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Electronic Code of Federal Regulations

e-CFR data is current as of November 7, 2019

Title 40Chapter ISubchapter CPart 98 → Subpart X


Title 40: Protection of Environment
PART 98—MANDATORY GREENHOUSE GAS REPORTING


Subpart X—Petrochemical Production


Contents
§98.240   Definition of the source category.
§98.241   Reporting threshold.
§98.242   GHGs to report.
§98.243   Calculating GHG emissions.
§98.244   Monitoring and QA/QC requirements.
§98.245   Procedures for estimating missing data.
§98.246   Data reporting requirements.
§98.247   Records that must be retained.
§98.248   Definitions.

§98.240   Definition of the source category.

(a) The petrochemical production source category consists of processes as described in paragraphs (a)(1) and (2) of this section.

(1) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, as either an intermediate in the on-site production of other chemicals or as an end product for sale or shipment off site, except as specified in paragraphs (b) through (g) of this section.

(2) When ethylene dichloride and vinyl chloride monomer are produced in an integrated process, you may consider the entire integrated process to be the petrochemical process for the purpose of complying with the mass balance option in §98.243(c). If you elect to consider the integrated process to be the petrochemical process, then the mass balance must be performed over the entire integrated process.

(b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category.

(c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and methanol.

(d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category.

(e) A process that produces bone black is not part of the petrochemical source category.

(f) A process that produces a petrochemical from bio-based feedstock is not part of the petrochemical production source category.

(g) A process that solely distills or recycles waste solvent that contains a petrochemical is not part of the petrochemical production source category.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 76 FR 80590, Dec. 23, 2011; 81 FR 89260, Dec. 9, 2016]

§98.241   Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in §98.240, and the facility meets the requirements of either §98.2(a)(1) or (2).

§98.242   GHGs to report.

You must report the information in paragraphs (a) through (c) of this section:

(a) CO2 CH4, and N2O process emissions from each petrochemical process unit. Process emissions include CO2 generated by reaction in the process and by combustion of process off-gas in stationary combustion units and flares.

(1) If you comply with §98.243(b) or (d), report under this subpart the calculated CO2, CH4, and N2O emissions for each stationary combustion source and flare that burns any amount of petrochemical process off-gas. If you comply with §98.243(b), also report under this subpart the measured CO2 emissions from process vents routed to stacks that are not associated with stationary combustion units.

(2) If you comply with §98.243(c), report under this subpart the calculated CO2 emissions for each petrochemical process unit.

(b) CO2, CH4, and N2O combustion emissions from stationary combustion units.

(1) If you comply with §98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(2) If you comply with §98.243(c), report CO2, CH4, and N2O combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C for all fuels, except emissions from burning petrochemical process off-gas in any combustion unit, including units that are not part of the petrochemical process unit, are not to be reported under subpart C of this part. Determine the applicable Tier in subpart C of this part (General Stationary Fuel Combustion Sources) based on the maximum rated heat input capacity of the stationary combustion source.

(c) CO2 captured. You must report the mass of CO2 captured under, subpart PP of this part (Suppliers of Carbon Dioxide (CO2) by following the requirements of subpart PP.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71960, Nov. 29, 2013]

§98.243   Calculating GHG emissions.

(a) If you route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and use CEMS on each stack to measure CO2 emissions (except flare stacks), then you must determine process-based GHG emissions in accordance with paragraph (b) of this section. Otherwise, determine process-based GHG emissions in accordance with the procedures specified in paragraph (c) or (d) of this section.

(b) Continuous emission monitoring system (CEMS). Route all process vent emissions and emissions from stationary combustion units that burn any amount of process off-gas to one or more stacks and determine GHG emissions as specified in paragraphs (b)(1) through (3) of this section.

(1) Determine CO2 emissions from each stack (except flare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this part.

(2) For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH4 and N2O emissions in accordance with subpart C of this part (use Equation C-10 and the “fuel gas” emission factors in Table C-2 of subpart C of this part).

(3) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in §98.253(b)(1) through (3).

(c) Mass balance for each petrochemical process unit. Calculate the emissions of CO2 from each process unit, for each calendar month as described in paragraphs (c)(1) through (c)(5) of this section.

(1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in §98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in §98.244(b)(3). Fuels used for combustion purposes are not considered to be feedstocks.

(2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in §98.244(b)(1).

(3) Collect a sample of each feedstock and product at least once per month and determine the molecular weight (for gaseous materials when the quantity is measured in scf) and carbon content of each sample according to the procedures of §98.244(b)(4). If multiple valid molecular weight or carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a feedstock supplier, or product customer, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in §98.244(b)(4).

(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume or mass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may determine molecular weight and carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section.

(i) Calculate the molecular weight and carbon content assuming 100 percent of that feedstock or product is the specific compound.

(ii) Maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information.

(iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. Keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.

(5) Calculate the CO2 mass emissions for each petrochemical process unit using Equations X-1 through X-4 of this section.

(i) Gaseous feedstocks and products. Use Equation X-1 of this section to calculate the net annual carbon input or output from gaseous feedstocks and products. Note that the result will be a negative value if there are no gaseous feedstocks in the process but there are gaseous products.

eCFR graphic er29no13.017.gif

View or download PDF

Where:

Cg = Annual net contribution to calculated emissions from carbon (C) in gaseous materials, including streams containing CO2 recovered for sale or use in another process (kg/yr).

(Fgf)i,n = Volume or mass of gaseous feedstock i introduced in month “n” (scf or kg). If you measure mass, the term (MWf)i,n/MVC is replaced with “1”.

(CCgf)i,n = Average carbon content of the gaseous feedstock i for month “n” (kg C per kg of feedstock).

(MWf)i,n = Molecular weight of gaseous feedstock i in month “n”(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68 °F and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole at 60 °F and 14.7 pounds per square inch absolute).

(Pgp)i,n = Volume or mass of gaseous product i produced in month “n” (scf or kg). If you measure mass, the term (MWp)i,n/MVC is replaced with “1”.

(CCgp)i,n = Average carbon content of gaseous product i, including streams containing CO2 recovered for sale or use in another process, for month “n” (kg C per kg of product).

(MWp)i,n = Molecular weight of gaseous product i in month “n” (kg/kg-mole).

j = Number of feedstocks.

k = Number of products.

(ii) Liquid feedstocks and products. Use Equation X-2 of this section to calculate the net carbon input or output from liquid feedstocks and products. Note that the result will be a negative value if there are no liquid feedstocks in the process but there are liquid products.

eCFR graphic er30oc09.084.gif

View or download PDF

Where:

Cl = Annual net contribution to calculated emissions from carbon in liquid materials, including liquid organic wastes (kg/yr).

(Flf)i,n = Volume or mass of liquid feedstock i introduced in month “n” (gallons or kg).

(CClf)i,n = Average carbon content of liquid feedstock i for month “n” (kg C per gallon or kg of feedstock).

(Plp)i,n = Volume or mass of liquid product i produced in month “n” (gallons or kg).

(CClp)i,n = Average carbon content of liquid product i, including organic liquid wastes, for month “n” (kg C per gallon or kg of product).

j = Number of feedstocks.

k = Number of products.

(iii) Solid feedstocks and products. Use Equation X-3 of this section to calculate the net annual carbon input or output from solid feedstocks and products. Note that the result will be a negative value if there are no solid feedstocks in the process but there are solid products.

eCFR graphic er30oc09.085.gif

View or download PDF

Where:

Cs = Annual net contribution to calculated emissions from carbon in solid materials (kg/yr).

(Fsf)i,n = Mass of solid feedstock i introduced in month “n” (kg).

(CCsf)i,n = Average carbon content of solid feedstock i for month “n” (kg C per kg of feedstock).

(Psp)i,n = Mass of solid product i produced in month “n” (kg).

(CCsp)i,n = Average carbon content of solid product i in month “n” (kg C per kg of product).

j = Number of feedstocks.

k = Number of products.

(iv) Annual emissions. Use the results from Equations X-1 through X-3 of this section, as applicable, in Equation X-4 of this section to calculate annual CO2 emissions.

eCFR graphic er30oc09.086.gif

View or download PDF

Where:

CO2 = Annual CO2 mass emissions from process operations and process off-gas combustion (metric tons/year).

0.001 = Conversion factor from kg to metric tons.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of carbon (C) (kg/kg-mole).

(d) Optional combustion methodology for ethylene production processes. For each ethylene production process, calculate GHG emissions from combustion units that burn fuel that contains any off-gas from the ethylene process as specified in paragraphs (d)(1) through (d)(5) of this section.

(1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO2 emissions using the Tier 3 or Tier 4 methodology in subpart C of this part.

(2) You may use either Equation C-1 or Equation C-2a in subpart C of this part to calculate CO2 emissions from combustion of any ethylene process off-gas streams that meet either of the conditions in paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default values in the calculation, use the defaults for fuel gas in Table C-1 of subpart C of this part). Follow the otherwise applicable procedures in subpart C to calculate emissions from combustion of all other fuels in the combustion unit.

(i) The annual average flow rate of fuel gas (that contains ethylene process off-gas) in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute, and a flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.

(ii) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that contains ethylene process off-gas) or an upstream common pipe.

(3) Except as specified in paragraph (d)(5) of this section, calculate CH4 and N2O emissions using the applicable procedures in §98.33(c) for the same tier methodology that you used for calculating CO2 emissions.

(i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for “Fuel Gas” in Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources).

(ii) For Tier 3, use either the default high heat value for fuel gas in Table C-1 of subpart C of this part or a calculated HHV, as allowed in Equation C-8 of subpart C of this part.

(4) You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas.

(5) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in §§98.253(b)(1) through (b)(3).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71961, Nov. 29, 2013; 81 FR 89260, Dec. 9, 2016]

§98.244   Monitoring and QA/QC requirements.

(a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in §98.34(c).

(b) If you use the mass balance methodology in §98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents.

(1) Operate, maintain, and calibrate belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see §98.7), or follow procedures specified by the measurement device manufacturer. You must recalibrate each weighing device according to one of the following frequencies. You may recalibrate either at the minimum frequency specified by the manufacturer or biennially (i.e., once every two years).

(2) Operate and maintain all flow meters used for gas and liquid feedstocks and products according to the manufacturer's recommended procedures. You must calibrate each of these flow meters as specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section:

(i) You may use either the calibration methods specified by the flow meter manufacturer or an industry consensus standard method. Each flow meter must meet the applicable accuracy specification in §98.3(i), except as otherwise specified in §§98.3(i)(4) through (i)(6).

(ii) You must recalibrate each flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used.

(3) You must perform tank level measurements (if used to determine feedstock or product flows) according to one of the following methods. You may use any standard method published by a consensus-based standards organization or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th Floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org,) and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).

(4) Beginning January 1, 2010, use any applicable methods specified in paragraphs (b)(4)(i) through (xv) of this section to determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products. Calibrate instruments in accordance with paragraphs (b)(4)(i) through (xv) of this section, as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (xv) of this section may be performed by the owner or operator, by an independent laboratory, by the supplier of a feedstock, or by a product customer.

(i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7).

(ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph (incorporated by reference, see §98.7).

(iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography (incorporated by reference, see §98.7).

(iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7).

(v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference, see §98.7).

(vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see §98.7).

(vii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7).

(viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A (all incorporated by reference, see §98.7).

(ix) Method 18 at 40 CFR part 60, appendix A-6.

(x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of the rule.

(xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography (incorporated by reference, see §98.7).

(xii) ASTM D7633-10 Standard Test Method for Carbon Black—Carbon Content (incorporated by reference, see §98.7).

(xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions.

(xiv) The results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions.

(xv) Beginning on January 1, 2010, the methods specified in paragraphs (b)(4)(xv)(A) and (B) of this section may be used as alternatives for the methods specified in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section.

(A) An industry standard practice or a method published by a consensus-based standards organization if such a method exists for carbon black feedstock oils and carbon black products. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.naesb.org). The method(s) used shall be documented in the monitoring plan required under §98.3(g)(5).

(B) Modifications of existing analytical methods or other methods that are applicable to your process provided that the methods listed in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe.

(c) If you comply with §98.243(b) or (d), conduct monitoring and QA/QC for flares in accordance with §98.254(b) through (e) for each flare gas flow meter, gas composition meter, and/or heating value monitor that you use to comply with §98.253(b)(1) through (b)(3). You must implement all applicable QA/QC requirements specified in this paragraph (c) beginning no later than January 1, 2015.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79158, Dec. 17, 2010; 78 FR 71961, Nov. 29, 2013]

§98.245   Procedures for estimating missing data.

For missing feedstock and product flow rates, use the same procedures as for missing fuel usage as specified in §98.35(b)(2). For missing feedstock and product carbon contents and missing molecular weights for gaseous feedstocks and products, use the same procedures as for missing carbon contents and missing molecular weights for fuels as specified in §98.35(b)(1).

For missing flare data, follow the procedures in §98.255(b) and (c).

[78 FR 71962, Nov. 29, 2013]

§98.246   Data reporting requirements.

In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit.

(a) If you use the mass balance methodology in §98.243(c), you must report the information specified in paragraphs (a)(1) through (13) of this section for each type of petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other appropriate descriptor.

(2) The type of petrochemical produced, names of products, and names of carbon-containing feedstocks.

(3) Annual CO2 emissions calculated using Equation X-4 of this subpart.

(4) The temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X-1 of §98.243 were determined.

(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.

(6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.

(i) Name of each method used to determine carbon content or molecular weight in accordance with §98.244(b)(4);

(ii) Description of each type of measurement device (e.g., flow meter, weighing device) used to determine volume or mass in accordance with §98.244(b)(1) through (3).

(iii) Identification of each method (i.e., method number, title, or other description) used to determine volume or mass in accordance with §98.244(b)(1) through (3).

(7) [Reserved]

(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit.

(9) The number of days during which off-specification product was produced if the alternative to sampling and analysis specified in §98.243(c)(4) is used for a product, and, if applicable, the date of any process change that reduced the monthly average composition to less than 99.5 percent for each product or feedstock for which you comply with the alternative to sampling and analysis specified in §98.243(c)(4).

(10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation.

(11) If you determine carbon content or composition of a feedstock or product using a method under §98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports.

(i) Name or title of the analytical method.

(ii) A copy of the method. If the method is a modification of a method listed in §§98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the listed method.

(iii) An explanation of why an alternative to the methods listed in §§98.244(b)(4)(i) through (xiv) is needed.

(12) Name and annual quantity (in metric tons) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of §98.243.

(13) Name and annual quantity (in metric tons) of each product included in Equations X-1, X-2, and X-3.

(14) Annual average of the measurements or determinations of the carbon content of each feedstock and product, conducted according to §98.243(c)(3) or (4).

(i) For feedstocks and products that are gaseous or solid, report this quantity in kg C per kg of feedstock or product.

(ii) For liquid feedstocks and products, report this quantity either in units of kg C per kg of feedstock or product, or kg C per gallon of feedstock or product.

(15) For each gaseous feedstock and product, the annual average of the measurements or determinations of the molecular weight in units of kg per kg mole, conducted according to §98.243(c)(3) or (4).

(b) If you measure emissions in accordance with §98.243(b), then you must report the information listed in paragraphs (b)(1) through (10) of this section.

(1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.

(2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Section 98.36(c)(2)(ii), (ix) and (x) do not apply for the purposes of this subpart.

(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under §98.36(b)(6) and (7), (b)(9)(i) and (ii) and (e)(2)(vi).

(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO2 emissions that results from CO2 directly emitted by the petrochemical process unit plus CO2 generated by the combustion of off-gas from the petrochemical process unit.

(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH4 and N2O emissions expressed in metric tons of each gas. For each CEMS monitoring location, provide an estimate based on engineering judgment of the fraction of the total CH4 and N2O emissions that is attributable to combustion of off-gas from the petrochemical process unit.

(6) [Reserved]

(7) Information listed in §98.256(e) of subpart Y of this part for each flare that burns process off-gas.

(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.

(9) Name and annual quantity (in metric tons) of each carbon-containing feedstock.

(10) Name and annual quantity (in metric tons) of each product.

(c) If you comply with the combustion methodology specified in §98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(5) of this section.

(1) The ethylene process unit ID or other appropriate descriptor.

(2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in §98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit.

(3) Information listed in §98.256(e) of subpart Y of this part for each flare that burns ethylene process off-gas.

(4) Name and annual quantity of each feedstock (metric tons).

(5) Annual quantity of ethylene produced from each process unit (metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79159, Dec. 17, 2010; 78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014; 81 FR 89260, Dec. 9, 2016]

§98.247   Records that must be retained.

In addition to the recordkeeping requirements in §98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section, as applicable.

(a) If you comply with the CEMS measurement methodology in §98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in §98.37, records of the procedures used to develop estimates of the fraction of total emissions attributable to petrochemical processing and combustion of petrochemical process off-gas as required in §98.246(b), and records of any annual average HHV calculations.

(b) If you comply with the mass balance methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (4) of this section.

(1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4).

(2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of product.

(3) As part of the monitoring plan required under §98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.

(4) The dates and results (e.g., percent calibration error) of the calibrations of each measurement device.

(c) If you comply with the combustion methodology in §98.243(d), then you must retain under this subpart the records required for the applicable Tier Calculation Methodologies in §98.37. If you comply with §98.243(d)(2), you must also keep records of the annual average flow calculations.

(d) 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 (d)(1) through (30) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (30) of this section.

(1) Indicate whether the feedstock is measured as mass or volume (Equation X-1 of §98.243).

(2) Indicate whether you used the alternative to sampling and analysis specified in §98.243(c)(4) (Equation X-1).

(3) Volume of gaseous feedstock introduced per month (scf) (Equation X-1).

(4) Mass of gaseous feedstock introduced per month (kg) (Equation X-1).

(5) Average carbon content of the gaseous feedstock per month (kg C per kg of feedstock) (Equation X-1).

(6) Molecular weight of gaseous feedstock per month (kg per kg-mole) (Equation X-1).

(7) Indicate whether the gaseous product is measured as mass or volume (Equation X-1).

(8) Volume of gaseous product produced per month (scf) (Equation X-1).

(9) Mass of gaseous product produced per month (kg) (Equation X-1).

(10) Average carbon content of gaseous product (including streams containing CO2 recovered for sale or use in another process) per month (kg C per kg of product) (Equation X-1).

(11) Molecular weight of gaseous product per month (kg per kg-mole) (Equation X-1).

(12) Molar volume conversion factor of product (scf per kg-mole) (Equation X-1).

(13) Indicate whether feedstock is measured as mass or volume (Equation X-2 of §98.243).

(14) Indicate whether you used the alternative to sampling and analysis specified in §98.243(c)(4) (Equation X-2).

(15) Volume of liquid feedstock introduced per month (gallons) (Equation X-2).

(16) Mass of liquid feedstock introduced per month (kg) (Equation X-2).

(17) Average carbon content of liquid feedstock per month (kg C per gallon) (Equation X-2).

(18) Average carbon content of liquid feedstock per month (kg C per kg of feedstock) (Equation X-2).

(19) Indicate whether product is measured as mass or volume per month (Equation X-2).

(20) Volume of liquid product produced per month (gallons) (Equation X-2).

(21) Mass of liquid product produced per month (kg) (Equation X-2).

(22) Average carbon content of liquid product per month, including organic liquid wastes (kg C per gallon) (Equation X-2).

(23) Average carbon content of liquid product, including organic liquid wastes (kg C per kg of product) (Equation X-2).

(24) Indicate whether you used the alternative to sampling and analysis specified in §98.243(c)(4) (Equation X-3 of §98.243).

(25) Mass of solid feedstock introduced per month (kg) (Equation X-3).

(26) Average carbon content of solid feedstock per month (kg C per kg of feedstock) (Equation X-3).

(27) Mass of solid product produced per month (kg) (Equation X-3).

(28) Average carbon content of solid product per month (kg C per kg of product) (Equation X-3).

(29) Records required in §98.257(b)(1) through (8) of this section for each flare that burns ethylene process off-gas.

(30) Records required in §98.37 for each stationary fuel combustion unit (or group of stationary sources with a common pipe) that burns ethylene process off-gas, except flares.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014; 81 FR 89261, Dec. 9, 2016]

§98.248   Definitions.

Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

Product means each of the following carbon-containing outputs from a process: The petrochemical, recovered byproducts, and liquid organic wastes that are not combusted onsite. Product does not include process vent emissions, fugitive emissions, or wastewater.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71963, Nov. 29, 2013; 81 FR 89261, Dec. 9, 2016]

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