| (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 H2S 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 2S or SO2 process fugitive emissions unless the equipment is inspected and repaired according to subsection (c)(3) of this section or unless the H2S 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 H2S 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 2S or 30 grains total sulfur compounds per 100 dscf, the operator shall maintain records, including at least quarterly measurements of fuel H2S 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. (b) Control requirements. (1) Floating roofs or equivalent controls shall be required on all new or modified storage tanks, other than pressurized tanks which meet §106.476 of this title (relating to Pressurized Tanks or Tanks Vented to Control), unless the tank is less than 25,000 gallons in nominal size or the vapor pressure of the compound to be stored in the tank is less than 0.5 pounds per square inch absolute (psia) at maximum short-term storage temperature. (A) For internal floating roofs, mechanical shoe primary seal or liquid-mounted primary seal or a vapor-mounted primary with rim-mounted secondary seal shall be used. (B) Mechanical shoe or liquid-mounted primary seals shall include a rim-mounted secondary seal on all external floating roofs tanks. Vapor-mounted primary seals will not be accepted. (C) All floating roof tanks shall comply with the requirements under §115.112(a)(2)(A) - (F) of this title (relating to Control Requirements). (D) In lieu of a floating roof, tank emissions may be routed to: (i) a destruction device such that a minimum VOC destruction efficiency of 98% is achieved; or (ii) a vapor recovery system such that a minimum VOC recovery efficiency of 95% is achieved. (E) Independent of the permits by rule listed in this paragraph, if the emissions from any fixed roof tank exceed ten tpy of VOC or ten tpy of sulfur compounds, the tank emissions shall be routed to a destruction device, vapor recovery unit, or equivalent method of control that meets the requirements listed in subparagraph (D) of this paragraph. (2) The VOC emissions from a natural gas glycol dehydration unit shall be controlled as follows. (A) If total uncontrolled VOC emissions are equal to or greater than ten tpy, but less than 50 tpy, a minimum of 80% by weight minimum control efficiency shall be achieved by either operating a condenser and a separator (or flash tank), vapor recovery unit, destruction device, or equivalent control device. (B) If total uncontrolled VOC emissions are equal to or greater than 50 tpy, a minimum of: Cont'd... |
