Texas Administrative Code › Title 30 - ENVIRONMENTAL QUALITY › Part 1 - TEXAS COMMISSION ON ENVIRONMENTAL QUALITY › Chapter 116 - CONTROL OF AIR POLLUTION BY PERMITS FOR NEW CONSTRUCTION OR MODIFICATION › Subchapter F - STANDARD PERMITS › Section 116.620 - Installation and/or Modification of Oil and Gas Facilities

Current through Reg. 49, No. 28; July 12, 2024
(a) Emission specifications.
(1) Venting or flaring more than 0.3 long
				  tons per day of total sulfur shall not be allowed.
(2) No facility shall be allowed to emit
				  total uncontrolled emissions of sulfur compounds, except sulfur dioxide (SO
				  2), from all vents (excluding process fugitives
				  emissions) equal to or greater than four pounds per hour unless the vapors are
				  collected and routed to a flare.
(3) Any vent, excluding any safety relief
				  valves that discharge to the atmosphere only as a result of fire or failure of
				  utilities, emitting sulfur compounds other than SO2
				  shall be at least 20 feet above ground level.
(4) New or modified internal combustion
				  reciprocating engines or gas turbines permitted under this standard permit
				  shall satisfy all of the requirements of §
											106.512
				  of this title (relating to Stationary Engines and Turbines), except that
				  registration using the Form PI-7 or PI-8 shall not be required. Emissions from
				  engines or turbines shall be limited to the amounts found in §
											106.4(a)(1)
				  of this title (relating to Requirements for Permitting by Rule).
(5) Total Volatile Organic Compound (VOC)
				  emissions from a natural gas glycol dehydration unit shall not exceed ten tons
				  per year (tpy) unless the vapors are collected and controlled in accordance
				  with subsection (b)(2) of this section.
(6) Any combustion unit (excluding flares,
				  internal combustion engines, or natural gas turbines), with a design maximum
				  heat input greater than 40 million British thermal units (Btu) per hour (using
				  lower heating values) shall not emit more than 0.06 pounds of nitrogen oxides
				  per million Btu.
(7) No facility
				  which is less than 500 feet from the nearest off-plant receptor shall be
				  allowed to emit uncontrolled VOC process fugitive emissions equal to or greater
				  than ten tpy, but less than 25 tpy, unless the equipment is inspected and
				  repaired according to subsection (c)(1) of this section.
(8) No facility which is 500 feet or more
				  from the nearest off-plant receptor shall be allowed to emit uncontrolled VOC
				  process fugitive emissions equal to or greater than 25 tpy unless the equipment
				  is inspected and repaired according to subsection (c)(1) of this
				  section.
(9) No facility which is
				  less than 500 feet from the nearest off-plant receptor shall be allowed to emit
				  uncontrolled VOC process fugitive emissions equal to or greater than 25 tpy
				  unless the equipment is inspected and repaired according to subsection (c)(2)
				  of this section.
(10) No facility
				  shall be allowed to emit uncontrolled VOC process fugitive emissions equal to
				  or greater than 40 tpy unless the equipment is inspected and repaired according
				  to subsection (c)(2) of this section.
(11) No facility which is located less than
				  1/4 mile from the nearest off-plant receptor shall be allowed to emit hydrogen
				  sulfide H2 S or SO2 process
				  fugitive emissions unless the equipment is inspected and repaired according to
				  subsection (c)(3) of this section. No facility which is located at least 1/4
				  mile from the nearest off-plant receptor shall be allowed to emit H
				  2 S or SO2 process fugitive
				  emissions unless the equipment is inspected and repaired according to
				  subsection (c)(3) of this section or unless the H2 S or
				  SO 2 emissions are monitored with ambient property line
				  monitors according to subsection (e)(1) of this section. Components in sweet
				  crude oil or gas service as defined by Chapter 101 of this title (relating to
				  General Air Quality Rules) are exempt from these limitations.
(12) Flares shall be designed and operated in
				  accordance with 40 Code of Federal Regulations (CFR), Part 60.18 or equivalent
				  standard approved by the commission, including specifications of minimum
				  heating values of waste gas, maximum tip velocity, and pilot flame monitoring.
				  If necessary to ensure adequate combustion, sufficient gas shall be added to
				  make the gases combustible. An infrared monitor is considered equivalent to a
				  thermocouple for flame monitoring purposes. An automatic ignition system may be
				  used in lieu of a continuous pilot.
(13) Appropriate documentation shall be
				  submitted to demonstrate that compliance with the Prevention of Significant
				  Deterioration (PSD) and nonattainment new source review provisions of the FCAA,
				  Parts C and D, and regulations promulgated thereunder, and with Subchapter C of
				  this chapter (relating to Hazardous Air Pollutants: Regulations Governing
				  Constructed or Reconstructed Major Sources (FCAA, §112(g), 40 CFR Part
				  63)) are being met. The oil and gas facility shall be required to meet the
				  requirements of Subchapter B of this chapter (relating to New Source Review
				  Permits) instead of this subchapter if a PSD or nonattainment permit or a
				  review under Subchapter C of this chapter is required.
(14) Documentation shall be submitted to
				  demonstrate compliance with applicable New Source Performance Standards (NSPS,
				  40 CFR Part 60).
(15) Documentation
				  shall be submitted to demonstrate compliance with applicable National Emission
				  Standards for Hazardous Air Pollution (NESHAP, 40 CFR Part 61).
(16) Documentation shall be submitted to
				  demonstrate compliance with applicable maximum achievable control technology
				  standards as listed under 40 CFR Part 63, promulgated by the EPA under FCAA,
				  §112 or as listed in Chapter 113, Subchapter C of this title (relating to
				  National Emissions Standards for Hazardous Air Pollutants for Source Categories
				  (FCAA §112, 40 CFR Part 63)).
(17) New and increased emissions shall not
				  cause or contribute to a violation of any National Ambient Air Quality Standard
				  or regulation property line standards as specified in Chapters 111, 112, and
				  113 of this title (relating to Control of Air Pollution from Visible Emissions
				  and Particulate Matter; Control of Air Pollution from Sulfur Compounds; and
				  Control of Air Pollution from Toxic Materials). Engineering judgment and/or
				  computerized air dispersion modeling may be used in this demonstration. To show
				  compliance with §
											116.610(a)(1)
				  of this title (relating to Applicability) for H2 S
				  emissions from process vents, ten milligrams per cubic meter shall be used as
				  the "L" value instead of the value represented by §
											116.610(a)(1)
				  of this title.
(18) Fuel for all
				  combustion units and flare pilots shall be sweet natural gas or liquid
				  petroleum gas, fuel gas containing no more than ten grains of total sulfur per
				  100 dry standard cubic feet (dscf), or field gas. If field gas contains more
				  than 1.5 grains of H 2 S or 30 grains total sulfur
				  compounds per 100 dscf, the operator shall maintain records, including at least
				  quarterly measurements of fuel H2 S and total sulfur
				  content, which demonstrate that the annual SO2 emissions
				  from the facility do not exceed the limitations listed in the standard permit
				  registration. If a flare is the only combustion unit on a property, the
				  operator shall not be required to maintain such records on flare pilot
				  gas.