[Federal Register: February 18, 2005 (Volume 70, Number 33)]
[Proposed Rules]
[Page 8314-8332]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr18fe05-22]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[OAR-2004-0490, FRL-7874-1]
RIN 2060-AM79
Standards of Performance for Stationary Combustion Turbines
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: The EPA is proposing standards of performance for new
stationary combustion turbines in 40 CFR part 60, subpart KKKK. The new
standards would reflect changes in nitrogen oxides (NOX)
emission control technologies and turbine design since standards for
these units were originally promulgated in 40 CFR part 60, subpart GG.
The NOX and sulfur dioxide (SO2) standards have
been established at a level which brings the emission limits up to date
with the performance of current combustion turbines and their
emissions.
DATES: Comments must be received on or before April 19, 2005, or 30
days after the date of any public hearing, if later.
Public Hearing. If anyone contacts EPA by March 10, 2005,
requesting to speak at a public hearing, EPA will hold a public hearing
on March 21, 2005. If you are interested in attending the public
hearing, contact Ms. Eloise Shepherd at (919) 541-5578 to verify that a
hearing will be held.
ADDRESSES: Submit your comments, identified by Docket ID No. OAR-2004-
0490, by one of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the on-line instructions for submitting comments.
Agency Web site: http://www.epa.gov/edocket. EDOCKET,
EPA's electronic public docket and comment system, is EPA's preferred
method for receiving comments. Follow the on-line instructions for
submitting comments.
E-mail: Send your comments via electronic mail to
a-and-r-docket@epa.gov, Attention Docket ID No. OAR-2004-0490.
[[Page 8315]]
Fax: Fax your comments to (202) 566-1741, Attention Docket
ID No. OAR-2004-0490.
Mail: Send your comments to: EPA Docket Center (EPA/DC),
Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR-2004-0490.
Please include a total of two copies. The EPA requests a separate copy
also be sent to the contact person identified below (see FOR FURTHER
INFORMATION CONTACT). 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 St. NW., Washington, DC 20503.
Hand Delivery: Deliver your comments to: EPA Docket Center
(EPA/DC), EPA West Building, Room B108, 1301 Constitution Ave., NW.,
Washington DC, 20460, Attention Docket ID No. OAR-2004-0490. Such
deliveries are accepted only during the normal hours of operation (8:30
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays),
and special arrangements should be made for deliveries of boxed
information.
Instructions: Direct your comments to Docket ID No. OAR-2004-0490.
The 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.epa.gov/edocket
, 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 EDOCKET, regulations.gov, or e-
mail. The EPA EDOCKET and the Federal regulations.gov Web sites are
``anonymous access'' systems, 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 EDOCKET or 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 EDOCKET on-line or see the Federal Register of May 31,
2002 (67 FR 38102).
Docket: All documents in the docket are listed in the EDOCKET index
at http://www.epa.gov/edocket. Although listed in the index, some
information is not publicly available, i.e., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically in EDOCKET or in hard
copy at the Docket, EPA/DC, EPA West, Room B102, 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 EPA Docket Center is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Jaime Pagan, Combustion Group,
Emission Standards Division (C439-01), U.S. EPA, Research Triangle
Park, North Carolina 27711; telephone number (919) 541-5340; facsimile
number (919) 541-5450; e-mail address ``pagan.jaime@epa.gov.''
SUPPLEMENTARY INFORMATION: Organization of This Document. The
following outline is provided to aid in locating information in this
preamble.
I. General Information
A. Does This Action Apply to Me?
B. What Should I Consider as I Prepare My Comments for EPA?
II. Background Information
III. Summary of the Proposed Rule
A. Does the Proposed Rule Apply to Me?
B. What Pollutants Would Be Regulated?
C. What Is the Affected Source?
D. What Emission Limits Must I Meet?
E. If I Modify or Reconstruct My Existing Turbine, Does the
Proposed Rule Apply To Me?
F. How Do I Demonstrate Compliance?
G. What Monitoring Requirements Must I Meet?
H. What Reports Must I Submit?
IV. Rationale for the Proposed Rule
A. Why Did EPA Choose Output-Based Standards?
B. How Did EPA Determine the Proposed NOX Limits?
C. How Did EPA Determine the Proposed SO2 Limit?
D. What Other Criteria Pollutants Did EPA Consider?
E. How Did EPA Determine Testing and Monitoring Requirements for
the Proposed Rule?
F. Why Are Heat Recovery Steam Generators Included in 40 CFR
part 60, Subpart KKKK?
G. What Emission Limits Must I Meet if I Fire More Than One Type
of Fuel?
H. Why Can I No Longer Claim a Fuel-Bound Nitrogen Allowance?
I. Why Isn't My IGCC Turbine Covered in 40 CFR Part 60, Subpart
KKKK?
V. Environmental and Economic Impacts
A. What Are the Air Impacts?
B. What Are the Energy Impacts?
C. What Are the Economic Impacts?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork 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 that Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
I. General Information
A. Does This Action Apply to Me?
Regulated Entities. Categories and entities potentially regulated
by this action are those that own and operate new stationary combustion
turbines with a peak rated power output greater than or equal to 1
megawatt (MW). Regulated categories and entities include:
[[Page 8316]]
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Category NAICS SIC Examples of regulated entities
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Any industry using a new stationary 2211 4911 Electric services.
combustion turbine as defined in the
proposed rule.
486210 4922 Natural gas transmission.
211111 1311 Crude petroleum and natural gas.
211112 1321 Natural gas liquids.
221 4931 Electric and other services,
combined.
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This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility is regulated by this action,
you should examine the applicability criteria in section 60.4305 of the
proposed rule. For further information concerning applicability and
rule determinations, contact the appropriate State or local agency
representative. For information concerning the analyses performed in
developing the New Source Performance Standards (NSPS), consult the
contact person listed in the preceding FOR FURTHER INFORMATION CONTACT
section.
B. What Should I Consider as I Prepare My Comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through
EDOCKET, regulations.gov or e-mail. Send or deliver information
identified as CBI to only the following address: Mr. Jaime Pagan, c/o
OAQPS Document Control Officer (Room C404-02), U.S. EPA, Research
Triangle Park, NC 27711, Attention Docket ID No. OAR-2004-0490. Clearly
mark the part or all of the information that you claim to be CBI. For
CBI information in a disk or CD ROM that you mail to EPA, mark the
outside of the disk or CD ROM as CBI and then identify electronically
within the disk or CD ROM the specific information that is claimed as
CBI. In addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
2. Tips for Preparing Your Comments. When submitting comments,
remember to:
a. Identify the rulemaking by docket number and other identifying
information (subject heading, Federal Register date and page number).
b. Follow directions. The EPA may ask you to respond to specific
questions or organize comments by referencing a Code of Federal
Regulations (CFR) part or section number.
c. Explain why you agree or disagree; suggest alternatives and
substitute language for your requested changes.
d. Describe any assumptions and provide any technical information
and/or data that you used.
e. If you estimate potential costs or burdens, explain how you
arrived at your estimate in sufficient detail to allow for it to be
reproduced.
f. Provide specific examples to illustrate your concerns, and
suggest alternatives.
g. Explain your views as clearly as possible, avoiding the use of
profanity or personal threats.
h. Make sure to submit your comments by the comment period deadline
identified.
Docket. The docket number for the proposed NSPS (40 CFR part 60,
subpart KKKK) is Docket ID No. OAR-2004-0490.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the proposed rule is also available on the WWW
through the Technology Transfer Network Website (TTN Web). Following
signature, EPA will post a copy of the proposed rule on the TTN's
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. If you
need more information regarding the TTN, call the TTN HELP line at
(919) 541-5384.
II. Background Information
This action proposes NSPS that would apply to new stationary
combustion turbines greater than or equal to 1 MW that commence
construction, modification or reconstruction after February 18, 2005.
The NSPS are being proposed pursuant to section 111 of the Clean Air
Act (CAA) which requires the EPA to promulgate and periodically revise
the NSPS, taking into consideration available control technologies and
the costs of control. The EPA promulgated the NSPS for stationary gas
turbines in 1979 (44 FR 52798). Since promulgation of the NSPS for
stationary gas turbines, many advances in the design and control of
emissions from stationary turbines have occurred. Nitrogen oxides and
SO2 are known to cause adverse health and environmental
effects. The proposed standards represent reductions in the
NOX and SO2 limits of over 80 and 93 percent,
respectively. The output-based standards in the proposed rule would
allow owners and operators the flexibility to meet their emission limit
targets by increasing the efficiency of their turbines.
III. Summary of the Proposed Rule
A. Does the Proposed Rule Apply to Me?
Today's proposed standards would apply to new stationary combustion
turbines with a power output at peak load greater than or equal to 1
MW. The applicability of the proposed rule is similar to that of
existing 40 CFR part 60, subpart GG, except that the proposed rule
would apply to new stationary combustion turbines, and their associated
heat recovery steam generators (HRSG) and duct burners. A new
stationary combustion turbine is defined as any simple cycle combustion
turbine, regenerative cycle combustion turbine, or combined cycle
steam/electric generating system that is not self-propelled and that
commences construction, modification, or reconstruction after February
18, 2005. The new stationary combustion turbines subject to the
proposed standards are exempt from the requirements of 40 CFR part 60,
subpart GG. Heat recovery steam generators and duct burners subject to
the proposed rule would be exempt from the requirements of 40 CFR part
60, subparts Da and Db.
B. What Pollutants Would Be Regulated?
The pollutants to be regulated by the proposed standards are
NOX and SO2.
C. What Is the Affected Source?
The affected source for the proposed stationary combustion turbine
NSPS is each stationary combustion turbine with a power output at peak
load greater than or equal to 1 MW, that commences construction,
modification, or reconstruction after February 18, 2005. Integrated
gasification combined cycle (IGCC) combustion turbine facilities
covered by subpart Da of 40 CFR part 60 (the Utility NSPS) are exempt
from the requirements of the proposed rule.
[[Page 8317]]
D. What Emission Limits Must I Meet?
The format of the proposed standards for NOX is an
output-based emission limit in units of emissions mass per unit useful
recovered energy, nanograms/Joule (ng/J) or pounds per megawatt-hour
(lb/MW-hr). There are four subcategories, and thus four separate
output-based NOX limits. These are presented in Table 1 of
this preamble. The output of the turbine does not include any steam
turbine output and refers to the rating of the combustion turbine
itself.
Table 1.--NOX Emission Standards (ng/J)
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Combustion turbine size
Combustion turbine fuel type -------------------------------------------------------------------------
< 30 MW >= 30 MW
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Natural gas........................... 132 (1.0 lb/MW-hr) 50 (0.39 lb/MW-hr)
Oil and other fuel.................... 234 (1.9 lb/MW-hr) 146 (1.2 lb/MW-hr)
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We have determined that it is appropriate to exempt emergency
combustion turbines from the NOX limit. We have defined
these units as turbines that operate in emergency situations. For
example, turbines used to supply electric power when the local utility
service is interrupted are considered to fall under this definition. In
addition, we are proposing that combustion turbines used by
manufacturers in research and development of equipment for both
combustion turbine emission control techniques and combustion turbine
efficiency improvements be exempted from the NOX limit.
Given the small number of turbines that are expected to fall under this
category and since there is not one definition that can provide an all-
inclusive description of the type of research and development work that
qualifies for the exemption from the NOX limit, we have
decided that it is appropriate to make these exemption determinations
on case by case basis only.
The proposed standard for SO2 is the same for all
turbines regardless of size and fuel type. You may not cause to be
discharged into the atmosphere from the subject stationary combustion
turbine any gases which contain SO2 in excess of 73 ng/J
(0.58 lb/MW-hr). You would be able to choose to comply with the
SO2 limit itself or with a limit on the sulfur content of
the fuel. We are proposing this sulfur content limit to be 0.05 percent
by weight (500 parts per million by weight (ppmw)).
E. If I Modify or Reconstruct My Existing Turbine, Does the Proposed
Rule Apply to Me?
The proposed standards would apply to stationary combustion
turbines that are modified or reconstructed after February 18, 2005.
The guidelines for determining whether a source is modified or
reconstructed are given in 40 CFR 60.14 and 60.15, respectively.
F. How Do I Demonstrate Compliance?
In order to demonstrate compliance with the NOX limit,
an initial performance test is required. If you are using water or
steam injection, you must continuously monitor your water or steam to
fuel ratio in order to demonstrate compliance and you are not required
to perform annual stack testing to demonstrate compliance. If you are
not using water or steam injection, you would conduct performance tests
annually following the initial performance test in order to demonstrate
compliance. Alternatively, you may choose to demonstrate continuous
compliance with the use of a continuous emission monitoring system
(CEMS) or parametric monitoring; if you choose this option, you are not
required to conduct subsequent annual performance tests.
If you are using a NOX CEMS, the initial performance
test required under 40 CFR 60.8 may, alternatively, coincide with the
relative accuracy test audit (RATA). If you choose this as your initial
performance test, you must perform a minimum of nine reference method
runs, with a minimum time per run of 21 minutes, at a single load
level, between 90 and 100 percent of peak (or the highest achievable)
load. You must use the test data both to demonstrate compliance with
the applicable NOX emission limit and to provide the
required reference method data for the RATA of the CEMS. The
requirement to test at three additional load levels is waived.
G. What Monitoring Requirements Must I Meet?
If you are using water or steam injection to control NOX
emissions, you would have to install and operate a continuous
monitoring system to monitor and record the fuel consumption and the
ratio of water or steam to fuel being fired in the turbine.
Alternatively, you could use a CEMS consisting of NOX and
oxygen (O2) or carbon dioxide (CO2) monitors.
During each full unit operating hour, each monitor would complete a
minimum of one cycle of operation for each 15-minute quadrant of the
hour. For partial unit operating hours, at least one valid data point
would be obtained for each quadrant of the hour in which the unit
operates.
If you operate any new turbine which does not use water or steam
injection to control NOX emissions, you would have to
perform annual stack testing to demonstrate continuous compliance with
the NOX limit. Alternatively, you could elect either to use
a NOX CEMS or perform continuous parameter monitoring as
follows:
(1) For a diffusion flame turbine without add-on selective
catalytic reduction (SCR) controls, you would define at least four
parameters indicative of the unit's NOX formation
characteristics, and you would monitor these parameters continuously;
(2) For any lean premix stationary combustion turbine, you would
continuously monitor the appropriate parameters to determine whether
the unit is operating in the lean premixed combustion mode;
(3) For any turbine that uses SCR to reduce NOX
emissions, you would continuously monitor appropriate parameters to
verify the proper operation of the emission controls; and
(4) For affected units that are also regulated under part 75 of
this chapter, if you elect to monitor the NOX emission rate
using the methodology in appendix E to part 75 of this chapter, or the
low mass emissions methodology in 40 CFR 75.19, the monitoring
requirements of the turbine NSPS may be met by performing the
parametric monitoring described in section 2.3 of appendix E of part 75
of this chapter or in 40 CFR 75.19(c)(1)(iv)(H).
Alternatively, you could petition the Administrator for other
acceptable methods of monitoring your emissions. If you choose to use a
CEMS or perform parameter monitoring to demonstrate
[[Page 8318]]
continuous compliance, annual stack testing is not required.
If you operate any stationary combustion turbine subject to the
provisions of the proposed rule, and you choose not to comply with the
SO2 stack limit, you would monitor the total sulfur content
of the fuel being fired in the turbine. There are several options for
determining the frequency of fuel sampling, consistent with appendix D
to part 75 of this chapter for fuel oil; and the sulfur content would
be determined and recorded once per unit operating day for gaseous
fuel, unless a custom fuel sampling schedule is used. Alternatively,
you could elect not to monitor the total sulfur content of the fuel
combusted in the turbine, if you demonstrate that the fuel does not to
exceed a total sulfur content of 300 ppmw. This demonstration may be
performed by using the fuel quality characteristics in a current, valid
purchase contract, tariff sheet, or transportation contract, or through
representative fuel sampling data which show that the sulfur content of
the fuel does not exceed 300 ppmw.
If you choose to monitor combustion parameters or parameters
indicative of proper operation of NOX emission controls, the
appropriate parameters would be continuously monitored and recorded
during each run of the initial performance test, to establish
acceptable operating ranges, for purposes of the parameter monitoring
plan for the affected unit.
If you are required to periodically determine the sulfur content of
the fuel combusted in the turbine, a minimum of three fuel samples
would be collected during the performance test. For liquid fuels, the
samples for the total sulfur content of the fuel must be analyzed using
American Society of Testing and Materials (ASTM) methods D129-00,
D2622-98, D4294-02, D1266-98, D5453-00 or D1552-01. For gaseous fuels,
ASTM D1072-90 (Reapproved 1999); D3246-96; D4468-85 (Reapproved 2000);
or D6667-01 must be used to analyze the total sulfur content of the
fuel.
The applicable ranges of some ASTM methods mentioned above are not
adequate to measure the levels of sulfur in some fuel gases. Dilution
of samples before analysis (with verification of the dilution ratio)
may be used, subject to the approval of the Administrator.
H. What Reports Must I Submit?
For each affected unit for which you continuously monitor
parameters or emissions, or periodically determine the fuel sulfur
content under the proposed rule, you would submit reports of excess
emissions and monitor downtime, in accordance with 40 CFR 60.7(c).
Excess emissions would be reported for all 4-hour rolling average
periods of unit operation, including start-up, shutdown, and
malfunctions where emissions exceed the allowable emission limit or
where one or more of the monitored process or control parameters
exceeds the acceptable range as determined in the monitoring plan.
IV. Rationale for the Proposed Rule
A. Why Did EPA Choose Output-Based Standards?
We have written the proposed standards to incorporate output-based
NOX and SO2 limits. The primary benefit of
output-based standards is that they recognize energy efficiency as a
form of pollution prevention. The use of more efficient technologies
reduces fossil fuel use and leads to reductions in the environmental
impacts associated with the production and use of fossil fuels. Another
benefit is that output-based standards allow sources to use energy
efficiency as a part of their emissions control strategy. This provides
an additional compliance option that can lead to reduced compliance
costs as well as lower emissions.
Several States have initiated regulations or permits-by-rule for
distributed generation (DG) units, including combustion turbines.
States that have made efforts to regulate DG sources include
California, Texas, New York, New Jersey, Connecticut, Delaware, Maine,
and Massachusetts. Those State rules include emission limits that are
output-based, and many allow generators that use combined heat and
power (CHP) to take credit for heat recovered. For example, Texas
recently passed a DG permit-by-rule regulation that gives facilities
100 percent credit for steam generation thermal output, and
incorporates HRSG and duct burners under the same limit. The California
Air Resources Board (CARB) also has output-based emission limits which
allow DG units that use CHP to take a credit to meet the standards, at
a rate of 1 MW-hr for each 3.4 million British thermal units (MMBtu) of
heat recovered, or essentially, 100 percent. The draft rules for New
York and Delaware also allow DG sources using CHP to receive credit
toward compliance with the emission standards.
B. How Did EPA Determine the Proposed NOX Limits?
Over the last several years NOX performance in
combustion turbines has improved dramatically. At the current time,
lean premix turbines, or dry low NOX, dominate the market
for combustion turbines fired by natural gas. To determine the proposed
NOX limits, we evaluated stack test data for stationary
combustion turbines of different sizes. The data provided us with
information on actual NOX emissions performance in relation
to the size of the unit and the type of fuel being used. In addition,
we obtained information from turbine manufacturers on the
NOX levels that they guarantee for their new stationary
combustion turbines. We only used these manufacturer guarantees to
confirm the NOX levels observed in the stack test data that
we studied.
We considered requiring the use of SCR in setting the limit for
NOX. However, we determined that the costs for SCR were high
compared to the incremental difference in emission concentration. Newer
large turbines without add-on controls can readily achieve 9 or 10
parts per million (ppm). The use of SCR might bring this level down to
2 to 4 ppm. In addition, SCR may be difficult to implement for turbines
operating under variable loads. We determined that the incremental
benefit in emissions reductions did not justify the costs and technical
challenges associated with the addition and operation of SCR.
Therefore, we did not base the NOX emission limit on this
add-on control. However, add-on control technologies may be required at
the State or local level, for Prevention of Significant Deterioration
(PSD) and New Source Review (NSR) programs.
We identified a distinct difference in the technologies and
capabilities between small and large turbines. We found the breaking
point between these two turbine types to be 30 MW. Smaller turbines
have less space to install NOX reducing technologies such as
lean premix combustor design. In addition, the smaller combustion
chamber of small turbines provides inadequate space for the adequate
mixing needed for very low NOX emission levels. The design
differences between small and large turbines leads to different
emission characteristics. When we examined data of NOX
emissions versus turbine size, there was a clear difference in
NOX emissions for turbines below and above 30 MW. In
addition, manufacturer guarantees are, generally speaking, higher for
smaller turbines, because of differences in design and technologies.
The 30 MW cutoff is consistent with the manufacturer guarantees.
As explained below, the output-based NOX limits being
proposed are based on
[[Page 8319]]
concentration levels that are achievable by new stationary combustion
turbines without the use of add-on controls such as SCR. Also, it is
important to note that the output-based limits were determined using
thermal efficiencies typical of full-load operation.
Small Natural Gas Fired Turbines
We are proposing the NOX limit for small (less than 30
MW) natural gas-fired turbines to be 132 ng/J, or 1.0 lb/MW-hr. This
limit is based on a NOX emission concentration of 25 ppm and
a turbine efficiency of 30 percent. Multiple manufacturers guarantee 25
ppm NOX for natural gas-fired turbines of all sizes,
including those less than 30 MW. Since actual NOX emissions
are considerably lower than the guaranteed levels for most turbines, an
emission limit based on a NOX level of 25 ppm at 15 percent
O2 for small natural gas-fired turbines can readily be
achieved without the use of additional controls. We also gathered many
recent source tests, supporting the conclusion that the majority of new
small natural gas-fired turbines can achieve NOX levels
lower than 25 ppm at 15 percent O2 without the use of add-on
controls. Regarding efficiency, a significant number of small turbines
are simple cycle; therefore, we selected the baseline efficiency of 30
percent for small simple cycle natural gas-fired turbines.
Large Natural Gas Fired Turbines
We are proposing a NOX emission limit of 50 ng/J (0.39
lb/MW-hr) for large natural gas-fired turbines (greater than or equal
to 30 MW). The proposed NOX output-based limit for large
natural gas-fired turbines is based on a NOX emission
concentration of 15 ppm at 15 percent O2 and a combined
cycle turbine efficiency of 48 percent, which also equates to a
NOX emission concentration of 9 ppm at 15 percent
O2 and a simple cycle turbine at an efficiency of 29
percent. Many manufacturers guarantee NOX emissions of 15
ppm at 15 percent O2 for large natural gas-fired turbines,
and a few even guarantee NOX levels at or below 9 ppm at 15
percent O2. In addition, we have gathered a number of source
tests which confirm that these turbines can achieve these levels
without the use of add-on controls. Therefore, this emission limit may
be achieved by most large natural gas combustion turbines without the
use of add-on controls. Other options for new turbine owners and
operators include the following: Add a SCR add-on control device to a
simple cycle turbine which does not have a low NOX
guarantee, or locate their turbine where the exhaust heat can be
recovered as useful output (a combined cycle unit or CHP unit).
Distillate Oil Fired Turbines
Very few turbines sold today are solely distillate oil-fired.
However, a significant number of turbines which primarily fire natural
gas also have the capability to fire distillate oil. We are proposing a
NOX emission limit of 234 ng/J (1.9 lb/MW-hr) for small
distillate oil-fired turbines, and 146 ng/J (1.2 lb/MW-hr) for large
distillate oil-fired turbines. When firing distillate oil fuel, the
majority of turbine manufacturers guarantee a NOX emission
level of 42 ppm at 15 percent O2, regardless of turbine
size. We confirmed through the analysis of recent source test reports
provided by States that this level is achievable by the majority of new
distillate oil-fired turbines without the use of add-on controls. The
basis for the output-based emission limits for distillate oil-fired
turbines is 42 ppm NOX at 15 percent O2; for
small turbines, a 30 percent efficiency, and for large turbines, a 48
percent efficiency. The 30 percent efficiency for small oil-fired
turbines is consistent with that of simple-cycle units, while the 48
percent efficiency for large oil-fired turbines is consistent with that
of combined-cycle units. This approach is appropriate since there are
almost no oil-fired simple-cycle turbines in the ``greater than 30 MW''
category. We would like to request comment on this issue and the
appropriateness of the NOX limits for oil-fired simple-cycle
turbines that are greater than 30 MW. Furthermore, since according to
our information, most of these simple-cycle turbines are used as
peaking units, we would like to request comments on an alternative
approach that allows large oil-fired peaking units to meet the same
NOX limit that applies to the small units.
The proposed output-based NOX limits for oil-fired
combustion turbines can be achieved when operating at loads near 100
percent, where the thermal efficiency tends to be the highest. However,
at part-loads, there may be concern about higher output-based
NOX levels emitted due to the lower thermal efficiencies
that are characteristic under those conditions. We request comment on
the ability of oil-fired combustion turbines to meet the proposed
NOX limits under part-load operation.
Other Fuels
It is expected that few turbines would burn fuels other than
natural gas and distillate oil. Turbines that burn other fuels would
have to comply with the NOX emission limit for distillate
oil. We understand that there are concerns about certain fuels, such as
landfill, digester and other waste gases, process, refinery or syn
gases, and other alternative fuels. Of particular concern are the fuels
that are of lower heating value or of highly variable heating value,
that are in locations where these fuels would be flared or otherwise
disposed without energy recovery. Landfill and digester gases have
considerably lower heating values than natural gas, making it more
difficult to comply with an output-based emission limit. If the
installation of these turbines became impossible due to lack of ability
to comply with the NSPS, these gases might otherwise just be vented to
the atmosphere or flared, without the benefit of any useful energy
recovery as would have been achieved with a combustion turbine. Because
of these issues, we are requesting public comment on the output-based
NOX limit for alternative fuels.
Simple-Cycle and Combined-Cycle Combustion Turbines
Although we believe that proposing different NOX limits
for small and large turbines is appropriate, an alternative approach
considered was to set different NOX limits for simple-cycle
and combined-cycle combustion turbines burning natural gas. Simple-
cycle turbines are not able to recover exhaust heat as combined-cycle
turbines do. As a result, the output-based NOX levels of
simple-cycle turbines will tend to be higher than those for combined-
cycle units. Even though we have taken into account these differences
between simple- and combined-cycle turbines in the proposed
NOX limits, we would like to request comment on this issue.
If data is presented showing that it would be more appropriate to set
different NOX limits for simple-cycle and combined-cycle
gas-fired turbines, rather than based on turbine size, we would
consider a range of 0.2 lb/MW-hr to 0.6 lb/MW-hr.
Supporting data for the proposed NOX limits were
received from contacts with turbine manufacturers, State agencies and
EPA Regional offices, the 2003 Gas Turbine World Handbook, the 2003-
2004 Diesel and Gas Turbine Worldwide Catalog, NOX
performance tests, and State permit data. For more details regarding
the supporting data used in this analysis, please consult the docket.
C. How Did EPA Determine the Proposed SO2 Limit?
Because of the lower levels of sulfur in today's fuels, including
distillate oil and natural gas, lower SO2 emissions can be
achieved. Low sulfur fuel oil (500 ppmw sulfur content or less) has
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recently become widely available, since it is required by EPA
regulations on diesel fuels used for highway and non-road applications.
In addition, ultra low sulfur (15 ppmw or less sulfur content) diesel
fuel will become available over the next few years as more recent EPA
rules for fuels used on highway and non-road applications come into
effect. According to EPA estimates done for the Non-Road Diesel Rule
(69 FR 38958), the cost differential to produce low sulfur (500 ppmw
sulfur content) is only about 2.5 cents per gallon. It is expected that
stationary combustion turbines burning low sulfur diesel fuel will have
lower maintenance expenses associated with reduced formation of acid
compounds inside the turbine. These lower maintenance expenses are
expected to reduce or even eliminate the overall costs associated with
the use of low sulfur fuel oil on stationary combustion turbines. For
these reasons, we have set a SO2 emission limit which
corresponds to a 500 ppmw sulfur fuel content for distillate oil fuel.
Natural gas also has naturally low levels of sulfur.
All owners and operators of new turbines are expected to comply
with low sulfur content in fuel rather than stack testing for
SO2, since this option is significantly easier and less
costly to perform than stack testing. In addition, if the levels are
shown to be below 300 ppmw sulfur, fuel monitoring is not required.
Fuels are often supplied with specifications which include stringent
sulfur standards, requiring levels lower than 500 ppmw, oftentimes at
or below the 300 ppmw range. If the fuel is demonstrated to be lower
than 300 ppmw sulfur, you could use proof from the fuel vendor's tariff
sheet or purchase contract in order to become exempt from monitoring
your total sulfur content or SO2 emissions. We believe that
300 ppmw provides an adequate margin of compliance. If your fuel is
greater than 300 ppmw, you must follow a fuel monitoring schedule as
outlined in the proposed rule.
D. What Other Criteria Pollutants Did EPA Consider?
In order to characterize the current emissions levels from new
stationary combustion turbines, the Reasonably Achievable Control
Technology (RACT), Best Available Control Technology (BACT) and Lowest
Achievable Emissions Rate (LAER) Clearinghouse (RBLC) was queried to
obtain data on permits for newly installed turbines. The EPA's AP-42
Emission Factors Background Document was also consulted for information
on pollutant formation mechanisms. In addition, several turbine
manufacturers were contacted to determine their guaranteed emission
concentrations.
Emissions from combustion turbines are primarily NOX and
carbon monoxide (CO). Particulate matter (PM) is also a primary
pollutant for combustion turbines using liquid fuels. While
NOX formation is strongly dependent on the high temperatures
developed in the combustor, emissions of CO and PM are primarily the
result of incomplete combustion. Ash and metallic additives in the fuel
may also contribute to PM in the exhaust. Available emissions data in
EPA's AP-42 indicate that the turbine's operating load has a
considerable effect on the resulting emission levels. Combustion
turbines are typically operated at high loads (greater than or equal to
80 percent of rated capacity) to achieve maximum thermal efficiency and
peak combustor zone flame temperatures. Information on each pollutant
is listed below, including formation, control, and emission
concentrations.
Carbon Monoxide
Carbon monoxide is a product of incomplete combustion. Carbon
monoxide results when there is insufficient residence time at high
temperature, or incomplete mixing to complete the final step in fuel
carbon oxidation. The oxidation of CO to CO2 at combustion
turbine temperatures is a slow reaction compared to most hydrocarbon
oxidation reactions. In combustion turbines, failure to achieve CO
burnout may result from quenching by dilution air. With liquid fuels,
this can be aggravated by carryover of larger droplets from the
atomizer at the fuel injector. Carbon monoxide emissions are also
dependent on the loading of the combustion turbine. For example, a
combustion turbine operating under full load would experience greater
fuel efficiencies, which will reduce the formation of CO.
Turbine manufacturers have significantly reduced CO emissions from
combustion turbines by developing lean premix technology. Most of the
newer designs for turbines incorporate lean premix technology. Lean
premix combustion design not only produces lower NOX than
diffusion flame technology, but also lowers CO and volatile organic
compounds (VOC), due to increased combustion efficiency. In the most
recent version of AP-42 emission factors, (April 2000), CO emission
factors for lean premix turbines are 9.9 e-2 lb/MMBtu, while for
diffusion flame turbines, the CO emission factor is 3.2 e-1 lb/MMBtu.
Virtually all new combustion turbines sold are lean premix combustor
technology turbines. Siemens Westinghouse, Solar Turbines, and General
Electric (GE) Heavy Duty Turbine manufacturers typically guarantee CO
emissions from 9 to 50 ppm for natural gas, and 20 to 50 ppm for diesel
fuel. On a case-by-case basis, some manufacturers will guarantee lower
emissions for CO.
Stationary combustion turbines do not contribute significantly to
ambient CO levels. Almost 80 percent of CO emissions nationwide result
from on-road vehicles and non-road vehicles and engines. High levels of
CO generally occur in areas that have heavy traffic congestion.
Currently, there are only eight areas in the U.S. that are classified
as non-attainment for CO. As a result, control measures for CO
emissions from stationary combustion turbines historically have not
been instituted nationwide. In California, for example, only one air
district has a CO emission limit for combustion turbines. Because of
advances in turbine technology and increases in thermal and combustion
efficiencies, CO emissions from combustion turbines have been mostly
regulated in local areas of non-attainment for CO.
Any new major stationary source or major modification located in an
area attaining the National Ambient Air Quality Standard (NAAQS) is
subject to PSD requirements and must conduct an analysis to ensure the
application of BACT. Similarly, if the source is in a non-attainment
area, it is subject to non-attainment NSR and must conduct an analysis
to ensure the application of LAER. The RBLC provides State agencies
with the best technologies and emission rates determined by other
States on a nationwide basis. Several BACT and LAER determinations in
the RBLC included the use of an oxidation catalyst to control CO
emissions from stationary combustion turbines. Out of the 42 permits
for CO for combustion turbines reported since January 2003, 15 required
the use of oxidation catalysts for CO reduction. Other requirements
included good combustion practices and good combustion design. Emission
limitations ranged from 2 ppm to 14 ppm for CO with the use of
oxidation catalysts, and 4 ppm to 132 ppm CO for good combustion
practices and design.
Based on the available information, we propose that no CO emission
limitations be developed for the combustion turbine NSPS. With the
advancement of turbine technology and more complete combustion through
increased efficiencies, and the prevalence of lean premix combustion
technology in new turbines, it is not necessary to further reduce CO in
the
[[Page 8321]]
proposed rule. Because of these advances, the addition of an oxidation
catalyst would be cost prohibitive, on a dollar per ton basis, relative
to the limited additional emissions reductions to be realized. However,
individual States may continue to evaluate CO limits on a case-by-case
basis, as has been done historically and as has been required in the
NSR Program.
Volatile Organic Compounds
Volatile organic compounds are also products of incomplete
combustion. These compounds are discharged into the atmosphere when
fuel remains unburned or is burned only partially during the combustion
process. The pollutants commonly classified as VOC can encompass a wide
spectrum of organic compounds, some of which are hazardous air
pollutants. With natural gas, some organics are carried over as
unreacted, trace constituents of the gas, while others may be pyrolysis
products of the heavier hydrocarbon constituents. With liquid fuels,
large droplet carryover to the quench zone accounts for much of the
unreacted and partially pyrolized volatile organic emissions. Similar
to CO emissions, VOC emissions are affected by the gas turbine
operating load conditions. Volatile organic compounds emissions are
higher for gas turbines operating at low loads as compared to similar
gas turbines operating at higher loads.
Owners of combustion turbines have improved combustion practices to
increase combustion efficiency in the turbine, thereby limiting the
unburned fuel. In addition, lean premix technology has significantly
reduced VOC emissions from combustion turbines by increasing the
combustion efficiency. Because of better combustion practices, and the
prevalence of lean premix combustion technology in new turbines, it is
not necessary to regulate VOC in the proposed rule. Therefore, we
propose that no VOC emission limitations be developed for the
combustion turbine NSPS.
Particulate Matter
Particulate matter emissions from turbines result primarily from
carryover of noncombustible trace constituents in the fuel. Particulate
matter emissions are negligible with natural gas firing due to the low
sulfur content of natural gas. Emissions of PM are only marginally
significant with distillate oil firing because of the low ash content.
The sulfur content of distillate fuel is decreasing due to requirements
from other regulations such as the non-road diesel engine rule.
Particulate matter emissions from distillate oil-fired turbines would
decrease even further as the sulfur content of distillate oil
decreases. Furthermore, there are very few new turbines that solely
fire distillate oil. A fraction have the ability to fire distillate oil
(dual-fuel units), but generally speaking, most owners and operators
fire natural gas the majority of the time.
A review of the BACT and LAER determinations in the RBLC since
January of 2003 showed that no add-on controls were required to limit
PM for any of the turbines. Permit requirements included the use of
clean fuel or good combustion practices. Emission limitations required
by permits in the RBLC database with permit dates after January of 2003
ranged from 9 pounds per hour (lb/hr) to 27 lb/hr for PM for natural
gas, and 27 to 44 lb/hr for PM for diesel-fired turbines. General
Electric is the only manufacturer who provides PM guarantees on their
heavy duty turbines, and these guarantees ranged from 3 lb/hr to 15 lb/
hr for natural gas, and 6 lb/hr to 34 lb/hr for diesel fuel.
As fuels continue to get cleaner, PM would be greatly reduced. In
addition, the NOX limits set forth in the proposed rule
would also limit PM emissions by reducing nitrate formation. Therefore,
we feel that an emission limitation for PM emissions from stationary
combustion turbines is not necessary.
E. How Did EPA Determine Testing and Monitoring Requirements for the
Proposed Rule?
Monitoring provisions in subpart GG of 40 CFR part 60 only
addressed turbines that used water injection for NOX
control. Over the years, EPA has approved on a case-by-case basis
alternative monitoring methods for turbines that do not use water
injection for NOX control, since this technology has become
increasingly archaic. Some requested the use of a NOX CEMS,
since the turbines had these monitoring systems already in place for
other regulatory requirements, such as the acid rain regulations or
PSD/NSR permits. In the July 8, 2004 amendments to subpart GG of 40 CFR
part 60, Stationary Gas Turbine NSPS (69 FR 41346), we added the option
to utilize a NOX CEMS in place of water to fuel ratio
monitoring. We also included in the July 8, 2004 final rule a provision
allowing sources to use CEMS to monitor their NOX emissions
for turbines that do not use water or steam injection.
In today's action, we are proposing monitoring requirements similar
to those in 40 CFR part 60, subpart GG. For turbines that do not use
water or steam injection, we are proposing annual stack testing to
demonstrate continuous compliance. We considered other monitoring
requirements, including CEMS and parametric monitoring. However, costs
were high compared to costs for annual stack testing and annual stack
testing provides a reliable means of demonstrating compliance.
Therefore, annual stack testing is an appropriate monitoring method,
and would help ensure continuous compliance with the new NOX
limits.
We also considered the use of portable analyzers as monitoring
requirements. Recent testing by EPA has shown portable analyzers to be
a reliable method of monitoring emissions, and they are believed to be
as good as the traditional EPA method tests. Costs are comparable to
EPA method tests. Portable analyzers are, therefore, a viable option to
traditional method stack tests and the proposed rule allows the use of
ASTM D6522-00 to measure the NOX concentration during
performance testing.
Many of the large turbines in the utility sector are already
equipped with NOX CEMS for compliance with other
regulations, such as 40 CFR part 75. It is appropriate to allow the use
of NOX CEMS to demonstrate compliance with the proposed
rule, particularly when they are already installed on-site for other
regulatory purposes. Continuous emission monitoring systems are,
therefore, the natural choice for these large turbines, and we are
allowing the use of data from these certified CEMS for demonstrating
compliance instead of an annual stack test.
Also, we included additional options for owners and operators to
establish parameters which would be appropriate to monitor in order to
correlate NOX emissions with these data. Historically, some
turbines have used parametric monitoring for compliance with 40 CFR
part 75 requirements. For example, the owner/operator of a lean premix
turbine might establish during the initial performance test that when
the turbine is running in the lean premix mode, it is in compliance.
Certain parameters, such as load or combustion temperature, might let
the owner or operator know when the turbine is in compliance. Another
option is for owners or operators to petition the Administrator for
approval of another monitoring strategy.
F. Why Are Heat Recovery Steam Generators Included in 40 CFR Part 60,
Subpart KKKK?
For sources that are combined cycle turbine systems using
supplemental heat, turbine NOX emissions would be
[[Page 8322]]
measured after the duct burner, since emissions and output associated
with duct burners are included in the NOX emission limit.
Any combined cycle units that are subject to the NOX CEMS
requirements for 40 CFR part 75 would most likely have installed the
CEMS after the duct burner, on the HRSG stack. Another reason to
require measurement of NOX emissions after the duct burner
is that add-on NOX control systems, such as SCR, are
generally located after the duct burner. Turbine NOX
performance testing should be conducted after the NOX
control device and would, therefore, include any emissions from the
duct burner.
In addition, all of the data that we have gathered where emissions
were tested with and without duct burner firing show that duct burners
have little to no effect on NOX emissions. Minimal additions
and reductions were noted in several recent source tests, as well as an
EPA sponsored test conducted by the EPA's Emissions Measurement Center.
Thus, it is appropriate to include heat recovery sources such as duct
burners in the proposed rule.
G. What Emission Limits Must I Meet if I Fire More Than One Type of
Fuel?
New combustion turbines that fire both natural gas and distillate
oil (or some other combination of fuels) are required to meet the
corresponding emission limit for the fuel being fired in the turbine at
that time.
H. Why Can I No Longer Claim a Fuel-Bound Nitrogen Allowance?
We are not including a fuel-bound nitrogen allowance in the
proposed rule. In subpart GG of 40 CFR part 60, this provision allowed
sources to claim a credit for nitrogen content in their fuel, up to a
certain limit, attributing a part of their NOX emissions to
the fuel. We concluded that this provision is outdated since the
nitrogen content of fuel is now lower than it has been in the past and
is no longer an issue. The vast majority of new turbines are fired by
natural gas. Many of these turbines are permitted to fire only pipeline
quality natural gas, which is virtually nitrogen free. We do not
anticipate any new turbines needing to utilize the fuel-bound nitrogen
allowance, and are, therefore, not proposing it.
I. Why Isn't My IGCC Turbine Covered in 40 CFR Part 60, Subpart KKKK?
We consider gasification as an emissions control technology for
solid fuels. Therefore, we consider it appropriate to cover combustion
turbines fueled by gasified coal under the Utility NSPS. Combustion
turbines fueled by gasified coal and not meeting the heat input
requirements of the Utility NSPS would be covered by the proposed rule
under the ``other fuel'' category.
V. Environmental and Economic Impacts
In setting the standards, the CAA requires us to consider
alternative emission control approaches, taking into account the
estimated costs and benefits, as well as the energy, solid waste and
other effects. The EPA requests comment on whether it has 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.
The EPA will consider the available information in developing the final
rule.
A. What Are the Air Impacts?
We estimate that approximately 355 new stationary combustion
turbines will be installed in the United States over the next 5 years
and affected by the rule, as proposed. No more than ten of these units
may need to install add-on controls to meet the NOX limits
required under the rule, as proposed. However, these ten new turbines
will already be required to install add-on controls to meet
NOX reduction requirements under PSD/NSR. Thus, we concluded
that the NOX and CO reductions resulting from the rule, as
proposed, will essentially be zero. The expected SO2
reductions as a result of the rule, as proposed, would be approximately
830 tons per year (tpy) in the 5th year after promulgation of the
standards.
Although we expect the proposed rule to result in a slight increase
in electrical supply generated by unaffected sources (e.g. existing
stationary combustion turbines), we do not believe that this will
result in higher NOX and SO2 emissions from these
sources. Other emission control programs such as the Acid Rain Program
and PSD/NSR already promote or require emission controls that would
effectively prevent emissions from increasing. All the emissions
reductions estimates and assumptions have been documented in the docket
to the proposed rule.
B. What Are the Energy Impacts?
We do not expect any significant energy impacts resulting from the
rule, as proposed. The only energy requirement is a potential small
increase in fuel consumption, resulting from back pressure caused by
operating a add-on emission control device, such as an SCR. However,
most entities would be able to comply with the proposed rule without
the use of any add-on control devices.
C. What Are the Economic Impacts?
The EPA prepared an economic impact analysis to evaluate the
impacts the proposed rule would have on combustion turbines producers,
consumers of goods and services produced by combustion turbines, and
society. The analysis showed minimal changes in prices and output for
products made by the industries affected by the proposed rule. The
price increase for affected output is less than 0.003 percent, and the
reduction in output is less than 0.003 percent for each affected
industry. Estimates of impacts on fuel markets show price increases of
less than 0.01 percent for petroleum products and natural gas, and
price increases of 0.04 and 0.06 percent for base-load and peak-load
electricity, respectively. The price of coal is expected to decline by
about 0.002 percent, and that is due to a small reduction in demand for
this fuel type. Reductions in output are expected to be less than 0.02
percent for each energy type, including base-load and peak-load
electricity.
The social costs of the rule, as proposed, are estimated at $0.4
million (2002 dollars). Social costs include the compliance costs, but
also include those costs that reflect changes in the national economy
due to changes in consumer and producer behavior in response to the
compliance costs associated with a regulation. For the proposed rule,
changes in energy use among both consumers and producers to reduce the
impact of the regulatory requirements of the rule lead to the estimated
social costs being less than the total annualized compliance cost
estimate of $3.4 million (2002 dollars). The primary reason for the
lower social cost estimate is the increase in electricity supply
generated by unaffected sources (e.g. existing stationary combustion
turbines), which offsets mostly the impact of increased electricity
prices to consumers. The social cost estimates discussed above do not
account for any benefits from emission reductions associated with the
proposed rule.
For more information on these impacts, please refer to the economic
impact analysis in the public docket.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), we must
[[Page 8323]]
determine whether a regulatory action is ``significant'' and,
therefore, subject to review by OMB and the requirements of the
Executive Order. The Executive Order defines ``significant regulatory
action'' as one that is likely to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, OMB has notified
EPA that it considers this a ``significant regulatory action'' within
the meaning of the Executive Order. The EPA submitted this action to
OMB for review. Changes made in response to OMB suggestions or
recommendations would be documented in the public record.
B. Paperwork Reduction Act
The information collection requirements in the proposed rule have
been submitted for approval to 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 ICR No. 2177.01.
The proposed rule contains monitoring, reporting, and recordkeeping
requirements. The information would be used by EPA to identify any new,
modified, or reconstructed stationary combustion turbines subject to
the NSPS and to ensure that any new stationary combustion turbines
comply with the emission limits and other requirements. Records and
reports would be necessary to enable EPA or States to identify new
stationary combustion turbines 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 rule 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 confidentiality is
made will be safeguarded according to EPA policies in 40 CFR part 2,
subpart B, Confidentiality of Business Information.
The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after [date the final rule
is published in the Federal Register]) is estimated to be 20,542 labor
hours per year at an average total annual cost of $1,797,264. This
estimate includes performance testing, continuous monitoring,
semiannual excess emission reports, notifications, and recordkeeping.
There are no capital/start-up costs or operation and maintenance costs
associated with the monitoring requirements over the 3-year period of
the ICR.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9 and 48 CFR chapter
15.
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, including the use of automated collection
techniques, EPA has established a public docket for the ICR under
Docket ID No. OAR-2004-0490. See information under the ADDRESSES
section of this preamble to find instructions for sending comments to
this docket and for viewing comments submitted to the docket. Also, you
can send comments to the Office of Information and Regulatory Affairs,
Office of Management and Budget, 725 17th Street, NW., Washington, DC
20503, Attention: Desk Office for EPA. Please include the EPA Docket ID
No. and OMB control number in any correspondence.
Since OMB is required to make a decision concerning the ICR between
30 and 60 days after February 18, 2005, a comment to OMB is best
assured of having its full effect if OMB receives it by March 21, 2005.
In the final rule, EPA will respond to any OMB or public comments on
the information collection requirements contained in the proposed rule.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedures 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 today's rule on small
entities, small entity is defined as: (1) A small business whose parent
company has fewer than 100 or 1,000 employees, depending on size
definition for the affected North American Industry Classification
System (NAICS) code, or fewer than 4 billion kilowatt-hours (kW-hr) per
year of electricity usage; (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. It
should be noted that small entities in 1 NAICS code would be affected
by the proposed rule, and the small business definition applied to each
industry by NAICS code is that listed in the Small Business
Administration (SBA) size standards (13 CFR part 121).
After considering the economic impacts of today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. We have
determined, based on the existing combustion turbines inventory and
presuming the percentage of small entities in that inventory is
representative of the percentage of small entities owning new turbines
in the 5th year after promulgation, that one small entity out of 29 in
the industries impacted by the proposed rule will
[[Page 8324]]
incur compliance costs (in this case, only monitoring, recordkeeping,
and reporting costs since control costs are zero) associated with the
proposed rule. This small entity owns one affected turbine in the
projected set of new combustion turbines. This affected small entity is
estimated to have annual compliance costs of 0.3 percent of its
revenues. The proposed rule is likely to also increase profits for the
small firms and increase revenues for the many small communities (in
total, 28 small entities) using combustion turbines that are not
affected by the proposed rule as a result of the very slight increase
in market prices. For more information on the results of the analysis
of small entity impacts, please refer to the economic impact analysis
in the docket.
Although the proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of the rule on small entities. In the
proposed rule, the Agency is applying the minimum level of control and
the minimum level of monitoring, recordkeeping, and reporting to
affected sources allowed by the CAA. In addition, as mentioned earlier
in this preamble, new turbines with capacities under 1 MW are not
subject to the proposed rule. This provision should reduce the size of
small entity impacts. 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
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures by State, local, and tribal governments, in
the aggregate, or by the private sector, of $100 million or more in any
1 year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost effective, or least burdensome alternative
that achieves the objective of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
The EPA has determined that the proposed rule contains no Federal
mandates 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 1 year. Thus, the proposed rule is not subject to the
requirements of sections 202 and 205 of the UMRA. In addition, EPA has
determined that the proposed rule contains no regulatory requirements
that might significantly or uniquely affect small governments because
they contain no requirements that apply to such governments or impose
obligations upon them. Therefore, the proposed rule is not subject to
the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999) requires us 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'' are defined in the Executive Order 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.''
The proposed rule does not have federalism implications. It 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 Executive Order 13132. Thus, Executive Order 13132 does
not apply to the proposed rule.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 6, 2000) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' ``Policies that have tribal
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on one or more Indian tribes, on
the relationship between the Federal government and the Indian tribes,
or on the distribution of power and responsibilities between the
Federal government and Indian tribes.''
The proposed rule does not have tribal implications. It will not
have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in Executive Order 13175. We
do not know of any stationary combustion turbines owned or operated by
Indian tribal governments. However, if there are any, the effect of the
proposed rule on communities of tribal governments would not be unique
or disproportionate to the effect on other communities. Thus, Executive
Order 13175 does not apply to the proposed rule.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, we must evaluate the environmental health or safety
effects of the planned rule on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably
feasible alternatives.
The proposed rule is not subject to Executive Order 13045 because
it is not an economically significant action as defined under Executive
Order 12866.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies shall prepare and submit to the
[[Page 8325]]
Administrator of the Office of Information and Regulatory Affairs,
Office of Management and Budget, a Statement of Energy Effects for
certain actions identified as ``significant energy actions.'' Section
4(b) of Executive Order 13211 defines ``significant energy actions'' as
``any action by an agency (normally published in the Federal Register)
that promulgates or is expected to lead to the promulgation of a final
rule or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1) (i) That
is a significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a ``significant energy action.'' Although the
proposed rule is considered to be a significant regulatory action under
Executive Order 12866, it is not a ``significant energy action''
because it is not likely to have a significant adverse effect on the
supply, distribution or use of energy.
An increase in petroleum product output, which includes increases
in fuel production, is estimated at less than 0.01 percent, or about
600 barrels per day based on 2004 U.S. fuel production nationwide. A
reduction in coal production is estimated at 0.00003 percent, or about
3,000 short tons per year based on 2004 U.S. coal production
nationwide. The reduction in electricity output is estimated at 0.02
percent, or about 5 billion kW-hr per year based on 2000 U.S.
electricity production nationwide.
Production of natural gas is expected to increase by 4 million
cubic feet (ft3) per day. The maximum of all energy price
increases, which include increases in natural gas prices as well as
those for petroleum products, coal, and electricity, is estimated to be
the 0.04 percent increase in peak-load electricity rates nationwide.
Energy distribution costs may increase by no more than the same amount
as electricity rates. We expect that there will be no discernable
impact on the import of foreign energy supplies, and no other adverse
outcomes are expected to occur with regards to energy supplies.
Also, the increase in cost of energy production should be minimal
given the very small increase in fuel consumption resulting from back
pressure related to operation of add-on emission control devices, such
as SCR. All of the estimates presented above account for some
passthrough of costs to consumers as well as the direct cost impact to
producers. Therefore, we conclude that the rule, as proposed, will not
have a significant adverse effect on the supply, distribution, or use
of energy. For more information on these estimated energy effects,
please refer to the economic impact analysis for the proposed rule.
This analysis is available in the public docket.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs EPA
to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to OMB, with explanations when an
agency does not use available and applicable voluntary consensus
standards.
The proposed rule involves technical standards. The EPA cites the
following methods in the proposed rule: EPA Methods 1, 2, 3A, 7E, 19,
and 20 of 40 CFR part 60, appendix A; and Performance Specifications
(PS) 2 of 40 CFR part 60, appendix B.
In addition, the proposed rule cites the following standards that
are also incorporated by reference (IBR) in 40 CFR part 60, section 17:
ASTM D129-00, ASTM D1072-90 (Reapproved 1999), ASTM D1266-98, ASTM
D1552-01, ASTM D2622-98, ASTM D3246-81 or -92 or -96, ASTM D4057-95
(Reapproved 2000), ASTM D4084-82 or -94, ASTM D4177-95 (Reapproved
2000), ASTM D4294-02, ASTM D4468-85 (Reapproved 2000), ASTM D5287-97
(Reapproved 2002), ASTM D5453-00, ASTM D5504-01, ASTM D6228-98, ASTM
D6522-00, ASTM D6667-01, and Gas Processors Association Standard 2377-
86.
Consistent with the NTTAA, EPA conducted searches to identify
voluntary consensus standards in addition to these EPA methods/
performance specifications. No applicable voluntary consensus standards
were identified for EPA Method 19. The search and review results have
been documented and are placed in the docket for the proposed rule.
In addition to the voluntary consensus standards EPA uses in the
proposed rule, the search for emissions measurement procedures
identified 11 other voluntary consensus standards. The EPA determined
that nine of these 11 standards identified for measuring air emissions
or surrogates subject to emission standards in the proposed rule were
impractical alternatives to EPA test methods/performance specifications
for the purposes of the proposed rule. Therefore, the EPA does not
intend to adopt these standards. See the docket for the reasons for the
determinations of these methods.
Two of the 11 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the proposed rule because they are under development by a
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2.
Sections 60.4345, 60.4360, 60.4400 and 60.4415 of the proposed rule
discuss the EPA testing methods, performance specifications, and
procedures required. Under 40 CFR 63.7(f) and 63.8(f) of subpart A of
the General Provisions, a source may apply to EPA for permission to use
alternative test methods or alternative monitoring requirements in
place of any of the EPA testing methods, performance specifications, or
procedures.
List of Subjects in 40 CFR Part 60
Administrative practice and procedure, Air pollution control,
Environmental protection, Intergovernmental relations, Nitrogen oxides,
Reporting and recordkeeping requirements, Sulfur oxides.
Dated: February 9, 2005.
Stephen L. Johnson,
Acting Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
60, of the Code of 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.
2. Part 60 is amended by adding subpart KKKK to read as follows:
[[Page 8326]]
Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines for Which Construction Is Commenced After February 18,
2005 or for Which Modification or Reconstruction is Commenced on or
After [Date 6 Months After Date Final Rule Is Published in the
Federal Register]
Introduction
Sec.
60.4300 What is the purpose of this subpart?
Applicability
60.4305 Does this subpart apply to my stationary combustion turbine?
60.4310 What types of operations are exempt from these standards of
performance?
Emission Limits
60.4315 What pollutants are regulated by this subpart?
60.4320 What emission limits must I meet for nitrogen oxides
(NOX)?
60.4325 What emission limits must I meet for NOX if my
turbine burns both natural gas and distillate oil (or some other
combination of fuels)?
60.4330 What emission limits must I meet for sulfur dioxide
(SO2)?
Monitoring
60.4335 How do I demonstrate compliance for NOX if I use
water or steam injection?
60.4340 How do I demonstrate continuous compliance for
NOX if I do not use water or steam injection?
60.4345 What are the requirements for the continuous emission
monitoring system equipment, if I choose to use this option?
60.4350 How do I use data from the continuous emission monitoring
equipment to identify excess emissions?
60.4355 How do I establish and document a proper parameter
monitoring plan?
60.4360 How do I determine the total sulfur content of the turbine's
combustion fuel?
60.4365 How can I be exempted from monitoring the total sulfur
content of the fuel?
60.4370 How often must I determine the sulfur content of the fuel?
Reporting
60.4375 What reports must I submit?
60.4380 How are excess emissions and monitor downtime defined for
NOX?
60.4385 How are excess emissions and monitoring downtime defined for
SO2?
60.4390 What are my reporting requirements if I operate an emergency
combustion turbine or a research and development turbine?
60.4395 When must I submit my reports?
Performance Tests
60.4400 How do I conduct the initial and subsequent performance
tests, regarding NOX?
60.4405 How do I perform the initial performance test if I have
chosen to install a NOX-diluent CEMS?
60.4410 How do I establish a valid parameter range if I have chosen
to continuously monitor parameters?
60.4415 How do I conduct the initial and subsequent performance
tests for sulfur?
Definitions
60.4420 What definitions apply to this subpart?
Tables to Subpart KKKK of Part 60
Table 1 to Subpart KKKK of Part 60--Nitrogen Oxide Emission Limits
for New Stationary Combustion Turbines
Introduction
Sec. 60.4300 What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of emissions for new stationary combustion
turbines that were constructed, modified or reconstructed after
February 18, 2005.
Applicability
Sec. 60.4305 Does this subpart apply to my stationary combustion
turbine?
(a) If you are the owner or operator of a stationary combustion
turbine with a power output at peak load equal to or greater than 1
megawatt (MW), which commences construction, modification, or
reconstruction after February 18, 2005, your turbine is subject to this
subpart. Only power output from the combustion turbine should be
included when determining whether or not this subpart is applicable to
your turbine. Any associated recovered heat or steam turbine output
should not be included when determining your peak power output.
However, this subpart does apply to emissions from any associated heat
recovery steam generators (HRSG) and duct burners.
(b) Stationary combustion turbines regulated under this subpart are
exempt from the requirements of subpart GG of this part. Heat recovery
steam generators and duct burners regulated under this subpart are
exempted from the requirements of subparts Da and Db of this part.
Sec. 60.4310 What types of operations are exempt from these standards
of performance?
(a) Emergency combustion turbines, as defined in Sec. 60.4420(g),
are exempt from the nitrogen oxides (NOX) emission limits in
Sec. 60.4320.
(b) Stationary combustion turbines engaged by manufacturers in
research and development of equipment for both combustion turbine
emission control techniques and combustion turbine efficiency
improvements are exempt from the NOX emission limits in
Sec. 60.4320 on a case-by-case basis as determined by the
Administrator.
Emission Limits
Sec. 60.4315 What pollutants are regulated by this subpart?
The pollutants regulated by this subpart are NOX and
sulfur dioxide (SO2).
Sec. 60.4320 What emission limits must I meet for nitrogen oxides
(NOX)?
You must meet the emission limits for nitrogen oxides specified in
Table 1 to this subpart.
Sec. 60.4325 What emission limits must I meet for NOX if
my turbine burns both natural gas and distillate oil (or some other
combination of fuels)?
You must meet the emission limits specified in Table 1 to this
subpart. If you are burning natural gas, you must meet the
corresponding limit for a natural gas-fired turbine when you are
burning that fuel. Similarly, when you are burning distillate oil and
fuels other than natural gas, you must meet the corresponding limit for
distillate oil and fuels other than natural gas for the duration of the
time that you burn that particular fuel.
Sec. 60.4330 What emission limits must I meet for sulfur dioxide
(SO2)?
You must comply with one or the other of the following conditions:
(a) You must not cause to be discharged into the atmosphere from
the subject stationary combustion turbine any gases which contain
SO2 in excess of 73 nanograms per Joule (ng/J) (0.58 pounds
per megawatt-hour (lb/MW-hr)), or
(b) You must not burn in the subject stationary combustion turbine
any fuel which contains total sulfur in excess of 0.05 percent by
weight (500 parts per million by weight (ppmw)).
Monitoring
Sec. 60.4335 How do I demonstrate compliance for NOX if I use water
or steam injection?
(a) If you are using water or steam injection to control
NOX emissions, you must install, calibrate, maintain and
operate a continuous monitoring system to monitor and record the fuel
consumption and the ratio of water or steam to fuel being fired in the
turbine.
(b) Alternatively, you may use continuous emission monitoring, as
follows:
(1) Install, certify, maintain, and operate a continuous emission
monitoring system (CEMS) consisting of a NOX monitor and a
diluent gas (oxygen (O2) or carbon dioxide (CO2))
[[Page 8327]]
monitor, to determine the hourly NOX emission rate in pounds
per million British thermal units (lb/MMBtu); and
(2) Install, calibrate, maintain, and operate a fuel flow meter (or
flow meters) to continuously measure the heat input to the affected
unit; and
(3) Install, calibrate, maintain, and operate a watt meter (or
meters) to continuously measure the gross electrical output of the unit
in megawatt-hours; and
(4) For cogeneration units, install, calibrate, maintain, and
operate meters for steam flow rate, temperature, and pressure, to
continuously measure the total thermal energy output in British thermal
units per hour (Btu/hr).
Sec. 60.4340 How do I demonstrate continuous compliance for NOX if I
do not use water or steam injection?
(a) If you are not using water or steam injection to control
NOX emissions, you must perform annual performance tests in
accordance with Sec. 60.4400 to demonstrate continuous compliance.
(b) As an alternative, you may install, calibrate, maintain and
operate one of the following continuous monitoring systems:
(1) Continuous emission monitoring as described in Sec. Sec.
60.4335(b) and 60.4345, or
(2) Continuous parameter monitoring as follows:
(i) For a diffusion flame turbine without add-on selective
catalytic reduction (SCR) controls, you must define at least four
parameters indicative of the unit's NOX formation
characteristics, and you must monitor these parameters continuously.
(ii) For any lean premix stationary combustion turbine, you must
continuously monitor the appropriate parameters to determine whether
the unit is operating in the lean premixed (low-NOX)
combustion mode.
(iii) For any turbine that uses SCR to reduce NOX
emissions, you must continuously monitor appropriate parameters to
verify the proper operation of the emission controls.
(iv) For affected units that are also regulated under part 75 of
this chapter, if you elect to monitor the NOX emission rate
using the methodology in appendix E to part 75 of this chapter, or the
low mass emissions methodology in Sec. 75.19, the requirements of this
paragraph (b) may be met by performing the parametric monitoring
described in section 2.3 of appendix E or in Sec. 75.19(c)(1)(iv)(H).
Sec. 60.4345 What are the requirements for the continuous emission
monitoring system equipment, if I choose to use this option?
If the option to use a NOX CEMS is chosen:
(a) Each NOX diluent CEMS must be installed and
certified according to Performance Specification 2 (PS 2) in appendix B
to this part, except the 7-day calibration drift is based on unit
operating days, not calendar days. Procedure 1 in appendix F to this
part is not required. Alternatively, a NOX diluent CEMS that
is installed and certified according to appendix A to part 75 of this
chapter is acceptable for use under this subpart. The relative accuracy
test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis.
(b) As specified in Sec. 60.13(e)(2), during each full unit
operating hour, both the NOX monitor and the diluent monitor
must complete a minimum of one cycle of operation (sampling, analyzing,
and data recording) for each 15-minute quadrant of the hour, to
validate the hour. For partial unit operating hours, at least one valid
data point must be obtained with each monitor for each quadrant of the
hour in which the unit operates. For unit operating hours in which
required quality assurance and maintenance activities are performed on
the CEMS, a minimum of two valid data points (one in each of two
quadrants) are required for each monitor to validate the NOX
emission rate for the hour.
(c) Each fuel flowmeter shall be installed, calibrated, maintained,
and operated according to the manufacturer's instructions.
Alternatively, fuel flowmeters that meet the installation,
certification, and quality assurance requirements of appendix D to part
75 of this chapter are acceptable for use under this subpart.
(d) Each watt meter, steam flow meter, and each pressure or
temperature measurement device shall be installed, calibrated,
maintained, and operated according to manufacturer's instructions.
(e) The owner or operator shall develop and keep on-site a quality
assurance (QA) plan for all of the continuous monitoring equipment
described in paragraphs (a), (c), and (d) of this section. For the CEMS
and fuel flow meters, the owner or operator may satisfy the
requirements of this paragraph by implementing the QA program and plan
described in section 1 of appendix B to part 75 of this chapter.
Sec. 60.4350 How do I use data from the continuous emission
monitoring equipment to identify excess emissions?
For purposes of identifying excess emissions:
(a) All CEMS data must be reduced to hourly averages as specified
in Sec. 60.13(h).
(b) For each unit operating hour in which a valid hourly average,
as described in Sec. 60.4345(b), is obtained for both NOX
and diluent monitors, the data acquisition and handling system must
calculate and record the hourly NOX emission rate in units
of lb/MMBtu, using the appropriate equation from method 19 in appendix
A to this part. For any hour in which the hourly average O2
concentration exceeds 19.0 percent O 2 (or the hourly
average CO2 concentration is less than 1.0 percent
CO2), a diluent cap value of 19.0 percent O2 or
1.0 percent CO2 (as applicable) may be used in the emission
calculations.
(c) Correction of measured NOX concentrations to 15
percent O2 is not allowed.
(d) If you have installed and certified a NOX diluent
CEMS to meet the requirements of part 75 of this chapter, only quality
assured data from the CEMS shall be used to identify excess emissions
under this subpart. Periods where the missing data substitution
procedures in subpart D of part 75 are applied are to be reported as
monitor downtime in the excess emissions and monitoring performance
report required under Sec. 60.7(c).
(e) All required fuel flow rate, steam flow rate, temperature,
pressure, and megawatt data must be reduced to hourly averages.
(f) Calculate the hourly average NOX emission rates, in
units of the emission standards under Sec. 60.4320, using the
following equation:
(1) For simple-cycle operation:
[GRAPHIC] [TIFF OMITTED] TP18FE05.000
Where:
E = hourly NOX emission rate, in lb/MW-hr,
(NOX)h = hourly NOX emission rate, in
lb/MMBtu,
(HI)h = hourly heat input rate to the unit, in MMBtu/hr,
measured using the fuel flowmeter(s), e.g., calculated using Equation
D-15a in appendix D to part 75 of this chapter, and
P = gross energy output of the turbine in MW.
(2) For combined-cycle operation, use Equation 1 of this subpart,
except that the gross energy output is calculated as the sum of the
total electrical energy
[[Page 8328]]
generated by the turbine, the additional electrical energy (if any)
generated by the heat recovery steam generator, and 100 percent of the
total thermal energy output, expressed in equivalent MW, as in the
following equations:
[GRAPHIC] [TIFF OMITTED] TP18FE05.001
Where:
(Pe)t = electrical energy output of the turbine in MW,
(Pe)c = electrical energy output (if any) of the heat
recovery steam generator) in MW, and
[GRAPHIC] [TIFF OMITTED] TP18FE05.002
Where:
Ps = thermal energy of the steam, expressed as equivalent electrical
energy, in MW,
Q = measured steam flow rate in lb/hr,
H = enthalpy of the steam at measured temperature and pressure relative
to ISO standard conditions, in Btu/lb, and
3.413 x 106 = conversion from Btu/hr to MW.
(3) For mechanical drive applications, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP18FE05.003
Where:
E = emissions in lb/MW-hr,
(NOX)m = nitrogen oxides emission rate in lb/hr,
BL = manufacturer's base load rating of turbine, in MW, and
AL = actual load as a percentage of the base load.
(g) Use the calculated hourly average emission rates from paragraph
(f) of this section to assess excess emissions on a 4-hour rolling
average basis, as described in Sec. 60.4380(b)(1).
Sec. 60.4355 How do I establish and document a proper parameter
monitoring plan?
(a) The steam or water to fuel ratio or other parameters that are
continuously monitored as described in Sec. Sec. 60.4335 and 60.4340
must be monitored during the performance test required under Sec.
60.8, to establish acceptable values and ranges. You may supplement the
performance test data with engineering analyses, design specifications,
manufacturer's recommendations and other relevant information to define
the acceptable parametric ranges more precisely. You must develop and
keep on-site a parameter monitoring plan which explains the procedures
used to document proper operation of the NOX emission
controls. The plan must:
(1) Include the indicators to be monitored and show there is a
significant relationship to emissions and proper operation of the
NOX emission controls,
(2) Pick ranges (or designated conditions) of the indicators, or
describe the process by which such range (or designated condition) will
be established,
(3) Explain the process you will use to make certain that you
obtain data that is representative of the emissions or parameters being
monitored (such as detector location, installation specification if
applicable),
(4) Describe quality assurance and control practices that are
adequate to ensure the continuing validity of the data,
(5) Describe the frequency of monitoring and the data collection
procedures which you will use (e.g., you are using a computerized data
acquisition over a number of discrete data points with the average (or
maximum value) being used for purposes of determining whether an
exceedance has occurred),
(6) Submit justification for the proposed elements of the
monitoring. If a proposed performance specification differs from
manufacturer recommendation, you must explain the reasons for the
differences. You must submit the data supporting the justification, but
you may refer to generally available sources of information used to
support the justification. You may rely on engineering assessments and
other data, provided you demonstrate factors which assure compliance or
explain why performance testing is unnecessary to establish indicator
ranges. When establishing indicator ranges, you may choose to simplify
the process by treating the parameters as if they were correlated.
Using this assumption, testing can be divided into two cases:
(i) All indicators are significant only on one end of range (e.g.,
for a thermal incinerator controlling volatile organic compounds (VOC)
it is only important to insure a minimum temperature, not a maximum).
In this case, you may conduct your study so that each parameter is at
the significant limit of its range while you conduct your emissions
testing. If the emissions tests show that the source is in compliance
at the significant limit of each parameter, then as long as each
parameter is within its limit, you are presumed to be in compliance.
(ii) Some or all indicators are significant on both ends of the
range. In this case, you may conduct your study so that each parameter
that is significant at both ends of its range assumes its extreme
values in all possible combinations of the extreme values (either
single or double) of all of the other parameters. For example, if there
were only two parameters, A and B, and A had a range of values while B
had only a minimum value, the combinations would be A high with B
minimum and A low with B minimum. If both A and B had a range, the
combinations would be A high and B high, A low and B low, A high and B
low, A low and B high. For the case of four parameters all having a
range, there are 16 possible combinations.
(b) For affected units that are also subject to part 75 of this
chapter and that use the low mass emissions methodology in Sec. 75.19
or the NOX emission measurement methodology in appendix E to
part 75, you may meet the requirements of this paragraph by developing
and keeping on-site (or at a central location for unmanned facilities)
a QA plan, as described in Sec. 75.19(e)(5) or in section 2.3 of
appendix E to part 75 of this chapter and section 1.3.6 of appendix B
to part 75 of this chapter.
Sec. 60.4360 How do I determine the total sulfur content of the
turbine's combustion fuel?
You must monitor the total sulfur content of the fuel being fired
in the turbine, except as provided in Sec. 60.4365. The sulfur content
of the fuel must be determined using total sulfur methods described in
Sec. 60.4415. Alternatively, if the total sulfur content of the
gaseous fuel during the most recent performance test was less than
0.0250 weight percent (250 ppmw), ASTM D4084-82, 94, D5504-01, or
D6228-98, or Gas Processors Association Standard 2377-86 (all of which
are incorporated by reference--see Sec. 60.17), which measure the
major sulfur compounds, may be used.
Sec. 60.4365 How can I be exempted from monitoring the total sulfur
content of the fuel?
You may elect not to monitor the total sulfur content of the fuel
combusted in the turbine, if the fuel is demonstrated not to exceed 300
ppmw total sulfur. You must use one of the following sources of
information to make the required demonstration:
(a) The fuel quality characteristics in a current, valid purchase
contract, tariff sheet or transportation contract for the fuel,
specifying that the maximum total sulfur content of the fuel is 300
ppmw or less; or
(b) Representative fuel sampling data which show that the sulfur
content of the fuel does not exceed 300 ppmw. At
[[Page 8329]]
a minimum, the amount of fuel sampling data specified in section
2.3.1.4 or 2.3.2.4 of appendix D to part 75 of this chapter is
required.
Sec. 60.4370 How often must I determine the sulfur content of the
fuel?
The frequency of determining the sulfur content of the fuel must be
as follows:
(a) Fuel oil. For fuel oil, use one of the total sulfur sampling
options and the associated sampling frequency described in sections
2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4.3 of appendix D to part 75 of this
chapter (i.e., flow proportional sampling, daily sampling, sampling
from the unit's storage tank after each addition of fuel to the tank,
or sampling each delivery prior to combining it with fuel oil already
in the intended storage tank).
(b) Gaseous fuel. If you elect not to demonstrate sulfur content
using options in Sec. 60.4365, and the fuel is supplied without
intermediate bulk storage, the sulfur content value of the gaseous fuel
must be determined and recorded once per unit operating day.
Reporting
Sec. 60.4375 What reports must I submit?
For each affected unit required to continuously monitor parameters
or emissions, or to periodically determine the fuel sulfur content
under this subpart, you must submit reports of excess emissions and
monitor downtime, in accordance with Sec. 60.7(c). Excess emissions
must be reported for all periods of unit operation, including start-up,
shutdown, and malfunction.
Sec. 60.4380 How are excess emissions and monitor downtime defined
for NOX?
For the purpose of reports required under Sec. 60.7(c), periods of
excess emissions and monitor downtime that must be reported are defined
as follows:
(a) For turbines using water or steam to fuel ratio monitoring:
(1) An excess emission is any unit operating hour for which the 4-
hour rolling average steam or water to fuel ratio, as measured by the
continuous monitoring system, falls below the acceptable steam or water
to fuel ratio needed to demonstrate compliance with Sec. 60.4320, as
established during the performance test required in Sec. 60.8. Any
unit operating hour in which no water or steam is injected into the
turbine will also be considered an excess emission.
(2) A period of monitor downtime is any unit operating hour in
which water or steam is injected into the turbine, but the essential
parametric data needed to determine the steam or water to fuel ratio
are unavailable or invalid.
(3) Each report must include the average steam or water to fuel
ratio, average fuel consumption, and the combustion turbine load during
each excess emission.
(b) For turbines using continuous emission monitoring, as described
in Sec. Sec. 60.4335(b) and 60.4345:
(1) An hour of excess emissions is any unit operating hour in which
the 4-hour rolling average NOX emission rate exceeds the
applicable emission limit in Sec. 60.4320. For the purposes of this
subpart, a ``4-hour rolling average NOX emission rate'' is
the arithmetic average of the average NOX emission rate in
ng/J (lb/MW-hr) measured by the continuous emission monitoring
equipment for a given hour and the three unit operating hour average
NOX emission rates immediately preceding that unit operating
hour. Calculate the rolling average if a valid NOX emission
rate is obtained for at least 1 of the 4 hours.
(2) A period of monitor downtime is any unit operating hour in
which the data for any of the following parameters are either missing
or invalid: NOX concentration, CO2 or
O2
concentration, fuel flow rate, steam flow rate, steam temperature,
steam pressure, or megawatts.(c) For turbines required to monitor
combustion parameters or parameters that document proper operation of
the NOX emission controls:
(1) An excess emission is a 4-hour rolling unit operating hour
average in which any monitored parameter does not achieve the target
value or is outside the acceptable range defined in the parameter
monitoring plan for the unit.
(2) A period of monitor downtime is a unit operating hour in which
any of the required parametric data are either not recorded or are
invalid.
Sec. 60.4385 How are excess emissions and monitoring downtime defined
for SO2?
If you choose the option to monitor the sulfur content of the fuel,
excess emissions and monitoring downtime are defined as follows:
(a) For samples of gaseous fuel and for oil samples obtained using
daily sampling, flow proportional sampling, or sampling from the unit's
storage tank, an excess emission occurs each unit operating hour
included in the period beginning on the date and hour of any sample for
which the sulfur content of the fuel being fired in the combustion
turbine exceeds 0.05 weight percent and ending on the date and hour
that a subsequent sample is taken that demonstrates compliance with the
sulfur limit.
(b) If the option to sample each delivery of fuel oil has been
selected, you must immediately switch to one of the other oil sampling
options (i.e., daily sampling, flow proportional sampling, or sampling
from the unit's storage tank) if the sulfur content of a delivery
exceeds 0.05 weight percent. You must continue to use one of the other
sampling options until all of the oil from the delivery has been
combusted, and you must evaluate excess emissions according to
paragraph (a) of this section. When all of the fuel from the delivery
has been burned, you may resume using the as-delivered sampling option.
(c) A period of monitor downtime begins when a required sample is
not taken by its due date. A period of monitor downtime also begins on
the date and hour of a required sample, if invalid results are
obtained. The period of monitor downtime ends on the date and hour of
the next valid sample.
Sec. 60.4390 What are my reporting requirements if I operate an
emergency combustion turbine or a research and development turbine?
(a) If you operate an emergency combustion turbine, you are exempt
from the NOX limit and must submit an initial report to the
Administrator stating your case.
(b) Combustion turbines engaged by manufacturers in research and
development of equipment for both combustion turbine emission control
techniques and combustion turbine efficiency improvements may be
exempted from the NOX limit on a case-by-case basis as
determined by the Administrator. You must petition for the exemption.
Sec. 60.4395 When must I submit my reports?
All reports required under Sec. 60.7(c) must be postmarked by the
30th day following the end of each calendar quarter.
Performance Tests
Sec. 60.4400 How do I conduct the initial and subsequent performance
tests, regarding NOX?
(a) You must conduct an initial performance test, as required in
Sec. 60.8.
(1) There are two general methodologies that you may use to conduct
the performance tests. For each test run:
(i) Measure the NOX concentration (in parts per million
(ppm)), using Method 7E or Method 20 in appendix A to this part or ASTM
D6522-00. Also, concurrently measure the stack gas flow rate, using
Methods 1 and 2 in appendix A to this part, and measure and record
[[Page 8330]]
the electrical and thermal output from the unit. Then, use the
following equation to calculate the NOX emission rate:
[GRAPHIC] [TIFF OMITTED] TP18FE05.004
Where:
E = NOX emission rate, in lb/MW-hr
1.194 x 10-7 = conversion constant, in lb/dscf-ppm
(NOX)c = average NOX concentration for
the run,
in ppmQstd = stack gas volumetric flow rate, in dscf/hr
P = gross energy output of the turbine, in MW (for simple-cycle
operation), or, for combined-cycle operation, the sum of all electrical
and thermal output from the unit, in MW, calculated according to Sec.
60.4350(f)(2); or
(ii) Measure the NOX and diluent gas concentrations,
using either Methods 7E and 3A, or Method 20 in appendix A to this
part, or ASTM Method D6522-00. Concurrently measure the heat input to
the unit, using a fuel flowmeter (or flowmeters), and measure the
electrical and thermal output of the unit. Use Method 19 in appendix A
to this part to calculate the NOX emission rate in lb/MMBtu.
Then, use Equations 1 and, if necessary, 2 and 3 in Sec. 60.4350(f) to
calculate the NOX emission rate in lb/MW-hr.
(2) Sampling traverse points for NOX and (if applicable)
diluent gas are to be selected following Method 20 or Method 1 (non-
particulate procedures), and sampled for equal time intervals. The
sampling must be performed with a traversing single-hole probe, or, if
feasible, with a stationary multi-hole probe that samples each of the
points sequentially. Alternatively, a multi-hole probe designed and
documented to sample equal volumes from each hole may be used to sample
simultaneously at the required points.
(3) Notwithstanding the requirements in paragraph (a)(2) of this
section, you may test at fewer points than are specified in Method 1 or
Method 20 if the following conditions are met:
(i) You may perform a stratification test for NOX and
diluent pursuant to
(A) [Reserved], or
(B) The procedures specified in section 6.5.6.1(a) through (e) of
appendix A to part 75 of this chapter.
(ii) Once the stratification sampling is completed, you may use the
following alternative sample point selection criteria for the
performance test:
(A) If each of the individual traverse point NOX (and,
if applicable, diluent) concentrations, is within +/-10 percent of the
mean concentration for all traverse points, then you may use three
points (located either 16.7, 50.0 and 83.3 percent of the way across
the stack or duct, or, for circular stacks or ducts greater than 2.4
meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the
wall). The three points must be located along the measurement line that
exhibited the highest average NOX concentration during the
stratification test; or
(B) If each of the individual traverse point NOX (and,
if applicable, diluent) concentrations, is within +/-5 percent of the
mean concentration for all traverse points, then you may sample at a
single point, located at least 1 meter from the stack wall or at the
stack centroid.
(b) The performance test must be done at four load levels, i.e.,
either within +/-5 percent of 30, 50, 75, and 90-to-100 percent of peak
load or at four evenly-spaced load points in the normal operating range
of the combustion turbine, including the minimum point in the operating
range and 90 to 100 percent of peak load. You may perform testing at
the highest achievable load point, if 90 to 100 percent of peak load
cannot be achieved in practice. Three test runs are required at each
load level. The minimum time per run is 20 minutes.
(1) If the stationary combustion turbine combusts both oil and gas
as primary or backup fuels, separate performance testing is required
for each fuel.
(2) For a combined cycle turbine system with supplemental heat
(duct burner), you must measure the total NOX emissions
after the duct burner rather than directly after the turbine.
(3) If water or steam injection is used to control NOX
with no additional post-combustion NOX control and you
choose to monitor the steam or water to fuel ratio in accordance with
Sec. 60.4335, then that monitoring system must be operated
concurrently with each EPA Method 20, ASTM D6522-00 (incorporated by
reference, see Sec. 60.17), or EPA Method 7E run and must be used to
determine the fuel consumption and the steam or water to fuel ratio
necessary to comply with the applicable Sec. 60.4320 NOX
emission limit.
(4) Compliance with the applicable emission limit in Sec. 60.4320
must be demonstrated at each tested load level. Compliance is achieved
if the three-run arithmetic average NOX emission rate at
each tested level meets the applicable emission limit in Sec. 60.4320.
(5) If you elect to install a CEMS, the performance evaluation of
the CEMS may either be conducted separately or (as described in Sec.
60.4405) as part of the initial performance test of the affected unit.
Sec. 60.4405 How do I perform the initial performance test if I have
chosen to install a NOX-diluent CEMS?
If you elect to install and certify a NOX-diluent CEMS
under Sec. 60.4345, then the initial performance test required under
Sec. 60.8 may be performed in the following alternative manner:
(a) Perform a minimum of nine relative accuracy test audit (RATA)
reference method runs, with a minimum time per run of 21 minutes, at a
single load level, between 90 and 100 percent of peak (or the highest
achievable) load.
(b) For each RATA run, concurrently measure the heat input to the
unit using a fuel flow meter (or flow meters) and measure the
electrical and thermal output from the unit.
(c) Use the test data both to demonstrate compliance with the
applicable NOX emission limit under Sec. 60.4320 and to
provide the required reference method data for the RATA of the CEMS
described under Sec. 60.4335.
(d) The requirement to test at three additional load levels is
waived.
(e) Compliance with the applicable emission limit in Sec. 60.4320
is achieved if the arithmetic average of all of the NOX
emission rates for the RATA runs, expressed in units of lb/MW-hr, does
not exceed the emission limit.
Sec. 60.4410 How do I establish a valid parameter range if I have
chosen to continuously monitor parameters?
If you have chosen to monitor combustion parameters or parameters
indicative of proper operation of NOX emission controls in
accordance with Sec. 60.4340, the appropriate parameters must be
continuously monitored and recorded during each run of the initial
performance test, to establish acceptable operating ranges, for
purposes of the
[[Page 8331]]
parameter monitoring plan for the affected unit, as specified in Sec.
60.4355.
Sec. 60.4415 How do I conduct the initial and subsequent performance
tests for sulfur?
(a) If you choose to periodically determine the sulfur content of
the fuel combusted in the turbine, a representative fuel sample would
be collected following ASTM D5287-97 (2002) for natural gas or ASTM
D4177-95 (2000) for oil. Alternatively, for oil, you may follow the
procedures for manual pipeline sampling in section 14 of ASTM D4057-95
(2000). At least one fuel sample must be collected during each load
condition. Analyze the samples for the total sulfur content of the fuel
using:
(1) For liquid fuels, ASTM D129-00, or alternatively D2622-98,
D4294-02, D1266-98, D5453-00 or D1552-01; or
(2) For gaseous fuels, ASTM D 1072-90 (Reapproved 1999), or
alternatively D3246-96; D4468-85 (Reapproved 2000); or D6667-01.
(b) The fuel analyses required under paragraph (a) of this section
may be performed either by you, a service contractor retained by you,
the fuel vendor, or any other qualified agency.
Definitions
Sec. 60.4420 What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subpart A (General
Provisions) of this part.
Base load means the load level at which a combustion turbine is
normally operated.
Combined cycle combustion turbine means any stationary combustion
turbine which recovers heat from the combustion turbine exhaust gases
to heat water or generate steam.
Combustion turbine model means a group of combustion turbines
having the same nominal air flow, combustor inlet pressure, combustor
inlet temperature, firing temperature, turbine inlet temperature and
turbine inlet pressure.
Diffusion flame stationary combustion turbine means any stationary
combustion turbine where fuel and air are injected at the combustor and
are mixed only by diffusion prior to ignition. A unit which is capable
of operating in both lean premix and diffusion flame modes is
considered a lean premix stationary combustion turbine when it is in
the lean premix mode, and it is considered a diffusion flame stationary
combustion turbine when it is in the diffusion flame mode.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary combustion
turbine, internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a heat recovery steam generating unit.
Efficiency means the combustion turbine manufacturer's rated heat
rate at peak load in terms of heat input per unit of power output-based
on the lower heating value of the fuel.
Emergency combustion turbine means any stationary combustion
turbine which operates in an emergency situation. Examples include
stationary combustion turbines used to produce power for critical
networks or equipment, including power supplied to portions of a
facility, when electric power from the local utility is interrupted, or
stationary combustion turbines used to pump water in the case of fire
or flood, etc. Emergency stationary combustion turbines do not include
stationary combustion turbines used as peaking units at electric
utilities or stationary combustion turbines at industrial facilities
that typically operate at low capacity factors. Emergency combustion
turbines may be operated for the purpose of maintenance checks and
readiness testing, provided that the tests are required by the
manufacturer, the vendor, or the insurance company associated with the
turbine. Required testing of such units should be minimized, but there
is no time limit on the use of emergency combustion turbines.
Excess emissions means a specified averaging period over which
either the NOX emissions are higher than the applicable
emission limit in Sec. 60.4320; the total sulfur content of the fuel
being combusted in the affected facility exceeds the limit specified in
Sec. 60.4330; or the recorded value of a particular monitored
parameter is outside the acceptable range specified in the parameter
monitoring plan for the affected unit.
Gross useful output means the gross useful work performed by the
combustion turbine. For units using the mechanical energy directly or
generating only electricity, the gross useful work performed is the
gross electrical or mechanical output from the turbine/generator set.
For combined heat and power units, the gross useful work performed is
the gross electrical or mechanical output plus the useful thermal
output (i.e., thermal energy delivered to a process).
Heat recovery steam generating unit means a unit where the hot
exhaust gases from the combustion turbine are routed in order to
extract heat from the gases and generate steam, for use in a steam
turbine or other device that utilizes steam. Heat recovery steam
generating units can be used with or without duct burners.
ISO standard conditions means 288 degrees Kelvin, 60 percent
relative humidity and 101.3 kilopascals pressure.
Lean premix stationary combustion turbine means any stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture before delivery to the combustor. Mixing may occur
before or in the combustion chamber. A unit which is capable of
operating in both lean premix and diffusion flame modes is considered a
lean premix stationary combustion turbine when it is in the lean premix
mode, and it is considered a diffusion flame stationary combustion
turbine when it is in the diffusion flame mode.
Natural gas means a naturally occurring fluid mixture of
hydrocarbons (e.g., methane, ethane, or propane) produced in geological
formations beneath the Earth's surface that maintains a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions. Natural gas contains 20.0 grains or less of total sulfur
per 100 standard cubic feet. Equivalents of this in other units are as
follows: 0.068 weight percent total sulfur, 680 ppmw total sulfur, and
338 ppmv at 20 degrees Celsius total sulfur. Additionally, natural gas
must either be composed of at least 70 percent methane by volume or
have a gross calorific value between 950 and 1100 British thermal units
(Btu) per standard cubic foot. Natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value. Pipeline natural gas contains
0.5 grains or less of total sulfur per 100 standard cubic feet.
Additionally, pipeline natural gas must either be composed of at least
70 percent methane by volume or have a gross calorific value between
950 Btu and 1100 Btu per standard cubic foot.
Peak load means 100 percent of the manufacturer's design capacity
of the combustion turbine at ISO standard conditions.
Regenerative cycle combustion turbine means any stationary
combustion turbine which recovers heat from the combustion turbine
exhaust gases to preheat the inlet combustion air to the combustion
turbine.
[[Page 8332]]
Simple cycle combustion turbine means any stationary combustion
turbine which does not recover heat from the combustion turbine exhaust
gases to preheat the inlet combustion air to the combustion turbine, or
which does not recover heat from the combustion turbine exhaust gases
to heat water or generate steam.
Stationary combustion turbine means any simple cycle combustion
turbine, regenerative cycle combustion turbine or a combined cycle
steam/electric generating system that is not self-propelled. It may,
however, be mounted on a vehicle for portability.
Unit operating day means a 24-hour period between 12:00 midnight
and the following midnight during which any fuel is combusted at any
time in the unit. It is not necessary for fuel to be combusted
continuously for the entire 24-hour period.
Unit operating hour means a clock hour during which any fuel is
combusted in the affected unit. If the unit combusts fuel for the
entire clock hour, it is considered to be a full unit operating hour.
If the unit combusts fuel for only part of the clock hour, it is
considered to be a partial unit operating hour.
Useful thermal output means the thermal energy made available for
use in any industrial or commercial process, or used in any heating or
cooling application, i.e., total thermal energy made available for
processes and applications other than electrical generation. Thermal
output for this subpart means the energy in recovered thermal output
measured against the energy in the thermal output at 15 degrees Celsius
and 101.325 kiloPascals (kPa) of pressure.
Table to Subpart KKKK of Part 60
Table 1 to Subpart KKKK of Part 60.--Nitrogen Oxide Emission Limits for New Stationary Combustion Turbines
----------------------------------------------------------------------------------------------------------------
You must meet the following nitrogen
For the following stationary combustion With a peak load capacity of: oxides limit, given in ng/J of
turbines: useful output:
----------------------------------------------------------------------------------------------------------------
Natural gas-fired turbine............... < 30 MW........................ 132 (1.0 lb/MW-hr)
Natural gas-fired turbine............... >= 30 MW....................... 50 (0.39 lb/MW-hr)
Distillate oil and fuels other than < 30 MW........................ 234 (1.9 lb/MW-hr)
natural gas-fired turbine.
Distillate oil and fuels other than >= 30 MW....................... 146 (1.2 lb/MW-hr)
natural gas-fired turbine.
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[FR Doc. 05-3000 Filed 2-17-05; 8:45 am]
BILLING CODE 6560-50-P