e., lower oxygen
content) eliminates the explosion hazard.  A baghouse typically controls
fine PM better than a wet scrubber, uses less energy to operate, has
annual costs of approximately one-third that of a high energy venturi
scrubber, and allows the recovery of fine coal that is otherwise sent to
a slurry impoundment.  In addition, recirculation thermal dryers are
more efficient at drying coal than once-through designs and result in
lower emissions per ton of coal dried.  Finally, because the flue gas is
recirculated, the pollutants are more concentrated, potentially making
post combustion controls more cost effective.  Considering the
advantages of a recirculation thermal dryer, we have concluded that a
new facility located at a mine would use this design.  EPA is aware of
two facilities (Amax Coal Company’s Belle Ayr thermal dryer in Wyoming
and the Dendrobium thermal dryer in Australia) that use recirculation
thermal dryers and use fabric filters to control PM emissions.

Indirect thermal dryers use a heat transfer medium, such as a metal
shell, to supply heat to dry the coal, and the exhaust gas never comes
in direct contact with the coal.  The primary advantage to this approach
is that significantly less off-gas is created and drying occurs at low
temperatures, meaning that waste heat from condensing water at power
plants, as well as the flue gas, can be used.  Because no additional
fuel is combusted and the moisture reduction improves the power plant
efficiency, the process reduces overall fuel use and decreases
emissions.  Also, because drying occurs at low temperatures, there are
minimal volatile organic compound (VOC) emissions, which normally occur
in other types of thermal dryers as a result of the more volatile
hydrocarbons being evaporated from the coal.  We have identified one
indirect thermal dryer recently installed to dry lignite at the Great
River Energy Coal Creek Power Plant in North Dakota.

Approach to Selecting Emissions Standards

When developing the proposed standards for thermal dryers, we concluded
that it is appropriate to use a fuel-neutral approach.  This approach
dictates that emission standards should be as neutral as possible
between clean fuels (fuels that have inherently low emissions) and other
fuels.  We proposed to adopt this approach in order to set a nationwide
emission standard that can be achieved by all new facilities in this
source category, including facilities that do not have long-term access
to clean fuels at a reasonable cost.  In addition, we have concluded
that most coal mines are located away from major population centers and
are not connected to the natural gas distribution system; therefore, use
of natural gas as the thermal dryer fuel at these coal mines is not an
economic option.  Consequently, we concluded that the thermal dryer
limit should be based on the best demonstrated technology (BDT) for
controlling emissions from coal-fired thermal dryers.

We contacted State environmental agencies to collect emissions
information for thermal dryers.  Although some natural gas-fired thermal
dryers have recently been permitted, none yet have been constructed. 
Thus, we were not able to collect emissions information for natural
gas-fired thermal dryers.  However, because we expect that natural
gas-fired thermal dryers will generally have lower emissions when
compared to coal-fired thermal dryers, and the standards proposed in
this supplemental proposal are based on emission rates achievable by
coal-fired thermal dryers, we expect that owners/operators electing to
use a fuel with better combustion characteristics than coal (such as
natural gas) will also be able to meet the proposed emissions limits.

Coal-fired direct contact once-through thermal dryers represent the
majority of existing thermal dryers, and most of these control emissions
with wet scrubbers.  However, no such facilities have been built in the
last decade.  Therefore, we concluded that the control technology and
emissions rates from the best-performing existing coal-fired thermal
dryers do not necessarily represent BDT for a new thermal dryer.  For
this reason and for the reasons explained below, we also collected
information on the control technologies used, and emission rates
achieved, by recently constructed industrial coal-fired boilers. 
Industrial coal-fired boilers use similar burner and combustion
technologies as coal-fired thermal dryers.  Combustion-related controls
used to achieve emissions reductions in coal-fired industrial boilers
are directly transferable to coal-fired thermal dryers.  We used these
data to establish the new source performance standards (NSPS) for newly
constructed thermal dryers at coal preparation plants.  For the reasons
explained below, however, we determined that it was appropriate to
establish different standards for reconstructed facilities and for
modified facilities.  We used performance data from the best-performing
existing facilities to determine the appropriate standards for both
facility categories.

Pollutants Emitted

Emissions from a thermal dryer contain, among other things, substantial
amounts of PM, sulfur dioxide (SO2), nitrogen oxides (NOX), and carbon
monoxide (CO).  PM is associated with premature mortality and a number
of serious adverse respiratory and cardiovascular effects, especially in
children, the elderly, and people with existing heart or lung disease. 
PM also reduces visibility and damages building materials.

SO2 is a criteria pollutant and is considered harmful to public health
and the environment.  It contributes to respiratory illness,
particularly in children and the elderly, and aggravates existing heart
and lung diseases.  It also contributes to acid deposition and damage to
forests, aquatic ecosystems, crops, and building materials.  SO2
undergoes chemical reactions in the atmosphere to form sulfate PM.

Nitrogen dioxide (NO2) (measured collectively along with other nitrogen
oxide compounds as the surrogate compound NOX) is a criteria pollutant
and is regulated due to its contribution to ozone formation.  Exposure
to ozone has been linked to negative health and welfare impacts and
includes impaired respiratory function, eye irritation, deterioration of
materials such as rubber, and necrosis of plant tissue.  NOX is also a
major precursor for nitrate PM.  NOX can cause irritation of the lungs
and can also reduce resistance to respiratory infection.  Because of its
contribution to tropospheric ozone, NOX is also an indirect greenhouse
gas (GHG).  However, like tropospheric ozone, NOX increases hydroxyl
(OH) abundance, which in turn decreases the atmospheric lifetime of
potent GHGs like methane.

CO is a criteria pollutant and is considered harmful to public health
and the environment.  It has been linked to increased risk to heart
disease, reduced visual perception, cognitive functions and aerobic
capacity, and possible fetal effects.  CO is a weak GHG on its own. 
However, CO reacts with atmospheric OH to function as an indirect GHG,
because decreased concentrations of OH in the atmosphere increase the
atmospheric lifetime of stronger GHGs like methane.

Affected Facilities and Regulated Pollutants

Subpart Y presently establishes PM and opacity limits for thermal dryers
that dry bituminous coal where the exhaust gas comes in direct contact
with the coal.  In the April 2008 proposal, we proposed to amend the PM
limit for direct contact thermal dryers drying bituminous coal.  Thermal
dryers that dry non-bituminous coals and dryers that reduce the moisture
content of the coal through indirect heating using a heat transfer
medium are not presently subject to any emission standards.  We received
comments suggesting that we include indirect thermal dryers and thermal
dryers drying all coal ranks as affected facilities.  In addition,
commenters suggested we include limits for all other criteria pollutants
emitted from thermal dryers.

Based on our review of public comments and subsequent analysis, in the
May 2009 supplemental proposal we proposed to expand the coverage of
subpart Y to include emission standards for thermal dryers drying all
ranks of coals, as well as for indirect thermal dryers, and to add both
an SO2 standard and a combined NOX - CO standard for thermal dryers that
exhaust the combustion gas directly to the atmosphere.  Indirect thermal
dryers that use waste heat, such as the Great River Energy facility,
would only be subject to the PM limit because the exhaust gases used to
supply the heat are not generated via combustion.  Venturi scrubbers and
fabric filters control PM equally well regardless of the source of PM,
and we have concluded that all coal thermal dryers using similar control
technologies will have comparable emissions rates.  In addition, subpart
Y was originally promulgated in 1976 and additional pollution control
technologies have become available since then.

PM Standard

In the April 2008 proposal, we proposed to revise the PM limit for
thermal dryers that dry bituminous coal from 0.070 grams per dry
standard cubic meter (g/dscm) (0.031 grains per dry standard cubic foot
(gr/dscf)) to 0.045 g/dscm (0.020 gr/dscf).  We received comments that
this limit would be prohibitively expensive for modified and
reconstructed units to achieve, but that the limit should be lower for
new units.

Based on our review of public comments and subsequent analysis, in the
May 2009 supplemental proposal, we proposed different PM limits for new,
reconstructed, and modified units.  The physical layout of existing
thermal dryers makes it more expensive to reduce emissions from existing
dryers than from new or reconstructed units.  The majority of existing
coal-fired thermal dryers are once-through designs that use cyclones
followed by a high-energy wet scrubber to control PM emissions. 
Existing facilities sometimes have the exhaust fan located on top of the
dryer and use a short, narrow exhaust stack.  In general, to
significantly improve the PM emissions reduction of these units, the
facility would have to relocate the exhaust fan to the ground, demolish
the existing stack, and construct a wider, taller stack.  In the event
of a minor modification of an existing facility, this retrofit would be
cost prohibitive and, unless the entire control system was redesigned,
it could potentially be difficult to control PM emissions under various
load conditions.  Therefore, we proposed to maintain the PM limit for
modified facilities at the existing limit of 0.070 g/dscm (0.031
gr/dscf).  We noted in the supplemental proposal that a PM standard of
between 0.060 g/dscm (0.026 gr/dscf) and 0.070 g/dscm (0.031 gr/dscf)
was being considered for the final rule.  Recognizing the limitations
that may be associated with the physical layout of existing dryers, the
final rule retains the same limits for PM as those in the supplemental
proposal.

However, because reconstructed facilities could take this design
consideration into account during the reconstruction process, we
proposed to maintain the PM limit in the April 2008 proposal at 0.045
g/dscm (0.020 gr/dscf) for reconstructed facilities.  This level of
control has been demonstrated to be consistently achievable at several
existing facilities (e.g., the Consolidation Coal Company’s Loveridge
thermal dryer in West Virginia, the Mettiki Coal thermal dryer in
Maryland, the Island Creek Coal Company’s VP#8 Deskins Garden thermal
dryer in Virginia, and the Consol Coal Company’s Bailey #2 thermal
dryer in Pennsylvania), and we have concluded that a reconstructed
facility could design a PM control strategy based on conventional wet
scrubbing that could achieve this emissions rate at all evaporative load
rates.

Based on comments received, and on a review of the data, we have
concluded that units undergoing reconstruction as defined in the CAA
could undergo the conversions necessary to install BDT for PM emissions
control for new thermal dryers and, thus, meet the PM and opacity limits
of new facilities.  Therefore, we have concluded that reconstructed
thermal dryers could also employ fabric filters applied to recirculation
thermal dryers and indirect thermal dryers.  The PM and opacity
standards in the final rule are based on these conclusions.

As described earlier, new thermal dryers would likely be designed as
either a coal-fired recirculation thermal dryer or an indirect thermal
dryer.  BDT for controlling PM emissions from these types of dryers is a
fabric filter.  An assessment of the costs of a fabric filter on a 30
ton per hour natural gas-fired recirculating thermal dryer and a 135 ton
per hour waste heat-fired indirect thermal dryer indicate
cost-effectiveness of under $500/ton of PM for both model dryers.  An
estimated 323 tons per year and 14,214 tons per year of solid waste
would be generated by the recirculating thermal dryer and the indirect
thermal dryer, respectively.  See Thermal Coal Dryer Model Plant
Analysis in Docket EPA-HQ-OAR-2008-0260 for calculation details.

Data collected to date demonstrates that fabric filters on such
facilities can achieve low emission rates.  Both the Belle Ayr and Coal
Creek thermal dryers use a fabric filter to control PM emissions and
have measured emissions rates of 0.0048 and 0.0031 gr/dscf,
respectively.  Based on this data and recent permit limits for new
thermal dryers using a baghouse (Auburn Nugget’s coke production
facility in Indiana, Iron Dynamics’ coke production facility in
Indiana, and Dendrobium), we proposed in the May 2009 supplemental
proposal a PM limit of 0.023 g/dscm (0.010 gr/dscf) and less than 10
percent opacity for new facilities.  This limit would provide an
adequate compliance margin for new/reconstructed units and is lower than
the April 2008 proposed limit of 0.045 g/dscm (0.020 gr/dscf).  The
April 2008 limit, however, would have applied to new, reconstructed and
modified facilities.  EPA is maintaining the PM limit of 0.023 g/dscm
(0.010 gr/dscf) and less than 10 percent opacity for new facilities in
the final rule.

It is important to note that although the standard is based on the use
of a fabric filter, a new/reconstructed facility would not be required
to use any specific control technology.  Our analysis demonstrates that
a new facility could use a once-through dryer design and achieve the PM
standard using a wet scrubber to control PM emissions.  We identified
two wet-control approaches that an owner/operator of a new facility
could use to achieve this limit.  The first approach is to use a
high-energy venturi scrubber.  We analyzed the incremental cost
effectiveness of the increased pressure drop necessary to achieve the
proposed PM limit for a model thermal dryer.  To estimate the
incremental control cost of using venturi scrubbers, we used the sixth
edition of the OAQPS Control Cost Manual.  The model thermal dryer
assumes an inlet PM loading of 7.0 g/dscm (3.0 gr/dscf), a flow rate of
260,000 actual cubic feet per minute (acfm), and a 64 percent capacity
factor.  Table 1 lists the incremental costs for each PM emissions rate,
the energy requirements, and the increased indirect power plant
emissions, assuming an emissions rate equivalent to the current subpart
Da requirements.

Table 1:  Incremental PM Control Costs

PM Emissions Rate (gr/dscf)	Annual PM Emissions (tons)	Pressure Drop
(inches H2O)	Incremental Control Cost ($/ton in 2007 $)	Annual Energy
Use (MWh)	Indirect Power Plant Emissions

	PM (tons)	NOX (tons)	SO2 (tons)	CO2 (tons)

0.031	150	28

8,000	0.56	4.0	5.6	8,000

0.020	96	35	3,100	10,000	0.70	5.0	7.0	10,000

0.015	72	40	3,700	11,000	0.79	5.7	7.9	11,000

0.010	48	49	6,900	14,000	0.98	7.0	10	14,000

0.0050	24	70	16,000	20,000	1.4	9.8	14	20,000

Based on this analysis, an emissions rate of 0.023 g/dscm (0.010
gr/dscf) would be cost effective for a new thermal dryer using a
high-energy venturi scrubber to control PM emissions, even in the
absence of a baghouse or ESP.  We recognize that no recent coal-fired
thermal dryer has been constructed and that this level of control has
not yet been demonstrated on a subpart Y affected facility with wet
controls.  However, this level of control has been demonstrated at
comparable facilities.  For example, the Celite diatomaceous earth
facility in Santa Barbara, California, uses a venturi scrubber with a
pressure drop of 65 to 67 inches of water to control PM emissions from
an 80,000 acfm, 120 oC exhaust gas stream and has a permitted PM limit
of 0.011 g/dscm (0.0050 gr/dscf).

An assessment of the costs to upgrade a venturi scrubber on a 200 ton
per hour direct contact thermal dryer such that it could achieve the PM
limit for new/reconstructed thermal dryers and of the resulting PM
reductions indicate a cost-effectiveness of $3,300/ton of PM (based on
estimated emission reductions of 90 tons per year at a cost of $300,000
per year).  An estimated 30 million gallons per year of waste water
would be generated and 4,200 megawatt hours per year of electricity
would be consumed.  See Thermal Coal Dryer Model Plant Analysis in
Docket EPA-HQ-OAR-2008-0260 for calculation details.

A venturi scrubber, moreover, is not the only wet control strategy an
owner/operator could use to control PM emissions.  To decrease power
requirements, a low-pressure tray scrubber could be used to remove the
majority of the PM emissions, and then either a wet ESP or cloud chamber
could be used to remove the remaining fine PM.  Both a wet ESP and cloud
chamber have demonstrated an ability to control PM emissions to below
0.023 g/dscm (0.010 gr/dscf) with less than 10 percent opacity.

PM2.5 and Condensible PM

In the April 2008 proposal, we proposed a single PM limit based on total
filterable PM.  Commenters suggested we include separate requirements
for condensable PM, filterable PM2.5, and filterable PM10.  Based on our
review of public comments and subsequent analysis, in the May 2009
supplemental proposal we concluded that we have insufficient emissions
and control data and did not propose to set separate limits for
condensable PM, filterable PM2.5, or filterable PM10 emissions.  In
addition, there are currently concerns about artifact measurements in
Method 202, the EPA-approved method for measuring condensable PM
emissions, and we do not expect to promulgate revisions addressing these
concerns until early 2010.  Because we do not presently have a
consistent approach for measuring condensable PM, we do not have
sufficient data to establish a limit or determine the control efficiency
of different control technologies.  In addition, PM performance test
data generally measure total filterable PM emissions; size separation is
presently only possible for dry stacks.  Because all existing thermal
dryers subject to subpart Y have wet stacks, at this time we do not have
sufficient performance test data on condensable PM or PM2.5 emissions
from thermal dryers to determine what limits would be reasonable.

SO2 Standard

SO2 emissions from a thermal dryer are a function of the sulfur content
of the fuel burned in the dryer.  However, measured SO2 emissions are
often less than what would be theoretically predicted based on the
sulfur in the fuel burned assuming all of the sulfur in the coal is
emitted as SO2.  There are 2 possible reasons for this discrepancy. 
Either SO2 emissions are reduced by the wet scrubber installed to
control PM or a portion of the SO2 is adsorbed as sulfuric acid into the
pores of the coal being dried (due to the reaction of the SO2 with
oxygen in the flue gas).  Emissions data for SO2 controls from
coal-fired thermal dryers are limited, and at this time it is not
possible for us to determine the full extent to which each mechanism is
reducing emissions.  Only the PBS Coals Cambria Slope thermal dryer in
Pennsylvania has done a detailed analysis of the mechanism controlling
SO2 emissions.  During the 1998 performance test, this facility burned
coal with a theoretical emissions rate of 1.2 lb SO2/MMBtu and achieved
an overall control efficiency of 58 percent.  Approximately 22 percent
of the SO2, 0.26 lb/MMBtu, was absorbed onto the coal and 35 percent,
0.42 lb/MMBtu, was collected as a co-benefit in the venturi scrubber. 
In addition, based on the emissions data from other sources using
venturi scrubbers primarily for PM control, it appears that the majority
of SO2 control occurs as a co-benefit of the wet scrubber.  The
measurements of SO2 emissions from thermal dryers with wet scrubbers
collected for this review range from 0.02 to 1.9 pounds per million
British thermal units (lb/MMBtu) and, for the sources reporting removal
efficiencies, overall control efficiencies range from 50 to 98 percent.

Existing facilities presently use two techniques to specifically control
SO2 emissions.  The first approach is to spray a caustic solution (e.g.,
sodium hydroxide, NaOH) on the coal before it enters the drying chamber.
 The caustic reacts with the SO2 in the drying chamber and forms a salt
(sodium sulfate, Na2SO4) that is collected in the PM control device. 
The other approach is to add caustic directly to the wet scrubber fluid
and control SO2 along with PM.  Wet scrubbers designed for SO2 control
are able to achieve greater than 95 percent reduction.  However, the wet
scrubbers used on existing thermal dryers are designed for PM control
and not specifically for SO2 control.  Therefore, high levels of SO2
control might be difficult to achieve without redesign of the scrubber
(e.g., different construction materials to handle the corrosion
resulting from use of the caustic solution, scaling deposits, and
plugging of liquid lines).  Nonetheless, if scaling deposit and plugging
of liquid lines were a concern, an owner/operator using a wet scrubber
to control SO2 could switch to newer scrubbing agents with a higher
solubility, such as calcium magnesium acetate.  Based on the performance
of the Mettiki facility and analysis of other venturi scrubbers used to
control SO2 emissions, we have concluded an existing thermal dryer with
a wet scrubber could achieve 90 percent reduction without a significant
redesign.

As discussed previously, BDT for controlling PM from a new thermal dryer
is a fabric filter-controlled recirculation thermal dryer or a fabric
filter-controlled indirect thermal dry, and we analyzed the incremental
cost of controls to reduce SO2 emissions from thermal dryers.  For low
cost reductions, we evaluated the use of dry sorbent injection or
spraying caustic on the coal prior to the drying chamber.  The caustic
approach is presently used at the Loveridge facility and the salt
produced is removed by the PM control device.  We do not have detailed
information on the contribution of each mechanism on overall SO2
control.  However, if we assume the same absolute amounts, in lb/MMBtu,
are controlled by absorption onto the coal and as a co-benefit of the
venturi scrubber as reported for the Cambria Slope facility, the caustic
spray achieves approximately 50 percent reduction in theoretical SO2
emissions.  We have not identified any facilities which apply sorbent
injection to a thermal dryer, but it has been applied to industrial and
utility boilers, and the technology is directly transferable to
coal-fired thermal dryers.  Various companies supply calcium- and
sodium-based sorbent reagents, and the technology can be used at any
facility with injection locations and sufficient residence time within a
temperature range of 130 oC to 430 oC.  A new thermal dryer could be
designed to include an injection site into the combustion gases above
the burners and prior to the drying chamber.  An advantage of using
sorbent injection in combination with a baghouse is that the sorbent
forms a cake on the bags and increases SO2 control.  Sorbent SO2 control
efficiencies vary between 30 and 60 percent for calcium-based agents and
can be as high as 90 percent for sodium-based agents.  Higher levels of
control have been achieved in boilers with sorbent injection, but this
control has not been applied to thermal dryers and we concluded that 50
percent would be a reasonable expectation.  Higher percent reductions
would be technically achievable with the addition of more sorbent, but
incremental costs would increase.  The cost per ton of SO2 controlled
using sorbent injection is approximately $1,000 per ton and is
considered cost effective for this source category. 

For all the reasons described above, we concluded for the May 2009
supplemental proposal that a 50 percent SO2 reduction is the standard
that can be achieved by the application of BDT to a thermal dryer.  As
described above, this standard reflects the degree of emissions
reduction achievable by both sorbent injection and caustic spray onto
the coal prior to the drying chamber.  Both techniques were considered
BDT for new, reconstructed, and modified thermal dryers.

Adding a wet scrubber for the sole purpose of controlling SO2 emissions
above 50 percent control has an incremental cost of over $5,000/ton of
SO2 controlled.  This higher cost is partially due to the fact that most
thermal dryers are not typically large, ranging from 100 to 200
MMBtu/hr, and are not major sources of SO2 emissions; these factors
result in the fixed costs of scrubbing units being high for smaller
facilities.  Thus, we concluded that wet scrubbers are not a
cost-effective control technology for this source category.  However, in
the event caustic spray or sorbent injection could not achieve a 50
percent reduction in theoretical emissions, a wet scrubber for the sole
purpose of SO2 control is cost effective.  In addition, an upper limit
of 520 ng/J (1.2 lb/MMBtu) is appropriate because control is easier and
more cost effective at high pollutant concentrations.  Adding a wet
scrubber to strictly control SO2 emissions for thermal dryers with a
theoretical emissions rate of 520 ng/J (1.2 lb/MMBtu) has an incremental
cost of less than $3,000/ton of SO2 controlled, and is considered
cost-effective for this source category.

Finally, our analysis also demonstrates that facilities with lower SO2
emission rates may not be able to consistently achieve design rate
percent reduction efficiencies because control is more technically
difficult at lower pollutant concentrations.  For this reason, we
proposed in the May 2009 supplemental proposal a lower, alternate limit
of 85 ng/J (0.20 lb/MMBtu).  A source that can meet the lower alternate
limit does not also need to demonstrate that it is reducing SO2
emissions by a specified percent.  This approach is consistent with the
approach used in the NSPS for steam generating units, subparts Da, Db,
and Dc.  We noted in the May 2009 supplemental proposal that an SO2
percent reduction requirement of between 50 and 90 percent would be
considered for the final rule.

Based on comments received and a review of the data, EPA determined that
BDT for modified and reconstructed thermal dryers for controlling SO2
emissions from coal dryers for the final rule is a wet scrubber with a
scrubbing reagent (e.g., an upgraded venturi scrubber with sodium
hydroxide or packed bed scrubber with lime).  The information that EPA
has indicates that all of the once-through direct contact thermal dryers
currently use venturi scrubbers for PM control.  Thus, the upgraded
venturi scrubber with sodium hydroxide or the packed bed scrubber with
lime (would be in addition to the venturi scrubber) would provide SO2
control, along with additional PM control necessary for reconstructed
thermal dryers to meet their PM and opacity limits.  For new thermal
dryers, we determined that BDT for controlling SO2 emissions is the
injection of sodium hydroxide directly to the venturi scrubber fluid or
injection of a sodium-based sorbent into the combustion gases prior to
the drying chamber.  For a new once-through direct contact thermal
dryer, the caustic injection into the scrubber fluid for SO2 control
would be in addition to a high-energy venturi scrubber which is the
likely control technology that would be used for PM and opacity control.
 For a new coal recirculation thermal dryer, sorbent injection into the
combustion gases for SO2 control would be used in conjunction with a
fabric filter which is the likely control technology that would be used
for PM and opacity control.  An assessment of the costs to upgrade a
venturi scrubber to be capable of adding a scrubbing reagent on a 200
ton per hour direct contact thermal dryer such that it could achieve the
SO2 limits for new/reconstructed/modified thermal dryers and of the
resulting SO2 reductions indicate a cost-effectiveness of under $2,000
per ton of SO2.  See Thermal Coal Dryer Model Plant Analysis in Docket
EPA-HQ-OAR-2008-0260 for calculation details.  As previously explained,
we have concluded an existing thermal dryer with a wet scrubber could
achieve 90 percent reduction without a significant redesign, and the
cost per ton of SO2 controlled using sorbent injection is approximately
$1,000 per ton.  For those reasons and based on a review of the
available data, we believe that a 90 percent removal requirement is
appropriate for new, reconstructed, and modified thermal dryers; this is
reflected in the final rule.  Affected facilities that meet the
alternative SO2 emissions limit of 85 ng/J (0.20 lb/MMBtu) heat input
are not required to meet this requirement.

Combined NOX and CO Standard

Although advanced combustion controls can achieve both low NOX and CO
emissions, the pollutant emissions rates are related.  NOX reduction
techniques that rely on delayed combustion and lower combustion
temperatures tend to increase incomplete combustion and result in a
corresponding increase in CO and VOC emissions.  To account for
variability in combustion properties and to provide additional
compliance strategy options for the regulated community, while still
providing an equivalent level of environmental protection, we proposed
in the May 2009 supplemental proposal to establish a combined NOX and CO
limit.  The combined limit for new sources would be 280 ng/J (0.65
lb/MMBtu), and the combined limit for modified and reconstructed units
would be 520 ng/J (1.0 lb/MMBtu).  The Bailey #2 and Buchanan # 1
thermal dryers have demonstrated that this level is achievable for
existing units.  For new units, we evaluated what emissions limits we
would propose individually for NOX and CO to arrive at the combined
limit.  We have previously established combined emissions limits for
pollutants that are inversely related in the NSPS for stationary
compression ignition internal combustion engines, subpart IIII.

Based on comments received and a review of the data, we are maintaining
the combined NOX and CO limits established in the May 2009 supplemental
proposal for the final rule.

NOX Controls

NOX emissions from coal thermal dryers primarily occur via two
mechanisms.  The main source, thermal NOX, is formed when nitrogen and
oxygen in the combustion air react at high temperatures.  Fuel NOX is
due to the reaction of fuel-bound nitrogen compounds with oxygen.  NOX
emissions can be minimized through two general control strategies: 
combustion controls and post-combustion controls.  Combustion controls
limit the formation of NOX, whereas post-combustion controls convert NOX
to nitrogen and oxygen prior to release to the atmosphere.  We are not
presently aware of any coal-fired thermal dryers that use
post-combustion controls.

Post-combustion controls include selective catalytic reduction (SCR),
selective non-catalytic reduction (SNCR), non-selective catalytic
reduction (NSCR), and catalytic oxidation/absorption (SCONOX).  NSCR is
not technically feasible for a thermal dryer because the combustion
process must be near stoichiometric conditions (i.e., conditions at
which the proportion of the air-to-fuel is such that all combustible
products will be completely burned with no oxygen remaining in the
combustion air) in order to operate properly.  Thermal dryers require
excess air to operate properly, and because NSCR does not work in the
presence of oxygen it was not evaluated as a viable control technology.

SCR controls cause ammonia to react with NOX in the presence of a
catalyst to form water and nitrogen.  Ammonia is injected into the
exhaust gas prior to the gas entering a catalyst bed.  The operating
temperature for conventional SCR is between 260 oC to 430 oC and removal
efficiencies can be as high as 90 percent.  Efficient operation of an
SCR requires fairly constant exhaust temperatures.  This constant
temperature window is not available in the thermal dryer, and
conventional SCR, therefore, is not considered a viable control
technology.  High-temperature SCR operates at a temperature of
approximately 600 oC and could, in theory, be located after the burners
and prior to the drying chamber.  However, the high sulfur levels in the
flue gas contacting the SCR catalyst would likely lead to secondary
problems with sulfuric acid mist emissions.  This could result in both
corrosion of the thermal dryer and, if secondary controls are not
installed, harmful emissions.  Also, the high PM loadings could foul and
mask the catalyst.  High-temperature SCR has not been demonstrated to
work on a coal-fired thermal drying system and has only been applied to
simple cycle gas turbines.  Low-temperature SCR operates at temperatures
as low as 120 oC, which is significantly higher than the flue gas
temperature of a thermal dryer; therefore, low-temperature SCR is not
considered a viable control technology.

SNCR uses ammonia or urea to reduce NOX emissions through a chemical
reaction similar to SCR.  However, a catalyst is not required; instead,
a temperature range of 700 oC to 1,100 oC is necessary, depending on the
blend of chemicals used to control emissions.  This temperature window
does not typically exist in a thermal dryer, and SNCR is, therefore, not
considered to be a viable control technology.  In addition, unreacted
ammonia (ammonia slip) can react with the sulfur present in the exhaust
gas to produce fine PM, reducing the environmental benefit of the
decreased NOX emissions.  However, we continue to be interested in
additional information that would indicate if SNCR could be successfully
integrated into a new thermal dryer.

SCONOX is an emerging catalytic/adsorption technology that has been
applied to reduce NOX, CO, and VOC emissions from multiple types of
combustion applications.  SCONOX uses a single catalyst to convert CO to
carbon dioxide (CO2), NOX to elemental nitrogen and oxygen, and to
oxidize the VOC into CO2 and water.  For optimum performance without
harming the catalyst, the flue gas temperature should be between 100 oC
to 370 oC, which is significantly higher than the flue gas temperature
of a thermal dryer, and, therefore, is not considered a viable control
technology.

Combustion controls are the only viable NOX controls we identified that
could be used across the range of thermal dryers presently used in the
United States.  They include low NOX burners (LNB), staged combustion,
co-firing with natural gas or liquefied petroleum gas (LPG), and flue
gas recirculation (FGR).  LNB minimizes NOX formation through good fuel
mixing, restriction of oxygen, and minimization of peak flame
temperature.  The basic operating principles of LNB involve stepwise
combustion and local exhaust gas recirculation.  Stepwise combustion
delays the mixing of fuel and air to achieve an initial reduced oxygen
level in the combustion zone, which decreases fuel-generated NOX and
lowers peak flame temperature, in turn decreasing thermally-generated
NOX.  Oxygen-depleted exhaust gas recirculation lowers the peak flame
temperature and decreases the formation of thermal NOX.  LNB can also
reduce formation of thermal NOX if designed to minimize residence time
at peak temperatures.

Staged combustion reduces NOX by limiting the oxygen present at
temperatures where NOX formation is likely to occur and suppressing peak
flame temperatures.  Additional oxygen is added to complete the
combustion process after the initial fuel is burned.  Co-firing is the
use of small amounts (as low as 2 percent) of natural gas, LPG, or other
fuels with good combustion characteristics in the second stage of
combustion to enhance the performance of solid fuel boilers.  Co-firing
decreases NOX, CO, VOC, SO2, and PM emissions and is an easy retrofit
for most combustion sources.

FGR involves recirculating a portion of the dryer exhaust into the flame
with baffled burners.  The fuel is mixed with the combustion air and
recirculated flue gas prior to combustion.  This technique is useful for
reducing thermal NOX formation by limiting the oxygen concentration in
the combustion zone.

The practical operating range of existing thermal dryers is relatively
small, and redesign of the thermal dryer would be required to obtain
significant NOX reductions.  However, we have identified several
existing thermal dryers – Mettiki, Belle Ayr, and the Consol Energy
Buchanan #1 thermal dryer in Virginia – that have demonstrated NOX
emissions of less than 0.60 lb/MMBtu.  Our assessment of the available
information demonstrates that existing facilities could achieve this
limit through combustion controls alone.

Our assessment also demonstrates that new thermal dryers could be
constructed to comply with a NOX limit of 170 ng/J (0.40 lb/MMBtu). 
Although utility-size units burning bituminous coal can achieve NOX
limits of less than 130 ng/J (0.30 lb/MMBtu), NOX-reducing technologies
for smaller thermal dryers are more limited.  We reviewed permits issued
over the past decade and only found NOX requirements of less than 250
MMBtu/hr for 6 new comparable small coal-fired boilers.  Three were
circulating fluidized bed (CFB) boilers, a design that is not generally
used in dryers.  Permit conditions for the other three boilers were 110,
170, and 300 ng/J (0.25, 0.40, and 0.70 lb/MMBtu).  The highest permit
limit had a corresponding low CO standard, which could explain the
unusually high NOX standard.  This NOX emissions rate could be achieved
for either a new stoker or pulverized coal-based thermal dryer using
combustion controls alone.  Furthermore, we reviewed data developed by
State permitting authorities which list combustion controls as able to
cost effectively achieve over 50 percent reduction for coal-fired
industrial boilers from an uncontrolled emissions rate of 300 ng/J (0.70
lb/MMBtu).  The cost per ton of NOX controlled using combustion controls
(i.e., low NOX burners) is less than $2,000 per ton and is considered
cost effective for this source category.  See Thermal Coal Dryer Model
Plant Analysis in Docket EPA-HQ-OAR-2008-0260 for calculation details.

CO and VOC Controls

CO emissions are intermediate products produced by the incomplete
combustion of hydrocarbons.  The emissions are formed in hot,
oxygen-depleted regions of the combustion chamber and at the edges of
the lean flame zone where the temperature is lower.  Short residence
times also contribute to CO formation.  During complete combustion, CO
reacts with various oxidants to form CO2 through recombination
reactions.  However, these recombination reactions cannot proceed to
completion if the combustion temperature is low or there is a deficient
amount of oxidants in the combustion gas.  VOC emitted from thermal
dryers are a result of both incomplete fuel combustion and volatile
matter released from the coal bed as it is heated and dried.  Controls
to minimize both CO and VOC include thermal oxidation and flaring,
catalytic oxidation, catalytic incineration, and good combustion
practices.  In addition, high levels of excess air can be used to
control CO emissions and VOC absorbers can be used to control VOC
emissions.  However, high levels of excess air increase NOX emissions
and the PM emissions in a thermal dryer exhaust would plug the pores in
the absorber bed; therefore, such controls are not considered to be a
viable control techniques.

Thermal oxidation and flaring use high temperatures and residence time
to oxidize CO and VOC to CO2 and water.  Exhaust gas temperatures from
driers are typically 50 oC, whereas the required temperature for thermal
oxidation is approximately 700 oC.  Because the system would have to be
located after the PM control device to avoid the build-up of PM in the
oxidation unit, an inordinately large amount of fuel (typically natural
gas and on the order of the heat input to the thermal dryer itself)
would be required to heat the flue gas in a flaring process.  Because a
regenerative thermal oxidizer is much more efficient and uses less fuel,
we evaluated it as a control option.  For a model thermal dryer, the
overall annual cost of a regenerative thermal oxidizer is $1.8 million
and would control 95 percent, or 150 tons, of VOC emissions for a cost
effectiveness of $12,000 per ton.  In addition, for our model plants the
regenerative thermal oxidizer would destroy 260 tons of methane, which
have an equivalent warming potential of 6,000 tons of CO2.  However,
assuming the thermal dryer is fueled by natural gas, it would directly
emit an additional 40 tons of NOX and 2,600 tons of CO2.  Finally, we
estimate the indirect power plant criteria pollutant emissions that
result from the electrical use as 6,000 tons of CO2, 4 tons of SO2, 3
tons of NOX, and 800 pounds of PM.  This approach is not considered
appropriate for several reasons.  First, coal mines typically do not
have access to natural gas and although LPG technically could be used,
the storage, delivery logistics, and expense are prohibitive for all
facilities.  Finally, the adverse environmental impact from the
additional NOX and CO2 created from the combustion of natural gas or LPG
negate the environmental benefit of the control technique.

A catalytic oxidizer uses a catalyst to facilitate the oxidation of CO
and VOC to CO2 and water at lower temperatures than a thermal oxidizer. 
However, the optimal temperature is 450 oC to 600 oC, with a minimum
temperature of 260 oC.  Because the temperature of the exhaust gas from
the thermal dryer is 50 oC, auxiliary burners would be required to raise
the flue gas temperature.  In addition, PM loading of the exhaust could
potentially coat and plug the catalyst and the SO2 emissions could
poison the catalyst, significantly degrading performance.  For these
reasons, catalytic oxidation is not considered a viable control option
for reducing CO and VOC from coal-fired thermal dryers.

Catalytic incinerators use a catalyst bed to facilitate complete gas
combustion.  The catalyst increases the reaction rate of CO and VOC to
form CO2 and water at low temperatures.  We have not identified any
applications of catalytic incineration for coal-fired thermal dryers or
similar industrial applications and, therefore, did not consider this
technology as a control option.

Good combustion practices limit the formation of CO and VOC by providing
sufficient oxygen in the combustion zone for complete combustion to
occur.  Based on a review of CO emissions rates from existing thermal
dryers, based the combined NOX and CO limit on a CO emissions rate of
190 ng/J (0.45 lb/MMBtu) for modified and reconstructed thermal dryers. 
We have identified several existing thermal dryers – Bailey #2,
Loveridge, Belle Ayr, and Buchanan #1 – that are achieving this
emissions rate with combustion controls alone.  Because we have not
identified a method for control of VOC emissions beyond combustion
controls, we did not propose a separate limit for VOC emissions. 
However, by setting an emissions limit that contains a CO emissions
rate, we are minimizing the VOC emissions that result from incomplete
combustion.  The VOC emissions from the coal bed itself are variable,
and we concluded that we are unable to set a standard that would be
achievable for variable coal types across the country.

For new thermal dryers, we concluded that a CO emissions rate of 110
ng/J (0.25 lb/MMBtu) is appropriate for part of the basis for the
combined NOX and CO limit.  Although new utility-sized units can reduce
CO emissions to 0.15 lb/MMBtu, technologies are more limited for the
smaller thermal dryers.  However, because new thermal dryers would
likely use a gas recirculation design, both VOC and CO emissions would
be minimized.  The exhaust gases would be recirculated to the high
temperatures of the combustion chamber and would oxidize some of the
emissions to CO2 and water.  Of the three non-CFB permits for small
coal-fired boilers, the requirements over the past decade were 0.02,
0.21, 0.23 lb/MMBtu.  We also reviewed information on coal-fired boilers
developed for State permitting agencies, and the basis limit for CO is
consistent with the values listed in those references.  In addition, we
reviewed the CO data collected for coal-fired industrial boilers in
support of the CAA section 112 maximum achievable technology (MACT)
standards.  Of the 60 industrial boilers with CO emissions listed in
lb/MMBtu, the average was 40 ng/J (0.095 lb/MMBtu) and the range was 0.1
ng/J to 230 ng/J (0.0002 to 0.54 lb/MMBtu).  Unfortunately, we do not
have the corresponding NOX emissions data to determine if the low CO
emissions rates have a corresponding high NOX emissions rate. 
Regardless, the data indicate that 92 percent of existing small
coal-fired boilers are achieving the new source CO emissions value used
in determining the combined NOX and CO limit, and 98 percent are
achieving the CO emissions value used in determining the combined NOX
and CO limit for modified and reconstructed thermal dryers.Performance
Test Data and Permit Limits

Table 2:  Thermal Dryer Permit Limit

Facility Name	PM (gr/scf)	Opacity (%)	NOX (lb/MMBtu)	CO (lb/MMBtu)	VOC
(lb/MMBtu)	SO2 (lb/MMBtu)

American Cement Company, Sumterville Plant	0.01	5

Auburn Nugget LLC	0.01	3

Bailey Mine 1	0.031

0.8	2.28

Bailey Mine 2	0.02

0.59	0.52

1.2

Belle Ayr	0.005

0.21

	Buchanan Preparation Plant 1	0.025	20	0.46	2.34	0.29	0.2

Buchanan Preparation Plant 2	0.025	20	0.46	1	0.33	0.35

Cambria	0.031

	Cambria Slope	0.04

	Davenport Plant	0.031

	Dendrobium	0.009

0.18

	DTE Utah	0.031

	ETSI	0.031

	Gallatin Steel Company	0.031

	Gary Coal Processing, LP	0.031

	GCC Dacatah (cement)	0.01

	Goals Preparation Plant	0.031	20

Holnam Portland Plant	0.031	20

Iron Dynamics	0.01	3	0.049	0.082	0.0053	0.0006

Jewell Coke Company, L.P.	0.031

	Loveridge Preparation Plant	0.02	20

Mettiki General	0.02	20

Moss 3 Preparation Plant	0.031	20

Mountaintop Anthracite/Wright TWP	0.02	20

Robena Preparation Plant (Consolidation Coal)	0.031

0.6

	1.9

Shade Creek	0.031

	0.96

VP#8 Garden Plant (Island Creek Coal)	0.025

0.83	1.22	0.53	0.63

Table 3:  PM Performance Test Results

Facility Name	Controls	PM (gr/scf)	Max Opacity (%)	NOX (lb/MMBtu)	CO
(lb/MMBtu)	NOX & CO (lb/MMBtu)	VOC (lb/MMBtu)	SO2 (lb/MMBtu)	% SO2
Removal	Additional information

Amante (1978)	cyclones & venturi 	0.022

 

Cambria Slope (1989)	cyclones & venturi 	0.0364

0.51	58%	Rebuilt and new scrubbers in 1988 (original equipment installed
in 1962)

Homer City  A (1990)	cyclones & venturi 	0.0236

All operationally identical

Homer City  B (1990)	cyclones & venturi 	0.02096

 

Homer City  C (1990)	cyclones & venturi 	0.0141

 

Ohio Valley Coal mine #6 (1991)	cyclones & venturi 	0.0346	5

	1.9	71%	1974 vintage equipment; 1983 scrubber and sack moved from top
of dryer to ground

Cambria (1991)	cyclones & venturi	0.0196	5

	0.06	94%	reconditioned in 1990 (original equipment 1972); scrubber
maintained at pH of 9 to 10

Belle Ayr (1990)	baghouse	0.0048

0.35	2.2	2.6	0.089	0.003

Belle Ayr (1991)	baghouse	0.004

0.47	0.15	0.62	0.014	0.02

 

Shade Creek (1992)	cyclones & venturi 	0.09

0.02	98%	 

Hawthorn Mine (1994)	cyclones & venturi 	0.0092	15	0.67

0.56	81%	 

VP#8 Deskins Garden (1997)	cyclones & venturi 	0.019

 

VP#8 Deskins Garden (2001)	cyclones & venturi 	0.011

0.52	50%	 

Pinnacle (2002)	cyclones & venturi 	0.0247

 

Buchanan #1 (2003)	cyclones & venturi 	0.016	10	0.115	0.18	0.295	0.45

	 

Buchanan #1 (2006)	cyclones & venturi 	0.018	20	0.14	0.15	0.29	0.74

	 

Bailey #1 (1997)	cyclones & venturi 	0.024	12	0.51	0.79	1.3	0.53	0.89
70%	 estimated assuming 3 lb coal

Bailey #1 (1998)	cyclones & venturi 	0.027	9.5	0.68	1.19	1.87	0.33	0.73
76%	 estimated assuming 3 lb coal

Bailey #1 (1999)	cyclones & venturi 	0.030	15.5	0.59	2.07	2.66	0.4	0.45
85%	 estimated assuming 3 lb coal

Bailey #1 (2000)	cyclones & venturi 	0.028	10.9

0.86

0.23

	 

Bailey #1 (2001)	cyclones & venturi 	0.035	10.3

	failed PM test

Bailey #1 (2002)	cyclones & venturi 	0.026	12.6

1.02

	 

Bailey #1 (2003)	cyclones & venturi 	0.023	10

0.89

0.3

	 

Bailey #1 (2004)	cyclones & venturi 	0.017	10

1.19

0.51

	 

Bailey #1 (2006)	cyclones & venturi 	0.013	15

1.71

0.15

	 

Bailey #1 (2007)	cyclones & venturi 	0.028	10

0.92

0.79

	 

Bailey #2 (1997)	cyclones & venturi 	0.015	7	0.56	0.33	0.89	0.58	0.78
74%	 estimated assuming 3 lb coal

Bailey #2 (1998)	cyclones & venturi 	0.015	8.2	0.55	0.27	0.82	0.14	0.48
84%	 estimated assuming 3 lb coal

Bailey #2 (1999)	cyclones & venturi 	0.013	6.7	0.67	0.12	0.79	0.20	0.52
83%	 estimated assuming 3 lb coal

Bailey #2 (2000)	cyclones & venturi 	0.015	5.1

0.42

0.41

	 

Bailey #2 (2001)	cyclones & venturi 	0.034	6.9

	failed PM test

Bailey #2 (2002)	cyclones & venturi 	0.016	6.8

0.18

0.37

	 

Bailey #2 (2003)	cyclones & venturi 	0.018	0

0.22

	failed VOC test

Bailey #2 (2006)	cyclones & venturi 	0.009	15

0.31

0.097

	 

Bailey #2 (2007)	cyclones & venturi 

	0.84

0.91

 

Bailey #2 (2007)	cyclones & venturi 	0.016	10

0.16

0.71

	 

Mettiki (2000)	cyclones & venturi 	0.0127

constructed in 1978

Mettiki (2002)	cyclones & venturi 	0.0112

0.45

0.19	97%	 estimated assuming 5.6 lb coal

Mettiki (2003)	cyclones & venturi 	0.0150

0.52

0.12	98%	 estimated assuming 5.6 lb coal

Mettiki (2006)	cyclones & venturi 	0.0153

0.46

0.54	90%	estimated assuming 5.6 lb coal; failed SO2

Mettiki (2006)	cyclones & venturi 

	0.10	98%	estimated assuming 5.6 lb coal; retest SO2

Mettiki (2007)	cyclones & venturi 	0.0164

0.16	97%	 estimated assuming 5.6 lb coal

Mettiki (2008)	cyclones & venturi 	0.0120

0.11	98%	estimated assuming 5.6 lb coal 

Loveridge (2004)	cyclones & venturi 	0.016	10	0.42	0.34	0.76	0.66	1.5
63%	 estimated assuming 4.1 lb coal

Loveridge (2006)	cyclones & venturi 	0.008	15	0.70	0.43	1.13	0.52	1.5
63%	 estimated assuming 4.1 lb coal

Coal Creek (2006)	baghouse	0.0031	0

	 

Table 4:  RACT/BACT Permits

Company	Facility	Year of Permit	State	Process	Primary Fuel	Heat Input
(MMBtu/hr)	NOX (lb/MMBtu)	CO (lb/MMBtu)

Northern Michigan University	Ripley Heating Plant	2008	MI	CFB Boiler
Wood & Coal	185	0.10	0.17

University of Northern Iowa	Boiler 4	2007	IA	CFB Boiler	Coal	143.1	0.11
 

Red Trail Energy, LLC.	Richardton Plant	2004	ND	CFB Boiler	Lignite	250
0.10	0.11

Miller Brewing Company	Miller Brewing Company Trenton	2004	OH	Coal-fired
Boiler	Coal	238	0.70	0.02

VPI University	VPI Power Station	2001	VA	Overfeed stoker coal-fired
boiler	Coal	147	0.25	0.23

International Paper Co.	Riegelwood Mill	2001	NC	Coal-fired boiler	Coal
249	0.40	0.21



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