[Federal Register Volume 74, Number 100 (Wednesday, May 27, 2009)]
[Proposed Rules]
[Pages 25304-25327]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-11912]
[[Page 25303]]
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Part II
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for Coal Preparation and Processing Plants;
Proposed Rule
Federal Register / Vol. 74, No. 100 / Wednesday, May 27, 2009 /
Proposed Rules
[[Page 25304]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2008-0260; FRL-8908-7]
RIN 2060-AO57
Standards of Performance for Coal Preparation and Processing
Plants
AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental proposal.
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SUMMARY: EPA is proposing a supplemental action to the proposed
amendments to the new source performance standards for coal preparation
and processing plants published on April 28, 2008. The 2008 proposal,
among other things, proposed to revise the particulate matter and
opacity standards for thermal dryers, pneumatic coal cleaning
equipment, and coal handling equipment located at coal preparation and
processing plants. This supplemental action proposes to revise the
particulate matter emissions and opacity limits included in the
original proposal for thermal dryers, pneumatic coal-cleaning
equipment, and coal handling equipment. It also proposes to expand the
applicability of the thermal dryer standards so that the proposed
standards for thermal dryers would apply to both direct contact and
indirect contact thermal dryers drying all coal ranks and pneumatic
coal-cleaning equipment cleaning all coal ranks. In addition, it
proposes to establish a sulfur dioxide emission limit and a combined
nitrogen oxide and carbon monoxide emissions limit for thermal dryers.
We are also proposing to amend the definition of coal for purposes of
subpart Y to include petroleum coke and coal refuse. Finally, it
proposes to establish work practice standards to control coal dust
emissions from open storage piles and roadways associated with coal
preparation and processing plants.
DATES: Comments. Comments must be received on or before July 13, 2009.
If anyone contacts EPA by June 8, 2009 requesting to speak at a public
hearing, EPA will hold a public hearing on June 11, 2009. Under the
Paperwork Reduction Act, comments on the information collection
provisions must be received by the Office of Management and Budget
(OMB) on or before June 26, 2009.
Because, under the terms of a consent decree, the final action must
be signed not later than September 26, 2009, EPA will not grant
requests for extensions beyond these dates.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2008-0260, by one of the following methods:
http://www.regulations.gov. Follow the on-line
instructions for submitting comments.
E-mail: [email protected].
By Facsimile: (202) 566-1741.
Mail: Air and Radiation Docket, U.S. EPA, Mail Code 6102T,
1200 Pennsylvania Ave., NW., Washington, DC 20460.
Please include a total of two copies. In addition, please mail a
copy of your comments on the information collection provisions to the
Office of Information and Regulatory Affairs, Office of Management and
Budget (OMB), Attn: Desk Officer for EPA, 725 17th Street, NW.,
Washington, DC 20503. EPA requests a separate copy also be sent to the
contact person identified below (see FOR FURTHER INFORMATION CONTACT).
Hand Delivery: EPA Docket Center, Docket ID Number EPA-HQ-
OAR-2008-0260, EPA West Building, 1301 Constitution Ave., NW., Room
3334, Washington, DC, 20004. Such deliveries are accepted only during
the Docket's normal hours of operation, and special arrangements should
be made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2008-0260. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through regulations.gov or e-
mail. The http://www.regulations.gov Web site is an ``anonymous
access'' system, which means EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an e-mail comment directly to EPA without going through http://www.regulations.gov, your e-mail address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, EPA recommends that you include your name and other contact
information in the body of your comment and with any disk or CD-ROM you
submit. If EPA cannot read your comment due to technical difficulties
and cannot contact you for clarification, EPA may not be able to
consider your comment. Electronic files should avoid the use of special
characters, any form of encryption, and be free of any defects or
viruses. For additional information about EPA's public docket visit the
EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air and Radiation
Docket EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding legal holidays. The telephone
number for the Public Reading Room is (202) 566-1744, and the telephone
number for the Air and Radiation Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy Strategies
Group, Sector Policies and Programs Division (D243-01), U.S. EPA,
Research Triangle Park, NC 27711, telephone number (919) 541-5025,
facsimile number (919) 541-5450, electronic mail (e-mail) address:
[email protected].
SUPPLEMENTARY INFORMATION: Regulated Entities. Entities potentially
affected by this proposed action include, but are not limited to, the
following:
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Examples of regulated
Category NAICS \1\ entities
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Industry......................... 212111 Bituminous Coal and
Lignite Surface Mining.
212112 Bituminous Coal
Underground Mining.
221112 Fossil Fuel Electric
Power Generation.
212113 Anthracite Mining.
213113 Support Activities for
Coal Mining.
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322121 Paper (except Newsprint)
Mills.
324199 All other petroleum and
coal products
manufacturing.
325110 Petrochemical
Manufacturing.
327310 Cement Manufacturing.
331111 Iron and Steel Mills.
Federal Government............... 22112 Fossil fuel-fired
electric utility steam
generating units owned
by the Federal
Government.
State/local/tribal government.... 22112 Fossil fuel-fired
921150 electric utility steam
generating units owned
by municipalities.
Fossil fuel-fired
electric steam
generating units in
Indian Country.
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\1\ North American Industry Classification System (NAICS) code.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by the
proposed rule. This table lists categories of entities that may have
coal preparation and processing plants regulated by this proposed rule.
To determine whether your facility is regulated by the proposed rule,
you should examine the applicability criteria in Sec. 60.250 and the
definitions in Sec. 60.251. If you have any questions regarding the
applicability of the proposed rule to a particular entity, contact the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
WorldWide Web (WWW). Following the Administrator's signature, a
copy of the proposed amendments will be posted on the Technology
Transfer Network's (TTN) policy and guidance page for newly proposed or
promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides
information and technology exchange in various areas of air pollution
control.
Public Hearing. If anyone contacts EPA by June 8, 2009 requesting
to speak at a public hearing, EPA will hold a public hearing on June
11, 2009. If a public hearing is held, it will be held at 10 a.m. at
the EPA Facility Complex in Research Triangle Park, North Carolina or
at an alternate site nearby. Contact Mrs. Pamela Garrett at 919-541-
7966 to request a hearing, to request to speak at a public hearing, to
determine if a hearing will be held, or to determine the hearing
location.
Outline. The information presented in this preamble is organized as
follows:
I. Background
II. Summary of Proposed Amendments
A. Affected Facilities
B. PM and Opacity Limits for Thermal Dryers
C. SO2, NOX, and CO Emission Limits for
Thermal Dryers
D. PM and Opacity Limits for Pneumatic Coal-Cleaning Equipment,
Coal Processing and Conveying Equipment, Coal Storage Systems, and
Transfer and Loading Systems
E. Emissions Monitoring Requirements
F. Opacity Monitoring Requirements for Pneumatic Coal-Cleaning
Equipment, Coal Processing and Conveying Equipment, Coal Storage
Systems, and Transfer and Loading Systems
G. Electronic Reporting
H. Addition of Petroleum Coke and Coal Refuse to the Definition
of Coal
I. Additional Amendments
III. Rationale for the Proposed Amendments
A. Additional Affected Facilities
B. Selection of Thermal Dryer PM and Opacity Emissions Limits
C. Selection of Thermal Dryer SO2, NOX,
and CO Emissions Limits
D. Selection of Pneumatic Coal-Cleaning Equipment, Coal
Processing and Conveying Equipment, Coal Storage Systems, and
Transfer and Loading System PM and Opacity Limits
E. Selection of Monitoring Requirements
F. Selection of Opacity Monitoring Requirements for Pneumatic
Coal-Cleaning Equipment, Coal Processing and Conveying Equipment,
Coal Storage Systems, and Transfer and Loading Systems
G. Required Electronic Reporting
H. Addition of Petroleum Coke and Coal Refuse to the Definition
of Coal
I. Additional Amendments
J. Emissions Reductions
IV. Modification and Reconstruction Provisions
V. Summary of Costs, Environmental, Energy, and Economic Impacts
VI. Request for Comment
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paper Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Background
On April 28, 2008 (73 FR 22901), we proposed amendments to the New
Source Performance Standards (NSPS) for Coal Preparation and Processing
Plants (40 CFR part 60, subpart Y). The Federal Register action for
that original proposal included additional background information on
the coal preparation NSPS. That information is not repeated in this
action. EPA received numerous comments in response to the April 2008
proposal. After reviewing those comments and considering additional
data, EPA decided to publish this supplemental proposal which contains
proposed emission limits and monitoring requirements that differ from
those in the original action and proposes to apply those requirements
to additional affected facilities.
II. Summary of Proposed Amendments
In this supplemental action, we are proposing to establish
emissions standards for both direct contact and indirect thermal dryers
and pneumatic coal-cleaning equipment that process all coal ranks. We
are also proposing to establish work practice standards to control coal
dust emissions from open storage piles and roadways associated with
coal preparation and processing plants. In addition, we are proposing
to establish a sulfur dioxide (SO2) emission limit and a
combined nitrogen oxide (NOX) and carbon monoxide (CO)
emissions limit for thermal dryers. Finally, we are proposing
particulate matter (PM) emission limits, opacity limits, and monitoring
requirements that differ from those included in the April 2008
proposal. For all standards proposed in the April 2008 proposed rule,
this supplemental proposal will not change the applicability date for
determining whether a source constitutes a ``new source'' subject to
the final version of such standards. All standards originally included
in the April 2008 proposed rule, regardless of whether the level of the
standard is modified in this supplemental proposal or in an eventual
final rule, apply to
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sources constructed, modified, or reconstructed after April 28, 2008.
Standards, such as the SO2 and combined NOX and
CO standards, proposed for the first time in this supplemental
proposal, apply to all sources constructed, modified, or reconstructed
after May 27, 2009. A summary of the proposed amendments is presented
below.
A. Affected Facilities
The existing NSPS for coal preparation and processing plants in 40
CFR part 60, subpart Y establishes emission limits for the following
affected facilities located at coal preparation and processing plants
which process more than 181 megagrams (Mg) (200 tons) of coal per day:
thermal dryers, pneumatic coal-cleaning equipment (air tables), coal
processing and conveying equipment (including breakers and crushers),
coal storage systems, and transfer and loading systems. The terms
``thermal dryer'' and ``pneumatic coal-cleaning equipment'' are defined
to include only facilities that process bituminous coal and ``coal
storage system'' is defined to exclude open storage piles.
In the April 2008 proposal, we did not propose any revisions to
these provisions. Several commenters suggested that standards should
also be developed for indirect thermal dryers, thermal dryers drying
all coal ranks, open storage piles, and coal dust associated with
roadways associated with coal preparation and processing plants.
Commenters said EPA's original rationale for limiting the applicability
for thermal dryers was a lack of emissions data and thermal dryers, and
pneumatic coal-cleaning equipment processing non-bituminous coals did
not exist and that these reasons are no longer valid. Commenters said
indirect thermal dryers and direct contact thermal dryers ``upgrading''
subbituminous and lignite will become more common in the future. Even
though power plant emissions might be decreased, if emissions standards
are not established on the pre-combustion process, they argued, there
is no environmental benefit and potential net degradation to air
quality from coal ``upgrading.''
For open storage piles and roadways, commenters pointed out that
both are significant sources of PM emissions for which control
technology is available. One commenter pointed out that enclosures,
wind fences and other barriers, and wet or chemical suppression are
available control technologies. Potential controls for coal road dust
include tire or truck wash systems, sweeper trucks, and wet
suppression.
Based on our review of public comments and subsequent analysis, we
are proposing to amend the definition of thermal dryer for units
constructed after May 27, 2009 to include both direct and indirect
dryers drying all coal ranks. We are also proposing to amend the
definition of pneumatic coal-cleaning equipment for units constructed
after May 27, 2009 to include pneumatic coal-cleaning equipment
cleaning all coal ranks. In addition, we are proposing to establish
work practice standards that apply to open storage piles and roads
associated with a coal preparation plant constructed after May 27,
2009.
B. PM and Opacity Limits for Thermal Dryers
In the April 2008 proposed rule, we proposed a PM standard of 0.046
grams per dry standard cubic meter (g/dscm) (0.020 grains per dry
standard cubic foot (gr/dscf)) and proposed to retain the existing 1976
rule's opacity limit of less than 20 percent for thermal dryers
constructed, modified, or reconstructed after April 28, 2008. We
received comments that the PM limit would be prohibitively expensive
for modified and reconstructed units to achieve, but that the limit
should be lower for new units and should be based on the use of a
fabric filter (baghouse).
Based on our review of public comments and subsequent analysis, we
are now proposing to revise our April 2008 proposal regarding PM and
opacity standards for thermal dryers. We are now proposing separate
standards for new, reconstructed, and modified units. We are proposing
to revise the limits for new units constructed after April 28, 2008, to
0.023 g/dscm (0.010 gr/dscf) of PM and an opacity limit of less than 10
percent. We are proposing to revise the PM limit for units
reconstructed after April 28, 2008, to 0.045 g/dscm (0.020 gr/dscf) and
proposing to maintain the existing 1976 rule's opacity limit of less
than 20 percent. For units modified after April 28, 2008, we are
proposing to maintain the existing 1976 rule's PM limit of 0.070 g/dscm
(0.031 gr/dscf) and the existing 1976 rule's opacity limit of less than
20 percent.
C. SO2, NOX, and CO Emission Limits for Thermal Dryers
The existing NSPS does not limit emissions of SO2,
NOX, or CO from coal preparation facilities, and in the
April 2008 proposed rule, we did not propose to add limits for these
pollutants. A commenter suggested that standards should be established
for each pollutant because thermal dryers emit these pollutants and can
cause or contribute significantly to air pollution which may reasonably
be anticipated to endanger public health or welfare. The commenter also
said using AP-42 emission factors, a 2,000 ton/hr coal thermal dryer
would emit 12,000 tons/yr SO2 and 1,400 tons/yr
NOX, and because cost-effective controls exist the EPA
should base requirements on the use of those controls.
Based on our review of public comments and subsequent analysis, for
owners/operators of thermal dryers constructed, modified, or
reconstructed after May 27, 2009 we are proposing to add the following
emissions limits: for new, reconstructed, and modified units, an
SO2 limit of 85 nanograms per Joule (ng/J) (0.20 pounds per
million British thermal units (lb/MMBtu)), or 50 percent reduction of
potential SO2 emissions and no more than 520 ng/J; for new
units, a combined NOX and CO limit of 280 ng/J (0.65 lb/
MMBtu); for reconstructed units and modified units, a combined
NOX and CO limit of 430 ng/J (1.0 lb/MMBtu).
D. PM and Opacity Limits for Pneumatic Coal-Cleaning Equipment, Coal
Processing and Conveying Equipment, Coal Storage Systems, and Transfer
and Loading Systems
The original 1976 rulemaking treated each coal processing and
conveying equipment, coal storage systems, and transfer and loading
systems operation as a separate affected facility. However, it grouped
them together for the purpose of establishing a single emissions
standard. This was done because all of the affected facilities could
use similar control devices and achieve comparable emissions rates. We
have concluded that this is still an appropriate approach. While each
operation is a separate affected facility, all are either fugitive
sources or point sources of PM and similar control equipment can be
used on each affected facility resulting in comparable emissions. If
additional data is submitted during the comment period that justifies
different opacity limits for different coal handling operations, we
will consider that approach in the final rule.
The original 1976 rulemaking did not include a PM limit for coal
processing and conveying equipment, coal storage systems, and transfer
and loading systems. However, the original rulemaking included an
opacity limit of less than 20 percent for all of these affected
facilities. For pneumatic coal cleaning equipment, the original
rulemaking included both a PM limit of
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0.040 g/dscm (0.017 gr/dscf) and an opacity limit of less than 10
percent.
In the April 2008 proposed rule, we proposed a PM limit of 0.011 g/
dscm (0.0050 gr/dscf) and an opacity limit of less than 5 percent for
pneumatic coal-cleaning equipment and coal processing and conveying
equipment, coal storage systems, and transfer and loading systems
processing subbituminous and lignite coals that commenced construction,
reconstruction, or modification after April 28, 2008. We proposed the
same limit for both pneumatic coal-cleaning equipment and coal handling
operations because we determined that the best demonstrated technology
(BDT) for both was a fabric filter. In addition, we proposed to
establish a requirement that coal handling equipment processing
subbituminous and lignite coals must be vented to a control device.
Multiple commenters challenged the requirement that coal handling
equipment processing subbituminous and lignite coals must vent to a
control device, and the levels of the PM and opacity limits.
Based on our review of public comments and subsequent analysis, we
have concluded it is not appropriate to require coal handling equipment
processing subbituminous and lignite coals be vented to a control
device. In addition, after further analysis, we are proposing to revise
the PM emission limits for pneumatic coal-cleaning equipment and
mechanically vented coal handling equipment processing all coal ranks
constructed, modified, or reconstructed after April 28, 2008, to 0.023
g/dscm (0.010 gr/dscf). In addition, we are proposing to revise the
opacity standard to no greater than 5 percent for all pneumatic coal-
cleaning equipment, coal processing and conveying equipment, coal
storage systems, and transfer and loading systems that commenced
construction, reconstruction, or modification after April 28, 2008.
E. Emissions Monitoring Requirements
In the April 2008 proposed rule, we proposed to require initial and
annual performance tests for all new thermal dryers, pneumatic coal-
cleaning equipment, and subbituminous and lignite coal handling
equipment vented to a control device. Commenters suggested that annual
performance testing is unduly burdensome for subpart Y affected
facilities and suggested either eliminating PM performance testing
completely for coal handling equipment or tiered testing requirements
depending on the results of the most recent performance test.
Based on our review of public comments and further analysis, we are
proposing to amend the testing requirements as follows: first, owners/
operators of an affected facility with design potential emissions
rates, considering controls, of 1.0 Mg (1.1 tons) per year or less
would be required to perform an initial performance test; however,
annual performance testing would not be required as long as the design
emissions rate is less than or equal to the applicable emissions limit
(confirmed by the initial performance test), the manufacturer's
recommended maintenance procedures are followed, and the unit operates
without significant visible emissions. In addition, for owners/
operators with similar, separate affected facilities using identical
control equipment with design potential emissions rates, considering
controls, of 10 Mg (11 tons) per year or less, we are proposing to
allow the permitting authority to authorize a single test as adequate
demonstration for up to four other similar, separate affected
facilities as long the following conditions are met: (1) The design
emissions rate is less than or equal to the applicable emissions limit;
(2) the individual performance test is 90 percent or less of the
applicable standard; (3) the manufacturer's recommended maintenance
procedures are followed for each control device; (4) each of the
affected facilities operates without significant visible emissions; and
(5) each affected facility conducts a performance test at least once
every 5 years. Finally, we are proposing that owners/operators of
affected facilities are only required to conduct performance testing
every 24 months, as opposed to every 12 months, if the most recent
performance test shows the affected facility emits at 50 percent or
less of the applicable standard.
In the April 2008 proposal, we did not propose to require the use
of PM continuous emission monitoring systems (CEMS), but added specific
language directly to the regulatory text that allowed owners/operators
to elect to use PM CEMS and provided incentives for them to do so by
proposing to eliminate the opacity standard for owner/operators of
affected facilities using a PM CEMS. Commenters suggested that by
having the specific language directly in the regulatory text, we were
encouraging State permitting authorities to require the use of PM CEMS,
and that the costs are not justified for this source category. Other
commenters suggested we require the use of PM CEMS for all units.
Based on our review of public comments and further analysis, we are
no longer proposing to include the PM CEMS-specific language in the
regulatory text. Non-fugitive sources at coal preparation plants are
generally not significant sources of PM emissions. Further, we are not
aware of any application of PM CEMS to comparable emissions sources in
the United States, and we have concluded that it is unlikely that an
owner/operator of a coal preparation plant would elect to install PM
CEMS. In addition, owners/operators continue to have the option to
request site-specific approval for the use of PM CEMS as an alternate
monitoring technique.
In the April 2008 proposed rule, we proposed to require bag leak
detection systems for owners/operators of thermal dryers and pneumatic-
coal cleaning equipment, if the dryer or equipment uses a fabric filter
installed after April 28, 2008. Based on further analysis, we are
proposing to require a bag leak detection system for owners/operators
of any subpart Y affected facilities with fabric filters, if the filter
has a design controlled potential emissions rate of 25 Mg (28 tons) or
more. For this source category, the variable operation of fabric
filters makes the likely actual emissions much less than the potential
emissions rate and the added expense of a bag leak detection system for
smaller sources is not justified. This requirement would apply to
facilities constructed, modified, or reconstructed after April 28,
2008.
F. Opacity Monitoring Requirements for Pneumatic Coal-Cleaning
Equipment, Coal Processing and Conveying Equipment, Coal Storage
Systems, and Transfer and Loading Systems
In the April 2008 proposed rule, we proposed the following PM
monitoring requirements. Each affected facility would be required to
perform an initial EPA Method 9 of appendix A-4 of 40 CFR part 60
performance test. Following the initial compliance test, three 1-hour
EPA Method 22 of appendix A-7 of 40 CFR part 60 observations would be
required for each affected facility at least once per calendar month
that the coal preparation plant operates. If the sum of visible
emissions exceeded 5 percent of the observation period, the owner/
operator would be required to conduct a Method 9 performance test
within 24 hours. Commenters suggested that three 1-hour observations
are unduly burdensome and suggested that it would be appropriate to
include a provision allowing for corrective action prior to requiring a
Method 9 performance test. In addition, a commenter suggested adding a
provision for the use of a continuous opacity monitoring system (COMS)
as
[[Page 25308]]
an alternative to the Method 9 and Method 22 approach.
Based on our review of public comments and further analysis, we are
proposing to change the April 2008 proposed opacity monitoring
requirements for pneumatic coal-cleaning and coal handling equipment.
First, we are proposing to allow the use of a COMS as an alternative to
all other opacity monitoring requirements. Second, we are proposing to
allow an owner/operator of an affected facility to decrease the
observation period for a Method 9 performance test from 3 hours to 60
minutes if, during the initial 60 minutes of the observation of a
Method 9 performance test, all the 6-minute averages are less than or
equal to 3 percent and all the individual 15-second observations are
less than or equal to 20 percent. Third, we are proposing to base the
frequency of visible emissions monitoring on the results of the highest
individual 15-second opacity observed during the most recent
performance test. Owners/operators of affected facilities where the
maximum 15-second opacity reading is greater than 5 percent would be
required to conduct weekly Method 9 performance testing; owners/
operators of affected facilities where the maximum 15-second opacity
reading is 5 percent would be required to conduct monthly Method 9
performance testing; and owners/operators of affected facilities with
no visible emissions would be required to conduct quarterly Method 9
performance testing.
As an alternative, owners/operators of affected facilities where
the maximum 6-minute opacity reading from the most recent Method 9
performance test is less than or equal to 3 percent could elect to use
either Method 22 or a digital opacity monitoring system in lieu of
subsequent Method 9 performance testing. The April 2008 proposal would
have required a total of three 1-hour observations monthly. We have
concluded that for sources with low opacity, it is more protective to
the environment and minimizes burden to industry to increase the
frequency of opacity observations, but to decrease the length of each
observation. When a control device is operating properly there should
be minimal visible emissions and a 1-hour observation would not provide
any significant additional useful information than a 10 minute
observation. In addition, by requiring more frequent observations we
are decreasing the time period before a malfunctioning piece of control
equipment is identified. Therefore, we have concluded it is appropriate
to decrease the length of each observation to a minimum of 10 minutes,
but to increase the frequency to daily observations.
Further, we are proposing to base monitoring requirements for
affected facilities, in part, on recent observations of visible
emissions from the facilities. If no visible emissions are observed for
7 consecutive operating days, observations could be reduced to once
every 7 operating days. If an owner/operator of an affected facility
observes visible emissions in excess of 5 percent during any
observation and is unable to take corrective action, they would be
required to conduct a Method 9 performance test with the previously
specified frequency. Finally, to maintain consistency in the operation
of the digital opacity monitoring system, the EPA Administrator would
approve opacity monitoring plans for owners/operators that elect to use
the digital opacity monitoring system to detect the presence of visible
emissions.
G. Electronic Reporting
We are proposing to take a step to improve data accessibility. We
are proposing to require owners/operators of affected facilities at
coal preparation plants to submit an electronic copy of all performance
test reports to an EPA electronic data base (WebFIRE). Data entry
requires access to the Internet and is expected to be completed by the
stack testing company as part of the work that they are contracted to
perform. This option would be required as of July 1, 2011. For
performance tests not accepted by WebFIRE, we are proposing to require
owner/operators to mail summary results directly to EPA.
H. Addition of Petroleum Coke and Coal Refuse to the Definition of Coal
We are proposing to amend the definition of coal for purposes of
subpart Y to include petroleum coke and coal refuse. The amended
definition will be used to make applicability determinations for all
facilities constructed, reconstructed, or modified after May 27, 2009.
This change indicates our determination that the subpart Y regulations
should apply to affected facilities that prepare and process these non-
traditional materials that are processed like coal.
I. Additional Amendments
We are also proposing several additional amendments. First, we are
proposing to change the title of subpart Y from Coal Preparation Plants
to Coal Preparation and Processing Plants. In addition, we are
proposing to amend the definitions for bituminous coal, coal, coal
storage system, pneumatic coal-cleaning equipment, and thermal dryer;
to add definitions for anthracite, bag leak detection system, design
controlled potential emissions rate, lignite, mechanical vent,
operating day, potential combustion concentration, and subbituminous
coal; and to delete the definition for cyclonic flow. Finally, we are
proposing to exempt units that have been out of operation for at least
60 days prior to the time of the required performance test from
conducting the required performance test until 30 days after the
facility is brought back into operation.
III. Rationale for the Proposed Amendments
A. Additional Affected Facilities
The existing NSPS for coal preparation and processing plants
establishes PM and opacity limits for thermal dryers that dry
bituminous coal where the exhaust gas comes in direct contact with the
coal (direct contact thermal dryers). 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. In the April 2008
proposal, we proposed to amend the PM limit for direct contact thermal
dryers drying bituminous coal, but did not propose to establish
standards for other thermal dryers. 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 other criteria pollutants emitted from thermal
dryers.
Based on our review of public comments and subsequent analysis, in
this supplemental proposal we are proposing emission standards that
would apply to thermal dryers drying all ranks of coals and to both
direct contact and indirect thermal dryers. We are proposing to amend
the PM and opacity standards and to add both an SO2 standard
and a combined NOX-CO standard for thermal dryers.
For indirect thermal dryers, the affected facility will include the
heat source for the thermal dryer unless that heat source is subject to
a boiler NSPS (e.g., subpart Da, Db, or Dc). Indirect thermal dryers
use a heat transfer medium to supply heat and blow air over the coal to
evaporate the water. The high moisture content air is vented through a
stack and the dryer exhaust contains entrained PM. If the source of
heat (the source of combustion or furnace) is subject to a boiler NSPS
(subpart Da, Db, or Dc) then the furnace and the associated emissions
would not
[[Page 25309]]
be part of the subpart Y affected facility. However, if the source of
heat is not subject to a boiler NSPS, then the heat source and the
associated emissions are part of the subpart Y affected facility.
In situations where the heat source is part of the subpart Y
affected facility and the exhaust is combined with the dryer exhaust in
a single stack, the combined exhaust stack will contain all of the
applicable pollutants (i.e., PM, SO2, NOX, and
CO) and all of the testing requirements would apply. However, in
situations where the heat source is part of the subpart Y affected
facility and the exhaust is not combined with the dryer exhaust, the
subpart Y requirements would apply differently to the dryer exhaust
stack and the combustion exhaust stack. The only applicable pollutant
in the dryer exhaust would be PM. Therefore, the only performance test
that would be required on the dryer exhaust would be for PM. However,
all of the requirements of subpart Y, including the PM, SO2,
and NOX-CO standards, would apply to the combustion exhaust
stack and all of the testing requirements would apply.
In situations where the heat source is not part of the subpart Y
affected facility because it is a unit covered by a steam generating
NSPS (e.g., 40 CFR part 60 subparts Da, Db, or Dc), the only applicable
pollutant contained in the thermal dryer stack exhaust would be PM.
Because the thermal dryer stack exhaust would not contain
SO2, NOX, or CO, the SO2 and combined
NOX-CO testing requirements would not apply.
We are proposing to establish standards that apply to direct
contact and indirect thermal dryers drying all coal ranks of coal
because the control technologies commonly used on thermal dryers--
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 can achieve
comparable emissions rates. In addition, subpart Y was originally
promulgated in 1976 and additional pollution control technologies have
become available since then.
Open storage piles and dust associated with roadways are
potentially significant sources of fugitive PM emissions. These sources
are integral parts of coal preparation plants, located on contiguous or
adjacent property, and under common control. Although part of the coal
preparation plant and, thus, contained within the source category
listed in 1976, the existing subpart Y regulations do not set standards
for emissions from open storage piles or from coal dust from roadways.
In the April 2008 proposal, we requested comment on including
requirements for open storage piles. We received comments both in
support of and opposed to including requirements for open storage
piles. In addition, we received comments in support of including
requirements for the coal dust disturbed by, or released from, vehicle
tires as vehicles move within the coal preparation plant. Based on our
review of public comments and subsequent analysis, we have concluded
that both open storage piles and vehicle tires are significant sources
of potential fugitive PM emissions; however, neither operation lends
itself to an emissions standard. Therefore, in this supplemental
proposal we are proposing to establish work practice standards instead
of an opacity or PM limit for these types of affected facilities.
B. Selection of Thermal Dryer PM and Opacity Emissions Limits
In the April 2008 proposal, we proposed to revise the PM limit for
thermal dryers that dry bituminous coal from 0.070 g/dscm (0.031 gr/
dscf) to 0.046 g/dscm (0.020 gr/dscf). We received comments that
achieving this limit would be prohibitively expensive for modified and
reconstructed units, but that the limit should be lower for new units.
Based on our review of public comments and subsequent analysis, in
this supplemental proposal we are proposing separate PM limits for new,
reconstructed, and modified units. As discussed in the Thermal Dryer
Memo in Docket EPA-HQ-OAR-2008-0260, the physical layout of existing
thermal dryers makes it more expensive to reduce emissions from
existing dryers than from new or reconstructed units. Therefore, we are
proposing to maintain the PM limit for modified facilities at the
existing 1976 limit of 0.070 g/dscm (0.031 gr/dscf). We continue to be
interested in additional performance test data and information on the
ability of modified units to achieve additional PM reductions beyond
the present limit and are also considering establishing a lower PM
standard between 0.045 g/dscm (0.020 gr/dscf) and 0.070 g/dscm (0.031
gr/dscf) for the final rule. We specifically request comment on all
this range of possible standards, including 0.045 g/dscm (0.020 gr/
dscf).
Because reconstructed facilities could take design options into
account during the reconstruction process, we are proposing a PM limit
of 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, 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.
As described in Thermal Dryer Memo in Docket EPA-HQ-OAR-2008-0260,
new thermal dryers would likely be designed as either a coal-fired
recirculation thermal dryer or an indirect thermal dryer. We have
determined that BDT for controlling PM emissions from these types of
dryers is a fabric filter. Data collected to date demonstrates that
fabric filters on such facilities can achieve emission rates of 0.004
to 0.0031 gr/dscf. As explained below, based on these data and recent
permit limits for new thermal dryers using a baghouse, we are proposing
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 units and is lower than the limit of 0.046 g/
dscm (0.020 gr/dscf) in the April 2008 proposal. The April 2008
proposed limit, however, would have applied to new, reconstructed and
modified facilities.
It is important to note that although the standard is based on the
use of a fabric filter, a new 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 proposed
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 (see Thermal Dryer Memo in Docket EPA-
HQ-OAR-2008-0260). The incremental control cost of using venturi
scrubbers ranged from $3,100/ton for an emission level of 0.020 gr/dscf
to $16,000/ton for an emission level of 0.0050 gr/dscf.
Based on this analysis, we concluded that 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 electrostatic precipitator (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. This
level of control, however, has been
[[Page 25310]]
demonstrated at comparable, recently constructed facilities (see
Thermal Dryer Memo in Docket EPA-HQ-OAR-2008-0260). 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). Thus, although wet scrubbing is not considered BDT for
controlling PM emissions from new thermal dryers, the proposed level of
PM control would be achievable using wet control approaches, such as a
wet scrubber.
C. Selection of Thermal Dryer SO2, NOX, and CO Emissions Limits
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 fuel is emitted as SO2. There are
two possible reasons for this discrepancy: Either SO2
emissions are reduced by the wet scrubber installed to control PM or a
portion of the S02 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. 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 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 specifically 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 are likely to 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 one existing 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, we have concluded that BDT for controlling
PM from a new thermal dryer is a fabric filter. PM has historically
been the primary pollutant of concern for subpart Y affected
facilities. Therefore, in analyzing BDT for SO2 control, we
considered the incremental cost of controls to reduce SO2
emissions from thermal dryers with fabric filters.
Adding a wet scrubber for the sole purpose of controlling
SO2 emissions beyond 50 percent control (i.e., to achieve an
additional 40 percent control) has an incremental cost of over $5,000/
ton of SO2 controlled (see Thermal Dryer Memo in Docket EPA-
HQ-OAR-2008-0260). This high 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. In addition to the high costs, facilities with wet
scrubbers must dispose of the scrubber sludge. For these reasons, we
have concluded that wet scrubbers are not a cost-effective control
technology, and are not BDT for this source category.
For a lower cost option, 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 one 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 described in the Thermal Dryer
Memo in Docket EPA-HQ-OAR-2008-0260, the caustic spray is achieving
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, sufficient residence time, and a suitable
temperature range. 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 have
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 the reasons described above, we have concluded that dry sorbent
injection into the thermal dryer and spraying caustic onto the coal
prior to the thermal dryer are both BDT for SO2 reduction
from new, modified, and reconstructed thermal dryers. Also for the
reasons described above, we have concluded that a 50 percent
SO2 reduction is the standard that can be achieved by the
application of BDT for controlling SO2 emissions to a
thermal dryer. This standard reflects the degree of emissions reduction
achievable by the technology available and provides an adequate
compliance margin for both sorbent injection into the thermal dryer and
caustic spraying onto the coal prior to the drying chamber.
We are also proposing to establish a maximum emission rate of 520
ng/J (1.2 lb/MMBtu). We believe it is appropriate to establish this
upper limit, in addition to the 50 percent reduction requirement,
because control is easier and more cost-
[[Page 25311]]
effective at high pollutant concentrations. Adding a wet scrubber to
strictly control SO2 emissions for thermal dryers with an
actual stack emissions rate of 520 ng/J (1.2 lb/MMBtu) or more 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 are setting 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, 40 CFR part 60, subparts Da,
Db, and Dc. We continue to be interested in additional SO2
performance test data from thermal dryers and comparable facilities
using caustic sprays, sorbent injection, and scrubbers to control
SO2 emissions and are currently considering an
SO2 percent reduction requirement of between 50 and 90
percent for the final rule.
We are also proposing to add a combined NOX and CO
emission limit for thermal dryers. As explained below, we have
determined that advanced combustion controls are BDT for both
NOX and CO emissions from thermal dryers. Such controls can
achieve both low NOX and CO emissions. In addition, 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 volatile organic compound (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 are proposing to establish a combined NOX and
CO limit. The combined limit for modified and reconstructed units would
be 520 ng/J (1.0 lb/MMBtu). This level has been demonstrated as being
achievable for existing units (see Thermal Dryer Memo in Docket EPA-HQ-
OAR-2008-0260). The combined limit for new sources would be 280 ng/J
(0.65 lb/MMBtu). For new units, we evaluated what emission limits could
be achieved by application of BDT for both NOX and CO, and
relied on this evaluation to develop the combined standard. We have
previously established combined emissions limits for pollutants that
are inversely related in the NSPS for stationary compression ignition
internal combustion engines, 40 CFR part 60, subpart IIII.
We continue to be interested in additional NOX and CO
performance test data from thermal dryers and comparable facilities
using combustion controls to control both NOX and CO
emissions and are also considering, and requesting comment on, a
combined limit of between 390 ng/J (0.90 lb/MMBtu) and 470 ng/J (1.1
lb/MMBtu) for modified and reconstructed units and between 200 ng/J
(0.47 lb/MMBtu) and 300 ng/J (0.70 lb/MMBtu) for new units. In
addition, we are continuing to consider separate limits and
specifically request comment on whether a combined limit is
appropriate.
To determine the NOX and CO emission reductions
achievable from the application of BDT to thermal dryers, we examined
the nature of the emissions, demonstrated control technologies, and the
removal efficiencies of those technologies. 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). For reasons presented in the Thermal Dryer Memo in
Docket EPA-HQ-OAR-2008-0260, none of these control options are
technically feasible control options for a thermal dryer and they were
not evaluated as viable control technologies. However, we continue to
be interested in additional information that would indicate if SNCR
could be successfully integrated into a new thermal dryer and
specifically request comment on this issue. At this time, we have
determined that combustion controls are the only viable NOX
controls identified that could be used across the range of thermal
dryers presently used in the United States and, thus, we have
determined that combustion controls constitute BDT for NOX
emissions from thermal dryers. Available combustion controls include
low NOX burners (LNB), staged combustion, co-firing with
natural gas or liquefied petroleum gas (LPG), and flue gas
recirculation (FGR). These control options are described in the Thermal
Dryer Memo in Docket EPA-HQ-OAR-2008-0260.
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 that have demonstrated
NOX emissions of less than 0.60 lb/MMBtu. Our analysis
demonstrates that existing facilities could achieve this limit through
combustion controls alone.
Our analysis 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 for boilers less than 250 MMBtu/hr
for six 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 is less than $2,000 per ton and is
considered cost effective for this source category.
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
[[Page 25312]]
complete combustion, CO reacts with various oxidants to form carbon
dioxide (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. For reasons presented in the Thermal Dryer Memo
in Docket EPA-HQ-OAR-2008-0260, thermal oxidation and flaring,
catalytic oxidation, and catalytic incineration are not technically
feasible control options for a thermal dryer, and they were not
evaluated as viable control technologies. 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 also not considered to be a viable control techniques. For
these reasons, we conclude that good combustion practices constitute
BDT for CO emissions from thermal dryers.
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, we are basing 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 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 are not
proposing 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 the appropriate rate to use as 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 Clean Air
Act (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 to 230 ng/J
(0.0002 to 0.54 lb/MMBtu). At this time, we do not have the
corresponding NOX emissions data to determine if the low CO
emissions rates have a corresponding high NOX emissions
rate. These data indicate that 92 percent of existing small coal-fired
boilers are achieving a rate of 110 ng/J (0.25 lb/MMBtu) and 98 percent
are achieving a rate of 190 ng/J (0.45 lb/MMBtu).
D. Selection of Pneumatic Coal-Cleaning Equipment, Coal Processing and
Conveying Equipment, Coal Storage Systems, and Transfer and Loading
System PM and Opacity Limits
We are proposing standards for a wide variety of coal handling
equipment. For open storage piles and roadways, we are proposing,
consistent with CAA section 111(h), to establish work practice
standards. For other coal handling equipment, including pneumatic coal-
cleaning equipment, coal processing and conveying equipment, coal
storage systems, and transfer and loading systems, we are establishing
PM and/or opacity emission limits.
1. Open Storage Piles and Roadways
CAA section 111(h) provides that if, in the judgment of the
Administrator, it is not feasible to prescribe or enforce a standard of
performance, EPA may among other things, promulgate work practice,
design, or equipment standards. A determination that the emissions from
the sources cannot be measured due to technological or economic
limitations may be used to support a determination that it is not
feasible to establish standards of performance. It is difficult and
prohibitively expensive to measure actual PM emissions from individual
open storage piles or roadways. Further, the size of open storage piles
and the mobile nature of coal dust from vehicle tires on roadways make
the use of Method 9 opacity observations unreasonable in many
situations. For these reasons, the Administrator is proposing to
determine that it is not feasible to establish an emissions standard
for open storage piles or the coal dust associated with roadways. This
determination would support the proposed work practice standards
outlined below.
Based on that proposed determination, we are proposing to establish
the following work practice standards for open storage piles and coal
dust from roadways. We propose to require owners/operators of open
storage piles and roadways associated with coal preparation plants to
develop and comply with a fugitive dust emissions plan to control
fugitive PM emissions. These fugitive dust plans would be required to
contain the elements described below.
For open storage piles, we are proposing to require the fugitive
dust plan to prescribe the use of an enclosure, chemical suppressants
(including encrusting agents), wet suppression, a wind barrier, or a
vegetative cover to control emissions.
We are also proposing to require that the fugitive dust plan
include procedures for limiting emissions from all types of ``coal
processing and conveying equipment'' at a coal preparation plant.
Although the source category listing covers the entire coal preparation
plant, we have not previously established emission limits for all
facilities located at the plant. Because open storage piles were not
previously considered affected facilities, unloading and conveying
operations to an open storage pile were also not regulated. Only
unloading operations that were directly loaded into receiving equipment
were subject to an opacity limit. Because we are proposing to include
open storage piles as an affected facility, the loading, unloading, and
conveying operations of open storage piles would also be covered under
the fugitive dust emissions control plan, but not subject to an opacity
limit.
Open storage piles also include piles of coal that have been loaded
into trucks, railcars, and/or ships. At this time, we are not proposing
to require that the fugitive dust emissions control plan address
emissions from these piles.
[[Page 25313]]
We identified two potential control options for these piles: covers and
chemical encrusting agents. However, we have determined it is not
practical to require these controls. First, the majority of fugitive
emissions occur while the coal is in transit outside the physical
boundaries of the coal preparation plant. The emissions from the piles
while they are at the coal preparation plant have not been shown to be
significant. Second, it would not be economically feasible to require
end users to cover the coal or spray chemical suppressants as the coal
arrives on the property of the owner/operator and then proceed to
unload the coal.
We are also proposing to require that the permitting authority
approve the fugitive dust plans required by this subpart and to grant
specific authority to the permitting authority to approve alternate
technologies to control fugitive emissions from open storage piles and
coal dust from roadways. The permitting authority may approve the use
of such alternative technologies in the fugitive dust plan if it has
determined that the approved technology provides equivalent overall
environmental protection.
For roadways, we are proposing to require that the fugitive dust
plan require the owner/operator to pave the roads, wet the road
surface, sweep up excess coal dust, or install tire washes to remove
entrained dust to control PM emissions. For roadways that do not leave
the property (e.g., haul roads at coal mines), the owner/operator of
the coal preparation plant would not have to include such requirements
in the fugitive dust plan because of the particular impracticality of,
for example, paving roadways that are frequently re-routed.
2. Coal Handling Equipment
In the April 2008 proposal, we concluded that a fabric filter was
BDT for controlling PM emissions from coal-handling equipment
processing subbituminous and lignite coals. That determination provided
the basis for the proposed PM and opacity standards, and also for our
proposal requiring that coal-handling equipment processing
subbituminous and lignite coals be vented (i.e., connected to a duct or
stack) such that a PM performance test could be conducted on the
contained exhaust gas stream. As discussed more fully in the Coal
Handling Memo in Docket EPA-HQ-OAR-2008-0260, multiple commenters
disagreed with our BDT determination for several reasons. First, they
noted that the use of baghouses to collect subbituminous coal dust
presents potential safety concerns. For this reason alone, the
commenters argued that EPA should not use a baghouse as the basis for
the emissions rate. Second, their comments noted that although the use
of baghouses frequently results in low stack grain loadings, the
practice of returning the collected dust to the conveyor belt may cause
potential problems with fine coal dust emissions later in the coal
handling process, decreasing their overall effectiveness. Finally,
commenters identified multiple State best available control technology
(BACT) determinations that allow sources to remove existing baghouses
and replace them with passive enclosure containment systems (PECS),
fogging systems, or wet extraction scrubbers. Neither PECS nor fogging
systems can be vented, so the requirement to conduct a PM performance
test conflicts with such State BACT determinations.
Based on our review of public comments and subsequent analysis, we
have concluded that a baghouse is not the only technology that is BDT
for coal-handling equipment used on subbituminous and lignite coals.
Depending on the plant-specific circumstances, all four technologies
(fabric filters, PECS, fogging systems, and wet extraction scrubbers)
can control PM emissions equally well. They all provide equivalent
levels of emissions reductions; in addition, fogging systems, PECS, and
the wet extraction systems often have lower costs than baghouses. For
this reason, we are no longer proposing to require that all emissions
from such facilities be vented and are proposing PM and opacity limits
for coal-handling operations based on the level of reduction achievable
by these four technologies.
In the April 2008 proposal, we also determined that the use of
chemical suppressants was BDT for coal-handling equipment processing
bituminous coal. This determination also provided a basis for the
proposed PM and opacity limits. Multiple commenters disagreed with that
determination, stating that wet suppression is often used to control
fugitive PM from coal-handling operations processing bituminous coal
and that this control approach results in limited visible emissions
from the operation.
Based on our review of public comments and subsequent analysis, we
have reaffirmed our determination that BDT for coal-handling equipment
processing bituminous coal is the use of chemical suppressants. The
proposed opacity limit is based on that BDT determination. However, it
is important to note that although our BDT analysis identifies a
specific technology as BDT, the actual requirement in the rule is an
opacity limit, and an owner/operator can use any combination of
controls at a particular site as long as it demonstrates compliance
with the opacity limit. The owner/operator is not obligated to use the
specific technology identified as BDT.
Since the April 2008 proposal, we have performed an extensive data-
gathering effort for both PM performance test data and opacity
observations (both Method 9 and Method 22) on recently installed coal-
handling equipment. This data gathering is discussed in more detail in
the Coal Handling Memo in Docket EPA-HQ-OAR-2008-0260.
In the April 2008 proposal, we proposed to establish a PM limit of
0.011 g/dscm (0.0050 gr/dscf) for coal-handling equipment processing
subbituminous and lignite coals. We also proposed to require that all
such equipment vent emissions such that mass PM emissions from the
facility could be measured. Multiple commenters disagreed with the PM
limit, saying that it is technically difficult to achieve at some
locations and is more stringent than the BACT determinations from
multiple State permitting authorities. In addition, commenters
suggested we collect more PM emissions data specific to coal handling
operations.
As described earlier, we have reconsidered our prior BDT
determination and are now proposing a determination that any of four
technologies--fabric filters, PECS, fogging systems, and wet extraction
scrubbers--may be BDT, and we are establishing PM and opacity limits
consistent with that determination. Only the fabric filter technology
and wet extraction scrubbers are typically vented; PECS and fogging
systems technologies rely on reduced air flow and as such could not be
used if emissions are vented. Requiring venting of either PECS or
fogging systems would conflict with the design criteria of both
approaches. In this proposal, we are proposing to establish both PM and
opacity limits that would apply to all emissions that are vented, and
an opacity limit that would apply to all emissions that are not vented.
Based on our review of public comments and subsequent analysis, we
are proposing a change from the April 2008 proposed PM limit of 0.011
g/dscm (0.0050 gr/dscf) to 0.023 g/dscm (0.010 gr/dscf). The PM
performance test data specific to coal-handling equipment ranged from
0.001 to 0.011 gr/dscf. Based on the performance test data, we
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have concluded that although 0.011 g/dscm (0.0050 gr/dscf) has been
shown to be achievable, due to the limited data set, we are not
convinced that such a limit would be achievable on a long-term basis
for all affected facilities across the country. However, we have
concluded that 0.023 g/dscm (0.010 gr/dscf) is achievable for all sizes
of affected facilities and provides an adequate compliance margin to be
consistently achievable on a long-term basis for control technologies
that are vented through a stack. As shown in docket entries EPA-HQ-OAR-
2008-0260-0003.1 (``Discussion of Particulate Matter Control Concepts
for Coal Handling NSPS'') and -0035.1 (``Comments of the Utility Air
Regulatory Group''), this standard is also consistent with the majority
of recently issued permits.
We continue to be interested in additional performance test data
from recently installed fabric filters and wet extraction scrubbers and
are requesting comment on a PM standard of 0.020 g/dscm to 0.025 g/dscm
(0.0090 gr/dscf to 0.011 gr/dscf) for the final rule. All the PM
performance test data collected for this supplemental proposal show
emissions equal to or less than 0.025 g/dscm (0.011 gr/dscf). However,
the source with the highest PM emissions concentration has permit
requirements in lb/hr of PM emissions and the design emissions rate of
those fabric filters is unclear. All of the other PM performance test
data, including the individual tests runs, are below 0.020 g/dscm
(0.0090 gr/dscf).
In the April 2008 proposal, we proposed to amend the opacity limit
for coal-handling equipment from the existing 1976 limit of less than
20 percent to less than 5 percent. Multiple commenters opposed that
proposal for several reasons. First, the data used for the proposal
were largely based on data collected from the nonmetallic minerals
processing industry. In addition, commenters noted that because
individual Method 9 opacity observations are made in increments of 5
percent, a less than 5 percent opacity limit would mean that the
presence of any visible emissions would result in a violation.
Commenters asserted that it would be difficult to guarantee that each
affected facility will operate with no visible emissions at all times.
Also, because the proposed standard is based on a 6-minute reading,
there would be no opportunity for an owner/operator to fix a problem
prior to being in violation of the standard. Further, because opacity
from fugitive sources is more difficult to measure than from point
sources, they argued that the less than 5 percent limit was
unreasonable.
It is important to note that the April 2008 proposed limit of less
than 5 percent opacity is not the same as a no visible emissions limit.
A Method 9 performance test is conducted by taking one or more sets of
24 observations at 15-second intervals over a 6-minute period. Each
observation is reported in 5 percent increments. The 6-minute average
is calculated by averaging all observations made over the 6-minute
period. Thus, a 6-minute average based on both 0 and 5 percent opacity
readings (or higher), would not exceed the 5 percent standard as long
as the average is less than 5 percent. In contrast, a ``no visible
emissions'' limit for a Method 9 performance test would require all
opacity readings to be 0 percent.
Nonetheless, based on our review of public comments and subsequent
analysis, in this supplemental proposal we are proposing to change the
opacity limit for all subpart Y coal-handling facilities to no greater
than 5 percent. We gathered data on coal-handling operations at 25 coal
preparation plants, and the reported highest 6-minute average opacity
reading was 5 percent for a recently installed facility. Therefore, we
have concluded that this is an appropriate opacity limit for new
sources.
We are also specifically requesting comment on whether an opacity
limit of less than 10 percent is more appropriate than a limit of no
greater than 5 percent. The data we collected were primarily from
initial compliance tests, and we are requesting comment on whether the
5 percent limit is achievable on a long-term basis for all subpart Y
coal-handling facilities under all operating conditions, including
windy dry periods, and whether the limit provides an adequate
compliance margin. We are also requesting comment on establishing
different opacity limits for each type of coal-handling operation.
Finally, we are proposing to require periodic Method 9 performance
tests to assure compliance with the no greater than 5 percent standard.
However, to create an incentive for sources to operate with minimal
visible emissions (visible emissions readings less than 5 percent of
the time using Method 22) whenever possible, we are proposing to allow
owners/operators of facilities with the most recent Method 9
performance test of 3 percent or less opacity to qualify for reduced
monitoring requirements. Owners/operators of affected facilities
operating with minimal visible emissions would be able to elect to
perform periodic short opacity observations using Method 22 as an
alternative to Method 9 performance tests. Facilities with visible
emissions would have to perform periodic Method 9 performance tests
and, therefore, would have an incentive to operate without visible
emissions. We believe it is important to provide these incentives
because the data we have gathered suggest that many affected facilities
should be able to operate with zero opacity much of the time if they
are being properly operated and maintained.
E. Selection of Monitoring Requirements
In the April 2008 proposal, we proposed to require initial and
annual PM performance testing for each subpart Y affected facility with
an emissions limit. After further consideration, and for the reasons
explained below, we have concluded that it would be more appropriate to
require testing every other year of affected facilities operating at 50
percent or less of the applicable limit and reduced testing
requirements for facilities with relatively low potential emissions.
Reducing the frequency of compliance testing from annual to every
other year for owner/operators of affected facilities operating at 50
percent or less of the applicable limit both reduces compliance costs
and could provide benefits to the environment by recognizing the
environmental benefit of owners/operators installing controls beyond
what is required by the NSPS. By reducing monitoring requirements, we
are recognizing the increased environmental benefit of control
equipment that is both designed and operated in such a manner to exceed
the new source performance requirements and are incentivizing the
development of improved control technology. Also, if an affected
facility is tested as operating well below the standard, there is less
of a chance of exceeding the limit.
For smaller facilities with lower potential emissions, we have
concluded the cost of the testing proposed in the April 2008 proposal
is not justified by the information that would be gained from the
testing. In addition, we are not aware of an economically feasible way
to measure PM emissions from vent filters. Vent filters are typically
smaller than 2,000 actual cubic feet per minute (acfm), and the
exemption for affected facilities with potential emissions of less than
1.0 Mg (1.1 tons) equates to 2,800 standard cubic feet per minute
(scfm) at a design emissions rate of 0.010 gr/dscf. Furthermore,
smaller baghouses often do not come equipped with sampling access. It
would cost approximately $6,000 to add sampling
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ports and sampling platforms to each baghouse. Considering that
baghouse operations are often intermittent, potential emissions from
deterioration over time are expected to be low. Instead of requiring
annual performance tests, we are proposing to require that each
baghouse be monitored for visible emissions on an ongoing basis. We
have concluded that these visual observations should detect significant
problems such as holes and tears in the filter medium or if the filter
becomes unseated. Under these circumstances, visible emissions will
increase dramatically because part of the exhaust gas is emitted
directly to the atmosphere without any emissions reduction, resulting
in readily apparent visible emissions.
Similarly, for an owner/operator of up to five affected facilities
of the same type using identical control equipment with potential
annual emissions of less than 10 Mg each at a coal preparation plant,
we are proposing to allow a performance test on a single affected
facility as a check on the compliance of all of the affected facilities
with the emissions standard. We are allowing this option only where
performance test results are 90 percent of the standard, the design
emissions rate of the control device is less than or equal to the
applicable emission limit, and each affected facility is tested at
least once every 5 years. The facilities must perform the applicable
ongoing monitoring, and adhere to manufacturer's recommended
maintenance procedures. We concluded that for these sources the test
results at one control device will likely be representative of other
similar control devices, and that the additional compliance costs
associated with testing each affected facility would not result in
significant emissions reductions.
We are proposing to require bag leak detection systems for large
baghouses. We considered, but decided against, requiring installation
and use of a bag leak detection system at each affected facility using
a fabric filter to control PM. These detectors are useful and effective
for early detection of bag leaks; however, the capital costs of a bag
leak detection system can be as much as $24,000 and the annualized
costs might be as much as $7,000 (including capital recovery). These
costs are considered unjustifiably high for smaller baghouses with low
potential emissions at subpart Y affected facilities. Because potential
PM emissions from a bag leak are more significant for larger baghouses,
we are proposing to require a bag leak detection system for owners/
operators of baghouses with a potential annual emissions rate of 25 Mg
(28 tons) or more. This equates to a baghouse of approximately 70,000
scfm with a design emissions rate of 0.010 gr/dscf, or 140,000 scfm
with a design emissions rate of 0.0050 gr/dscf.
F. Selection of Opacity Monitoring Requirements for Pneumatic Coal-
Cleaning Equipment, Coal Processing and Conveying Equipment, Coal
Storage Systems, and Transfer and Loading System
In the April 2008 proposal, we proposed to require three 1-hour
Method 22 observations to monitor for visible emissions at all coal-
handling affected facilities. With this approach an owner/operator
could perform the initial readings on the first day of the month and
not perform a subsequent observation for 30 days. When a control device
is operating properly there should be minimal visible emissions and a
1-hour observation would not provide any significant additional useful
information than a 10-minute observation. In addition, allowing
extended periods of operation between observations could allow as much
as 30 days before a malfunctioning piece of control equipment is
identified. Therefore, we have concluded it is appropriate to decrease
the length of each observation to a minimum of 10 minutes, but to
increase the frequency to daily observations. By taking more frequent
observations, we assure that control equipment is consistently well
operated.
G. Required Electronic Reporting
We are also proposing to require owners/operators to submit
compliance test data electronically to EPA. Compliance test data are
necessary for compliance determinations and for EPA to conduct 8-year
reviews of CAA section 111 standards. The data are also used for many
other purposes such as developing emission factors and determining
annual emission rates. In conducting 8-year reviews, EPA has found it
burdensome and time-consuming to collect emission test data because the
data are often stored at varied locations through differing storage
methods. One improvement in recent years is the availability of stack
test reports in electronic format as a replacement for paper copies.
The proposed option to submit source test data electronically to EPA
would not require any additional performance testing. In addition, when
a facility submits performance test data to WebFIRE, there would be no
additional requirements for data compilation; instead, we believe
industry would greatly benefit from improved emissions factors, fewer
information requests, and better regulation development as discussed
below. Because the information that would be reported is already
required in the existing test methods and is necessary to evaluate
conformance to the test method, facilities would already be collecting
and compiling these data. One major advantage of electing to submit
source test data through the Electronic Reporting Tool (ERT), which was
developed with input from stack testing companies (who already collect
and compile performance test data electronically), is that it would
provide a standardized method to compile and store all the
documentation required by this rule. Another important benefit of
submitting these data to EPA at the time the source test is conducted
is that it will substantially reduce the effort involved in data
collection activities in the future. Specifically, because we would
already have adequate source category data to conduct NSPS reviews,
there would be fewer data collection requests (e.g., letters issued
under the authority of CAA section 114). This results in a reduced
burden on both affected facilities (in terms of reduced manpower to
respond to data collection requests) and EPA (in terms of preparing and
distributing data collection requests). Finally, another benefit of
electronic data submission is that these data will greatly improve the
overall quality of existing and new emissions factors by supplementing
the pool of emissions test data upon which a particular emission factor
is based, and by ensuring that the data are more representative of
current industry operational procedures. A common complaint from
industry and regulators is that emissions factors are outdated or not
representative of a particular source category. Additional performance
tests results would ensure that emissions factors are updated more
frequently and are more accurate. In summary, receiving the test data
already collected for other purposes and using them in the emissions
factors development program will save industry, State/local/tribal
agencies, and EPA time and money.
Data would be submitted electronically to the EPA database WebFIRE,
which is a Web site accessible through the EPA TTN. The WebFIRE Web
site was constructed to store emissions test data for use in developing
emission factors. A description of the WebFIRE database can be found at
http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. The ERT is an
interface program that transmits the
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electronic report through EPA's Central Data Exchange (CDX) network for
storage in the WebFIRE database. Although ERT is not the only
electronic interface that can be used to submit source test data to the
CDX for entry into WebFIRE, it is the most straightforward and easy way
to submit data. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert_tool.html. The ERT can be used to
document the conduct of stack tests data for various pollutants,
including PM (EPA Method 5 in appendix A-3), SO2 (EPA Method
6C in appendix A-4), NOX (EPA Method 7E in appendix A-4), CO
(EPA Method 10 in appendix A-4), cadmium (Cd) (EPA Method 29 in
appendix A-8), lead (Pb) (Method 29), mercury (Hg) (Method 29), and
hydrogen chloride (HCl) (EPA Method 26A in appendix A-8). The ERT does
not currently accept opacity data or CEMS data.
H. Addition of Petroleum Coke and Coal Refuse to the Definition of Coal
Petroleum coke and coal refuse are useful boiler fuels, have
similar PM emissions as primary coals, and the same equipment is used
to control PM emissions from the handling of primary coals, petroleum
coke, and coal refuse. Therefore, we are proposing to amend the
definition of coal in subpart Y to include petroleum coke and coal
refuse (after May 27, 2009). The standards in the original 1976 subpart
Y were based on data from coal preparation plants processing bituminous
coal at mines. However, the original applicability of subpart Y was
intentionally broad, and covered processing of all coal ranks and coal
processing at end-user locations (owner/operators of boilers, coke
ovens, etc.), as the mechanical processing of coal is the same
regardless of location.
Petroleum coke, a carbonaceous material, is a by-product residual
from the thermal cracking of heavy residual oil during the petroleum
refining process. Petroleum coke has a superior heating value and low
ash content compared to coal. However, depending on the original crude
feedstock, it may contain greater concentrations of sulfur and metals,
making it less attractive as a boiler fuel. Historically, petroleum
coke has been priced at a discount compared to coal. Because of the
increased use of heavier crudes and more efficient processing of
refinery residuals, U.S. and worldwide production of petroleum coke is
increasing and is expected to continue to grow.
Coal refuse, a by-product of coal mining and cleaning operations,
is generally a high ash (non-combustible rock), low Btu material. It is
cost-prohibitive to transport because of the weight per amount of
energy that can be extracted, and is usually burned close to the point
of generation. Large volumes of coal refuse began to accumulate at
mining sites when mining first began in the Appalachians in the 1970s.
Current mining operations continue to generate coal refuse; estimates
show that up to 1 billion tons of coal refuse were generated in 2007
alone. When subpart Y was originally published in 1976, there was no
way to cost-effectively dispose of coal refuse. Also, laws requiring
the stabilization and reclamation of mining sites were not established
until the late 1970s, after subpart Y was originally promulgated. After
the late 1970s, mining operations began to process coal refuse. With
the development of fluidized beds, it is burned for energy and is used
for other non-combustion products.
Petroleum coke can be interchanged with primary coals in pulverized
coal boilers, fluidized beds, and stoker boilers. Coal refuse can be
substituted for primary coals in fluidized beds and stoker boilers.
Petroleum coke and coal refuse are burned in the same boilers as
primary coals at the coal preparation plant and are processed alongside
the primary coals. The health impacts of PM from petroleum coke and
primary coals are similar; coverage of petroleum coke would therefore
further protect public health.
The approach proposed is consistent with subparts Db and Dc, the
large and small industrial boiler NSPS. Both subparts include petroleum
coke and coal refuse under the definition of coal. Subpart Da, the
utility boiler NSPS, was published prior to the industrial boiler NSPS,
and only includes coal refuse in the definition of coal. At the time
subpart Da was promulgated, petroleum coke was not considered to be
``created for the purpose of creating useful heat'' and hence was not
used in the fossil fuel capacity as it is today.
I. Additional Amendments
We are proposing to change the title of subpart Y to more
accurately reflect the affected facilities subject to subpart Y. The
original applicability included affected facilities that some in the
regulated community term ``processing'' facilities and would not call
those operations ``preparation'' even though the original rulemaking
used ``preparation'' more broadly. The revision is strictly intended to
clarify the rule and not change the applicability.
The definitional amendments and additional amendments are intended
to implement aspects of the rule discussed earlier and to update the
American Society of Testing and Materials (ASTM) test methods for the
different coal ranks. Also, because cyclonic flow is not used in
subpart Y, its removal would not impact the rule.
We have concluded that it is not appropriate or beneficial to the
public health to require an affected facility that is not currently in
operation to start up to demonstrate compliance with the NSPS.
Commencing operation strictly for the purposes of demonstrating
compliance is an unnecessary cost and increases emissions.
J. Emissions Reductions
EPA believes that the proposed amendments would not significantly
impact the overall compliance costs estimated for the original
proposal, $3 million, and would continue to have an insignificant
economic impact. However, EPA acknowledges that the overall emissions
reductions that would result from the proposed amendments and
associated costs of control are difficult to quantify precisely in
advance.
For thermal dryers and pneumatic coal-cleaning equipment, the
proposed amendments would significantly tighten control requirements.
Because these controls apply to new sources not yet in operation, it is
difficult to quantify the aggregated emissions reductions or costs for
those reductions in advance. However, we anticipate that there will be
only a limited number of new sources with thermal dryers or pneumatic
coal-cleaning equipment, so the overall costs associated with the
proposed amendments will likewise be limited. As to benefits, EPA
believes that the proposed amendments are necessary because they would
help to protect the public health and the environment by assuring that
appropriate controls would be installed on future new thermal dryers
and pneumatic coal-cleaning equipment should any be built.
The proposed pneumatic coal-cleaning PM standard is 40 percent
lower than the existing standard. For thermal dryers, the proposed PM
standard is one-third of the existing limit. The proposed
SO2 standard and combined NOX-CO standard for
these sources would reduce emissions by 50 percent from current
uncontrolled levels. For the model thermal dryer used in the costing
analysis, this equates to estimated annual reductions of 100 tons each
of PM and SO2 and 200 tons of combined NOX and
CO.
For coal handling operations, the proposed amendments would reduce
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the current opacity standard from less than 20 percent to no greater
than 5 percent. The proposal would thus reduce the opacity standard by
75 percent. Opacity is an indirect means to address the presence of PM
emissions and not an actual direct measurement of the mass of PM
emissions. Thus, in order to determine the precise amount of PM
reductions that would be associated with this change in the opacity
standard, we would need actual baseline PM emissions data at 20 percent
opacity for a source, which are not available. Without these data, it
is not possible for us to calculate the precise amount of PM reductions
associated with the more stringent opacity limit with a high degree of
certainty. We know, however, that lowering opacity from an affected
facility generally results in a reduction in PM emissions, provided
particle characteristics and size distribution remain similar for that
facility.
The existing subpart Y standards for coal handling equipment
include only an opacity limit. The proposed amendments would establish
a new PM standard of 0.023 g/dscm (0.010 gr/dscf) that would apply to
all sources that are mechanically vented. At this time we, only expect
end users processing bituminous coal to mechanically vent affected
facilities, and, thus, only these facilities would be subject to the
proposed new PM limit. Under the existing NSPS, affected facilities
that are mechanically vented would already need to install some type of
control device to comply with the 20 percent opacity limit. For coal
handling facilities that are mechanically vented, EPA believes that a
baghouse is the lowest cost option. If we assume that in the absence of
the proposed revisions such affected facilities would have installed
baghouses with an emissions limit equivalent to that of the pneumatic
coal-cleaning equipment (0.040 g/dscm), the proposed amendments reduce
emissions by an additional 40 percent. For the model bituminous power
plant used in the costing analysis, this equates to approximately 5
tons of PM reductions annually.
Based on public comment on the proposed amendments, we believe that
the majority of new coal handling operations at mines are likely to be
fugitive dust sources because they do not vent to a baghouse. In
addition, end user locations that process subbituminous coal are moving
toward PECS and fogging systems and would also be classified as
fugitive dust sources. In both cases, only the opacity standard would
apply. Thus, the aggregate costs of the new PM standard would be
limited.
Subpart Y has not been revised since it was originally promulgated
in 1976 and many States have more stringent control requirements. We
believe it is appropriate to consider these existing State requirements
when determining what is an appropriate baseline to compare against the
proposed amendments. The majority of State permitting authorities that
have more stringent control requirements require controls and work
practice standards that maintain opacity well below 20 percent. In
addition, any coal preparation plant that is subject to New Source
Review (NSR) would also already have control requirements significantly
more stringent than the existing NSPS. Therefore, EPA believes that
additional costs resulting from the proposed amendments should be
negligible for these affected facilities, and recognizes that
additional emissions reductions from such sources would be lower as
well.
IV. Modification and Reconstruction Provisions
Existing affected facilities at coal preparation plants that are
modified or reconstructed after the date on which standards applicable
to the facility are proposed are subject to the standard as finalized.
In revising the standards in subpart Y, we have considered whether
existing facilities that are reconstructed or modified will be able to
achieve the new standards. Where appropriate, we have proposed
different standards for new, modified, and reconstructed facilities. We
are not proposing any amendments to existing law regarding how a
facility would conduct the modification and reconstruction analysis.
V. Summary of Costs, Environmental, Energy, and Economic Impacts
In setting NSPS, the CAA requires EPA to consider alternative
emission control approaches, taking into account the estimated costs
and benefits, as well as energy, solid waste, and other effects. We
request comment on whether we have identified the appropriate
alternatives and whether the proposed standards adequately take into
consideration the incremental effects in terms of emission reductions,
energy, and other effects of these alternatives. We will consider the
available information in developing the final rule.
The costs and environmental, energy, and economic impacts are
expressed as incremental differences between the impacts of coal
preparation facilities complying with the proposed amendments and the
current common permitting authority requirements (i.e., baseline). We
have concluded that the supplemental proposal adds additional
compliance options and does not increase control costs or recordkeeping
and reporting costs above those of the April 2008 proposal. The April
2008 proposal economic impact analysis still holds; the amendments
would result in minimal changes in prices and output for the industries
affected by the final rule. The price increase for baseload
electricity, cement prices, coke prices, and coal prices are
insignificant.
VI. Request for Comment
We request comments on all aspects of the proposed amendments to
NSPS subpart Y. All significant comments received will be considered in
the development and selection of the final rule. We specifically
solicit comments on additional amendments that are under consideration.
These potential amendments are described below.
1. Control Technologies for Controlling Emissions From Thermal Dryers
No new thermal dryers have been installed at bituminous coal mines
in the past decade, and as described previously, we have concluded that
a new thermal dryer would likely use gas recirculation instead of a
once-through design. Although present coal-fired thermal dryer designs
use either stoker or pulverized coal burners, we are requesting comment
on the cost and whether it would be technically feasible to use a
fluidized bed design to generate the heat for the drying process. We
are also requesting comment on whether SNCR could be successfully
applied at a new thermal dryer for control of NOX emissions.
If either of these control technologies is determined to be possible
for a new thermal dryer, we will consider basing the combined
NOX and CO, and SO2 limits for new thermal dryers
on the use of these controls. Fluidized beds use limestone injection
into the bed and can reduce potential SO2 emissions by over
90 percent; SNCR reduces NOX emissions by as much as 50
percent.
We are also requesting comment on whether it would be appropriate
to set separate SO2 emissions standards for new,
reconstructed, and modified thermal dryers depending on whether the
dryer is a once-through design. As described earlier, once-though
dryers typically use scrubbers to control PM emissions and could
concurrently control SO2 emissions by 90 percent or more. If
we decide to set separate standards for once-through and recirculation
dryers, the once-through
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SO2 limit for new, reconstructed, and modified thermal
dryers would be changed to 85 ng/J (0.20 lb/MMBtu), or 90 percent
reduction in potential emissions and 520 ng/J (1.2 lb/MMBtu). The
corresponding definition of a once-through thermal dryer would be a
thermal dryer that does not recirculate any flue gas back to the
furnace for temperature tempering. We request comment on this
definition, as well as the standard discussed above.
In addition, we are requesting comment on establishing separate
SO2 limits based on the heat input capacity of the thermal
dryer. For thermal dryers with heat input capacities of 250 MMBtu/hr or
greater the incremental costs of scrubbers for the sole purpose of
reducing SO2 emissions is approximately $3,500 per ton and
is considered cost effective for this source category. If we decide to
set separate standards for larger thermal dryers, the large thermal
dryer SO2 limit for new, reconstructed, and modified thermal
dryers would be changed to 85 ng/J (0.20 lb/MMBtu), or 90 percent
reduction in potential emissions and 520 ng/J (1.2 lb/MMBtu).
2. PM Standard
We are considering, and requesting comment on, setting a more
stringent PM limit for operations with a high volume of air vented from
the affected facility. Larger control devices are more cost effective,
and we are specifically requesting comment on setting the PM limit for
coal handling and pneumatic coal cleaning equipment operations venting
more than 2,000 dscm/min (70,000 dscf/min) at 0.012 g/dscm (0.0054 gr/
dscf). Two-thirds of the post 1995 PM performance test results we
collected were below this limit, and those that were not had a lb/hr
limit and not a concentration limit and the design criteria for those
fabric filters are unknown.
3. Rear Truck Dumps
The physical size and operation characteristics of rear truck dumps
make operation with low instantaneous opacity difficult to achieve.
Several western subbituminous mining operations that began operation in
the late 1970s and early 1980s originally used enclosures and fabric
filters to control PM emissions from rear truck dumps. It was the only
viable technology at the time, but while PM and opacity emissions from
the fabric filter stack were relatively low, overall capture and
control were not as high. With the advent of larger coal trucks and
stilling sheds, the State of Wyoming has allowed for the replacement of
enclosures that are vented to a fabric filter with stilling sheds.
Stilling sheds provide a fairly high level of PM control. However, the
coal is dumped rapidly and there are instantaneous periods of high
opacity even when the 6-minute opacity is low. The State of Wyoming
determines if the still shed is working properly by averaging the
highest instantaneous 15-second opacity of 10 truck dumps. As long as
the average instantaneous opacity is less than 20 percent, the stilling
shed is determined to be operating properly. We are requesting comment
on whether requiring an annual average instantaneous opacity from 10
truck dumps is appropriate as an alternate to the Method 22 monitoring
required for other affected facilities.
4. Opacity Monitoring
A single coal preparation plant can contain multiple similar
affected facilities using similar control equipment configurations. To
reduce the burden of the rulemaking while still maintaining an
equivalent level of environmental protection, we are requesting comment
on allowing the permitting authority to approve a single Method 22
observation as sufficient monitoring for up to 4 other similar affected
facilities if the owner/operator agrees to site-specific equipment
inspection and maintenance procedures approved by the permitting
authority. If we include this approach in the final rule, the owner/
operator would have to observe a different affected facility in the
group each week and would still be required to conduct at least monthly
observations for each piece of equipment.
5. Thermal Dryer Monitoring
We are requesting comment on several of the monitoring requirements
for thermal dryers. First, owner/operators of thermal dryers are
required to continuously monitor the temperature of the gas stream at
the exit of the thermal dryer. We are requesting comment on the utility
of collecting this information. If we determine this requirement could
be eliminated without risk of a significant increase in emissions, we
will consider eliminating this requirement.
Second, subpart Y requires owner/operators of wet scrubbers to
continuously monitor the pressure drop through the venturi constriction
and the water supply pressure. However, there are no requirements
specified in the rule to maintain these values within a specified
range, nor requirements regarding what averaging period should be used
when determining the appropriate value. We are considering, and
requesting comment on, adding requirements that pressure drop and water
pressure be maintained at a minimum of 90 percent of the values
recorded during the most recent performance test, and that an operating
day average be used to determine the values.
Next, we are requesting comment on whether it is appropriate to
replace the water supply pressure monitoring requirement with a
requirement to monitor and maintain the water flow rate as determined
from the most recent performance test.
Finally, because we are adding additional standards for thermal
dryers we are considering, and requesting comment on, possible
monitoring requirements for SO2, NOX, and CO. We
request comment on requiring CEMS for monitoring SO2,
NOX, and CO emissions. If we do require CEMS, we would use
the same numerical emissions rate but the averaging period would be 30
days. We also request comment on alternative continuous monitoring
options. In the event we do not require CEMS, we would require other
continuous monitoring and require that the relevant parameters are
maintained within 10 percent of the value recorded during the
performance test on an operating day average. With regard to monitoring
for SO2, we are also considering, and requesting comment on,
whether pH and water flow rate monitoring are appropriate for owner/
operators of thermal dryers with a wet scrubber. In addition, for
owner/operators of thermal dryers without a wet scrubber, we are
considering, and requesting comment on, whether reagent injection flow
rate and airflow rate are the appropriate monitoring parameters. For
NOX and CO, we are considering, and requesting comment on,
requiring an O2 monitor prior to temperature tempering to
verify that the appropriate air-to-fuel ratio is maintained.
6. Opacity Standard for Open Storage Piles and Roadways
We are considering, and requesting comment on, both the feasibility
of establishing an opacity standard for open storage piles and roadways
and what opacity standard would be appropriate.
7. Work Practice Standards for Haul Roads
As an alternative to our proposal to exempt an owner/operator of
roadways that do not leave the property of the affected facility from
work practice standards directly, we request comment
[[Page 25319]]
on whether permitting authorities should be required to include other
fugitive dust prevention measures (e.g., wetting of the road surface,
sweeping of excess dust, tire washes) in the fugitive dust plan for
such roadways.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action'' because it may raise
novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in the EO.
Accordingly, EPA submitted this action to the OMB for review under EO
12866, and any changes made in response to OMB recommendations have
been documented in the docket for this action.
B. Paperwork Reduction Act
The information collection requirements associated with the April
2008 proposed rule have been submitted for approval to the OMB under
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information
Collection Request (ICR) document prepared by EPA has been assigned EPA
ICR number 1062.10. Because this supplemental proposal does not result
in additional recordkeeping and reporting requirements, a new ICR
document was not prepared.
The proposed amendments to the existing standards of performance
for Coal Preparation Plants would add new monitoring, reporting, and
recordkeeping requirements. The information would be used by EPA to
ensure that any new affected facilities comply with the emission limits
and other requirements. Records and reports would be necessary to
enable EPA or States to identify new affected facilities that may not
be in compliance with the requirements. Based on reported information,
EPA would decide which units and what records or processes should be
inspected.
The proposed amendments would not require any notifications or
reports beyond those required by the General Provisions. The
recordkeeping requirements require only the specific information needed
to determine compliance. These recordkeeping and reporting requirements
are specifically authorized by CAA section 114 (42 U.S.C. 7414). All
information submitted to EPA for which a claim of confidentially is
made will be safeguarded according to EPA policies in 40 CFR part 2,
subpart B, Confidentially of Business Information.
The annual monitoring, reporting, and recordkeeping burden for this
collection averaged over the first 3 years of this ICR is estimated to
total 32,664 labor hours per year at an average annual cost of
$2,957,707. This estimate includes performance testing, excess emission
reports, notifications, and recordkeeping. There are no capital/start-
up costs or operational and maintenance costs associated with the
monitoring requirements over the 3-year period of the ICR. Burden is
defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a current
valid OMB control number. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, EPA has established a public docket for
this rule, which includes this ICR, under Docket ID number EPA-HQ-OAR-
2008-0260. Submit any comments related to the ICR to EPA and OMB. See
ADDRESSES section at the beginning of this action for where to submit
comments to EPA. Send comments to OMB at the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street,
NW., Washington, DC 20503, Attention: Desk Office for EPA. Because OMB
is required to make a decision concerning the ICR between 30 and 60
days after May 27, 2009, a comment to OMB is best assured of having its
full effect if OMB receives it by June 26, 2009. The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
For purposes of assessing the impacts of the proposed amendments on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This
proposed rule will not impose any requirements on small entities.
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
The total annual control and monitoring costs of the proposed
amendments, compared to a baseline of no control, at year five is $2
million. Thus, this rule is not subject to the requirements of sections
202 or 205 of UMRA.
This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments.
E. Executive Order 13132: Federalism
EO 13132, entitled ``Federalism'' (64 FR 43255, August 10, 1999),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by State and local officials in the development of
regulatory policies that have federalism implications.'' ``Policies
that have federalism implications'' is defined in the EO to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
These proposed amendments do not have federalism implications. They
will not have substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government, as specified in EO 13132. These proposed amendments will
not impose substantial direct compliance costs on State or local
governments; they will not preempt State law. Thus, EO 13132 does not
[[Page 25320]]
apply to these proposed amendments. In the spirit of EO 13132, and
consistent with EPA policy to promote communications between EPA and
State and local governments, EPA specifically solicits comment on these
proposed amendments from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). We are not aware
of any coal preparation facilities owned by an Indian tribe. Thus,
Executive Order 13175 does not apply to this action.
EPA specifically solicits additional comment on this proposed
action from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
to those regulatory actions that concern health or safety risks, such
that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This proposed action is not
subject to EO 13045 because it is based solely on technology
performance.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This proposed action is not a ``significant energy action'' as
defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. Further, we have concluded that this
proposed action is not likely to have any adverse energy effects.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law No. 104-113 (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable VCS.
This proposed rulemaking involves technical standards. EPA proposes
to use ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' for its
manual methods of measuring the oxygen, carbon dioxide, sulfur dioxide
or nitrogen dioxide content of the exhaust gas. These parts of ASME PTC
19.10-1981 are acceptable alternatives to EPA Method 3B of appendix A-2
and EPA Methods 6, 6A, and 7 of appendix A-4 of 40 CFR part 60. This
standard is available from the American Society of Mechanical Engineers
(ASME), Three Park Avenue, New York, NY 10016-5990.
EPA also proposes to use EPA Methods 1, 1A, 2, 2A, 2C, 2D, 2F, 2G,
3, 3A, 3B, 4, 5, 5B, 5D, 6, 6A, 6C, 7, 7E, 9, 10, 17, and 22 (40 CFR
part 60, appendices A-1 through A-7). While the Agency has identified
20 VCS as being potentially applicable, we do not propose to use these
standards in this proposed rulemaking. The use of these VCS would be
impractical because they do not meet the objectives of the standards
cited in this proposed rule. The search and review results are in the
docket for this rule.
EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
EO 12898 (59 FR 7629, February 16, 1994) establishes Federal
executive policy on environmental justice. Its main provision directs
Federal agencies, to the greatest extent practical and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
United States.
EPA has determined that this proposed rule will not have
disproportionately high adverse human health or environmental effects
on minority or low-income populations because it increases the level of
environmental protection for all affected populations without having
any disproportionately high adverse human health or environmental
effects on any populations, including any minority or low-income
population. The proposed amendments would assure that all new coal
preparation plants install appropriate controls to limit health impacts
to nearby populations.
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: May 15, 2009.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
60, of the Code of the Federal Regulations is proposed to be amended as
follows:
PART 60--[AMENDED]
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
2. Section 60.17 is amended:
a. By revising paragraph (a)(13);
b. By removing paragraph (a)(14);
c. By redesignating paragraphs (a)(15) through (a)(93) as
paragraphs (a)(14) through (a)(92); and
d. By revising paragraph (h)(4) to read as follows.
Sec. 60.17 Incorporations by reference.
* * * * *
(a) * * *
(13) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004)[egr]\1\,
Standard Specification for Classification of Coals by Rank, IBR
approved for Sec. Sec. 60.24(h)(8), 60.41 of subpart D of this part,
60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da
of this part, 60.41b of subpart Db of this part, 60.41c of subpart Dc
of this part, 60.251 of subpart Y of this part, and 60.4102.
* * * * *
(h) * * *
(4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus], IBR approved for Sec. 60.106(e)(2) of
subpart J, Sec. Sec. 60.104a(d)(3), (d)(5), (d)(6), (h)(3), (h)(4),
(h)(5), (i)(3), (i)(4), (i)(5), (j)(3), and (j)(4), 60.105a(d)(4),
(f)(2), (f)(4), (g)(2), and (g)(4), 60.106a(a)(1)(iii), (a)(2)(iii),
(a)(2)(v), (a)(2)(viii), (a)(3)(ii), and (a)(3)(v), and
60.107a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (c)(2), (c)(4), and (d)(2)
of subpart Ja, Sec. 60.257(b)(3) of subpart Y, tables 1 and 3 of
subpart EEEE, tables 2 and 4 of subpart FFFF, table 2 of subpart JJJJ,
and
[[Page 25321]]
Sec. Sec. 60.4415(a)(2) and 60.4415(a)(3) of subpart KKKK of this
part.
* * * * *
Subpart Y--[Amended]
3. Part 60 is amended by revising subpart Y to read as follows:
Subpart Y--Standards of Performance for Coal Preparation and
Processing Plants
Sec.
60.250 Applicability and designation of affected facility.
60.251 Definitions.
60.252 Standards for thermal dryers.
60.253 Standards for pneumatic coal-cleaning equipment.
60.254 Standards for coal processing and conveying equipment, coal
storage system, and coal transfer system operations.
60.255 Performance tests and other compliance requirements.
60.256 Continuous monitoring requirements.
60.257 Test methods and procedures.
60.258 Reporting and recordkeeping.
Sec. 60.250 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to any of the
following affected facilities in coal preparation and processing plants
which process more than 181 megagrams (Mg) (200 tons) per day of coal:
Thermal dryers, pneumatic coal-cleaning equipment (air tables), coal
processing and conveying equipment (including breakers and crushers),
coal storage systems, and transfer and loading systems.
(b) Any affected facility under paragraph (a) of this section that
commences construction, reconstruction, or modification after October
24, 1974, is subject to the requirements of this subpart.
Sec. 60.251 Definitions.
As used in this subpart, all terms not defined herein have the
meaning given them in the Clean Air Act (Act) and in subpart A of this
part.
Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Bag leak detection system means a system that is capable of
continuously monitoring relative particulate matter (dust loadings) in
the exhaust of a fabric filter to detect bag leaks and other upset
conditions. A bag leak detection system includes, but is not limited
to, an instrument that operates on triboelectric, light scattering,
light transmittance, or other effect to continuously monitor relative
particulate matter loadings.
Bituminous coal means solid fossil fuel classified as bituminous
coal by ASTM D388 (incorporated by reference-see Sec. 60.17).
Coal for units constructed, reconstructed, or modified on or before
May 27, 2009 means all solid fossil fuels classified as anthracite,
bituminous, subbituminous, or lignite by ASTM D388 (incorporated by
reference-see Sec. 60.17). For units constructed, reconstructed, or
modified after May 27, 2009, coal means all solid fossil fuels
classified as anthracite, bituminous, subbituminous, or lignite by ASTM
D388 (incorporated by reference-see Sec. 60.17), coal refuse, and
petroleum coke.
Coal preparation and processing plant means any facility (excluding
underground mining operations) which prepares coal by one or more of
the following processes: breaking, crushing, screening, wet or dry
cleaning, and thermal drying.
Coal processing and conveying equipment means any machinery used to
reduce the size of coal or to separate coal from refuse, and the
equipment used to convey coal to or remove coal and refuse from the
machinery. This includes, but is not limited to, breakers, crushers,
screens, and conveying systems.
Coal refuse means debris product of coal mining or coal preparation
and processing operations (e.g., culm, gob, boney, slate dumps, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
Coal storage system for units constructed, reconstructed, or
modified on or before May 27, 2009 means any facility used to store
coal except for open storage piles. For units constructed,
reconstructed, or modified after May 27, 2009, coal storage system
means any facility used to store coal.
Design controlled potential PM emissions rate means the theoretical
particulate matter (PM) emissions (Mg) that would result from the
operation of a control device at its design emissions rate (grams per
dry standard cubic meter (g/dscm)), multiplied by the maximum design
flow rate (dry standard cubic meter per minute (dscm/min)), multiplied
by 60 (minutes per hour (min/hr)), multiplied by 8,760 (hours per year
(hr/yr)), divided by 1,000,000 (megagrams per gram (Mg/g)).
Indirect thermal dryer means a thermal dryer that reduces the
moisture content of coal through indirect heating of the coal through
contact with a heat transfer medium. If the source of heat (the source
of combustion or furnace) is subject to either subpart Da, Db, or Dc of
this part then the furnace and the associated emissions are not part of
the affected facility. However, if the source of heat is not subject to
either subpart Da, Db, or Dc of this part, then the furnace and the
associated emissions are part of the affected facility.
Lignite means coal that is classified as lignite A or B according
to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Mechanical vent means a vent using a powered mechanical drive
(machine) to induce air flow.
Operating day means a 24-hour period between 12 midnight and the
following midnight during which and coal is prepared or processed at
any time by the affected facility. It is not necessary that coal be
prepared or processed the entire 24-hour period.
Petroleum Coke also known as petcoke means a carbonization product
of high-boiling hydrocarbon fractions obtained in petroleum processing
(heavy residues). Petroleum coke is typically derived from oil refinery
coker units or other cracking processes.
Pneumatic coal-cleaning equipment for units constructed,
reconstructed, or modified on or before May 27, 2009 means any facility
which classifies bituminous coal by size or separates bituminous coal
from refuse by application of air stream(s). For units constructed,
reconstructed, or modified after May 27, 2009, pneumatic coal-cleaning
equipment means any facility which classifies coal by size or separates
coal from refuse by application of air stream(s).
Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J) or pounds per million British thermal units
(lb/MMBtu) heat input) that would result from combustion of a fuel in
an uncleaned state without emission control systems, as determined
using Method 19 of appendix A-7 of this part.
Subbituminous coal means coal that is classified as subbituminous
A, B, or C according to the American Society of Testing and Materials
in ASTM D388 (incorporated by reference, see Sec. 60.17).
Thermal dryer for units constructed, reconstructed, or modified on
or before May 27, 2009 means any facility in which the moisture content
of bituminous coal is reduced by contact with a heated gas stream which
is exhausted to the atmosphere. For units constructed, reconstructed,
or modified after May 27, 2009, thermal dryer means any facility in
which the moisture content of coal is reduced by either contact with a
heated gas stream which
[[Page 25322]]
is exhausted to the atmosphere or through indirect heating of the coal
through contact with a heated heat transfer medium.
Transfer and loading system means any facility used to transfer and
load coal for shipment.
Sec. 60.252 Standards for thermal dryers.
(a) On and after the date on which the performance test is
conducted or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of a thermal dryer constructed,
reconstructed, or modified on or before April 28, 2008, subject to the
provisions of this subpart must meet the requirements in paragraphs
(a)(1) and (a)(2) of this section.
(1) The owner or operator shall not cause to be discharged into the
atmosphere from the thermal dryer any gases which contain PM in excess
of 0.070 g/dscm (0.031 grains per dry standard cubic feet (gr/dscf));
and
(2) The owner or operator shall not cause to be discharged into the
atmosphere from the thermal dryer any gases which exhibit 20 percent
opacity or greater.
(b) On and after the date on which the performance test is
conducted or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of a thermal dryer constructed,
reconstructed, or modified after April 28, 2008, subject to the
provisions of this subpart must meet the applicable standards for PM,
sulfur dioxide (SO2), and combined nitrogen oxides
(NOX) and carbon monoxide (CO) as specified in paragraphs
(b)(1) through (3) of this section.
(1) The owner or operator must meet the requirements for PM
emissions in paragraphs (b)(1)(i) through (iii) of this section, as
applicable to the affected facility.
(i) For each thermal dryer constructed after April 28, 2008, the
owner or operator must meet the requirements of (b)(1)(i)(A) and
(b)(1)(i)(B).
(A) The owner or operator must not cause to be discharged into the
atmosphere from the thermal dryer any gases that contain PM in excess
of 0.023 g/dscm (0.010 grains per dry standard cubic feet (gr/dscf));
and
(B) The owner or operator must not cause to be discharged into the
atmosphere from the thermal dryer any gases that exhibit 10 percent
opacity or greater.
(ii) For each thermal dryer reconstructed after April 28, 2008, the
owner or operator must meet the requirements of paragraph (b)(1)(ii)(A)
and (b)(1)(ii)(B) of this section.
(A) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases that contain PM in
excess of 0.045 g/dscm (0.020 gr/dscf); and
(B) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases that exhibit 20 percent
opacity or greater.
(iii) For each thermal dryer modified after April 28, 2008, the
owner or operator must meet the requirements of paragraphs
(b)(1)(iii)(A) and (b)(1)(iii)(B) of this section.
(A) The owner or operator must not cause to be discharged to the
atmosphere from the affected facility any gases which contain PM in
excess of 0.070 g/dscm (0.031 gr/dscf); and
(B) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases which exhibit 20
percent opacity or greater.
(2) For each thermal dryer constructed, reconstructed, or modified
after May 27, 2009, the owner or operator must meet the requirements
for SO2 emissions in either paragraph (b)(2)(i) or (ii) of
this section, except for indirect thermal dryers where the source of
the heat is subject to either subpart Da, Db, or Dc of this part.
(i) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases that contain
SO2 in excess of 85 ng/J (0.20 lb/MMBtu) heat input; or
(ii) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases that either contain
SO2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input or
exceed 50 percent of the potential combustion concentration (i.e.,
achieve at least a 50 percent reduction of the potential combustion
concentration and do not exceed a maximum emissions rate of 1.2 lb/
MMBtu (520 ng/J)).
(3) The owner or operator must meet the requirements for combined
NOX and CO emissions in paragraph (b)(3)(i) or (ii) of this
section, as applicable to the affected facility, except for indirect
thermal dryers where the source of the heat is subject to either
subpart Da, Db, or Dc of this part.
(i) For each thermal dryer constructed after May 27, 2009, the
owner or operator must not cause to be discharged into the atmosphere
from the affected facility any gases which contain a combined
concentration of NOX and CO in excess of 280 ng/J (0.65 lb/
MMBtu) heat input.
(ii) For each thermal dryer reconstructed or modified after May 27,
2009, the owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases which contain combined
concentration of NOX and CO in excess of 430 ng/J (1.0 lb/
MMBtu) heat input.
Sec. 60.253 Standards for pneumatic coal-cleaning equipment.
(a) On and after the date on which the performance test is
conducted or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of pneumatic coal-cleaning equipment
constructed, reconstructed, or modified on or before April 28, 2008,
must meet the requirements of paragraphs (a)(1) and (a)(2) of this
section.
(1) The owner or operator must not cause to be discharged into the
atmosphere from the pneumatic coal-cleaning equipment any gases that
contain PM in excess of 0.040 g/dscm (0.017 gr/dscf); and
(2) The owner or operator must not cause to be discharged into the
atmosphere from the pneumatic coal-cleaning equipment any gases that
exhibit 10 percent opacity or greater.
(b) On and after the date on which the performance test is
conducted or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of pneumatic coal-cleaning equipment
constructed, reconstructed, or modified after April 28, 2008, must meet
the requirements in paragraphs (b)(1) and (b)(2) of this section.
(1) The owner of operator must not cause to be discharged into the
atmosphere from the pneumatic coal-cleaning equipment any gases that
contain PM in excess of 0.023 g/dscm (0.010 gr/dscf); and
(2) The owner or operator must not cause to be discharged into the
atmosphere from the pneumatic coal-cleaning equipment any gases that
exhibit greater than 5 percent opacity.
Sec. 60.254 Standards for coal processing and conveying equipment,
coal storage system, and coal transfer system operations.
(a) On and after the date on which the performance test is
conducted or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator shall not cause to be discharged into
the atmosphere from any coal processing and conveying equipment, coal
storage system, or coal transfer and loading system processing coal
constructed, reconstructed, or modified on or before April 28, 2008,
gases which exhibit 20 percent opacity or greater.
(b) On and after the date on which the performance test is
conducted or
[[Page 25323]]
required to be completed under Sec. 60.8, whichever date comes first,
an owner or operator of any coal processing and conveying equipment,
coal storage system, or coal transfer and loading system processing
coal constructed, reconstructed, or modified after April 28, 2008, must
meet the requirements in paragraphs (b)(1) through (3) of this section,
as applicable to the affected facility.
(1) The owner or operator must not cause to be discharged into the
atmosphere from the affected facility any gases which exhibit greater
than 5 percent opacity.
(2) The owner or operator must not cause to be discharged into the
atmosphere from any mechanical vent at the facility gases which contain
particulate matter in excess of 0.023 g/dscm (0.010 gr/dscf).
(3) The owner or operator must control fugitive coal dust emissions
from fugitive sources at the facility by operating according to a
written fugitive emissions control plan that has been approved by the
permitting authority. The fugitive emissions control plan must address
the fugitive emissions sources specified in paragraph (b)(3)(i) of this
section, as applicable to the affected facility, and include the
information specified in paragraph (b)(3)(ii) of this section.
(i) The fugitive emissions control plan must address each of the
fugitive emissions sources listed in paragraphs (b)(3)(i)(A) through
(C) of this section that are located at the facility.
(A) Open storage piles used for storage of coal.
(B) Roadways associated with and within the same contiguous
property as the coal preparation and processing plant.
(C) Other site-specific sources of fugitive emissions that the
Administrator or permitting authority determines need to be included in
your fugitive emissions control plan.
(ii) The fugitive emissions control plan must describe the control
measures the owner or operator shall use to minimize fugitive emissions
from each source addressed in the plan, and explain how the measures
are applicable and appropriate for the site conditions. For open
storage piles, the fugitive emissions plan must specify how one or more
of the following control measures will be used to minimize fugitive
coal dust: locating the source inside a partial enclosure, installing
and operating a water spray or fogging system, applying appropriate
chemical dust suppression agents on the source, use of a wind barrier,
or use of a vegetative cover. For roadways, the fugitive emissions plan
must specify how one or more of the following control measures will be
used to minimize fugitive dust: paving, sweeping excess coal dust,
wetting of the road surface, or tire washes. The permitting authority
may approve a fugitive emissions plan that includes control
technologies other than those specified above only if the owner or
operator has demonstrated to the Administrator that the alternate
control technology will provide equivalent overall environmental
protection or if it has determined to the Administrator that it is
either economically or technically infeasible for the affected facility
to use the control options specifically identified in this paragraph.
(iii) If the owner or operator of the affected facility is part of
a source which is subject to title V permitting, then the requirement
for the owner or operator to operate according to a written fugitive
emissions control plan which has been approved by the permitting
authority must be incorporated into the title V operating permit for
the source. Additionally, a copy of the fugitive emissions control plan
must be submitted to the permitting authority 90 days prior to the
compliance date for the affected facility. Any revisions to the
fugitive emissions control plan are not effective until approved by the
permitting authority. All of the requirements in this paragraph are to
be specified in any title V permit which covers the affected facility.
Sec. 60.255 Performance tests and other compliance requirements.
(a) An owner or operator of each affected facility that commenced
construction, reconstruction, or modification on or before April 28,
2008, must conduct all performance tests required by Sec. 60.8 to
demonstrate compliance with the applicable emission standards using the
methods identified in Sec. 60.257.
(b) An owner or operator of each affected facility that commenced
construction, reconstruction, or modification after April 28, 2008,
must conduct performance tests according to the requirements of Sec.
60.8 and the methods identified in Sec. 60.257 to demonstrate
compliance with the applicable emissions standards in this subpart as
specified in paragraphs (b)(1) and (2) of this section.
(1) For each affected facility subject to a PM, SO2, or
combined NOX and CO emissions standard, an initial
performance test must be performed except as provided for in paragraph
(d) of this section. Thereafter, a new performance test must be
conducted according to the requirements in paragraphs (b)(1)(i) and
(ii) of this section, as applicable.
(i) If the results of the most recent performance test demonstrate
that emissions from the affected facility are greater than 50 percent
of the applicable emissions standard, a new performance test must be
conducted within 12 calendar months of the date that the previous
performance test was required to be completed.
(ii) If the results of the most recent performance test demonstrate
that emissions from the affected facility are 50 percent or less of the
applicable emissions standard, a new performance test must be conducted
within 24 calendar months of the date that the previous performance
test was required to be completed.
(iii) An owner or operator of an affected facility that has not
operated for the 60 calendar days prior to the due date of a
performance test is not required to perform the subsequent performance
test until 30 calendar days after the next operating day.
(2) For each affected facility subject to an opacity standard, an
initial performance test must be performed. Thereafter, a new
performance test must be conducted according the requirements in
paragraphs (b)(2)(i) through (iv) of this section, as applicable,
except as provided for in paragraphs (e) and (f) of this section.
(i) If the maximum 15-second opacity reading in the most recent
performance test is greater than 5 percent, a new performance test must
be conducted within 7 operating days of the date that the previous
performance test was required to be completed.
(ii) If the maximum 15-second opacity reading in the most recent
performance test is 5 percent, a new performance test must be conducted
within 30 operating days of the date that the previous performance test
was required to be completed.
(iii) If no visible emissions are observed in the most recent
performance test, a new performance test must be conducted within 120
operating days of the date of the previous performance test was
required to be completed.
(iv) An owner or operator of affected facilities continuously
monitoring scrubber parameters as specified in Sec. 60.256 is exempt
from the requirements in paragraphs (b)(2)(i) through (iii) if opacity
performance tests are conducted concurrently (or within a 60-minute
period) with PM performance tests.
(c) An owner or operator of an affected facility subject to a PM
[[Page 25324]]
emission standard (other than a thermal dryer) that uses a control
device with a design control potential PM emissions rate of 1.0 Mg (1.1
tons) per year or less is exempted from the requirements of paragraphs
(b)(1)(i) and (ii) of this section provided that the owner or operator
meets all of the following conditions specified in paragraphs (c)(1)
through (4) of this section. This exemption does not apply to thermal
dryers.
(1) The design emissions limit is less than or equal to the
applicable PM emissions standard and the results of the most recent
performance test were less than or equal to the applicable limit,
(2) The control device manufacturer's recommended maintenance
procedures are followed, and
(3) The monitoring requirements in paragraphs (e) or (f) of this
section are followed.
(d) An owner or operator of a group of up to five of the same type
of affected facilities that are subject to PM emissions standards and
use identical control devices each with a design potential PM emissions
rate of 10 Mg (11 tons) per year or less, the permitting authority may
allow the owner or operator to use a single PM performance test for one
of the affected control devices to demonstrate that the group of
affected facilities is in compliance with the applicable emissions
standards provided that the owner or operator meets all of the
following conditions specified in paragraphs (d)(1) through (4) of this
section.
(1) The design emissions limit for each individual affected
facility is less than or equal to the applicable PM emissions limit and
the performance test for each individual affected facility is 90
percent or less of the applicable PM standard;
(2) The manufacturer's recommended maintenance procedures are
followed for each control device;
(3) The monitoring requirements in paragraph (e) or (f) of this
section are used for each affected facility; and
(4) A performance test is conducted on each affected facility at
least once every 5 calendar years.
(e) As an alternative to meeting the requirements in paragraph
(b)(2)(i) through (iii) of this section, an owner or operator of an
affected facility for which the maximum 6-minute opacity reading from
the most recent Method 9 of appendix A-4 of this part performance test
is less than 3 percent may elect to comply with the requirements in
paragraph (e)(1) or (2) of this section.
(1) Monitor visible emissions from each affected facility according
to the requirements in either paragraph (e)(1)(i) or (ii) of this
section.
(i) Conduct daily observations each operating day for a period of
at least 10 minutes (during normal operation) when the coal preparation
and processing plant is in operation using EPA Method 22 of appendix A-
7 of this part and demonstrate that the sum of the occurrences of any
visible emissions is not in excess of 5 percent of the observation
period (i.e., 30 seconds per 10-minute period). If the sum of the
occurrence of any visible emissions is greater than 30 seconds during
the initial 10-minute observation, immediately conduct a 30-minute
observation. If the sum of the occurrence of visible emissions is
greater than 5 percent of the observation period (i.e., 90 seconds per
30-minute period) the owner or operator shall either document and
adjust the operation of the facility and demonstrate within 24 hours
that the sum of the occurrence of visible emissions is equal to or less
than 5 percent during a 30-minute observation (i.e., 90 seconds) or
conduct a new Method 9 of appendix A-4 of this part performance test
within 30 calendar days unless a waiver is granted by the permitting
authority.
(ii) If no visible emissions are observed for 7 consecutive
operating days, observations can be reduced to once every 7 operating
days. If any visible emissions are observed, daily observations shall
be resumed.
(2) Prepare a written site-specific monitoring plan for a digital
opacity compliance system for approval by the Administrator. The plan
shall require observations of at least one digital image every 15
seconds for 10-minute periods (during normal operation) every operating
day. An approvable monitoring plan must include a demonstration that
the occurrences of visible emissions are not in excess of 5 percent of
the observation period. For reference purposes in preparing the
monitoring plan, see OAQPS ``Determination of Visible Emission Opacity
From Stationary Sources Using Computer-Based Photographic Analysis
Systems.'' This document is available from the U.S. Environmental
Protection Agency (U.S. EPA); Office of Air Quality and Planning
Standards; Sector Policies and Programs Division; Measurement Group
(D243-02), Research Triangle Park, NC 27711. This document is also
available on the Technology Transfer Network (TTN) under Emission
Measurement Center Preliminary Methods. The monitoring plan approved by
the Administrator shall be implemented by the owner or operator.
(f) As an alternative to meeting the requirements in paragraph
(b)(2) of this section, an owner or operator of an affected facility
subject to a visible emissions standard under this subpart may install,
operate, and maintain a continuous opacity monitoring system (COMS).
Each COMS used to comply with provisions of this subpart must be
installed, calibrated, maintained, and continuously operated according
to the requirements in paragraphs (f)(1) and (2) of this section.
(1) The COMS must meet Performance Specification 1 in 40 CFR part
60, appendix B.
(2) The COMS must comply with the quality assurance requirements in
paragraphs (f)(2)(i) through (v) of this section.
(i) The owner or operator must automatically (intrinsic to the
opacity monitor) check the zero and upscale (span) calibration drifts
at least once daily. For particular COMS, the acceptable range of zero
and upscale calibration materials is as defined in the applicable
version of Performance Specification 1 in 40 CFR part 60, appendix B.
(ii) The owner or operator must adjust the zero and span whenever
the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity.
The COMS must allow for the amount of excess zero and span drift
measured at the 24-hour interval checks to be recorded and quantified.
The optical surfaces exposed to the effluent gases must be cleaned
prior to performing the zero and span drift adjustments, except for
systems using automatic zero adjustments. For systems using automatic
zero adjustments, the optical surfaces must be cleaned when the
cumulative automatic zero compensation exceeds 4 percent opacity.
(iii) The owner or operator must apply a method for producing a
simulated zero opacity condition and an upscale (span) opacity
condition using a certified neutral density filter or other related
technique to produce a known obscuration of the light beam. All
procedures applied must provide a system check of the analyzer internal
optical surfaces and all electronic circuitry including the lamp and
photodetector assembly.
(iv) Except during periods of system breakdowns, repairs,
calibration checks, and zero and span adjustments, the COMS must be in
continuous operation and must complete a minimum of one cycle of
sampling and analyzing for each successive 10-second period and one
cycle of data recording for each successive 6-minute period.
[[Page 25325]]
(v) The owner or operator must reduce all data from the COMS to 6-
minute averages. Six-minute opacity averages must be calculated from 36
or more data points equally spaced over each 6-minute period. Data
recorded during periods of system breakdowns, repairs, calibration
checks, and zero and span adjustments must not be included in the data
averages. An arithmetic or integrated average of all data may be used.
Sec. 60.256 Continuous monitoring requirements.
(a) The owner or operator of each affected facility constructed,
reconstructed, or modified on or before April 28, 2008, must meet the
monitoring requirements specified in paragraphs (a)(1) and (2) of this
section, as applicable to the affected facility.
(1) The owner or operator of any thermal dryer shall install,
calibrate, maintain, and continuously operate monitoring devices as
follows:
(i) A monitoring device for the measurement of the temperature of
the gas stream at the exit of the thermal dryer on a continuous basis.
The monitoring device is to be certified by the manufacturer to be
accurate within 1.7 [deg]C (3 [deg]F).
(ii) For affected facilities that use wet scrubber emission control
equipment:
(A) A monitoring device for the continuous measurement of the
pressure loss through the venturi constriction of the control
equipment. The monitoring device is to be certified by the manufacturer
to be accurate within 1 inch water gauge.
(B) A monitoring device for the continuous measurement of the water
supply pressure to the control equipment. The monitoring device is to
be certified by the manufacturer to be accurate within 5
percent of design water supply pressure. The pressure sensor or tap
must be located close to the water discharge point. The Administrator
shall have discretion to grant requests for approval of alternative
monitoring locations.
(2) All monitoring devices under paragraph (a) of this section are
to be recalibrated annually in accordance with procedures under Sec.
60.13(b).
(b) The owner or operator of each affected facility constructed,
reconstructed, or modified after April 28, 2008, that has one or more
mechanical vents must install, calibrate, maintain, and continuously
operate the monitoring devices specified in paragraphs (b)(1) and (2)
of this section, as applicable to the mechanical vent and any control
device installed on the vent.
(1) For mechanical vents with fabric filters (baghouses) with the
design controlled potential PM emissions rate of 25 Mg (28 tons) per
year or more, a bag leak detection system according to the requirements
in paragraph (c) of this section.
(2) For mechanical vents with wet scrubbers, monitoring devices
according to the requirements in paragraphs (b)(2)(i) and (ii) of this
section.
(i) A monitoring device for the continuous measurement of the
pressure loss through the venturi constriction of the control
equipment. The monitoring device is to be certified by the manufacturer
to be accurate within 1 inch water gauge.
(ii) A monitoring device for the continuous measurement of the
water supply pressure to the control equipment. The monitoring device
is to be certified by the manufacturer to be accurate within 5 percent of design water supply pressure. The pressure sensor or
tap must be located close to the water discharge point.
(c) Each bag leak detection system used to comply with provisions
of this subpart must be installed, calibrated, maintained, and
continuously operated according to the requirements in paragraphs
(c)(1) through (3) of this section.
(1) The bag leak detection system must meet the specifications and
requirements in paragraphs (c)(1)(i) through (viii) of this section.
(i) The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 1 milligram per dry standard cubic meter (mg/dscm) (0.00044 grains
per actual cubic foot (gr/acf)) or less.
(ii) The bag leak detection system sensor must provide output of
relative PM loadings. The owner or operator shall continuously record
the output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger).
(iii) The bag leak detection system must be equipped with an alarm
system that will sound when the system detects an increase in relative
particulate loading over the alarm set point established according to
paragraph (c)(1)(iv) of this section, and the alarm must be located
such that it can be heard by the appropriate plant personnel.
(iv) In the initial adjustment of the bag leak detection system,
the owner or operator must establish, at a minimum, the baseline output
by adjusting the sensitivity (range) and the averaging period of the
device, the alarm set points, and the alarm delay time.
(v) Following initial adjustment, the owner or operator must not
adjust the averaging period, alarm set point, or alarm delay time
without approval from the Administrator or permitting authority except
as provided in paragraph (c)(2)(vi) of this section.
(vi) Once per quarter, the owner or operator may adjust the
sensitivity of the bag leak detection system to account for seasonal
effects, including temperature and humidity, according to the
procedures identified in the site-specific monitoring plan required by
paragraph (c)(2) of this section.
(vii) The owner or operator must install the bag leak detection
sensor downstream of the fabric filter.
(viii) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(2) The owner or operator must develop and submit to the permitting
authority for approval a site-specific monitoring plan for each bag
leak detection system. This plan must be submitted to the permitting
authority 90 days prior to the compliance date for the affected
facility. The owner or operator must operate and maintain the bag leak
detection system according to the site-specific monitoring plan at all
times. Each monitoring plan must describe the items in paragraphs
(c)(2)(i) through (vi) of this section.
(i) Installation of the bag leak detection system;
(ii) Initial and periodic adjustment of the bag leak detection
system, including how the alarm set-point will be established;
(iii) Operation of the bag leak detection system, including quality
assurance procedures;
(iv) How the bag leak detection system will be maintained,
including a routine maintenance schedule and spare parts inventory
list;
(v) How the bag leak detection system output will be recorded and
stored; and
(vi) Corrective action procedures as specified in paragraph (c)(3)
of this section. In approving the site-specific monitoring plan, the
Administrator or permitting authority may allow the owner and operator
more than 3 hours to alleviate a specific condition that causes an
alarm if the owner or operator identifies in the monitoring plan this
specific condition as one that could lead to an alarm, adequately
explains why it is not feasible to alleviate this condition within 3
hours of the time the alarm occurs, and demonstrates that the requested
time will ensure alleviation of this condition as expeditiously as
practicable.
[[Page 25326]]
(3) For each bag leak detection system, the owner or operator must
initiate procedures to determine the cause of every alarm within 1 hour
of the alarm. Except as provided in paragraph (c)(2)(vi) of this
section, the owner or operator must alleviate the cause of the alarm
within 3 hours of the alarm by taking whatever corrective action(s) are
necessary. Corrective actions may include, but are not limited to the
following:
(i) Inspecting the fabric filter for air leaks, torn or broken bags
or filter media, or any other condition that may cause an increase in
PM emissions;
(ii) Sealing off defective bags or filter media;
(iii) Replacing defective bags or filter media or otherwise
repairing the control device;
(iv) Sealing off a defective fabric filter compartment;
(v) Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or
(vi) Shutting down the process producing the PM emissions.
Sec. 60.257 Test methods and procedures.
(a) The owner or operator must determine compliance with the
applicable opacity standards as specified in paragraphs (a)(1) through
(4) of this section.
(1) Method 9 of appendix A-4 of this part and the procedures in
Sec. 60.11 must be used to determine opacity.
(2) To determine opacity for fugitive emissions sources, the
additional requirements specified in paragraphs (a)(2)(i) through (iii)
of this section must be used.
(i) The minimum distance between the observer and the emission
source shall be 5.0 meters (16 feet), and the sun shall be oriented in
the 140-degree sector of the back.
(ii) The observer shall select a position that minimizes
interference from other fugitive emissions sources and make
observations such that the line of vision is approximately
perpendicular to the plume and wind direction.
(iii) The observer shall make opacity observations at the point of
greatest opacity in that portion of the plume where condensed water
vapor is not present. Water vapor is not considered a visible emission.
(3) If during the initial 60 minutes of the observation of a Method
9 of appendix A-4 of this part performance test all of the individual
15-second observations are less than or equal to 20 percent and all of
the resulting 6-minute averages are less than or equal to 3 percent or
half the applicable limit, whichever is greater, then the observation
period may be reduced from 3 hours to 60 minutes.
(4) A visible emissions observer may conduct visible emission
observations for up to three fugitive, stack, or vent emission points
within a 15-second interval if the following conditions specified in
paragraphs (a)(4)(i) through (iii) of this section are met.
(i) No more than three emissions points may be read concurrently.
(ii) All three emissions points must be within a 70-degree viewing
sector or angle in front of the observer such that the proper sun
position can be maintained for all three points.
(iii) If an opacity reading for any one of the three emissions
points is within 5 percent opacity from the applicable standard
(excluding readings of zero opacity), then the observer must stop
taking readings for the other two points and continue reading just that
single point.
(b) The owner or operator must conduct all performance tests
required by Sec. 60.8 to demonstrate compliance with the applicable
emissions standards specified in Sec. 60.252 according to the
requirements in Sec. 60.8 using the applicable test methods and
procedures in paragraphs (b)(1) through (8) of this section.
(1) Method 1 or 1A of appendix A-4 of this part shall be used to
select sampling port locations and the number of traverse points in
each stack or duct. Sampling sites must be located at the outlet of the
control device (or at the outlet of the emissions source if no control
device is present) prior to any releases to the atmosphere.
(2) Method 2, 2A, 2C, 2D, 2F, or 2G of appendix A-4 of this part
shall be used to determine the volumetric flow rate of the stack gas.
(3) Method 3, 3A, or 3B of appendix A-4 of this part shall be used
to determine the dry molecular weight of the stack gas. The owner or
operator may use ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses'' (incorporated by reference--see Sec. 60.17) as an
alternative to EPA Method 3B of appendix A-2 of this part.
(4) Method 4 of appendix A-4 of this part shall be used to
determine the moisture content of the stack gas.
(5) Method 5, 5B or 5D of appendix A-4 of this part or Method 17 of
appendix A-7 of this part shall be used to determine the PM
concentration as follows:
(i) The sampling time and sample volume for each run shall be at
least 60 minutes and 0.85 dscm (30 dscf). Sampling shall begin no less
than 30 minutes after startup and shall terminate before shutdown
procedures begin. A minimum of three valid test runs are needed to
comprise a PM performance test.
(ii) Method 5 of appendix A of this part shall be used only to test
emissions from affected facilities without wet flue gas desulfurization
(FGD) systems.
(iii) Method 5B of appendix A of this part is to be used only after
wet FGD systems.
(iv) Method 5D of appendix A-4 of this part shall be used for
positive pressure fabric filters and other similar applications (e.g.,
stub stacks and roof vents).
(v) Method 17 of appendix A-6 of this part may be used at
facilities with or without wet scrubber systems provided the stack gas
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F).
The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of
this part may be used in Method 17 of appendix A-6 of this part only if
it is used after a wet FGD system. Do not use Method 17 of appendix A-6
of this part after wet FGD systems if the effluent is saturated or
laden with water droplets.
(6) Method 6, 6A, or 6C of appendix A-4 of this part shall be used
to determine the SO2 concentration. A minimum of three valid
test runs are needed to comprise an SO2 performance test.
(7) Method 7 or 7E of appendix A-4 of this part shall be used to
determine the NOX concentration. A minimum of three valid
test runs are needed to comprise an NOX performance test.
(8) Method 10 of appendix A-4 of this part shall be used to
determine the CO concentration. A minimum of three valid test runs are
needed to comprise a CO performance test. CO performance tests are
conducted concurrently (or within a 30- to 60-minute period) with
NOX performance tests.
Sec. 60.258 Reporting and recordkeeping.
(a) The owner or operator of a coal preparation and processing
plant that commenced construction, reconstruction, or modification
after April 28, 2008, shall maintain in a logbook (written or
electronic) on-site and make it available upon request. The logbook
shall record the following:
(1) The manufacturer's recommended maintenance procedures and the
date and time of any maintenance and inspection activities and the
results of those activities. Any variance from manufacturer
recommendation, if any, shall be noted.
(2) The date and time of periodic coal preparation and processing
plant opacity observations noting those sources with emissions above
the action
[[Page 25327]]
level (visible emissions in excess of 5 percent of the observation
period) along with corrective actions taken to reduce visible
emissions. Results from the actions shall be noted.
(3) The amount and type of coal processed each calendar month.
(4) The amount of chemical stabilizer or water purchased for use in
the coal preparation and processing plant.
(5) Monthly certification that the dust suppressant systems were
operational when any coal was processed and that manufacturer's
recommendations were followed for all control systems. Any variance
from the manufacturer's recommendations, if any, shall be noted.
(6) A copy of any applicable fugitive dust emissions control plan
and monthly certification that the plan was implemented as described.
Any variance from plan, if any, shall be noted.
(7) For each bag leak detection system, the owner or operator must
keep the records specified in paragraphs (a)(7)(i) through (iii) of
this section.
(i) Records of the bag leak detection system output;
(ii) Records of bag leak detection system adjustments, including
the date and time of the adjustment, the initial bag leak detection
system settings, and the final bag leak detection settings; and
(iii) The date and time of all bag leak detection system alarms,
the time that procedures to determine the cause of the alarm were
initiated, the cause of the alarm, an explanation of the actions taken,
the date and time the cause of the alarm was alleviated, and whether
the cause of the alarm was alleviated within 3 hours of the alarm.
(8) A copy of any applicable monitoring plan for a digital opacity
compliance system and monthly certification that the plan was
implemented as described. Any variance from plan, if any, shall be
noted.
(9) During a performance test of a wet scrubber, and each operating
day thereafter, the owner or operator shall record the measurements of
both the scrubber pressure loss and water supply pressure.
(b) For the purpose of reports required under Sec. 60.7(c), any
owner/operator subject to the provisions of this subpart shall report
semiannually periods of excess emissions as follows:
(1) The owner or operator of an affected facility with a wet
scrubber shall submit semiannual reports to the Administrator of
occurrences when the measurements of the scrubber pressure loss and
water supply pressure decrease by more than 10 percent from the average
determined during the most recent performance test.
(2) All 6-minute average opacities that exceed the applicable
standard.
(c) The owner or operator of an affected facility shall submit the
results of initial performance tests to the Administrator, consistent
with the provisions of Sec. 60.8. The owner or operator who elects to
comply with the reduced performance testing provisions of Sec. Sec.
60.255(c) or (d) shall include in the performance test report
identification of each affected facility that will be subject to the
reduced testing, and the design emissions limit of each associated
control device. The owner or operator electing to comply with Sec.
60.255(d) shall also include information which demonstrates that the
control devices are identical.
(d) After July 1, 2011, within 60 days after the date of completing
each performance evaluation conducted to demonstrate compliance with
this subpart, the owner or operator of the affected facility must
submit the test data to EPA by successfully entering the data
electronically into EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. For performance tests
that cannot be entered into WebFIRE (i.e., Method 9 of appendix A-4 of
this part opacity performance tests) the owner or operator of the
affected facility must mail a summary copy to United States
Environmental Protection Agency, Energy Strategies Group, 109 TW
Alexander DR, mail code: D243-01, RTP, NC 27711.
[FR Doc. E9-11912 Filed 5-26-09; 8:45 am]
BILLING CODE 6560-50-P