The voluntary consensus standards ASTM D1945-03 and later revision
ASTM D1945-14 ``Standard Test Method for Analysis of Natural Gas by Gas
Chromatography'' are acceptable for natural gas analysis. This
voluntary consensus standard covers the determination of the chemical
composition of natural gases and similar gaseous mixtures. This test
method may be abbreviated for the analysis of lean natural gases
containing negligible amounts of hexanes and higher hydrocarbons, or
for the determination of one or more components, as required.
    The voluntary consensus standard ASTM UOP539-12 ``Refinery Gas
Analysis by GC'' is acceptable for refinery gas analysis. This
voluntary consensus standard is for determining the composition of
refinery gas streams or vaporized liquefied petroleum gas using a
preconfigured, commercially available gas chromatograph.
    The voluntary consensus standard ASTM D6348-03 (Reapproved 2010)
including Annexes A1 through A8, ``Determination of Gaseous Compounds
by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy''
is an acceptable alternative to EPA Method 320. This voluntary
consensus standard is a field test method that employs an extractive
sampling system to direct stationary source effluent to an FTIR
spectrometer for the identification and quantification of gaseous
compounds. This field test method provides near real time analysis of
extracted gas samples from stationary sources.
    The voluntary consensus standard ASTM D6348-12e1 ``Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
(FTIR) Spectroscopy'' is an acceptable alternative to EPA Method 320
with the following two caveats: (1) The test plan preparation and
implementation in the Annexes to ASTM D 6348-03 (Reapproved 2010),
Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03
(Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%)
R must be determined for each target analyte (Equation A5.5). In order
for the test data to be acceptable for a compound, %R must be 70% >= R
<= 130%. If the %R value does not meet this criterion for a target
compound, the test data is not acceptable for that compound and the
test must be repeated

for that analyte (i.e., the sampling and/or analytical procedure should
be adjusted before a retest). The %R value for each compound must be
reported in the test report, and all field measurements must be
corrected with the calculated %R value for that compound by using the
following equation:

Reported Result = (Measured Concentration in the Stack x 100)/% R.

    This voluntary consensus standard is a field test method that
employs an extractive sampling system to direct stationary source
effluent to an FTIR spectrometer for the identification and
quantification of gaseous compounds. This field test method provides
near real time analysis of extracted gas samples from stationary
sources.
    The EPA solicited comments on VCS and invited the public to
identify potentially-applicable VCS; however, we did not receive
comments regarding this aspect of 40 CFR part 60, subparts J and Ja,
and part 63, subparts CC, UUU, and Y. Under 40 CFR 63.7(f) and 63.8(f),
a source may apply to the EPA for permission to use alternative test
methods or alternative monitoring requirements in place of any required
testing methods, performance specifications, or procedures in this
final rule.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the U.S. The EPA defines environmental justice as the
fair treatment and meaningful involvement of all people regardless of
race, color, national origin or income with respect to the development,
implementation and enforcement of environmental laws, regulations and
policies. The EPA has this goal for all communities and persons by
working to ensure that everyone enjoys the same degree of protection
from environmental and health hazards and equal access to the decision-
making process to have a healthy environment in which to live, learn
and work.
    The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations. As discussed in section V.D. of this
preamble, the EPA conducted an analysis of the characteristics of the
population with greater than 1-in-1 million risk living within 50 km of
the 142 refineries affected by this rulemaking and determined that
there are more African-Americans, Other and multiracial groups,
Hispanics, low-income individuals, individuals with less than a high
school diploma compared to national averages. Therefore, these
populations are expected to experience the benefits of the risk
reductions associated with this rule. The results of this evaluation
are contained in two technical reports, ``Risk and Technology Review--
Analysis of Socio-Economic Factors for Populations Living Near
Petroleum Refineries'', available in the docket for this action (See
Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227). Additionally, a
discussion of the final risk analysis is included in Sections IV.A and
V.D of this preamble.
    The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because it
maintains or increases the level of environmental protection for all
affected populations without having any disproportionately high and
adverse human health or environmental effects on any population,
including any minority, low-income or indigenous populations. Further,
the EPA believes that implementation of this rule will provide an ample
margin of safety to protect public health of all demographic groups.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.

40 CFR Part 63

    Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.

    Dated: September 29, 2015.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart J--Standards of Performance for Petroleum Refineries

0
2. Section 60.105 is amended by revising paragraphs (b)(1)(iv) and
(b)(3)(iii) to read as follows:

Sec.  60.105  Monitoring of emissions and operations.

* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv. Sampling data must include, at minimum, 2 weeks of daily
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems, seven grab
samples must be collected unless other additional information would
support reduced sampling. The owner or operator shall use detector
tubes (``length-of-stain tube'' type measurement) following the ``Gas
Processors Association Standard 2377-86 (incorporated by reference--see
Sec.  60.17), using tubes with a maximum span between 10 and 40 ppmv
inclusive when 1<=N<=10, where N = number of pump strokes, to test the
applicant fuel gas stream for H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of

stain tubes with a maximum span between 200 and 400 ppmv inclusive when
1<=N<=5, where N = number of pump strokes. The owner or operator must
begin monitoring according to the requirements in paragraph (a)(1) or
(2) of this section as soon as practicable but in no case later than
180 days after the operation change. During daily stain tube sampling,
a daily sample exceeding 162 ppmv is an exceedance of the 3-hour
H2S concentration limit.
* * * * *

Subpart Ja--Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After
May 14, 2007

0
3. Section 60.100a is amended by revising the first sentence of
paragraph (b) to read as follows:

Sec.  60.100a  Applicability, designation of affected facility, and
reconstruction.

* * * * *
    (b) Except for flares and delayed coking units, the provisions of
this subpart apply only to affected facilities under paragraph (a) of
this section which either commence construction, modification or
reconstruction after May 14, 2007, or elect to comply with the
provisions of this subpart in lieu of complying with the provisions in
subpart J of this part. * * *
* * * * *

0
4. Section 60.101a is amended by:
0
a. Revising the definition of ``Corrective action''; and
0
b. Adding, in alphabetical order, a definition for ``Sour water''.
    The revision and addition read as follows:

Sec.  60.101a  Definitions.

* * * * *
    Corrective action means the design, operation and maintenance
changes that one takes consistent with good engineering practice to
reduce or eliminate the likelihood of the recurrence of the primary
cause and any other contributing cause(s) of an event identified by a
root cause analysis as having resulted in a discharge of gases from an
affected facility in excess of specified thresholds.
* * * * *
    Sour water means water that contains sulfur compounds (usually
H2S) at concentrations of 10 parts per million by weight or
more.
* * * * *

0
5. Section 60.102a is amended by revising paragraphs (b)(1)(i) and
(iii), (f), and (g)(1) introductory text to read as follows:

Sec.  60.102a  Emissions limitations.

* * * * *
    (b) * * *
    (1) * * *
    (i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke
burn-off or, if a PM continuous emission monitoring system (CEMS) is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each modified or reconstructed FCCU.
* * * * *
    (iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each affected FCU.
* * * * *
    (f) Except as provided in paragraph (f)(3) of this section, each
owner or operator of an affected sulfur recovery plant shall comply
with the applicable emission limits in paragraph (f)(1) or (2) of this
section.
    (1) For a sulfur recovery plant with a design production capacity
greater than 20 long tons per day (LTD), the owner or operator shall
comply with the applicable emission limit in paragraph (f)(1)(i) or
(ii) of this section. If the sulfur recovery plant consists of multiple
process trains or release points, the owner or operator shall comply
with the applicable emission limit for each process train or release
point individually or comply with the applicable emission limit in
paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group
of release points from the sulfur recovery plant provided that flow is
monitored as specified in Sec.  60.106a(a)(7); if flow is not monitored
as specified in Sec.  60.106a(a)(7), the owner or operator shall comply
with the applicable emission limit in paragraph (f)(1)(i) or (ii) for
each process train or release point individually. For a sulfur recovery
plant with a design production capacity greater than 20 long LTD and a
reduction control system not followed by incineration, the owner or
operator shall also comply with the H2S emission limit in
paragraph (f)(1)(iii) of this section for each individual release
point.
    (i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere (SO2) in excess of the emission limit
calculated using Equation 1 of this section. For Claus units that use
only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emissions limit is 250 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.000

Where:

ELS = Emission limit for large sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used for the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
reduced sulfur compounds in excess of the emission limit calculated
using Equation 1 of this section. For Claus units that use only ambient
air in the Claus burner or for non-Claus sulfur recovery plants, this
reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv
SO2 (dry basis) at 0-percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
hydrogen sulfide (H2S) in excess of 10 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.

    (2) For a sulfur recovery plant with a design production capacity
of 20 LTD or less, the owner or operator shall comply with the
applicable emission limit in paragraph (f)(2)(i) or (ii) of this
section. If the sulfur recovery plant consists of multiple process
trains or release points, the owner or operator may comply with the
applicable emission limit for each process train or release point
individually or comply with the applicable emission limit in paragraph
(f)(2)(i) or (ii) as a flow rate weighted average for a group of
release points from the sulfur recovery plant provided that flow is
monitored as specified in Sec.  60.106a(a)(7); if flow is not monitored
as specified in Sec.  60.106a(a)(7), the owner or operator shall comply
with the applicable emission limit in paragraph (f)(2)(i) or (ii) for
each process train or release point individually. For a sulfur recovery
plant with a design production capacity of 20 LTD or less and a
reduction control system not followed by incineration, the owner or
operator shall also comply with the H2S emission limit in
paragraph (f)(2)(iii) of this section for each individual release
point.
    (i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere containing SO2 in excess of the emission
limit calculated using Equation 2 of this section. For Claus units that
use only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emission limit is 2,500 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.001

Where:

ESS = Emission limit for small sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used in the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
reduced sulfur compounds in excess of the emission limit calculated
using Equation 2 of this section. For Claus units that use only ambient
air in the Claus burner or for non-Claus sulfur recovery plants, this
reduced sulfur compounds emission limit is 3,000 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
H2S in excess of 100 ppmv calculated as ppmv SO2
(dry basis) at zero percent excess air.
    (3) The emission limits in paragraphs (f)(1) and (2) of this
section shall not apply during periods of maintenance of the sulfur
pit, which shall not exceed 240 hours per year. The owner or operator
must document the time periods during which the sulfur pit vents were
not controlled and measures taken to minimize emissions during these
periods. Examples of these measures include not adding fresh sulfur or
shutting off vent fans.
    (g) * * *
    (1) Except as provided in (g)(1)(iii) of this section, for each
fuel gas combustion device, the owner or operator shall comply with
either the emission limit in paragraph (g)(1)(i) of this section or the
fuel gas concentration limit in paragraph (g)(1)(ii) of this section.
For CO boilers or furnaces that are part of a fluid catalytic cracking
unit or fluid coking unit affected facility, the owner or operator
shall comply with the fuel gas concentration limit in paragraph
(g)(1)(ii) for all fuel gas streams combusted in these units.
* * * * *

0
6. Section 60.104a is amended by:
0
a. Revising the first sentence of paragraph (a) and paragraphs (b), (f)
introductory text, and (h) introductory text;
0
b. Adding paragraph (h)(6); and
0
c. Removing and reserving paragraphs (j)(1) through (3).
    The revisions and additions read as follows:

Sec.  60.104a  Performance tests.

    (a) The owner or operator shall conduct a performance test for each
FCCU, FCU, sulfur recovery plant and fuel gas combustion device to
demonstrate initial compliance with each applicable emissions limit in
Sec.  60.102a and conduct a performance test for each flare to
demonstrate initial compliance with the H2S concentration
requirement in Sec.  60.103a(h) according to the requirements of Sec.
60.8. * * *
    (b) The owner or operator of a FCCU or FCU that elects to monitor
control device operating parameters according to the requirements in
Sec.  60.105a(b), to use bag leak detectors according to the
requirements in Sec.  60.105a(c), or to use COMS according to the
requirements in Sec.  60.105a(e) shall conduct a PM performance test at
least annually (i.e., once per calendar year, with an interval of at
least 8 months but no more than 16 months between annual tests) and
furnish the Administrator a written report of the results of each test.
* * * * *
    (f) The owner or operator of an FCCU or FCU that uses cyclones to
comply with the PM per coke burn-off emissions limit in Sec.
60.102a(b)(1) shall establish a site-specific opacity operating limit
according to the procedures in paragraphs (f)(1) through (3) of this
section.
* * * * *
    (h) The owner or operator shall determine compliance with the
SO2 emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and
H2S emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the
following methods and procedures:
* * * * *
    (6) If oxygen or oxygen-enriched air is used in the Claus burner
and either Equation 1 or 2 of this subpart is used to determine the
applicable emissions limit, determine the average O2
concentration of the air/oxygen mixture supplied to the Claus burner,
in percent by volume (dry basis), for the performance test using all
hourly average O2 concentrations determined

during the test runs using the procedures in Sec.  60.106a(a)(5) or
(6).
* * * * *

0
7. Section 60.105a is amended by:
0
a. Revising paragraphs (b)(1)(i), (b)(1)(ii)(A), (b)(2), (h)(1),
(h)(3)(i), and (i)(1);
0
b. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
c. Adding paragraph (i)(2); and
0
d. Revising newly redesignated paragraph (i)(7).
    The revisions and additions read as follows:

Sec.  60.105a  Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
    (b) * * *
    (1) * * *
    (i) For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary current to the entire system.
    (ii) * * *
    (A) As an alternative to pressure drop, the owner or operator of a
jet ejector type wet scrubber or other type of wet scrubber equipped
with atomizing spray nozzles must conduct a daily check of the air or
water pressure to the spray nozzles and record the results of each
check. Faulty (e.g., leaking or plugged) air or water lines must be
repaired within 12 hours of identification of an abnormal pressure
reading.
* * * * *
    (2) For use in determining the coke burn-off rate for an FCCU or
FCU, the owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations
of CO2, O2 (dry basis), and if needed, CO in the
exhaust gases prior to any control or energy recovery system that burns
auxiliary fuels. A CO monitor is not required for determining coke
burn-off rate when no auxiliary fuel is burned and a continuous CO
monitor is not required in accordance with paragraph (h)(3) of this
section.
    (i) The owner or operator shall install, operate, and maintain each
CO2 and O2 monitor according to Performance
Specification 3 of appendix B to this part.
    (ii) The owner or operator shall conduct performance evaluations of
each CO2 and O2 monitor according to the
requirements in Sec.  60.13(c) and Performance Specification 3 of
appendix B to this part. The owner or operator shall use Method 3 of
appendix A-3 to this part for conducting the relative accuracy
evaluations.
    (iii) If a CO monitor is required, the owner or operator shall
install, operate, and maintain each CO monitor according to Performance
Specification 4 or 4A of appendix B to this part. If this CO monitor
also serves to demonstrate compliance with the CO emissions limit in
Sec.  60.102a(b)(4), the span value for this instrument is 1,000 ppm;
otherwise, the span value for this instrument should be set at
approximately 2 times the typical CO concentration expected in the FCCU
of FCU flue gas prior to any emission control or energy recovery system
that burns auxiliary fuels.
    (iv) If a CO monitor is required, the owner or operator shall
conduct performance evaluations of each CO monitor according to the
requirements in Sec.  60.13(c) and Performance Specification 4 of
appendix B to this part. The owner or operator shall use Method 10,
10A, or 10B of appendix A-3 to this part for conducting the relative
accuracy evaluations.
    (v) The owner or operator shall comply with the quality assurance
requirements of procedure 1 of appendix F to this part, including
quarterly accuracy determinations for CO2 and CO monitors,
annual accuracy determinations for O2 monitors, and daily
calibration drift tests.
* * * * *
    (h) * * *
    (1) The owner or operator shall install, operate, and maintain each
CO monitor according to Performance Specification 4 or 4A of appendix B
to this part. The span value for this instrument is 1,000 ppmv CO.
* * * * *
    (3) * * *
    (i) The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements
of Performance Specification 4 or 4A of appendix B to this part. The
span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5
ppmv CO, whichever is greater. For instruments that are identical to
Method 10 of appendix A-4 to this part and employ the sample
conditioning system of Method 10A of appendix A-4 to this part, the
alternative relative accuracy test procedure in section 10.1 of
Performance Specification 2 of appendix B to this part may be used in
place of the relative accuracy test.
* * * * *
    (i) * * *
    (1) If a CPMS is used according to paragraph (b)(1) of this
section, all 3-hour periods during which the average PM control device
operating characteristics, as measured by the continuous monitoring
systems under paragraph (b)(1), fall below the levels established
during the performance test. If the alternative to pressure drop CPMS
is used for the owner or operator of a jet ejector type wet scrubber or
other type of wet scrubber equipped with atomizing spray nozzles, each
day in which abnormal pressure readings are not corrected within 12
hours of identification.
    (2) If a bag leak detection system is used according to paragraph
(c) of this section, each day in which the cause of an alarm is not
alleviated within the time period specified in paragraph (c)(3) of this
section.
* * * * *
    (7) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under paragraph (h) of
this section exceeds 500 ppmv or, if applicable, all 1-hour periods
during which the average temperature and O2 concentration as
measured by the continuous monitoring systems under paragraph (h)(4) of
this section fall below the operating limits established during the
performance test.

0
8. Section 60.106a is amended by:
0
a. Revising paragraph (a)(1)(i);
0
b. Adding paragraphs (a)(1)(iv) through (vii);
0
c. Revising paragraphs (a)(2) introductory text, (a)(2)(i) and (ii),
and the first sentence of paragraph (a)(2)(iii);
0
d. Removing paragraphs (a)(2)(iv) and (v);
0
e. Redesignating paragraphs (a)(2)(vi) through (ix) as (a)(2)(iv)
through (vii);
0
f. Revising the first sentence of paragraph (a)(3) introductory text
and paragraph (a)(3)(i);
0
g. Adding paragraphs (a)(4) through (7); and
0
h. Revising paragraphs (b)(2) and (3).
    The revisions and additions read as follows:

Sec.  60.106a  Monitoring of emissions and operations for sulfur
recovery plants.

    (a) * * *
    (1) * * *
    (i) The span value for the SO2 monitor is two times the
applicable SO2 emission limit at the highest O2
concentration in the air/oxygen stream used in the Claus burner, if
applicable.
* * * * *
    (iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to this part.
    (v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.

    (vi) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
    (vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to this part for each
monitor, including annual accuracy determinations for each
O2 monitor, and daily calibration drift determinations.
    (2) For sulfur recovery plants that are subject to the reduced
sulfur compounds emission limit in Sec.  60.102a(f)(1)(ii) or
(f)(2)(ii), the owner or operator shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording
the concentration of reduced sulfur compounds and O2
emissions into the atmosphere. The reduced sulfur compounds emissions
shall be calculated as SO2 (dry basis, zero percent excess
air).
    (i) The span value for the reduced sulfur compounds monitor is two
times the applicable reduced sulfur compounds emission limit as
SO2 at the highest O2 concentration in the air/
oxygen stream used in the Claus burner, if applicable.
    (ii) The owner or operator shall install, operate, and maintain
each reduced sulfur compounds CEMS according to Performance
Specification 5 of appendix B to this part.
    (iii) The owner or operator shall conduct performance evaluations
of each reduced sulfur compounds monitor according to the requirements
in Sec.  60.13(c) and Performance Specification 5 of appendix B to this
part. * * *
* * * * *
    (3) In place of the reduced sulfur compounds monitor required in
paragraph (a)(2) of this section, the owner or operator may install,
calibrate, operate, and maintain an instrument using an air or
O2 dilution and oxidation system to convert any reduced
sulfur to SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2. * * *
    (i) The span value for this monitor is two times the applicable
reduced sulfur compounds emission limit as SO2 at the
highest O2 concentration in the air/oxygen stream used in
the Claus burner, if applicable.
* * * * *
    (4) For sulfur recovery plants that are subject to the
H2S emission limit in Sec.  60.102a(f)(1)(iii) or
(f)(2)(iii), the owner or operator shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording
the concentration of H2S, and O2 emissions into
the atmosphere. The H2S emissions shall be calculated as
SO2 (dry basis, zero percent excess air).
    (i) The span value for this monitor is two times the applicable
H2S emission limit.
    (ii) The owner or operator shall install, operate, and maintain
each H2S CEMS according to Performance Specification 7 of
appendix B to this part.
    (iii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 of appendix B to this part.
The owner or operator shall use Methods 11 or 15 of appendix A-5 to
this part or Method 16 of appendix A-6 to this part for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 15A of appendix A-5 to this part.
    (iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to this part.
    (v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
    (vi) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
    (vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to this part for each
monitor, including annual accuracy determinations for each
O2 monitor, and daily calibration drift determinations.
    (5) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner and that elects to monitor O2
concentration of the air/oxygen mixture supplied to the Claus burner,
the owner or operator shall install, operate, calibrate, and maintain
an instrument for continuously monitoring and recording the
O2 concentration of the air/oxygen mixture supplied to the
Claus burner in order to determine the allowable emissions limit.
    (i) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to this part.
    (ii) The span value for the O2 monitor shall be 100
percent.
    (iii) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
    (iv) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to this part for each monitor,
including annual accuracy determinations for each O2
monitor, and daily calibration drift determinations.
    (v) The owner or operator shall use the hourly average
O2 concentration from this monitor for use in Equation 1 or
2 of Sec.  60.102a(f), as applicable, for each hour and determine the
allowable emission limit as the arithmetic average of 12 contiguous 1-
hour averages (i.e., the rolling 12-hour average).
    (6) As an alternative to the O2 monitor required in
paragraph (a)(5) of this section, the owner or operator may install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of ambient air and oxygen-enriched gas
supplied to the Claus burner and calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner as specified in paragraphs (a)(6)(i) through (iv) of this
section in order to determine the allowable emissions limit as
specified in paragraphs (a)(6)(v) of this section.
    (i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
    (A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.

    (B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet
per minute, whichever is greater.
    (C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure and, for ambient air
flow monitor, moisture content, and is able to record dry flow in
standard conditions (as defined in Sec.  60.2) over one-minute
averages.
    (D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall use 20.9 percent as the oxygen
content of the ambient air.
    (iii) The owner or operator shall use product specifications (e.g.,
as reported in material safety data sheets) for percent oxygen for
purchased oxygen. For oxygen produced onsite, the percent oxygen shall
be determined by periodic measurements or process knowledge.
    (iv) The owner or operator shall calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner using Equation 10 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.002

Where:

%O2 = O2 concentration of the air/oxygen
mixture used in the Claus burner, percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry basis;
Qair = Volumetric flow rate of ambient air used in the
Claus burner, dscfm;
%O2,oxy = O2 concentration in the enriched
oxygen stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched oxygen stream
used in the Claus burner, dscfm.

    (v) The owner or operator shall use the hourly average
O2 concentration determined using Equation 8 of Sec.
60.104a(d)(8) for use in Equation 1 or 2 of Sec.  60.102a(f), as
applicable, for each hour and determine the allowable emission limit as
the arithmetic average of 12 contiguous 1-hour averages (i.e., the
rolling 12-hour average).
    (7) Owners or operators of a sulfur recovery plant that elects to
comply with the SO2 emission limit in Sec.  60.102a(f)(1)(i)
or (f)(2)(i) or the reduced sulfur compounds emission limit in Sec.
60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a
group of release points from the sulfur recovery plant rather than for
each process train or release point individually shall install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of each release point within the group of
release points from the sulfur recovery plant as specified in
paragraphs (a)(7)(i) through (iv) of this section.
    (i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
    (A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.
    (B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet
per minute, whichever is greater.
    (C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure, and moisture content,
and is able to record dry flow in standard conditions (as defined in
Sec.  60.2) over one-minute averages.
    (D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall correct the flow to 0 percent
excess air using Equation 11 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.003

Where:

Qadj = Volumetric flow rate adjusted to 0 percent excess
air, dry standard cubic feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the flow meter
corrected to dry standard conditions, dscfm;
20.9c = 20.9 percent O2-0.0 percent
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.

    (iii) The owner or operator shall calculate the flow weighted
average SO2 or reduced sulfur compounds concentration for
each hour using Equation 12 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.004

Where:

Cave = Flow weighted average concentration of the
pollutant, ppmv (dry basis, zero percent excess air). The pollutant
is either SO2 (if complying with the SO2
emission limit in Sec.  60.102a(f)(1)(i) or (f)(2)(i)) or reduced
sulfur compounds (if complying with the reduced sulfur compounds
emission limit in Sec.  60.102a(f)(1)(ii) or (f)(2)(ii));
N = Number of release points within the group of release points from
the sulfur recovery plant for which emissions averaging is elected;
Cn = Pollutant concentration in the nth
release point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, ppmv (dry
basis, zero percent excess air);
Qadj,n = Volumetric flow rate of the nth
release point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, dry
standard cubic feet per minute (dscfm, adjusted to 0 percent excess
air).

    (iv) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner, the owner or operator shall use Equation 10 of
this section and the hourly emission limits determined in paragraph
(a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant
concentration to determine the flow weighted average hourly emission
limit for each hour. The allowable emission limit shall be calculated
as the arithmetic average of 12 contiguous 1-hour averages (i.e., the
rolling 12-hour average).
    (b) * * *
    (2) All 12-hour periods during which the average concentration of
reduced sulfur compounds (as SO2) as measured by the reduced
sulfur compounds continuous monitoring system required under paragraph
(a)(2) or (3) of this section exceeds the applicable emission limit; or
    (3) All 12-hour periods during which the average concentration of
H2S as measured by the H2S continuous monitoring
system required under paragraph (a)(4) of this section exceeds the
applicable emission limit (dry basis, 0 percent excess air).

0
9. Section 60.107a is amended by revising paragraphs (a)(1)(i) and
(ii), (b)(1)(iv), the first sentence of paragraph (b)(3)(iii), (d)(3),
(e)(1) introductory text, (e)(1)(ii), (e)(2) introductory text,
(e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii), and (h)(5) to read as
follows:

Sec.  60.107a  Monitoring of emissions and operations for fuel gas
combustion devices and flares.

    (a) * * *
    (1) * * *
    (i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 of
appendix B to this part. The span value for the SO2 monitor
is 50 ppmv SO2.
    (ii) The owner or operator shall conduct performance evaluations
for the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 of appendix B to this part.
The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17)
is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to
this part. Samples taken by Method 6 of appendix A-4 to this part shall
be taken at a flow rate of approximately 2 liters/min for at least 30
minutes. The relative accuracy limit shall be 20 percent or 4 ppmv,
whichever is greater, and the calibration drift limit shall be 5
percent of the established span value.
* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv H2S. Sampling data must include, at minimum, 2 weeks of
daily monitoring (14 grab samples) for frequently operated fuel gas
streams/systems; for infrequently operated fuel gas streams/systems,
seven grab samples must be collected unless other additional
information would support reduced sampling. The owner or operator shall
use detector tubes (``length-of-stain tube'' type measurement)
following the ``Gas Processors Association Standard 2377-86
(incorporated by reference--see Sec.  60.17), using tubes with a
maximum span between 10 and 40 ppmv inclusive when 1<=N<=10, where N =
number of pump strokes, to test the applicant fuel gas stream for
H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of-stain tubes with a maximum span between 200
and 400 ppmv inclusive when 1<=N<=5, where N = number of pump strokes.
* * *
* * * * *
    (d) * * *
    (3) As an alternative to the requirements in paragraph (d)(2) of
this section, the owner or operator of a gas-fired process heater shall
install, operate and maintain a gas composition analyzer and determine
the average F factor of the fuel gas using the factors in Table 1 of
this subpart and Equation 13 of this section. If a single fuel gas
system provides fuel gas to several process heaters, the F factor may
be determined at a single location in the fuel gas system provided it
is representative of the fuel gas fed to the affected process
heater(s).
[GRAPHIC] [TIFF OMITTED] TR01DE15.005

Where:

Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
    Xi = mole or volume fraction of each component in the
fuel gas.
    MEVi = molar exhaust volume, dry standard cubic feet
per mole (dscf/mol).
    MHCi = molar heat content, Btu per mole (Btu/mol).
    1,000,000 = unit conversion, Btu per MMBtu.
* * * * *
    (e) * * *
    (1) Total reduced sulfur monitoring requirements. The owner or
operator shall install, operate, calibrate and maintain an instrument
or instruments for continuously monitoring and recording the
concentration of total reduced sulfur in gas discharged to the flare.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of
each total reduced sulfur monitor according to the requirements in
Sec.  60.13(c) and Performance Specification 5 of appendix B to this
part. The owner or operator of each total

reduced sulfur monitor shall use EPA Method 15A of appendix A-5 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference-see Sec.  60.17) is an
acceptable alternative to EPA Method 15A of appendix A-5 to this part.
The alternative relative accuracy procedures described in section 16.0
of Performance Specification 2 of appendix B to this part (cylinder gas
audits) may be used for conducting the relative accuracy evaluations,
except that it is not necessary to include as much of the sampling
probe or sampling line as practical.
* * * * *
    (2) H2S monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument or instruments
for continuously monitoring and recording the concentration of
H2S in gas discharged to the flare according to the
requirements in paragraphs (e)(2)(i) through (iii) of this section and
shall collect and analyze samples of the gas and calculate total sulfur
concentrations as specified in paragraphs (e)(2)(iv) through (ix) of
this section.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of
each H2S monitor according to the requirements in Sec.
60.13(c) and Performance Specification 7 of appendix B to this part.
The owner or operator shall use EPA Method 11, 15 or 15A of appendix A-
5 to this part for conducting the relative accuracy evaluations. The
method ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 15A of appendix A-5
to this part. The alternative relative accuracy procedures described in
section 16.0 of Performance Specification 2 of appendix B to this part
(cylinder gas audits) may be used for conducting the relative accuracy
evaluations, except that it is not necessary to include as much of the
sampling probe or sampling line as practical.
* * * * *
    (vi) * * *
    (C) Determine the acceptable range for subsequent weekly samples
based on the 95-percent confidence interval for the distribution of
daily ratios based on the 10 individual daily ratios using Equation 14
of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.006

Where:

    AR = Acceptable range of subsequent ratio determinations,
unitless.
    RatioAvg = 10-day average total sulfur-to-
H2S concentration ratio, unitless.
    2.262 = t-distribution statistic for 95-percent 2-sided
confidence interval for 10 samples (9 degrees of freedom).
    SDev = Standard deviation of the 10 daily average total sulfur-
to-H2S concentration ratios used to develop the 10-day
average total sulfur-to-H2S concentration ratio,
unitless.
* * * * *
    (3) SO2 monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration of
SO2 from a process heater or other fuel gas combustion
device that is combusting gas representative of the fuel gas in the
flare gas line according to the requirements in paragraph (a)(1) of
this section, determine the F factor of the fuel gas at least daily
according to the requirements in paragraphs (d)(2) through (4) of this
section, determine the higher heating value of the fuel gas at least
daily according to the requirements in paragraph (d)(7) of this
section, and calculate the total sulfur content (as SO2) in
the fuel gas using Equation 15 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.007

Where:

    TSFG = Total sulfur concentration, as SO2,
in the fuel gas, ppmv.
    CSO2 = Concentration of SO2 in the exhaust
gas, ppmv (dry basis at 0-percent excess air).
    Fd = F factor gas on dry basis at 0-percent excess
air, dscf/MMBtu.
    HHVFG = Higher heating value of the fuel gas, MMBtu/
scf.
* * * * *
    (f) * * *
    (1) * * *
    (ii) Use a flow sensor meeting an accuracy requirement of 20 percent of the flow rate at velocities ranging from 0.1 to 1
feet per second and an accuracy of 5 percent of the flow
rate for velocities greater than 1 feet per second.
* * * * *
    (h) * * *
    (5) Daily O2 limits for fuel gas combustion devices. Each day
during which the concentration of O2 as measured by the
O2 continuous monitoring system required under paragraph
(c)(6) or (d)(8) of this section exceeds the O2 operating
limit or operating curve determined during the most recent biennial
performance test.

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES

0
10. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401 et se.

Subpart A--General Provisions

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (h)(14);
0
b. Redesignating paragraphs (h)(82) through (99) as (h)(86) through
(103), paragraphs (h)(77) through (81) as (h)(80) through (84),
paragraphs (h)(73) through (76) as paragraphs (h)(75) through (78), and
paragraphs (h)(15) through (72) as (16) through (73), respectively;
0
c. Revising newly redesignated paragraph (h)(78);
0
d. Adding paragraphs (h)(15), (74), (79), (85), (104) and (j)(2);
0
e. Redesignating paragraph (m)(3) through (21) as (m)(5) through (23),
respectively, and paragraph (m)(2) as (m)(3).
0
f. Adding paragraphs (m)(2) and (4) and (n)(3); and
0
g. Revising paragraph (s)(1).
    The revisions and additions read as follows:

Sec.  63.14  Incorporation by reference.

* * * * *
    (h) * * *
    (14) ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, Approved January 1,
2010, IBR approved for Sec. Sec.  63.670(j), 63.772(h), and 63.1282(g).
    (15) ASTM D1945-14, Standard Test Method for Analysis of Natural
Gas by Gas Chromatography, Approved

November 1, 2014, IBR approved for Sec.  63.670(j).
* * * * *
    (74) ASTM D6196-03 (Reapproved 2009), Standard Practice for
Selection of Sorbents, Sampling, and Thermal Desorption Analysis
Procedures for Volatile Organic Compounds in Air, Approved March 1,
2009, IBR approved for appendix A to this part: Method 325A and Method
325B.
* * * * *
    (78) ASTM D6348-03 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1
through A8, Approved October 1, 2010, IBR approved for Sec.
63.1571(a), tables 4 and 5 to subpart JJJJJ, tables 4 and 6 to subpart
KKKKK, tables 1, 2, and 5 to subpart UUUUU and appendix B to subpart
UUUUU.
* * * * *
    (79) ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, Approved February 1, 2012, IBR approved
for Sec.  63.1571(a).
* * * * *
    (85) ASTM D6420-99 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, Approved October 1, 2010, IBR
approved for Sec.  63.670(j) and appendix A to this part: Method 325B.
* * * * *
    (104) ASTM UOP539-12, Refinery Gas Analysis by GC, Copyright 2012
(to UOP), IBR approved for Sec.  63.670(j).
* * * * *
    (j) * * *
    (2) BS EN 14662-4:2005, Ambient air quality standard method for the
measurement of benzene concentrations--Part 4: Diffusive sampling
followed by thermal desorption and gas chromatography, Published June
27, 2005, IBR approved for appendix A to this part: Method 325A and
Method 325B.
* * * * *
    (m) * * *
    (2) EPA-454/B-08-002, Office of Air Quality Planning and Standards
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final),
March 24, 2008, IBR approved for Sec.  63.658(d) and appendix A to this
part: Method 325A.
* * * * *
    (4) EPA-454/R-99-005, Office of Air Quality Planning and Standards
(OAQPS), Meteorological Monitoring Guidance for Regulatory Modeling
Applications, February 2000, IBR approved for appendix A to this part:
Method 325A.
* * * * *
    (n) * * *
    (3) ISO 16017-2:2003(E): Indoor, ambient and workplace air--
sampling and analysis of volatile organic compounds by sorbent tube/
thermal desorption/capillary gas chromatography--Part 2: Diffusive
sampling, May 15, 2003, IBR approved for appendix A to this part:
Method 325A and Method 325B.
* * * * *
    (s) * * *
    (1) ``Air Stripping Method (Modified El Paso Method) for
Determination of Volatile Organic Compound Emissions from Water
Sources,'' Revision Number One, dated January 2003, Sampling Procedures
Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003, IBR
approved for Sec. Sec.  63.654(c) and (g), 63.655(i), and 63.11920.
* * * * *

Subpart Y--National Emission Standards for Marine Tank Vessel
Loading Operations

0
12. Section 63.560 is amended by revising paragraph (a)(4) to read as
follows:

Sec.  63.560  Applicability and designation of affected source.

    (a) * * *
    (4) Existing sources with emissions less than 10 and 25 tons must
meet the submerged fill standards of 46 CFR 153.282.
* * * * *

Subpart CC--National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries

0
13. Section 63.640 is amended by:
0
a. Revising paragraphs (a) introductory text and (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraphs (d)(5), (h), (k)(1), (l) introductory text,
(l)(2) introductory text, (l)(2)(i), (l)(3) introductory text, (m)
introductory text, (n) introductory text, (n)(1) through (5), (n)(8)
introductory text, and (n)(8)(ii);
0
e. Adding paragraphs (n)(8)(vii) and (viii);
0
f. Revising paragraph (n)(9)(i);
0
g. Adding paragraph (n)(10);
0
h. Revising paragraph (o)(2)(i) introductory text;
0
i. Adding paragraph (o)(2)(i)(D);
0
j. Revising paragraph (o)(2)(ii) introductory text; and
0
k. Adding paragraphs (o)(2)(ii)(C) and (s).
    The revisions and additions read as follows:

Sec.  63.640  Applicability and designation of affected source.

    (a) This subpart applies to petroleum refining process units and to
related emissions points that are specified in paragraphs (c)(1)
through (9) of this section that are located at a plant site and that
meet the criteria in paragraphs (a)(1) and (2) of this section:
* * * * *
    (c) For the purposes of this subpart, the affected source shall
comprise all emissions points, in combination, listed in paragraphs
(c)(1) through (9) of this section that are located at a single
refinery plant site.
* * * * *
    (9) All releases associated with the decoking operations of a
delayed coking unit, as defined in this subpart.
    (d) * * *
    (5) Emission points routed to a fuel gas system, as defined in
Sec.  63.641, provided that on and after January 30, 2019, any flares
receiving gas from that fuel gas system are subject to Sec.  63.670. No
other testing, monitoring, recordkeeping, or reporting is required for
refinery fuel gas systems or emission points routed to refinery fuel
gas systems.
* * * * *
    (h) Sources subject to this subpart are required to achieve
compliance on or before the dates specified in table 11 of this
subpart, except as provided in paragraphs (h)(1) through (3) of this
section.
    (1) Marine tank vessels at existing sources shall be in compliance
with this subpart, except for Sec. Sec.  63.657 through 63.660, no
later than August 18, 1999, unless the vessels are included in an
emissions average to generate emission credits. Marine tank vessels
used to generate credits in an emissions average shall be in compliance
with this subpart no later than August 18, 1998, unless an extension
has been granted by the Administrator as provided in Sec.  63.6(i).
    (2) Existing Group 1 floating roof storage vessels meeting the
applicability criteria in item 1 of the definition of Group 1 storage
vessel shall be in compliance with Sec.  63.646 at the first degassing
and cleaning activity after August 18, 1998, or August 18, 2005,
whichever is first.

    (3) An owner or operator may elect to comply with the provisions of
Sec.  63.648(c) through (i) as an alternative to the provisions of
Sec.  63.648(a) and (b). In such cases, the owner or operator shall
comply no later than the dates specified in paragraphs (h)(3)(i)
through (iii) of this section.
    (i) Phase I (see table 2 of this subpart), beginning on August 18,
1998;
    (ii) Phase II (see table 2 of this subpart), beginning no later
than August 18, 1999; and
    (iii) Phase III (see table 2 of this subpart), beginning no later
than February 18, 2001.
* * * * *
    (k) * * *
    (1) The reconstructed source, addition, or change shall be in
compliance with the new source requirements in item (1), (2), or (3) of
table 11 of this subpart, as applicable, upon initial startup of the
reconstructed source or by August 18, 1995, whichever is later; and
* * * * *
    (l) If an additional petroleum refining process unit is added to a
plant site or if a miscellaneous process vent, storage vessel, gasoline
loading rack, marine tank vessel loading operation, heat exchange
system, or decoking operation that meets the criteria in paragraphs
(c)(1) through (9) of this section is added to an existing petroleum
refinery or if another deliberate operational process change creating
an additional Group 1 emissions point(s) (as defined in Sec.  63.641)
is made to an existing petroleum refining process unit, and if the
addition or process change is not subject to the new source
requirements as determined according to paragraph (i) or (j) of this
section, the requirements in paragraphs (l)(1) through (4) of this
section shall apply. Examples of process changes include, but are not
limited to, changes in production capacity, or feed or raw material
where the change requires construction or physical alteration of the
existing equipment or catalyst type, or whenever there is replacement,
removal, or addition of recovery equipment. For purposes of this
paragraph (l) and paragraph (m) of this section, process changes do not
include: Process upsets, unintentional temporary process changes, and
changes that are within the equipment configuration and operating
conditions documented in the Notification of Compliance Status report
required by Sec.  63.655(f).
* * * * *
    (2) The added emission point(s) and any emission point(s) within
the added or changed petroleum refining process unit shall be in
compliance with the applicable requirements in item (4) of table 11 of
this subpart by the dates specified in paragraph (l)(2)(i) or (ii) of
this section.
    (i) If a petroleum refining process unit is added to a plant site
or an emission point(s) is added to any existing petroleum refining
process unit, the added emission point(s) shall be in compliance upon
initial startup of any added petroleum refining process unit or
emission point(s) or by the applicable compliance date in item (4) of
table 11 of this subpart, whichever is later.
* * * * *
    (3) The owner or operator of a petroleum refining process unit or
of a storage vessel, miscellaneous process vent, wastewater stream,
gasoline loading rack, marine tank vessel loading operation, heat
exchange system, or decoking operation meeting the criteria in
paragraphs (c)(1) through (9) of this section that is added to a plant
site and is subject to the requirements for existing sources shall
comply with the reporting and recordkeeping requirements that are
applicable to existing sources including, but not limited to, the
reports listed in paragraphs (l)(3)(i) through (vii) of this section. A
process change to an existing petroleum refining process unit shall be
subject to the reporting requirements for existing sources including,
but not limited to, the reports listed in paragraphs (l)(3)(i) through
(vii) of this section. The applicable reports include, but are not
limited to:
* * * * *
    (m) If a change that does not meet the criteria in paragraph (l) of
this section is made to a petroleum refining process unit subject to
this subpart, and the change causes a Group 2 emission point to become
a Group 1 emission point (as defined in Sec.  63.641), then the owner
or operator shall comply with the applicable requirements of this
subpart for existing sources, as specified in item (4) of table 11 of
this subpart, for the Group 1 emission point as expeditiously as
practicable, but in no event later than 3 years after the emission
point becomes Group 1.
* * * * *
    (n) Overlap of this subpart with other regulations for storage
vessels. As applicable, paragraphs (n)(1), (3), (4), (6), and (7) of
this section apply for Group 2 storage vessels and paragraphs (n)(2)
and (5) of this section apply for Group 1 storage vessels.
    (1) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is subject to the provisions of
40 CFR part 60, subpart Kb, is required to comply only with the
requirements of 40 CFR part 60, subpart Kb, except as provided in
paragraph (n)(8) of this section. After the compliance dates specified
in paragraph (h) of this section, a Group 2 storage vessel that is
subject to the provisions of 40 CFR part 61, subpart Y, is required to
comply only with the requirements of 40 CFR part 61, subpart Y, except
as provided in paragraph (n)(10) of this section.
    (2) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to 40 CFR part
60, subpart Kb, is required to comply only with either 40 CFR part 60,
subpart Kb, except as provided in paragraph (n)(8) of this section or
this subpart. After the compliance dates specified in paragraph (h) of
this section, a Group 1 storage vessel that is also subject to 40 CFR
part 61, subpart Y, is required to comply only with either 40 CFR part
61, subpart Y, except as provided in paragraph (n)(10) of this section
or this subpart.
    (3) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 60.110b, but is not required to apply controls by 40
CFR 60.110b or 60.112b, is required to comply only with this subpart.
    (4) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 61.270, but is not required to apply controls by 40
CFR 61.271, is required to comply only with this subpart.
    (5) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to the
provisions of 40 CFR part 60, subpart K or Ka, is required to only
comply with the provisions of this subpart.
* * * * *
    (8) Storage vessels described by paragraph (n)(1) of this section
are to comply with 40 CFR part 60, subpart Kb, except as provided in
paragraphs (n)(8)(i) through (vi) of this section. Storage vessels
described by paragraph (n)(2) electing to comply with part 60, subpart
Kb of this chapter shall comply with subpart Kb except as provided in
paragraphs (n)(8)(i) through (viii) of this section.
* * * * *
    (ii) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec.  60.113b(b) of this
chapter or to inspect the vessel to determine compliance with

Sec.  60.113b(a) of this chapter because the roof appears to be
structurally unsound and poses an imminent danger to inspecting
personnel, the owner or operator shall comply with the requirements in
either Sec.  63.120(b)(7)(i) or (ii) of subpart G (only up to the
compliance date specified in paragraph (h) of this section for
compliance with Sec.  63.660, as applicable) or either Sec.
63.1063(c)(2)(iv)(A) or (B) of subpart WW.
* * * * *
    (vii) To be in compliance with Sec.  60.112b(a)(1)(iv) or
(a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels
must be equipped with covers and/or controls (e.g., pole float system,
pole sleeve system, internal sleeve system or flexible enclosure
system) as appropriate to comply with the ``no visible gap''
requirement.
    (viii) If a flare is used as a control device for a storage vessel,
on and after January 30, 2019, the owner or operator must meet the
requirements of Sec.  63.670 instead of the requirements referenced
from part 60, subpart Kb of this chapter for that flare.
    (9) * * *
    (i) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec.  60.113a(a)(1) of
this chapter because the floating roof appears to be structurally
unsound and poses an imminent danger to inspecting personnel, the owner
or operator shall comply with the requirements in either Sec.
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date
specified in paragraph (h) of this section for compliance with Sec.
63.660, as applicable) or either Sec.  63.1063(c)(2)(iv)(A) or (B) of
subpart WW.
* * * * *
    (10) Storage vessels described by paragraph (n)(1) of this section
are to comply with 40 CFR part 61, subpart Y, except as provided in
paragraphs (n)(10)(i) through (vi) of this section. Storage vessels
described by paragraph (n)(2) electing to comply with 40 CFR part 61,
subpart Y, shall comply with subpart Y except as provided for in
paragraphs (n)(10)(i) through (viii) of this section.
    (i) Storage vessels that are to comply with Sec.  61.271(b) of this
chapter are exempt from the secondary seal requirements of Sec.
61.271(b)(2)(ii) of this chapter during the gap measurements for the
primary seal required by Sec.  61.272(b) of this chapter.
    (ii) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec.  61.272(b) of this
chapter or to inspect the vessel to determine compliance with Sec.
61.272(a) of this chapter because the roof appears to be structurally
unsound and poses an imminent danger to inspecting personnel, the owner
or operator shall comply with the requirements in either Sec.
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date
specified in paragraph (h) of this section for compliance with Sec.
63.660, as applicable) or either Sec.  63.1063(c)(2)(iv)(A) or (B) of
subpart WW.
    (iii) If a failure is detected during the inspections required by
Sec.  61.272(a)(2) of this chapter or during the seal gap measurements
required by Sec.  61.272(b)(1) of this chapter, and the vessel cannot
be repaired within 45 days and the vessel cannot be emptied within 45
days, the owner or operator may utilize up to two extensions of up to
30 additional calendar days each. The owner or operator is not required
to provide a request for the extension to the Administrator.
    (iv) If an extension is utilized in accordance with paragraph
(n)(10)(iii) of this section, the owner or operator shall, in the next
periodic report, identify the vessel, provide the information listed in
Sec.  61.272(a)(2) or (b)(4)(iii) of this chapter, and describe the
nature and date of the repair made or provide the date the storage
vessel was emptied.
    (v) Owners and operators of storage vessels complying with 40 CFR
part 61, subpart Y, may submit the inspection reports required by Sec.
61.275(a), (b)(1), and (d) of this chapter as part of the periodic
reports required by this subpart, rather than within the 60-day period
specified in Sec.  61.275(a), (b)(1), and (d) of this chapter.
    (vi) The reports of rim seal inspections specified in Sec.
61.275(d) of this chapter are not required if none of the measured gaps
or calculated gap areas exceed the limitations specified in Sec.
61.272(b)(4) of this chapter. Documentation of the inspections shall be
recorded as specified in Sec.  61.276(a) of this chapter.
    (vii) To be in compliance with Sec.  61.271(a)(6) or (b)(3) of this
chapter, guidepoles in floating roof storage vessels must be equipped
with covers and/or controls (e.g., pole float system, pole sleeve
system, internal sleeve system or flexible enclosure system) as
appropriate to comply with the ``no visible gap'' requirement.
    (viii) If a flare is used as a control device for a storage vessel,
on and after January 30, 2019, the owner or operator must meet the
requirements of Sec.  63.670 instead of the requirements referenced
from part 61, subpart Y of this chapter for that flare.
    (o) * * *
    (2) * * *
    (i) Comply with paragraphs (o)(2)(i)(A) through (D) of this
section.
* * * * *
    (D) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of 40 CFR part 61, subpart FF, and subpart G of this part, or the
requirements of Sec.  63.670.
    (ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this
section.
* * * * *
    (C) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of 40 CFR part 61, subpart FF, and subpart G of this part, or the
requirements of Sec.  63.670.
* * * * *
    (s) Overlap of this subpart with other regulation for flares. On
January 30, 2019, flares that are subject to the provisions of 40 CFR
60.18 or 63.11 and subject to this subpart are required to comply only
with the provisions specified in this subpart. Prior to January 30,
2019, flares that are subject to the provisions of 40 CFR 60.18 or
63.11 and elect to comply with the requirements in Sec. Sec.  63.670
and 63.671 are required to comply only with the provisions specified in
this subpart.
0
14. Section 63.641 is amended by:
0
a. Adding, in alphabetical order, definitions of ``Assist air,''
``Assist steam,'' ``Center steam,'' ``Closed blowdown system,''
``Combustion zone,'' ``Combustion zone gas,'' ``Decoking operations,''
``Delayed coking unit,'' ``Flare,'' ``Flare purge gas,'' ``Flare
supplemental gas,'' ``Flare sweep gas,'' ``Flare vent gas,'' ``Flexible
enclosure device,'' ``Force majeure event,'' ``Lower steam,'' ``Net
heating value,'' ``Perimeter assist air,'' ``Pilot gas,'' ``Premix
assist air,'' ``Regulated material,'' ``Thermal expansion relief
valve,'' ``Total steam,'' and ``Upper steam''; and
0
b. Revising the definitions of ``Delayed coker vent,'' ``Emission
point,'' ``Group 1 storage vessel,'' ``Miscellaneous process vent,''
``Periodically discharged,'' and ``Reference control technology for
storage vessels.''
    The revisions and additions read as follows:

Sec.  63.641  Definitions.

* * * * *
    Assist air means all air that intentionally is introduced prior to
or at

a flare tip through nozzles or other hardware conveyance for the
purposes including, but not limited to, protecting the design of the
flare tip, promoting turbulence for mixing or inducing air into the
flame. Assist air includes premix assist air and perimeter assist air.
Assist air does not include the surrounding ambient air.
    Assist steam means all steam that intentionally is introduced prior
to or at a flare tip through nozzles or other hardware conveyance for
the purposes including, but not limited to, protecting the design of
the flare tip, promoting turbulence for mixing or inducing air into the
flame. Assist steam includes, but is not necessarily limited to, center
steam, lower steam and upper steam.
* * * * *
    Center steam means the portion of assist steam introduced into the
stack of a flare to reduce burnback.
    Closed blowdown system means a system used for depressuring process
vessels that is not open to the atmosphere and is configured of piping,
ductwork, connections, accumulators/knockout drums, and, if necessary,
flow inducing devices that transport gas or vapor from process vessel
to a control device or back into the process.
* * * * *
    Combustion zone means the area of the flare flame where the
combustion zone gas combines for combustion.
    Combustion zone gas means all gases and vapors found just after a
flare tip. This gas includes all flare vent gas, total steam, and
premix air.
* * * * *
    Decoking operations means the sequence of steps conducted at the
end of the delayed coking unit's cooling cycle to open the coke drum to
the atmosphere in order to remove coke from the coke drum. Decoking
operations begin at the end of the cooling cycle when steam released
from the coke drum is no longer discharged via the unit's blowdown
system but instead is vented directly to the atmosphere. Decoking
operations include atmospheric depressuring (venting), deheading,
draining, and decoking (coke cutting).
    Delayed coker vent means a miscellaneous process vent that contains
uncondensed vapors from the delayed coking unit's blowdown system.
Venting from the delayed coker vent is typically intermittent in
nature, and occurs primarily during the cooling cycle of a delayed
coking unit coke drum when vapor from the coke drums cannot be sent to
the fractionator column for product recovery. The emissions from the
decoking operations, which include direct atmospheric venting,
deheading, draining, or decoking (coke cutting), are not considered to
be delayed coker vents.
    Delayed coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system
reactors. A delayed coking unit includes, but is not limited to, all of
the coke drums associated with a single fractionator; the fractionator,
including the bottoms receiver and the overhead condenser; the coke
drum cutting water and quench system, including the jet pump and coker
quench water tank; and the coke drum blowdown recovery compressor
system.
* * * * *
    Emission point means an individual miscellaneous process vent,
storage vessel, wastewater stream, equipment leak, decoking operation
or heat exchange system associated with a petroleum refining process
unit; an individual storage vessel or equipment leak associated with a
bulk gasoline terminal or pipeline breakout station classified under
Standard Industrial Classification code 2911; a gasoline loading rack
classified under Standard Industrial Classification code 2911; or a
marine tank vessel loading operation located at a petroleum refinery.
* * * * *
    Flare means a combustion device lacking an enclosed combustion
chamber that uses an uncontrolled volume of ambient air to burn gases.
For the purposes of this rule, the definition of flare includes, but is
not necessarily limited to, air-assisted flares, steam-assisted flares
and non-assisted flares.
    Flare purge gas means gas introduced between a flare header's water
seal and the flare tip to prevent oxygen infiltration (backflow) into
the flare tip. For a flare with no water seal, the function of flare
purge gas is performed by flare sweep gas and, therefore, by
definition, such a flare has no flare purge gas.
    Flare supplemental gas means all gas introduced to the flare in
order to improve the combustible characteristics of combustion zone
gas.
    Flare sweep gas means, for a flare with a flare gas recovery
system, the gas intentionally introduced into the flare header system
to maintain a constant flow of gas through the flare header in order to
prevent oxygen buildup in the flare header; flare sweep gas in these
flares is introduced prior to and recovered by the flare gas recovery
system. For a flare without a flare gas recovery system, flare sweep
gas means the gas intentionally introduced into the flare header system
to maintain a constant flow of gas through the flare header and out the
flare tip in order to prevent oxygen buildup in the flare header and to
prevent oxygen infiltration (backflow) into the flare tip.
    Flare vent gas means all gas found just prior to the flare tip.
This gas includes all flare waste gas (i.e., gas from facility
operations that is directed to a flare for the purpose of disposing of
the gas), that portion of flare sweep gas that is not recovered, flare
purge gas and flare supplemental gas, but does not include pilot gas,
total steam or assist air.
    Flexible enclosure device means a seal made of an elastomeric
fabric (or other material) which completely encloses a slotted
guidepole or ladder and eliminates the vapor emission pathway from
inside the storage vessel through the guidepole slots or ladder slots
to the outside air.
* * * * *
    Force majeure event means a release of HAP, either directly to the
atmosphere from a relief valve or discharged via a flare, that is
demonstrated to the satisfaction of the Administrator to result from an
event beyond the refinery owner or operator's control, such as natural
disasters; acts of war or terrorism; loss of a utility external to the
refinery (e.g., external power curtailment), excluding power
curtailment due to an interruptible service agreement; and fire or
explosion originating at a near or adjoining facility outside of the
refinery owner or operator's control that impacts the refinery's
ability to operate.
* * * * *
    Group 1 storage vessel means:
    (1) Prior to February 1, 2016:
    (i) A storage vessel at an existing source that has a design
capacity greater than or equal to 177 cubic meters and stored-liquid
maximum true vapor pressure greater than or equal to 10.4 kilopascals
and stored-liquid annual average true vapor pressure greater than or
equal to 8.3 kilopascals and annual average HAP liquid concentration
greater than 4 percent by weight total organic HAP;
    (ii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 151 cubic meters and stored-liquid
maximum true vapor pressure greater than or equal to 3.4 kilopascals
and annual average HAP liquid concentration greater than 2 percent by
weight total organic HAP; or
    (iii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 76 cubic meters and less than 151
cubic meters and stored-

liquid maximum true vapor pressure greater than or equal to 77
kilopascals and annual average HAP liquid concentration greater than 2
percent by weight total organic HAP.
    (2) On and after February 1, 2016:
    (i) A storage vessel at an existing source that has a design
capacity greater than or equal to 151 cubic meters (40,000 gallons) and
stored-liquid maximum true vapor pressure greater than or equal to 5.2
kilopascals (0.75 pounds per square inch) and annual average HAP liquid
concentration greater than 4 percent by weight total organic HAP;
    (ii) A storage vessel at an existing source that has a design
storage capacity greater than or equal to 76 cubic meters (20,000
gallons) and less than 151 cubic meters (40,000 gallons) and stored-
liquid maximum true vapor pressure greater than or equal to 13.1
kilopascals (1.9 pounds per square inch) and annual average HAP liquid
concentration greater than 4 percent by weight total organic HAP;
    (iii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 151 cubic meters (40,000 gallons) and
stored-liquid maximum true vapor pressure greater than or equal to 3.4
kilopascals (0.5 pounds per square inch) and annual average HAP liquid
concentration greater than 2 percent by weight total organic HAP; or
    (iv) A storage vessel at a new source that has a design storage
capacity greater than or equal to 76 cubic meters (20,000 gallons) and
less than 151 cubic meters (40,000 gallons) and stored-liquid maximum
true vapor pressure greater than or equal to 13.1 kilopascals (1.9
pounds per square inch) and annual average HAP liquid concentration
greater than 2 percent by weight total organic HAP.
* * * * *
    Lower steam means the portion of assist steam piped to an exterior
annular ring near the lower part of a flare tip, which then flows
through tubes to the flare tip, and ultimately exits the tubes at the
flare tip.
* * * * *
    Miscellaneous process vent means a gas stream containing greater
than 20 parts per million by volume organic HAP that is continuously or
periodically discharged from a petroleum refining process unit meeting
the criteria specified in Sec.  63.640(a). Miscellaneous process vents
include gas streams that are discharged directly to the atmosphere, gas
streams that are routed to a control device prior to discharge to the
atmosphere, or gas streams that are diverted through a product recovery
device prior to control or discharge to the atmosphere. Miscellaneous
process vents include vent streams from: Caustic wash accumulators,
distillation tower condensers/accumulators, flash/knockout drums,
reactor vessels, scrubber overheads, stripper overheads, vacuum pumps,
steam ejectors, hot wells, high point bleeds, wash tower overheads,
water wash accumulators, blowdown condensers/accumulators, and delayed
coker vents. Miscellaneous process vents do not include:
    (1) Gaseous streams routed to a fuel gas system, provided that on
and after January 30, 2019, any flares receiving gas from the fuel gas
system are in compliance with Sec.  63.670;
    (2) Pressure relief device discharges;
    (3) Leaks from equipment regulated under Sec.  63.648;
    (4) [Reserved]
    (5) In situ sampling systems (onstream analyzers) until January 30,
2019. After this date, these sampling systems will be included in the
definition of miscellaneous process vents;
    (6) Catalytic cracking unit catalyst regeneration vents;
    (7) Catalytic reformer regeneration vents;
    (8) Sulfur plant vents;
    (9) Vents from control devices such as scrubbers, boilers,
incinerators, and electrostatic precipitators applied to catalytic
cracking unit catalyst regeneration vents, catalytic reformer
regeneration vents, and sulfur plant vents;
    (10) Vents from any stripping operations applied to comply with the
wastewater provisions of this subpart, subpart G of this part, or 40
CFR part 61, subpart FF;
    (11) Emissions associated with delayed coking unit decoking
operations;
    (12) Vents from storage vessels;
    (13) Emissions from wastewater collection and conveyance systems
including, but not limited to, wastewater drains, sewer vents, and sump
drains; and
    (14) Hydrogen production plant vents through which carbon dioxide
is removed from process streams or through which steam condensate
produced or treated within the hydrogen plant is degassed or deaerated.
    Net heating value means the energy released as heat when a compound
undergoes complete combustion with oxygen to form gaseous carbon
dioxide and gaseous water (also referred to as lower heating value).
* * * * *
    Perimeter assist air means the portion of assist air introduced at
the perimeter of the flare tip or above the flare tip. Perimeter assist
air includes air intentionally entrained in lower and upper steam.
Perimeter assist air includes all assist air except premix assist air.
    Periodically discharged means discharges that are intermittent and
associated with routine operations, maintenance activities, startups,
shutdowns, malfunctions, or process upsets.
* * * * *
    Pilot gas means gas introduced into a flare tip that provides a
flame to ignite the flare vent gas.
* * * * *
    Premix assist air means the portion of assist air that is
introduced to the flare vent gas, whether injected or induced, prior to
the flare tip. Premix assist air also includes any air intentionally
entrained in center steam.
* * * * *
    Reference control technology for storage vessels means either:
    (1) For Group 1 storage vessels complying with Sec.  63.660:
    (i) An internal floating roof, including an external floating roof
converted to an internal floating roof, meeting the specifications of
Sec.  63.1063(a)(1)(i) and (b);
    (ii) An external floating roof meeting the specifications of Sec.
63.1063(a)(1)(ii), (a)(2), and (b); or
    (iii) [Reserved]
    (iv) A closed-vent system to a control device that reduces organic
HAP emissions by 95 percent, or to an outlet concentration of 20 parts
per million by volume (ppmv).
    (v) For purposes of emissions averaging, these four technologies
are considered equivalent.
    (2) For all other storage vessels:
    (i) An internal floating roof meeting the specifications of Sec.
63.119(b) of subpart G except for Sec.  63.119(b)(5) and (6);
    (ii) An external floating roof meeting the specifications of Sec.
63.119(c) of subpart G except for Sec.  63.119(c)(2);
    (iii) An external floating roof converted to an internal floating
roof meeting the specifications of Sec.  63.119(d) of subpart G except
for Sec.  63.119(d)(2); or
    (iv) A closed-vent system to a control device that reduces organic
HAP emissions by 95 percent, or to an outlet concentration of 20 parts
per million by volume.
    (v) For purposes of emissions averaging, these four technologies
are considered equivalent.
* * * * *
    Regulated material means any stream associated with emission
sources listed

in Sec.  63.640(c) required to meet control requirements under this
subpart as well as any stream for which this subpart or a cross-
referencing subpart specifies that the requirements for flare control
devices in Sec.  63.670 must be met.
* * * * *
    Thermal expansion relief valve means a pressure relief valve
designed to protect equipment from excess pressure due to thermal
expansion of blocked liquid-filled equipment or piping due to ambient
heating or heat from a heat tracing system. Pressure relief valves
designed to protect equipment from excess pressure due to blockage
against a pump or compressor or due to fire contingency are not thermal
expansion relief valves.
* * * * *
    Total steam means the total of all steam that is supplied to a
flare and includes, but is not limited to, lower steam, center steam
and upper steam.
    Upper steam means the portion of assist steam introduced via
nozzles located on the exterior perimeter of the upper end of the flare
tip.
* * * * *

0
15. Section 63.642 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraphs (d)(3), (e), (i), (k) introductory text, (k)(1),
(l) introductory text, and (l)(2); and
0
c. Adding paragraph (n).
    The revisions and additions read as follows:

Sec.  63.642  General standards.

* * * * *
    (b) The emission standards set forth in this subpart shall apply at
all times.
* * * * *
    (d) * * *
    (3) Performance tests shall be conducted according to the
provisions of Sec.  63.7(e) except that performance tests shall be
conducted at maximum representative operating capacity for the process.
During the performance test, an owner or operator shall operate the
control device at either maximum or minimum representative operating
conditions for monitored control device parameters, whichever results
in lower emission reduction. An owner or operator shall not conduct a
performance test during startup, shutdown, periods when the control
device is bypassed or periods when the process, monitoring equipment or
control device is not operating properly. The owner/operator may not
conduct performance tests during periods of malfunction. The owner or
operator must record the process information that is necessary to
document operating conditions during the test and include in such
record an explanation to support that the test was conducted at maximum
representative operating capacity. Upon request, the owner or operator
shall make available to the Administrator such records as may be
necessary to determine the conditions of performance tests.
* * * * *
    (e) All applicable records shall be maintained as specified in
Sec.  63.655(i).
* * * * *
    (i) The owner or operator of an existing source shall demonstrate
compliance with the emission standard in paragraph (g) of this section
by following the procedures specified in paragraph (k) of this section
for all emission points, or by following the emissions averaging
compliance approach specified in paragraph (l) of this section for
specified emission points and the procedures specified in paragraph
(k)(1) of this section.
* * * * *
    (k) The owner or operator of an existing source may comply, and the
owner or operator of a new source shall comply, with the applicable
provisions in Sec. Sec.  63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as specified in Sec.  63.640(h).
    (1) The owner or operator using this compliance approach shall also
comply with the requirements of Sec. Sec.  63.648 and/or 63.649,
63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable.
* * * * *
    (l) The owner or operator of an existing source may elect to
control some of the emission points within the source to different
levels than specified under Sec. Sec.  63.643 through 63.645, 63.646 or
63.660, 63.647, 63.650, and 63.651, as applicable according to Sec.
63.640(h), by using an emissions averaging compliance approach as long
as the overall emissions for the source do not exceed the emission
level specified in paragraph (g) of this section. The owner or operator
using emissions averaging shall meet the requirements in paragraphs
(l)(1) and (2) of this section.
* * * * *
    (2) Comply with the requirements of Sec. Sec.  63.648 and/or
63.649, 63.654, 63.652, 63.653, 63.655, 63.657, 63.658, 63.670 and
63.671, as applicable.
* * * * *
    (n) At all times, the owner or operator must operate and maintain
any affected source, including associated air pollution control
equipment and monitoring equipment, in a manner consistent with safety
and good air pollution control practices for minimizing emissions. The
general duty to minimize emissions does not require the owner operator
to make any further efforts to reduce emissions if levels required by
the applicable standard have been achieved. Determination of whether a
source is operating in compliance with operation and maintenance
requirements will be based on information available to the
Administrator which may include, but is not limited to, monitoring
results, review of operation and maintenance procedures, review of
operation and maintenance records, and inspection of the source.

0
16. Section 63.643 is amended by revising paragraphs (a) introductory
text and (a)(1) and adding paragraph (c) to read as follows:

Sec.  63.643  Miscellaneous process vent provisions.

    (a) The owner or operator of a Group 1 miscellaneous process vent
as defined in Sec.  63.641 shall comply with the requirements of either
paragraph (a)(1) or (2) of this section or, if applicable, paragraph
(c) of this section. The owner or operator of a miscellaneous process
vent that meets the conditions in paragraph (c) of this section is only
required to comply with the requirements of paragraph (c) of this
section and Sec.  63.655(g)(13) and (i)(12) for that vent.
    (1) Reduce emissions of organic HAP's using a flare. On and after
January 30, 2019, the flare shall meet the requirements of Sec.
63.670. Prior to January 30, 2019, the flare shall meet the
requirements of Sec.  63.11(b) of subpart A or the requirements of
Sec.  63.670.
* * * * *
    (c) An owner or operator may designate a process vent as a
maintenance vent if the vent is only used as a result of startup,
shutdown, maintenance, or inspection of equipment where equipment is
emptied, depressurized, degassed or placed into service. The owner of
operator does not need to designate a maintenance vent as a Group 1 or
Group 2 miscellaneous process vent. The owner or operator must comply
with the applicable requirements in paragraphs (c)(1) through (3) of
this section for each maintenance vent.
    (1) Prior to venting to the atmosphere, process liquids are removed
from the equipment as much as practical and the equipment is
depressured to a control device, fuel gas system, or back to the
process until one of the following conditions, as applicable, is met.
    (i) The vapor in the equipment served by the maintenance vent has a
lower

explosive limit (LEL) of less than 10 percent.
    (ii) If there is no ability to measure the LEL of the vapor in the
equipment based on the design of the equipment, the pressure in the
equipment served by the maintenance vent is reduced to 5 psig or less.
Upon opening the maintenance vent, active purging of the equipment
cannot be used until the LEL of the vapors in the maintenance vent (or
inside the equipment if the maintenance is a hatch or similar type of
opening) equipment is less than 10 percent.
    (iii) The equipment served by the maintenance vent contains less
than 72 pounds of VOC.
    (iv) If the maintenance vent is associated with equipment
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers)
at refineries that do not have a pure hydrogen supply, the LEL of the
vapor in the equipment must be less than 20 percent, except for one
event per year not to exceed 35 percent.
    (2) Except for maintenance vents complying with the alternative in
paragraph (c)(1)(iii) of this section, the owner or operator must
determine the LEL or, if applicable, equipment pressure using process
instrumentation or portable measurement devices and follow procedures
for calibration and maintenance according to manufacturer's
specifications.
    (3) For maintenance vents complying with the alternative in
paragraph (c)(1)(iii) of this section, the owner or operator shall
determine mass of VOC in the equipment served by the maintenance vent
based on the equipment size and contents after considering any contents
drained or purged from the equipment. Equipment size may be determined
from equipment design specifications. Equipment contents may be
determined using process knowledge.

0
17. Section 63.644 is amended by revising paragraphs (a) introductory
text, (a)(2), and (c) to read as follows:

Sec.  63.644  Monitoring provisions for miscellaneous process vents.

    (a) Except as provided in paragraph (b) of this section, each owner
or operator of a Group 1 miscellaneous process vent that uses a
combustion device to comply with the requirements in Sec.  63.643(a)
shall install the monitoring equipment specified in paragraph (a)(1),
(2), (3), or (4) of this section, depending on the type of combustion
device used. All monitoring equipment shall be installed, calibrated,
maintained, and operated according to manufacturer's specifications or
other written procedures that provide adequate assurance that the
equipment will monitor accurately and, except for CPMS installed for
pilot flame monitoring, must meet the applicable minimum accuracy,
calibration and quality control requirements specified in table 13 of
this subpart.
* * * * *
    (2) Where a flare is used prior to January 30, 2019, a device
(including but not limited to a thermocouple, an ultraviolet beam
sensor, or an infrared sensor) capable of continuously detecting the
presence of a pilot flame is required, or the requirements of Sec.
63.670 shall be met. Where a flare is used on and after January 30,
2019, the requirements of Sec.  63.670 shall be met.
* * * * *
    (c) The owner or operator of a Group 1 miscellaneous process vent
using a vent system that contains bypass lines that could divert a vent
stream away from the control device used to comply with paragraph (a)
of this section either directly to the atmosphere or to a control
device that does not comply with the requirements in Sec.  63.643(a)
shall comply with either paragraph (c)(1) or (2) of this section. Use
of the bypass at any time to divert a Group 1 miscellaneous process
vent stream to the atmosphere or to a control device that does not
comply with the requirements in Sec.  63.643(a) is an emissions
standards violation. Equipment such as low leg drains and equipment
subject to Sec.  63.648 are not subject to this paragraph (c).
    (1) Install, calibrate and maintain a flow indicator that
determines whether a vent stream flow is present at least once every
hour. A manual block valve equipped with a valve position indicator may
be used in lieu of a flow indicator, as long as the valve position
indicator is monitored continuously. Records shall be generated as
specified in Sec.  63.655(h) and (i). The flow indicator shall be
installed at the entrance to any bypass line that could divert the vent
stream away from the control device to the atmosphere; or
    (2) Secure the bypass line valve in the non-diverting position with
a car-seal or a lock-and-key type configuration. A visual inspection of
the seal or closure mechanism shall be performed at least once every
month to ensure that the valve is maintained in the non-diverting
position and that the vent stream is not diverted through the bypass
line.
* * * * *

0
18. Section 63.645 is amended by revising paragraphs (e)(1) and (f)(2)
to read as follows:

Sec.  63.645  Test methods and procedures for miscellaneous process
vents.

* * * * *
    (e) * * *
    (1) Methods 1 or 1A of 40 CFR part 60, appendix A-1, as
appropriate, shall be used for selection of the sampling site. For
vents smaller than 0.10 meter in diameter, sample at the center of the
vent.
* * * * *
    (f) * * *
    (2) The gas volumetric flow rate shall be determined using Methods
2, 2A, 2C, 2D, or 2F of 40 CFR part 60, appendix A-1 or Method 2G of 40
CFR part 60, appendix A-2, as appropriate.
* * * * *

0
19. Section 63.646 is amended by adding introductory text and revising
paragraph (b)(2) to read as follows:

Sec.  63.646  Storage vessel provisions.

    Upon a demonstration of compliance with the standards in Sec.
63.660 by the compliance dates specified in Sec.  63.640(h), the
standards in this section shall no longer apply.
* * * * *
    (b) * * *
    (2) When an owner or operator and the Administrator do not agree on
whether the annual average weight percent organic HAP in the stored
liquid is above or below 4 percent for a storage vessel at an existing
source or above or below 2 percent for a storage vessel at a new
source, an appropriate method (based on the type of liquid stored) as
published by EPA or a consensus-based standards organization shall be
used. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute
(ANSI, 1819 L Street NW., 6th floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400
North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, http://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990,<PHONE_NUMBER>,
http://www.asme.org), the American Petroleum Institute (API, 1220 L
Street NW., Washington, DC 20005-4070,<PHONE_NUMBER>, http://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002,<PHONE_NUMBER>, http://www.naesb.org).
* * * * *

0
20. Section 63.647 is amended by:
0
a. Revising paragraph (a);
0
b. Redesignating paragraph (c) as paragraph (d); and
0
c. Adding paragraph (c).
    The revisions and additions read as follows:

Sec.  63.647  Wastewater provisions.

    (a) Except as provided in paragraphs (b) and (c) of this section,
each owner or operator of a Group 1 wastewater stream shall comply with
the requirements of Sec. Sec.  61.340 through 61.355 of this chapter
for each process wastewater stream that meets the definition in Sec.
63.641.
* * * * *
    (c) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of part 61, subpart FF of this chapter, or the requirements of Sec.
63.670.
* * * * *

0
21. Section 63.648 is amended by:
0
a. Adding paragraph (a)(3);
0
b. Revising paragraph (c) introductory text; and
0
c. Adding paragraphs (c)(11) and (12) and (j).
    The revisions and additions read as follows:

Sec.  63.648  Equipment leak standards.

    (a) * * *
    (3) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of part 60, subpart VV of this chapter, or the requirements of Sec.
63.670.
* * * * *
    (c) In lieu of complying with the existing source provisions of
paragraph (a) in this section, an owner or operator may elect to comply
with the requirements of Sec. Sec.  63.161 through 63.169, 63.171,
63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except
as provided in paragraphs (c)(1) through (12) and (e) through (i) of
this section.
* * * * *
    (11) [Reserved]
    (12) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of Sec. Sec.  63.172 and 63.180, or the requirements of Sec.  63.670.
* * * * *
    (j) Except as specified in paragraph (j)(4) of this section, the
owner or operator must comply with the requirements specified in
paragraphs (j)(1) and (2) of this section for pressure relief devices,
such as relief valves or rupture disks, in organic HAP gas or vapor
service instead of the pressure relief device requirements of Sec.
60.482-4 or Sec.  63.165, as applicable. Except as specified in
paragraphs (j)(4) and (5) of this section, the owner or operator must
also comply with the requirements specified in paragraph (j)(3) of this
section for all pressure relief devices.
    (1) Operating requirements. Except during a pressure release,
operate each pressure relief device in organic HAP gas or vapor service
with an instrument reading of less than 500 ppm above background as
detected by Method 21 of 40 CFR part 60, appendix A-7.
    (2) Pressure release requirements. For pressure relief devices in
organic HAP gas or vapor service, the owner or operator must comply
with the applicable requirements in paragraphs (j)(2)(i) through (iii)
of this section following a pressure release.
    (i) If the pressure relief device does not consist of or include a
rupture disk, conduct instrument monitoring, as specified in Sec.
60.485(b) or Sec.  63.180(c), as applicable, no later than 5 calendar
days after the pressure relief device returns to organic HAP gas or
vapor service following a pressure release to verify that the pressure
relief device is operating with an instrument reading of less than 500
ppm.
    (ii) If the pressure relief device includes a rupture disk, either
comply with the requirements in paragraph (j)(2)(i) of this section
(not replacing the rupture disk) or install a replacement disk as soon
as practicable after a pressure release, but no later than 5 calendar
days after the pressure release. The owner or operator must conduct
instrument monitoring, as specified in Sec.  60.485(b) or Sec.
63.180(c), as applicable, no later than 5 calendar days after the
pressure relief device returns to organic HAP gas or vapor service
following a pressure release to verify that the pressure relief device
is operating with an instrument reading of less than 500 ppm.
    (iii) If the pressure relief device consists only of a rupture
disk, install a replacement disk as soon as practicable after a
pressure release, but no later than 5 calendar days after the pressure
release. The owner or operator may not initiate startup of the
equipment served by the rupture disk until the rupture disc is
replaced. The owner or operator must conduct instrument monitoring, as
specified in Sec.  60.485(b) or Sec.  63.180(c), as applicable, no
later than 5 calendar days after the pressure relief device returns to
organic HAP gas or vapor service following a pressure release to verify
that the pressure relief device is operating with an instrument reading
of less than 500 ppm.
    (3) Pressure release management. Except as specified in paragraphs
(j)(4) and (5) of this section, the owner or operator shall comply with
the requirements specified in paragraphs (j)(3)(i) through (v) of this
section for all pressure relief devices in organic HAP service no later
than January 30, 2019.
    (i) The owner or operator must equip each affected pressure relief
device with a device(s) or use a monitoring system that is capable of:
    (A) Identifying the pressure release;
    (B) Recording the time and duration of each pressure release; and
    (C) Notifying operators immediately that a pressure release is
occurring. The device or monitoring system may be either specific to
the pressure relief device itself or may be associated with the process
system or piping, sufficient to indicate a pressure release to the
atmosphere. Examples of these types of devices and systems include, but
are not limited to, a rupture disk indicator, magnetic sensor, motion
detector on the pressure relief valve stem, flow monitor, or pressure
monitor.
    (ii) The owner or operator must apply at least three redundant
prevention measures to each affected pressure relief device and
document these measures. Examples of prevention measures include:
    (A) Flow, temperature, level and pressure indicators with deadman
switches, monitors, or automatic actuators.
    (B) Documented routine inspection and maintenance programs and/or
operator training (maintenance programs and operator training may count
as only one redundant prevention measure).
    (C) Inherently safer designs or safety instrumentation systems.
    (D) Deluge systems.
    (E) Staged relief system where initial pressure relief valve (with
lower set release pressure) discharges to a flare or other closed vent
system and control device.
    (iii) If any affected pressure relief device releases to atmosphere
as a result of a pressure release event, the owner or operator must
perform root cause analysis and corrective action analysis according to
the requirement in paragraph (j)(6) of this section and implement
corrective actions according to the requirements in paragraph (j)(7) of
this section. The owner or operator must also calculate the quantity of
organic HAP released during each pressure

release event and report this quantity as required in Sec.
63.655(g)(10)(iii). Calculations may be based on data from the pressure
relief device monitoring alone or in combination with process parameter
monitoring data and process knowledge.
    (iv) The owner or operator shall determine the total number of
release events occurred during the calendar year for each affected
pressure relief device separately. The owner or operator shall also
determine the total number of release events for each pressure relief
device for which the root cause analysis concluded that the root cause
was a force majeureevent, as defined in this subpart.
    (v) Except for pressure relief devices described in paragraphs
(j)(4) and (5) of this section, the following release events are a
violation of the pressure release management work practice standards.
    (A) Any release event for which the root cause of the event was
determined to be operator error or poor maintenance.
    (B) A second release event not including force majeure events from
a single pressure relief device in a 3 calendar year period for the
same root cause for the same equipment.
    (C) A third release event not including force majeure events from a
single pressure relief device in a 3 calendar year period for any
reason.
    (4) Pressure relief devices routed to a control device. If all
releases and potential leaks from a pressure relief device are routed
through a closed vent system to a control device, back into the process
or to the fuel gas system, the owner or operator is not required to
comply with paragraph (j)(1), (2), or (3) (if applicable) of this
section. Both the closed vent system and control device (if applicable)
must meet the requirements of Sec.  63.644. When complying with this
paragraph (j)(4), all references to ``Group 1 miscellaneous process
vent'' in Sec.  63.644 mean ``pressure relief device.'' If a pressure
relief device complying with this paragraph (j)(4) is routed to the
fuel gas system, then on and after January 30, 2019, any flares
receiving gas from that fuel gas system must be in compliance with
Sec.  63.670.
    (5) Pressure relief devices exempted from pressure release
management requirements. The following types of pressure relief devices
are not subject to the pressure release management requirements in
paragraph (j)(3) of this section.
    (i) Pressure relief devices in heavy liquid service, as defined in
Sec.  63.641.
    (ii) Pressure relief devices that only release material that is
liquid at standard conditions (1 atmosphere and 68 degrees Fahrenheit)
and that are hard-piped to a controlled drain system (i.e., a drain
system meeting the requirements for Group 1 wastewater streams in Sec.
63.647(a)) or piped back to the process or pipeline.
    (iii) Thermal expansion relief valves.
    (iv) Pressure relief devices designed with a set relief pressure of
less than 2.5 psig.
    (v) Pressure relief devices that do not have the potential to emit
72 lbs/day or more of VOC based on the valve diameter, the set release
pressure, and the equipment contents.
    (vi) Pressure relief devices on mobile equipment.
    (6) Root cause analysis and corrective action analysis. A root
cause analysis and corrective action analysis must be completed as soon
as possible, but no later than 45 days after a release event. Special
circumstances affecting the number of root cause analyses and/or
corrective action analyses are provided in paragraphs (j)(6)(i) through
(iv) of this section.
    (i) You may conduct a single root cause analysis and corrective
action analysis for a single emergency event that causes two or more
pressure relief devices installed on the same equipment to release.
    (ii) You may conduct a single root cause analysis and corrective
action analysis for a single emergency event that causes two or more
pressure relief devices to release, regardless of the equipment served,
if the root cause is reasonably expected to be a force majeure event,
as defined in this subpart.
    (iii) Except as provided in paragraphs (j)(6)(i) and (ii) of this
section, if more than one pressure relief device has a release during
the same time period, an initial root cause analysis shall be conducted
separately for each pressure relief device that had a release. If the
initial root cause analysis indicates that the release events have the
same root cause(s), the initially separate root cause analyses may be
recorded as a single root cause analysis and a single corrective action
analysis may be conducted.
    (7) Corrective action implementation. Each owner or operator
required to conduct a root cause analysis and corrective action
analysis as specified in paragraphs (j)(3)(iii) and (j)(6) of this
section shall implement the corrective action(s) identified in the
corrective action analysis in accordance with the applicable
requirements in paragraphs (j)(7)(i) through (iii) of this section.
    (i) All corrective action(s) must be implemented within 45 days of
the event for which the root cause and corrective action analyses were
required or as soon thereafter as practicable. If an owner or operator
concludes that no corrective action should be implemented, the owner or
operator shall record and explain the basis for that conclusion no
later than 45 days following the event.
    (ii) For corrective actions that cannot be fully implemented within
45 days following the event for which the root cause and corrective
action analyses were required, the owner or operator shall develop an
implementation schedule to complete the corrective action(s) as soon as
practicable.
    (iii) No later than 45 days following the event for which a root
cause and corrective action analyses were required, the owner or
operator shall record the corrective action(s) completed to date, and,
for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates.

0
22. Section 63.649 is amended by revising definition of Cc
term in the equation in paragraph (c)(6)(i) to read as follows:

Sec.  63.649  Alternative means of emission limitation: Connectors in
gas/vapor service and light liquid service.

* * * * *
    (c) * * *
    (6) * * *
    (i) * * *

Cc = Optional credit for removed connectors = 0.67 x net
number (i.e., the total number of connectors removed minus the total
added) of connectors in organic HAP service removed from the process
unit after the applicability date set forth in Sec.
63.640(h)(3)(iii) for existing process units, and after the date of
start-up for new process units. If credits are not taken, then
Cc = 0.

* * * * *

0
23. Section 63.650 is amended by revising paragraph (a) and adding
paragraph (d) to read as follows:

Sec.  63.650  Gasoline loading rack provisions.

    (a) Except as provided in paragraphs (b) through (d) of this
section, each owner or operator of a Group 1 gasoline loading rack
classified under Standard Industrial Classification code 2911 located
within a contiguous area and under common control with a petroleum
refinery shall comply with subpart R of this part, Sec. Sec.  63.421,
63.422(a) through (c) and (e), 63.425(a) through (c) and (e) through
(i), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3),
and (k).
* * * * *

    (d) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of subpart R of this part, or the requirements of Sec.  63.670.

0
24. Section 63.651 is amended by revising paragraphs (a) and (d) and
adding paragraph (e) to read as follows:

Sec.  63.651  Marine tank vessel loading operation provisions.

    (a) Except as provided in paragraphs (b) through (e) of this
section, each owner or operator of a marine tank vessel loading
operation located at a petroleum refinery shall comply with the
requirements of Sec. Sec.  63.560 through 63.568.
* * * * *
    (d) The compliance time of 4 years after promulgation of 40 CFR
part 63, subpart Y, does not apply. The compliance time is specified in
Sec.  63.640(h)(1).
    (e) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of subpart Y of this part, or the requirements of Sec.  63.670.

0
25. Section 63.652 is amended by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (f)(2); and
0
c. Revising paragraphs (g)(2)(iii)(B)(1), (h)(3), (k) introductory
text, and (k)(3).
    The revisions and additions read as follows:

Sec.  63.652  Emissions averaging provisions.

    (a) This section applies to owners or operators of existing sources
who seek to comply with the emission standard in Sec.  63.642(g) by
using emissions averaging according to Sec.  63.642(l) rather than
following the provisions of Sec. Sec.  63.643 through 63.645, 63.646 or
63.660, 63.647, 63.650, and 63.651. Existing marine tank vessel loading
operations located at the Valdez Marine Terminal source may not comply
with the standard by using emissions averaging.
* * * * *
    (g) * * *
    (2) * * *
    (iii) * * *
    (B) * * *
    (1) The percent reduction shall be measured according to the
procedures in Sec.  63.116 of subpart G if a combustion control device
is used. For a flare meeting the criteria in Sec.  63.116(a) of subpart
G or Sec.  63.670, as applicable, or a boiler or process heater meeting
the criteria in Sec.  63.645(d) or Sec.  63.116(b) of subpart G, the
percentage of reduction shall be 98 percent. If a noncombustion control
device is used, percentage of reduction shall be demonstrated by a
performance test at the inlet and outlet of the device, or, if testing
is not feasible, by a control design evaluation and documented
engineering calculations.
* * * * *
    (h) * * *
    (3) Emissions from storage vessels shall be determined as specified
in Sec.  63.150(h)(3) of subpart G, except as follows:
    (i) For storage vessels complying with Sec.  63.646:
    (A) All references to Sec.  63.119(b) in Sec.  63.150(h)(3) of
subpart G shall be replaced with: Sec.  63.119(b) or Sec.  63.119(b)
except for Sec.  63.119(b)(5) and (6).
    (B) All references to Sec.  63.119(c) in Sec.  63.150(h)(3) of
subpart G shall be replaced with: Sec.  63.119(c) or Sec.  63.119(c)
except for Sec.  63.119(c)(2).
    (C) All references to Sec.  63.119(d) in Sec.  63.150(h)(3) of
subpart G shall be replaced with: Sec.  63.119(d) or Sec.  63.119(d)
except for Sec.  63.119(d)(2).
    (ii) For storage vessels complying with Sec.  63.660:
    (A) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.
63.1063(a)(1)(i) and (b) shall apply instead of Sec.  63.119(b) in
Sec.  63.150(h)(3) of subpart G.
    (B) Section 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead
of Sec.  63.119(c) in Sec.  63.150(h)(3) of subpart G.
    (C) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.
63.1063(a)(1)(i) and (b) shall apply instead of Sec.  63.119(d) in
Sec.  63.150(h)(3) of subpart G.
* * * * *
    (k) The owner or operator shall demonstrate that the emissions from
the emission points proposed to be included in the average will not
result in greater hazard or, at the option of the State or local
permitting authority, greater risk to human health or the environment
than if the emission points were controlled according to the provisions
in Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650,
and 63.651, as applicable.
* * * * *
    (3) An emissions averaging plan that does not demonstrate an
equivalent or lower hazard or risk to the satisfaction of the State or
local permitting authority shall not be approved. The State or local
permitting authority may require such adjustments to the emissions
averaging plan as are necessary in order to ensure that the average
will not result in greater hazard or risk to human health or the
environment than would result if the emission points were controlled
according to Sec. Sec.  63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as applicable.
* * * * *

0
26. Section 63.653 is amended by revising paragraphs (a) introductory
text, (a)(3)(i) and (ii), and (a)(7) to read as follows:

Sec.  63.653  Monitoring, recordkeeping, and implementation plan for
emissions averaging.

    (a) For each emission point included in an emissions average, the
owner or operator shall perform testing, monitoring, recordkeeping, and
reporting equivalent to that required for Group 1 emission points
complying with Sec. Sec.  63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as applicable. The specific requirements
for miscellaneous process vents, storage vessels, wastewater, gasoline
loading racks, and marine tank vessels are identified in paragraphs
(a)(1) through (7) of this section.
* * * * *
    (3) * * *
    (i) Perform the monitoring or inspection procedures in Sec.  63.646
and either Sec.  63.120 of subpart G or Sec.  63.1063 of subpart WW, as
applicable; and
    (ii) For closed vent systems with control devices, conduct an
initial design evaluation as specified in Sec.  63.646 and either Sec.
63.120(d) of subpart G or Sec.  63.985(b) of subpart SS, as applicable.
* * * * *
    (7) If an emission point in an emissions average is controlled
using a pollution prevention measure or a device or technique for which
no monitoring parameters or inspection procedures are specified in
Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and
63.651, as applicable, the owner or operator shall establish a site-
specific monitoring parameter and shall submit the information
specified in Sec.  63.655(h)(4) in the Implementation Plan.
* * * * *

0
27. Section 63.655 is amended by:
0
a. Revising paragraphs (f) introductory text, (f)(1) introductory text,
(f)(1)(i)(A) introductory text, (f)(1)(i)(A)(2) and (3), (f)(1)(i)(B)
introductory text, (f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv)
introductory text, and (f)(1)(iv)(A);
0
b. Adding paragraphs (f)(1)(vii) and (viii);
0
c. Revising paragraphs (f)(2) introductory text, (f)(3) introductory
text, the first sentence of (f)(6), (g) introductory text, (g)(1)
through (5), (g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i);

0
d. Adding paragraphs (g)(10) through (14);
0
e. Removing and reserving paragraph (h)(1);
0
f. Revising paragraphs (h)(2) introductory text, (h)(2)(i)(B),
(h)(2)(ii), and (h)(5)(iii);
0
g. Adding paragraphs (h)(8) and (9) and (i) introductory text;
0
h. Revising paragraph (i)(1) introductory text and paragraph
(i)(1)(ii);
0
i. Adding paragraphs (i)(1)(v) and (vi);
0
j. Redesignating paragraphs (i)(4) and (5) as paragraphs (i)(5) and
(6), respectively;
0
k. Adding paragraph (i)(4);
0
l. Revising newly redesignated paragraph (i)(5) introductory text; and
0
m. Adding paragraphs (i)(7) through (12).
    The revisions and additions read as follows:

Sec.  63.655  Reporting and recordkeeping requirements.

* * * * *
    (f) Each owner or operator of a source subject to this subpart
shall submit a Notification of Compliance Status report within 150 days
after the compliance dates specified in Sec.  63.640(h) with the
exception of Notification of Compliance Status reports submitted to
comply with Sec.  63.640(l)(3) and for storage vessels subject to the
compliance schedule specified in Sec.  63.640(h)(2). Notification of
Compliance Status reports required by Sec.  63.640(l)(3) and for
storage vessels subject to the compliance dates specified in Sec.
63.640(h)(2) shall be submitted according to paragraph (f)(6) of this
section. This information may be submitted in an operating permit
application, in an amendment to an operating permit application, in a
separate submittal, or in any combination of the three. If the required
information has been submitted before the date 150 days after the
compliance date specified in Sec.  63.640(h), a separate Notification
of Compliance Status report is not required within 150 days after the
compliance dates specified in Sec.  63.640(h). If an owner or operator
submits the information specified in paragraphs (f)(1) through (5) of
this section at different times, and/or in different submittals, later
submittals may refer to earlier submittals instead of duplicating and
resubmitting the previously submitted information. Each owner or
operator of a gasoline loading rack classified under Standard
Industrial Classification Code 2911 located within a contiguous area
and under common control with a petroleum refinery subject to the
standards of this subpart shall submit the Notification of Compliance
Status report required by subpart R of this part within 150 days after
the compliance dates specified in Sec.  63.640(h).
    (1) The Notification of Compliance Status report shall include the
information specified in paragraphs (f)(1)(i) through (viii) of this
section.
    (i) * * *
    (A) Identification of each storage vessel subject to this subpart,