| (ii) only piping and fugitive components handling liquids
or gas up to a maximum of 25 valves, 25 open-ended lines, any combination
of connectors and flanges up to 2,000 components, and 25 component
types otherwise not specified;
(iii) only piping and fugitive components handling
liquids or gas up to a maximum of four pump seals; four open-ended
lines; and any combination of valves, flanges, and connectors up to
225 components; or
(iv) separators used solely to separate crude oil,
condensate, and natural gas (which are routed directly to a sales
pipeline) from produced water. Tanks used and handling only produced
water up to 1,205 barrels per day. All associated piping and fugitive
components up to a maximum of five pump seals; five open-ended lines;
and any combination of valves, flanges, and connectors totaling 150
components in VOC service and 500 components in water service; or
(v) separators used solely to separate crude oil, condensate,
and natural gas (which are routed directly to a sales pipeline) from
produced water. Tanks used and handling only produced water up to
580 barrels per day. All associated piping and fugitive components
up to a maximum of two pump seals; two open-ended lines; and any combination
of valves, flanges, and connectors totaling 230 components in VOC
service and 500 components in water service.
(d) Facilities and Exclusions.
(1) Only the following specific facilities and groups
of facilities have been evaluated for this PBR, along with supporting
infrastructure equipment and facilities, and may be included in a
registration for this section:
(A) fugitive components, including valves, pressure
relief valves, pipe flanges and connectors, pumps, compressors, stuffing
boxes, instrumentation and meters, natural gas driven pneumatic pumps,
and other similar devices with seals that separate process and waste
material from the atmosphere and the associated piping;
(B) separators, including all gas, oil, and water physical
separation units;
(C) treatment and processing equipment, including heater-treaters,
methanol injection, glycol dehydrators, molecular or mole sieves,
amine sweeteners, H2 S scavenger chemical
reaction vessels for sulfur removal, and iron sponge units;
(D) cooling towers and associated heat exchangers;
(E) gas recovery units, including cryogenic expansion,
absorption, adsorption, heat exchangers and refrigeration units;
(F) combustion units, including engines, turbines,
boilers, reboilers, and heaters;
(G) storage tanks for crude oil, condensate, produced
water, fuels, treatment chemicals, slop and sump oils, and pressure
tanks with liquefied petroleum gases;
(H) surface support facilities associated with underground
storage of gas or liquids;
(I) truck loading equipment;
(J) control equipment, including vapor recovery systems,
glycol and amine reboilers, condensers, flares, vapor combustors,
and thermal oxidizers; and
(K) temporary facilities used for planned maintenance,
and temporary control devices for planned startups and shutdowns.
(2) Exclusions. The following are not authorized under
this section:
(A) sour water strippers or sulfur recovery units;
(B) carbon dioxide hot carbonate processing units;
(C) water injection facilities. These facilities may
otherwise be authorized by §106.351 of this title (relating to
Salt Water Disposal (Petroleum));
(D) liquefied petroleum gases, crude oil, or condensate
transfer or loading into or from railcars, ships, or barges. These
facilities may otherwise be authorized by §106.261 of this title
(relating to Facilities (Emission Limitations)) and §106.262
of this title (relating to Facilities (Emission and Distance Limitations));
(E) incinerators for solid waste destruction;
(F) remediation of petroleum contaminated water and
soil. These facilities may otherwise be authorized by §106.533
of this title (relating to Remediation); and
(G) cooling towers and heat exchangers with direct
contact with gaseous or liquid process streams containing VOC, H2 S, halogens or halogen compounds, cyanide
compounds, inorganic acids, or acid gases.
(e) BMP and Minimum Requirements. For any new project,
and any associated emission control equipment registered under this
section, paragraphs (1) - (5) of this subsection shall be met as applicable.
These requirements are not applicable to existing, unchanging facilities.
Equipment design and control device requirements listed in paragraphs
(6) - (12) of this subsection only apply to those that are chosen
by the operator to meet the limitations of this section.
(1) All facilities which have the potential to emit
air contaminants must be maintained in good working order and operated
properly during facility operations. Each operator shall establish
and maintain a program to replace, repair, and/or maintain facilities
to keep them in good working order. The minimum requirements of this
program shall include:
(A) Compliance with manufacturer's specifications and
recommended programs applicable to equipment performance and effect
on emissions, or alternatively, an owner or operator developed maintenance
plan for such equipment that is consistent with good air pollution
control practices;
(B) cleaning and routine inspection of all equipment;
and
(C) replacement and repair of equipment on schedules
which prevent equipment failures and maintain performance.
(2) Any facility shall be operated at least 50 feet
from any property line or receptor (whichever is closer to the facility).
This distance limitation does not apply to the following:
(A) any fugitive components that are used for isolation
and/or safety purposes may be located at 1/2 of the width of any applicable
easement;
(B) any facility at a location for which the distance
requirements were satisfied at the time this section is claimed, registered,
or certified (provided that the authorization was maintained) regardless
of whether a receptor is subsequently built or put to use less than
50 feet from any OGS facility; or
(C) existing facilities which are located less than
50 feet from a property line or receptor when constructed and previously
authorized. If modified or replaced the operator shall consider, to
the extent that good engineering practice will permit, moving these
facilities to meet the 50-foot requirement. Replacement facilities
must meet all other requirements of this section.
(3) Engines and turbines shall meet the emission and
performance standards listed in Table 6 in subsection (m) of this
section and the following requirements:
(A) liquid fueled engines used for back-up power generation
and periodic power needs at the OGS are authorized if the fuel has
no more than 0.05% sulfur and the engine is operated less than 876
hours per rolling 12-month period;
(B) engines and turbines used for electric generation
more than 876 hours per rolling 12-month period are authorized if
no reliable electric service is readily available and Table 6 in subsection
(m) of this section is met. In all other circumstances, electric generators
must meet the technical requirements of the Air Quality Standard Permit
for Electric Generating Unit (EGU) (not including the EGU standard
permit registration requirements) and the emissions shall be included
in the registration under this section;
(C) all applicable requirements of Chapter 117 of this
title (relating to Control of Air Pollution from Nitrogen Compounds);
(D) all applicable requirements of 40 CFR Parts 60
and 63; and
(E) compression ignition engines that are rated less
than 225 kilowatts (300 hp) and emit less than or equal to the emission
tier for an equivalent-sized model year 2008 non-road compression
ignition engine located at 40 CFR §89.112, Table 1 are authorized.
(4) Open-topped tanks or ponds containing VOCs or H2 S are allowed up to a potential to emit equal
to 1.0 tpy of VOC and 0.1 tpy of H2 S.
(5) The following shall apply to all fugitive components
at the site associated with the project:
(A) All components shall be physically inspected quarterly
for leaks.
(B) All components found to be leaking shall be repaired.
Every reasonable effort shall be made to repair a leaking component.
All leaks not repaired immediately shall be tagged or noted in a log.
At manned sites, leaks shall be repaired no later than 30 days after
the leak is found. At unmanned sites, leaks shall be repaired no later
than 60 days after the leak is found. If the repair of a component
would require a unit shutdown, which would create more emissions than
the repair would eliminate, the repair may be delayed until the next
shutdown.
(C) Tank hatches, not designed to be completely sealed,
shall remain closed (but not completely sealed in order to maintain
safe design functionality) except for sampling, gauging, loading,
unloading, or planned maintenance activities.
(D) To the extent that good engineering practices will
permit, new and reworked valves and piping connections shall be located
in a place that is reasonably accessible for leak checking during
plant operation. Underground process pipelines shall contain no buried
valves such that fugitive emission monitoring is rendered impractical.
(6) When leak detection and repair (LDAR) fugitive
monitoring is chosen by the operator, Table 9, in subsection (m) of
this section, shall apply. In addition, all components shall be physically
inspected at least weekly by operating personnel walk-through.
(7) Tanks and vessels that utilize a paint color to
minimize the effects of solar heating (including, but not limited
to, white or aluminum):
(A) to meet this requirement the solar absorptance
should be 0.43 or less, as referenced in Table 7.1 - 6 in Compilation
of Air Pollutant Emission Factors (AP-42);
(B) paint shall be applied according to paint producers
recommended application requirements if provided and in sufficient
quantity as to be considered solar resistant;
(C) paint coatings shall be maintained in good condition
and will not compromise tank integrity. Minimal amounts of rust may
be present not to exceed 10% of the external surface area of the roof
or walls of the tank and in no way may compromise tank integrity.
Additionally, up to 10% of the external surface area of the roof or
walls of the tank or vessel may be painted with other colors to allow
for identification and/or aesthetics;
(D) for tanks and vessels purposefully darkened to
create the process reaction and help condense liquids from being entrained
in the vapor or are in an area whereby a local, state, federal law,
ordinance, or private contract predating this section's effective
date establishes in writing tank and vessel colors other than white,
these requirements do not apply.
(8) All emission estimation methods including but not
limited to computer programs such as GRI-GLYCalc, AmineCalc, E&P
Tanks, and Tanks 4.0, must be used with monitoring data generated
in accordance with Table 8 in subsection (m) of this section where
monitoring is required. All emission estimation methods must also
be used in a way that is consistent with protocols established by
the commission or promulgated in federal regulations (NSPS, NESHAPS).
Where control is relied upon to meet subsection (k) of this section,
control monitoring is required.
(9) Process reboilers, heaters, and furnaces that are
also used for control of waste gas streams:
(A) may claim 50% to 99% destruction efficiency for
VOCs and H2 S depending on the design
and level of monitoring applied. The 90% destruction may be claimed
where the waste gas is delivered to the flame zone or combustion fire
box with basic monitoring as specified in subsection (j) of this section.
Any value greater than 90% and up to 99% destruction efficiency may
be claimed where enhanced monitoring and/or testing are applied as
specified in subsection (j) of this section;
(B) if the waste gas is premixed with the primary fuel
gas and used as the primary fuel in the device through the primary
fuel burners, 99% destruction may be claimed with basic monitoring
as specified in subsection (j) of this section;
(C) in systems where the combustion device is designed
to cycle on and off to maintain the designed heating parameters, and
may not fully utilize the waste gas stream, records of run time and
enhanced monitoring are required to claim any run time beyond 50%.
(10) Vapor recovery Units (VRUs) may claim up to 100%
control. The control efficiency is based on whether it is a mechanical
VRU (mVRU) or a liquid VRU (lVRU). The VRUs must meet the appropriate
design, monitoring, and recordkeeping in Table 7 and Table 8 in subsection
(m) of this section.
(11) Flares used for control of emissions from production,
planned MSS, emergency, or upset events may claim design destruction
efficiency of 98%. 99% may be claimed for destruction of compounds
containing only carbon, hydrogen, and oxygen with no more than three
carbon atoms. All flares must be designed and operated in accordance
with the following:
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