Title 40—Protection of Environment--Volume 1
PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
§ 60.623   Equivalent equipment and procedures.
(a) Upon written application from any person, the Administrator may approve the use of equipment or procedures that have been demonstrated to his satisfaction to be equivalent, in terms of reducing VOC emissions to the atmosphere, to those prescribed for compliance within a specified paragraph of this subpart. The application must contain a complete description of the equipment or procedure; the testing method; the date, time and location of the test; and a description of the test results. Written applications shall be submitted to the Administrator, U.S. Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
(b) The Administrator will make a preliminary determination of whether or not the application for equivalency is approvable and will publish a notice of these findings in the Federal Register. After notice and opportunity for public hearing, the Administrator will publish the final determination in the Federal Register.
§ 60.624   Test methods and procedures.
Each owner or operator of an affected facility subject to the provisions of § 60.622(a) shall perform an initial test to verify that the flow rate of recovered solvent from the solvent recovery dryer at the termination of the recovery cycle is no greater than 0.05 liters per minute. This test shall be conducted for a duration of no less than 2 weeks during which no less than 50 percent of the dryer loads shall be monitored for their final recovered solvent flow rate. The suggested point for measuring the flow rate of recovered solvent is the outlet of the solvent-water separator. Near the end of the recovery cycle, the entire flow of recovered solvent should be diverted to a graduated cylinder. As the recovered solvent collects in the graduated cylinder, the elapsed time is monitored and recorded in periods of greater than or equal to 1 minute. At the same time, the volume of solvent in the graduated cylinder is monitored and recorded to determine the volume of recovered solvent that is collected during each time period. The recovered solvent flow rate is calculated by dividing the volume of solvent collected per period by the length of time elapsed during the period and converting the result with appropriate factors into units of liters per minute. The recovery cycle and the monitoring procedure should continue until the flow rate of solvent is less than or equal to 0.05 liter per minute. The type of articles cleaned and the total length of the cycle should then be recorded.
§ 60.625   Recordkeeping requirements.
Each owner or operator of an affected facility subject to the provisions of this subpart shall maintain a record of the performance test required under § 60.624.
§ 60.630   Applicability and designation of affected facility.
(a)(1) The provisions of this subpart apply to affected facilities in onshore natural gas processing plants.
(2) A compressor in VOC service or in wet gas service is an affected facility.
(3) The group of all equipment except compressors (definied in § 60.631) within a process unit is an affected facility.
(b) Any affected facility under paragraph (a) of this section that commences construction, reconstruction, or modification after January 20, 1984, and on or before August 23, 2011, is subject to the requirements of this subpart.
(c) Addition or replacement of equipment (defined in § 60.631) for the purpose of process improvement that is accomplished without a capital expenditure shall not by itself be considered a modification under this subpart.
(d) Facilities covered by subpart VV or subpart GGG of 40 CFR part 60 are excluded from this subpart.
(e) A compressor station, dehydration unit, sweetening unit, underground storage tank, field gas gathering system, or liquefied natural gas unit is covered by this subpart if it is located at an onshore natural gas processing plant. If the unit is not located at the plant site, then it is exempt from the provisions of this subpart.
(f) An affected facility must continue to comply with the requirements of this subpart until it begins complying with a more stringent requirement, that applies to the same affected facility, in an approved, and effective, State or Federal plan that implements subpart OOOOc of this part, or modifies or reconstructs after December 6, 2022, and thus becomes subject to subpart OOOOb of this part.
§ 60.631   Definitions.
As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, in subpart A or subpart VV of part 60; and the following terms shall have the specific meanings given them.
Alaskan North Slope means the approximately 69,000 square-mile area extending from the Brooks Range to the Arctic Ocean.
Equipment means each pump, pressure relief device, open-ended valve or line, valve, compressor, and flange or other connector that is in VOC service or in wet gas service, and any device or system required by this subpart.
Field gas means feedstock gas entering the natural gas processing plant.
In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in § 60.485(e) or § 60.633(h)(2).
In wet gas service means that a piece of equipment contains or contacts the field gas before the extraction step in the process.
Natural gas liquids means the hydrocarbons, such as ethane, propane, butane, and pentane, that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both.
Nonfractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products.
Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.
Process unit means equipment assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.
Reciprocating compressor means a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear movement of the driveshaft.
§ 60.632   Standards.
(a) Each owner or operator subject to the provisions of this subpart shall comply with the requirements of §§ 60.482-1 (a), (b), and (d) and 60.482-2 through 60.482-10, except as provided in § 60.633, as soon as practicable, but no later than 180 days after initial startup.
(b) An owner or operator may elect to comply with the requirements of §§ 60.483-1 and 60.483-2.
(c) An owner or operator may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by the controls required in this subpart. In doing so, the owner or operator shall comply with requirements of § 60.634 of this subpart.
(d) Each owner or operator subject to the provisions of this subpart shall comply with the provisions of § 60.485 except as provided in § 60.633(f) of this subpart.
(e) Each owner or operator subject to the provisions of this subpart shall comply with the provisions of §§ 60.486 and 60.487 except as provided in §§ 60.633, 60.635, and 60.636 of this subpart.
(f) An owner or operator shall use the following provision instead of § 60.485(d)(1): Each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the methods described in ASTM E169-63, 77, or 93, E168-67, 77, or 92, or E260-73, 91, or 96 (incorporated by reference as specified in § 60.17) shall be used.
§ 60.633   Exceptions.
(a) Each owner or operator subject to the provisions of this subpart may comply with the following exceptions to the provisions of subpart VV.
(b)(1) Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified in § 60.485(b) except as provided in §§ 60.632(c), paragraph (b)(4) of this section, and 60.482-4 (a) through (c) of subpart VV.
(2) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.
(3)(i) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in § 60.482-9.
(ii) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.
(4)(i) Any pressure relief device that is located in a nonfractionating plant that is monitored only by nonplant personnel may be monitored after a pressure release the next time the monitoring personnel are on site, instead of within 5 days as specified in paragraph (b)(1) of this section and § 60.482-4(b)(1) of subpart VV.
(ii) No pressure relief device described in paragraph (b)(4)(i) of this section shall be allowed to operate for more than 30 days after a pressure release without monitoring.
(c) Sampling connection systems are exempt from the requirements of § 60.482-5.
(d) Pumps in light liquid service, valves in gas/vapor and light liquid service, and pressure relief devices in gas/vapor service that are located at a nonfractionating plant that does not have the design capacity to process 283,200 standard cubic meters per day (scmd) (10 million standard cubic feet per day) or more of field gas are exempt from the routine monitoring requirements of §§ 60.482-2(a)(1) and 60.482-7(a), and paragraph (b)(1) of this section.
(e) Pumps in light liquid service, valves in gas/vapor and light liquid service, and pressure relief devices in gas/vapor service within a process unit that is located in the Alaskan North Slope are exempt from the routine monitoring requirements of §§ 60.482-2(a)(1), 60.482-7(a), and paragraph (b)(1) of this section.
(f) Reciprocating compressors in wet gas service are exempt from the compressor control requirements of § 60.482-3.
(g) Flares used to comply with this subpart shall comply with the requirements of § 60.18.
(h) An owner or operator may use the following provisions instead of § 60.485(e):
(1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150 °C (302 °F) as determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by reference as specified in § 60.17).
(2) Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150 °C (302 °F) as determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by reference as specified in § 60.17).
§ 60.634   Alternative means of emission limitation.
(a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in VOC emissions at least equivalent to the reduction in VOC emissions achieved under any design, equipment, work practice or operational standard, the Administrator will publish, in the Federal Register a notice permitting the use of that alternative means for the purpose of compliance with that standard. The notice may condition permission on requirements related to the operation and maintenance of the alternative means.
(b) Any notice under paragraph (a) of this section shall be published only after notice and an opportunity for a public hearing.
(c) The Administrator will consider applications under this section from either owners or operators of affected facilities, or manufacturers of control equipment.
(d) The Administrator will treat applications under this section according to the following criteria, except in cases where he concludes that other criteria are appropriate:
(1) The applicant must collect, verify and submit test data, covering a period of at least 12 months, necessary to support the finding in paragraph (a) of this section.
(2) If the applicant is an owner or operator of an affected facility, he must commit in writing to operate and maintain the alternative means so as to achieve a reduction in VOC emissions at least equivalent to the reduction in VOC emissions achieved under the design, equipment, work practice or operational standard.
§ 60.635   Recordkeeping requirements.
(a) Each owner or operator subject to the provisions of this subpart shall comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.486.
(b) The following recordkeeping requirements shall apply to pressure relief devices subject to the requirements of § 60.633(b)(1) of this subpart.
(1) When each leak is detected as specified in § 60.633(b)(2), a weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired.
(2) When each leak is detected as specified in § 60.633(b)(2), the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location:
(i) The instrument and operator identification numbers and the equipment identification number.
(ii) The date the leak was detected and the dates of each attempt to repair the leak.
(iii) Repair methods applied in each attempt to repair the leak.
(iv) “Above 10,000 ppm” if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 10,000 ppm or greater.
(v) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak.
(vi) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown.
(vii) The expected date of successful repair of the leak if a leak is not repaired within 15 days.
(viii) Dates of process unit shutdowns that occur while the equipment is unrepaired.
(ix) The date of successful repair of the leak.
(x) A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of § 60.482-4(a). The designation of equipment subject to the provisions of § 60.482-4(a) shall be signed by the owner or operator.
(c) An owner or operator shall comply with the following requirement in addition to the requirement of § 60.486(j): Information and data used to demonstrate that a reciprocating compressor is in wet gas service to apply for the exemption in § 60.633(f) shall be recorded in a log that is kept in a readily accessible location.
§ 60.636   Reporting requirements.
(a) Each owner or operator subject to the provisions of this subpart shall comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487.
(b) An owner or operator shall include the following information in the initial semiannual report in addition to the information required in § 60.487(b) (1)-(4): Number of pressure relief devices subject to the requirements of § 60.633(b) except for those pressure relief devices designated for no detectable emissions under the provisions of § 60.482-4(a) and those pressure relief devices complying with § 60.482-4(c).
(c) An owner or operator shall include the following information in all semiannual reports in addition to the information required in § 60.487(c)(2) (i) through (vi):
(1) Number of pressure relief devices for which leaks were detected as required in § 60.633(b)(2) and
(2) Number of pressure relief devices for which leaks were not repaired as required in § 60.633(b)(3).
§ 60.640   Applicability and designation of affected facilities.
(a) The provisions of this subpart are applicable to the following affected facilities that process natural gas: each sweetening unit, and each sweetening unit followed by a sulfur recovery unit.
(b) Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H 2 S) in the acid gas (expressed as sulfur) are required to comply with § 60.647(c) but are not required to comply with §§ 60.642 through 60.646.
(c) The provisions of this subpart are applicable to facilities located on land and include facilities located onshore which process natural gas produced from either onshore or offshore wells.
(d) The provisions of this subpart apply to each affected facility identified in paragraph (a) of this section which commences construction or modification after January 20, 1984, and on or before August 23, 2011.
(e) The provisions of this subpart do not apply to sweetening facilities producing acid gas that is completely reinjected into oil-or-gas-bearing geologic strata or that is otherwise not released to the atmosphere.
§ 60.641   Definitions.
All terms used in this subpart not defined below are given the meaning in the Act and in subpart A of this part.
Acid gas means a gas stream of hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) that has been separated from sour natural gas by a sweetening unit.
Natural gas means a naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface. The principal hydrocarbon constituent is methane.
Onshore means all facilities except those that are located in the territorial seas or on the outercontinental shelf.
Reduced sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ).
Sulfur production rate means the rate of liquid sulfur accumulation from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element sulfur from acid gas.
Sweetening unit means a process device that separates the H 2 S and CO 2 contents from the sour natural gas stream.
Total SO 2 equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)).
§ 60.642   Standards for sulfur dioxide.
(a) During the initial performance test required by § 60.8(b), each owner or operator shall achieve at a minimum, an SO 2 emission reduction efficiency (Z i ) to be determined from table 1 based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility.
(b) After demonstrating compliance with the provisions of paragraph (a) of this section, the owner or operator shall achieve at a minimum, an SO 2 emission reduction efficiency (Z c ) to be determined from table 2 based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility.
§ 60.643   Compliance provisions.
(a)(1) To determine compliance with the standards for sulfur dioxide specified in § 60.642(a), during the initial performance test as required by § 60.8, the minimum required sulfur dioxide emission reduction efficiency (Z) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology.
(i) If R ≥ Z i , the affected facility is in compliance.
(ii) If R < Z i , the affected facility is not in compliance.
(2) Following the initial determination of compliance as required by § 60.8, any subsequent compliance determinations that may be required by the Administrator would compare R to Z c .
(b) The emission reduction efficiency (R) achieved by the sulfur reduction technology shall be determined using the procedures in § 60.644(c)(1).
§ 60.644   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 paragraph § 60.8(b).
(b) During a performance test required by § 60.8, the owner or operator shall determine the minimum required reduction efficiencies (Z) of SO 2 emissions as required in § 60.642 (a) and (b) as follows:
(1) The average sulfur feed rate (X) shall be computed as follows:
(2) The continuous readings from the process flowmeter shall be used to determine the average volumetric flow rate (Q a ) in dscm/day (dscf/day) of the acid gas from the sweetening unit for each run.
(3) The Tutwiler procedure in § 60.648 or a chromatographic procedure following ASTM E-260 (incorporated by reference—see § 60.17) shall be used to determine the H 2 S concentration in the acid gas feed from the sweetening unit. At least one sample per hour (at equally spaced intervals) shall be taken during each 4-hour run. The arithmetic mean of all samples shall be the average H 2 S concentration (Y) on a dry basis for the run. By multiplying the result from the Tutwiler procedure by 1.62 × 10 −3 , the units gr/100 scf are converted to volume percent.
(4) Using the information from paragraphs (b) (1) and (3), tables 1 and 2 shall be used to determine the required initial (Z i ) and continuous (Z c ) reduction efficiencies of SO 2 emissions.
(c) The owner or operator shall determine compliance with the SO 2 standards in § 60.642 (a) or (b) as follows:
(1) The emission reduction efficiency (R) achieved by the sulfur recovery technology shall be computed for each run using the following equation:
(2) The level indicators or manual soundings shall be used to measure the liquid sulfur accumulation rate in the product storage tanks. Readings taken at the beginning and end of each run, the tank geometry, sulfur density at the storage temperature, and sample duration shall be used to determine the sulfur production rate (S) in kg/hr (lb/hr) for each run.
(3) The emission rate of sulfur shall be computed for each run as follows:
(4) The concentration (C e ) of sulfur equivalent shall be the sum of the SO 2 and TRS concentrations, after being converted to sulfur equivalents. For each run and each of the test methods specified in this paragraph (c) of this section, the sampling time shall be at least 4 hours. Method 1 shall be used to select the sampling site. The sampling point in the duct shall be at the centroid of the cross-section if the area is less than 5 m 2 (54 ft 2 ) or at a point no closer to the walls than 1 m (39 in.) if the cross-sectional area is 5 m 2 or more, and the centroid is more than 1 m (39 in.) from the wall.
(i) Method 6 shall be used to determine the SO 2 concentration. Eight samples of 20 minutes each shall be taken at 30-minute intervals. The arithmetic average shall be the concentration for the run. The concentration shall be multiplied by 0.5 × 10 −3 to convert the results to sulfur equivalent.
(ii) Method 15 shall be used to determine the TRS concentration from reduction-type devices or where the oxygen content of the effluent gas is less than 1.0 percent by volume. The sampling rate shall be at least 3 liters/min (0.1 ft 3 /min) to insure minimum residence time in the sample line. Sixteen samples shall be taken at 15-minute intervals. The arithmetic average of all the samples shall be the concentration for the run. The concentration in ppm reduced sulfur as sulfur shall be multiplied by 1.333 × 10 −3 to convert the results to sulfur equivalent.
(iii) Method 16A or 15 shall be used to determine the reduced sulfur concentration from oxidation-type devices or where the oxygen content of the effluent gas is greater than 1.0 percent by volume. Eight samples of 20 minutes each shall be taken at 30-minute intervals. The arithmetic average shall be the concentration for the run. The concentration in ppm reduced sulfur as sulfur shall be multiplied by 1.333 × 10 −3 to convert the results to sulfur equivalent.
(iv) Method 2 shall be used to determine the volumetric flow rate of the effluent gas. A velocity traverse shall be conducted at the beginning and end of each run. The arithmetic average of the two measurements shall be used to calculate the volumetric flow rate (Q sd ) for the run. For the determination of the effluent gas molecular weight, a single integrated sample over the 4-hour period may be taken and analyzed or grab samples at 1-hour intervals may be taken, analyzed, and averaged. For the moisture content, two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes shall be taken at the beginning of the 4-hour run and near the end of the time period. The arithmetic average of the two runs shall be the moisture content for the run.
(d) To comply with § 60.646(d), the owner or operator shall obtain the information required by using the monitoring devices in paragraph (b) or (c) of this section.
§ 60.645   [Reserved]
§ 60.646   Monitoring of emissions and operations.
(a) The owner or operator subject to the provisions of § 60.642 (a) or (b) shall install, calibrate, maintain, and operate monitoring devices or perform measurements to determine the following operations information on a daily basis:
(1) The accumulation of sulfur product over each 24-hour period: The monitoring method may incorporate the use of an instrument to measure and record the liquid sulfur production rate, or may be a procedure for measuring and recording the sulfur liquid levels in the storage tanks with a level indicator or by manual soundings, with subsequent calculation of the sulfur production rate based on the tank geometry, stored sulfur density, and elapsed time between readings. The method shall be designed to be accurate within ±2 percent of the 24-hour sulfur accumulation.
(2) The H 2 S concentration in the acid gas from the sweetening unit for each 24-hour period: At least one sample per 24-hour period shall be collected and analyzed using the method specified in § 60.644(b)(1). The Administrator may require the owner or operator to demonstrate that the H 2 S concentration obtained from one or more samples over a 24-hour period is within ±20 percent of the average of 12 samples collected at equally spaced intervals during the 24-hour period. In instances where the H 2 S concentration of a single sample is not within ±20 percent of the average of the 12 equally spaced samples, the Administrator may require a more frequent sampling schedule.
(3) The average acid gas flow rate from the sweetening unit: The owner or operator shall install and operate a monitoring device to continuously measure the flow rate of acid gas. The monitoring device reading shall be recorded at least once per hour during each 24-hour period. The average acid gas flow rate shall be computed from the individual readings.
(4) The sulfur feed rate (X): For each 24-hour period, X shall be computed using the equation in § 60.644(b)(3).
(5) The required sulfur dioxide emission reduction efficiency for the 24-hour period: The sulfur feed rate and the H 2 S concentration in the acid gas for the 24-hour period as applicable, shall be used to determine the required reduction efficiency in accordance with the provisions of § 60.642(b).
(b) Where compliance is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device, the owner or operator shall install, calibrate, maintain, and operate monitoring devices and continuous emission monitors as follows:
(1) A continuous monitoring system to measure the total sulfur emission rate (E) of SO 2 in the gases discharged to the atmosphere. The SO 2 emission rate shall be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring system shall be set so that the equivalent emission limit of § 60.642(b) will be between 30 percent and 70 percent of the measurement range of the instrument system.
(2) Except as provided in paragraph (b)(3) of this section: A monitoring device to measure the temperature of the gas leaving the combustion zone of the incinerator, if compliance with § 60.642(a) is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device. The monitoring device shall be certified by the manufacturer to be accurate to within ±1 percent of the temperature being measured.
(3) Upon promulgation of a performance specification of continuous monitoring systems for total reduced sulfur compounds at sulfur recovery plants, the owner or operator may, as an alternative to paragraph (b)(2) of this section, install, calibrate, maintain, and operate a continuous emission monitoring system for total reduced sulfur compounds as required in paragraph (d) of this section in addition to a sulfur dioxide emission monitoring system. The sum of the equivalent sulfur mass emission rates from the two monitoring systems shall be used to compute the total sulfur emission rate (E).
(c) Where compliance is achieved through the use of a reduction control system not followed by a continually operated incineration device, the owner or operator shall install, calibrate, maintain, and operate a continuous monitoring system to measure the emission rate of reduced sulfur compounds as SO 2 equivalent in the gases discharged to the atmosphere. The SO 2 equivalent compound emission rate shall be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring system shall be set so that the equivalent emission limit of § 60.642(b) will be between 30 and 70 percent of the measurement range of the system. This requirement becomes effective upon promulgation of a performance specification for continuous monitoring systems for total reduced sulfur compounds at sulfur recovery plants.
(d) For those sources required to comply with paragraph (b) or (c) of this section, the average sulfur emission reduction efficiency achieved (R) shall be calculated for each 24-hour clock internal. The 24-hour interval may begin and end at any selected clock time, but must be consistent. The 24-hour average reduction efficiency (R) shall be computed based on the 24-hour average sulfur production rate (S) and sulfur emission rate (E), using the equation in § 60.644(c)(1).
(1) Data obtained from the sulfur production rate monitoring device specified in paragraph (a) of this section shall be used to determine S.
(2) Data obtained from the sulfur emission rate monitoring systems specified in paragraphs (b) or (c) of this section shall be used to calculate a 24-hour average for the sulfur emission rate (E). The monitoring system must provide at least one data point in each successive 15-minute interval. At least two data points must be used to calculate each 1-hour average. A minimum of 18 1-hour averages must be used to compute each 24-hour average.
(e) In lieu of complying with (b) or (c) of this section, those sources with a design capacity of less than 152 Mg/D (150 LT/D) of H 2 S expressed as sulfur may calculate the sulfur emission reduction efficiency achieved for each 24-hour period by:
(f) The monitoring devices required in paragraphs (b)(1), (b)(3) and (c) of this section shall be calibrated at least annually according to the manufacturer's specifications, as required by § 60.13(b).
(g) The continuous emission monitoring systems required in paragraphs (b)(1), (b)(3), and (c) of this section shall be subject to the emission monitoring requirements of § 60.13 of the General Provisions. For conducting the continuous emission monitoring system performance evaluation required by § 60.13(c), Performance Specification 2 shall apply, and Method 6 shall be used for systems required by paragraph (b) of this section.
§ 60.647   Recordkeeping and reporting requirements.
(a) Records of the calculations and measurements required in §§ 60.642 (a) and (b) and 60.646 (a) through (g) must be retained for at least 2 years following the date of the measurements by owners and operators subject to this subpart. This requirement is included under § 60.7(d) of the General Provisions.
(b) Each owner or operator shall submit a written report of excess emissions to the Administrator semiannually. For the purpose of these reports, excess emissions are defined as:
(1) Any 24-hour period (at consistent intervals) during which the average sulfur emission reduction efficiency (R) is less than the minimum required efficiency (Z).
(2) For any affected facility electing to comply with the provisions of § 60.646(b)(2), any 24-hour period during which the average temperature of the gases leaving the combustion zone of an incinerator is less than the appropriate operating temperature as determined during the most recent performance test in accordance with the provisions of § 60.646(b)(2). Each 24-hour period must consist of at least 96 temperature measurements equally spaced over the 24 hours.
(c) To certify that a facility is exempt from the control requirements of these standards, each owner or operator of a facility with a design capacity less that 2 LT/D of H 2 S in the acid gas (expressed as sulfur) shall keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H 2 S expressed as sulfur.
(d) Each owner or operator who elects to comply with § 60.646(e) shall keep, for the life of the facility, a record demonstrating that the facility's design capacity is less than 150 LT/D of H 2 S expressed as sulfur.
(e) The requirements of paragraph (b) 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 sources within the State will be relieved of obligation to comply with paragraph (b) of this section, provided that they comply with the requirements established by the State.
§ 60.648   Optional procedure for measuring hydrogen sulfide in acid gas—Tutwiler Procedure.1
1 Gas Engineers Handbook, Fuel Gas Engineering Practices, The Industrial Press, 93 Worth Street, New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket A-80-20-A, Entry II-I-67).
(a) When an instantaneous sample is desired and H 2 S concentration is ten grains per 1000 cubic foot or more, a 100 ml Tutwiler burette is used. For concentrations less than ten grains, a 500 ml Tutwiler burette and more dilute solutions are used. In principle, this method consists of titrating hydrogen sulfide in a gas sample directly with a standard solution of iodine.
(b) Apparatus. (See Figure 1.) A 100 or 500 ml capacity Tutwiler burette, with two-way glass stopcock at bottom and three-way stopcock at top which connect either with inlet tubulature or glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml subdivision; rubber tubing connecting burette with leveling bottle.
(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g iodine, and 20 to 25 g cp potassium iodide for each liter of solution. Dissolve KI in as little water as necessary; dissolve iodine in concentrated KI solution, make up to proper volume, and store in glass-stoppered brown glass bottle.
(2) Standard iodine solution, 1 ml = 0.001771 g I. Transfer 33.7 ml of above 0.1N stock solution into a 250 ml volumetric flask; add water to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard iodine solution is equivalent to 100 grains H 2 S per cubic feet of gas.
(3) Starch solution. Rub into a thin paste about one teaspoonful of wheat starch with a little water; pour into about a pint of boiling water; stir; let cool and decant off clear solution. Make fresh solution every few days.
(d) Procedure. Fill leveling bulb with starch solution. Raise (L), open cock (G), open (F) to (A), and close (F) when solutions starts to run out of gas inlet. Close (G). Purge gas sampling line and connect with (A). Lower (L) and open (F) and (G). When liquid level is several ml past the 100 ml mark, close (G) and (F), and disconnect sampling tube. Open (G) and bring starch solution to 100 ml mark by raising (L); then close (G). Open (F) momentarily, to bring gas in burette to atmospheric pressure, and close (F). Open (G), bring liquid level down to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E) and disconnect it from burette. Rinse graduated cylinder with a standard iodine solution (0.00171 g I per ml); fill cylinder and record reading. Introduce successive small amounts of iodine thru (F); shake well after each addition; continue until a faint permanent blue color is obtained. Record reading; subtract from previous reading, and call difference D.
(e) With every fresh stock of starch solution perform a blank test as follows: introduce fresh starch solution into burette up to 100 ml mark. Close (F) and (G). Lower (L) and open (G). When liquid level reaches the 10 ml mark, close (G). With air in burette, titrate as during a test and up to same end point. Call ml of iodine used C. Then,
(f) Greater sensitivity can be attained if a 500 ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine solution. Concentrations less than 1.0 grains per 100 cubic foot can be determined in this way. Usually, the starch-iodine end point is much less distinct, and a blank determination of end point, with H 2 S-free gas or air, is required.
§ 60.660   Applicability and designation of affected facility.
(a) The provisions of this subpart apply to each affected facility designated in paragraph (b) of this section that is part of a process unit that produces any of the chemicals listed in § 60.667 as a product, co-product, by-product, or intermediate, except as provided in paragraph (c).
(b) The affected facility is any of the following for which construction, modification, or reconstruction commenced after December 30, 1983, and on or before April 25, 2023:
(1) Each distillation unit not discharging its vent stream into a recovery system.
(2) Each combination of a distillation unit and the recovery system into which its vent stream is discharged.
(3) Each combination of two or more distillation units and the common recovery system into which their vent streams are discharged.
(c) Exemptions from the provisions of paragraph (a) of this section are as follows:
(1) Any distillation unit operating as part of a process unit which produces coal tar or beverage alcohols, or which uses, contains, and produces no VOC is not an affected facility.
(2) Any distillation unit that is subject to the provisions of subpart DDD is not an affected facility.
(3) Any distillation unit that is designed and operated as a batch operation is not an affected facility.
(4) Each affected facility that has a total resource effectiveness (TRE) index value greater than 8.0 is exempt from all provisions of this subpart except for §§ 60.662; 60.664 (e), (f), and (g); and 60.665 (h) and (l).
(5) Each affected facility in a process unit with a total design capacity for all chemicals produced within that unit of less than one gigagram per year is exempt from all provisions of this subpart except for the recordkeeping and reporting requirements in paragraphs (j), (l)(6), and (n) of § 60.665.
(6) Each affected facility operated with a vent stream flow rate less than 0.008 scm/min is exempt from all provisions of this subpart except for the test method and procedure and the recordkeeping and reporting requirements in §§ 60.664(h) and 60.665(i), (l)(5), and (o).
(d) Alternative means of compliance —(1) Option to comply with part 65. Owners or operators of process vents that are subject to this subpart may choose to comply with the provisions of 40 CFR part 65, subpart D, to satisfy the requirements of §§ 60.662 through 60.665 and 60.668. The provisions of 40 CFR part 65 also satisfy the criteria of paragraphs (c)(4) and (6) of this section. Other provisions applying to an owner or operator who chooses to comply with 40 CFR part 65 are provided in 40 CFR 65.1.
(2) Part 60, subpart A. Owners or operators who choose to comply with 40 CFR part 65, subpart D, must also comply with §§ 60.1, 60.2, 60.5, 60.6, 60.7(a)(1) and (4), 60.14, 60.15, and 60.16 for those process vents. All sections and paragraphs of subpart A of this part that are not mentioned in this paragraph (d)(2) do not apply to owners or operators of process vents complying with 40 CFR part 65, subpart D, except that provisions required to be met prior to implementing 40 CFR part 65 still apply. Owners and operators who choose to comply with 40 CFR part 65, subpart D, must comply with 40 CFR part 65, subpart A.
(3) Compliance date. Owners or operators who choose to comply with 40 CFR part 65, subpart D, at initial startup shall comply with paragraphs (d)(1) and (2) of this section for each vent stream on and after the date on which the initial performance test is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after the initial startup, whichever date comes first.
(4) Initial startup notification. Each owner or operator subject to the provisions of this subpart that chooses to comply with 40 CFR part 65, subpart D, at initial startup shall notify the Administrator of the specific provisions of 40 CFR 65.63(a)(1), (2), or (3), with which the owner or operator has elected to comply. Notification shall be submitted with the notifications of initial startup required by 40 CFR 65.5(b).
(e) Owners and operators of flares that are subject to the flare related requirements of this subpart and flare related requirements of any other regulation in this part or 40 CFR part 61 or 63, may elect to comply with the requirements in § 60.669a in lieu of all flare related requirements in any other regulation in this part or 40 CFR part 61 or 63.
The intent of these standards is to minimize the emissions of VOC through the application of best demonstrated technology (BDT). The numerical emission limits in these standards are expressed in terms of total organic compounds (TOC), measured as TOC less methane and ethane. This emission limit reflects the performance of BDT.
§ 60.661   Definitions.
As used in this subpart, all terms not defined here shall have the meaning given them in the Act and in subpart A of part 60, and the following terms shall have the specific meanings given them.
Batch distillation operation means a noncontinuous distillation operation in which a discrete quantity or batch of liquid feed is charged into a distillation unit and distilled at one time. After the initial charging of the liquid feed, no additional liquid is added during the distillation operation.
Boiler means any enclosed combustion device that extracts useful energy in the form of steam.
By compound means by individual stream components, not carbon equivalents.
Continuous recorder means a data recording device recording an instantaneous data value at least once every 15 minutes.
Distillation operation means an operation separating one or more feed stream(s) into two or more exit stream(s), each exit stream having component concentrations different from those in the feed stream(s). The separation is achieved by the redistribution of the components between the liquid and vapor-phase as they approach equilibrium within the distillation unit.
Distillation unit means a device or vessel in which distillation operations occur, including all associated internals (such as trays or packing) and accessories (such as reboiler, condenser, vacuum pump, steam jet, etc.), plus any associated recovery system.
Flame zone means the portion of the combustion chamber in a boiler or process heater occupied by the flame envelope.
Flow indicator means a device which indicates whether gas flow is present in a vent stream.
Halogenated vent stream means any vent stream determined to have a total concentration (by volume) of compounds containing halogens of 20 ppmv (by compound) or greater.
Incinerator means any enclosed combustion device that is used for destroying organic compounds and does not extract energy in the form of steam or process heat.
Process heater means a device that transfers heat liberated by burning fuel to fluids contained in tubes, including all fluids except water that is heated to produce steam.
Process unit means equipment assembled and connected by pipes or ducts to produce, as intermediates or final products, one or more of the chemicals in § 60.667. A process unit can operate independently if supplied with sufficient fuel or raw materials and sufficient product storage facilities.
Product means any compound or chemical listed in § 60.667 that is produced for sale as a final product as that chemical, or for use in the production of other chemicals or compounds. By-products, co-products, and intermediates are considered to be products.
Recovery device means an individual unit of equipment, such as an absorber, carbon adsorber, or condenser, capable of and used for the purpose of recovering chemicals for use, reuse, or sale.
Recovery system means an individual recovery device or series of such devices applied to the same vent stream.
Total organic compounds (TOC) means those compounds measured according to the procedures in § 60.664(b)(4). For the purposes of measuring molar composition as required in § 60.664(d)(2)(i); hourly emissions rate as required in § 60.664(d)(5) and § 60.664(e); and TOC concentration as required in § 60.665(b)(4) and § 60.665(g)(4), those compounds which the Administrator has determined do not contribute appreciably to the formation of ozone are to be excluded. The compounds to be excluded are identified in Environmental Protection Agency's statements on ozone abatement policy for State Implementation Plans (SIP) revisions (42 FR 35314; 44 FR 32042; 45 FR 32424; 45 FR 48942).
TRE index value means a measure of the supplemental total resource requirement per unit reduction of TOC associated with an individual distillation vent stream, based on vent stream flow rate, emission rate of TOC net heating value, and corrosion properties (whether or not the vent stream is halogenated), as quantified by the equation given under § 60.664(e).
Vent stream means any gas stream discharged directly from a distillation facility to the atmosphere or indirectly to the atmosphere after diversion through other process equipment. The vent stream excludes relief valve discharges and equipment leaks including, but not limited to, pumps, compressors, and valves.
§ 60.662   Standards.
Each owner or operator of any affected facility shall comply with paragraph (a), (b), or (c) of this section for each vent stream on and after the date on which the initial performance test required by §§ 60.8 and 60.664 is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after the initial start-up, whichever date comes first. Each owner or operator shall either:
(a) Reduce emissions of TOC (less methane and ethane) by 98 weight-percent, or to a TOC (less methane and ethane) concentration of 20 ppmv, on a dry basis corrected to 3 percent oxygen, whichever is less stringent. If a boiler or process heater is used to comply with this paragraph, then the vent stream shall be introduced into the flame zone of the boiler or process heater; or
(b) Combust the emissions in a flare that meets the requirements of § 60.18; or
(c) Maintain a TRE index value greater than 1.0 without use of VOC emission control devices.
§ 60.663   Monitoring of emissions and operations.
(a) The owner or operator of an affected facility that uses an incinerator to seek to comply with the TOC emission limit specified under § 60.662(a) shall install, calibrate, maintain, and operate according to manufacturer's specifications the following equipment:
(1) A temperature monitoring device equipped with a continuous recorder and having an accuracy of ±1 percent of the temperature being monitored expressed in degrees Celsius or ±0.5 °C, whichever is greater.
(i) Where an incinerator other than a catalytic incinerator is used, a temperature monitoring device shall be installed in the firebox.
(ii) Where a catalytic incinerator is used, temperature monitoring devices shall be installed in the gas stream immediately before and after the catalyst bed.
(2) A flow indicator that provides a record of vent stream flow to the incinerator at least once every hour for each affected facility. The flow indicator shall be installed in the vent stream from each affected facility at a point closest to the inlet of each incinerator and before being joined with any other vent stream.
(b) The owner or operator of an affected facility that uses a flare to seek to comply with § 60.662(b) shall install, calibrate, maintain and operate according to manufacturer's specifications the following equipment:
(1) A heat sensing device, such as an ultra-violet beam sensor or thermocouple, at the pilot light to indicate the continuous presence of a flame.
(2) A flow indicator that provides a record of vent stream flow to the flare at least once every hour for each affected facility. The flow indicator shall be installed in the vent stream from each affected facility at a point closest to the flare and before being joined with any other vent stream.
(c) The owner or operator of an affected facility that uses a boiler or process heater to seek to comply with § 60.662(a) shall install, calibrate, maintain and operate according to the manufacturer's specifications the following equipment:
(1) A flow indicator that provides a record of vent stream flow to the boiler or process heater at least once every hour for each affected facility. The flow indicator shall be installed in the vent stream from each distillation unit within an affected facility at a point closest to the inlet of each boiler or process heater and before being joined with any other vent stream.
(2) A temperature monitoring device in the firebox equipped with a continuous recorder and having an accuracy of ±1 percent of the temperature being measured expressed in degrees Celsius or ±0.5 °C, whichever is greater, for boilers or process heaters of less than 44 MW (150 million Btu/hr) heat input design capacity.
(d) Monitor and record the periods of operation of the boiler or process heater if the design heat input capacity of the boiler or process heater is 44 MW (150 million Btu/hr) or greater. The records must be readily available for inspection.
(e) The owner or operator of an affected facility that seeks to comply with the TRE index value limit specified under § 60.662(c) shall install, calibrate, maintain, and operate according to manufacturer's specifications the following equipment, unless alternative monitoring procedures or requirements are approved for that facility by the Administrator:
(1) Where an absorber is the final recovery device in the recovery system:
(i) A scrubbing liquid temperature monitoring device having an accuracy of ±1 percent of the temperature being monitored expressed in degrees Celsius or ±0.5 °C, whichever is greater, and a specific gravity monitoring device having an accuracy of ±0.02 specific gravity units, each equipped with a continuous recorder, or
(ii) An organic monitoring device used to indicate the concentration level of organic compounds exiting the recovery device based on a detection principle such as infrared, photoionization, or thermal conductivity, each equipped with a continuous recorder.
(2) Where a condenser is the final recovery device in the recovery system:
(i) A condenser exit (product side) temperature monitoring device equipped with a continuous recorder and having an accuracy of ±1 percent of the temperature being monitored expressed in degrees Celsius or ±0.5 °C, whichever is greater, or
(ii) An organic monitoring device used to monitor organic compounds exiting the recovery device based on a detection principle such as infra-red, photoionization, or thermal conductivity, each equipped with a continuous recorder.
(3) Where a carbon adsorber is the final recovery device unit in the recovery system:
(i) An integrating steam flow monitoring device having an accuracy of ±10 percent, and a carbon bed temperature monitoring device having an accuracy of ±1 percent of the temperature being monitored expressed in degrees Celsius or ±0.5 °C, whichever is greater, both equipped with a continuous recorder, or
(ii) An organic monitoring device used to indicate the concentration level of organic compounds exiting the recovery device based on a detection principle such as infra-red, photoionization, or thermal conductivity, each equipped with a continuous recorder.
(f) An owner or operator of an affected facility seeking to demonstrate compliance with the standards specified under § 60.662 with control devices other than incinerator, boiler, process heater, or flare; or recovery device other than an absorber, condenser, or carbon adsorber shall provide to the Administrator information describing the operation of the control device or recovery device and the process parameter(s) which would indicate proper operation and maintenance of the device. The Administrator may request further information and will specify appropriate monitoring procedures or requirements.
§ 60.664   Test methods and procedures.
(a) For the purpose of demonstrating compliance with § 60.662, all affected facilities shall be run at full operating conditions and flow rates during any performance test.
(b) The following methods in appendix A to this part, except as provided under § 60.8(b), shall be used as reference methods to determine compliance with the emission limit or percent reduction efficiency specified under § 60.662(a).
(1) Method 1 or 1A, as appropriate, for selection of the sampling sites. The control device inlet sampling site for determination of vent stream molar composition or TOC (less methane and ethane) reduction efficiency shall be prior to the inlet of the control device and after the recovery system.
(2) Method 2, 2A, 2C, or 2D, as appropriate, for determination of the gas volumetric flow rates.
(3) The emission rate correction factor, integrated sampling and analysis procedure of Method 3 shall be used to determine the oxygen concentration (%O 2d ) for the purposes of determining compliance with the 20 ppmv limit. The sampling site shall be the same as that of the TOC samples, and the samples shall be taken during the same time that the TOC samples are taken.
The TOC concentration corrected to 3 percent 0 2 (C c ) shall be computed using the following equation:
(4) Method 18 of appendix A-6 to this part to determine the concentration of TOC in the control device outlet and the concentration of TOC in the inlet when the reduction efficiency of the control device is to be determined. ASTM D6420-18 (incorporated by reference, see §  60.17) may be used in lieu of Method 18, if the target compounds are all known and are all listed in Section 1.1 of ASTM D6420-18 as measurable; ASTM D6420-18 may not be used for methane and ethane; and ASTM D6420-18 may not be used as a total VOC method.
(i) The sampling time for each run shall be 1 hour in which either an integrated sample or four grab samples shall be taken. If grab sampling is used then the samples shall be taken at 15-minute intervals.
(ii) The emission reduction (R) of TOC (minus methane and ethane) shall be determined using the following equation:
(iii) The mass rates of TOC (E i , E o ) shall be computed using the following equations:
(iv) The TOC concentration (C TOC ) is the sum of the individual components and shall be computed for each run using the following equation:
(c) When a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater is used to seek to comply with § 60.662(a), the requirement for an initial performance test is waived, in accordance with § 60.8(b). However, the Administrator reserves the option to require testing at such other times as may be required, as provided for in section 114 of the Act.
(d) When a flare is used to seek to comply with § 60.662(b), the flare shall comply with the requirements of § 60.18.
(e) The following test methods, except as provided under § 60.8(b), shall be used for determining the net heating value of the gas combusted to determine compliance under § 60.662(b) and for determining the process vent stream TRE index value to determine compliance under § 60.662(c).
(1)(i) Method 1 or 1A of appendix A-1 to this part, as appropriate, for selection of the sampling site. The sampling site for the vent stream flow rate and molar composition determination prescribed in paragraphs (e)(2) and (3) of this section shall be, except for the situations outlined in paragraph (e)(1)(ii) of this section, prior to the inlet of any control device, prior to any post-distillation dilution of the stream with air, and prior to any post-distillation introduction of halogenated compounds into the process vent stream. No transverse site selection method is needed for vents smaller than 10 centimeters (4 inches) in diameter.
(ii) If any gas stream other than the distillation vent stream from the affected facility is normally conducted through the final recovery device.
(A) The sampling site for vent stream flow rate and molar composition shall be prior to the final recovery device and prior to the point at which the nondistillation stream is introduced.
(B) The efficiency of the final recovery device is determined by measuring the TOC concentration using Method 18 of appendix A-6 to this part, or ASTM D6420-18 (incorporated by reference, see §  60.17) as specified in paragraph (b)(4) of this section, at the inlet to the final recovery device after the introduction of any nondistillation vent stream and at the outlet of the final recovery device.
(C) This efficiency is applied to the TOC concentration measured prior to the final recovery device and prior to the introduction of the nondistillation stream to determine the concentration of TOC in the distillation vent stream from the final recovery device. This concentration of TOC is then used to perform the calculations outlined in § 60.664(e)(4) and (5).
(2) The molar composition of the process vent stream shall be determined as follows:
(i) Method 18 of appendix A-6 to this part, or ASTM D6420-18 (incorporated by reference, see §  60.17) as specified in paragraph (b)(4) of this section, to measure the concentration of TOC including those containing halogens.
(ii) ASTM D1946-77 or 90 (Reapproved 1994) (incorporation by reference as specified in § 60.17 of this part) to measure the concentration of carbon monoxide and hydrogen.
(iii) Method 4 of appendix A-3 to this part to measure the content of water vapor.
(3) The volumetric flow rate shall be determined using Method 2, 2A, 2C, or 2D of appendix A-1 to this part, as appropriate.
(4)(i) The net heating value of the vent stream shall be calculated using the following equation:
(ii) The heats of combustion of vent stream components would be required to be determined using ASTM D2382-76 (incorporated by reference as specified in § 60.17) if published values are not available or cannot be calculated.
(5) The emission rate of TOC in the vent stream shall be calculated using the following equation:
(6) The total process vent stream concentration (by volume) of compounds containing halogens (ppmv, by compound) shall be summed from the individual concentrations of compounds containing halogens which were measured by Method 18 of appendix A-6 to this part, or ASTM D6420-18 (incorporated by reference, see §  60.17) as specified in paragraph (b)(4) of this section.
(f) For purposes of complying with § 60.662(c) the owner or operator of a facility affected by this subpart shall calculate the TRE index value of the vent stream using the equation for incineration in paragraph (e)(1) of this section for halogenated vent streams. The owner or operator of an affected facility with a nonhalogenated vent stream shall determine the TRE index value by calculating values using both the incinerator equation in (e)(1) and the flare equation in (e)(2) of this section and selecting the lower of the two values.
(1) The equation for calculating the TRE index value of a vent stream controlled by an incinerator is as follows:
(i) Where for a vent stream flow rate that is greater than or equal to 14.2 scm/min (501 scf/min) at a standard temperature of 20 °C (68 °F):
a, b, c, d, e, and f are coefficients.
The set of coefficients that apply to a vent stream can be obtained from table 1.
(ii) Where for a vent stream flow rate that is less than 14.2 scm/min (501 scf/min) at a standard temperature of 20 °C (68 °F):
a, b, c, d, e, and f are coefficients
The set of coefficients that apply to a vent stream can be obtained from table 1.
(2) The equation for calculating the TRE index value of a vent stream controlled by a flare is as follows:
a, b, c, d, and e are coefficients.
The set of coefficients that apply to a vent stream shall be obtained from table 2.
Table 2—Distillation NSPS TRE Coefficients for Vent Streams Controlled By a Flare
(g) Each owner or operator of an affected facility seeking to comply with § 60.660(c)(4) or § 60.662(c) shall recalculate the TRE index value for that affected facility whenever process changes are made. Examples of process changes include changes in production capacity, feedstock type, or catalyst type, or whenever there is replacement, removal, or addition of recovery equipment. The TRE index value shall be recalculated based on test data, or on best engineering estimates of the effects of the change to the recovery system.
(1) Where the recalculated TRE index value is less than or equal to 1.0, the owner or operator shall notify the Administrator within 1 week of the recalculation and shall conduct a performance test according to the methods and procedures required by § 60.664 in order to determine compliance with § 60.662(a). Performance tests must be conducted as soon as possible after the process change but no later than 180 days from the time of the process change.
(2) Where the initial TRE index value is greater than 8.0 and the recalculated TRE index value is less than or equal to 8.0 but greater than 1.0, the owner or operator shall conduct a performance test in accordance with §§ 60.8 and 60.664 and shall comply with §§ 60.663, 60.664 and 60.665. Performance tests must be conducted as soon as possible after the process change but no later than 180 days from the time of the process change.
(h) Any owner or operator subject to the provisions of this subpart seeking to demonstrate compliance with § 60.660(c)(6) shall use Method 2, 2A, 2C, or 2D as appropriate, for determination of volumetric flow rate.
§ 60.665   Reporting and recordkeeping requirements.
(a) Each owner or operator subject to § 60.662 shall notify the Administrator of the specific provisions of § 60.662 (§ 60.662 (a), (b), or (c)) with which the owner or operator has elected to comply. Notification shall be submitted with the notification of initial start-up required by § 60.7(a)(3). If an owner or operator elects at a later date to use an alternative provision of § 60.662 with which he or she will comply, then the Administrator shall be notified by the owner or operator 90 days before implementing a change and, upon implementing the change, a performance test shall be performed as specified by § 60.664 within 180 days.
(b) Each owner or operator subject to the provisions of this subpart shall keep an up-to-date, readily accessible record of the following data measured during each performance test, and also include the following data in the report of the initial performance test required under § 60.8. Where a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater is used to comply with § 60.662(a), a report containing performance test data need not be submitted, but a report containing the information in § 60.665(b)(2)(i) is required. The same data specified in this section shall be submitted in the reports of all subsequently required performance tests where either the emission control efficiency of a control device, outlet concentration of TOC, or the TRE index value of a vent stream from a recovery system is determined. Beginning on July 15, 2024, owners and operators must submit the performance test report following the procedures specified in paragraph (q) of this section. Data collected using test methods that are supported by the EPA's Electronic Reporting Tool (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 must be submitted in a file format generated using the EPA's ERT. Alternatively, the owner or operator 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 as listed on the EPA's ERT website at the time of the test must be included as an attachment in the ERT or an alternate electronic file.
(1) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.662(a) through use of either a thermal or catalytic incinerator:
(i) The average firebox temperature of the incinerator (or the average temperature upstream and downstream of the catalyst bed for a catalytic incinerator), measured at least every 15 minutes and averaged over the same time period of the performance testing, and
(ii) The percent reduction of TOC determined as specified in § 60.664(b) achieved by the incinerator, or the concentration of TOC (ppmv, by compound) determined as specified in § 60.664(b) at the outlet of the control device on a dry basis corrected to 3 percent oxygen.
(2) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.662(a) through use of a boiler or process heater:
(i) A description of the location at which the vent stream is introduced into the boiler or process heater, and
(ii) The average combustion temperature of the boiler or process heater with a design heat input capacity of less than 44 MW (150 million Btu/hr) measured at least every 15 minutes and averaged over the same time period of the performance testing.
(3) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.662(b) through use of a smokeless flare, flare design (i.e., steam-assisted, air-assisted or nonassisted), all visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the performance test, continuous records of the flare pilot flame monitoring, and records of all periods of operations during which the pilot flame is absent.
(4) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.662(c):
(i) Where an absorber is the final recovery device in the recovery system, the exit specific gravity (or alternative parameter which is a measure of the degree of absorbing liquid saturation, if approved by the Administrator), and average exit temperature, of the absorbing liquid measured at least every 15 minutes and averaged over the same time period of the performance testing (both measured while the vent stream is normally routed and constituted), or
(ii) Where a condenser is the final recovery device in the recovery system, the average exit (product side) temperature measured at least every 15 minutes and averaged over the same time period of the performance testing while the vent stream is routed and constituted normally, or
(iii) Where a carbon adsorber is the final recovery device in the recovery system, the total steam mass flow measured at least every 15 minutes and averaged over the same time period of the performance test (full carbon bed cycle), temperature of the carbon bed after regeneration (and within 15 minutes of completion of any cooling cycle(s)), and duration of the carbon bed steaming cycle (all measured while the vent stream is routed and constituted normally), or
(iv) As an alternative to § 60.665(b)(4) ((i), (ii) or (iii), the concentration level or reading indicated by the organics monitoring device at the outlet of the absorber, condenser, or carbon adsorber, measured at least every 15 minutes and averaged over the same time period of the performance testing while the vent stream is normally routed and constituted.
(v) All measurements and calculations performed to determine the TRE index value of the vent stream.
(c) Each owner or operator subject to the provisions of this subpart shall keep up-to-date, readily accessible continuous records of the equipment operating parameters specified to be monitored under § 60.663 (a) and (c) as well as up-to-date, readily accessible records of periods of operation during which the parameter boundaries established during the most recent performance test are exceeded. The Administrator may at any time require a report of these data. Where a combustion device is used to comply with § 60.662(a), periods of operation during which the parameter boundaries established during the most recent performance tests are exceeded are defined as follows:
(1) For thermal incinerators, all 3-hour periods of operation during which the average combustion temperature was more than 28 °C (50 °F) below the average combustion temperature during the most recent performance test at which compliance with § 60.662(a) was determined.
(2) For catalytic incinerators, all 3-hour periods of operation during which the average temperature of the vent stream immediately before the catalyst bed is more than 28 °C (50 °F) below the average temperature of the vent stream during the most recent performance test at which compliance with § 60.662(a) was determined. The owner or operator also shall record all 3-hour periods of operation during which the average temperature difference across the catalyst bed is less than 80 percent of the average temperature difference of the device during the most recent performance test at which compliance with § 60.662(a) was determined.
(3) All 3-hour periods of operation during which the average combustion temperature was more than 28 °C (50 °F) below the average combustion temperature during the most recent performance test at which compliance with § 60.662(a) was determined for boilers or process heaters with a design heat input capacity of less than 44 MW (150 million Btu/hr).
(4) For boilers or process heaters, whenever there is a change in the location at which the vent stream is introduced into the flame zone as required under § 60.662(a).
(d) Each owner or operator subject to the provisions of this subpart shall keep up to date, readily accessible continuous records of the flow indication specified under § 60.663(a)(2), § 60.663(b)(2) and § 60.663(c)(1), as well as up-to-date, readily accessible records of all periods when the vent stream is diverted from the control device or has no flow rate.
(e) Each owner or operator subject to the provisions of this subpart who uses a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater to comply with § 60.662(a) shall keep an up-to-date, readily accessible record of all periods of operation of the boiler or process heater. (Examples of such records could include records of steam use, fuel use, or monitoring data collected pursuant to other State or Federal regulatory requirements.)
(f) Each owner or operator subject to the provisions of this subpart shall keep up-to-date, readily accessible continuous records of the flare pilot flame monitoring specified under § 60.663(b), as well as up-to-date, readily accessible records of all periods of operations in which the pilot flame is absent.
(g) Each owner or operator subject to the provisions of this subpart shall keep up-to-date, readily accessible continuous records of the equipment operating parameters specified to be monitored under § 60.663(e), as well as up-to-date, readily accessible records of periods of operation during which the parameter boundaries established during the most recent performance test are exceeded. The Administrator may at any time require a report of these data. Where an owner or operator seeks to comply with § 60.662(c), periods of operation during which the parameter boundaries established during the most recent performance tests are exceeded are defined as follows:
(1) Where an absorber is the final recovery device in a recovery system, and where an organic compound monitoring device is not used:
(i) All 3-hour periods of operation during which the average absorbing liquid temperature was more than 11 °C (20 °F) above the average absorbing liquid temperature during the most recent performance test, or
(ii) All 3-hour periods of operation during which the average absorbing liquid specific gravity was more than 0.1 unit above, or more than 0.1 unit below, the average absorbing liquid specific gravity during the most recent performance test (unless monitoring of an alternative parameter, which is a measure of the degree of absorbing liquid saturation, is approved by the Administrator, in which case he will define appropriate parameter boundaries and periods of operation during which they are exceeded).
(2) Where a condenser is the final recovery device in a system, and where an organic compound monitoring device is not used, all 3-hour periods of operation during which the average exit (product side) condenser operating temperature was more than 6 °C (1 1 °F) above the average exit (product side) operating temperature during the most recent performance test.
(3) Where a carbon adsorber is the final recovery device in a system, and where an organic compound monitoring device is not used:
(i) All carbon bed regeneration cycles during which the total mass steam flow was more than 10 percent below the total mass steam flow during the most recent performance test, or
(ii) All carbon bed regeneration cycles during which the temperature of the carbon bed after regeneration (and after completion of any cooling cycle(s)) was more than 10 percent greater than the carbon bed temperature (in degrees Celsius) during the most recent performance test.
(4) Where an absorber, condenser, or carbon adsorber is the final recovery device in the recovery system and where an organic compound monitoring device is used, all 3-hour periods of operation during which the average organic compound concentration level or reading of organic compounds in the exhaust gases is more than 20 percent greater than the exhaust gas organic compound concentration level or reading measured by the monitoring device during the most recent performance test.
(h) Each owner or operator of an affected facility subject to the provisions of this subpart and seeking to demonstrate compliance with § 60.662(c) shall keep up-to-date, readily accessible records of:
(1) Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal or addition of recovery equipment or a distillation unit;
(2) Any recalculation of the TRE index value performed pursuant to § 60.664(g); and
(3) The results of any performance test performed pursuant to the methods and procedures required by § 60.664(e).
(i) Each owner or operator of an affected facility that seeks to comply with the requirements of this subpart by complying with the flow rate cutoff in § 60.660(c)(6) shall keep up-to-date, readily accessible records to indicate that the vent stream flow rate is less than 0.008 scm/min (0.3 scf/min) and of any change in equipment or process operation that increases the operating vent stream flow rate, including a measurement of the new vent stream flow rate.
(j) Each owner or operator of an affected facility that seeks to comply with the requirements of this subpart by complying with the design production capacity provision in § 60.660(c)(5) shall keep up-to-date, readily accessible records of any change in equipment or process operation that increases the design production capacity of the process unit in which the affected facility is located.
(k) Each owner and operator subject to the provisions of this subpart is exempt from the quarterly reporting requirements contained in § 60.7(c) of the General Provisions.
(l) Each owner or operator that seeks to comply with the requirements of this subpart by complying with the requirements of § 60.660 (c)(4), (c)(5), or (c)(6) or § 60.662 shall submit to the Administrator semiannual reports of the following recorded information. The initial report shall be submitted within 6 months after the initial start-up date. On and after July 15, 2025 or once the report template for this subpart has been available on the Compliance and Emissions Data Reporting Interface (CEDRI) website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for 1 year, whichever date is later, owners and operators must submit all subsequent reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in paragraph (q) 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.
(1) Exceedances of monitored parameters recorded under § 60.665 (c) and (g).
(2) All periods recorded under § 60.665(d) when the vent stream is diverted from the control device or has no flow rate.
(3) All periods recorded under § 60.665(e) when the boiler or process heater was not operating.
(4) All periods recorded under § 60.665(f) in which the pilot flame of the flare was absent.
(5) Any change in equipment or process operation that increases the operating vent stream flow rate above the low flow exemption level in § 60.660(c)(6), including a measurement of the new vent stream flow rate, as recorded under § 60.665(i). These must be reported as soon as possible after the change and no later than 180 days after the change. These reports may be submitted either in conjunction with semiannual reports or as a single separate report. A performance test must be completed with the same time period to verify the recalculated flow value and to obtain the vent stream characteristics of heating value and E TOC . The performance test is subject to the requirements of § 60.8, and the performance test must be reported according to paragraph (b) of this section. Unless the facility qualifies for an exemption under the low capacity exemption status in § 60.660(c)(5), the facility must begin compliance with the requirements set forth in § 60.662.
(6) Any change in equipment or process operation, as recorded under paragraph (j) of this section, that increases the design production capacity above the low capacity exemption level in § 60.660(c)(5) and the new capacity resulting from the change for the distillation process unit containing the affected facility. These must be reported as soon as possible after the change and no later than 180 days after the change. These reports may be submitted either in conjunction with semiannual reports or as a single separate report. A performance test must be completed within the same time period to obtain the vent stream flow rate, heating value, and E TOC . The performance test is subject to the requirements of § 60.8, and the performance test must be reported according to paragraph (b) of this section. The facility must begin compliance with the requirements set forth in § 60.660(d) or § 60.662. If the facility chooses to comply with § 60.662, the facility may qualify for an exemption in § 60.660(c)(4) or (6).
(7) Any recalculation of the TRE index value, as recorded under § 60.665(h).
(m) The requirements of § 60.665(l) 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 sources within the State will be relieved of the obligation to comply with § 60.665(l), 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.
(n) Each owner or operator that seeks to demonstrate compliance with § 60.660(c)(5) must submit to the Administrator an initial report detailing the design production capacity of the process unit.
(o) Each owner or operator that seeks to demonstrate compliance with § 60.660(c)(6) must submit to the Administrator an initial report including a flow rate measurement using the test methods specified in § 60.664.
(p) The Administrator will specify appropriate reporting and recordkeeping requirements where the owner or operator of an affected facility complies with the standards specified under § 60.662 other than as provided under § 60.663(a), (b), (c) and (d).
(q) If an owner or operator is required to submit notifications or reports following the procedure specified in this paragraph (q), the owner or operator 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 the owner or operator. Do not use CEDRI to submit information the owner or operator claims as CBI. Although the EPA does not expect persons to assert a claim of CBI, if an owner or operator wishes to assert a CBI claim for some of the information in the report or notification, the owner or operator 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 (q)(1) and (2) of this section. Clearly mark the part or all of the information that claimed 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. The owner or operator 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 (q).
(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. Owners and operators who do not have their own file sharing service and who require assistance with submitting large electronic files that exceed the file size limit for email attachments should email oaqpscbi@epa.gov to request a file transfer link.
(2) If an owner or operator cannot transmit the file electronically, the owner or operator 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.
(r) Owners and operators required to electronically submit notifications or reports through CEDRI in the EPA's CDX may assert a claim of EPA system outage for failure to timely comply with the electronic submittal requirement. To assert a claim of EPA system outage, owners and operators must meet the requirements outlined in paragraphs (r)(1) through (7) of this section.
(1) The owner or operator 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) The owner or operator must submit notification to the Administrator in writing as soon as possible following the date the owner or operator first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(5) The owner or operator 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 the owner or operator proposes to report, or if the owner or operator has already met the reporting requirement at the time of the notification, the date the report was submitted.
(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.
(s) Owners and operators required to electronically submit notifications or reports through CEDRI in the EPA's CDX may assert a claim of force majeure for failure to timely comply with the electronic submittal requirement. To assert a claim of force majeure, owners and operators must meet the requirements outlined in paragraphs (s)(1) through (5) of this section.
(1) An owner or operator 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 the owner or operator 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) The owner or operator must submit notification to the Administrator in writing as soon as possible following the date the owner or operator first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.
(3) An owner or operator 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 the owner or operator proposes to report, or if the owner or operator has already met the reporting requirement at the time of the notification, the date the report was submitted.
(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.
§ 60.666   Reconstruction.
For purposes of this subpart “fixed capital cost of the new components,” as used in § 60.15, includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following December 30, 1983. 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.
§ 60.667   Chemicals affected by subpart NNN.
* CAS numbers refer to the Chemical Abstracts Registry numbers assigned to specific chemicals, isomers, or mixtures of chemicals. Some isomers or mixtures that are covered by the standards do not have CAS numbers assigned to them. The standards apply to all of the chemicals listed, whether CAS numbers have been assigned or not.
§ 60.668   Delegation of authority.
(a) In delegating implementation and enforcement authority to a State under § 111(c) of the Act, the authorities contained in paragraph (b) of this section shall be retained by the Administrator and not transferred to a State.
(b) Authorities which will not be delegated to States: § 60.663(e) and approval of an alternative to any electronic reporting to the EPA required by this subpart.
§ 60.660a   Am I subject to this subpart?
(a) You are subject to this subpart if you operate an affected facility designated in paragraph (b) of this section that produces any of the chemicals listed in § 60.667a as a product, co-product, by-product, or intermediate, except as provided in paragraph (c) of this section.
(b) The affected facility is any of the following for which construction, modification, or reconstruction commenced after April 25, 2023:
(1) Each distillation unit not discharging its vent stream into a recovery system.
(2) Each combination of a distillation unit and the recovery system into which its vent stream is discharged.
(3) Each combination of two or more distillation units and the common recovery system into which their vent streams are discharged.
(c) Exemptions from the provisions of paragraph (a) of this section are as follows:
(1) Any distillation unit operating as part of a process unit which produces coal tar or beverage alcohols, or which uses, contains, and produces no VOC is not an affected facility.
(2) Any distillation unit that is subject to the provisions of subpart DDD is not an affected facility.
(3) Any distillation unit that is designed and operated as a batch operation is not an affected facility.
(4) Each affected facility in a process unit with a total design capacity for all chemicals produced within that unit of less than one gigagram per year is exempt from all provisions of this subpart except for the recordkeeping and reporting requirements in § 60.665a(h), (j)(6), and (o).
(5) Each affected facility operated with a vent stream flow rate less than 0.008 standard cubic meter per minute (scm/min) is exempt from all provisions of this subpart except for the test method and procedure and the recordkeeping and reporting requirements in § 60.664a(e) and § 60.665a(i), (j)(7), and (p).
(6) Each affected facility operated with a vent stream flow rate less than 0.001 pound per hour (lb/hr) of TOC is exempt from all provisions of this subpart except for the test method and procedure and the recordkeeping and reporting requirements in §§ 60.664a(f) and 60.665a(i), (j)(7), and (p).
(7) A vent stream going to a fuel gas system as defined in § 63.661a.
§ 60.661a   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.
Batch distillation operation means a noncontinuous distillation operation in which a discrete quantity or batch of liquid feed is charged into a distillation unit and distilled at one time. After the initial charging of the liquid feed, no additional liquid is added during the distillation operation.
Breakthrough means the time when the level of TOC, measured at the outlet of the first bed, has been detected is at the highest concentration allowed to be discharged from the adsorber system and indicates that the adsorber bed should be replaced.
Boiler means any enclosed combustion device that extracts useful energy in the form of steam.
By compound means by individual stream components, not carbon equivalents.
Closed vent system means a system that is not open to the atmosphere and is composed of piping, ductwork, connections, and, if necessary, flow inducing devices that transport gas or vapor from an emission point to a control device.
Continuous recorder means a data recording device recording an instantaneous data value at least once every 15 minutes.
Distillation operation means an operation separating one or more feed stream(s) into two or more exit stream(s), each exit stream having component concentrations different from those in the feed stream(s). The separation is achieved by the redistribution of the components between the liquid and vapor-phase as they approach equilibrium within the distillation unit.
Distillation unit means a device or vessel in which distillation operations occur, including all associated internals (such as trays or packing) and accessories (such as reboiler, condenser, vacuum pump, steam jet, etc.), plus any associated recovery system.
Flame zone means the portion of the combustion chamber in a boiler or process heater occupied by the flame envelope.
Flow indicator means a device which indicates whether gas flow is present in a vent stream.
Fuel gas means gases that are combusted to derive useful work or heat.
Fuel gas system means the offsite and onsite piping and flow and pressure control system that gathers gaseous stream(s) generated by onsite operations, may blend them with other sources of gas, and transports the gaseous stream for use as fuel gas in combustion devices or in in-process combustion equipment such as furnaces and gas turbines either singly or in combination.
Halogenated vent stream means any vent stream determined to have a total concentration (by volume) of compounds containing halogens of 20 ppmv (by compound) or greater.
Incinerator means any enclosed combustion device that is used for destroying organic compounds and does not extract energy in the form of steam or process heat.
Pressure-assisted multi-point flare means a flare system consisting of multiple flare burners in staged arrays whereby the vent stream pressure is used to promote mixing and smokeless operation at the flare burner tips. Pressure-assisted multi-point flares are designed for smokeless operation at velocities up to Mach = 1 conditions ( i.e., sonic conditions), can be elevated or at ground level, and typically use cross-lighting for flame propagation to combust any flare vent gases sent to a particular stage of flare burners.
Primary fuel means the fuel fired through a burner or a number of similar burners. The primary fuel provides the principal heat input to the device, and the amount of fuel is sufficient to sustain operation without the addition of other fuels.
Process heater means a device that transfers heat liberated by burning fuel to fluids contained in tubes, including all fluids except water that is heated to produce steam.
Process unit means equipment assembled and connected by pipes or ducts to produce, as intermediates or final products, one or more of the chemicals in § 60.667a. A process unit can operate independently if supplied with sufficient fuel or raw materials and sufficient product storage facilities.
Product means any compound or chemical listed in § 60.667a that is produced for sale as a final product as that chemical, or for use in the production of other chemicals or compounds. By-products, co-products, and intermediates are considered to be products.
Recovery device means an individual unit of equipment, such as an absorber, carbon adsorber, or condenser, capable of and used for the purpose of recovering chemicals for use, reuse, or sale.
Recovery system means an individual recovery device or series of such devices applied to the same vent stream.
Relief valve means a valve used only to release an unplanned, nonroutine discharge. A relief valve discharge results from an operator error, a malfunction such as a power failure or equipment failure, or other unexpected cause that requires immediate venting of gas from process equipment in order to avoid safety hazards or equipment damage.
Total organic compounds (TOC) means those compounds measured according to the procedures in Method 18 of appendix A-6 of this part or the concentration of organic compounds measured according to the procedures in Method 21 or Method 25A of appendix A-7 of this part.
Vent stream means any gas stream discharged directly from a distillation facility to the atmosphere or indirectly to the atmosphere after diversion through other process equipment. The vent stream excludes equipment leaks including, but not limited to, pumps, compressors, and valves.
§ 60.662a   What standards and associated requirements must I meet?
(a) You must comply with the emission limits and standards specified in table 1 to this subpart and the requirements specified in paragraphs (b) and (c) of this section for each vent stream on and after the date on which the initial performance test required by §§ 60.8 and 60.664a is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after the initial start-up, whichever date comes first. The standards in this section apply at all times, including periods of startup, shutdown and malfunction. As provided in § 60.11(f), this provision supersedes the exemptions for periods of startup, shutdown and malfunction in the general provisions in subpart A of this part.
(b) The following release events from an affected facility are a violation of the emission limits and standards specified in table 1 to this subpart.
(1) Any relief valve discharge to the atmosphere of a vent stream.
(2) The use of a bypass line at any time on a closed vent system to divert emissions to the atmosphere, or to a control device or recovery device not meeting the requirements specified in § 60.663a.
(c) You may designate a vent stream as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed, or placed into service. You must comply with the applicable requirements in paragraphs (c)(1) through (3) of this section for each maintenance vent. Any vent stream designated as a maintenance vent is only subject to the maintenance vent provisions in this paragraph (c) and the associated recordkeeping and reporting requirements in § 60.665a(g), respectively.
(1) Prior to venting to the atmosphere, remove process liquids from the equipment as much as practical and depressurize the equipment to either: A flare meeting the requirements of § 60.669a, as applicable, or using any combination of a non-flare control device or recovery device meeting the requirements in table 1 to this subpart until one of the following conditions, as applicable, is met.
(i) The vapor in the equipment served by the maintenance vent has a lower explosive limit (LEL) of less than 10 percent.
(ii) If there is no ability to measure the LEL of the vapor in the equipment based on the design of the equipment, the pressure in the equipment served by the maintenance vent is reduced to 5 pounds per square inch gauge (psig) or less. Upon opening the maintenance vent, active purging of the equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside the equipment if the maintenance vent is a hatch or similar type of opening) is less than 10 percent.
(iii) The equipment served by the maintenance vent contains less than 50 pounds of total VOC.
(iv) If, after applying best practices to isolate and purge equipment served by a maintenance vent, none of the applicable criterion in paragraphs (c)(1)(i) through (iii) of this section can be met prior to installing or removing a blind flange or similar equipment blind, then the pressure in the equipment served by the maintenance vent must be reduced to 2 psig or less before installing or removing the equipment blind. During installation or removal of the equipment blind, active purging of the equipment may be used provided the equipment pressure at the location where purge gas is introduced remains at 2 psig or less.
(2) Except for maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, you must determine the LEL or, if applicable, equipment pressure using process instrumentation or portable measurement devices and follow procedures for calibration and maintenance according to manufacturer's specifications.
(3) For maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, you must determine mass of VOC in the equipment served by the maintenance vent based on the equipment size and contents after considering any contents drained or purged from the equipment. Equipment size may be determined from equipment design specifications. Equipment contents may be determined using process knowledge.
§ 60.663a   What are my monitoring, installation, operation, and maintenance requirements?
(a) Except as specified in paragraphs (a)(5) through (7) of this section, if you use a non-flare control device or recovery system to comply with the TOC emission limit specified in table 1 to this subpart, then you must comply with paragraphs (a)(1) through (4), (b), and (c) of this section.
(1) Install a continuous parameter monitoring system(s) (CPMS) and monitor the operating parameter(s) applicable to the control device or recovery system as specified in table 2 to this subpart or established according to paragraph (c) of this section.
(2) Establish the applicable minimum, maximum, or range for the operating parameter limit as specified in table 3 to this subpart or established according to paragraph (c) of this section by calculating the value(s) as the arithmetic average of operating parameter measurements recorded during the three test runs conducted for the most recent performance test. You may operate outside of the established operating parameter limit(s) during subsequent performance tests in order to establish new operating limits. You must include the updated operating limits with the performance test results submitted to the Administrator pursuant to § 60.665a(b). Upon establishment of a new operating limit, you must thereafter operate under the new operating limit. If the Administrator determines that you did not conduct the performance test in accordance with the applicable requirements or that the operating limit established during the performance test does not correspond to the conditions specified in § 60.664a(a), then you must conduct a new performance test and establish a new operating limit.
(3) Monitor, record, and demonstrate continuous compliance using the minimum frequencies specified in table 3 to this subpart or established according to paragraph (c) of this section.
(4) Comply with the calibration and quality control requirements as specified in table 4 to this subpart or established according to paragraph (c) of this section that are applicable to the CPMS used.
(5) Any vent stream introduced with primary fuel into a boiler or process heater is exempt from the requirements specified in paragraphs (a)(1) through (4) of this section.
(6) If you vent emissions through a closed vent system to an adsorber(s) that cannot be regenerated or a regenerative adsorber(s) that is regenerated offsite, then you must install a system of two or more adsorber units in series and comply with the requirements specified in paragraphs (a)(6)(i) through (iii) of this section in addition to the requirements specified in paragraphs (a)(1) through (4) of this section.
(i) Conduct an initial performance test or design evaluation of the adsorber and establish the breakthrough limit and adsorber bed life.
(ii) Monitor the TOC concentration through a sample port at the outlet of the first adsorber bed in series according to the schedule in paragraph (a)(6)(iii)(B) of this section. You must measure the concentration of TOC using either a portable analyzer, in accordance with Method 21 of appendix A-7 of this part using methane, propane, or isobutylene as the calibration gas or Method 25A of appendix A-7 of this part using methane or propane as the calibration gas.
(iii) Comply with paragraph (a)(6)(iii)(A) of this section and comply with the monitoring frequency according to paragraph (a)(6)(iii)(B) of this section.
(A) The first adsorber in series must be replaced immediately when breakthrough, as defined in § 60.661a, is detected between the first and second adsorber. The original second adsorber (or a fresh canister) will become the new first adsorber and a fresh adsorber will become the second adsorber. For purposes of this paragraph (a)(6)(iii)(A), “immediately” means within 8 hours of the detection of a breakthrough for adsorbers of 55 gallons or less, and within 24 hours of the detection of a breakthrough for adsorbers greater than 55 gallons. You must monitor at the outlet of the first adsorber within 3 days of replacement to confirm it is performing properly.
(B) Based on the adsorber bed life established according to paragraph (a)(6)(i) of this section and the date the adsorbent was last replaced, conduct monitoring to detect breakthrough at least monthly if the adsorbent has more than 2 months of life remaining, at least weekly if the adsorbent has between 2 months and 2 weeks of life remaining, and at least daily if the adsorbent has 2 weeks or less of life remaining.
(7) If you install a continuous emissions monitoring system (CEMS) to demonstrate compliance with the TOC standard in table 1 of this subpart, you must comply with the requirements specified in § 60.664a(g) in lieu of the requirements specified in paragraphs (a)(1) through (4) and (c) of this section.
(b) If you vent emissions through a closed vent system to a boiler or process heater, then the vent stream must be introduced into the flame zone of the boiler or process heater.
(c) If you seek to demonstrate compliance with the standards specified under § 60.662a with control devices other than an incinerator, boiler, process heater, or flare; or recovery devices other than an absorber, condenser, or carbon adsorber, you shall provide to the Administrator prior to conducting the initial performance test information describing the operation of the control device or recovery device and the parameter(s) which would indicate proper operation and maintenance of the device and how the parameter(s) are indicative of control of TOC emissions. The Administrator may request further information and will specify appropriate monitoring procedures or requirements, including operating parameters to be monitored, averaging times for determining compliance with the operating parameter limits, and ongoing calibration and quality control requirements.
§ 60.664a   What test methods and procedures must I use to determine compliance with the standards?
(a) For the purpose of demonstrating compliance with the emission limits and standards specified in table 1 to this subpart, all affected facilities must be run at full operating conditions and flow rates during any performance test. Performance tests are not required if you determine compliance using a CEMS that meets the requirements outlined in paragraph (g) of this section.
(1) Conduct initial performance tests no later than the date required by § 60.8(a).
(2) Conduct subsequent performance tests no later than 60 calendar months after the previous performance test.
(b) The following methods, except as provided in § 60.8(b) must, must be used as reference methods to determine compliance with the emission limit or percent reduction efficiency specified in table 1 to this subpart for non-flare control devices and/or recovery systems.
(1) Method 1 or 1A of appendix A-1 to this part, as appropriate, for selection of the sampling sites. The inlet sampling site for determination of vent stream molar composition or TOC (less methane and ethane) reduction efficiency shall be prior to the inlet of the control device or, if equipped with a recovery system, then prior to the inlet of the first recovery device in the recovery system.
(2) Method 2, 2A, 2C, or 2D of appendix A-1 to this part, as appropriate, for determination of the gas volumetric flow rates.
(3) Method 3A of appendix A-2 to this part or the manual method in ANSI/ASME PTC 19.10-1981 (incorporated by reference, see §  60.17) must be used to determine the oxygen concentration (%O2d) for the purposes of determining compliance with the 20 ppmv limit. The sampling site must be the same as that of the TOC samples, and the samples must be taken during the same time that the TOC samples are taken. The TOC concentration corrected to 3 percent O 2 (C c ) must be computed using the following equation:
(4) Method 18 of appendix A-6 to this part to determine the concentration of TOC in the control device outlet or in the outlet of the final recovery device in a recovery system, and to determine the concentration of TOC in the inlet when the reduction efficiency of the control device or recovery system is to be determined. ASTM D6420-18 (incorporated by reference, see § 60.17) may be used in lieu of Method 18, if the target compounds are all known and are all listed in section 1.1 of ASTM D6420-18 as measurable; ASTM D6420-18 may not be used for methane and ethane; and ASTM D6420-18 must not be used as a total VOC method.
(i) The sampling time for each run must be 1 hour in which either an integrated sample or at least four grab samples must be taken. If grab sampling is used then the samples must be taken at 15-minute intervals.
(ii) The emission reduction (R) of TOC (minus methane and ethane) must be determined using the following equation:
(iii) The mass rates of TOC (E i , E o ) must be computed using the following equations:
(iv) The TOC concentration (C TOC ) is the sum of the individual components and must be computed for each run using the following equation:
(c) The requirement for initial and subsequent performance tests are waived, in accordance with § 60.8(b), for the following:
(1) When a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater is used to seek to comply with the emission limit or percent reduction efficiency specified in table 1 to this subpart.
(2) When a vent stream is introduced into a boiler or process heater with the primary fuel.
(3) When a boiler or process heater burning hazardous waste is used for which the owner or operator:
(i) Has been issued a final permit under 40 CFR part 270 and complies with the requirements of 40 CFR part 266, subpart H;
(ii) Has certified compliance with the interim status requirements of 40 CFR part 266, subpart H;
(iii) Has submitted a Notification of Compliance under 40 CFR 63.1207(j) and complies with the requirements of 40 CFR part 63, subpart EEE; or
(iv) Complies with 40 CFR part 63, subpart EEE and will submit a Notification of Compliance under 40 CFR 63.1207(j) by the date the owner or operator would have been required to submit the initial performance test report for this subpart.
(4) The Administrator reserves the option to require testing at such other times as may be required, as provided for in section 114 of the Act.
(d) For purposes of complying with the 98 weight-percent reduction in § 60.702a(a), if the vent stream entering a boiler or process heater with a design capacity less than 44 MW (150 million Btu/hour) is introduced with the combustion air or as secondary fuel, the weight-percent reduction of TOC (minus methane and ethane) across the combustion device shall be determined by comparing the TOC (minus methane and ethane) in all combusted vent streams, primary fuels, and secondary fuels with the TOC (minus methane and ethane) exiting the combustion device.
(e) Any owner or operator subject to the provisions of this subpart seeking to demonstrate compliance with § 60.660a(c)(5) must use Method 2, 2A, 2C, or 2D of appendix A-1 to this part as appropriate, for determination of volumetric flow rate. The owner or operator must conduct three velocity traverses and determine the volumetric flow rate for each traverse. If the pipe or duct is smaller than four inches in diameter, the owner operator may conduct the measurement at the centroid of the duct instead of conducting a traverse; the measurement period must be at least five minutes long and data must be recorded at least once every 30 seconds. Owners and operators who conduct the determination with Method 2A or 2D must record volumetric flow rate every 30 seconds for at least five minutes.
(f) Any owner or operator subject to the provisions of this subpart seeking to demonstrate compliance with § 60.660a(c)(6) must use the following methods:
(1) Method 1 or 1A of appendix A-1 to this part, as appropriate.
(2) Method 2, 2A, 2C, or 2D of appendix A-1 to this part, as appropriate, for determination of the gas volumetric flow rates.
(3) Method 18 of appendix A-6 to this part to determine the concentration of TOC. ASTM D6420-18 (incorporated by reference, see § 60.17) may be used in lieu of Method 18, if the target compounds are all known and are all listed in Section 1.1 of ASTM D6420-18 as measurable; ASTM D6420-18 may not be used for methane and ethane; and ASTM D6420-18 must not be used as a total VOC method.
(i) The sampling site must be at a location that provides a representative sample of the vent stream.
(ii) Perform three test runs. The sampling time for each run must be 1 hour in which either an integrated sample or at least four grab samples must be taken. If grab sampling is used then the samples must be taken at 15-minute intervals.
(iii) The mass rate of TOC (E) must be computed using the following equation:
(g) If you use a CEMS to demonstrate initial and continuous compliance with the TOC standard in table 1 of this subpart, each CEMS must be installed, operated and maintained according to the requirements in § 60.13 and paragraphs (g)(1) through (5) of this section.
(1) You must use a CEMS that is capable of measuring the target analyte(s) as demonstrated using either process knowledge of the control device inlet stream or the screening procedures of Method 18 of appendix A-6 to this part on the control device inlet stream. If your CEMS is located after a combustion device and inlet stream to that device includes methanol or formaldehyde, you must use a CEMS which meets the requirements in Performance Specification 9 or 15 of appendix B to this part.
(2) Each CEMS must be installed, operated, and maintained according to the applicable performance specification of appendix B to this part and the applicable quality assurance procedures of appendix F to this part. Locate the sampling probe or other interface at a measurement location such that you obtain representative measurements of emissions from the affected facility.
(3) Conduct a performance evaluation of each CEMS within 180 days of installation of the monitoring system. Conduct subsequent performance evaluations of the CEMS no later than 12 calendar months after the previous performance evaluation. The results each performance evaluation must be submitted in accordance with § 60.665a(b)(1).
(4) You must determine TOC concentration according to one of the following options. The span value of the TOC CEMS must be approximately 2 times the emission standard specified in table 1 of this subpart.
(i) For CEMS meeting the requirements of Performance Specification 15 of appendix B to this part, determine the target analyte(s) for calibration using either process knowledge of the control device inlet stream or the screening procedures of Method 18 of appendix A-6 to this part on the control device inlet stream. The individual analytes used to quantify TOC must represent 98 percent of the expected mass of TOC present in the stream. Report the results of TOC as equivalent to carbon (C1).
(ii) For CEMS meeting the requirements of Performance Specification 9 of appendix B of this part, determine the target analyte(s) for calibration using either process knowledge of the control device inlet stream or the screening procedures of Method 18 of appendix A-6 to this part on the control device inlet stream. The individual analytes used to quantify TOC must represent 98 percent of the expected mass of TOC present in the stream. Report the results of TOC as equivalent to carbon (C1).
(iii) For CEMS meeting the requirements of Performance Specification 8 of appendix B to this part used to monitor performance of a combustion device, calibrate the instrument on the predominant organic HAP and report the results as carbon (C1), and use Method 25A of appendix A-7 to this part as the reference method for the relative accuracy tests. You must also comply with procedure 1 of appendix F to this part.
(iv) For CEMS meeting the requirements of Performance Specification 8 of appendix B to this part used to monitor performance of a noncombustion device, determine the predominant organic compound using either process knowledge or the screening procedures of Method 18 on the control device inlet stream. Calibrate the monitor on the predominant organic compound and report the results as C 1 . Use Method 25A of appendix A-7 to this part as the reference method for the relative accuracy tests. You must also comply with procedure 1 of appendix F to this part.
(5) You must determine stack oxygen concentration at the same location where you monitor TOC concentration with a CEMS that meets the requirements of Performance Specification 3 of appendix B to this part. The span value of the oxygen CEMS must be approximately 25 percent oxygen. Use Method 3A of appendix A-2 to this part as the reference method for the relative accuracy tests.
(6) You must maintain written procedures for your CEMS. At a minimum, the procedures must include the information in paragraph (g)(6)(i) through (vi) of this section:
(i) Description of CEMS installation location.
(ii) Description of the monitoring equipment, including the manufacturer and model number for all monitoring equipment components and the span of the analyzer.
(iii) Routine quality control and assurance procedures.
(iv) Conditions that would trigger a CEMS performance evaluation, which must include, at a minimum, a newly installed CEMS; a process change that is expected to affect the performance of the CEMS; and the Administrator's request for a performance evaluation under section 114 of the Clean Air Act.
(v) Ongoing operation and maintenance procedures.
(vi) Ongoing recordkeeping and reporting procedures.
§ 60.665a   What records must I keep and what reports must I submit?
(a) You must notify the Administrator of the specific provisions of table 1 of this subpart or § 60.662a(c) with which you have elected to comply. Notification must be submitted with the notification of initial start-up required by § 60.7(a)(3). If you elect at a later date to use an alternative provision of table 1 to this subpart with which you will comply, then you must notify the Administrator 90 days before implementing a change and, upon implementing the change, you must conduct a performance test as specified by § 60.664a within 180 days.
(b) If you use a non-flare control device or recovery system to comply with the TOC emission limit specified in table 1 to this subpart, then you must keep an up-to-date, readily accessible record of the data measured during each performance test to show compliance with the TOC emission limit. You must also include all of the data you use to comply with § 60.663a(a)(2). The same data specified in this paragraph must also be submitted in the initial performance test required in § 60.8 and the reports of all subsequently required performance tests where either the emission reduction efficiency of a control device or recovery system or outlet concentration of TOC is determined. Alternatively, you must keep records of each CEMS performance evaluation.
(1) Within 60 days after the date of completing each performance test or CEMS performance evaluation required by this subpart, you must submit the results of the performance test or performance evaluation following the procedures specified in paragraph (k) of this section. Data collected using test methods and performance evaluations of CEMS measuring relative accuracy test audit (RATA) pollutants supported by the EPA's Electronic Reporting Tool (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 through the use of the EPA's ERT. Alternatively, owners and operators 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 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 must be included as an attachment in the ERT or alternate electronic file.
(2) If you use a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater to comply with the TOC emission limit specified in table 1 to this subpart, then you are not required to submit a report containing performance test data; however, you must submit a description of the location at which the vent stream is introduced into the boiler or process heater.
(c) If you use a non-flare control device or recovery system to comply with the TOC emission limit specified in Table 1 to this subpart, then you must keep up-to-date, readily accessible records of periods of operation during which the operating parameter limits established during the most recent performance test are exceeded or periods of operation where the TOC CEMS, averaged on a 3-hour block basis, indicate an exceedance of the emission standard in table 1 to this subpart. Additionally, you must record all periods when the TOC CEMS is inoperable. The Administrator may at any time require a report of these data. Periods of operation during which the operating parameter limits established during the most recent performance tests are exceeded are defined as follows:
(1) For absorbers:
(i) All 3-hour periods of operation during which the average absorbing liquid temperature was above the maximum absorbing liquid temperature established during the most recent performance test.
(ii) All 3-hour periods of operation during which the average absorbing liquid specific gravity was outside the exit specific gravity range ( i.e., more than 0.1 unit above, or more than 0.1 unit below, the average absorbing liquid specific gravity) established during the most recent performance test.
(2) For boilers or process heaters:
(i) Whenever there is a change in the location at which the vent stream is introduced into the flame zone as required under § 60.663a(b).
(ii) If the boiler or process heater has a design heat input capacity of less than 44 MW (150 million Btu/hr), then all 3-hour periods of operation during which the average firebox temperature was below the minimum firebox temperature during the most recent performance test.
(3) For catalytic incinerators:
(i) All 3-hour periods of operation during which the average temperature of the vent stream immediately before the catalyst bed is below the minimum temperature of the vent stream established during the most recent performance test.
(ii) All 3-hour periods of operation during which the average temperature difference across the catalyst bed is less than the average temperature difference of the device established during the most recent performance test.
(4) For carbon adsorbers:
(i) All carbon bed regeneration cycles during which the total mass stream flow or the total volumetric stream flow was below the minimum flow established during the most recent performance test.
(ii) All carbon bed regeneration cycles during which the temperature of the carbon bed after regeneration (and after completion of any cooling cycle(s)) was greater than the maximum carbon bed temperature (in degrees Celsius) established during the most recent performance test.
(5) For condensers, all 3-hour periods of operation during which the average exit (product side) condenser operating temperature was above the maximum exit (product side) operating temperature established during the most recent performance test.
(6) For scrubbers used to control halogenated vent streams:
(i) All 3-hour periods of operation during which the average pH of the scrubber effluent is below the minimum pH of the scrubber effluent established during the most recent performance test.
(ii) All 3-hour periods of operation during which the average influent liquid flow to the scrubber is below the minimum influent liquid flow to the scrubber established during the most recent performance test.
(iii) All 3-hour periods of operation during which the average liquid-to-gas ratio flow of the scrubber is below the minimum liquid-to-gas ratio of the scrubber established during the most recent performance test.
(7) For thermal incinerators, all 3-hour periods of operation during which the average firebox temperature was below the minimum firebox temperature established during the most recent performance test.
(8) For all other control devices, all periods (for the averaging time specified by the Administrator) when the operating parameter(s) established under § 60.663a(c) exceeded the operating limit established during the most recent performance test.
(d) You must keep up to date, readily accessible continuous records of the flow indication specified in table 2 to this subpart, as well as up-to-date, readily accessible records of all periods when the vent stream is diverted from the control device or recovery device or has no flow rate, including the records as specified in paragraphs (d)(1) and (2) of this section.
(1) For each flow event from a relief valve discharge subject to the requirements in § 60.662a(b)(1), you must include an estimate of the volume of gas, the concentration of TOC in the gas and the resulting emissions of TOC that released to the atmosphere using process knowledge and engineering estimates.
(2) For each flow event from a bypass line subject to the requirements in §§ 60.662a(b)(2) and 60.670a(e), you must maintain records sufficient to determine whether or not the detected flow included flow requiring control. For each flow event from a bypass line requiring control that is released either directly to the atmosphere or to a control device or recovery device not meeting the requirements in this subpart, you must include an estimate of the volume of gas, the concentration of TOC in the gas and the resulting emissions of TOC that bypassed the control device or recovery device using process knowledge and engineering estimates.
(e) If you use a boiler or process heater with a design heat input capacity of 44 MW (150 million Btu/hour) or greater to comply with the TOC emission limit specified in Table 1 to this subpart, then you must keep an up-to-date, readily accessible record of all periods of operation of the boiler or process heater. (Examples of such records could include records of steam use, fuel use, or monitoring data collected pursuant to other State or Federal regulatory requirements.)
(f) If you use a flare to comply with the TOC emission standard specified in Table 1 to this subpart, then you must keep up-to-date, readily accessible records of all visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the initial visible emissions demonstration required by § 63.670(h) of this chapter, as applicable; and all periods during the compliance determination when the pilot flame or flare flame is absent.
(g) For each maintenance vent opening subject to the requirements of § 60.662a(c), you must keep the applicable records specified in paragraphs (g)(1) through (5) of this section.
(1) You must maintain standard site procedures used to inventory equipment for safety purposes ( e.g., hot work or vessel entry procedures) to document the procedures used to meet the requirements in § 60.662a(c). The current copy of the procedures must be retained and available on-site at all times. Previous versions of the standard site procedures, as applicable, must be retained for five years.
(2) If complying with the requirements of § 60.662a(c)(1)(i), and the lower explosive limit at the time of the vessel opening exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and the lower explosive limit at the time of the vessel opening.
(3) If complying with the requirements of § 60.662a(c)(1)(ii), and either the vessel pressure at the time of the vessel opening exceeds 5 psig or the lower explosive limit at the time of the active purging was initiated exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, the pressure of the vessel or equipment at the time of discharge to the atmosphere and, if applicable, the lower explosive limit of the vapors in the equipment when active purging was initiated.
(4) If complying with the requirements of § 60.662a(c)(1)(iii), records of the estimating procedures used to determine the total quantity of VOC in the equipment and the type and size limits of equipment that contain less than 50 pounds of VOC at the time of maintenance vent opening. For each maintenance vent opening that contains greater than 50 pounds of VOC for which the inventory procedures specified in paragraph (g)(1) of this section are not followed or for which the equipment opened exceeds the type and size limits established in the records specified in this paragraph (g)(4), records that identify the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere.
(5) If complying with the requirements of § 60.662a(c)(1)(iv), identification of the maintenance vent, the process units or equipment associated with the maintenance vent, records documenting actions taken to comply with other applicable alternatives and why utilization of this alternative was required, the date of maintenance vent opening, the equipment pressure and lower explosive limit of the vapors in the equipment at the time of discharge, an indication of whether active purging was performed and the pressure of the equipment during the installation or removal of the blind if active purging was used, the duration the maintenance vent was open during the blind installation or removal process, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere for each applicable maintenance vent opening.
(h) If you seek to comply with the requirements of this subpart by complying with the design production capacity provision in § 60.660a(c)(4) you must keep up-to-date, readily accessible records of any change in equipment or process operation that increases the design production capacity of the process unit in which the affected facility is located.
(i) If you seek to comply with the requirements of this subpart by complying with the flow rate cutoff in § 60.660a(c)(5) or (6) you must keep up-to-date, readily accessible records to indicate that the vent stream flow rate is less than 0.008 scm/min (0.3 scf/min) or less than 0.001 lb/hr, and of any change in equipment or process operation that increases the operating vent stream flow rate, including a measurement of the new vent stream flow rate.
(j) You must submit to the Administrator semiannual reports of the information specified in paragraphs (j)(1) through (9) of this section. You are exempt from the reporting requirements specified in § 60.7(c). If there are no exceedances, periods, or events specified in paragraphs (j)(1) through (9) of this section that occurred during the reporting period, then you must include a statement in your report that no exceedances, periods, and events specified in paragraphs (j)(1) through (9) of this section occurred during the reporting period. The initial report must be submitted within 6 months after the initial start-up-date. On and after July 15, 2024 or once the report template for this subpart has been available on the Compliance and Emissions Data Reporting Interface (CEDRI) website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for 1 year, whichever date is later, you must submit all subsequent reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in paragraph (k) 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.
(1) Exceedances of monitored parameters recorded under paragraph (c) of this section. For each exceedance, the report must include a list of the affected facilities or equipment, the monitored parameter that was exceeded, the start date and time of the exceedance, the duration (in hours) of the exceedance, an estimate of the quantity in pounds of each regulated pollutant emitted over any emission limit, a description of the method used to estimate the emissions, the cause of the exceedance (including unknown cause, if applicable), as applicable, and the corrective action taken.
(2) All periods recorded under paragraph (d) of this section when the vent stream is diverted from the control device or recovery device, or has no flow rate, including the information specified in paragraphs (j)(2)(i) through (iii) of this section.
(i) For periods when the flow indicator is not operating, report the identification of the flow indicator and the start date, start time, and duration in hours.
(ii) For each flow event from a relief valve discharge subject to the requirements in § 60.662a(b)(1), the semiannual report must include the identification of the relief valve, the start date, start time, duration in hours, estimate of the volume of gas in standard cubic feet, the concentration of TOC in the gas in parts per million by volume and the resulting mass emissions of TOC in pounds that released to the atmosphere.
(iii) For each flow event from a bypass line subject to the requirements in § 60.662a(b)(2) and § 670a(e)(2), the semiannual report must include the identification of the bypass line, the start date, start time, duration in hours, estimate of the volume of gas in standard cubic feet, the concentration of TOC in the gas in parts per million by volume and the resulting mass emissions of TOC in pounds that bypass a control device or recovery device.
(3) All periods when a boiler or process heater was not operating (considering the records recorded under paragraph (e) of this section), including the start date, start time, and duration in hours of each period.
(4) For each flare subject to the requirements in § 60.669a, the semiannual report must include an identification of the flare and the items specified in § 60.669a(l)(2).
(5) For each closed vent system subject to the requirements in § 60.670a, the semiannual report must include an identification of the closed vent system and the items specified in § 60.670a(i).
(6) Any change in equipment or process operation, as recorded under paragraph (h) of this section, that increases the design production capacity above the low capacity exemption level in § 60.660a(c)(4) and the new capacity resulting from the change for the distillation process unit containing the affected facility. These must be reported as soon as possible after the change and no later than 180 days after the change. These reports may be submitted either in conjunction with semiannual reports or as a single separate report. Unless the facility qualifies for an exemption under § 60.660a(c), the facility must begin compliance with the requirements set forth in § 60.662a.
(7) Any change in equipment or process operation that increases the operating vent stream flow rate above the low flow exemption level in § 60.660a(c)(5) or (6), including a measurement of the new vent stream flow rate, as recorded under paragraph (i) of this section. These must be reported as soon as possible after the change and no later than 180 days after the change. These reports may be submitted either in conjunction with semiannual reports or as a single separate report. A performance test must be completed with the same time period to verify the recalculated flow value. The performance test is subject to the requirements of § 60.8 and must be submitted according to paragraph (b)(1) of this section. Unless the facility qualifies for an exemption under § 60.660a(c), the facility must begin compliance with the requirements set forth in § 60.662a.
(8) Exceedances of the emission standard in Table 1 of this subpart as indicated by a 3-hour average of the TOC CEMS and recorded under paragraph (c) of this section. For each exceedance, the report must include a list of the affected facilities or equipment, the start date and time of the exceedance, the duration (in hours) of the exceedance, an estimate of the quantity in pounds of each regulated pollutant emitted over the emission limit, a description of the method used to estimate the emissions, the cause of the exceedance (including unknown cause, if applicable), as applicable, and the corrective action taken.
(9) Periods when the TOC CEMS was inoperative. For each period, the report must include a list of the affected facilities or equipment, the start date and time of the period, the duration (in hours) of the period, the cause of the inoperability (including unknown cause, if applicable), as applicable, and the corrective action taken.
(k) If you are required to submit notifications or reports following the procedure specified in this paragraph (k), 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 (k)(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 (k).
(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.
(l) 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 the electronic submittal requirement. To assert a claim of EPA system outage, you must meet the requirements outlined in paragraphs (l)(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.
(m) 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 the electronic submittal requirement. To assert a claim of force majeure, you must meet the requirements outlined in paragraphs (m)(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.
(n) The requirements of paragraph (j) 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 sources within the State will be relieved of the obligation to comply with paragraph (j) 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.
(o) If you seek to demonstrate compliance with § 60.660(c)(4), then you must submit to the Administrator an initial report detailing the design production capacity of the process unit.
(p) If you seek to demonstrate compliance with § 60.660(c)(5) or (6), then you must submit to the Administrator, following the procedures in paragraph (b)(1) of this section, an initial report including a flow rate measurement using the test methods specified in § 60.664a.
(q) The Administrator will specify appropriate reporting and recordkeeping requirements where the owner or operator of an affected facility complies with the standards specified under § 60.662a other than as provided under § 60.663a.
(r) Any records required to be maintained by this subpart that are submitted electronically via the EPA's 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.
§ 60.666a   What do the terms associated with reconstruction mean for this subpart?
For purposes of this subpart “fixed capital cost of the new components,” as used in § 60.15, includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following April 25, 2023. For purposes of this paragraph, “commenced” means that you have undertaken a continuous program of component replacement or that you have entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.
§ 60.667a   What are the chemicals that I must produce to be affected by subpart NNNa?
* CAS numbers refer to the Chemical Abstracts Registry numbers assigned to specific chemicals, isomers, or mixtures of chemicals. Some isomers or mixtures that are covered by the standards do not have CAS numbers assigned to them. The standards apply to all of the chemicals listed, whether CAS numbers have been assigned or not.
§ 60.668a   [Reserved]
§ 60.669a   What are my requirements if I use a flare to comply with this subpart?
(a) If you use a flare to comply with the TOC emission standard specified in Table 1 to this subpart, then you must meet the applicable requirements for flares as specified in §§ 63.670 and 63.671 of this chapter, including the provisions in tables 12 and 13 to part 63, subpart CC, of this chapter, except as specified in paragraphs (b) through (o) of this section. This requirement also applies to any flare using fuel gas from a fuel gas system, of which 50 percent or more of the fuel gas is derived from an affected facility, as determined on an annual average basis. For purposes of compliance with this paragraph (a), the following terms are defined in § 63.641 of this chapter: Assist air, assist steam, center steam, combustion zone, combustion zone gas, flare, flare purge gas, flare supplemental gas, flare sweep gas, flare vent gas, lower steam, net heating value, perimeter assist air, pilot gas, premix assist air, total steam, and upper steam.
(b) When determining compliance with the pilot flame requirements specified in § 63.670(b) and (g) of this chapter, substitute “pilot flame or flare flame” for each occurrence of “pilot flame.”
(c) When determining compliance with the flare tip velocity and combustion zone operating limits specified in § 63.670(d) and (e) of this chapter, the requirement effectively applies starting with the 15-minute block that includes a full 15 minutes of the flaring event. You are required to demonstrate compliance with the velocity and NHVcz requirements starting with the block that contains the fifteenth minute of a flaring event. You are not required to demonstrate compliance for the previous 15-minute block in which the event started and contained only a fraction of flow.
(d) Instead of complying with § 63.670(o)(2)(i) of this chapter, you must develop and implement the flare management plan no later than startup for a new flare that commenced construction on or after April 25, 2023.
(e) Instead of complying with § 63.670(o)(2)(iii) of this chapter, if required to develop a flare management plan and submit it to the Administrator, then you must also submit all versions of the plan in portable document format (PDF) following the procedures specified in § 60.665a(k).
(f) Section 63.670(o)(3)(ii) of this chapter and all references to it do not apply. Instead, you must comply with the maximum flare tip velocity operating limit at all times.
(g) Substitute “affected facility” for each occurrence of “petroleum refinery.”
(h) Each occurrence of “refinery” does not apply.
(i) If a pressure-assisted multi-point flare is used as a control device, then you must meet the following conditions:
(1) You are not required to comply with the flare tip velocity requirements in § 63.670(d) and (k) of this chapter;
(2) The NHVcz for pressure-assisted mulit-point flares is 800 Btu/scf;
(3) You must determine the 15-minute block average NHVvg using only the direct calculation method specified in in § 63.670(l)(5)(ii) of this chapter;
(4) Instead of complying with § 63.670(b) and (g) of this chapter, if a pressure-assisted multi-point flare uses cross-lighting on a stage of burners rather than having an individual pilot flame on each burner, then you must operate each stage of the pressure-assisted multi-point flare with a flame present at all times when regulated material is routed to that stage of burners. Each stage of burners that cross-lights in the pressure-assisted multi-point flare must have at least two pilots with at least one continuously lit and capable of igniting all regulated material that is routed to that stage of burners. Each 15-minute block during which there is at least one minute where no pilot flame is present on a stage of burners when regulated material is routed to the flare is a deviation of the standard. Deviations in different 15-minute blocks from the same event are considered separate deviations. The pilot flame(s) on each stage of burners that use cross-lighting must be continuously monitored by a thermocouple or any other equivalent device used to detect the presence of a flame;
(5) Unless you choose to conduct a cross-light performance demonstration as specified in this paragraph (i)(5), you must ensure that if a stage of burners on the flare uses cross-lighting, that the distance between any two burners in series on that stage is no more than 6 feet when measured from the center of one burner to the next burner. A distance greater than 6 feet between any two burners in series may be used provided you conduct a performance demonstration that confirms the pressure-assisted multi-point flare will cross-light a minimum of three burners and the spacing between the burners and location of the pilot flame must be representative of the projected installation. The compliance demonstration must be approved by the permitting authority and a copy of this approval must be maintained onsite. The compliance demonstration report must include: a protocol describing the test methodology used, associated test method QA/QC parameters, the waste gas composition and NHVcz of the gas tested, the velocity of the waste gas tested, the pressure-assisted multi-point flare burner tip pressure, the time, length, and duration of the test, records of whether a successful cross-light was observed over all of the burners and the length of time it took for the burners to cross-light, records of maintaining a stable flame after a successful cross-light and the duration for which this was observed, records of any smoking events during the cross-light, waste gas temperature, meteorological conditions ( e.g., ambient temperature, barometric pressure, wind speed and direction, and relative humidity), and whether there were any observed flare flameouts; and
(6) You must install and operate pressure monitor(s) on the main flare header, as well as a valve position indicator monitoring system for each staging valve to ensure that the flare operates within the proper range of conditions as specified by the manufacturer. The pressure monitor must meet the requirements in table 13 to part 63, subpart CC, of this chapter.
(7) If a pressure-assisted multi-point flare is operating under the requirements of an approved alternative means of emission limitations, you must either continue to comply with the terms of the alternative means of emission limitations or comply with the provisions in paragraphs (i)(1) through (6) of this section.
(j) 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 (j)(1) through (7) of this section.
(1) 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.
(2) Calibration gas cylinders must be certified to an accuracy of 2 percent and traceable to National Institute of Standards and Technology (NIST) standards.
(3) 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 NHVvg.
(4) You may use the response factor for n-pentane to quantify any unknown components detected with a higher molecular weight than n-pentane.
(5) You must perform an initial calibration to identify mass fragment overlap and response factors for the target compounds.
(6) You must meet applicable requirements in Performance Specification 9 of appendix B of 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 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, of this chapter.
(7) 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 equation 1 to this paragraph (j)(7).
(k) 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 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 must be calculated using equation 2 to this paragraph (k).
(l) Instead of complying with § 63.670(q) of this chapter, you must comply with the reporting requirements specified in paragraphs (l)(1) and (2) of this section.
(1) The notification requirements specified in § 60.665a(a).
(2) The semiannual report specified in § 60.665a(j)(4) must include the items specified in paragraphs (l)(2)(i) through (vi) of this section.
(i) Records as specified in paragraph (m)(1) of this section for each 15-minute block during which there was at least one minute when regulated material is routed to a flare and no pilot flame or flare flame is present. Include the start and stop time and date of each 15-minute block.
(ii) Visible emission records as specified in paragraph (m)(2)(iv) of this section for each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes.
(iii) The periods specified in paragraph (m)(6) of this section. Indicate the date and start and end times for each period, and the net heating value operating parameter(s) determined following the methods in § 63.670(k) through (n) of this chapter as applicable.
(iv) For flaring events meeting the criteria in § 63.670(o)(3) of this chapter and paragraph (f) of this section:
(A) The start and stop time and date of the flaring event.
(B) The length of time in minutes for which emissions were visible from the flare during the event.
(C) For steam-assisted, air-assisted, and non-assisted flares, the start date, start time, and duration in minutes for periods of time that the flare tip velocity exceeds the maximum flare tip velocity determined using the methods in § 63.670(d)(2) of this chapter and the maximum 15-minute block average flare tip velocity in ft/sec recorded during the event.
(D) Results of the root cause and corrective actions analysis completed during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period.
(v) For pressure-assisted multi-point flares, the periods of time when the pressure monitor(s) on the main flare header show the burners operating outside the range of the manufacturer's specifications. Indicate the date and start and end times for each period.
(vi) For pressure-assisted multi-point flares, the periods of time when the staging valve position indicator monitoring system indicates a stage should not be in operation and is or when a stage should be in operation and is not. Indicate the date and start and end times for each period.
(m) Instead of complying with § 63.670(p) of this chapter, you must keep the flare monitoring records specified in paragraphs (m)(1) through (14) of this section.
(1) Retain records of the output of the monitoring device used to detect the presence of a pilot flame or flare flame as required in § 63.670(b) of this chapter and the presence of a pilot flame as required in paragraph (i)(4) of this section 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 or flare flame is present when regulated material is routed to a flare for a minimum of 5 years. For a pressure-assisted multi-point flare that uses cross-lighting, retain records of each 15-minute block during which there was at least one minute that no pilot flame is present on each stage when regulated material is routed to a flare for a minimum of 5 years. You may reduce the collected minute-by-minute data to a 15-minute block basis with an indication of whether there was at least one minute where no pilot flame or flare flame was present.
(2) Retain records of daily visible emissions observations as specified in paragraphs (m)(2)(i) through (iv) of this section, as applicable, for a minimum of 3 years.
(i) To determine when visible emissions observations are required, the record must identify all periods when regulated material is vented to the flare.
(ii) If visible emissions observations are performed using Method 22 of appendix A-7 of this part, then the record must identify whether the visible emissions observation was performed, the results of each observation, total duration of observed visible emissions, and whether it was a 5-minute or 2-hour observation. Record the date and start time of each visible emissions observation.
(iii) If a video surveillance camera is used pursuant to § 63.670(h)(2) of this chapter, then the record must include all video surveillance images recorded, with time and date stamps.
(iv) For each 2-hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours, then the record must include the date and start and end time of the 2-hour period and an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible.
(3) The 15-minute block average cumulative flows for flare 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 time interval 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, then 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, then retain records of the 15-minute block average temperature, pressure, and molecular weight of the flare 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.
(4) The flare vent gas compositions specified to be monitored under § 63.670(j) of this chapter. Retain records of individual component concentrations from each compositional analysis for a minimum of 2 years. If an NHVvg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years.
(5) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n) this chapter, as applicable.
(6) All periods during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) of this chapter and paragraph (i) of this section when regulated material is being routed to the flare.
(7) All periods during which you do not perform flare monitoring according to the procedures in § 63.670(g) through (j) of this chapter.
(8) For pressure-assisted multi-point flares, if a stage of burners on the flare uses cross-lighting, then a record of any changes made to the distance between burners.
(9) For pressure-assisted multi-point flares, all periods when the pressure monitor(s) on the main flare header show burners are operating outside the range of the manufacturer's specifications. Indicate the date and time for each period, the pressure measurement, the stage(s) and number of burners affected, and the range of manufacturer's specifications.
(10) For pressure-assisted multi-point flares, all periods when the staging valve position indicator monitoring system indicates a stage of the pressure-assisted multi-point flare should not be in operation and when a stage of the pressure-assisted multi-point flare should be in operation and is not. Indicate the date and time for each period, whether the stage was supposed to be open, but was closed or vice versa, and the stage(s) and number of burners affected.
(11) Records of periods when there is flow of vent gas to the flare, but when there is no flow of regulated material to the flare, including the start and stop time and dates of periods of no regulated material flow.
(12) Records when the flow of vent gas exceeds the smokeless capacity of the flare, including start and stop time and dates of the flaring event.
(13) Records of the root cause analysis and corrective action analysis conducted as required in § 63.670(o)(3) of this chapter and paragraph (f) of this section, including an identification of the affected flare, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 63.670(o)(5)(i) of this chapter.
(14) For any corrective action analysis for which implementation of corrective actions are required in § 63.670(o)(5) of this chapter, a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
(n) You may elect to comply with the alternative means of emissions limitation requirements specified in § 63.670(r) of this chapter in lieu of the requirements in § 63.670(d) through (f) of this chapter, as applicable. However, instead of complying with § 63.670(r)(3)(iii) of this chapter, you must also submit the alternative means of emissions limitation request to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (C404-02), Attention: SOCMI NSPS Sector Lead, 4930 Old Page Rd., Durham, NC 27703.
(o) The referenced provisions specified in paragraphs (o)(1) through (4) of this section do not apply when demonstrating compliance with this section.
(1) Section 63.670(o)(4)(iv) of this chapter.
(2) The last sentence of § 63.670(o)(6) of this chapter.
(3) The phrase “that were not caused by a force majeure event” in § 63.670(o)(7)(ii) of this chapter.
(4) The phrase “that were not caused by a force majeure event” in § 63.670(o)(7)(iv) of this chapter.
§ 60.670a   What are my requirements for closed vent systems?
(a) Except as provided in paragraphs (f) and (g) of this section, you must inspect each closed vent system according to the procedures and schedule specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct an initial inspection according to the procedures in paragraph (b) of this section unless the closed vent system is operated and maintained under negative pressure;
(2) Conduct annual inspections according to the procedures in paragraph (b) of this section unless the closed vent system is operated and maintained under negative pressure; and
(3) Conduct annual inspections for visible, audible, or olfactory indications of leaks.
(b) You must inspect each closed vent system according to the procedures specified in paragraphs (b)(1) through (6) of this section.
(1) Inspections must be conducted in accordance with Method 21 of appendix A of this part.
(2)(i) Except as provided in paragraph (b)(2)(ii) of this section, the detection instrument must meet the performance criteria of Method 21 of appendix A of this part, except the instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average composition of the process fluid not each individual volatile organic compound in the stream. For process streams that contain nitrogen, air, or other inerts which are not organic hazardous air pollutants or volatile organic compounds, the average stream response factor must be calculated on an inert-free basis.
(ii) If no instrument is available at the plant site that will meet the performance criteria specified in paragraph (b)(2)(i) of this section, the instrument readings may be adjusted by multiplying by the average response factor of the process fluid, calculated on an inert-free basis as described in paragraph (b)(2)(i).
(3) The detection instrument must be calibrated before use on each day of its use by the procedures specified in Method 21 of appendix A of this part.
(4) Calibration gases must be as follows:
(i) Zero air (less than 10 parts per million hydrocarbon in air); and
(ii) Mixtures of methane in air at a concentration less than 2,000 parts per million. A calibration gas other than methane in air may be used if the instrument does not respond to methane or if the instrument does not meet the performance criteria specified in paragraph (b)(2)(i) of this section. In such cases, the calibration gas may be a mixture of one or more of the compounds to be measured in air.
(5) You may elect to adjust or not adjust instrument readings for background. If you elect to not adjust readings for background, all such instrument readings must be compared directly to the applicable leak definition to determine whether there is a leak.
(6) If you elect to adjust instrument readings for background, you must determine the background concentration using Method 21 of appendix A of this part. After monitoring each potential leak interface, subtract the background reading from the maximum concentration indicated by the instrument. The arithmetic difference between the maximum concentration indicated by the instrument and the background level must be compared with 500 parts per million for determining compliance.
(c) Leaks, as indicated by an instrument reading greater than 500 parts per million above background or by visual, audio, or olfactory inspections, must be repaired as soon as practicable, except as provided in paragraph (d) of this section.
(1) A first attempt at repair must be made no later than 5 calendar days after the leak is detected.
(2) Repair must be completed no later than 15 calendar days after the leak is detected.
(d) Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is technically infeasible without a shutdown, as defined in § 60.2, or if you determine that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of such equipment must be complete by the end of the next shutdown.
(e) For each closed vent system that contains bypass lines that could divert a vent stream away from the control device and to the atmosphere, you must comply with the provisions of either paragraph (e)(1) or (2), except as specified in paragraph (e)(3) of this section.
(1) Install, calibrate, maintain, and operate a flow indicator that determines whether vent stream flow is present at least once every 15 minutes. You must keep hourly records of whether the flow indicator was operating and whether a diversion was detected at any time during the hour, as well as records of the times and durations of all periods when the vent stream is diverted to the atmosphere or the flow indicator is not operating. The flow indicator must be installed at the entrance to any bypass line; or
(2) Secure the bypass line valve in the closed position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism must be performed at least once every month to ensure the valve is maintained in the closed position and the vent stream is not diverted through the bypass line.
(3) Open-ended valves or lines that use a cap, blind flange, plug, or second valve and follow the requirements specified in § 60.482-6(a)(2), (b), and (c) or follow requirements codified in another regulation that are the same as § 60.482-6(a)(2), (b), and (c) are not subject to this paragraph (e) of this section.
(f) Any parts of the closed vent system that are designated, as described in paragraph (h)(1) of this section, as unsafe to inspect are exempt from the inspection requirements of paragraphs (a)(1) and (2) of this section if:
(1) You determine 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 (a)(1) and (2) of this section; and
(2) You have a written plan that requires inspection of the equipment as frequently as practicable during safe-to-inspect times.
(g) Any parts of the closed vent system are designated, as described in paragraph (h)(2) of this section, as difficult to inspect are exempt from the inspection requirements of paragraphs (a)(1) and (2) of this section if:
(1) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface; and
(2) You have a written plan that requires inspection of the equipment at least once every 5 years.
(h) You must record the information specified in paragraphs (h)(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 closed vent system that contains bypass lines that could divert a vent stream away from the control device and to the atmosphere, you must keep a record of the information specified in either paragraph (h)(3)(i) or (ii) of this section in addition to the information specified in paragraph (h)(3)(iii) of this section.
(i) Hourly records of whether the flow indicator specified under paragraph (e)(1) of this section was operating and whether a diversion was detected at any time during the hour, as well as records of the times of all periods when the vent stream is diverted from the control device or the flow indicator is not operating.
(ii) Where a seal mechanism is used to comply with paragraph (e)(2) of this section, hourly records of flow are not required. In such cases, you must record whether the monthly visual inspection of the seals or closure mechanisms has been done, and you must record the occurrence of all periods when the seal mechanism is broken, the bypass line valve position has changed, or the key for a lock-and-key type configuration has been checked out, and records of any car-seal that has broken.
(iii) For each flow event from a bypass line subject to the requirements in paragraph (e) of this section, you must maintain records sufficient to determine whether or not the detected flow included flow requiring control. For each flow event from a bypass line requiring control that is released either directly to the atmosphere or to a control device not meeting the requirements in this subpart, you must include an estimate of the volume of gas, the concentration of VOC in the gas and the resulting emissions of VOC that bypassed the control device using process knowledge and engineering estimates.
(4) For each inspection during which a leak is detected, a record of the information specified in paragraphs (h)(4)(i) through (viii) of this section.
(i) The instrument identification numbers; operator name or initials; and identification of the equipment.
(ii) The date the leak was detected and the date of the first attempt to repair the leak.
(iii) Maximum instrument reading measured by the method specified in paragraph (c) of this section after the leak is successfully repaired or determined to be nonrepairable.
(iv) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak.
(v) The name, initials, or other form of identification of the owner or operator (or designee) whose decision it was that repair could not be effected without a shutdown.
(vi) The expected date of successful repair of the leak if a leak is not repaired within 15 calendar days.
(vii) Dates of shutdowns that occur while the equipment is unrepaired.
(viii) The date of successful repair of the leak.
(5) For each inspection conducted in accordance with paragraph (b) 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.
(6) For each inspection conducted in accordance with paragraph (a)(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.
(i) The semiannual report specified in § 60.665a(j)(5) must include the items specified in paragraphs (i)(1) through (3) of this section.
(1) Reports of the times of all periods recorded under paragraph (h)(3)(i) of this section when the vent stream is diverted from the control device through a bypass line. Include the start date, start time, and duration in hours of each period.
(2) Reports of all periods recorded under paragraph (h)(3)(ii) of this section in which the seal mechanism is broken, the bypass line valve position has changed, or the key to unlock the bypass line valve was checked out. Include the start date, start time, and duration in hours of each period.
(3) For bypass lines subject to the requirements in paragraph (e) of this section, the semiannual reports must include the start date, start time, duration in hours, estimate of the volume of gas in standard cubic feet, the concentration of VOC in the gas in parts per million by volume and the resulting mass emissions of VOC in pounds that bypass a control device. For periods when the flow indicator is not operating, report the start date, start time, and duration in hours.
§ 60.670   Applicability and designation of affected facility.
(a)(1) Except as provided in paragraphs (a)(2), (b), (c), and (d) of this section, the provisions of this subpart are applicable to the following affected facilities in fixed or portable nonmetallic mineral processing plants: each crusher, grinding mill, screening operation, bucket elevator, belt conveyor, bagging operation, storage bin, enclosed truck or railcar loading station. Also, crushers and grinding mills at hot mix asphalt facilities that reduce the size of nonmetallic minerals embedded in recycled asphalt pavement and subsequent affected facilities up to, but not including, the first storage silo or bin are subject to the provisions of this subpart.
(2) The provisions of this subpart do not apply to the following operations: All facilities located in underground mines; plants without crushers or grinding mills above ground; and wet material processing operations (as defined in § 60.671).
(b) An affected facility that is subject to the provisions of subparts F or I of this part or that follows in the plant process any facility subject to the provisions of subparts F or I of this part is not subject to the provisions of this subpart.
(c) Facilities at the following plants are not subject to the provisions of this subpart:
(1) Fixed sand and gravel plants and crushed stone plants with capacities, as defined in § 60.671, of 23 megagrams per hour (25 tons per hour) or less;
(2) Portable sand and gravel plants and crushed stone plants with capacities, as defined in § 60.671, of 136 megagrams per hour (150 tons per hour) or less; and
(3) Common clay plants and pumice plants with capacities, as defined in § 60.671, of 9 megagrams per hour (10 tons per hour) or less.
(d)(1) When an existing facility is replaced by a piece of equipment of equal or smaller size, as defined in § 60.671, having the same function as the existing facility, and there is no increase in the amount of emissions, the new facility is exempt from the provisions of §§ 60.672, 60.674, and 60.675 except as provided for in paragraph (d)(3) of this section.
(2) An owner or operator complying with paragraph (d)(1) of this section shall submit the information required in § 60.676(a).
(3) An owner or operator replacing all existing facilities in a production line with new facilities does not qualify for the exemption described in paragraph (d)(1) of this section and must comply with the provisions of §§ 60.672, 60.674 and 60.675.
(e) An affected facility under paragraph (a) of this section that commences construction, modification, or reconstruction after August 31, 1983, is subject to the requirements of this part.
(f) Table 1 of this subpart specifies the provisions of subpart A of this part 60 that do not apply to owners and operators of affected facilities subject to this subpart or that apply with certain exceptions.
§ 60.671   Definitions.
All terms used in this subpart, but not specifically defined in this section, shall have the meaning given them in the Act and in subpart A of this part.
Bagging operation means the mechanical process by which bags are filled with nonmetallic minerals.
Belt conveyor means a conveying device that transports material from one location to another by means of an endless belt that is carried on a series of idlers and routed around a pulley at each end.
Bucket elevator means a conveying device of nonmetallic minerals consisting of a head and foot assembly which supports and drives an endless single or double strand chain or belt to which buckets are attached.
Building means any frame structure with a roof.
Capacity means the cumulative rated capacity of all initial crushers that are part of the plant.
Capture system means the equipment (including enclosures, hoods, ducts, fans, dampers, etc.) used to capture and transport particulate matter generated by one or more affected facilities to a control device.
Control device means the air pollution control equipment used to reduce particulate matter emissions released to the atmosphere from one or more affected facilities at a nonmetallic mineral processing plant.
Conveying system means a device for transporting materials from one piece of equipment or location to another location within a plant. Conveying systems include but are not limited to the following: Feeders, belt conveyors, bucket elevators and pneumatic systems.
Crush or Crushing means to reduce the size of nonmetallic mineral material by means of physical impaction of the crusher or grinding mill upon the material.
Crusher means a machine used to crush any nonmetallic minerals, and includes, but is not limited to, the following types: Jaw, gyratory, cone, roll, rod mill, hammermill, and impactor.
Enclosed truck or railcar loading station means that portion of a nonmetallic mineral processing plant where nonmetallic minerals are loaded by an enclosed conveying system into enclosed trucks or railcars.
Fixed plant means any nonmetallic mineral processing plant at which the processing equipment specified in § 60.670(a) is attached by a cable, chain, turnbuckle, bolt or other means (except electrical connections) to any anchor, slab, or structure including bedrock.
Fugitive emission means particulate matter that is not collected by a capture system and is released to the atmosphere at the point of generation.
Grinding mill means a machine used for the wet or dry fine crushing of any nonmetallic mineral. Grinding mills include, but are not limited to, the following types: Hammer, roller, rod, pebble and ball, and fluid energy. The grinding mill includes the air conveying system, air separator, or air classifier, where such systems are used.
Initial crusher means any crusher into which nonmetallic minerals can be fed without prior crushing in the plant.
Nonmetallic mineral means any of the following minerals or any mixture of which the majority is any of the following minerals:
(1) Crushed and Broken Stone, including Limestone, Dolomite, Granite, Traprock, Sandstone, Quartz, Quartzite, Marl, Marble, Slate, Shale, Oil Shale, and Shell.
(2) Sand and Gravel.
(3) Clay including Kaolin, Fireclay, Bentonite, Fuller's Earth, Ball Clay, and Common Clay.
(4) Rock Salt.
(5) Gypsum (natural or synthetic).
(6) Sodium Compounds, including Sodium Carbonate, Sodium Chloride, and Sodium Sulfate.
(7) Pumice.
(8) Gilsonite.
(9) Talc and Pyrophyllite.
(10) Boron, including Borax, Kernite, and Colemanite.
(11) Barite.
(12) Fluorospar.
(13) Feldspar.
(14) Diatomite.
(15) Perlite.
(16) Vermiculite.
(17) Mica.
(18) Kyanite, including Andalusite, Sillimanite, Topaz, and Dumortierite.
Nonmetallic mineral processing plant means any combination of equipment that is used to crush or grind any nonmetallic mineral wherever located, including lime plants, power plants, steel mills, asphalt concrete plants, portland cement plants, or any other facility processing nonmetallic minerals except as provided in § 60.670 (b) and (c).
Portable plant means any nonmetallic mineral processing plant that is mounted on any chassis or skids and may be moved by the application of a lifting or pulling force. In addition, there shall be no cable, chain, turnbuckle, bolt or other means (except electrical connections) by which any piece of equipment is attached or clamped to any anchor, slab, or structure, including bedrock that must be removed prior to the application of a lifting or pulling force for the purpose of transporting the unit.
Production line means all affected facilities (crushers, grinding mills, screening operations, bucket elevators, belt conveyors, bagging operations, storage bins, and enclosed truck and railcar loading stations) which are directly connected or are connected together by a conveying system.
Saturated material means, for purposes of this subpart, mineral material with sufficient surface moisture such that particulate matter emissions are not generated from processing of the material through screening operations, bucket elevators and belt conveyors. Material that is wetted solely by wet suppression systems is not considered to be “saturated” for purposes of this definition.
Screening operation means a device for separating material according to size by passing undersize material through one or more mesh surfaces (screens) in series, and retaining oversize material on the mesh surfaces (screens). Grizzly feeders associated with truck dumping and static (non-moving) grizzlies used anywhere in the nonmetallic mineral processing plant are not considered to be screening operations.
Seasonal shut down means shut down of an affected facility for a period of at least 45 consecutive days due to weather or seasonal market conditions.
Size means the rated capacity in tons per hour of a crusher, grinding mill, bucket elevator, bagging operation, or enclosed truck or railcar loading station; the total surface area of the top screen of a screening operation; the width of a conveyor belt; and the rated capacity in tons of a storage bin.
Stack emission means the particulate matter that is released to the atmosphere from a capture system.
Storage bin means a facility for storage (including surge bins) of nonmetallic minerals prior to further processing or loading.
Transfer point means a point in a conveying operation where the nonmetallic mineral is transferred to or from a belt conveyor except where the nonmetallic mineral is being transferred to a stockpile.
Truck dumping means the unloading of nonmetallic minerals from movable vehicles designed to transport nonmetallic minerals from one location to another. Movable vehicles include but are not limited to: Trucks, front end loaders, skip hoists, and railcars.
Vent means an opening through which there is mechanically induced air flow for the purpose of exhausting from a building air carrying particulate matter emissions from one or more affected facilities.
Wet material processing operation(s) means any of the following:
(1) Wet screening operations (as defined in this section) and subsequent screening operations, bucket elevators and belt conveyors in the production line that process saturated materials (as defined in this section) up to the first crusher, grinding mill or storage bin in the production line; or
(2) Screening operations, bucket elevators and belt conveyors in the production line downstream of wet mining operations (as defined in this section) that process saturated materials (as defined in this section) up to the first crusher, grinding mill or storage bin in the production line.
Wet mining operation means a mining or dredging operation designed and operated to extract any nonmetallic mineral regulated under this subpart from deposits existing at or below the water table, where the nonmetallic mineral is saturated with water.
Wet screening operation means a screening operation at a nonmetallic mineral processing plant which removes unwanted material or which separates marketable fines from the product by a washing process which is designed and operated at all times such that the product is saturated with water.
§ 60.672   Standard for particulate matter (PM).
(a) Affected facilities must meet the stack emission limits and compliance requirements in Table 2 of this subpart within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup as required under § 60.8. The requirements in Table 2 of this subpart apply for affected facilities with capture systems used to capture and transport particulate matter to a control device.
(b) Affected facilities must meet the fugitive emission limits and compliance requirements in Table 3 of this subpart within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup as required under § 60.11. The requirements in Table 3 of this subpart apply for fugitive emissions from affected facilities without capture systems and for fugitive emissions escaping capture systems.
(c) [Reserved]
(d) Truck dumping of nonmetallic minerals into any screening operation, feed hopper, or crusher is exempt from the requirements of this section.
(e) If any transfer point on a conveyor belt or any other affected facility is enclosed in a building, then each enclosed affected facility must comply with the emission limits in paragraphs (a) and (b) of this section, or the building enclosing the affected facility or facilities must comply with the following emission limits:
(1) Fugitive emissions from the building openings (except for vents as defined in § 60.671) must not exceed 7 percent opacity; and
(2) Vents (as defined in § 60.671) in the building must meet the applicable stack emission limits and compliance requirements in Table 2 of this subpart.
(f) Any baghouse that controls emissions from only an individual, enclosed storage bin is exempt from the applicable stack PM concentration limit (and associated performance testing) in Table 2 of this subpart but must meet the applicable stack opacity limit and compliance requirements in Table 2 of this subpart. This exemption from the stack PM concentration limit does not apply for multiple storage bins with combined stack emissions.
§ 60.673   Reconstruction.
(a) The cost of replacement of ore-contact surfaces on processing equipment 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 new facility” under § 60.15. Ore-contact surfaces are crushing surfaces; screen meshes, bars, and plates; conveyor belts; and elevator buckets.
(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 paragraph (a) of this section) which are or will be replaced pursuant to all continuous programs of component replacement commenced within any 2-year period following August 31, 1983.