Title 40—Protection of Environment--Volume 1
PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
§ 60.482-9b   Standards: Delay of repair.
(a) Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15 days is technically infeasible without a process unit shutdown. Repair of this equipment shall occur before the end of the next process unit shutdown. Monitoring to verify repair must occur within 15 days after startup of the process unit.
(b) Delay of repair of equipment will be allowed for equipment which is isolated from the process and which does not remain in VOC service.
(c) Delay of repair for valves and connectors will be allowed if:
(1) The owner or operator demonstrates that emissions of purged material resulting from immediate repair are greater than the fugitive emissions likely to result from delay of repair, and
(2) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control device complying with § 60.482-10b.
(d) Delay of repair for pumps will be allowed if:
(1) Repair requires the use of a dual mechanical seal system that includes a barrier fluid system, and
(2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.
(e) Delay of repair beyond a process unit shutdown will be allowed for a valve, if valve assembly replacement is necessary during the process unit shutdown, valve assembly supplies have been depleted, and valve assembly supplies had been sufficiently stocked before the supplies were depleted. Delay of repair beyond the next process unit shutdown will not be allowed unless the next process unit shutdown occurs sooner than 6 months after the first process unit shutdown.
(f) When delay of repair is allowed for a leaking pump, valve, or connector that remains in service, the pump, valve, or connector may be considered to be repaired and no longer subject to delay of repair requirements if two consecutive monthly monitoring instrument readings are below the leak definition.
§ 60.482-10b   Standards: Closed vent systems and control devices.
(a) Owners or operators of closed vent systems and control devices used to comply with provisions of this subpart shall comply with the provisions of this section.
(b) Vapor recovery systems (for example, condensers and absorbers) shall be designed and operated to recover the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20 parts per million by volume (ppmv), whichever is less stringent.
(c) Enclosed combustion devices shall be designed and operated to reduce the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20 ppmv, on a dry basis, corrected to 3 percent oxygen, whichever is less stringent or to provide a minimum residence time of 0.75 seconds at a minimum temperature of 816 °C.
(d) Flares used to comply with this subpart shall comply with the requirements of § 60.18.
(e) Owners or operators of control devices used to comply with the provisions of this subpart shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs.
(f) Except as provided in paragraphs (i) through (k) of this section, each closed vent system shall be inspected according to the procedures and schedule specified in paragraphs (f)(1) through (3) of this section.
(1) Conduct an initial inspection according to the procedures in § 60.485b(b); and
(2) Conduct annual inspections according to the procedures in § 60.485b(b).
(3) Conduct annual visual inspections for visible, audible, or olfactory indications of leaks.
(g) Leaks, as indicated by an instrument reading greater than 500 ppmv above background or by visual inspections, shall be repaired as soon as practicable except as provided in paragraph (h) of this section.
(1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected.
(2) Repair shall be completed no later than 15 calendar days after the leak is detected.
(h) Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is technically infeasible without a process unit shutdown or if the owner or operator determines that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of such equipment shall be complete by the end of the next process unit shutdown.
(i) If a vapor collection system or closed vent system is operated under a vacuum, it is exempt from the inspection requirements of paragraphs (f)(1) and (2) of this section.
(j) Any parts of the closed vent system that are designated, as described in paragraph (l)(1) of this section, as unsafe to inspect are exempt from the inspection requirements of paragraphs (f)(1) and (2) of this section if they comply with the requirements specified in paragraphs (j)(1) and (2) of this section:
(1) The owner or operator determines that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragraphs (f)(1) and (2) of this section; and
(2) The owner or operator has a written plan that requires inspection of the equipment as frequently as practicable during safe-to-inspect times.
(k) Any parts of the closed vent system that are designated, as described in paragraph (l)(2) of this section, as difficult to inspect are exempt from the inspection requirements of paragraphs (f)(1) and (2) of this section if they comply with the requirements specified in paragraphs (k)(1) through (3) of this section:
(1) The owner or operator determines that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface; and
(2) The process unit within which the closed vent system is located becomes an affected facility through §§ 60.14 or 60.15, or the owner or operator designates less than 3.0 percent of the total number of closed vent system equipment as difficult to inspect; and
(3) The owner or operator has a written plan that requires inspection of the equipment at least once every 5 years. A closed vent system is exempt from inspection if it is operated under a vacuum.
(l) The owner or operator shall record the information specified in paragraphs (l)(1) through (5) of this section.
(1) Identification of all parts of the closed vent system that are designated as unsafe to inspect, an explanation of why the equipment is unsafe to inspect, and the plan for inspecting the equipment.
(2) Identification of all parts of the closed vent system that are designated as difficult to inspect, an explanation of why the equipment is difficult to inspect, and the plan for inspecting the equipment.
(3) For each inspection during which a leak is detected, a record of the information specified in § 60.486b(c).
(4) For each inspection conducted in accordance with § 60.485b(b) during which no leaks are detected, a record that the inspection was performed, the date of the inspection, and a statement that no leaks were detected.
(5) For each visual inspection conducted in accordance with paragraph (f)(3) of this section during which no leaks are detected, a record that the inspection was performed, the date of the inspection, and a statement that no leaks were detected.
(m) Closed vent systems and control devices used to comply with provisions of this subpart shall be operated at all times when emissions may be vented to them.
§ 60.482-11b   Standards: Connectors in gas/vapor service and in light liquid service.
(a) The owner or operator shall initially monitor all connectors in the process unit for leaks by the later of either 12 months after the compliance date or 12 months after initial startup. If all connectors in the process unit have been monitored for leaks prior to the compliance date, no initial monitoring is required provided either no process changes have been made since the monitoring or the owner or operator can determine that the results of the monitoring, with or without adjustments, reliably demonstrate compliance despite process changes. If required to monitor because of a process change, the owner or operator is required to monitor only those connectors involved in the process change.
(b) Except as allowed in § 60.482-1b(c), § 60.482-10b, or as specified in paragraph (e) of this section, the owner or operator shall monitor all connectors in gas and vapor and light liquid service as specified in paragraphs (a) and (b)(3) of this section.
(1) The connectors shall be monitored to detect leaks by the method specified in § 60.485b(b) and, as applicable, § 60.485b(c).
(2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is detected.
(3) The owner or operator shall perform monitoring, subsequent to the initial monitoring required in paragraph (a) of this section, as specified in paragraphs (b)(3)(i) through (iii) of this section, and shall comply with the requirements of paragraphs (b)(3)(iv) and (v) of this section. The required period in which monitoring must be conducted shall be determined from paragraphs (b)(3)(i) through (iii) of this section using the monitoring results from the preceding monitoring period. The percent leaking connectors shall be calculated as specified in paragraph (c) of this section.
(i) If the percent leaking connectors in the process unit was greater than or equal to 0.5 percent, then monitor within 12 months (1 year).
(ii) If the percent leaking connectors in the process unit was greater than or equal to 0.25 percent but less than 0.5 percent, then monitor within 4 years. An owner or operator may comply with the requirements of this paragraph by monitoring at least 40 percent of the connectors within 2 years of the start of the monitoring period, provided all connectors have been monitored by the end of the 4-year monitoring period.
(iii) If the percent leaking connectors in the process unit was less than 0.25 percent, then monitor as provided in paragraph (b)(3)(iii)(A) of this section and either paragraph (b)(3)(iii)(B) or (C) of this section, as appropriate.
(A) An owner or operator shall monitor at least 50 percent of the connectors within 4 years of the start of the monitoring period.
(B) If the percent of leaking connectors calculated from the monitoring results in paragraph (b)(3)(iii)(A) of this section is greater than or equal to 0.35 percent of the monitored connectors, the owner or operator shall monitor as soon as practical, but within the next 6 months, all connectors that have not yet been monitored during the monitoring period. At the conclusion of monitoring, a new monitoring period shall be started pursuant to paragraph (b)(3) of this section, based on the percent of leaking connectors within the total monitored connectors.
(C) If the percent of leaking connectors calculated from the monitoring results in paragraph (b)(3)(iii)(A) of this section is less than 0.35 percent of the monitored connectors, the owner or operator shall monitor all connectors that have not yet been monitored within 8 years of the start of the monitoring period.
(iv) If, during the monitoring conducted pursuant to paragraphs (b)(3)(i) through (iii) of this section, a connector is found to be leaking, it shall be re-monitored once within 90 days after repair to confirm that it is not leaking.
(v) The owner or operator shall keep a record of the start date and end date of each monitoring period under this section for each process unit.
(c) For use in determining the monitoring frequency, as specified in paragraphs (a) and (b)(3) of this section, the percent leaking connectors as used in paragraphs (a) and (b)(3) of this section shall be calculated by using the following equation:
(d) When a leak is detected pursuant to paragraphs (a) and (b) of this section, it shall be repaired as soon as practicable, but not later than 15 calendar days after it is detected, except as provided in § 60.482-9b. A first attempt at repair as defined in this subpart shall be made no later than 5 calendar days after the leak is detected.
(e) Any connector that is designated, as described in § 60.486b(f)(1), as an unsafe-to-monitor connector is exempt from the requirements of paragraphs (a) and (b) of this section if:
(1) The owner or operator of the connector demonstrates that the connector is unsafe-to-monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with paragraphs (a) and (b) of this section; and
(2) The owner or operator of the connector has a written plan that requires monitoring of the connector as frequently as practicable during safe-to-monitor times but not more frequently than the periodic monitoring schedule otherwise applicable, and repair of the equipment according to the procedures in paragraph (d) of this section if a leak is detected.
(f)(1) Any connector that is inaccessible or that is ceramic or ceramic-lined ( e.g., porcelain, glass, or glass-lined), is exempt from the monitoring requirements of paragraphs (a) and (b) of this section, from the leak repair requirements of paragraph (d) of this section, and from the recordkeeping and reporting requirements of §§ 63.1038 and 63.1039. An inaccessible connector is one that meets any of the provisions specified in paragraphs (f)(1)(i) through (vi) of this section, as applicable:
(i) Buried;
(ii) Insulated in a manner that prevents access to the connector by a monitor probe;
(iii) Obstructed by equipment or piping that prevents access to the connector by a monitor probe;
(iv) Unable to be reached from a wheeled scissor-lift or hydraulic-type scaffold that would allow access to connectors up to 7.6 meters (25 feet) above the ground;
(v) Inaccessible because it would require elevating the monitoring personnel more than 2 meters (7 feet) above a permanent support surface or would require the erection of scaffold; or
(vi) Not able to be accessed at any time in a safe manner to perform monitoring. Unsafe access includes, but is not limited to, the use of a wheeled scissor-lift on unstable or uneven terrain, the use of a motorized man-lift basket in areas where an ignition potential exists, or access would require near proximity to hazards such as electrical lines, or would risk damage to equipment.
(2) If any inaccessible, ceramic, or ceramic-lined connector is observed by visual, audible, olfactory, or other means to be leaking, the visual, audible, olfactory, or other indications of a leak to the atmosphere shall be eliminated as soon as practical.
(g) Except for instrumentation systems and inaccessible, ceramic, or ceramic-lined connectors meeting the provisions of paragraph (f) of this section, identify the connectors subject to the requirements of this subpart. Connectors need not be individually identified if all connectors in a designated area or length of pipe subject to the provisions of this subpart are identified as a group, and the number of connectors subject is indicated.
§ 60.483-1b   Alternative standards for valves—allowable percentage of valves leaking.
(a) An owner or operator may elect to comply with an allowable percentage of valves leaking of equal to or less than 2.0 percent.
(b) The following requirements shall be met if an owner or operator wishes to comply with an allowable percentage of valves leaking:
(1) An owner or operator must notify the Administrator that the owner or operator has elected to comply with the allowable percentage of valves leaking before implementing this alternative standard, as specified in § 60.487b(d).
(2) A performance test as specified in paragraph (c) of this section shall be conducted initially upon designation, annually, and at other times requested by the Administrator.
(3) If a valve leak is detected, it shall be repaired in accordance with § 60.482-7b(d) and (e).
(c) Performance tests shall be conducted in the following manner:
(1) All valves in gas/vapor and light liquid service within the affected facility shall be monitored within 1 week by the methods specified in § 60.485b(b).
(2) If an instrument reading of 500 ppm or greater is measured, a leak is detected.
(3) The leak percentage shall be determined by dividing the number of valves for which leaks are detected by the number of valves in gas/vapor and light liquid service within the affected facility.
(d) Owners and operators who elect to comply with this alternative standard shall not have an affected facility with a leak percentage greater than 2.0 percent, determined as described in § 60.485b(h).
§ 60.483-2b   Alternative standards for valves—skip period leak detection and repair.
(a)(1) An owner or operator may elect to comply with one of the alternative work practices specified in paragraphs (b)(2) and (3) of this section.
(2) An owner or operator must notify the Administrator before implementing one of the alternative work practices, as specified in § 60.487a(d).
(b)(1) An owner or operator shall comply initially with the requirements for valves in gas/vapor service and valves in light liquid service, as described in § 60.482-7b.
(2) After 2 consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0, an owner or operator may begin to skip 1 of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.
(3) After 5 consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0, an owner or operator may begin to skip 3 of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.
(4) If the percent of valves leaking is greater than 2.0, the owner or operator shall comply with the requirements as described in § 60.482-7b but can again elect to use this section.
(5) The percent of valves leaking shall be determined as described in § 60.485b(h).
(6) An owner or operator must keep a record of the percent of valves found leaking during each leak detection period.
(7) A valve that begins operation in gas/vapor service or light liquid service after the initial startup date for a process unit following one of the alternative standards in this section must be monitored in accordance with § 60.482-7b(a)(2)(i) or (ii) before the provisions of this section can be applied to that valve.
§ 60.484b   Equivalence of means of emission limitation.
(a) Each owner or operator subject to the provisions of this subpart may apply to the Administrator for determination of equivalence for any means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to the reduction in emissions of VOC achieved by the controls required in this subpart.
(b) Determination of equivalence to the equipment, design, and operational requirements of this subpart will be evaluated by the following guidelines:
(1) Each owner or operator applying for an equivalence determination shall be responsible for collecting and verifying test data to demonstrate equivalence of means of emission limitation.
(2) The Administrator will compare test data for demonstrating equivalence of the means of emission limitation to test data for the equipment, design, and operational requirements.
(3) The Administrator may condition the approval of equivalence on requirements that may be necessary to assure operation and maintenance to achieve the same emission reduction as the equipment, design, and operational requirements.
(c) Determination of equivalence to the required work practices in this subpart will be evaluated by the following guidelines:
(1) Each owner or operator applying for a determination of equivalence shall be responsible for collecting and verifying test data to demonstrate equivalence of an equivalent means of emission limitation.
(2) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the required work practice shall be demonstrated.
(3) For each affected facility, for which a determination of equivalence is requested, the emission reduction achieved by the equivalent means of emission limitation shall be demonstrated.
(4) Each owner or operator applying for a determination of equivalence shall commit in writing to work practice(s) that provide for emission reductions equal to or greater than the emission reductions achieved by the required work practice.
(5) The Administrator will compare the demonstrated emission reduction for the equivalent means of emission limitation to the demonstrated emission reduction for the required work practices and will consider the commitment in paragraph (c)(4) of this section.
(6) The Administrator may condition the approval of equivalence on requirements that may be necessary to assure operation and maintenance to achieve the same emission reduction as the required work practice.
(d) An owner or operator may offer a unique approach to demonstrate the equivalence of any equivalent means of emission limitation.
(e)(1) After a request for determination of equivalence is received, the Administrator will publish a notice in the Federal Register and provide the opportunity for public hearing if the Administrator judges that the request may be approved.
(2) After notice and opportunity for public hearing, the Administrator will determine the equivalence of a means of emission limitation and will publish the determination in the Federal Register .
(3) Any equivalent means of emission limitations approved under this section shall constitute a required work practice, equipment, design, or operational standard within the meaning of section 111(h)(1) of the CAA.
(f)(1) Manufacturers of equipment used to control equipment leaks of VOC may apply to the Administrator for determination of equivalence for any equivalent means of emission limitation that achieves a reduction in emissions of VOC achieved by the equipment, design, and operational requirements of this subpart.
(2) The Administrator will make an equivalence determination according to the provisions of paragraphs (b) through (e) of this section.
§ 60.485b   Test methods and procedures.
(a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A to this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
(b) The owner or operator shall determine compliance with the standards in §§ 60.482-1b through 60.482-11b, 60.483a, and 60.484b as follows:
(1) Method 21 of appendix A-7 to this part shall be used to determine the presence of leaking sources. The instrument shall be calibrated before use each day of its use by the procedures specified in Method 21. The following calibration gases shall be used:
(i) Zero air (less than 10 ppm of hydrocarbon in air); and
(ii) A mixture of methane or n-hexane and air at a concentration no more than 2,000 ppm greater than the leak definition concentration of the equipment monitored. If the monitoring instrument's design allows for multiple calibration scales, then the lower scale shall be calibrated with a calibration gas that is no higher than 2,000 ppm above the concentration specified as a leak, and the highest scale shall be calibrated with a calibration gas that is approximately equal to 10,000 ppm. If only one scale on an instrument will be used during monitoring, the owner or operator need not calibrate the scales that will not be used during that day's monitoring.
(2) A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day. Check the instrument using the same calibration gas(es) that were used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 to this part, section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. Record the instrument reading for each scale used as specified in § 60.486b(e)(8). Divide the arithmetic difference of the initial and post-test calibration response by the corresponding calibration gas value for each scale and multiply by 100 to express the calibration drift as a percentage.
(i) If a calibration drift assessment shows a negative drift of more than 10 percent, then all equipment with instrument readings between the appropriate leak definition and the leak definition multiplied by (100 minus the percent of negative drift/divided by 100) that was monitored since the last calibration must be re-monitored.
(ii) If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment with instrument readings above the appropriate leak definition and below the leak definition multiplied by (100 plus the percent of positive drift/divided by 100) monitored since the last calibration may be re-monitored.
(c) The owner or operator shall determine compliance with the no-detectable-emission standards in §§ 60.482-2b(e), 60.482-3b(i), 60.482-4b, 60.482-7b(f), and 60.482-10b(e) as follows:
(1) The requirements of paragraph (b) shall apply.
(2) Method 21 of appendix A-7 to this part shall be used to determine the background level. All potential leak interfaces shall be traversed as close to the interface as possible. The arithmetic difference between the maximum concentration indicated by the instrument and the background level is compared with 500 ppm for determining compliance.
(d) The owner or operator shall test each piece of equipment unless they demonstrate that a process unit is not in VOC service, i.e., that the VOC content would never be reasonably expected to exceed 10 percent by weight. For purposes of this demonstration, the following methods and procedures shall be used:
(1) Procedures that conform to the general methods in ASTM E168-16 (Reapproved 2023), E169-16 (Reapproved 2022), or E260-96 (Reapproved 2019) (incorporated by reference, see § 60.17) shall be used to determine the percent VOC content in the process fluid that is contained in or contacts a piece of equipment.
(2) Organic compounds that are considered by the Administrator to have negligible photochemical reactivity may be excluded from the total quantity of organic compounds in determining the VOC content of the process fluid.
(3) Engineering judgment may be used to estimate the VOC content, if a piece of equipment had not been shown previously to be in service. If the Administrator disagrees with the judgment, paragraphs (d)(1) and (2) of this section shall be used to resolve the disagreement.
(e) The owner or operator shall demonstrate that a piece of equipment is in light liquid service by showing that all the following conditions apply:
(1) The vapor pressure of one or more of the organic components is greater than 0.3 kPa at 20 °C (1.2 in. H 2 O at 68 °F). Standard reference texts or ASTM D2879-23 (incorporated by reference, see § 60.17) shall be used to determine the vapor pressures.
(2) The total concentration of the pure organic components having a vapor pressure greater than 0.3 kPa at 20 °C (1.2 in. H 2 O at 68 °F) is equal to or greater than 20 percent by weight.
(3) The fluid is a liquid at operating conditions.
(f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be representative of the process fluid that is contained in or contacts the equipment or the gas being combusted in the flare.
(g) The owner or operator shall determine compliance with the standards of flares as follows:
(1) Method 22 of appendix A-7 to this part shall be used to determine visible emissions.
(2) A thermocouple or any other equivalent device shall be used to monitor the presence of a pilot flame in the flare.
(3) The maximum permitted velocity for air assisted flares shall be computed using the following equation:
(4) The net heating value (HT) of the gas being combusted in a flare shall be computed using the following equation:
(5) Method 18 of appendix A-6 to this part and ASTM D1945-14 (Reapproved 2019) (incorporated by reference, see § 60.17) shall be used to determine the concentration of sample component “i.” ASTM D6420-18 (incorporated by reference, see §  60.17) may be used in lieu of Method 18, under the conditions specified in paragraphs (g)(5)(i) through (iii) of this section.
(i) If the target compounds are all known and are all listed in Section 1.1 of ASTM D6420-18 as measurable.
(ii) ASTM D6420-18 may not be used for methane and ethane.
(iii) ASTM D6420-18 may not be used as a total VOC method.
(6) ASTM D240-19 or D4809-18 (incorporated by reference, see § 60.17) shall be used to determine the net heat of combustion of component “i” if published values are not available or cannot be calculated.
(7) Method 2, 2A, 2C, or 2D of appendix A-7 to this part, as appropriate, shall be used to determine the actual exit velocity of a flare. If needed, the unobstructed (free) cross-sectional area of the flare tip shall be used.
(h) The owner or operator shall determine compliance with § 60.483-1b or § 60.483-2b as follows:
(1) The percent of valves leaking shall be determined using the following equation:
(2) The total number of valves monitored shall include difficult-to-monitor and unsafe-to-monitor valves only during the monitoring period in which those valves are monitored.
(3) The number of valves leaking shall include valves for which repair has been delayed.
(4) Any new valve that is not monitored within 30 days of being placed in service shall be included in the number of valves leaking and the total number of valves monitored for the monitoring period in which the valve is placed in service.
(5) If the process unit has been subdivided in accordance with § 60.482-7b(c)(1)(ii), the sum of valves found leaking during a monitoring period includes all subgroups.
(6) The total number of valves monitored does not include a valve monitored to verify repair.
§ 60.486b   Recordkeeping requirements.
(a)(1) Each owner or operator subject to the provisions of this subpart shall comply with the recordkeeping requirements of this section.
(2) An owner or operator of more than one affected facility subject to the provisions of this subpart may comply with the recordkeeping requirements for these facilities in one recordkeeping system if the system identifies each record by each facility.
(3) The owner or operator shall record the information specified in paragraphs (a)(3)(i) through (v) of this section for each monitoring event required by §§ 60.482-2b, 60.482-3b, 60.482-7b, 60.482-8b, 60.482-11b, and 60.483-2b.
(i) Monitoring instrument identification.
(ii) Operator identification.
(iii) Equipment identification.
(iv) Date of monitoring.
(v) Instrument reading.
(b) When each leak is detected as specified in §§ 60.482-2b, 60.482-3b, 60.482-7b, 60.482-8b, 60.482-11b, and 60.483-2b, the following requirements apply:
(1) A weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment.
(2) The identification on a valve may be removed after it has been monitored for 2 successive months as specified in § 60.482-7b(c) and no leak has been detected during those 2 months.
(3) The identification on a connector may be removed after it has been monitored as specified in § 60.482-11b(b)(3)(iv) and no leak has been detected during that monitoring.
(4) The identification on equipment, except on a valve or connector, may be removed after it has been repaired.
(c) When each leak is detected as specified in §§ 60.482-2b, 60.482-3b, 60.482-7b, 60.482-8b, 60.482-11b, and 60.483-2b, the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location:
(1) The instrument and operator identification numbers and the equipment identification number, except when indications of liquids dripping from a pump are designated as a leak.
(2) The date the leak was detected and the dates of each attempt to repair the leak.
(3) Repair methods applied in each attempt to repair the leak.
(4) Maximum instrument reading measured by Method 21 of appendix A-7 of this part at the time the leak is successfully repaired or determined to be nonrepairable, except when a pump is repaired by eliminating indications of liquids dripping.
(5) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak.
(6) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown.
(7) The expected date of successful repair of the leak if a leak is not repaired within 15 days.
(8) Dates of process unit shutdowns that occur while the equipment is unrepaired.
(9) The date of successful repair of the leak.
(d) The following information pertaining to the design requirements for closed vent systems and control devices described in § 60.482-10b shall be recorded and kept in a readily accessible location:
(1) Detailed schematics, design specifications, and piping and instrumentation diagrams.
(2) The dates and descriptions of any changes in the design specifications.
(3) A description of the parameter or parameters monitored, as required in § 60.482-10b(e), to ensure that control devices are operated and maintained in conformance with their design and an explanation of why that parameter (or parameters) was selected for the monitoring.
(4) Periods when the closed vent systems and control devices required in §§ 60.482-2b, 60.482-3b, 60.482-4b, and 60.482-5b are not operated as designed, including periods when a flare pilot light does not have a flame.
(5) Dates of startups and shutdowns of the closed vent systems and control devices required in §§ 60.482-2b, 60.482-3b, 60.482-4b, and 60.482-5b.
(e) The following information pertaining to all equipment subject to the requirements in §§ 60.482-1b to 60.482-11b shall be recorded in a log that is kept in a readily accessible location:
(1) A list of identification numbers for equipment subject to the requirements of this subpart.
(2)(i) A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §§ 60.482-2b(e), 60.482-3b(i), and 60.482-7b(f).
(ii) The designation of equipment as subject to the requirements of § 60.482-2b(e), § 60.482-3b(i), or § 60.482-7b(f) shall be signed by the owner or operator. Alternatively, the owner or operator may establish a mechanism with their permitting authority that satisfies this requirement.
(3) A list of equipment identification numbers for pressure relief devices required to comply with § 60.482-4b.
(4)(i) The dates of each compliance test as required in §§ 60.482-2b(e), 60.482-3b(i), 60.482-4b, and 60.482-7b(f).
(ii) The background level measured during each compliance test.
(iii) The maximum instrument reading measured at the equipment during each compliance test.
(5) A list of identification numbers for equipment in vacuum service.
(6) A list of identification numbers for equipment that the owner or operator designates as operating in VOC service less than 300 hr/yr in accordance with § 60.482-1b(e), a description of the conditions under which the equipment is in VOC service, and rationale supporting the designation that it is in VOC service less than 300 hr/yr.
(7) The date and results of the weekly visual inspection for indications of liquids dripping from pumps in light liquid service.
(8) Records of the information specified in paragraphs (e)(8)(i) through (vi) of this section for monitoring instrument calibrations conducted according to sections 8.1.2 and 10 of Method 21 of appendix A-7 of this part and § 60.485b(b).
(i) Date of calibration and initials of operator performing the calibration.
(ii) Calibration gas cylinder identification, certification date, and certified concentration.
(iii) Instrument scale(s) used.
(iv) A description of any corrective action taken if the meter readout could not be adjusted to correspond to the calibration gas value in accordance with section 10.1 of Method 21 of appendix A-7 of this part.
(v) Results of each calibration drift assessment required by § 60.485b(b)(2) ( i.e., instrument reading for calibration at end of monitoring day and the calculated percent difference from the initial calibration value).
(vi) If an owner or operator makes their own calibration gas, a description of the procedure used.
(9) The connector monitoring schedule for each process unit as specified in § 60.482-11b(b)(3)(v).
(10) Records of each release from a pressure relief device subject to § 60.482-4b.
(f) The following information pertaining to all valves subject to the requirements of § 60.482-7b(g) and (h), all pumps subject to the requirements of § 60.482-2b(g), and all connectors subject to the requirements of § 60.482-11b(e) shall be recorded in a log that is kept in a readily accessible location:
(1) A list of identification numbers for valves, pumps, and connectors that are designated as unsafe-to-monitor, an explanation for each valve, pump, or connector stating why the valve, pump, or connector is unsafe-to-monitor, and the plan for monitoring each valve, pump, or connector.
(2) A list of identification numbers for valves that are designated as difficult-to-monitor, an explanation for each valve stating why the valve is difficult-to-monitor, and the schedule for monitoring each valve.
(g) The following information shall be recorded for valves complying with § 60.483-2b:
(1) A schedule of monitoring.
(2) The percent of valves found leaking during each monitoring period.
(h) The following information shall be recorded in a log that is kept in a readily accessible location:
(1) Design criterion required in §§ 60.482-2b(d)(5) and 60.482-3b(e)(2) and explanation of the design criterion; and
(2) Any changes to this criterion and the reasons for the changes.
(i) The following information shall be recorded in a log that is kept in a readily accessible location for use in determining exemptions as provided in § 60.480b(d):
(1) An analysis demonstrating the design capacity of the affected facility,
(2) A statement listing the feed or raw materials and products from the affected facilities and an analysis demonstrating whether these chemicals are heavy liquids or beverage alcohol, and
(3) An analysis demonstrating that equipment is not in VOC service.
(j) Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in a log that is kept in a readily accessible location.
(k) The provisions of § 60.7(b) and (d) do not apply to affected facilities subject to this subpart.
(l) Any records required to be maintained by this subpart that are submitted electronically via the EPA's Compliance and Emissions Data Reporting Interface (CEDRI) may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated air agency or the EPA as part of an on-site compliance evaluation.
§ 60.487b   Reporting requirements.
(a) Each owner or operator subject to the provisions of this subpart shall submit semiannual reports to the Administrator beginning 6 months after the initial startup date. Beginning on July 15, 2024, or once the report template for this subpart has been available on the CEDRI website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for 1 year, whichever date is later, submit all subsequent reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in paragraph (g) of this section. The date report templates become available will be listed on the CEDRI website. Unless the Administrator or delegated state agency or other authority has approved a different schedule for submission of reports, the report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted. All semiannual reports must include the following general information: company name, address (including county), and beginning and ending dates of the reporting period.
(b) The initial semiannual report to the Administrator shall include the following information:
(1) Process unit identification.
(2) Number of valves subject to the requirements of § 60.482-7b, excluding those valves designated for no detectable emissions under the provisions of § 60.482-7b(f).
(3) Number of pumps subject to the requirements of § 60.482-2b, excluding those pumps designated for no detectable emissions under the provisions of § 60.482-2b(e) and those pumps complying with § 60.482-2b(f).
(4) Number of compressors subject to the requirements of § 60.482-3b, excluding those compressors designated for no detectable emissions under the provisions of § 60.482-3b(i) and those compressors complying with § 60.482-3b(h).
(5) Number of connectors subject to the requirements of § 60.482-11b.
(c) All semiannual reports to the Administrator shall include the following information, summarized from the information in § 60.486b:
(1) Process unit identification.
(2) For each month during the semiannual reporting period,
(i) Number of valves for which leaks were detected as described in § 60.482-7b(b) or § 60.483-2b,
(ii) Number of valves for which leaks were not repaired as required in § 60.482-7b(d)(1),
(iii) Number of pumps for which leaks were detected as described in § 60.482-2b(b), (d)(4)(ii)(A) or (B), or (d)(5)(iii),
(iv) Number of pumps for which leaks were not repaired as required in § 60.482-2b(c)(1) and (d)(6),
(v) Number of compressors for which leaks were detected as described in § 60.482-3b(f),
(vi) Number of compressors for which leaks were not repaired as required in § 60.482-3b(g)(1),
(vii) Number of connectors for which leaks were detected as described in § 60.482-11b(b)
(viii) Number of connectors for which leaks were not repaired as required in § 60.482-11b(d), and
(ix)-(x) [Reserved]
(xi) The facts that explain each delay of repair and, where appropriate, why a process unit shutdown was technically infeasible.
(3) Dates of process unit shutdowns which occurred within the semiannual reporting period.
(4) Revisions to items reported according to paragraph (b) of this section if changes have occurred since the initial report or subsequent revisions to the initial report.
(d) An owner or operator electing to comply with the provisions of §§ 60.483-1b or 60.483-2b shall notify the Administrator of the alternative standard selected 90 days before implementing either of the provisions.
(e) An owner or operator shall report the results of all performance tests in accordance with § 60.8. The provisions of § 60.8(d) do not apply to affected facilities subject to the provisions of this subpart except that an owner or operator must notify the Administrator of the schedule for the initial performance tests at least 30 days before the initial performance tests.
(f) The requirements of paragraphs (a) through (c) of this section remain in force until and unless EPA, in delegating enforcement authority to a state under section 111(c) of the CAA, approves reporting requirements or an alternative means of compliance surveillance adopted by such state. In that event, affected sources within the state will be relieved of the obligation to comply with the requirements of paragraphs (a) through (c) of this section, provided that they comply with the requirements established by the state. The EPA will not approve a waiver of electronic reporting to the EPA in delegating enforcement authority. Thus, electronic reporting to the EPA cannot be waived, and as such, the provisions of this paragraph cannot be used to relieve owners or operators of affected facilities of the requirement to submit the electronic reports required in this section to the EPA.
(g) If you are required to submit notifications or reports following the procedure specified in this paragraph (g), you must submit notifications or reports to the EPA via CEDRI, which can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ). The EPA will make all the information submitted through CEDRI available to the public without further notice to you. Do not use CEDRI to submit information you claim as CBI. Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim for some of the information in the report or notification, you must submit a complete file in the format specified in this subpart, including information claimed to be CBI, to the EPA following the procedures in paragraphs (g)(1) and (2) of this section. Clearly mark the part or all of the information that you claim to be CBI. Information not marked as CBI may be authorized for public release without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. All CBI claims must be asserted at the time of submission. Anything submitted using CEDRI cannot later be claimed CBI. Furthermore, under CAA section 114(c), emissions data is not entitled to confidential treatment, and the EPA is required to make emissions data available to the public. Thus, emissions data will not be protected as CBI and will be made publicly available. You must submit the same file submitted to the CBI office with the CBI omitted to the EPA via the EPA's CDX as described earlier in this paragraph (g).
(1) The preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol, or other online file sharing services. Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address oaqpscbi@epa.gov , and as described above, should include clear CBI markings. ERT files should be flagged to the attention of the Group Leader, Measurement Policy Group; all other files should be flagged to the attention of the SOCMI NSPS Sector Lead. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email oaqpscbi@epa.gov to request a file transfer link.
(2) If you cannot transmit the file electronically, you may send CBI information through the postal service to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, North Carolina 27711. ERT files should be sent to the attention of the Group Leader, Measurement Policy Group, and all other files should be sent to the attention of the SOCMI NSPS Sector Lead. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.
(h) If you are required to electronically submit notifications or reports through CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for failure to timely comply with that reporting requirement. To assert a claim of EPA system outage, you must meet the requirements outlined in paragraphs (h)(1) through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI and submitting a required report within the time prescribed due to an outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time beginning five business days prior to the date that the submission is due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(5) You must provide to the Administrator a written description identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize the delay in reporting; and
(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.
(6) The decision to accept the claim of EPA system outage and allow an extension to the reporting deadline is solely within the discretion of the Administrator.
(7) In any circumstance, the report must be submitted electronically as soon as possible after the outage is resolved.
(i) If you are required to electronically submit notifications or reports through CEDRI in the EPA's CDX, you may assert a claim of force majeure for failure to timely comply with that reporting requirement. To assert a claim of force majeure, you must meet the requirements outlined in paragraphs (i)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to occur, occurs, or has occurred or there are lingering effects from such an event within the period of time beginning five business days prior to the date the submission is due. For the purposes of this section, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature ( e.g., hurricanes, earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility (e.g., large scale power outage).
(2) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize the delay in reporting; and
(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.
(4) The decision to accept the claim of force majeure and allow an extension to the reporting deadline is solely within the discretion of the Administrator.
(5) In any circumstance, the reporting must occur as soon as possible after the force majeure event occurs.
§ 60.488b   Reconstruction.
For the purposes of this subpart:
(a) The cost of the following frequently replaced components of the facility shall not be considered in calculating either the “fixed capital cost of the new components” or the “fixed capital costs that would be required to construct a comparable new facility” under § 60.15: Pump seals, nuts and bolts, rupture disks, and packings.
(b) Under § 60.15, the “fixed capital cost of new components” includes the fixed capital cost of all depreciable components (except components specified in § 60.488b(a)) which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following the applicability date for the appropriate subpart. (See the “Applicability and designation of affected facility” section of the appropriate subpart.) For purposes of this paragraph, “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.
§ 60.489b   List of chemicals produced by affected facilities.
Process units that produce, as intermediates or final products, chemicals listed in § 60.489 are covered under this subpart. The applicability date for process units producing one or more of these chemicals is April 25, 2023.
§ 60.490   Applicability and designation of affected facility.
(a) The provisions of this subpart apply to the following affected facilities in beverage can surface coating lines: each exterior base coat operation, each overvarnish coating operation, and each inside spray coating operation.
(b) The provisions of this subpart apply to each affected facility which is identified in paragraph (a) of this section and commences construction, modification, or reconstruction after November 26, 1980.
§ 60.491   Definitions.
(a) All terms which are used in this subpart and are not defined below are given the same meaning as in the Act and subpart A of this part.
(1) Beverage can means any two-piece steel or aluminum container in which soft drinks or beer, including malt liquor, are packaged. The definition does not include containers in which fruit or vegetable juices are packaged.
(2) Exterior base coating operation means the system on each beverage can surface coating line used to apply a coating to the exterior of a two-piece beverage can body. The exterior base coat provides corrosion resistance and a background for lithography or printing operations. The exterior base coat operation consists of the coating application station, flashoff area, and curing oven. The exterior base coat may be pigmented or clear (unpigmented).
(3) Inside spray coating operation means the system on each beverage can surface coating line used to apply a coating to the interior of a two-piece beverage can body. This coating provides a protective film between the contents of the beverage can and the metal can body. The inside spray coating operation consists of the coating application station, flashoff area, and curing oven. Multiple applications of an inside spray coating are considered to be a single coating operation.
(4) Overvarnish coating operation means the system on each beverage can surface coating line used to apply a coating over ink which reduces friction for automated beverage can filling equipment, provides gloss, and protects the finished beverage can body from abrasion and corrosion. The overvarnish coating is applied to two-piece beverage can bodies. The overvarnish coating operation consists of the coating application station, flashoff area, and curing oven.
(5) Two-piece can means any beverage can that consists of a body manufactured from a single piece of steel or aluminum and a top. Coatings for a two-piece can are usually applied after fabrication of the can body.
(6) VOC content means all volatile organic compounds (VOC) that are in a coating. VOC content is expressed in terms of kilograms of VOC per liter of coating solids.
(b) Notations used under § 60.493 of this subpart are defined below:
§ 60.492   Standards for volatile organic compounds.
On or after the date on which the initial performance test required by § 60.8(a) is completed, no owner or operator subject to the provisions of this subpart shall discharge or cause the discharge of VOC emissions to the atmoshpere that exceed the following volume-weighted calendar-month average emissions:
(a) 0.29 kilogram of VOC per litre of coating solids from each two-piece can exterior base coating operation, except clear base coat;
(b) 0.46 kilogram of VOC per litre of coating solids from each two-piece can clear base coating operation and from each overvarnish coating operation; and
(c) 0.89 kilogram of VOC per litre of coating solids from each two-piece can inside spray coating operation.
§ 60.493   Performance test and compliance provisions.
(a) Section 60.8(d) does not apply to monthly performance tests and § 60.8(f) does not apply to the performance test procedures required by this subpart.
(b) The owner or operator of an affected facility shall conduct an initial performance test as required under § 60.8(a) and thereafter a performance test each calendar month for each affected facility.
(1) The owner or operator shall use the following procedures for each affected facility that does not use a capture system and a control device to comply with the emission limit specified under § 60.492. The owner or operator shall determine the VOC-content of the coatings from formulation data supplied by the manufacturer of the coating or by an analysis of each coating, as received, using Method 24. The Administrator may require the owner or operator who uses formulation data supplied by the manufacturer of the coating to determine the VOC content of coatings using Method 24 or an equivalent or alternative method. The owner or operator shall determine from company records the volume of coating and the mass of VOC-solvent added to coatings. If a common coating distribution system serves more than one affected facility or serves both affected and exiting facilities, the owner or operator shall estimate the volume of coating used at each facility by using the average dry weight of coating, number of cans, and size of cans being processed by each affected and existing facility or by other procedures acceptable to the Administrator.
(i) Calculate the volume-weighted average of the total mass of VOC per volume of coating solids used during the calendar month for each affected facility, except as provided under paragraph (b)(1)(iv) of this section. The volume-weighted average of the total mass of VOC per volume of coating solids used each calendar month will be determined by the following procedures.
(A) Calculate the mass of VOC used (M o + M d ) during the calendar month for the affected facility by the following equation:
(B) Calculate the total volume of coating solids used (L s ) in the calendar month for the affected facility by the following equation:
(C) Calculate the volume-weighted average mass of VOC per volume of solids used (G) during the calendar month for the affected facility by the following equation:
(ii) Calculate the volume-weighted average of VOC emissions discharged to the atmosphere (N) during the calendar month for the affected facility by the following equation:
(iii) Where the value of the volume-weighted average mass of VOC per volume of solids discharged to the atmosphere (N) is equal to or less than the applicable emission limit specified under § 60.492, the affected facility is in compliance.
(iv) If each individual coating used by an affected facility has a VOC content equal to or less than the limit specified under § 60.492, the affected facility is in compliance provided no VOC-solvents are added to the coating during distribution or application.
(2) An owner or operator shall use the following procedures for each affected facility that uses a capture system and a control device that destroys VOC (e.g., incinerator) to comply with the emission limit specified under § 60.492.
(i) Determine the overall reduction efficiency (R) for the capture system and control device.
(A) Determine the fraction (F) of total VOC used by the affected facility that enters the control device using the following equation:
Table 1—Distribution of VOC Emissions
(B) Determine the destruction efficiency of the control device (E) using values of the volumetric flow rate of each of the gas streams and the VOC content (as carbon) of each of the gas streams in and out of the device by the following equation:
(C) Determine overall reduction efficiency (R) using the following equation:
(ii) Calculate the volume-weighted average of the total mass of VOC per volume of coating solids (G) used during the calendar month for the affected facility using equations (1), (2), and (3).
(iii) Calculate the volume-weighted average of VOC emissions discharged to the atmosphere (N) during the calendar month by the following equation:
(iv) If the volume-weighted average of mass of VOC emitted to the atmosphere for the calendar month (N) is equal to or less than the applicable emission limit specified under § 60.492, the affected facility is in compliance.
(3) An owner or operator shall use the following procedure for each affected facility that uses a capture system and a control device that recovers the VOC (e.g., carbon adsorber) to comply with the applicable emission limit specified under § 60.492.
(i) Calculate the volume-weighted average of the total mass of VOC per unit volume of coating solids applied (G) used during the calendar month for the affected facility using equations (1), (2), and (3).
(ii) Calculate the total mass of VOC recovered (M r ) during each calendar month using the following equation:
(iii) Calculate overall reduction efficiency of the control device (R) for the calendar month for the affected facility using the following equation:
(iv) Calculate the volume-weighted average mass of VOC discharged to the atmosphere (N) for the calendar month for the afffected facility using equation (8).
(v) If the weighted average of VOC emitted to the atmosphere for the calendar month (N) is equal to or less than the applicable emission limit specified under § 60.492, the affected facility is in compliance.
§ 60.494   Monitoring of emissions and operations.
The owner or operator of an affected facility that uses a capture system and an incinerator to comply with the emission limits specified under § 60.492 shall install, calibrate, maintain, and operate temperature measurement devices as prescribed below.
(a) Where thermal incineration is used, a temperature measurement device shall be installed in the firebox. Where catalytic incineration is used, temperature measurement devices shall be installed in the gas stream immediately before and after the catalyst bed.
(b) Each temperature measurement device shall be installed, calibrated, and maintained according to the manufacturer's specifications. The device shall have an accuracy of 0.75 percent of the temperature being measured, expressed in degrees Celsius, or ±2.5 °C, whichever is greater.
(c) Each temperature measurement device shall be equipped with a recording device so that a permanent continuous record is produced.
§ 60.495   Reporting and recordkeeping requirements.
(a) The owner or operator of an affected facility shall include the following data in the initial compliance report required under § 60.8(a).
(1) Where only coatings which individually have a VOC content equal to or less than the limits specified under § 60.492 are used, and no VOC is added to the coating during the application or distribution process, the owner or operator shall provide a list of the coatings used for each affected facility and the VOC content of each coating calculated from data determined using Method 24 or supplied by the manufacturers of the coatings.
(2) Where one or more coatings which individually have a VOC content greater than the limits specified under § 60.492 are used or where VOC are added or used in the coating process, the owner or operator shall report for each affected facility the volume-weighted average of the total mass of VOC per volume of coating solids.
(3) Where compliance is achieved through the use of incineration, the owner or operator shall include in the initial performance test required under § 60.8(a) the combustion temperature (or the gas temperature upstream and downstream of the catalyst bed), the total mass of VOC per volume of coating solids before and after the incinerator, capture efficiency, and the destruction efficiency of the incinerator used to attain compliance with the applicable emission limit specified under § 60.492. The owner or operator shall also include a description of the method used to establish the amount of VOC captured by the capture system and sent to the control device.
(b) Following the initial performance test, each owner or operator shall identify, record, and submit quarterly reports to the Administrator of each instance in which the volume-weighted average of the total mass of VOC per volume of coating solids, after the control device, if capture devices and control systems are used, is greater than the limit specified under § 60.492. If no such instances occur during a particular quarter, a report stating this shall be submitted to the Administrator semiannually.
(c) Following the initial performance test, the owner or operator of an affected facility shall identify, record, and submit at the frequency specified in § 60.7(c) the following:
(1) Where compliance with § 60.492 is achieved through the use of thermal incineration, each 3-hour period when cans are processed, during which the average temperature of the device was more than 28 °C below the average temperature of the device during the most recent performance test at which destruction efficiency was determined as specified under § 60.493.
(2) Where compliance with § 60.492 is achieved through the use of catalytic incineration, each 3-hour period when cans are being processed, during which the average temperature of the device immediately before the catalyst bed is more than 28 °C below the average temperature of the device immediately before the catalyst bed during the most recent performance test at which destruction efficiency was determined as specified under § 60.493 and all 3-hour periods, when cans are being processed, during which the average temperature difference across the catalyst bed is less than 80 percent of the average temperature difference across the catalyst bed during the most recent performance test at which destruction efficiency was determined as specified under § 60.494.
(3) For thermal and catalytic incinerators, if no such periods as described in paragraphs (c)(1) and (c)(2) of this section occur, the owner or operator shall state this in the report.
(d) Each owner or operator subject to the provisions of this subpart shall maintain at the source, for a period of at least 2 years, records of all data and calculations used to determine VOC emissions from each affected facility in the initial and monthly performance tests. Where compliance is achieved through the use of thermal incineration, each owner or operator shall maintain, at the source, daily records of the incinerator combustion chamber temperature. If catalytic incineration is used, the owner or operator shall maintain at the source daily records of the gas temperature, both upstream and downstream of the incinerator catalyst bed. Where compliance is achieved through the use of a solvent recovery system, the owner or operator shall maintain at the source daily records of the amount of solvent recovered by the system for each affected facility.
(e) The requirements of this section remain in force until and unless EPA, in delegating enforcement authority to a State under section 111(c) of the Act, approves reporting requirements or an alternative means of compliance surveillance adopted by such State. In that event, affected facilities within the State will be relieved of the obligation to comply with this subsection, provided that they comply with the requirements established by the State.
§ 60.496   Test methods and procedures.
(a) The reference methods in appendix A to this part, except as provided in § 60.8, shall be used to conduct performance tests.
(1) Method 24, an equivalent or alternative method approved by the Administrator, or manufacturers' formulation data from which the VOC content of the coatings used for each affected facility can be calculated. In the event of a dispute, Method 24 data shall govern. When VOC content of water-borne coatings, determined from data generated by Method 24, is used to determine compliance of affected facilities, the results of the Method 24 analysis shall be adjusted as described in Section 12.6 of Method 24.
(2) Method 25 or an equivalent or alternative method for the determination of the VOC concentration in the effluent gas entering and leaving the control device for each stack equipped with an emission control device. The owner or operator shall notify the Administrator at least 30 days in advance of any State test using Method 25. The following reference methods are to be used in conjunction with Method 25:
(i) Method 1 for sample and velocity traverses,
(ii) Method 2 for velocity and volumetric flow rate,
(iii) Method 3 for gas analysis, and
(iv) Method 4 for stack gas moisture.
(b) For Method 24, the coating sample must be a 1-litre sample collected in a 1-litre container at a point where the sample will be representative of the coating material.
(c) For Method 25, the sampling time for each of three runs must be at least 1 hour. The minimum sample volume must be 0.003 dscm except that shorter sampling times or smaller volumes, when necessitated by process variables or other factors, may be approved by the Administrator. The Administrator will approve the sampling of representative stacks on a case-by-case basis if the owner or operator can demonstrate to the satisfaction of the Administrator that the testing of representative stacks would yield results comparable to those that would be obtained by testing all stacks.
§ 60.500   Applicability and designation of affected facility.
(a) The affected facility to which the provisions of this subpart apply is the total of all the loading racks at a bulk gasoline terminal which deliver liquid product into gasoline tank trucks.
(b) Each facility under paragraph (a) of this section, the construction or modification of which is commenced after December 17, 1980, and on or before June 10, 2022, is subject to the provisions of this subpart.
(c) For purposes of this subpart, any replacement of components of an existing facility, described in paragraph (a) of this section, commenced before August 18, 1983 in order to comply with any emission standard adopted by a State or political subdivision thereof will not be considered a reconstruction under the provisions of 40 CFR 60.15.
The intent of these standards is to minimize the emissions of VOC through the application of best demonstrated technologies (BDT). The numerical emission limits in this standard are expressed in terms of total organic compounds. This emission limit reflects the performance of BDT.
§ 60.501   Definitions.
The terms used in this subpart are defined in the Clean Air Act, in § 60.2 of this part, or in this section as follows:
Bulk gasoline terminal means any gasoline facility which receives gasoline by pipeline, ship or barge, and has a gasoline throughput greater than 75,700 liters per day. Gasoline throughput shall be the maximum calculated design throughput as may be limited by compliance with an enforceable condition under Federal, State or local law and discoverable by the Administrator and any other person.
Continuous vapor processing system means a vapor processing system that treats total organic compounds vapors collected from gasoline tank trucks on a demand basis without intermediate accumulation in a vapor holder.
Existing vapor processing system means a vapor processing system [capable of achieving emissions to the atmosphere no greater than 80 milligrams of total organic compounds per liter of gasoline loaded], the construction or refurbishment of which was commenced before December 17, 1980, and which was not constructed or refurbished after that date.
Flare means a thermal oxidation system using an open (without enclosure) flame.
Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid vapor pressure of 27.6 kilopascals or greater which is used as a fuel for internal combustion engines.
Gasoline tank truck means a delivery tank truck used at bulk gasoline terminals which is loading gasoline or which has loaded gasoline on the immediately previous load.
Intermittent vapor processing system means a vapor processing system that employs an intermediate vapor holder to accumulate total organic compounds vapors collected from gasoline tank trucks, and treats the accumulated vapors only during automatically controlled cycles.
Loading rack means the loading arms, pumps, meters, shutoff valves, relief valves, and other piping and valves necessary to fill delivery tank trucks.
Refurbishment means, with reference to a vapor processing system, replacement of components of, or addition of components to, the system within any 2-year period such that the fixed capital cost of the new components required for such component replacement or addition exceeds 50 percent of the cost of a comparable entirely new system.
Thermal oxidation system means a combustion device used to mix and ignite fuel, air pollutants, and air to provide a flame to heat and oxidize hazardous air pollutants. Auxiliary fuel may be used to heat air pollutants to combustion temperatures.
Total organic compounds means those compounds measured according to the procedures in § 60.503.
Vapor collection system means any equipment used for containing total organic compounds vapors displaced during the loading of gasoline tank trucks.
Vapor processing system means all equipment used for recovering or oxidizing total organic compounds vapors displaced from the affected facility.
Vapor-tight gasoline tank truck means a gasoline tank truck which has demonstrated within the 12 preceding months that its product delivery tank will sustain a pressure change of not more than 750 pascals (75 mm of water) within 5 minutes after it is pressurized to 4,500 pascals (450 mm of water). This capability is to be demonstrated using the pressure test procedure specified in Method 27.
§ 60.502   Standard for Volatile Organic Compound (VOC) emissions from bulk gasoline terminals.
On and after the date on which § 60.8(a) requires a performance test to be completed, the owner or operator of each bulk gasoline terminal containing an affected facility shall comply with the requirements of this section.
(a) Each affected facility shall be equipped with a vapor collection system designed to collect the total organic compounds vapors displaced from tank trucks during product loading.
(b) The emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline tank trucks are not to exceed 35 milligrams of total organic compounds per liter of gasoline loaded, except as noted in paragraph (c) of this section.
(c) For each affected facility equipped with an existing vapor processing system, the emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline tank trucks are not to exceed 80 milligrams of total organic compounds per liter of gasoline loaded.
(d) Each vapor collection system shall be designed to prevent any total organic compounds vapors collected at one loading rack from passing to another loading rack.
(e) Loadings of liquid product into gasoline tank trucks shall be limited to vapor-tight gasoline tank trucks using the following procedures:
(1) The owner or operator shall obtain the vapor tightness documentation described in § 60.505(b) for each gasoline tank truck which is to be loaded at the affected facility.
(2) The owner or operator shall require the tank identification number to be recorded as each gasoline tank truck is loaded at the affected facility.
(3)(i) The owner or operator shall cross-check each tank identification number obtained in paragraph (e)(2) of this section with the file of tank vapor tightness documentation within 2 weeks after the corresponding tank is loaded, unless either of the following conditions is maintained:
(A) If less than an average of one gasoline tank truck per month over the last 26 weeks is loaded without vapor tightness documentation then the documentation cross-check shall be performed each quarter; or
(B) If less than an average of one gasoline tank truck per month over the last 52 weeks is loaded without vapor tightness documentation then the documentation cross-check shall be performed semiannually.
(ii) If either the quarterly or semiannual cross-check provided in paragraphs (e)(3)(i) (A) through (B) of this section reveals that these conditions were not maintained, the source must return to biweekly monitoring until such time as these conditions are again met.
(4) The terminal owner or operator shall notify the owner or operator of each non-vapor-tight gasoline tank truck loaded at the affected facility within 1 week of the documentation cross-check in paragraph (e)(3) of this section.
(5) The terminal owner or operator shall take steps assuring that the nonvapor-tight gasoline tank truck will not be reloaded at the affected facility until vapor tightness documentation for that tank is obtained.
(6) Alternate procedures to those described in paragraphs (e)(1) through (5) of this section for limiting gasoline tank truck loadings may be used upon application to, and approval by, the Administrator.
(f) The owner or operator shall act to assure that loadings of gasoline tank trucks at the affected facility are made only into tanks equipped with vapor collection equipment that is compatible with the terminal's vapor collection system.
(g) The owner or operator shall act to assure that the terminal's and the tank truck's vapor collection systems are connected during each loading of a gasoline tank truck at the affected facility. Examples of actions to accomplish this include training drivers in the hookup procedures and posting visible reminder signs at the affected loading racks.
(h) The vapor collection and liquid loading equipment shall be designed and operated to prevent gauge pressure in the delivery tank from exceeding 4,500 pascals (450 mm of water) during product loading. This level is not to be exceeded when measured by the procedures specified in § 60.503(d).
(i) No pressure-vacuum vent in the bulk gasoline terminal's vapor collection system shall begin to open at a system pressure less than 4,500 pascals (450 mm of water).
(j) Each calendar month, the vapor collection system, the vapor processing system, and each loading rack handling gasoline shall be inspected during the loading of gasoline tank trucks for total organic compounds liquid or vapor leaks. For purposes of this paragraph, detection methods incorporating sight, sound, or smell are acceptable. Each detection of a leak shall be recorded and the source of the leak repaired within 15 calendar days after it is detected.
§ 60.503   Test methods and procedures.
(a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). The three-run requirement of § 60.8(f) does not apply to this subpart.
(b) Immediately before the performance test required to determine compliance with § 60.502 (b), (c), and (h), the owner or operator shall use Method 21 to monitor for leakage of vapor all potential sources in the terminal's vapor collection system equipment while a gasoline tank truck is being loaded. The owner or operator shall repair all leaks with readings of 10,000 ppm (as methane) or greater before conducting the performance test.
(c) The owner or operator shall determine compliance with the standards in § 60.502 (b) and (c) as follows:
(1) The performance test shall be 6 hours long during which at least 300,000 liters of gasoline is loaded. If this is not possible, the test may be continued the same day until 300,000 liters of gasoline is loaded or the test may be resumed the next day with another complete 6-hour period. In the latter case, the 300,000-liter criterion need not be met. However, as much as possible, testing should be conducted during the 6-hour period in which the highest throughput normally occurs.
(2) If the vapor processing system is intermittent in operation, the performance test shall begin at a reference vapor holder level and shall end at the same reference point. The test shall include at least two startups and shutdowns of the vapor processor. If this does not occur under automatically controlled operations, the system shall be manually controlled.
(3) The emission rate (E) of total organic compounds shall be computed using the following equation:
(4) The performance test shall be conducted in intervals of 5 minutes. For each interval “i”, readings from each measurement shall be recorded, and the volume exhausted (V esi ) and the corresponding average total organic compounds concentration (C ei ) shall be determined. The sampling system response time shall be considered in determining the average total organic compounds concentration corresponding to the volume exhausted.
(5) The following methods shall be used to determine the volume (V esi ) air-vapor mixture exhausted at each interval:
(i) Method 2B shall be used for combustion vapor processing systems.
(ii) Method 2A shall be used for all other vapor processing systems.
(6) Method 25A or 25B shall be used for determining the total organic compounds concentration (C ei ) at each interval. The calibration gas shall be either propane or butane. The owner or operator may exclude the methane and ethane content in the exhaust vent by any method (e.g., Method 18) approved by the Administrator.
(7) To determine the volume (L) of gasoline dispensed during the performance test period at all loading racks whose vapor emissions are controlled by the processing system being tested, terminal records or readings from gasoline dispensing meters at each loading rack shall be used.
(d) The owner or operator shall determine compliance with the standard in § 60.502(h) as follows:
(1) A pressure measurement device (liquid manometer, magnehelic gauge, or equivalent instrument), capable of measuring up to 500 mm of water gauge pressure with ±2.5 mm of water precision, shall be calibrated and installed on the terminal's vapor collection system at a pressure tap located as close as possible to the connection with the gasoline tank truck.
(2) During the performance test, the pressure shall be recorded every 5 minutes while a gasoline truck is being loaded; the highest instantaneous pressure that occurs during each loading shall also be recorded. Every loading position must be tested at least once during the performance test.
(e) The performance test requirements of paragraph (c) of this section do not apply to flares defined in § 60.501 and meeting the requirements in § 60.18(b) through (f). The owner or operator shall demonstrate that the flare and associated vapor collection system is in compliance with the requirements in §§ 60.18(b) through (f) and 60.503(a), (b), and (d).
(f) The owner or operator shall use alternative test methods and procedures in accordance with the alternative test method provisions in § 60.8(b) for flares that do not meet the requirements in § 60.18(b).
§ 60.504   [Reserved]
§ 60.505   Reporting and recordkeeping.
(a) The tank truck vapor tightness documentation required under § 60.502(e)(1) shall be kept on file at the terminal in a permanent form available for inspection.
(b) The documentation file for each gasoline tank truck shall be updated at least once per year to reflect current test results as determined by Method 27. This documentation shall include, as a minimum, the following information:
(1) Test title: Gasoline Delivery Tank Pressure Test—EPA Reference Method 27.
(2) Tank owner and address.
(3) Tank identification number.
(4) Testing location.
(5) Date of test.
(6) Tester name and signature.
(7) Witnessing inspector, if any: Name, signature, and affiliation.
(8) Test results: Actual pressure change in 5 minutes, mm of water (average for 2 runs).
(c) A record of each monthly leak inspection required under § 60.502(j) shall be kept on file at the terminal for at least 2 years. Inspection records shall include, as a minimum, the following information:
(1) Date of inspection.
(2) Findings (may indicate no leaks discovered; or location, nature, and severity of each leak).
(3) Leak determination method.
(4) Corrective action (date each leak repaired; reasons for any repair interval in excess of 15 days).
(5) Inspector name and signature.
(d) The terminal owner or operator shall keep documentation of all notifications required under § 60.502(e)(4) on file at the terminal for at least 2 years.
(e) As an alternative to keeping records at the terminal of each gasoline cargo tank test result as required in paragraphs (a), (c), and (d) of this section, an owner or operator may comply with the requirements in either paragraph (e)(1) or (2) of this section.
(1) An electronic copy of each record is instantly available at the terminal.
(i) The copy of each record in paragraph (e)(1) of this section is an exact duplicate image of the original paper record with certifying signatures.
(ii) The permitting authority is notified in writing that each terminal using this alternative is in compliance with paragraph (e)(1) of this section.
(2) For facilities that utilize a terminal automation system to prevent gasoline cargo tanks that do not have valid cargo tank vapor tightness documentation from loading ( e.g., via a card lock-out system), a copy of the documentation is made available ( e.g., via facsimile) for inspection by permitting authority representatives during the course of a site visit, or within a mutually agreeable time frame.
(i) The copy of each record in paragraph (e)(2) of this section is an exact duplicate image of the original paper record with certifying signatures.
(ii) The permitting authority is notified in writing that each terminal using this alternative is in compliance with paragraph (e)(2) of this section.
(f) The owner or operator of an affected facility shall keep records of all replacements or additions of components performed on an existing vapor processing system for at least 3 years.
§ 60.506   Reconstruction.
For purposes of this subpart:
(a) The cost of the following frequently replaced components of the affected facility shall not be considered in calculating either the “fixed capital cost of the new components” or the “fixed capital costs that would be required to construct a comparable entirely new facility” under § 60.15: pump seals, loading arm gaskets and swivels, coupler gaskets, overfill sensor couplers and cables, flexible vapor hoses, and grounding cables and connectors.
(b) Under § 60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components (except components specified in § 60.506(a)) which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following December 17, 1980. For purposes of this paragraph, “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.
§ 60.500a   Applicability and designation of affected facility.
(a) You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the affected facilities listed in paragraphs (a)(1) and (2) of this section.
(1) Each gasoline loading rack affected facility, which is the total of all the loading racks at a bulk gasoline terminal that deliver liquid product into gasoline cargo tanks including the gasoline loading racks, the vapor collection systems, and the vapor processing system.
(2) Each collection of equipment at a bulk gasoline terminal affected facility, which is the total of all equipment associated with the loading of gasoline at a bulk gasoline terminal including the lines and pumps transferring gasoline from storage vessels, the gasoline loading racks, the vapor collection systems, and the vapor processing system.
(b) Each affected facility under paragraph (a) of this section for which construction, modification (as defined in § 60.2 and detailed in § 60.14), or reconstruction (as detailed in § 60.15 and paragraph (e) of this section) is commenced after June 10, 2022, is subject to the provisions of this subpart.
(c) All standards including emission limitations shall apply at all times, including periods of startup, shutdown, and malfunction. As provided in § 60.11(f), this paragraph (c) supersedes the exemptions for periods of startup, shutdown, and malfunction in subpart A of this part.
(d) A newly constructed gasoline loading rack affected facility that was subject to the standards in § 60.502a(b) will continue to be subject to the standards in § 60.502a(b) for newly constructed gasoline loading rack affected facilities if they are subsequently modified or reconstructed.
(e) For purposes of this subpart:
(1) The cost of the following frequently replaced components of the gasoline loading rack affected facility shall not be considered in calculating either the “fixed capital cost of the new components” or the “fixed capital cost that would be required to construct a comparable entirely new facility” under § 60.15: pump seals, loading arm gaskets and swivels, coupler gaskets, overfill sensor couplers and cables, flexible vapor hoses, and grounding cables and connectors.
(2) Under § 60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components, except components specified in paragraph (e)(1) of this section which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following June 10, 2022. For purposes of this paragraph (e)(2), “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.
§ 60.501a   Definitions.
The terms used in this subpart are defined in the Clean Air Act, in § 60.2, or in this section as follows:
3-hour rolling average means the arithmetic mean of the previous thirty-six 5-minute periods of valid operating data collected, as specified, for the monitored parameter. Valid data excludes data collected during periods when the monitoring system is out of control, while conducting repairs associated with periods when the monitoring system is out of control, or while conducting required monitoring system quality assurance or quality control activities. The thirty-six 5-minute periods should be consecutive, but not necessarily continuous if operations or the collection of valid data were intermittent.
Bulk gasoline terminal means any gasoline facility which receives gasoline by pipeline, ship, barge, or cargo tank and subsequently loads all or a portion of the gasoline into gasoline cargo tanks for transport to bulk gasoline plants or gasoline dispensing facilities and has a gasoline throughput greater than 20,000 gallons per day (75,700 liters per day). Gasoline throughput shall be the maximum calculated design throughput for the facility as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.
Continuous monitoring system is a comprehensive term that may include, but is not limited to, continuous emission monitoring systems, continuous parameter monitoring systems, or other manual or automatic monitoring that is used for demonstrating compliance on a continuous basis.
Equipment means each valve, pump, pressure relief device, open-ended valve or line, sampling connection system, and flange or other connector in the gasoline liquid transfer and vapor collection systems. This definition also includes the entire vapor processing system except the exhaust port(s) or stack(s).
Flare means a thermal combustion device using an open or shrouded flame (without full enclosure) such that the pollutants are not emitted through a conveyance suitable to conduct a performance test.
Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid vapor pressure of 4.0 pounds per square inch (27.6 kilopascals) or greater which is used as a fuel for internal combustion engines.
Gasoline cargo tank means a delivery tank truck or railcar which is loading gasoline or which has loaded gasoline on the immediately previous load.
In gasoline service means that a piece of equipment is used in a system that transfers gasoline or gasoline vapors.
Loading rack means the loading arms, pumps, meters, shutoff valves, relief valves, and other piping and valves necessary to fill gasoline cargo tanks.
Submerged filling means the filling of a gasoline cargo tank through a submerged fill pipe whose discharge is no more than the 6 inches from the bottom of the tank. Bottom filling of gasoline cargo tanks is included in this definition.
Thermal oxidation system means an enclosed combustion device used to mix and ignite fuel, air pollutants, and air to provide a flame to heat and oxidize air pollutants. Auxiliary fuel may be used to heat air pollutants to combustion temperatures. Thermal oxidation systems emit pollutants through a conveyance suitable to conduct a performance test.
Total organic compounds (TOC) means those compounds measured according to the procedures in Method 25, 25A, or 25B of appendix A-7 to this part. The methane content may be excluded from the TOC concentration as described in § 60.503a.
Vapor collection system means any equipment used for containing total organic compounds vapors displaced during the loading of gasoline cargo tanks.
Vapor processing system means all equipment used for recovering or oxidizing total organic compounds vapors displaced from the affected facility.
Vapor recovery system means processing equipment used to absorb and/or condense collected vapors and return the total organic compounds for blending with gasoline or other petroleum products or return to a petroleum refinery or transmix facility for further processing. Vapor recovery systems include but are not limited to carbon adsorption systems or refrigerated condensers.
Vapor-tight gasoline cargo tank means a gasoline cargo tank which has demonstrated within the 12 preceding months that it meets the annual certification test requirements in § 60.503a(f).
§ 60.502a   Standard for volatile organic compound (VOC) emissions from bulk gasoline terminals.
(a) Each gasoline loading rack affected facility shall be equipped with a vapor collection system designed and operated to collect the total organic compounds vapors displaced from gasoline cargo tanks during product loading.
(b) For each newly constructed gasoline loading rack affected facility, the facility owner or operator must meet the applicable emission limitations in paragraph (b)(1) or (2) of this section no later than the date on which § 60.8(a) requires a performance test to be completed. A flare cannot be used to comply with the emission limitations in this paragraph (b).
(1) If a thermal oxidation system is used, maintain the emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline cargo tanks at or below 1.0 milligram of total organic compounds per liter of gasoline loaded (mg/L). Continual compliance with this requirement must be demonstrated as specified in paragraphs (b)(1)(i) and (ii) of this section.
(i) Conduct initial and periodic performance tests as specified in § 60.503a(a) through (c) and meet the emission limitation in this paragraph (b)(1).
(ii) Maintain combustion zone temperature of the thermal oxidation system at or above the 3-hour rolling average operating limit established during the performance test when loading liquid product into gasoline cargo tanks. Valid operating data must exclude periods when there is no liquid product being loaded. If previous contents of the cargo tanks are known, you may also exclude periods when liquid product is loaded but no gasoline cargo tanks are being loaded provided that you excluded these periods in the determination of the combustion zone temperature operating limit according to the provisions in § 60.503a(c)(8)(ii).
(2) If a vapor recovery system is used:
(i) Maintain the emissions to the atmosphere from the vapor collection system at or below 550 parts per million by volume (ppmv) of TOC as propane determined on a 3-hour rolling average when the vapor recovery system is operating;
(ii) Operate the vapor recovery system during all periods when the vapor recovery system is capable of processing gasoline vapors, including periods when liquid product is being loaded, during carbon bed regeneration, and when preparing the beds for reuse; and
(iii) Operate the vapor recovery system to minimize air or nitrogen intrusion except as needed for the system to operate as designed for the purpose of removing VOC from the adsorption media or to break vacuum in the system and bring the system back to atmospheric pressure. Consistent with § 60.12, the use of gaseous diluents to achieve compliance with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere is prohibited.
(c) For each modified or reconstructed gasoline loading rack affected facility, the facility owner or operator must meet the applicable emission limitations in paragraphs (c)(1) through (3) of this section no later than the date on which § 60.8(a) requires a performance test to be completed.
(1) If a thermal oxidation system is used, maintain the emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline cargo tanks at or below 10 mg/L. Continual compliance with this requirement must be demonstrated as specified in paragraphs (c)(1)(i) through (iii) of this section.
(i) Conduct initial and periodic performance tests as specified in § 60.503a(a) through (c) and meet the emission limitation in this paragraph (c)(1).
(ii) Maintain combustion zone temperature of the thermal oxidation system at or above the 3-hour rolling average operating limit established during the performance test when loading liquid product into gasoline cargo tanks. Valid operating data must exclude periods when there is no liquid product being loaded. If previous contents of the cargo tanks are known, you may also exclude periods when liquid product is loaded but no gasoline cargo tanks are being loaded provided that you excluded these periods in the determination of the combustion zone temperature operating limit according to the provisions in § 60.503a(c)(8)(ii).
(iii) As an alternative to the combustion zone temperature operating limit, you may elect to use the monitoring provisions as specified in paragraph (c)(3) of this section.
(2) If a vapor recovery system is used:
(i) Maintain the emissions to the atmosphere from the vapor collection system at or below 5,500 ppmv of TOC as propane determined on a 3-hour rolling average when the vapor recovery system is operating;
(ii) Operate the vapor recovery system during all periods when the vapor recovery system is capable of processing gasoline vapors, including periods when liquid product is being loaded, during carbon bed regeneration, and when preparing the beds for reuse; and
(iii) Operate the vapor recovery system to minimize air or nitrogen intrusion except as needed for the system to operate as designed for the purpose of removing VOC from the adsorption media or to break vacuum in the system and bring the system back to atmospheric pressure. Consistent with § 60.12, the use of gaseous diluents to achieve compliance with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere is prohibited.
(3) If a flare is used or if a thermal oxidation system for which these provisions are specified as a monitoring alternative is used, meet all applicable requirements specified in § 63.670(b) through (g) and (i) through (n) of this chapter except as provided in paragraphs (c)(3)(i) through (ix) of this section.
(i) For the purpose of this subpart, “regulated materials” refers to “vapors displaced from gasoline cargo tanks during product loading”. If you do not know the previous contents of the cargo tank, you must assume that cargo tank is a gasoline cargo tank.
(ii) In § 63.670(c) of this chapter for visible emissions:
(A) The phrase “specify the smokeless design capacity of each flare and” does not apply.
(B) The phrase “and the flare vent gas flow rate is less than the smokeless design capacity of the flare” does not apply.
(C) Substitute “The owner or operator shall monitor for visible emissions from the flare as specified in § 60.504a(c)(4).” for the sentence “The owner or operator shall monitor for visible emissions from the flare as specified in paragraph (h) of this section.”
(iii) The phrase “and the flare vent gas flow rate is less than the smokeless design capacity of the flare” in § 63.670(d) of this chapter for flare tip velocity requirements does not apply.
(iv) Substitute “pilot flame or flare flame” for each occurrence of “pilot flame.”
(v) Substitute “gasoline distribution facility” for each occurrence of “petroleum refinery” or “refinery.”
(vi) As an alternative to the flow rate monitoring alternatives provided in § 63.670(i) of this chapter, you may elect to determine flare waste gas flow rate by monitoring the cumulative loading rates of all liquid products loaded into cargo tanks for which the displaced vapors are managed by the affected facility's vapor collection system and vapor processing system.
(vii) If using provision in § 63.670(j)(6) of this chapter for flare vent gas composition monitoring, you must comply with those provisions as specified in paragraphs (c)(3)(vii)(A) through (G) of this section.
(A) You must submit a separate written application to the Administrator for an exemption from monitoring, as described in § 63.670(j)(6)(i) of this chapter.
(B) You must determine the minimum ratio of gasoline loaded to total liquid product loaded for which the affected source must operate at or above at all times when liquid product is loaded into cargo tanks for which vapors collected are sent to the flare or, if applicable, thermal oxidation system and include that in the explanation of conditions expected to produce the flare gas with lowest net heating value as required in § 63.670(j)(6)(i)(C) of this chapter. For air assisted flares or thermal oxidation systems, you must also establish a minimum gasoline loading rate ( i.e., volume of gasoline loaded in a 15-minute period) for which the affected source must operate at or above at all times and include that in the explanation of conditions that ensure the flare gas net heating value is consistent and representative of the lowest net heating value as required in § 63.670(j)(6)(i)(C).
(C) As required in § 63.670(j)(6)(i)(D) of this chapter, samples must be collected at the conditions identified in § 63.670(j)(6)(i)(C) of this chapter, which includes the applicable conditions specified in paragraph (c)(3)(vii)(B) of this section.
(D) The first change from winter gasoline to summer gasoline or from summer gasoline to winter gasoline, whichever comes first, is considered a change in operating conditions under § 63.670(j)(6)(iii) of this chapter and must be evaluated according to the provisions in § 63.670(j)(6)(iii). If separate net heating values are determined for summer gasoline loading versus winter gasoline loading, you may use the summer net heating value for all subsequent summer gasoline loading operations and the winter net heating value for all subsequent winter gasoline loading operations provided there are no other changes in operations.
(E) You must monitor the volume of gasoline loaded and the total volume of liquid product loaded on a 5-minute block basis and maintain the ratio of gasoline loaded to total liquid product loaded at or above the value determined in paragraph (c)(3)(vii)(B) of this section and, for air assisted flares or thermal oxidation systems, maintain the gasoline loading rate at or above the value determined in paragraph (c)(3)(vii)(B) on a rolling 15-minute period basis, calculated based on liquid product loaded during 3 contiguous 5-minute blocks, considering only those periods when liquid product is loaded into gasoline cargo tanks for any portion of three contiguous 5-minute block periods.
(F) For unassisted or perimeter air assisted flares or thermal oxidation systems, if the net heating value determined in § 63.670(j)(6)(i)(F) of this chapter meets or exceeds 270 British thermal units per standard cubic feet (Btu/scf), compliance with the ratio of gasoline loaded to total liquid product loaded as specified in paragraph (c)(3)(vii)(E) of this section demonstrates compliance with the flare combustion zone net heating value (NHV cz ) operating limit in § 63.670(e) of this chapter.
(G) For perimeter air assisted flares or thermal oxidation systems, if the net heating value determined in § 63.670(j)(6)(i)(F) of this chapter meets or exceeds the net heating value dilution parameter (NHV dil ) operating limit of 22 British thermal units per square foot (Btu/ft 2 ) at the flow rate associated with the minimum gasoline loading rate determined in paragraph (c)(3)(vii)(B) of this section at any air assist rate used, compliance with the minimum gasoline loading rate as specified in paragraph (c)(3)(vii)(E) of this section demonstrates compliance with the NHV dil operating limit in § 63.670(f) of this chapter.
(viii) You may elect to establish a minimum supplemental gas addition rate and monitor the supplemental gas addition rate, in addition to the operating limits in paragraph (c)(3)(vii)(E) of this section, to demonstrate compliance with the flare combustion zone operating limit in § 63.670(e) of this chapter and, if applicable, flare dilution operating limit in § 63.670(f) of this chapter, as follows.
(A) Use the minimum flare vent gas net heating value prior to addition of supplemental gas as established in paragraph (c)(3)(vii) of this section.
(B) Determine the maximum flow rate based on the maximum cumulative loading rate for a 15-minute block period considering all loading racks at the affected facility and considering restrictions on maximum loading rates necessary for compliance with the maximum pressure limits for the vapor collection and liquid loading equipment specified in paragraph (h) of this section.
(C) Determine the supplemental gas addition rate needed to yield NHV cz of 270 Btu/scf using equation in § 63.670(m)(1) of this chapter.
(D) For flares (or thermal oxidation systems) with perimeter assist air, determine the supplemental gas addition rate needed to yield NHV dil of 22 Btu/ft 2 using equation in § 63.670(n)(1) of this chapter at the flare vent gas net heating value determined in paragraph (c)(3)(vii) of this section, the flare gas flow rate associated with the minimum gasoline loading rate as determined in paragraph (c)(3)(vii)(B) of this section, and the fixed air assist rate. If the air assist rate is varied based on total liquid product loading rates, you must use the air assist rate used at low flow rates and repeat the calculation using the minimum flow rate associated with each air assist rate setting and select the maximum supplemental gas addition rate across any of the air assist rate settings.
(E) Maintain the supplemental gas addition rate above the greater of the values determined in paragraphs (c)(3)(viii)(C) and, if applicable, (c)(3)(viii)(D) of this section on a 15-minute block period basis when liquid product is loaded into gasoline cargo tanks for at least 15-minutes.
(ix) As an alternative to determining the flare tip velocity rate for each 15-minute block to determine compliance with the flare tip velocity operating limit as specified in § 63.670(k)(2) of this chapter, you may elect to conduct a one-time flare tip velocity operating limit compliance assessment as provided in paragraphs (c)(3)(ix)(A) through (D) of this section. If the flare or loading rack configurations change ( e.g., flare tip modified or additional loading racks are added for which vapors are directed to the flare), you must repeat this one-time assessment based on the new configuration.
(A) Determine the unobstructed cross-sectional area of the flare tip, in units of square feet, as specified in § 63.670(k)(1) of this chapter.
(B) Determine the maximum flow rate, in units of cubic feet per second, based on the maximum cumulative loading rate for a 15-minute block period considering all loading racks at the gasoline loading racks affected facility and considering restrictions on maximum loading rates necessary for compliance with the maximum pressure limits for the vapor collection and liquid loading equipment specified in paragraph (h) of this section.
(C) Calculate the maximum flare tip velocity as the maximum flow rate from paragraph (c)(3)(ix)(B) of this section divided by the unobstructed cross-sectional area of the flare tip from paragraph (c)(3)(ix)(A) of this section.
(D) Demonstrate that the maximum flare tip velocity as calculated in paragraph (c)(3)(ix)(C) of this section is less than 60 feet per second.
(d) Each vapor collection system for the gasoline loading rack affected facility shall be designed to prevent any total organic compounds vapors collected at one loading rack from passing to another loading rack.
(e) Loadings of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall be limited to vapor-tight gasoline cargo tanks according to the methods in § 60.503a(f) using the following procedures:
(1) The owner or operator shall obtain the vapor tightness annual certification test documentation described in § 60.505a(a)(3) for each gasoline cargo tank which is to be loaded at the affected facility. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.
(2) The owner or operator shall obtain and record the cargo tank identification number of each gasoline cargo tank which is to be loaded at the affected facility.
(3) The owner or operator shall cross-check each cargo tank identification number obtained in paragraph (e)(2) of this section with the file of gasoline cargo tank vapor tightness documentation specified in paragraph (e)(1) of this section prior to loading any liquid product into the gasoline cargo tank.
(f) Loading of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall be conducted using submerged filling, as defined in § 60.501a, and only into gasoline cargo tanks equipped with vapor collection equipment that is compatible with the terminal's vapor collection system. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.
(g) Loading of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall only be conducted when the terminal's and the cargo tank's vapor collection systems are connected. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.
(h) The vapor collection and liquid loading equipment for a gasoline loading rack affected facility shall be designed and operated to prevent gauge pressure in the gasoline cargo tank from exceeding 18 inches of water (460 millimeters (mm) of water) during product loading. This level is not to be exceeded and must be continuously monitored according to the procedures specified in § 60.504a(d).
(i) No pressure-vacuum vent in the gasoline loading rack affected facility's vapor collection system shall begin to open at a system pressure less than 18 inches of water (460 mm of water) or at a vacuum of less than 6.0 inches of water (150 mm of water).
(j) Each owner or operator of a collection of equipment at a bulk gasoline terminal affected facility shall perform leak inspection and repair of all equipment in gasoline service, which includes all equipment in the vapor collection system, the vapor processing system, and each loading rack and loading arm handling gasoline, according to the requirements in paragraphs (j)(1) through (8) of this section. The owner or operator must keep a list, summary description, or diagram(s) showing the location of all equipment in gasoline service at the facility.
(1) Conduct leak detection monitoring of all pumps, valves, and connectors in gasoline service using either of the methods specified in paragraph (j)(1)(i) or (ii) of this section.
(i) Use optical gas imaging (OGI) to quarterly monitor all pumps, valves, and connectors in gasoline service as specified in § 60.503a(e)(2).
(ii) Use Method 21 of appendix A-7 to this part as specified in § 60.503a(e)(1) and paragraphs (j)(1)(ii)(A) through (C) of this section.
(A) All pumps must be monitored quarterly, unless the pump meets one of the requirements in § 60.482-1a(d) or § 60.482-2a(d) through (g). An instrument reading of 10,000 ppm or greater is a leak.
(B) All valves must be monitored quarterly, unless the valve meets one of the requirements in § 60.482-1a(d) or § 60.482-7a(f) through (h). An instrument reading of 10,000 ppm or greater is a leak.
(C) All connectors must be monitored annually, unless the connector meets one of the requirements in § 60.482-1a(d) or § 60.482-11a(e) or (f). An instrument reading of 10,000 ppm or greater is a leak.
(2) During normal duties, record leaks identified by audio, visual, or olfactory methods.
(3) If evidence of a potential leak is found at any time by audio, visual, olfactory, or any other detection method for any equipment (as defined in § 60.501a), a leak is detected.
(4) For pressure relief devices, comply with the requirements in paragraphs (j)(4)(i) through (ii) of this section.
(i) Conduct instrument monitoring of each pressure relief device quarterly and within 5 calendar days after each pressure release to detect leaks by the methods specified in paragraph (j)(1) of this section, except as provided in § 60.482-4a(c).
(ii) If emissions are observed when using OGI, a leak is detected. If Method 21 is used, an instrument reading of 10,000 ppm or greater indicates a leak is detected.
(5) For sampling connection systems, comply with the requirements in § 60.482-5a.
(6) For open-ended valves or lines, comply with the requirements in § 60.482-6a.
(7) When a leak is detected for any equipment, comply with the requirements of paragraphs (j)(7)(i) through (iii) of this section.
(i) A weatherproof and readily visible identification, marked with the equipment identification number, must be attached to the leaking equipment. The identification on equipment may be removed after it has been repaired.
(ii) An initial attempt at repair shall be made as soon as practicable, but no later than 5 calendar days after the leak is detected. An initial attempt at repair is not required if the leak is detected using OGI and the equipment identified as leaking would require elevating the repair personnel more than 2 meters above a support surface.
(iii) Repair or replacement of leaking equipment shall be completed within 15 calendar days after detection of each leak, except as provided in paragraph (j)(8) of this section.
(A) For leaks identified pursuant to instrument monitoring required under paragraph (j)(1) of this section, the leak is repaired when instrument re-monitoring of the equipment does not detect a leak.
(B) For leaks identified pursuant to paragraph (j)(2) of this section, the leak is repaired when the leak can no longer be identified using audio, visual, or olfactory methods.
(8) Delay of repair of leaking equipment will be allowed according to the provisions in paragraphs (j)(8)(i) though (iv) of this section. The owner or operator shall provide in the semiannual report specified in § 60.505a(c), the reason(s) why the repair was delayed and the date each repair was completed.
(i) Delay of repair of equipment will be allowed for equipment that is isolated from the affected facility and that does not remain in gasoline service.
(ii) Delay of repair for valves and connectors will be allowed if:
(A) The owner or operator demonstrates that emissions of purged material resulting from immediate repair are greater than the fugitive emissions likely to result from delay of repair, and
(B) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control device complying with § 60.482-10a or the requirements in paragraph (b) or (c) of this section, as applicable.
(iii) Delay of repair will be allowed for a valve, but not later than 3 months after the leak was detected, if valve assembly replacement is necessary, valve assembly supplies have been depleted, and valve assembly supplies had been sufficiently stocked before the supplies were depleted.
(iv) Delay of repair for pumps will be allowed if:
(A) Repair requires the use of a dual mechanical seal system that includes a barrier fluid system; and
(B) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.
(k) You must not allow gasoline to be handled at a bulk gasoline terminal that contains an affected facility listed under § 60.500a(a) in a manner that would result in vapor releases to the atmosphere for extended periods of time. Measures to be taken include, but are not limited to, the following:
(1) Minimize gasoline spills;
(2) Clean up spills as expeditiously as practicable;
(3) Cover all open gasoline containers and all gasoline storage tank fill-pipes with a gasketed seal when not in use; and
(4) Minimize gasoline sent to open waste collection systems that collect and transport gasoline to reclamation and recycling devices, such as oil/water separators.
§ 60.503a   Test methods and procedures.
(a) General performance test and performance evaluation requirements. (1) In conducting the performance tests or evaluations required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods and procedures as specified in this section, except as provided in § 60.8(b). The three-run requirement of § 60.8(f) does not apply to this subpart.
(2) Immediately before the performance test, conduct leak detection monitoring following the methods in paragraph (e)(1) of this section to identify leakage of vapor from all equipment, including loading arms, in the gasoline loading rack affected facility while gasoline is being loaded into a gasoline cargo tank to ensure the terminal's vapor collection system equipment is operated with no detectable emissions. The owner or operator shall repair all leaks identified with readings of 500 ppmv (as methane) or greater above background before conducting the performance test and within the timeframe specified in § 60.502a(j)(7).
(b) Performance test or performance evaluation timing. (1) For each gasoline loading rack affected facility subject to the mass emission limits in § 60.502a(b)(1) or (c)(1), conduct the initial performance test of the vapor collection and processing systems according to the timing specified in § 60.8(a). For each gasoline loading rack affected facility subject to the emission limits in § 60.502a(b)(2) or (c)(2), conduct the initial performance evaluation of the continuous emissions monitoring system (CEMS) according to the timing specified for performance tests in § 60.8(a).
(2) For each gasoline loading rack affected facility complying with the mass emission limits in § 60.502a(b)(1) or (c)(1), conduct subsequent performance test of the vapor collection and processing system no later than 60 calendar months after the previous performance test.
(3) For each gasoline loading rack affected facility complying with the concentration emission limits in § 60.502a(b)(2) or (c)(2), conduct subsequent performance evaluations of CEMS for the vapor collection and processing system no later than 12 calendar months after the previous performance evaluation.
(c) Performance test requirements for mass loading emission limit. The owner or operator of a gasoline loading rack affected facility shall conduct performance tests of the vapor collection and processing system subject to the emission limits in § 60.502a(b)(1) or (c)(1), as specified in paragraphs (c)(1) through (8) of this section.
(1) The performance test shall be 6 hours long during which at least 80,000 gallons (300,000 liters) of gasoline is loaded. If this is not possible, the test may be continued the same day until 80,000 gallons (300,000 liters) of gasoline is loaded. If 80,000 gallons (300,000 liters) cannot be loaded during the first day of testing, the test may be resumed the next day with another 6-hour period. During the second day of testing, the 80,000-gallon (300,000-liter) criterion need not be met. However, as much as possible, testing should be conducted during the 6-hour period in which the highest throughput of gasoline normally occurs.
(2) If the vapor processing system is intermittent in operation and employs an intermediate vapor holder to accumulate total organic compounds vapors collected from gasoline cargo tanks, the performance test shall begin at a reference vapor holder level and shall end at the same reference point. The test shall include at least two startups and shutdowns of the vapor processor. If this does not occur under automatically controlled operations, the system shall be manually controlled.
(3) The emission rate (E) of total organic compounds shall be computed using the following equation:
(4) The performance test shall be conducted in intervals of 5 minutes. For each interval “i”, readings from each measurement shall be recorded, and the volume exhausted (V esi ) and the corresponding average total organic compounds concentration (C ei ) shall be determined. The sampling system response time shall be accounted for when determining the average total organic compounds concentration corresponding to the volume exhausted.
(5) Method 2B of appendix A-1 to this part shall be used to determine the volume (V esi ) of air-vapor mixture exhausted at each interval.
(6) Method 25, 25A, or 25B of appendix A-7 to this part shall be used for determining the total organic compounds concentration (C ei ) at each interval. Method 25 must not be used if the outlet TOC concentration is less than 50 ppmv. The calibration gas shall be propane. If the owner or operator conducts the performance test using either Method 25A or Method 25B, the methane content in the exhaust vent may be excluded following the procedures in paragraphs (c)(6)(i) through (v) of this section. Alternatively, an instrument that uses gas chromatography with a flame ionization detector may be used according to the procedures in paragraph (c)(6)(vi) of this section.
(i) Measure the methane concentration by Method 18 of appendix A-6 to this part or Method 320 of appendix A to part 63 of this chapter.
(ii) Calibrate the Method 25A or Method 25B analyzer using both propane and methane to develop response factors to both compounds.
(iii) Determine the TOC concentration with the Method 25A or Method 25B analyzer on an as methane basis.
(iv) Subtract the methane measured according to paragraph (c)(6)(i) of this section from the concentration determined in paragraph (c)(6)(iii) of this section.
(v) Convert the concentration difference determined in paragraph (c)(6)(iv) of this section to TOC (minus methane), as propane, by using the response factors determined in paragraph (c)(6)(ii) of this section. Multiply the concentration difference in paragraph (c)(6)(iv) of this section by the ratio of the response factor for propane to the response factor for methane.
(vi) Methane must be separated by the gas chromatograph and measured by the flame ionization detector, followed by a back-flush of the chromatographic column to directly measure TOC concentration minus methane. Use a direct interface and heated sampling line from the sampling point to the gas chromatographic injection valve. All sampling components leading to the analyzer must be heated to greater than 110 °C. Calibrate the instrument with propane. Calibration error and calibration drift must be demonstrated according to Method 25A, and the appropriate procedures in Method 25A must be followed to ensure the calibration error and calibration drift are within Method 25A limits. The TOC concentration minus methane must be recorded at least once every 15 minutes. The performance test report must include the calibration results and the results demonstrating proper separation of methane from the TOC concentration.
(7) To determine the volume (L) of gasoline dispensed during the performance test period at all loading racks whose vapor emissions are controlled by the processing system being tested, terminal records or readings from gasoline dispensing meters at each loading rack shall be used.
(8) Monitor the temperature in the combustion zone using the continuous parameter monitoring system (CPMS) required in § 60.504a(a) and determine the operating limit for the combustion device using the following procedures:
(i) Record the temperature or average temperature for each 5-minute period during the performance test.
(ii) Using only the 5-minute periods in which liquid product is loaded into gasoline cargo tanks, determine the 1-hour average temperature for each hour of the performance test. If you do not know the previous contents of the cargo tank, you must assume liquid product loading is performed in gasoline cargo tanks such that you use all 5-minute periods in which liquid product is loaded into gasoline cargo tanks when determining the 1-hour average temperature for each hour of the performance test.
(iii) Starting at the end of the third hour of the performance test and at the end of each successive hour, calculate the 3-hour rolling average temperature using the 1-hour average values in paragraph (c)(8)(ii) of this section. For a 6-hour test, this would result in four 3-hour averages (averages for hours 1 through 3, 2 through 4, 3 through 5, and 4 through 6).
(iv) Set the operating limit at the lowest 3-hour average temperature determined in paragraph (c)(8)(iii) of this section. New operating limits become effective on the date that the performance test report is submitted to the U.S. Environmental Protection Agency (EPA) Compliance and Emissions Data Reporting Interface (CEDRI), per the requirements of § 60.505a(b).
(d) Performance evaluation requirements for concentration emission limit. The owner or operator shall conduct performance evaluations of the CEMS for vapor collection and processing systems subject to the emission limits in § 60.502a(b)(2) or (c)(2) as specified in paragraph (d)(1) or (2) of this section, as applicable.
(1) If the CEMS uses a nondispersive infrared analyzer, the CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8 of appendix B to this part. Method 25B in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. The owner or operator may request an alternative test method under § 60.8(b) to use a CEMS that excludes the methane content in the exhaust vent.
(2) If the CEMS uses a flame ionization detector, the CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8A of appendix B to this part. As part of the performance evaluation, conduct a relative accuracy test audit (RATA) following the procedures in Performance Specification 2, section 8.4, of appendix B to this part; the relative accuracy must meet the criteria of Performance Specification 8, section 13.2, of appendix B to this part. Method 25A in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. The owner or operator may exclude the methane content in the exhaust following the procedures in paragraphs (d)(2)(i) through (iv) of this section.
(i) Methane must be separated using a chromatographic column and measured by the flame ionization detector, followed by a back-flush of the chromatographic column to directly measure TOC concentration minus methane.
(ii) The CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8A of appendix B to this part, except the target compound is TOC minus methane. As part of the performance evaluation, conduct a RATA following the procedures in Performance Specification 2, section 8.4, of appendix B to this part; the relative accuracy must meet the criteria of Performance Specification 8, section 13.2, of appendix B to this part.
(iii) If the concentration of TOC minus methane in the exhaust stream is greater than 50 ppmv, Method 25 in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. If the concentration of TOC minus methane in the exhaust stream is 50 ppmv or less, Method 25A in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. If Method 25A is the reference method, the procedures in paragraph (c)(6) of this section may be used to subtract methane from the TOC concentration.
(iv) The TOC concentration minus methane must be recorded at least once every 15 minutes.
(e) Leak detection monitoring. Conduct the leak detection monitoring specified in § 60.502a(j)(1) for the collection of equipment at a bulk gasoline terminal affected facility using one of the procedures specified in paragraph (e)(1) or (2) of this section. Conduct the leak detection monitoring specified in paragraph (a)(2) of this section using the procedures specified in paragraph (e)(1) of this section, except that the instrument reading that defines a leak is specified in paragraph (a)(2) for all equipment, including loading arms, in the gasoline loading rack affected facility and the calibration gas in paragraph (e)(1)(ii) must be at a concentration of 500 ppm methane.
(1) Method 21 in appendix A-7 to this part. The instrument reading that defines a leak is 10,000 ppmv (as methane). The instrument shall be calibrated before use each day of its use by the procedures specified in Method 21 of appendix A-7. The calibration gases in paragraphs (e)(1)(i) and (ii) of this section must be used. The drift assessment specified in paragraph (e)(1)(iii) of this section must be performed at the end of each monitoring day.
(i) Zero air (less than 10 ppm of hydrocarbon in air); and
(ii) Methane and air at a concentration of 10,000 ppm methane.
(iii) At the end of each monitoring day, check the instrument using the same calibration gas that was used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 to this part, section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. If multiple scales are used, record the instrument reading for each scale used. Divide the arithmetic difference of the initial and post-test calibration response by the corresponding calibration gas value for each scale and multiply by 100 to express the calibration drift as a percentage. If a calibration drift assessment shows a negative drift of more than 10 percent, then re-monitor all equipment monitored since the last calibration with instrument readings between the leak definition and the leak definition multiplied by (100 minus the percent of negative drift) divided by 100. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment with instrument readings above the leak definition and below the leak definition multiplied by (100 plus the percent of positive drift) divided by 100 monitored since the last calibration may be re-monitored.
(2) OGI according to all the requirements in appendix K to this part. A leak is defined as any emissions plume imaged by the camera from equipment regulated by this subpart.
(f) Annual certification test. The annual certification test for gasoline cargo tanks shall consist of the following test methods and procedures:
(1) Method 27 of appendix A-8 to this part. Conduct the test using a time period (t) for the pressure and vacuum tests of 5 minutes. The initial pressure (P i ) for the pressure test shall be 460 mm water (H 2 O) (18 in. H 2 O), gauge. The initial vacuum (V i ) for the vacuum test shall be 150 mm H 2 O (6 in. H 2 O), gauge. The maximum allowable pressure and vacuum changes (Δ p, Δ v) are as shown in table 1 to this paragraph (f)(1).
Table 1 to Paragraph ( f )(1)—Allowable Gasoline Cargo Tank Test Pressure or Vacuum Change
(2) Pressure test of the gasoline cargo tank's internal vapor valve as follows:
(i) After completing the tests under paragraph (f)(1) of this section, use the procedures in Method 27 to repressurize the gasoline cargo tank to 460 mm H 2 O (18 in. H 2 O), gauge. Close the gasoline cargo tank's internal vapor valve(s), thereby isolating the vapor return line and manifold from the gasoline cargo tank.
(ii) Relieve the pressure in the vapor return line to atmospheric pressure, then reseal the line. After 5 minutes, record the gauge pressure in the vapor return line and manifold. The maximum allowable 5-minute pressure increase is 65 mm H 2 O (2.5 in. H 2 O).
(3) As an alternative to paragraph (f)(1) of this section, you may use the procedure in § 63.425(i) of this chapter.
§ 60.504a   Monitoring requirements.
(a) Monitoring requirements for thermal oxidation systems complying with the combustion zone temperature operating limit. Install, operate, and maintain a CPMS for measuring the combustion zone temperature as specified in paragraphs (a)(1) through (5) of this section.
(1) Install the temperature CPMS in the combustion (flame) zone or in the exhaust gas stream as close as practical to the combustion burners in a position that provides a representative temperature of the combustion zone of the thermal oxidation system.
(2) The temperature CPMS must be capable of measuring temperature with an accuracy of ±1 percent over the normal range of temperatures measured.
(3) The temperature CPMS must be capable of recording the temperature at least once every 5 minutes and calculating hourly block averages that include only those 5-minute periods in which liquid product was loaded into gasoline cargo tanks.
(4) At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor.
(5) Conduct calibration checks at least annually and conduct calibration checks following any period of more than 24 hours throughout which the temperature exceeded the manufacturer's specified maximum rated temperature or install a new temperature sensor.
(b) Monitoring requirements for vapor recovery systems. Install, calibrate, operate, and maintain a CEMS for measuring the concentration of TOC in the atmospheric vent from the vapor recovery system as specified in paragraphs (b)(1) and (2) of this section. Locate the sampling probe or other interface at a measurement location such that you obtain representative measurements of emissions from the vapor recovery system.
(1) The requirements of Performance Specification 8 of appendix B to this part, or, if the CEMS uses a flame ionization detector, Performance Specification 8A of appendix B to this part, the quality assurance requirements in Procedure 1 of appendix F to this part, and the procedures under § 60.13 must be followed for installation, evaluation, and operation of the CEMS. For CEMS certified using Performance Specification 8A of appendix B, conduct the RATA required under Procedure 1 according to the requirements in § 60.503a(d). As required by § 60.503a(b)(3), conduct annual performance evaluations of each TOC CEMS according to the requirements in § 60.503a(d). Conduct accuracy determinations quarterly and calibration drift tests daily in accordance with Procedure 1 in appendix F.
(2) The span value of the TOC CEMS must be approximately 2 times the applicable emission limit.
(c) Monitoring requirements for flares and thermal oxidation systems for which flare monitoring alternative is provided. Install, operate, and maintain CPMS for flares used to comply with the emission limitations in § 60.502a(c)(3), including monitors used for gasoline and total liquid product loading rates, following the requirements specified in § 63.671 of this chapter as specified in paragraphs (c)(1) through (3) of this section and conduct visible emission observations as specified in paragraph (c)(4) of this section.
(1) Substitute “pilot flame or flare flame” for each occurrence of “pilot flame.”
(2) You may elect to determine compositional analysis for net heating value with a continuous process mass spectrometer without the use of a gas chromatograph. If you choose to determine compositional analysis for net heating value with a continuous process mass spectrometer, then you must comply with the requirements specified in paragraphs (c)(2)(i) through (vii) of this section.
(i) You must meet the requirements in § 63.671(e)(2) of this chapter. You may augment the minimum list of calibration gas components found in § 63.671(e)(2) with compounds found during a pre-survey or known to be in the gas through process knowledge.
(ii) Calibration gas cylinders must be certified to an accuracy of 2 percent and traceable to National Institute of Standards and Technology (NIST) standards.
(iii) For unknown gas components that have similar analytical mass fragments to calibration compounds, you may report the unknowns as an increase in the overlapped calibration gas compound. For unknown compounds that produce mass fragments that do not overlap calibration compounds, you may use the response factor for the nearest molecular weight hydrocarbon in the calibration mix to quantify the unknown component's net heating value of flare vent gas (NHV vg ).
(iv) You may use the response factor for n-pentane to quantify any unknown components detected with a higher molecular weight than n-pentane.
(v) You must perform an initial calibration to identify mass fragment overlap and response factors for the target compounds.
(vi) You must meet applicable requirements in Performance Specification 9 of appendix B to this part for continuous monitoring system acceptance including, but not limited to, performing an initial multi-point calibration check at three concentrations following the procedure in section 10.1 of Performance Specification 9 and performing the periodic calibration requirements listed for gas chromatographs in table 13 to part 63, subpart CC, of this chapter, for the process mass spectrometer. You may use the alternative sampling line temperature allowed under Net Heating Value by Gas Chromatograph in table 13 to part 63, subpart CC.
(vii) The average instrument calibration error (CE) for each calibration compound at any calibration concentration must not differ by more than 10 percent from the certified cylinder gas value. The CE for each component in the calibration blend must be calculated using the following equation:
(3) If you use a gas chromatograph or mass spectrometer for compositional analysis for net heating value, then you may choose to use the CE of net heating value (NHV) measured versus the cylinder tag value NHV as the measure of agreement for daily calibration and quarterly audits in lieu of determining the compound-specific CE. The CE for NHV at any calibration level must not differ by more than 10 percent from the certified cylinder gas value. The CE for NHV must be calculated using the following equation:
(4) If visible emissions are observed for more than one continuous minute during normal duties, visible emissions observation using Method 22 of appendix A-7 to this part must be conducted for 2 hours or until 5-minutes of visible emissions are observed.
(d) Pressure CPMS requirements. The owner or operator shall install, operate, and maintain a CPMS to measure the pressure of the vapor collection system to determine compliance with the standard in § 60.502a(h) as specified in paragraphs (d)(1) through (4) of this section.
(1) Install a pressure CPMS (liquid manometer, magnehelic gauge, or equivalent instrument), capable of measuring up to 500 mm of water gauge pressure with ±2.5 mm of water precision on the terminal's vapor collection system at a pressure tap located as close as possible to the connection with the gasoline cargo tank. If necessary to obtain representative loading pressures, install pressure CPMS for each loading rack.
(2) Check the calibration of the pressure CPMS at least annually. Check the calibration of the pressure CPMS following any period of more than 24 hours throughout which the pressure exceeded the manufacturer's specified maximum rated pressure or install a new pressure sensor.
(3) At least quarterly, visually inspect components of the pressure CPMS for integrity, oxidation and galvanic corrosion, unless the system has a redundant pressure sensor.
(4) The output of the pressure CPMS must be reviewed each operating day to ensure that the pressure readings fluctuate as expected during loading of gasoline cargo tanks to verify the pressure taps are not plugged. Plugged pressure taps must be unplugged or otherwise repaired within 24 hours or prior to the next gasoline cargo tank loading, whichever time period is longer.
(e) Limited alternative requirements for vapor recovery systems. If the CEMS used for measuring the concentration of TOC in the atmospheric vent from the vapor recovery system as specified in paragraph (b) of this section requires maintenance such that it is off-line for more than 15 minutes, you may follow the requirements in paragraphs (e)(1) and (2) of this section and monitor product loading quantities and regeneration cycle parameters as an alternative to the monitoring requirement in paragraph (b) for no more than 240 hours in a calendar year.
(1) Determine the quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS going off-line and select the smallest of these values as your product loading quantity operating limit.
(2) Determine the vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS going off-line. You must operate vapor recovery system desorption cycles as specified in paragraphs (e)(2)(i) through (iii) of this section.
(i) The vacuum pressure for each desorption cycle must be at or above the average vacuum pressure from the past 10 desorption cycles. Note: a higher vacuum means a lower absolute pressure.
(ii) Purge gas quantity used for each desorption cycle must be at or above the average quantity of purge gas used from the past 10 desorption cycles.
(iii) Duration of the vacuum/purge cycle for each desorption cycle must be at or above the average duration of the vacuum/purge cycle used from the past 10 desorption cycles.
§ 60.505a   Recordkeeping and reporting.
(a) Recordkeeping requirements. For each affected facility listed under § 60.500a(a), keep records as specified in paragraphs (a)(1) through (9) of this section, as applicable, for a minimum of five years unless otherwise specified in this section. These recordkeeping requirements supersede the requirements in § 60.7(b).
(1) For each thermal oxidation system used to comply with the emission limitations in § 60.502a(b)(1) or (c)(1) by monitoring the combustion zone temperature as specified in § 60.502a(b)(1)(ii) or (c)(1)(ii), for each pressure CPMS used to comply with the requirements in § 60.502a(h), and for each vapor recovery system used to comply with the emission limitations in § 60.502a(b)(2) or (c)(2), maintain records, as applicable, of:
(i) The applicable operating or emission limit for the continuous monitoring system (CMS). For combustion zone temperature operating limits, include the applicable date range the limit applies based on when the performance test was conducted.
(ii) Each 3-hour rolling average combustion zone temperature measured by the temperature CPMS, each 5-minute average reading from the pressure CPMS, and each 3-hour rolling average TOC concentration (as propane) measured by the TOC CEMS.
(iii) For each deviation of the 3-hour rolling average combustion zone temperature operating limit, maximum loading pressure specified in § 60.502a(h), or 3-hour rolling average TOC concentration (as propane), the start date and time, duration, cause, and the corrective action taken.
(iv) For each period when there was a CMS outage or the CMS was out of control, the start date and time, duration, cause, and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).
(v) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check. For TOC CEMS, include the type of CEMS used ( i.e., flame ionization detector, nondispersive infrared analyzer) and an indication of whether methane is excluded from the TOC concentration reported in paragraph (a)(1)(ii) of this section.
(vi) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, also keep records of:
(A) The quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS outage.
(B) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS outage.
(C) The quantity of liquid product loaded in gasoline cargo tanks for each adsorption cycle while using the alternative.
(D) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles for each desorption cycle while using the alternative.
(2) For each flare used to comply with the emission limitations in § 60.502a(c)(3) and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii), maintain records of:
(i) The output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) of this chapter for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame was present when gasoline vapors were routed to the flare for a minimum of 5 years. The record must identify the start and end time and date of each 15-minute block.
(ii) Visible emissions observations as specified in paragraphs (a)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 3 years.
(A) If visible emissions observations are performed using Method 22 of appendix A-7 to this part, the record must identify the date, the start and end time of the visible emissions observation, and the number of minutes for which visible emissions were observed during the observation. If the owner or operator performs visible emissions observations more than one time during a day, include separate records for each visible emissions observation performed.
(B) For each 2-hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours but visible emissions observations according to Method 22 of appendix A-7 to this part were not conducted for the full 2-hour period, the record must include the date, the start and end time of the visible emissions observation, and an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.
(iii) Each 15-minute block period during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) of this chapter when liquid product is being loaded into gasoline cargo tanks for at least 15-minutes identifying the specific operating limit that was not met.
(iv) The 15-minute block average cumulative flows for flare vent gas or the thermal oxidation system vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i) of this chapter, along with the date and start and end time for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the flare vent gas, thermal oxidation system vent gas, or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum supplemental gas flow rate (winter and summer, if applicable) and the actual monitored supplemental gas flow rate for the 15-minute block. Retain the supplemental gas flow rate records for a minimum of 5 years.
(v) The flare vent gas compositions or thermal oxidation system vent gas specified to be monitored under § 63.670(j) of this chapter. Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If an NHV vg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. If you demonstrate your gas streams have consistent composition using the provisions in § 63.670(j)(6) of this chapter as specified in § 60.502a(c)(3)(vii), retain records of the required minimum ratio of gasoline loaded to total liquid product loaded and the actual ratio on a 5-minute block basis. If applicable, you must retain records of the required minimum gasoline loading rate as specified in § 60.502a(c)(3)(vii) and the actual gasoline loading rate on a 5-minute block basis for a minimum of 5 years.
(vi) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n) of this chapter, as applicable.
(vii) All periods during which the owner or operator does not perform monitoring according to the procedures in § 63.670(g), (i), and (j) of this chapter or in § 60.502a(c)(3)(vii) and (viii) as applicable. Note the start date, start time, and duration in minutes for each period.
(viii) An indication of whether “vapors displaced from gasoline cargo tanks during product loading” excludes periods when liquid product is loaded but no gasoline cargo tanks are being loaded or if liquid product loading is assumed to be loaded into gasoline cargo tanks according to the provisions in § 60.502a(c)(3)(i), records of all time periods when “vapors displaced from gasoline cargo tanks during product loading”, and records of time periods when there were no “vapors displaced from gasoline cargo tanks during product loading”.
(ix) If you comply with the flare tip velocity operating limit using the one-time flare tip velocity operating limit compliance assessment as provided in § 60.502a(c)(3)(ix), maintain records of the applicable one-time flare tip velocity operating limit compliance assessment for as long as you use this compliance method.
(x) For each parameter monitored using a CMS, retain the records specified in paragraphs (a)(2)(x)(A) through (C) of this section, as applicable:
(A) For each deviation, record the start date and time, duration, cause, and corrective action taken.
(B) For each period when there is a CMS outage or the CMS is out of control, record the start date and time, duration, cause, and corrective action taken.
(C) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check.
(3) The gasoline cargo tank vapor tightness documentation required under § 60.502a(e)(1) for each gasoline cargo tank loading at the affected facility shall be kept on file at the terminal in either a hardcopy or electronic form available for inspection. The documentation shall include, at a minimum, the following information:
(i) Test title: Annual Certification Test—EPA Method 27 or Railcar Bubble Leak Test Procedure.
(ii) Cargo tank owner's name and address.
(iii) Cargo tank identification number.
(iv) Test location and date.
(v) Tester name and signature.
(vi) Witnessing inspector, if any: Name, signature, and affiliation.
(vii) Vapor tightness repair: Nature of repair work and when performed in relation to vapor tightness testing.
(viii) Test results: Tank or compartment capacity, test pressure; pressure or vacuum change, mm of water; time period of test; number of leaks found with instrument; and leak definition.
(4) Records of each instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502a(e)(1) was not provided or available in the terminal's records. These records shall include, at a minimum:
(i) Cargo tank owner and address.
(ii) Cargo tank identification number.
(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.
(iv) Date proper documentation was received or statement that proper documentation was never received.
(5) Records of each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 60.501a, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system. These records shall include, at a minimum:
(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.
(ii) Type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).
(iii) Cargo tank identification number.
(6) A record [list, summary description, or diagram(s) showing the location] of all equipment in gasoline service at the collection of equipment at a bulk gasoline terminal affected facility and at the loading rack affected facility. A record of each leak inspection and leak identified under §§ 60.503a(a)(2) and 60.502a(j) as specified in paragraphs (a)(6)(i) through (iv) of this section:
(i) For each leak inspection, keep the following records:
(A) An indication if the leak inspection was conducted under § 60.502a(j) or § 60.503a(a)(2).
(B) Leak determination method used for the leak inspection.
(ii) For leak inspections conducted with Method 21 of appendix A-7 to this part, keep the following additional records:
(A) Date of inspection.
(B) Inspector name.
(C) Monitoring instrument identification.
(D) Identification of all equipment surveyed and the instrument reading for each piece of equipment.
(E) Date and time of instrument calibration and initials of operator performing the calibration.
(F) Calibration gas cylinder identification, certification date, and certified concentration.
(G) Instrument scale used.
(H) Results of the daily calibration drift assessment.
(iii) For leak inspections conducted with OGI, keep the records specified in section 12 of appendix K to this part.
(iv) For each leak detected during a leak inspection or by audio/visual/olfactory methods during normal duties, record the following information:
(A) The equipment type and identification number.
(B) The date the leak was detected, the name of the person who found the leak, the nature of the leak ( i.e., vapor or liquid), and the method of detection ( i.e., audio/visual/olfactory, Method 21 of appendix A-7 to this part, or OGI).
(C) The dates of each attempt to repair the leak and the repair methods applied in each attempt to repair the leak.
(D) The date of successful repair of the leak, the method of monitoring used to confirm the repair, and if Method 21 of appendix A-7 to this part is used to confirm the repair, the maximum instrument reading measured by Method 21 of appendix A-7. If OGI is used to confirm the repair, keep video footage of the repair confirmation.
(E) For each repair delayed beyond 15 calendar days after discovery of the leak, record “Repair delayed”, the reason for the delay, and the expected date of successful repair. The owner or operator (or designate) whose decision it was that repair could not be carried out in the 15-calendar-day timeframe must sign the record.
(F) For each leak that is not repairable, the maximum instrument reading measured by Method 21 of appendix A-7 to this part at the time the leak is determined to be not repairable, a video captured by the OGI camera showing that emissions are still visible, or a signed record that the leak is still detectable via audio/visual/olfactory methods.
(7) Records of each performance test or performance evaluation conducted on the affected facility and each notification and report submitted to the Administrator. For each performance test, include an indication of whether liquid product loading is assumed to be loaded into gasoline cargo tanks or periods when liquid product is loaded but no gasoline cargo tanks are being loaded are excluded in the determination of the combustion zone temperature operating limit according to the provision in § 60.503a(c)(8)(ii).
(8) Records of all 5-minute time periods during which liquid product is loaded into gasoline cargo tanks or assumed to be loaded into gasoline cargo tanks and records of all 5-minute time periods when there was no liquid product loaded into gasoline cargo tanks.
(9) Any records required to be maintained by this subpart that are submitted electronically via the EPA's Compliance and Emissions Reporting Interface (CEDRI) may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated authority or the EPA as part of an on-site compliance evaluation.
(b) Reporting requirements for performance tests and evaluations. Within 60 days after the date of completing each performance test and each CEMS performance evaluation required by this subpart, you must submit the results following the procedures specified in paragraph (e) of this section. As required by § 60.8(f)(2)(iv), you must include the value for the combustion zone temperature operating parameter limit set based on your performance test in the performance test report. Data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) and performance evaluations of CEMS measuring RATA pollutants that are supported by the EPA's ERT as listed on the EPA's ERT website ( https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert ) at the time of the test or performance evaluation must be submitted in a file format generated using the EPA's ERT. Alternatively, you may submit an electronic file consistent with the extensible markup language (XML) schema listed on the EPA's ERT website. Data collected using test methods that are not supported by the EPA's ERT and performance evaluations of CEMS measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT website at the time of the test or performance evaluation must be included as an attachment in the ERT or an alternate electronic file.
(c) Reporting requirements for semiannual report. You must submit to the Administrator semiannual reports with the applicable information in paragraphs (c)(1) through (7) of this section by the dates specified in paragraph (d) of this section following the procedure specified in paragraph (e) of this section. For this subpart, the semiannual reports supersede the excess emissions and monitoring systems performance report and/or summary report form required under § 60.7. Beginning on July 8, 2024, or once the report template for this subpart has been available on the CEDRI website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for one year, whichever date is later, submit all subsequent reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in paragraph (e). The date report templates become available will be listed on the CEDRI website. Unless the Administrator or delegated State agency or other authority has approved a different schedule for submission of reports, the report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted.
(1) Report the following general facility information:
(i) Facility name.
(ii) Facility physical address, including city, county, and State.
(iii) Latitude and longitude of facility's physical location. Coordinates must be in decimal degrees with at least five decimal places.
(iv) The following information for the contact person:
(A) Name.
(B) Mailing address.
(C) Telephone number.
(D) Email address.
(v) Date of report and beginning and ending dates of the reporting period. You are no longer required to provide the date of report when the report is submitted via CEDRI.
(vi) Statement by a responsible official, with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. If your report is submitted via CEDRI, the certifier's electronic signature during the submission process replaces the requirement in this paragraph (c)(1)(vi).
(2) For each thermal oxidation system used to comply with the emission limitations in § 60.502a(b)(1) or (c)(1) by monitoring the combustion zone temperature as specified in § 60.502a(b)(1)(ii) or (c)(1)(ii), for each pressure CPMS used to comply with the requirements in § 60.502a(h), and for each vapor recovery system used to comply with the emission limitations in § 60.502a(b)(2) or (c)(2) report the following information for the CMS:
(i) For all instances when the temperature CPMS measured 3-hour rolling averages below the established operating limit or when the vapor collection system pressure exceeded the maximum loading pressure specified in § 60.502a(h) when liquid product was being loaded into gasoline cargo tanks or when the TOC CEMS measured 3-hour rolling average concentrations higher than the applicable emission limitation when the vapor recovery system was operating:
(A) The date and start time of the deviation.
(B) The duration of the deviation in hours.
(C) Each 3-hour rolling average combustion zone temperature, average pressure, or 3-hour rolling average TOC concentration during the deviation. For TOC concentration, indicate whether methane is excluded from the TOC concentration.
(D) A unique identifier for the CMS.
(E) The make, model number, and date of last calibration check of the CMS.
(F) The cause of the deviation and the corrective action taken.
(ii) For all instances that the temperature CPMS for measuring the combustion zone temperature or pressure CPMS was not operating or was out of control when liquid product was loaded into gasoline cargo tanks, or the TOC CEMS was not operating or was out of control when the vapor recovery system was operating:
(A) The date and start time of the deviation.
(B) The duration of the deviation in hours.
(C) A unique identifier for the CMS.
(D) The make, model number, and date of last calibration check of the CMS.
(E) The cause of the deviation and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).
(F) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, report either an indication that there were no deviations from the operating limits when using the limited alternative or report the number of each of the following types of deviations that occurred during the use of the limited alternative for vapor recovery systems in § 60.504a(e).
( 1 ) The number of adsorption cycles when the quantity of liquid product loaded in gasoline cargo tanks exceeded the operating limit established in § 60.504a(e)(1). Enter 0 if no deviations of this type.
( 2 ) The number of desorption cycles when the vacuum pressure was below the average vacuum pressure as specified in § 60.504a(e)(2)(i). Enter 0 if no deviations of this type.
( 3 ) The number of desorption cycles when the quantity of purge gas used was below the average quantity of purge gas as specified in § 60.504a(e)(2)(ii). Enter 0 if no deviations of this type.
( 4 ) The number of desorption cycles when the duration of the vacuum/purge cycle was less than the average duration as specified in § 60.504a(e)(2)(iii). Enter 0 if no deviations of this type.
(3) For each flare used to comply with the emission limitations in § 60.502a(c)(3) and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii), report:
(i) The date and start and end times for each of the following instances:
(A) Each 15-minute block during which there was at least one minute when gasoline vapors were routed to the flare and no pilot flame was present.
(B) Each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. Additionally, report the number of minutes for which visible emissions were observed during the observation or an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.
(C) Each 15-minute period for which the applicable operating limits specified in § 63.670(d) through (f) of this chapter were not met. You must identify the specific operating limit that was not met. Additionally, report the information in paragraphs (c)(3)(i)(C)( 1 ) through ( 3 ) of this section, as applicable.
( 1 ) If you use the loading rate operating limits as determined in § 60.502a(c)(3)(vii) alone or in combination with the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum ratio and the actual ratio of gasoline loaded to total product loaded for the rolling 15-minute period and, if applicable, the required minimum quantity and the actual quantity of gasoline loaded, in gallons, for the rolling 15-minute period.
( 2 ) If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum supplemental gas flow rate and the actual supplemental gas flow rate including units of flow rates for the 15-minute block.
( 3 ) If you use parameter monitoring systems other than those specified in paragraphs (c)(3)(i)(C)( 1 ) and ( 2 ) of this section, the value of the net heating value operating parameter(s) during the deviation determined following the methods in § 63.670(k) through (n) of this chapter as applicable.
(ii) The start date, start time, and duration in minutes for each period when “vapors displaced from gasoline cargo tanks during product loading” were routed to the flare or thermal oxidation system and the applicable monitoring was not performed.
(iii) For each instance reported under paragraphs (c)(3)(i) and (ii) of this section that involves CMS, report the following information:
(A) A unique identifier for the CMS.
(B) The make, model number, and date of last calibration check of the CMS.
(C) The cause of the deviation or downtime and the corrective action taken.
(4) For any instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502a(e)(1) was not provided or available in the terminal's records, report:
(i) Cargo tank owner and address.
(ii) Cargo tank identification number.
(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.
(iv) Date proper documentation was received or statement that proper documentation was never received.
(5) For each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 60.501a, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system, report:
(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.
(ii) Type of deviation ( e.g., not submerged filling, incompatible equipment, or not properly connected).
(iii) Cargo tank identification number.
(6) Report the following information for each leak inspection required under §§ 60.502a(j)(1) and 60.503a(a)(2) and each leak identified under § 60.502a(j)(2).
(i) For each leak detected during a leak inspection required under §§ 60.502a(j)(1) and 60.503a(a)(2), report:
(A) The date of inspection.
(B) The leak determination method (OGI or Method 21 of appendix A-7 to this part).
(C) The total number and type of equipment for which leaks were detected.
(D) The total number and type of equipment for which leaks were repaired within 15 calendar days.
(E) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.
(F) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8).
(ii) For leaks identified under § 60.502a(j)(2), report:
(A) The total number and type of equipment for which leaks were identified.
(B) The total number and type of equipment for which leaks were repaired within 15 calendar days.
(C) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.
(D) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8).
(iii) The total number of leaks on the delay of repair list at the start of the reporting period.
(iv) The total number of leaks on the delay of repair list at the end of the reporting period.
(v) For each leak that was on the delay of repair list at any time during the reporting period, report:
(A) Unique equipment identification number.
(B) Type of equipment.
(C) Leak determination method (OGI, Method 21 of appendix A-7 to this part, or audio, visual, or olfactory).
(D) The reason(s) why the repair was not feasible within 15 calendar days.
(E) If applicable, the date repair was completed.
(7) If there were no deviations from the emission limitations, operating parameters, or work practice standards, then provide a statement that there were no deviations from the emission limitations, operating limits, or work practice standards during the reporting period. If there were no periods during which a CMS (including a CEMS or CPMS) was inoperable or out-of-control, then provide a statement that there were no periods during which a CMS was inoperable or out-of-control during the reporting period.
(d) Timeframe for semiannual report submissions. (1) The first semiannual report will cover the date starting with the date the source first becomes an affected facility subject to this subpart and ending with the last day of the month five months later. For example, if the source becomes an affected facility on April 15, the first semiannual report would cover the period from April 15 to September 30. The first semiannual report must be submitted on or before the last day of the month two months after the last date covered by the semiannual report. In this example, the first semiannual report would be due November 30.
(2) Subsequent semiannual reports will cover subsequent 6 calendar month periods with each report due on or before the last day of the month two months after the last date covered by the semiannual report.
(e) Requirements for electronically submitting reports. For reports required to be submitted following the procedures specified in this paragraph (e), you must submit reports to the EPA via CEDRI, which can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ). The EPA will make all the information submitted through CEDRI available to the public without further notice to you. Do not use CEDRI to submit information you claim as confidential business information (CBI). Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim for some of the information in the report, you must submit a complete file in the format specified in this subpart, including information claimed to be CBI, to the EPA following the procedures in paragraphs (e)(1) and (2) of this section. Clearly mark the part or all of the information that you claim to be CBI. Information not marked as CBI may be authorized for public release without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. All CBI claims must be asserted at the time of submission. Anything submitted using CEDRI cannot later be claimed CBI. Furthermore, under CAA section 114(c), emissions data are not entitled to confidential treatment, and the EPA is required to make emissions data available to the public. Thus, emissions data will not be protected as CBI and will be made publicly available. You must submit the same file submitted to the CBI office with the CBI omitted to the EPA via the EPA's CDX as described earlier in this paragraph (e).
(1) The preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol, or other online file sharing services. Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address oaqpscbi@epa.gov, and as described above, should include clear CBI markings. ERT files should be flagged to the attention of the Group Leader, Measurement Policy Group; all other files should be flagged to the attention of the Gasoline Distribution Sector Lead. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email oaqpscbi@epa.gov to request a file transfer link.
(2) If you cannot transmit the file electronically, you may send CBI information through the postal service to the following address: U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should be flagged to the attention of the Group Leader, Measurement Policy Group, and all other files should also be flagged to the attention of the Gasoline Distribution Sector Lead. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.
(f) Claims of EPA system outage. If you are required to electronically submit a report through CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for failure to timely comply with that reporting requirement. To assert a claim of EPA system outage, you must meet the requirements outlined in paragraphs (f)(1) through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI and submitting a required report within the time prescribed due to an outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time beginning five business days prior to the date that the submission is due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(5) You must provide to the Administrator a written description identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize the delay in reporting; and
(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.
(6) The decision to accept the claim of EPA system outage and allow an extension to the reporting deadline is solely within the discretion of the Administrator.
(7) In any circumstance, the report must be submitted electronically as soon as possible after the outage is resolved.
(g) Claims of force majeure. If you are required to electronically submit a report through CEDRI in the EPA's CDX, you may assert a claim of force majeure for failure to timely comply with that reporting requirement. To assert a claim of force majeure, you must meet the requirements outlined in paragraphs (g)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to occur, occurs, or has occurred or there are lingering effects from such an event within the period of time beginning five business days prior to the date the submission is due. For the purposes of this section, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature ( e.g., hurricanes, earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility ( e.g., large scale power outage).
(2) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize the delay in reporting; and
(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.
(4) The decision to accept the claim of force majeure and allow an extension to the reporting deadline is solely within the discretion of the Administrator.
(5) In any circumstance, the reporting must occur as soon as possible after the force majeure event occurs.
§ 60.530   Am I subject to this subpart?
(a) You are subject to this subpart if you manufacture, sell, offer for sale, import for sale, distribute, offer to distribute, introduce or deliver for introduction into commerce in the United States, or install or operate an affected wood heater specified in paragraphs (a)(1) or (a)(2) of this section, except as provided in paragraph (c) of this section.
(1) Each adjustable burn rate wood heater, single burn rate wood heater and pellet stove manufactured on or after July 1, 1988, with a current EPA certificate of compliance issued prior to May 15, 2015 according to the certification procedures in effect in this subpart at the time of certification is an affected wood heater.
(2) All other residential wood heaters as defined in § 60.531 manufactured or sold on or after May 15, 2015 are affected wood heaters, except as provided in paragraph (c) of this section.
(b) Each affected wood heater must comply with the provisions of this subpart unless exempted under paragraphs (b)(1) through (b)(6) of this section. These exemptions are determined by rule applicability and do not require EPA notification or public notice.
(1) Affected wood heaters manufactured in the United States for export are exempt from the applicable emission limits of § 60.532 and the requirements of § 60.533.
(2) Affected wood heaters used for research and development purposes that are never offered for sale or sold and that are not used for the purpose of providing heat are exempt from the applicable emission limits of § 60.532 and the requirements of § 60.533. No more than 50 wood heaters manufactured per model line can be exempted for this purpose.
(3) Appliances that do not burn wood or wood pellets (such as coal-only heaters that meet the definition in § 60.531 or corn-only pellet stoves) are exempt from the applicable emission limits of § 60.532 and the requirements of § 60.533 provided that all advertising and warranties exclude wood burning.
(4) Cook stoves as defined in § 60.531 are exempt from the applicable emission limits of § 60.532 and the requirements of § 60.533.
(5) Camp stoves as defined in § 60.531 are exempt from the applicable emission limits of § 60.532 and the requirements of § 60.533.
(6) Modification or reconstruction, as defined in §§ 60.14 and 60.15 of subpart A of this part does not, by itself, make a wood heater an affected facility under this subpart.
(c) The following are not affected wood heaters and are not subject to this subpart:
(1) Residential hydronic heaters and residential forced-air furnaces subject to subpart QQQQ of this part.
(2) Residential masonry heaters that meet the definition in § 60.531.
(3) Appliances that are not residential heating devices (for example, manufactured or site-built masonry fireplaces).
(4) Traditional Native American bake ovens that meet the definition in § 60.531.
§ 60.531   What definitions must I know?
As used in this subpart, all terms not defined herein have the meaning given them in the Clean Air Act and subpart A of this part.
Adjustable burn rate wood heater means a wood heater that is equipped with or installed with a damper or other mechanism to allow the operator to vary burn rate conditions, regardless of whether it is internal or external to the appliance. This definition does not distinguish between heaters that are free standing, built-in or fireplace inserts.
Approved test laboratory means a test laboratory that is approved for wood heater certification testing under § 60.535 or is an independent third-party test laboratory that is accredited under ISO-IEC Standard 17025 to perform testing using the test methods specified in § 60.534 by an accreditation body that is a full member signatory to the International Laboratory Accreditation Cooperation Mutual Recognition Arrangement and approved by the EPA for conducting testing under this subpart.
Camp stove (sometimes also called cylinder stove or wall tent stove) means a portable stove equipped with a pipe or chimney exhaust capable of burning wood or coal intended for use in a tent or other temporary structure used for hunting, camping, fishing or other outdoor recreation. The primary purpose of the stove is to provide space heating, although cooking and heating water may be additional functions.
Catalytic combustor means a device coated with a noble metal used in a wood heater to lower the temperature required for combustion.
Chip wood fuel means wood chipped into small pieces that are uniform in size, shape, moisture, density and energy content.
Coal-only heater means an enclosed, coal-burning appliance capable of space heating or space heating and domestic water heating, which is marketed and warranted solely as a coal-only heater and has all of the following characteristics:
(1) An opening for emptying ash that is located near the bottom or the side of the appliance;
(2) A system that admits air primarily up and through the fuel bed;
(3) A grate or other similar device for shaking or disturbing the fuel bed or a power-driven or mechanical stoker;
(4) Installation instructions, owner's manual and marketing information that state that the use of wood in the stove, except for coal ignition purposes, is prohibited by law; and
(5) A safety listing as a coal-only heater, except for coal ignition purposes, under accepted American or Canadian safety codes, as documented by a permanent label from a nationally recognized certification body.
Commercial owner means any person who owns or controls a wood heater in the course of the business of the manufacture, importation, distribution (including shipping and storage), or sale of the wood heater.
Cook stove means a wood-fired appliance that is designed, marketed and warranted primarily for cooking food and that has the following characteristics:
(1) An oven, with volume of 0.028 cubic meters (1 cubic foot) or greater, and an oven rack;
(2) A device for measuring oven temperatures;
(3) A flame path that is routed around the oven;
(4) An ash pan;
(5) An ash clean-out door below the oven;
(6) The absence of a fan or heat channels to dissipate heat from the appliance;
(7) A cooking surface with an area measured in square inches or square feet that is at least 1.5 times greater than the volume of firebox measured in cubic inches or cubic feet. Example: A cook stove with a firebox of 2 cubic feet must have a cooking surface of at least 3 square feet;
(8) A portion of at least four sides of the oven (which may include the bottom and/or top) is exposed to the flame path during the heating cycle of the oven. A flue gas bypass may exist for temperature control.
Fireplace means a wood-burning appliance intended to be used primarily for aesthetic enjoyment and not as a space heater. An appliance is a fireplace if it is in a model line that satisfies the requirements in paragraphs (1), (2) or (3) of this definition.
(1) The model line includes a safety listing under recognized American or Canadian safety standards, as documented by a permanent label from a nationally recognized certification body affixed on each unit sold, and that said safety listing only allows operation of the fireplace with doors fully open. Operation with any required safety screen satisfies this requirement.
(2) The model line has a safety listing that allows operation with doors closed, has no user-operated controls other than flue or outside air dampers that can only be adjusted to either a fully closed or fully opened position, and the requirements in either paragraph (2)(i) or (2)(ii) of this definition are satisfied.
(i) Appliances are sold with tempered glass panel doors only (either as standard or optional equipment), or
(ii) The fire viewing area is equal to or greater than 500 square inches.
(3)(i) A model line that is clearly positioned in the marketplace as intended to be used primarily for aesthetic enjoyment and not as a room heater, as demonstrated by product literature (including owner's manuals), advertising targeted at the trade or public (including web-based promotional materials) or training materials is presumptively a fireplace model line.
(ii) The presumption in paragraph (3)(i) of this definition can be rebutted by test data from an EPA-approved test laboratory reviewed by an EPA-approved third-party certifier that were generated when operating the appliance with the door(s) closed, and that demonstrate an average stack gas carbon dioxide (CO 2 ) concentration over the duration of the test run equal to or less than 5.00 percent and a ratio of the average stack gas CO 2 to the average stack gas carbon monoxide (CO) equal to or greater than 15:1. The stack gas average CO 2 and CO concentrations for the test run shall be determined in accordance with the requirements in CSA B415.1-10 (IBR, see § 60.17), clause 6.3, using a sampling interval no greater than 1 minute. The average stack gas CO 2 and CO concentrations for purposes of this determination shall be the average of the stack gas concentrations from all sampling intervals over the full test run.
Manufactured means completed and ready for shipment (whether or not assembled or packaged) for purposes of determining the date of manufacture.
Manufacturer means any entity that constructs or imports into the United States a wood heater.
Model line means all wood heaters offered for sale by a single manufacturer that are similar in all material respects that would affect emissions as defined in this section.
Particulate matter (PM) means total particulate matter including coarse particulate (PM 10 ) and fine particulate (PM 2.5 ).
Pellet fuel means refined and densified fuel shaped into small pellets or briquettes that are uniform in size, shape, moisture, density and energy content.
Pellet stove (sometimes called pellet heater or pellet space heater) means an enclosed, pellet or chip fuel-burning device capable of and intended for residential space heating or space heating and domestic water heating. Pellet stoves include a fuel storage hopper or bin and a fuel feed system. Pellet stoves include, but are not limited to:
(1) Free-standing pellet stoves—pellet stoves that are installed on legs or on a pedestal or other supporting base. These stoves generally are safety listed under ASTM E1509, UL-1482, ULC S627 or ULC-ORD C1482.
(2) Pellet stove fireplace inserts—pellet stoves intended to be installed in masonry fireplace cavities or in other enclosures. These stoves generally are safety listed under ASTM E1509, UL-1482, ULC-S628 or ULC-ORD C1482.
(3) Built-in pellet stoves—pellet stoves intended to be recessed into the wall. These stoves generally are safety listed under ASTM E1509, UL-127, ULC-S610 or ULC-ORD C1482.
Representative affected wood heater means an individual wood heater that is similar in all material respects that would affect emissions to other wood heaters within the model line it represents.
Residential masonry heater means a factory-built or site-built wood-burning device in which the heat from intermittent fires burned rapidly in the firebox is stored in the refractory mass for slow release to building spaces. Masonry heaters are site-built (using local materials or a combination of local materials and manufactured components) or site-assembled (using factory-built components), solid fuel-burning heating appliances constructed mainly of refractory materials ( e.g., masonry materials or soapstone. They typically have an interior construction consisting of a firebox and heat exchange channels built from refractory components, through which flue gases are routed. ASTM E-1602 “Standard Guide for Construction of Solid Fuel Burning Masonry Heaters” provides design and construction information for the range of masonry heaters most commonly built in the United States. The site-assembled models are generally listed to UL-1482.
Sale means the transfer of ownership or control, except that a transfer of control of an affected wood heater for research and development purposes within the scope of § 60.530(b)(2) is not a sale.
Similar in all material respects that would affect emissions means that the construction materials, exhaust and inlet air systems and other design features are within the allowed tolerances for components identified in § 60.533(k)(2), (3) and (4).
Single burn rate wood heater means a wood heater that is not equipped with or installed with a burn control device to allow the operator to vary burn rate conditions. Burn rate control devices include stack dampers that control the outflow of flue gases from the heater to the chimney, whether built into the appliance, sold with it, or recommended for use with the heater by the manufacturer, retailer or installer; and air control slides, gates or any other type of mechanisms that control combustion air flow into the heater.
Sold at retail means the sale by a commercial owner of a wood heater to the ultimate purchaser/user or noncommercial purchaser.
Third-party certifier (sometimes called third-party certifying body or product certifying body ) means an independent third party that is accredited under ISO-IEC Standards 17025 and 17065 to perform certifications, inspections and audits by an accreditation body that is a full member signatory to the International Laboratory Accreditation Cooperation Mutual Recognition Arrangement and approved by the EPA for conducting certifications, inspections and audits under this subpart.
Traditional Native American bake oven means a wood or other solid fuel burning appliance that is designed primarily for use by Native Americans for food preparation, cooking, warming or for instructional, recreational, cultural or ceremonial purposes.
Unseasoned wood means wood with an average moisture content of 20 percent or more.
Valid certification test means a test that meets the following criteria:
(1) The Administrator was notified about the test in accordance with § 60.534(g);
(2) The test was conducted by an approved test laboratory as defined in this section;
(3) The test was conducted on a wood heater similar in all material respects that would affect emissions to other wood heaters of the model line that is to be certified; and
(4) The test was conducted in accordance with the test methods and procedures specified in § 60.534.
Wood heater means an enclosed, wood burning-appliance capable of and intended for residential space heating or space heating and domestic water heating. These devices include, but are not limited to, adjustable burn rate wood heaters, single burn rate wood heaters and pellet stoves. Wood heaters may or may not include air ducts to deliver some portion of the heat produced to areas other than the space where the wood heater is located. Wood heaters include, but are not limited to:
(1) Free-standing wood heaters—Wood heaters that are installed on legs, on a pedestal or suspended from the ceiling. These products generally are safety listed under UL-1482, UL-737 or ULC-S627.
(2) Fireplace insert wood heaters—Wood heaters intended to be installed in masonry fireplace cavities or in other enclosures. These appliances generally are safety listed under UL-1482, UL-737 or ULC-S628.
(3) Built-in wood heaters—Wood heaters that are intended to be recessed into the wall. These appliances generally are safety listed under UL-1482, UL-737, UL-127 or ULC-S610.
§ 60.532   What standards and associated requirements must I meet and by when?
(a) 2015 particulate matter emission standards. Unless exempted under § 60.530(b), each affected wood heater manufactured, imported into the United States, and/or sold at retail on or after May 15, 2015 must be certified to not discharge into the atmosphere any gases that contain particulate matter in excess of a weighted average of 4.5 g/hr (0.010 lb/hr), except that a wood heater manufactured before May 15, 2015 may be imported into the United States and/or sold at retail on or before December 31, 2015. Compliance for all heaters must be determined by the test methods and procedures in § 60.534.
(b) 2020 particulate matter emission standards. Unless exempted under § 60.530(b) or electing to use the cord wood alternative means of compliance option in paragraph (c) of the section, each affected wood heater manufactured or sold at retail for use in the United States on or after May 15, 2020 must not discharge into the atmosphere any gases that contain particulate matter in excess of a weighted average of 2.0 g/hr (0.0044 lb/hr). Compliance for all heaters must be determined by the test methods and procedures in § 60.534.
(c) 2020 cord wood alternative compliance option. Each affected wood heater manufactured or sold at retail for use in the United States on or after May 15, 2020 must not discharge into the atmosphere any gases that contain particulate matter in excess of a weighted average of 2.5 g/hr (0.0055 lb/hr). Compliance must be determined by a cord wood test method approved by the Administrator and the procedures in § 60.534.
(d) Chip wood fuel requirements. Operators of wood heaters that are certified to burn chip wood fuels must only burn chip wood fuels that have been specified in the owner's manual. The chip wood fuel must meet the following minimum requirements:
(1) Moisture content: less than 35 percent;
(2) Inorganic fines: less than or equal to 1 percent;
(3) Chlorides: less than or equal to 300 parts per million by weight;
(4) Ash content: no more than 2 percent;
(5) No demolition or construction waste; and
(6) Trace metals: less than 100 mg/kg.
(e) Pellet fuel requirements. Operators of wood heaters that are certified to burn pellet fuels may burn only pellets that have been specified in the owner's manual and graded under a licensing agreement with a third-party organization approved by the EPA (including a certification by the third-party organization that the pellets do not contain, and are not manufactured from, any of the prohibited fuels in paragraph (f) of this section). The Pellet Fuels Institute, ENplus, and CANplus are initially deemed to be approved third-party organizations for this purpose, and additional organizations may apply to the Administrator for approval.
(f) Prohibited fuel types. No person is permitted to burn any of the following materials in an affected wood heater:
(1) Residential or commercial garbage;
(2) Lawn clippings or yard waste;
(3) Materials containing rubber, including tires;
(4) Materials containing plastic;
(5) Waste petroleum products, paints or paint thinners, or asphalt products;
(6) Materials containing asbestos;
(7) Construction or demolition debris;
(8) Paper products, cardboard, plywood, or particleboard. The prohibition against burning these materials does not prohibit the use of fire starters made from paper, cardboard, sawdust, wax and similar substances for the purpose of starting a fire in an affected wood heater;
(9) Railroad ties, pressure-treated wood or pallets;
(10) Manure or animal remains;
(11) Salt water driftwood or other previously salt water saturated materials;
(12) Unseasoned wood;
(13) Any materials that are not included in the warranty and owner's manual for the subject wood heater; or
(14) Any materials that were not included in the certification tests for the subject wood heater.
(g) Operation of affected wood heaters. The user of an affected residential wood heater must operate the heater in a manner consistent with the owner's manual. The owner's manual must clearly specify that operation in a manner inconsistent with the owner's manual would void the warranty.
(h) Temperature sensor requirement. An affected wood heater equipped with a catalytic combustor must be equipped with a temperature sensor that can monitor combustor gas stream temperatures within or immediately downstream [within 2.54 centimeters (1 inch)] of the catalytic combustor surface.