Title 40—Protection of Environment--Volume 1
PART 98—MANDATORY GREENHOUSE GAS REPORTING
§ 98.194   Monitoring and QA/QC requirements.
(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold.
(b) You must determine the annual quantity of each calcined byproduct or waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct or waste generation rate.
(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct or waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct or waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct or waste that is not sold on an annual basis.
(1) ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference— see § 98.7).
(2) The National Lime Association's CO 2 Emissions Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision-National Lime Association (incorporated by reference—see § 98.7).
(d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product that is produced and that is collected during the same month as the production data in monthly calculations.
(e) You must follow the quality assurance/quality control procedures (including documentation) in National Lime Association's CO 2 Emissions Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision—National Lime Association (incorporated by reference— see § 98.7).
§ 98.195   Procedures for estimating missing data.
For the procedure in § 98.193(b)(1), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., oxide content, quantity of lime products, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct or waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes.
(b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in § 98.194 (c)(1) or (c)(2).
§ 98.196   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.
(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by § 98.36 and the information listed in paragraphs (a)(1) through (14) of this section.
(1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold.
(2) Method used to determine the quantity of calcined lime byproduct or waste sold.
(3) Beginning and end of year inventories for each lime product that is produced, by type.
(4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type.
(5) Annual amount of calcined lime byproduct or waste sold, by type (tons).
(6) Annual amount of lime product sold, by type (tons).
(7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons).
(8) Annual amount of lime product not sold, by type (tons).
(9) Annual arithmetic average of calcium oxide content for each type of lime product produced (metric tons CaO/metric ton lime).
(10) Annual arithmetic average of magnesium oxide content for each type of lime product produced (metric tons MgO/metric ton lime).
(11) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste sold (metric tons CaO/metric ton lime).
(12) Annual arithmetic average of magnesium oxide content for each type of calcined lime byproduct/waste sold (metric tons MgO/metric ton lime).
(13) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste not sold (metric tons CaO/metric ton lime).
(14) Annual arithmetic average of magnesium oxide content for each type of calcined lime byproduct/waste not sold (metric tons MgO/metric ton lime)
(b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in paragraphs (b)(1) through (23) of this section.
(1) Annual CO 2 process emissions from all lime kilns combined (metric tons).
(2)-(3) [Reserved]
(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type.
(5)-(6) [Reserved]
(7) Method used to determine the quantity of lime produced and/or lime sold.
(8) [Reserved]
(9) Method used to determine the quantity of calcined lime byproduct or waste sold.
(10)-(12) [Reserved]
(13) Beginning and end of year inventories for each lime product that is produced.
(14) Beginning and end of year inventories for calcined lime byproducts or wastes sold.
(15) Annual lime production capacity (tons) per facility.
(16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months).
(17) Indicate whether CO 2 was captured and used on-site ( e.g., for use in a purification process, the manufacture of another product). If CO 2 was captured and used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section.
(i) The annual amount of CO 2 captured for use in all on-site processes.
(ii) The method used to determine the amount of CO 2 captured.
(18) Annual quantity (tons) of lime product sold, by type.
(19) Annual average emission factors for each lime product type produced.
(20) Annual average emission factors for each calcined byproduct/waste by lime type that is sold.
(21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold.
(22) Annual average results of chemical composition analysis of all lime byproducts or wastes not sold.
(23) Annual quantity (tons) of all lime byproducts or wastes not sold.
§ 98.197   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section.
(a) Annual operating hours in calendar year.
(b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (9) of this section.
(1) Monthly calcium oxide content for each lime type, determined according to § 98.194(c) (metric tons CaO/metric ton lime) (Equation S-1 of § 98.193).
(2) Monthly magnesium oxide content for each lime type, determined according to § 98.194(c) (metric tons MgO/metric ton lime) (Equation S-1).
(3) Monthly calcium oxide content for each calcined lime byproduct or waste type sold (metric tons CaO/metric ton lime) (Equation S-2 of § 98.193).
(4) Monthly magnesium oxide content for each calcined lime byproduct or waste type sold (metric tons MgO/metric ton lime) (Equation S-2).
(5) Calcium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons CaO/metric ton lime) (Equation S-3 of § 98.193).
(6) Magnesium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons MgO/metric ton lime) (Equation S-3).
(7) Annual weight or mass of calcined byproducts or wastes for lime type that is not sold (tons) (Equation S-3).
(8) Monthly weight or mass of each lime type produced (tons) (Equation S-4 of § 98.193).
(9) Monthly weight or mass of each calcined byproducts or wastes sold (tons) (Equation S-4).
§ 98.198   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.200   Definition of source category.
The magnesium production and processing source category consists of the following processes:
(a) Any process in which magnesium metal is produced through smelting (including electrolytic smelting), refining, or remelting operations.
(b) Any process in which molten magnesium is used in alloying, casting, drawing, extruding, forming, or rolling operations.
§ 98.201   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a magnesium production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.202   GHGs to report.
(a) You must report emissions of the following gases in metric tons per year resulting from their use as cover gases or carrier gases in magnesium production or processing:
(1) Sulfur hexafluoride (SF 6 ).
(2) HFC-134a.
(3) The fluorinated ketone, FK 5-1-12.
(4) Carbon dioxide (CO 2 ).
(5) Any other GHGs (as defined in § 98.6).
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO 2 , N 2 O, and CH 4 emissions from each combustion unit by following the requirements of subpart C.
§ 98.203   Calculating GHG emissions.
(a) Calculate the mass of each GHG emitted from magnesium production or processing over the calendar year using either Equation T-1 or Equation T-2 of this section, as appropriate. Both of these equations equate emissions of cover gases or carrier gases to consumption of cover gases or carrier gases.
(1) To estimate emissions of cover gases or carrier gases by monitoring changes in container masses and inventories, emissions of each cover gas or carrier gas shall be estimated using Equation T-1 of this section:
(2) To estimate emissions of cover gases or carrier gases by monitoring changes in the masses of individual containers as their contents are used, emissions of each cover gas or carrier gas shall be estimated using Equation T-2 of this section:
(b) For purposes of Equation T-2 of this section, the mass of the cover gas used over the period p for an individual container shall be estimated by using Equation T-3 of this section:
(c) If a facility has mass flow controllers (MFC) and the capacity to track and record MFC measurements to estimate total gas usage, the mass of each cover or carrier gas monitored may be used as the mass of cover or carrier gas consumed (Q p ), in kg for period p in Equation T-2 of this section.
§ 98.204   Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) Emissions (consumption) of cover gases and carrier gases may be estimated by monitoring the changes in container weights and inventories using Equation T-1 of this subpart, by monitoring the changes in individual container weights as the contents of each container are used using Equations T-2 and T-3 of this subpart, or by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system. Emissions must be estimated at least annually.
(c) When estimating emissions by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system, you must use gas flow meters, or mass flow controllers, with an accuracy of 1 percent of full scale or better.
(d) When estimating emissions using Equation T-1 of this subpart, you must ensure that all the quantities required by Equation T-1 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier e.g., for the contents of containers containing new gas or for the heels remaining in containers returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however you remain responsible for the accuracy of these masses or weights under this subpart.
(e) When estimating emissions using Equations T-2 and T-3 of this subpart, you must monitor and record container identities and masses as follows:
(1) Track the identities and masses of containers leaving and entering storage with check-out and check-in sheets and procedures. The masses of cylinders returning to storage shall be measured immediately before the cylinders are put back into storage.
(2) Ensure that all the quantities required by Equations T-2 and T-3 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier e.g., for the contents of cylinders containing new gas or for the heels remaining in cylinders returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however, you remain responsible for the accuracy of these masses or weights under this subpart.
(f) All flowmeters, scales, and load cells used to measure quantities that are to be reported under this subpart shall be calibrated using calibration procedures specified by the flowmeter, scale, or load cell manufacturer. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at the minimum frequency specified by the manufacturer.
§ 98.205   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emission calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter will be used in the calculations as specified in paragraph (b) of this section.
(b) Replace missing data on the emissions of cover or carrier gases by multiplying magnesium production during the missing data period by the average cover or carrier gas usage rate from the most recent period when operating conditions were similar to those for the period for which the data are missing. Calculate the usage rate for each cover or carrier gas using Equation T-4 of this section:
(c) If the precise before and after weights are not available, it should be assumed that the container was emptied in the process ( i.e., quantity purchased should be used, less heel).
§ 98.206   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must include the following information at the facility level:
(a) Emissions of each cover or carrier gas in metric tons.
(b) Types of production processes at the facility ( e.g., primary, secondary, die casting).
(c) Amount of magnesium produced or processed in metric tons for each process type. This includes the output of primary and secondary magnesium production processes and the input to magnesium casting processes.
(d) Cover and carrier gas flow rate ( e.g., standard cubic feet per minute) for each production unit and composition in percent by volume.
(e) For any missing data, you must report the length of time the data were missing for each cover gas or carrier gas, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
(f) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg).
(g) If applicable, an explanation of any change greater than 30 percent in the facility's cover gas usage rate ( e.g., installation of new melt protection technology or leak discovered in the cover gas delivery system that resulted in increased emissions).
(h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year.
§ 98.207   Records that must be retained.
In addition to the records specified in § 98.3(g), you must retain the following information at the facility level:
(a) Check-out and weigh-in sheets and procedures for gas cylinders.
(b) Accuracy certifications and calibration records for scales including the method or manufacturer's specification used for calibration.
(c) Residual gas amounts (heel) in cylinders sent back to suppliers.
(d) Records, including invoices, for gas purchases, sales, and disbursements for all GHGs.
§ 98.208   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additionally, some sector-specific definitions are provided below:
Carrier gas means the gas with which cover gas is mixed to transport and dilute the cover gas thus maximizing its efficient use. Carrier gases typically include CO 2 , N 2 , and/or dry air.
Cover gas means SF 6 , HFC-134a, fluorinated ketone (FK 5-1-12) or other gas used to protect the surface of molten magnesium from rapid oxidation and burning in the presence of air. The molten magnesium may be the surface of a casting or ingot production operation or the surface of a crucible of molten magnesium that feeds a casting operation.
§ 98.210   Definition of the source category.
(a) This source category includes any equipment that uses carbonates listed in Table U-1 in manufacturing processes that emit carbon dioxide. Table U-1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO 2 if they consume at least 2,000 tons per year of carbonates heated to a temperature sufficient to allow the calcination reaction to occur.
(b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, zinc, or ceramics.
(c) This source category does not include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel Combustion Sources).
§ 98.211   Reporting threshold.
You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in § 98.210 of this subpart and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.212   GHGs to report.
You must report CO 2 process emissions from all miscellaneous carbonate use at your facility as specified in this subpart.
§ 98.213   Calculating GHG emissions.
You must determine CO 2 process emissions from carbonate use in accordance with the procedures specified in either paragraphs (a) or (b) of this section.
(a) Calculate the process emissions of CO 2 using calcination fractions with Equation U-1 of this section.
§ 98.214   Monitoring and QA/QC requirements.
(a) The annual mass of carbonate consumed (for Equation U-1 of this subpart) or carbonate inputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders.
(b) The annual mass of carbonate outputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders.
(c) If you follow the procedures of § 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.).
§ 98.215   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the substitute data value must be the best available estimate based on the all available process data or data used for accounting purposes.
§ 98.216   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable.
(a) Annual CO 2 emissions from miscellaneous carbonate use (metric tons).
(b) [Reserved]
(c) Measurement method used to determine the mass of carbonate.
(d) Method used to calculate emissions.
(e) If you followed the calculation method of § 98.213(a), you must report the information in paragraphs (e)(1) through (3) of this section.
(1)-(2) [Reserved]
(3) If you determined the calcination fraction, indicate which standard method was used.
(f) [Reserved]
(g) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption, carbonate input or carbonate output (months).
§ 98.217   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section:
(a) Monthly carbonate consumption (by carbonate type in tons).
(b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement devices.
(c) Records of all analyses conducted to meet the requirements of this rule.
(d) Records of all calculations conducted.
(e) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (4) of this section.
(1) Fraction calcination achieved for each particular carbonate type. As an alternative to measuring the calcination fraction, a value of 1.0 can be used (decimal fraction) (Equation U-1 of § 98.213).
(2) Annual mass of each carbonate type consumed (tons) (Equation U-1).
(3) Annual mass of each input carbonate type (tons) (Equation U-2 of § 98.213).
(4) Annual mass of each output carbonate type (tons) (Equation U-2).
§ 98.218   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.220   Definition of source category.
This source category includes a nitric acid production facility using one or more trains to produce weak nitric acid (30 to 70 percent in strength). Starting with reporting year 2018, this source category includes all nitric acid production facilities using one or more trains to produce nitric acid (any strength). A nitric acid train produces nitric acid through the catalytic oxidation of ammonia.
§ 98.221   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a nitric acid train and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.222   GHGs to report.
(a) You must report N 2 O process emissions from each nitric acid train as required by this subpart.
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit by following the requirements of subpart C.
§ 98.223   Calculating GHG emissions.
(a) You must determine annual N 2 O process emissions from each nitric acid train according to paragraphs (a)(1) or (a)(2) of this section.
(1) Use a site-specific emission factor and production data according to paragraphs (b) through (i) of this section.
(2) Request Administrator approval for an alternative method of determining N 2 O emissions according to paragraphs (a)(2)(i) through (iv) of this section.
(i) If you received Administrator approval for an alternative method of determining N 2 O emissions in the previous reporting year and your methodology is unchanged, your alternative method is automatically approved for the next reporting year.
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, if you have not received Administrator approval for an alternative method of determining N 2 O emissions in a prior reporting year or your methodology has changed, you must submit the request within the first 30 days of each subsequent reporting year.
(iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N 2 O emissions for the current reporting period using the procedures specified in paragraph (a)(1) of this section.
(b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (3) of this section.
(1) You must conduct the performance test at the absorber tail gas vent, referred to as the test point, for each nitric acid train according to § 98.224(b) through (f). If multiple nitric acid trains exhaust to a common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains.
(2) You must conduct the performance test under normal process operating conditions.
(3) You must measure the production rate during the performance test and calculate the production rate for the test period in tons (100 percent acid basis) per hour.
(c) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train “t” according to Equation V-1 of this section:
(d) If nitric acid train “t” exhausts to any N 2 O abatement technology “N”, you must determine the destruction efficiency for each N 2 O abatement technology “N” according to paragraphs (d)(1), (2), or (3) of this section.
(1) Use the manufacturer's specified destruction efficiency.
(2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency.
(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N 2 O abatement technology.
(e) If nitric acid train “t” exhausts to any N 2 O abatement technology “N”, you must determine the annual amount of nitric acid produced on nitric acid train “t” while N 2 O abatement technology “N” is operating according to § 98.224(f). Then you must calculate the abatement utilization factor for each N 2 O abatement technology “N” for each nitric acid train “t” according to Equation V-2 of this section.
(f) [Reserved]
(g) You must calculate N 2 O emissions for each nitric acid train “t” according to paragraph (g)(1), (g)(2), (g)(3), or (g)(4) of this section.
(1) If nitric acid train “t” exhausts to one N 2 O abatement technology “N” after the test point, you must use the emissions factor (determined in Equation V-1 of this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of this section), and the abatement utilization factor (determined in paragraph (e) of this section) according to Equation V-3a of this section:
(2) If multiple N 2 O abatement technologies are located in series after your test point, you must use the emissions factor (determined in Equation V-1 of this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of this section), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V-3b of this section:
(3) If multiple N 2 O abatement technologies are located in parallel after your test point, you must use the emissions factor (determined in Equation V-1 of this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of this section), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V-3c of this section:
(4) If nitric acid train “t” does not exhaust to any N 2 O abatement technology after the test point, you must use the emissions factor (determined in Equation V-1 of this section), and the annual nitric acid production (determined in paragraph (i) of this section) according to Equation V-3b of this section:
(h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility using Equation V-4 of this section:
(i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (tons acid produced, 100 percent acid basis), according to § 98.224(f).
§ 98.224   Monitoring and QA/QC requirements.
(a) You must conduct a new performance test according to a test plan as specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct the performance test annually. The test should be conducted at a point during the campaign which is representative of the average emissions rate from the nitric acid campaigns. Facilities must document the methods used to determine the representative point of the campaign when the performance test is conducted.
(2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed.
(3) If you requested Administrator approval for an alternative method of determining N 2 O emissions under § 98.223(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was submitted.
(b) You must measure the N 2 O concentration during the performance test using one of the methods in paragraphs (b)(1) through (b)(3) of this section.
(1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy.
(2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference in § 98.7).
(3) An equivalent method, with Administrator approval.
(c) You must determine the production rate(s) (100 percent acid basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (2) of this section.
(1) Direct measurement of production and concentration (such as using flow meters, weigh scales, for production and concentration measurements).
(2) Existing plant procedures used for accounting purposes (i.e. dedicated tank-level and acid concentration measurements).
(d) You must determine the volumetric flow rate during the performance test in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section.
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor(s).
(3) The production rate during each test and how it was determined.
(e) You must determine the total monthly amount of nitric acid produced. You must also determine the monthly amount of nitric acid produced while N 2 O abatement technology is operating from each nitric acid train. These monthly amounts are determined according to the methods in paragraphs (c)(1) or (2) of this section.
(f) You must determine the annual amount of nitric acid produced. You must also determine the annual amount of nitric acid produced while N 2 O abatement technology is operating for each nitric acid train. These annual amounts are determined by summing the respective monthly nitric acid quantities determined in paragraph (e) of this section.
§ 98.225   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of nitric acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).
(b) For missing values related to the performance test, including emission factors, production rate, and N 2 O concentration, you must conduct a new performance test according to the procedures in § 98.224 (a) through (d).
§ 98.226   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (q) of this section.
(a) Nitric Acid train identification number.
(b) Annual process N 2 O emissions from each nitric acid train (metric tons).
(c)-(d) [Reserved]
(e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis).
(f) Number of nitric acid trains.
(g) Number of different N 2 O abatement technologies per nitric acid train “t”.
(h) Abatement technologies used (if applicable) and date of installation of abatement technology.
(i)-(j) [Reserved]
(k) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual pressure).
(l) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production (months).
(m) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (7) of this section.
(1) [Reserved]
(2) Test method used for performance test.
(3)-(6) [Reserved]
(7) Number of times in the reporting year that a performance test had to be repeated (number).
(n) If you requested Administrator approval for an alternative method of determining N 2 O emissions under § 98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (4) of this section.
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(o) [Reserved]
(p) [Reserved]
(q) Annual percent N 2 O emission reduction for all nitric acid trains combined.
§ 98.227   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section for each nitric acid production facility:
(a) Records of significant changes to process.
(b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable).
(c) Performance test reports.
(d) Number of operating hours in the calendar year for each nitric acid train (hours).
(e) Annual nitric acid permitted production capacity (tons).
(f) Measurements, records, and calculations used to determine reported parameters.
(g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(h) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (h)(1) through (10) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (h)(1) through (10) of this section.
(1) Annual nitric acid produced from each nitric acid train (tons nitric acid produced, 100% acid basis).
(2) Indicate which equation was used to calculate emissions for each nitric acid train.
(3) N 2 O concentration per test run during the performance test (ppm N 2 O) (Equation V-1 of § 98.223).
(4) Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr) (Equation V-1).
(5) Production rate per test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis) (Equation V-1).
(6) Annual nitric acid production from each nitric acid train during which each N 2 O abatement technology was operational (tons nitric acid produced, 100 percent acid basis) (Equation V-2 of § 98.223).
(7) Destruction efficiency of N 2 O abatement technology that is used on each nitric acid train (decimal fraction of N 2 O removed from vent stream) (Equation V-3a of § 98.223).
(8) Destruction efficiency of each N 2 O abatement technology that is used on each nitric acid train (decimal fraction of N 2 O removed from vent stream) (Equation V-3b of § 98.223).
(9) Destruction efficiency of each N 2 O abatement technology that is used on each nitric acid train (decimal fraction of N 2 O removed from vent stream) (Equation V-3c of § 98.223).
(10) Fraction control factor of each N 2 O abatement technology that is used on each nitric acid train (decimal fraction of total emissions from nitric acid train “t” that are sent to abatement technology “n”) (Equation V-3c).
§ 98.228   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.230   Definition of the source category.
(a) This source category consists of the following industry segments:
(1) Offshore petroleum and natural gas production. Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms.
(2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment, which includes well drilling and completion equipment, workover equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels, all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well-pad using CO2 or natural gas injection.
(3) Onshore natural gas processing. Onshore natural gas processing means the forced extraction of natural gas liquids (NGLs) from field gas, fractionation of mixed NGLs to natural gas products, or both. Natural gas processing does not include a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing plant.
(4) Onshore natural gas transmission compression. Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas from production fields, natural gas processing plants, or other transmission compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission compressor station includes equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing plants are included in the onshore natural gas processing segment and are excluded from this segment.
(5) Underground natural gas storage. Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs.
(6) Liquefied natural gas (LNG) storage. LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas.
(7) LNG import and export equipment. LNG import equipment means all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States.
(8) Natural gas distribution. Natural gas distribution means the distribution pipelines and metering and regulating equipment at metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system. This segment also excludes customer meters and regulators, infrastructure, and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.
(9) Onshore petroleum and natural gas gathering and boosting. Onshore petroleum and natural gas gathering and boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the petroleum and/or natural gas to a downstream endpoint, typically a natural gas processing facility, a natural gas transmission pipeline or a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. Gathering and boosting equipment does not include equipment reported under any other industry segment defined in this section. Gathering pipelines operating on a vacuum and gathering pipelines with a GOR less than 300 standard cubic feet per stock tank barrel (scf/STB) are not included in this industry segment (oil here refers to hydrocarbon liquids of all API gravities).
(10) Onshore natural gas transmission pipeline. Onshore natural gas transmission pipeline means all natural gas transmission pipelines as defined in § 98.238.
(b) [Reserved]
§ 98.231   Reporting threshold.
(a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2), except for the industry segments in paragraphs (a)(1) through (4) of this section.
(1) Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in § 98.232(c) emit 25,000 metric tons of CO 2 equivalent or more per year.
(2) Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in § 98.232(i) emit 25,000 metric tons of CO 2 equivalent or more per year.
(3) Facilities must report emissions from the onshore petroleum and natural gas gathering and boosting industry segment only if emission sources specified in § 98.232(j) emit 25,000 metric tons of CO 2 equivalent or more per year.
(4) Facilities must report emissions from the onshore natural gas transmission pipeline industry segment only if emission sources specified in § 98.232(m) emit 25,000 metric tons of CO 2 equivalent or more per year.
(b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment.
§ 98.232   GHGs to report.
(a) You must report CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraphs (b) through (j) and (m) of this section, CO2, CH 4 , and N 2 O emissions from each flare as specified in paragraphs (b) through (j) of this section, and stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section. You must also report the information specified in paragraph (l) of this section, as applicable.
(b) For offshore petroleum and natural gas production, report CO 2 , CH 4 , and N 2 O emissions from the following sources. Offshore platforms do not need to report emissions from portable equipment.
(1) Equipment leaks ( i.e. , fugitives), vented emission, and flare emission source types as identified by Bureau of Ocean Energy Management (BOEM) in compliance with 30 CFR 550.302 through 304.
(2) Other large release events.
(c) For an onshore petroleum and natural gas production facility, report CO 2 , CH 4 , and N 2 O emissions from only the following source types on a single well-pad or associated with a single well-pad:
(1) Natural gas pneumatic device venting.
(2) Blowdown vent stacks.
(3) Natural gas driven pneumatic pump venting.
(4) Well venting for liquids unloading.
(5) Gas well venting during well completions without hydraulic fracturing.
(6) Well venting during well completions with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(7) Gas well venting during well workovers without hydraulic fracturing.
(8) Well venting during well workovers with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(9) Flare stack emissions.
(10) Hydrocarbon liquids and produced water storage tank emissions.
(11) Reciprocating compressor venting.
(12) Well testing venting and flaring.
(13) Associated gas venting and flaring from produced hydrocarbons.
(14) Dehydrator vents.
(15) [Reserved]
(16) EOR injection pump blowdown.
(17) Acid gas removal unit vents and nitrogen removal unit vents.
(18) EOR hydrocarbon liquids dissolved CO 2 .
(19) Centrifugal compressor venting.
(20) [Reserved]
(21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this section, as applicable:
(i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels.
(22) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that is located at an onshore petroleum and natural gas production facility as defined in § 98.238. Stationary or portable equipment are the following equipment, which are integral to the extraction, processing, or movement of oil or natural gas: well drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters.
(23) Other large release events.
(24) Drilling mud degassing.
(25) Crankcase vents.
(d) For onshore natural gas processing, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Dehydrator vents.
(5) Acid gas removal unit vents and nitrogen removal unit vents.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters, and equipment leaks from all other components in gas service (not including thief hatches or other openings on storage vessels) that either are subject to equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Natural gas pneumatic device venting.
(9) Other large release events.
(10) Hydrocarbon liquids and produced water storage tank emissions.
(11) Crankcase vents.
(e) For onshore natural gas transmission compression, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Condensate storage tanks.
(4) Blowdown vent stacks.
(5) Natural gas pneumatic device venting.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters.
(8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel.
(9) Other large release events.
(10) Dehydrator vents.
(11) Crankcase vents.
(f) For underground natural gas storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Natural gas pneumatic device venting.
(4) Flare stack emissions.
(5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters associated with storage stations.
(6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (f)(6) do not include thief hatches or other openings on a storage vessel.
(7) Equipment leaks from valves, connectors, open-ended lines, and pressure relief valves associated with storage wellheads.
(8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(9) Other large release events.
(10) Dehydrator vents.
(11) Blowdown vent stacks.
(12) Condensate storage tanks.
(13) Crankcase vents.
(g) For LNG storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Flare stack emissions.
(4) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(5) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (g)(6) of this section.
(6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Other large release events.
(9) Blowdown vent stacks.
(10) Acid gas removal unit vents and nitrogen removal unit vents.
(11) Crankcase vents.
(h) LNG import and export equipment, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Flare stack emissions.
(5) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(6) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (h)(7) of this section.
(7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(9) Acid gas removal unit vents and nitrogen removal unit vents.
(10) Other large release events.
(11) Crankcase vents.
(i) For natural gas distribution, report CO 2 , CH 4 , and N 2 O emissions from the following sources:
(1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations.
(2) Equipment leaks at below grade transmission-distribution transfer stations.
(3) Equipment leaks at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
(4) Equipment leaks at below grade metering-regulating stations.
(5) Distribution main equipment leaks.
(6) Distribution services equipment leaks.
(7) Report under subpart W of this part the emissions of CO 2 , CH 4 , and N 2 O emissions from stationary fuel combustion sources following the methods in § 98.233(z).
(8) Other large release events.
(9) Blowdown vent stacks.
(10) Natural gas pneumatic device venting.
(11) Crankcase vents.
(j) For an onshore petroleum and natural gas gathering and boosting facility, report CO 2 , CH 4 , and N 2 O emissions from the following source types:
(1) Natural gas pneumatic device venting.
(2) Natural gas driven pneumatic pump venting.
(3) Acid gas removal unit vents and nitrogen removal unit vents.
(4) Dehydrator vents.
(5) Blowdown vent stacks.
(6) Hydrocarbon liquids and produced water storage tank emissions.
(7) Flare stack emissions.
(8) Centrifugal compressor venting.
(9) Reciprocating compressor venting.
(10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this section, as applicable:
(i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels.
(11) Gathering pipeline equipment leaks.
(12) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that is located at an onshore petroleum and natural gas gathering and boosting facility as defined in § 98.238. Stationary or portable equipment includes the following equipment, which are integral to the movement of natural gas: Natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters.
(13) Other large release events.
(14) Crankcase vents.
(k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary fuel combustion unit by following the requirements of subpart C except for facilities under onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, and natural gas distribution. Onshore petroleum and natural gas production facilities must report stationary and portable combustion emissions as specified in paragraph (c) of this section. Natural gas distribution facilities must report stationary combustion emissions as specified in paragraph (i) of this section. Onshore petroleum and natural gas gathering and boosting facilities must report stationary and portable combustion emissions as specified in paragraph (j) of this section.
(l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 emissions captured and transferred off site by following the requirements of subpart PP.
(m) For onshore natural gas transmission pipeline, report CO 2 , CH 4 , and N 2 O emissions from the following source types:
(1) Blowdown vent stacks.
(2) Other large release events.
(3) Equipment leaks listed in paragraph (m)(3)(i) or (ii) of this section, as applicable:
(i) Equipment leaks at transmission company interconnect metering-regulating stations.
(ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at transmission company interconnect metering-regulating stations.
(4) Equipment leaks listed in paragraph (m)(4)(i) or (ii) of this section, as applicable:
(i) Equipment leaks at farm tap and/or direct sale metering-regulating stations.
(ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at farm tap and/or direct sale metering-regulating stations.
(5) Transmission pipeline equipment leaks.