Title 40—Protection of Environment--Volume 1
PART 98—MANDATORY GREENHOUSE GAS REPORTING
§ 98.237   Records that must be retained.
Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by § 98.3(g), you must retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected and measurements.
(c) Calibration reports for detection and measurement instruments used.
(d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
(e) The records required under § 98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart.
(f) For each time a missing data procedure was used, keep a record listing the emission source type, a description of the circumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to develop the substitute value, and the substitute value.
(g) For each situation when you fail to fully conform with all cited provisions in either § 98.233(n)(1)(i) or (ii) for a period of 15 consecutive days and you utilized the Tier 3 default destruction and combustion efficiency values, you must document these periods when the non-conformance began, and the date when full conformance was re-established.
§ 98.238   Definitions.
Except as provided 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.
Acid gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural gas by an acid gas removal unit.
Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators.
Acid gas removal unit (AGR) vent emissions mean the acid gas separated from the acid gas absorbing medium ( e.g. , an amine solution) and released with methane and other light hydrocarbons to the atmosphere.
Associated gas venting or flaring means the venting or flaring of natural gas which originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. This does not include venting or flaring resulting from activities that are reported elsewhere, including tank venting, well completions, and well workovers.
Associated with a single well-pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well-pad. The association ends where the stream from a single well-pad is combined with streams from one or more additional single well-pads, where the point of combination is located off that single well-pad. Onshore production storage tanks on or associated with a single well-pad are considered a part of the onshore production facility.
Atmospheric pressure storage tank means a vessel (excluding sumps) operating at atmospheric pressure that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials ( e.g. , wood, concrete, steel, plastic) that provide structural support. Atmospheric pressure storage tanks include both fixed roof tanks and floating roof tanks. Floating roof tanks include tanks with either an internal floating roof or an external floating roof.
Automated liquids unloading means an unloading that is performed without manual interference. Examples of automated liquids unloadings include a timing and/or pressure device used to optimize intermittent shut-in of the well before liquids choke off gas flow or to open and close valves, continually operating equipment that does not require presence of an operator such as rod pumping units, automated and unmanned plunger lifts, or other unloading activities that do not entail a physical presence at the well-pad.
Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see § 98.7).
Centralized oil production site means any permanent combination of one or more hydrocarbon liquids storage tanks located on one or more contiguous or adjacent properties that does not also contain a permanent combination of one or more compressors that are part of the onshore petroleum and natural gas gathering and boosting facility that gathers hydrocarbon liquids from multiple well-pads. A centralized oil production site is a type of gathering and boosting site for purposes of this subpart.
Compressor means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natural gas or CO 2 .
Compressor mode means the operational and pressurized status of a compressor. For both centrifugal compressors and reciprocating compressors, “mode” refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
Compressor source means the source of certain venting or leaking emissions from a centrifugal or reciprocating compressor. For centrifugal compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, wet seal oil degassing vents, and dry seal vents. For reciprocating compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and rod packing emissions.
Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions.
Crankcase venting means the process of venting or removing blow-by from the void spaces of an internal combustion engine outside of the combustion cylinders to prevent excessive pressure build-up within the engine. This does not include ingestive systems that vent blow-by into the engine where it is returned to the combustion process ( e.g. , closed crankcase ventilation system, closed breather system) or if the vent blow-by is routed to another closed vent system.
Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3.
Drilling mud means a mixture of clays and additives with water, oil, or synthetic materials. While drilling, the drilling mud is continuously pumped through the drill string and out the bit to cool and lubricate the drill bit, and move cuttings through the wellbore to the surface.
Drilling mud degassing means the practice of safely removing pockets of free gas entrained in the drilling mud once it is outside of the wellbore.
Enclosed combustion device means a flare that uses a closed flame.
Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil.
Equivalent stratigraphic interval means the depth of the same stratum of rock in the Earth's subsurface.
External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units.
Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and 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 are operated as an independent municipally-owned distribution system.
Facility with respect to onshore petroleum and natural gas gathering and boosting for purposes of reporting under this subpart and for the corresponding subpart A requirements means all gathering pipelines and other equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in this section. Where a person owns or operates more than one gathering and boosting system in a basin (for example, separate gathering lines that are not connected), then all gathering and boosting equipment that the person owns or operates in the basin would be considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities, is considered to be under common control of the owner or operator of the gathering and boosting system that contains the pipeline. The facility does not include equipment and pipelines that are part of any other industry segment defined in this subpart.
Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements means all petroleum or natural gas equipment on a single well-pad or associated with a single well-pad and CO 2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in § 98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.
Facility with respect to the onshore natural gas transmission pipeline segment means the total U.S. mileage of natural gas transmission pipelines, as defined in this section, owned and operated by an onshore natural gas transmission pipeline owner or operator as defined in this section. The facility does not include pipelines that are part of any other industry segment defined in this subpart.
Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. In some cases a nearby LDC may handle the billing of the gas to the customer(s).
Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see § 98.7).
Flare, for the purposes of subpart W, means a combustion device, whether at ground level or elevated, that uses an open or closed flame to combust waste gases without energy recovery.
Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip.
Flare stack emissions means CO 2 in gas routed to a flare, CO 2 from partial combustion of hydrocarbons in gas routed to a flare, CH 4 emissions resulting from the incomplete combustion of hydrocarbons in gas routed to a flare, and N 2 O resulting from operation of a flare.
Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself natural gas dehydration, the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid.
Gathering and boosting site means a single gathering compressor station as defined in this section, centralized oil production site as defined in this section, gathering pipeline site as defined in this section, or other fence-line site within the onshore petroleum and natural gas gathering and boosting industry segment.
Gathering and boosting system means a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production or one or more other gathering and boosting systems and a downstream endpoint, typically a gas processing plant, transmission pipeline, LDC pipeline, or other gathering and boosting system.
Gathering and boosting system owner or operator means any person that holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natural gas production wells or one or more other gathering and boosting systems to a downstream endpoint, typically a natural gas processing facility, another gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline, or any person responsible for custody of the petroleum or natural gas transported.
Gathering compressor station means any permanent combination of one or more compressors located on one or more contiguous or adjacent properties that are part of the onshore petroleum and natural gas gathering and boosting facility that move natural gas at increased pressure through gathering pipelines or into or out of storage. A gathering compressor station is a type of gathering and boosting site for purposes of this subpart.
Gathering pipeline site means all of the gathering pipelines within a single state. A gathering pipeline site is a type of gathering and boosting site for purposes of this subpart.
Horizontal well means a well bore that has a planned deviation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation.
In vacuum service means equipment operating at an internal pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient pressure.
Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combustion engine the expansion of the high-temperature and -pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines.
Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to −260 degrees Fahrenheit at atmospheric pressure.
LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps.
Manifolded compressor source means a compressor source (as defined in this section) that is manifolded to a common vent that routes gas from multiple compressors.
Manifolded group of compressor sources means a collection of any combination of manifolded compressor sources (as defined in this section) that are manifolded to a common vent.
Manual liquids unloading means an unloading when field personnel attend to the well at the well-pad, for example to manually plunge a well at the site using a rig or other method, to open a valve to direct flow to an atmospheric tank to clear the well, or to manually shut-in the well to allow pressure to build in the well-bore. Manual unloadings may be performed on a routine schedule or on “as needed” basis.
Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow, or both, in the natural gas distribution industry segment. At least one meter, at least one regulator, or any combination of both on a single run of piping is considered one meter/regulator run.
Metering-regulating station means a station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas distribution facility. This does not include customer meters, customer regulators, or farm taps.
Mud rate means the pumping rate of the mud by the mud pumps, usually measured in gallons per minute (gpm).
Natural gas means a naturally occurring mixture or process derivative of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth's surface, of which its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas.
Nitrogen removal unit (NRU) means a process unit that separates nitrogen from natural gas using various separation processes ( e.g. , cryogenic units, membrane units).
Nitrogen removal unit vent emissions means the nitrogen gas separated from the natural gas and released with methane and other gases to the atmosphere.
Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.
Onshore natural gas transmission pipeline owner or operator means, for interstate pipelines, the person identified as the transmission pipeline owner or operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, the person identified as the owner or operator on the transmission pipeline's Statement of Operating Conditions under section 311 of the Natural Gas Policy Act, or for pipelines that fall under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994), the person identified as the owner or operator on blanket certificates issued under 18 CFR 284.224. If an intrastate pipeline is not subject to section 311 of the Natural Gas Policy Act (NGPA), the onshore natural gas transmission pipeline owner or operator is the person identified as the owner or operator on reports to the state regulatory body regulating rates and charges for the sale of natural gas to consumers.
Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in § 98.230(a)(2). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator.
Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank.
Other large release event means any planned or unplanned uncontrolled release to the atmosphere of gas, liquids, or mixture thereof, from wells and/or other equipment that result in emissions for which there are no methodologies in § 98.233 other than under § 98.233(y) to appropriately estimate these emissions. Other large release events include, but are not limited to, well blowouts, well releases, pressure relief valve releases from process equipment other than hydrocarbon liquids storage tanks, storage tank cleaning and other maintenance activities, and releases that occur as a result of an accident, equipment rupture, fire, or explosion. Other large release events also include failure of equipment or equipment components such that a single equipment leak or release has emissions that exceed the emissions calculated for that source using applicable methods in § 98.233(a) through (h), (j) through (s), (w), (x), (dd), or (ee) by the threshold in § 98.233(y)(1)(ii). Other large release events do not include blowdowns for which emissions are calculated according to the provisions in § 98.233(i).
Pressure groups as applicable to each sub-basin are defined as follows: Less than or equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of pressure groups is either the well shut-in pressure; well casing pressure; or you may use the casing-to-tubing pressure of one well from the same sub-basin multiplied by the tubing pressure for each well in the sub-basin.
Produced water means the water (brine) brought up from the hydrocarbon-bearing strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.
Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere.
Reduced emissions completion means a well completion following hydraulic fracturing where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emissions completion may occur.
Reduced emissions workover means a well workover with hydraulic fracturing ( i.e., refracturing) where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emissions workover may occur.
Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases.
Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline.
Routed to combustion means, for onshore petroleum and natural gas production facilities, natural gas distribution facilities, and onshore petroleum and natural gas gathering and boosting facilities, that emissions are routed to stationary or portable fuel combustion equipment specified in § 98.232(c)(22), (i)(7), or (j)(12), as applicable. For all other industry segments in this subpart, routed to combustion means that emissions are routed to a stationary fuel combustion unit subject to subpart C of this part (General Stationary Fuel Combustion Sources).
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub-basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation.
Target hydrocarbon-bearing stratigraphic formation means the stratigraphic interval intended to be the primary hydrocarbon producing formation.
Transmission company interconnect M&R station means a metering and pressure regulating stations with an inlet pressure above 100 psig located at a point of transmission pipeline to transmission pipeline interconnect.
Transmission-distribution (T-D) transfer station means a metering-regulating station where a local distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline.
Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994).
Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; outer diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 inch.
Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size.
Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate.
Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).
Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off-set horizontally from the surface location, intercepting the targets either vertically or at an angle.
Well blowout means a complete loss of well control for a long duration of time resulting in an emissions release.
Well identification (ID) number means the unique and permanent identification number assigned to a petroleum or natural gas well. If the well has been assigned a US Well Number, the well ID number required in this subpart is the US Well Number. If a US Well Number has not been assigned to the well, the well ID number is the identifier established by the well's permitting authority.
Well-pad site means all equipment on or associated with a single well-pad. Specifically, the well-pad site includes all equipment on a single well-pad plus all equipment associated with that single well-pad.
Well release means a short duration of uncontrolled emissions release from a well followed by a period of controlled emissions release in which control techniques were successfully implemented.
Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined for regulatory, commercial, or technical purposes. If well testing is conducted immediately after well completion or workover, then it is considered part of well completion or workover.
Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.
§ 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.
§ 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) CO 2 CH 4 , and N 2 O process emissions from each petrochemical process unit. Process emissions include CO 2 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 CO 2 , CH 4 , and N 2 O 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 CO 2 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 CO 2 emissions for each petrochemical process unit.
(b) CO 2 , CH 4 , and N 2 O 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 CO 2 , CH 4 , and N 2 O 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) CO 2 captured. You must report the mass of CO 2 captured under, subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 ) by following the requirements of subpart PP.
§ 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 CO 2 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 CO 2 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 CH 4 and N 2 O 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 CO 2 , CH 4 , and N 2 O emissions using the methodology specified in § 98.253(b).
(c) Mass balance for each petrochemical process unit. Calculate the emissions of CO 2 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 CO 2 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.
(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.
(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.
(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 CO 2 emissions.
(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 CO 2 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 CO 2 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 CH 4 and N 2 O emissions using the applicable procedures in § 98.33(c) for the same tier methodology that you used for calculating CO 2 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 CO 2 , CH 4 , and N 2 O emissions using the methodology specified in § 98.253(b).
§ 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 (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.
§ 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).
§ 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 (15) 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.
(3) Annual CO 2 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, the portion of the total amount of ethylene dichloride (EDC) produced that is used in vinyl chloride monomer (VCM) production may be a measured quantity or an estimate that is based on process knowledge and best available data. The portion of the total amount of EDC produced that is not utilized in VCM production must be measured in accordance with § 98.244(b)(2) or (3). Sum the amount of EDC used in the production of VCM plus the amount of separate EDC product to report as the total quantity of EDC petrochemical from an integrated EDC/VCM petrochemical process unit.
(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 to § 98.243. If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the reported quantity of EDC product should include only that which was not used in the VCM process.
(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 or product for which the volume was used in equation X-1 to § 98.243, report the annual average molecular weight of the measurements or determinations, conducted according to § 98.243(c)(3) or (4). Report the annual average molecular weight in units of kg per kg mole.
(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 CO 2 emissions that results from CO 2 directly emitted by the petrochemical process unit plus CO 2 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 CH 4 and N 2 O 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 CH 4 and N 2 O emissions that is attributable to combustion of off-gas from the petrochemical process unit.
(6) [Reserved]
(7) Information listed in § 98.256(e) for each flare that burns process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO 2 , CH 4 and N 2 O emissions that are attributable to combustion of off-gas from the petrochemical process unit(s) served by the flare.
(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons).
(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 (6) 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) for each flare that burns ethylene process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO 2 , CH 4 and N 2 O emissions that are attributable to combustion of off-gas from the ethylene process unit(s) served by the flare.
(4) Name and annual quantity of each carbon-containing feedstock (metric tons).
(5) Annual quantity of ethylene produced from each process unit (metric tons).
(6) Name and annual quantity (in metric tons) of each product produced in each process unit.
§ 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 CO 2 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.
§ 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.
§ 98.250   Definition of source category.
(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of this section.
(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced.
(c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; and sulfur recovery plants.
§ 98.251   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.252   GHGs to report.
You must report:
(a) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion units and from each flare. Calculate and report the emissions from stationary combustion units under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C, except for emissions from combustion of fuel gas. For CO 2 emissions from combustion of fuel gas, use either Equation C-5 in subpart C of this part or the Tier 4 methodology in subpart C of this part, unless either of the conditions in paragraphs (a)(1) or (2) of this section are met, in which case use either Equations C-1 or C-2a in subpart C of this part. For CH 4 and N 2 O emissions from combustion of fuel gas, use the applicable procedures in § 98.33(c) for the same tier methodology that was used for calculating CO 2 emissions. (Use the default CH 4 and N 2 O emission factors for “Fuel Gas” in Table C-2 of this part. 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.) You may aggregate units, monitor common stacks, or monitor common (fuel) pipes as provided in § 98.36(c) when calculating and reporting emissions from stationary combustion units. Calculate and report the emissions from flares under this subpart.
(1) The annual average fuel gas flow rate 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 either of the conditions in paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe.
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(2) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr and either of the following conditions exist:
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe; or
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(b) CO 2 , CH 4 , and N 2 O coke burn-off emissions from each catalytic cracking unit, fluid coking unit, and catalytic reforming unit under this subpart.
(c) CO 2 emissions from sour gas sent off site for sulfur recovery operations under this subpart. You must follow the calculation methodologies from § 98.253(f) and the monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of this subpart.
(d) CO 2 process emissions from each on-site sulfur recovery plant under this subpart.
(e) [Reserved]
(f) CO 2 and CH 4 emissions from asphalt blowing operations under this subpart.
(g) CH 4 emissions from equipment leaks, storage tanks, loading operations, delayed coking units, and uncontrolled blowdown systems under this subpart.
(h) CO 2 , CH 4 , and N 2 O emissions from each process vent not specifically included in paragraphs (a) through (g) of this section under this subpart.
(i) [Reserved]
§ 98.253   Calculating GHG emissions.
(a) Calculate GHG emissions required to be reported in § 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section.
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare GHG emissions calculations with the exception of the following, which may be excluded as applicable: gas used for the flare pilots, and if using the calculation method in paragraph (b)(1)(iii) of this section, the gas released during start-up, shutdown, or malfunction events of 500,000 scf/day or less.
(1) Calculate the CO 2 emissions according to the applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this section.
(i) Flow measurement. If you have a continuous flow monitor on the flare, you must use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range of the measurement device to calculate the flare gas flow. If you do not have a continuous flow monitor on the flare and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, you must use engineering calculations, company records, or similar estimates of volumetric flare gas flow.
(ii) Heat value or carbon content measurement. If you have a continuous higher heating value monitor or gas composition monitor on the flare or if you monitor these parameters at least weekly, you must use the measured heat value or carbon content value in calculating the CO 2 emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).
(A) If you monitor gas composition, calculate the CO 2 emissions from the flare using either Equation Y-1a or Equation Y-1b of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y-1a or Equation Y-1b of this section; otherwise, use weekly values.
(B) If you monitor heat content but do not monitor gas composition, calculate the CO 2 emissions from the flare using Equation Y-2 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y-2 of this section; otherwise, use weekly values.
(iii) Alternative to heat value or carbon content measurements. If you do not measure the higher heating value or carbon content of the flare gas at least weekly, determine the quantity of gas discharged to the flare separately for periods of routine flare operation and for periods of start-up, shutdown, or malfunction, and calculate the CO 2 emissions as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this section.
(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day.
(B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher heating value of the flare gas under normal operations may be estimated from historic data or engineering calculations.
(C) Calculate the CO 2 emissions using Equation Y-3 of this section.
(2) Calculate CH 4 using Equation Y-4 of this section.
(3) Calculate N 2 O emissions using Equation Y-5 of this section.
(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions from coke burn-off using the applicable methods described in paragraphs (c)(1) through (5) of this section.
(1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate and report CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic cracking units and traditional fluid coking units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Combustion Sources), or follow the requirements of paragraphs (c)(2) or (3) of this section.
(i) Calculate CO 2 emissions by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(ii) For catalytic cracking units whose process emissions are discharged through a combined stack with other CO 2 emissions ( e.g., co-mingled with emissions from a CO boiler) you must also calculate the other CO 2 emissions using the applicable methods for the applicable subpart ( e.g., subpart C of this part in the case of a CO boiler). Calculate the process emissions from the catalytic cracking unit or fluid coking unit as the difference in the CO 2 CEMS emissions and the calculated emissions associated with the additional units discharging through the combined stack.
(2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO 2 CEMS for the final exhaust stack, you must continuously or no less frequently than hourly monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels and calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section:
(i) Calculate the CO 2 emissions from each catalytic cracking unit and fluid coking unit using Equation Y-6 of this section.
(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using either Equation Y-7a or Equation Y-7b of this section.
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the combustion of these fuels or other materials following the requirements in subpart C and report those emissions by following the requirements of subpart C of this part.
(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO 2 CEMS for the final exhaust stack, comply with the requirements in paragraph (c)(3)(i) of this section or paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable.
(i) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, you must calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section, except that daily averages are allowed and the summation can be performed on a daily basis.
(ii) If you do not monitor at least daily the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, calculate the CO 2 emissions from each catalytic cracking unit and fluid coking unit using Equation Y-8 of this section.
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the combustion of these fuels or other materials following the requirements in subpart C of this part (General Stationary Fuel Combustion Sources) and report those emissions by following the requirements of subpart C of this part.
(4) Calculate CH 4 emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or equation Y-9 to this section.
(5) Calculate N 2 O emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or equation Y-10 to this section.
(d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.
(e) For catalytic reforming units, calculate the CO 2 emissions from coke burn-off using the applicable methods described in paragraphs (e)(1) through (3) of this section and calculate the CH 4 and N 2 O emissions using the methods described in paragraphs (c)(4) and (5) of this section, respectively.
(1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic reforming units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (e)(2) or (e)(3) of this section.
(2) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic reforming unit catalyst regenerator prior to the combustion of other fossil fuels, you must calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section.
(3) Calculate CO 2 emissions from the catalytic reforming unit catalyst regenerator using Equation Y-11 of this section.
(f) For on-site sulfur recovery plants and for sour gas sent off site for sulfur recovery, calculate and report CO 2 process emissions from sulfur recovery plants according to the requirements in paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus sulfur recovery plants, according to the requirements in paragraph (j) of this section regardless of the concentration of CO 2 in the vented gas stream. Combustion emissions from the sulfur recovery plant (e.g., from fuel combustion in the Claus burner or the tail gas treatment incinerator) must be reported under subpart C of this part (General Stationary Fuel Combustion Sources). For the purposes of this subpart, the sour gas stream for which monitoring is required according to paragraphs (f)(2) through (f)(5) of this section is not considered a fuel.
(1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part, you must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). You must monitor fuel use in the Claus burner, tail gas incinerator, or other combustion sources that discharge via the final exhaust stack from the sulfur recovery plant and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the sulfur recovery plant as the difference in the CO 2 CEMS emissions and the calculated combustion emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recovery plants must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C, or follow the requirements of paragraphs (f)(2) through (f)(5) of this section, or (for non-Claus sulfur recovery plants only) follow the requirements in paragraph (j) of this section to determine CO 2 emissions for the sulfur recovery plant.
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
(4) Calculate the CO 2 emissions from each on-site sulfur recovery plant and for sour gas sent off-site for sulfur recovery using Equation Y-12 of this section.
(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO 2 emissions calculated in paragraph (f)(4) of this section must be corrected to avoid double counting these emissions. You may use engineering estimates to perform this correction or assume that the corrected CO 2 emissions are 95 percent of the uncorrected value calculated using Equation Y-12 of this section.
(g) [Reserved]
(h) For asphalt blowing operations, calculate CO 2 and CH 4 emissions according to the requirements in paragraph (j) of this section regardless of the CO 2 and CH 4 concentrations or according to the applicable provisions in paragraphs (h)(1) and (h)(2) of this section.
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device, calculate CO 2 and CH 4 emissions using Equations Y-14 and Y-15 of this section, respectively.
(2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device, calculate CO 2 using either Equation Y-16a or Y-16b of this section and calculate CH 4 emissions using Equation Y-17 of this section, provided these emissions are not already included in the flare emissions calculated in paragraph (b) of this section or in the stationary combustion unit emissions required under subpart C of this part (General Stationary Fuel Combustion Sources).
(i) For each delayed coking unit, calculate the CH 4 emissions from delayed decoking operations (venting, draining, deheading, and coke-cutting) according to the requirements in paragraphs (i)(1) through (5) of this section.
(1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum) dimensions and typical coke drum outage at the end of the coking cycle using Equation Y-18a of this section.
(2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using equation Y-18b to this section.
(3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y-18c or Y-18d of this section, as appropriate, based on the measurement system available.
(4) Determine the typical mass of steam generated and released per decoking cycle using Equation Y-18e of this section.
(5) Calculate the CH 4 emissions from decoking operations at each delayed coking unit using equation Y-18f to this section.
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO 2 or greater than 0.5 percent by volume of CH 4 or greater than 0.01 percent by volume (100 parts per million) of N 2 O, calculate GHG emissions using Equation Y-19 of this section. You must also use Equation Y-19 of this section to calculate CH 4 emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas, and CO 2 and/or CH 4 emissions, as applicable, if you elected this method as an alternative to the methods in paragraph (f), (h), or (k) of this section.
(k) For uncontrolled blowdown systems, you must calculate CH 4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH 4 concentration or using Equation Y-20 of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device are considered to be controlled and are not required to estimate emissions under this paragraph (k).
(l) For equipment leaks, calculate CH 4 emissions using the method specified in either paragraph (l)(1) or (l)(2) of this section.
(1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS PB96-175401).
(2) Use Equation Y-21 of this section.
(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH 4 emissions using the applicable methods in paragraphs (m)(1) and (2) of this section.
(1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH 4 emissions from storage tanks that have a vapor-phase methane concentration of 0.5 volume percent or more using tank-specific methane composition data (from measurement data or product knowledge) and the emission estimation methods provided in AP 42, Section 7.1 (incorporated by reference, see § 98.7) or estimate CH 4 emissions from storage tanks using Equation Y-22 of this section.
(2) For storage tanks that process unstabilized crude oil, calculate CH 4 emissions from the storage of unstabilized crude oil using either tank-specific methane composition data (from measurement data or product knowledge) and direct measurement of the gas generation rate or by using Equation Y-23 of this section.
(3) You do not need to calculate CH 4 emissions from storage tanks that meet any of the following descriptions:
(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships;
(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere;
(iii) Bottoms receivers or sumps;
(iv) Vessels storing wastewater; or
(v) Reactor vessels associated with a manufacturing process unit.
(n) For crude oil, intermediate, or product loading operations for which the vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH 4 emissions from loading operations using vapor-phase methane composition data (from measurement data or process knowledge) and the emission estimation procedures provided in AP 42, Section 5.2 (incorporated by reference, see § 98.7). For loading operations in which the vapor-phase concentration of methane is less than 0.5 volume percent, you may assume zero methane emissions.
§ 98.254   Monitoring and QA/QC requirements.
(a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 emissions according to subpart C of this part or that are associated with stationary combustion sources must meet the applicable monitoring and QA/QC requirements in § 98.34.
(b) All gas flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than those subject to the requirements in paragraph (a) of this section shall be calibrated according to the procedures specified by the manufacturer, or according to the procedures in the applicable methods specified in paragraphs (c) through (g) of this section. In the case of gas flow meters, all gas flow meters must meet the calibration accuracy requirements in § 98.3(i). All gas flow meters, gas composition monitors, and heating value monitors must be recalibrated at the applicable frequency specified in paragraph (b)(1) or (b)(2) of this section.
(1) You must recalibrate each gas 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.
(2) You must recalibrate each gas composition monitor and heating value monitor according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, annually, or at the interval specified by the industry standard practice used.
(c) For flare or sour gas flow meters and gas flow meters used to comply with the requirements in § 98.253(j), operate, calibrate, and maintain the flow meter according to one of the following. You may use the procedures specified by the flow meter manufacturer, or a method published by a consensus-based standards organization. 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 ).
(d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic or direct mass spectrometer analysis of the gas may be used, provided that the gas chromatograph or mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph or mass spectrometer are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).
(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).
(e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the gas may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(1) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see § 98.7).
(2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see § 98.7).
(3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see § 98.7).
(4) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see § 98.7).
(5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see § 98.7).
(f) For gas flow meters used to comply with the requirements in § 98.253(c)(2)(ii), install, operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 63.1572(c) and the following requirements.
(1) Locate the flow monitor at a site that provides representative flow rates. Avoid locations where there is swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
(2) [Reserved]
(3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in § 98.6).
(g) For exhaust gas CO 2 /CO/O 2 composition monitors used to comply with the requirements in § 98.253(c)(2), install, operate, calibrate, and maintain exhaust gas composition monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 63.1572(c) or according to the manufacturer's specifications and requirements.
(h)-(i) [Reserved]
(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.
(k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer's instructions.
(l) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
§ 98.255   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For stationary combustion sources, use the missing data procedures in subpart C of this part.
(b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(c) For missing CO 2 , CO, O 2 , CH 4 , or N 2 O concentrations, gas flow rate, and percent moisture, the substitute data values shall be the best available estimate(s) of the parameter(s), based on all available process data (e.g., processing rates, operating hours, etc.). The owner or operator shall document and keep records of the procedures used for all such estimates.
(d) [Reserved]
§ 98.256   Data reporting requirements.
In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (q) of this section.
(a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources).
(b)-(d) [Reserved]
(e) For flares, owners and operators shall report:
(1) The flare ID number (if applicable).
(2) A description of the type of flare (steam assisted, air-assisted).
(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery system.
(4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each flare, expressed in metric tons of each pollutant emitted.
(5) A description of the method used to calculate the CO 2 emissions for each flare (e.g., reference section and equation number).
(6) If you use Equation Y-1a in § 98.253, an indication of whether daily or weekly measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), or the annual mass of flare gas combusted (in kg/yr).
(7) If you use Equation Y-1b of § 98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO 2 concentration (volume or mole percent), the number of carbon containing compounds other than CO 2 in the flare gas stream, and for each of the carbon containing compounds other than CO 2 in the flare gas stream:
(i) The annual average concentration of the compound (volume or mole percent).
(ii) [Reserved]
(8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in million (MM) scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted and the annual average higher heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia.
(9) If you use Equation Y-3 of § 98.253, the number of SSM events exceeding 500,000 scf/day.
(10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of § 98.253.
(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted.
(5) A description of the method used to calculate the CO 2 emissions for each unit (e.g., reference section and equation number).
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS (unadjusted to remove CO 2 combustion emissions associated with additional units, if present) and the process CO 2 emissions as calculated according to § 98.253(c)(1)(ii). Report the CO 2 annual emissions associated with sources other than those from the coke burn-off in accordance with the applicable subpart ( e.g., subpart C of this part in the case of a CO boiler).
(7) If you use Equation Y-6 of § 98.253, the annual average exhaust gas flow rate, %CO 2 , and %CO.
(8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O 2 , %O oxy , %CO 2 , and %CO.
(9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %N 2,oxy , and %N 2,exhaust.
(10) If you use Equation Y-8 of § 98.253, the basis for the value of the average carbon content of coke.
(11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH 4 emissions. If you use a unit-specific emission factor for CH 4 , report the basis for the factor.
(12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N 2 O emissions. If you use a unit-specific emission factor for N 2 O, report the basis for the factor.
(13) If you use Equation Y-11 of § 98.253, the number of regeneration cycles or measurement periods during the reporting year and the average coke burn-off quantity per cycle or measurement period.
(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c).
(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO 2 , CH 4 , and N 2 O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equation input parameters specified in paragraphs (f)(7) through (f)(13) of this section.
(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:
(1) The plant ID number (if applicable).
(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO 2 annual emissions for the sulfur recovery plant (e.g., CO 2 CEMS, Equation Y-12, or process vent method in § 98.253(j)).
(3) The calculated CO 2 annual emissions for each on-site sulfur recovery plant, expressed in metric tons. The calculated annual CO 2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.
(4) [Reserved]
(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for CO 2 emissions in the tail gas was used in Equation Y-12 of § 98.253. If so, then report:
(i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit-specific correction was used, report the value of the correction and the approach used.
(ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.
(A) The annual volume of recycled tail gas (in scf/year).
(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas).
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to § 98.253(f)(1). Report the CO 2 annual emissions associated with fuel combustion in accordance with subpart C of this part (General Stationary Fuel Combustion Sources).
(7) If you use the process vent method in § 98.253(j) for a non-Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section.
(i) [Reserved]
(j) For asphalt blowing operations, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in metric tons asphalt/stream day.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit.
(4) The calculated annual CO 2 and CH 4 emissions for each unit, expressed in metric tons of each pollutant emitted.
(5) If you use Equation Y-14 of § 98.253, the basis for the CO 2 emission factor used.
(6) If you use Equation Y-15 of § 98.253, the basis for the CH 4 emission factor used.
(7) If you use Equation Y-16a of § 98.253, the basis for the carbon emission factor used.
(8) If you use Equation Y-16b of § 98.253, the basis for the CO 2 emission factor used and the basis for the carbon emission factor used.
(9) If you use Equation Y-17 of § 98.253, the basis for the CH 4 emission factor used.
(10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section.
(k) For each delayed coking unit, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in bbl/stream day.
(3) Annual quantity of coke produced in the unit during the reporting year, in metric tons.
(4) The calculated annual CH 4 emissions (in metric tons of CH 4 ) for the delayed coking unit.
(5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit.
(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using equation Y-18a to § 98.253). If you use mass measurements from company records to determine the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle, you must also report:
(i) Internal height of delayed coking unit vessel (feet) for each delayed coking unit.
(ii) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed ( i.e. , coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates for each delayed coking unit.
(7) An indication of the method used to estimate the average temperature of the coke bed, T initial (overhead temperature and Equation Y-18c of this subpart or pressure correlation and Equation Y-18d of this subpart).
(8) An indication of whether a unit-specific methane emissions factor or the default methane emission factor was used for the delayed coking unit.
(l) For each process vent subject to § 98.253(j), the owner or operator shall report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated with the emissions.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.
(4) The calculated annual CO 2 , CH 4 , and N 2 O emissions for each vent, expressed in metric tons of each pollutant emitted.
(5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indication of the measurement or estimation method, and for intermittent vents, the number of venting events and the cumulative venting time.
(m) For uncontrolled blowdown systems, the owner or operator shall report:
(1) An indication of whether the uncontrolled blowdown emission are reported under § 98.253(k) or § 98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems.
(2) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for uncontrolled blowdown systems.
(3) For uncontrolled blowdown systems reporting under § 98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown systems.
(4) For uncontrolled blowdown systems reporting under § 98.253(j), the relevant information required under paragraph (l)(5) of this section.
(n) For equipment leaks, the owner or operator shall report:
(1) The cumulative CH 4 emissions (in metric tons of each pollutant emitted) for all equipment leak sources.
(2) The method used to calculate the reported equipment leak emissions.
(3) The number of each type of emission source listed in Equation Y-21 of this subpart at the facility.
(o) For storage tanks, the owner or operator shall report:
(1) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for all storage tanks, except for those used to process unstabilized crude oil.
(2) For storage tanks other than those processing unstabilized crude oil:
(i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude ( i.e., either AP 42, Section 7.1 (incorporated by reference, see § 98.7), or Equation Y-22 of this section).
(ii) [Reserved]
(3) The cumulative CH 4 emissions (in metric tons of CH 4 ) for storage tanks used to process unstabilized crude oil or a statement that the facility did not receive any unstabilized crude oil during the reporting year.
(4) For storage tanks that process unstabilized crude oil:
(i) The method used to calculate the reported unstabilized crude oil storage tank emissions.
(ii)-(iv) [Reserved]
(v) The basis for the mole fraction of CH 4 in vent gas from unstabilized crude oil storage tanks.
(vi) If you did not use Equation Y-23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH 4 emissions for storage tanks used to process unstabilized crude oil.
(5)-(7) [Reserved]
(p) For loading operations, the owner or operator shall report:
(1) The cumulative annual CH 4 emissions (in metric tons of each pollutant emitted) for loading operations.
(2) The types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, etc.) in which each type of material is loaded.
(3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).
(q) Name of each method listed in § 98.254 or a description of manufacturer's recommended method used to determine a measured parameter.
§ 98.257   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.
(a) The records of all parameters monitored under § 98.255. If you comply with the combustion methodology in § 98.252(a), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in § 98.37 and you must keep records of the annual average flow calculations.
(b) 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 (b)(1) through (73) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (73) of this section.
(1) Volume of flare gas combusted during measurement period (scf) (Equation Y-1b of § 98.253).
(2) Mole percent CO 2 concentration in the flare gas stream during the measurement period (mole percent) (Equation Y-1b).
(3) Mole percent concentration of compound “x” in the flare gas stream during the measurement period (mole percent) (Equation Y-1b).
(4) Carbon mole number of compound “x” in the flare gas stream during the measurement period (mole carbon atoms per mole compound) (Equation Y-1b).
(5) Molar volume conversion factor (scf per kg-mole) (Equation Y-1b).
(6) Annual volume of flare gas combusted for each flare during normal operations from company records (million (MM) standard cubic feet per year, MMscf/year) (Equation Y-3 of § 98.253).
(7) Higher heating value for fuel gas or flare gas for each flare from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y-3).
(8) Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations (scf) (Equation Y-3).
(9) Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/kg-mole) (Equation Y-3).
(10) Molar volume conversion factor (scf per kg-mole) (Equation Y-3).
(11) Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas) (Equation Y-3).
(12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas) (Equation Y-4 of § 98.253).
(13) Annual throughput of unit from company records for each catalytic cracking unit or fluid coking unit (barrels/year) (Equation Y-8 of § 98.253).
(14) Coke burn-off factor from engineering calculations (default for catalytic cracking units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y-8).
(15) Carbon content of coke based on measurement or engineering estimate (kg C per kg coke) (Equation Y-8).
(16) Value of unit-specific CH 4 emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(4)).
(17) Annual activity data ( e.g. , input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(4)).
(18) Value of unit-specific N 2 O emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(5)).
(19) Annual activity data ( e.g. , input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(5)).
(20) Carbon content of coke based on measurement or engineering estimate (default = 0.94) (kg C per kg coke) (Equation Y-11 of § 98.253).
(21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site for sulfur recovery in the year (scf/year) (Equation Y-12 of § 98.253).
(22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kg-mole C/kg-mole gas) (Equation Y-12).
(23) Molar volume conversion factor for sour gas sent off site (scf per kg-mole) (Equation Y-12).
(24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite sulfur recovery plant (scf/year) (Equation Y-12).
(25) Mole fraction of carbon in the sour gas fed to the onsite sulfur recovery plant (kg-mole C/kg-mole gas) (Equation Y-12).
(26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg-mole) (Equation Y-12).
(27)-(31)
(32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-14 of § 98.253).
(33) Emission factor for CO 2 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CO 2 /MMbbl asphalt blown) (Equation Y-14).
(34) Emission factor for CH 4 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CH 4 /MMbbl asphalt blown) (Equation Y-15 of § 98.253).
(35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y-16a of § 98.253).
(36) Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown) (Equation Y-16a).
(37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-16b of § 98.253).
(38) Emission factor for CO 2 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CO 2 /MMbbl asphalt blown) (Equation Y-16b).
(39) Carbon emission factor from asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y-16b).
(40) Emission factor for CH 4 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CH 4 /MMbbl asphalt blown) (Equation Y-17 of § 98.253).
(41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) from company records or calculated using Equation Y-18a of this subpart (Equations Y-18a, Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(42) Internal height of delayed coking unit vessel (feet) (Equation Y-18a in § 98.253) for each delayed coking unit.
(43) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed ( i.e., coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates (Equation Y-18a in § 98.253) for each delayed coking unit.
(44) Diameter of delayed coking unit vessel (feet) (Equations Y-18a and Y-18b in § 98.253) for each delayed coking unit.
(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting or draining (metric ton/cycle) (equations Y-18b and Y-18e to § 98.253) for each delayed coking unit.
(46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates (equation Y-18b to § 98.253) for each delayed coking unit.
(47) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equations Y-18e and Y-18f in § 98.253) for each delayed coking unit.
(48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere ( °F) (Equations Y-18c, Y-18d, and Y-18e in § 98.253) for each delayed coking unit.
(49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y-18c in § 98.253) for each delayed coking unit.
(50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y-18d in § 98.253) for each delayed coking unit.
(51) Methane emission factor for delayed coking unit (kilograms CH 4 per metric ton of steam; kg CH 4 /mt steam) (Equation Y-18f in § 98.253) for each delayed coking unit.
(52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y-18f in § 98.253) for each delayed coking unit.
(53) Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining (equation Y-18b to § 98.253) for each delayed coking unit.
(54)-(56) [Reserved]
(57) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-20 of § 98.253).
(58) Molar volume conversion factor (scf per kg-mole) (Equation Y-20).
(59) Methane emission factor for uncontrolled blown systems (scf CH 4 /MMbbl) (Equation Y-20).
(60) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-22 of § 98.253).
(61) Quantity of unstabilized crude oil received at the facility (MMbbl/year) (Equation Y-23 of § 98.253).
(62) Pressure differential from the previous storage pressure to atmospheric pressure (psi) (Equation Y-23).
(63) Average mole fraction of CH 4 in vent gas from the unstabilized crude oil storage tanks from facility measurements (kg-mole CH 4 /kg-mole gas) (Equation Y-23).
(64) Molar volume conversion factor (scf per kg-mole) (Equation Y-23).
(65) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(66) Saturation factor specified in § 98.253(n), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(67) True vapor pressure of liquid loaded, for each liquid loaded to each vessel (psia) (methods specified in § 98.253(n)).
(68) Molecular weight of vapors (lb per lb-mole), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(69) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees Rankine) (methods specified in § 98.253(n)).
(70) Total loading loss (without efficiency correction), for each liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods specified in § 98.253(n)).
(71) Overall emission control system reduction efficiency, including the vapor collection system efficiency and the vapor recovery or destruction efficiency (enter zero if no emission controls), for each liquid loaded to each vessel (percent) (methods specified § 98.253(n)).
(72) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to each vessel (percent by volume) (methods specified in § 98.253(n)).
(73) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon per year) (methods specified in § 98.253(n)).
§ 98.258   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.260   Definition of the source category.
The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply source with acid.
§ 98.261   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.262   GHGs to report.
(a) You must report CO 2 process emissions from each wet-process phosphoric acid process line.
(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 following the requirements of subpart C of this part.
§ 98.263   Calculating GHG emissions.
You must calculate and report the annual process CO 2 emissions from each wet-process phosphoric acid process line using the procedures in either paragraph (a) or (b) of this section.
(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(b) Calculate and report under this subpart the process CO 2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.
(1) Calculate the annual CO 2 mass emissions from each wet-process phosphoric acid process line using the methods in paragraphs (b)(1)(i) or (ii) of this section, as applicable.
(i) If your process measurement provides the inorganic carbon content of phosphate rock as an output, calculate and report the process CO 2 emissions from each wet-process phosphoric acid process line using Equation Z-1a of this section:
(ii) If your process measurement provides the CO 2 content directly as an output, calculate and report the process CO 2 emissions from each wet-process phosphoric acid process line using Equation Z-1b of this section:
(2) You must determine the total emissions from the facility using Equation Z-2 of this section:
(c) If GHG emissions from a wet-process phosphoric acid process line are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.
§ 98.264   Monitoring and QA/QC requirements.
(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.
(b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC.
(c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes (such as sales records) or you can use data from existing monitoring equipment that is used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63.
§ 98.265   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 must be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of the inorganic carbon content or CO 2 content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z-1 of this subpart. Alternatively, you must determine a substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents or CO 2 contents of phosphate rock of origin i (see Equation Z-1a or Z-1b of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents or CO 2 contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents or CO 2 contents for phosphate rock of origin i obtained after the missing data period.
(b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best available estimate based on all available process data or data used for accounting purposes.
§ 98.266   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 (f) of this section.
(a) Annual phosphoric acid production, by origin of the phosphate rock (tons).
(b) Annual phosphoric acid production capacity (tons).
(c) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate rock from monthly records (percent by weight, expressed as a decimal fraction).
(d) Annual phosphate rock consumption from monthly measurement records by origin (tons).
(e) If you use a CEMS to measure CO 2 emissions, then you must report the information in paragraphs (e)(1) and (e)(2) of this section.
(1) The identification number of each wet-process phosphoric acid process line.
(2) The annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation Methodology.
(f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (9) of this section.
(1) Identification number of each wet-process phosphoric acid process line.
(2) Annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) as calculated by either Equation Z-1a or Equation Z-1b of this subpart.
(3) Annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line.
(4) Method used to estimate any missing values of inorganic carbon content or carbon dioxide content of phosphate rock for each wet-process phosphoric acid process line.
(5) [Reserved]
(6) [Reserved]
(7) Number of wet-process phosphoric acid process lines.
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO 2 contents of the phosphate rock (months).
(9) Annual process CO 2 emissions from phosphoric acid production facility (metric tons).
§ 98.267   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 (d) of this section for each wet-process phosphoric acid production facility.
(a) Monthly mass of phosphate rock consumed by origin (tons).
(b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine).
(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin.
(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 (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (4) of this section.
(1) Inorganic carbon content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation Z-1a of § 98.263).
(2) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1a).
(3) Carbon dioxide content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction) (Equation Z-1b of § 98.263).
(4) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1b).
§ 98.268   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.270   Definition of source category.
(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.
(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section:
(1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).
(2) Chemical recovery combustion units at sulfite facilities.
(3) Chemical recovery combustion units at stand-alone semichemical facilities.
(4) Pulp mill lime kilns at kraft and soda facilities.
(5) Systems for adding makeup chemicals (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills.
§ 98.271   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.272   GHGs to report.
You must report the emissions listed in paragraphs (a) through (f) of this section:
(a) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each kraft or soda chemical recovery furnace.
(b) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each sulfite chemical recovery combustion unit.
(c) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each stand-alone semichemical chemical recovery combustion unit.
(d) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each kraft or soda pulp mill lime kiln.
(e) CO 2 emissions from addition of makeup chemicals (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills.
(f) CO 2 , CH 4 , and N 2 O combustion emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
§ 98.273   Calculating GHG emissions.
(a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (a)(1) through (4) of this section. CH4 and N2O emissions must be calculated as the sum of emissions from combustion of fuels and combustion of biomass in spent liquor solids.
(1) Calculate CO 2 emissions from fuel combustion using direct measurement of fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO 2 emissions if the respective monitoring and QA/QC requirements described in § 98.34 are met.
(2) Calculate CH 4 and N 2 O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c).
(3) Calculate biogenic CO 2 emissions and emissions of CH 4 and N 2 O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default emissions factors, according to equation AA-1 to this section:
(4) Calculate biogenic CO 2 emissions from combustion of biomass (other than spent liquor solids) with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e).
(b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (b)(1) through (5) of this section:
(1) Calculate CO 2 emissions from fuel combustion using direct measurement of fuels consumed and default emissions factors according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO 2 emissions if the respective monitoring and QA/QC requirements described in § 98.34 are met.
(2) Calculate CH 4 and N 2 O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c).
(3) Calculate biogenic CO 2 emissions using measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids, according to equation AA-2 to this section:
(4) Calculate biogenic CO 2 emissions from combustion of biomass (other than spent liquor solids) with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e).
(c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (c)(1) through (4) of this section:
(1) Calculate CO 2 emissions from fuel combustion using direct measurement of fuels consumed and default HHV and default emissions factors, according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO 2 emissions if the respective monitoring and QA/QC requirements described in § 98.34 are met.
(2) Calculate CH 4 and N 2 O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in § 98.33(c); use the default HHV listed in table C-1 to subpart C of this part and the default CH 4 and N 2 O emissions factors listed in table AA-2 to this subpart.
(3) Biogenic CO 2 emissions from conversion of CaCO 3 to CaO are included in the biogenic CO 2 estimates calculated for the chemical recovery furnace in paragraph (a)(3) of this section.
(4) Calculate biogenic CO 2 emissions from combustion of biomass with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e).
(d) For makeup chemical use, you must calculate CO 2 emissions by using direct or indirect measurement of the quantity of chemicals added and ratios of the molecular weights of CO 2 and the makeup chemicals, according to equation AA-3 to this section:
§ 98.274   Monitoring and QA/QC requirements.
(a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request.
(b) Fuel properties needed to perform the calculations in Equations AA-1 and AA-2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section.
(1) High heat values of black liquor must be determined no less than annually using T684 om-06 Gross Heating Value of Black Liquor, TAPPI (incorporated by reference, see § 98.7). If measurements are performed more frequently than annually, then the high heat value used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.
(2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i) Measure the mass of spent liquor solids annually (or more frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference in § 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.
(ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit.
(3) Carbon analyses for spent pulping liquor must be determined no less than annually using 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). If measurements using ASTM D5373-08 are performed more frequently than annually, then the spent pulping liquor carbon content used in Equation AA-2 of this subpart must be based on the average of the representative measurements made during the year.
(c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.
(d) Records must be made available upon request for verification of the calculations and measurements.
§ 98.275   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 (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section:
(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual measurements are determined to be invalid.
(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Alternatively, records of the daily spent liquor solids firing rate obtained to comply with § 63.866(c)(1) of this chapter may be used, adjusting for the duration of the missing measurements, as appropriate.
(c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates.
§ 98.276   Data reporting requirements.
(a) Annual emissions of CO 2 , biogenic CO 2 , CH 4 , and N 2 O (metric tons per year).
(b) [Reserved]
(c) Basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system).
(d) [Reserved]
(e) The default emission factor for CO 2 , CH 4 , or N 2 O, used in Equation AA-1 of this subpart (kg CO 2 , CH 4 , or N 2 O per mmBtu).
(f)-(i) [Reserved]
(j) Annual steam purchases (pounds of steam per year).
(k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total.
(l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and (2) of this section.
(1) The quantity of calcium oxide (CaO) produced (metric tons).
(2) The percent of annual heat input, individually for each fossil fuel type.
§ 98.277   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (g) of this section.
(a) GHG emission estimates (including separate estimates of biogenic CO 2 ) for each emissions source listed under § 98.270(b).
(b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities.
(c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.
(d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for determining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system). If an online measurement system is used, you must retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements.
(e) Annual steam purchases.
(f) Annual quantities of makeup chemicals used.
(g) 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 (g)(1) through (27) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (g)(1) through (27) of this section.
(1) Mass of the solid fuel combusted (tons/year) (Equation C-1 of § 98.33).
(2) Volume of the liquid fuel combusted (gallons/year) (Equation C-1).
(3) Volume of the gaseous fuel combusted (scf/year) (Equation C-1).
(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).
(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).
(6) Mass of the solid fuel combusted (tons/year) (Equation C-2a of § 98.33).
(7) Volume of the liquid fuel combusted (gallons/year) (Equation C-2a).
(8) Volume of the gaseous fuel combusted (scf/year) (Equation C-2a).
(9) Annual mass of the solid fuel combusted (short tons/year) (Equation C-3 of § 98.33).
(10) Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3).
(11) Annual volume of the liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33).
(12) Annual average carbon content of the liquid fuel (kg C per gallon of fuel) (Equation C-4).
(13) Annual volume of the gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33).
(14) Annual average carbon content of the gaseous fuel (kg C per kg of fuel) (Equation C-5).
(15) Annual average molecular weight of the gaseous fuel (kg/kg-mole) (Equation C-5).
(16) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5).
(17) Identify if you will use the default high heat value from Table C-1 of subpart C of this part, or actual HHV data (Equation C-8 of § 98.33).
(18) High heat value of the fuel (mmBTU/tons) (Equation C-8).
(19) High heat value of the fuel (mmBTU/gallons) (Equation C-8).
(20) High heat value of the fuel (mmBTU/scf) (Equation C-8).
(21) Mass of spent liquor solids combusted from each chemical recovery furnace located at a kraft or soda facility, in short tons in year, determined according to § 98.274(b) (tons/year) (Equation AA-1 of § 98.273).
(22) Annual high heat value of the spent liquor solids from each chemical recovery furnace located at a kraft or soda facility determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(23) Annual high heat value of the spent liquor solids from each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(24) Mass of the spent liquor solids combusted in short tons per year determined according to § 98.274(b) (tons/year) (Equation AA-2 of § 98.273).
(25) Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction (e.g., 95% = 0.95)) (Equation AA-2).
(26) Make-up quantity of CaCO 3 used for the reporting year (metric tons/year) (Equation AA-3 of § 98.273).
(27) Make-up quantity of Na 2 CO 3 used for the reporting year metric tons/year) (Equation AA-3).
§ 98.278   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.280   Definition of the source category.
Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.
§ 98.281   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.282   GHGs to report.
You must report:
(a) CO 2 process emissions from all silicon carbide process units or furnaces combined.
(b) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
§ 98.283   Calculating GHG emissions.
You must calculate and report the combined annual process CO 2 emissions from all silicon carbide process units and production furnaces using the procedures in either paragraph (a) or (b) of this section.
(a) Calculate and report under this subpart the combined annual process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(b) Calculate and report under this subpart the combined annual process CO 2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.
(1) Use Equation BB-1 of this section to calculate the facility-specific emissions factor for determining CO 2 emissions. The carbon content must be measured monthly and used to calculate a monthly CO 2 emissions factor:
(2) Calculate annual CO 2 process emissions from the silicon carbide production facility according to Equation BB-2 of this section:
(c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.
§ 98.284   Monitoring and QA/QC requirements.
(a) You must measure your consumption of petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of monthly petroleum coke consumption measurements.
(c) For CO 2 process emissions, you must determine the monthly carbon content of the petroleum coke using reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7) and 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).
(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176-89 and 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).
§ 98.285   Procedures for estimating missing data.
For the petroleum coke input procedure in § 98.283(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, 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 the paragraphs (a) and (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 monthly carbon content of petroleum coke, the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of the monthly petroleum coke consumption, the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).
§ 98.286   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraph (a) or (b) of this section, and paragraph (c) of this section, as applicable for each silicon carbide production facility.
(a) If a CEMS is used to measure process CO 2 emissions, you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in § 98.36 and the information listed in this paragraph (a):
(1) Annual consumption of petroleum coke (tons).
(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).
(b) If a CEMS is not used to measure process CO 2 emissions, you must report the information in paragraph (b)(1) through (8) of this section for all silicon carbide process units or production furnaces combined:
(1) [Reserved]
(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).
(4) [Reserved]
(5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method.
(6) [Reserved]
(7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a decimal fraction).
(8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).
(c) If methane abatement technology is used at the silicon carbide production facility, you must report the information in paragraphs (c)(1) through (3) of this section. Upon reporting this information once in an annual report, you are not required to report this information again unless the information changes during a reporting year, in which case, the reporter must include any updates in the annual report for the reporting year in which the change occurred.
(1) Type of methane abatement technology used on each silicon carbide process unit or production furnace, and date of installation for each.
(2) Methane destruction efficiency for each methane abatement technology (percent destruction). You must either use the manufacturer's specified destruction efficiency or the destruction efficiency determined via a performance test. If you report the destruction efficiency determined via a performance test, you must also report the test method that was used during the performance test.
(3) Percentage of annual operating hours that methane abatement technology was in use for all silicon carbide process units or production furnaces combined.
§ 98.287   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 (d) of this section for each silicon carbide production facility.
(1) Records of all petroleum coke purchases.
(2) Annual operating hours.
(b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b):
(1) Records of all analyses and calculations conducted for reported data listed in § 98.286(b).
(2) Records of all petroleum coke purchases.
(3) Annual operating hours.
(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) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) and (2) of this section.
(1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method (percent by weight expressed as a decimal fraction) (Equation BB-1 of § 98.283).
(2) Petroleum coke consumption in month (tons) (Equation BB-2 of § 98.283).
(d) Records of all information reported as required under § 98.286(c).
§ 98.288   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.290   Definition of the source category.
(a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a)(1) through (3) of this section:
(1) Calcining trona.
(2) Calcining sodium sesquicarbonate.
(3) Using a liquid alkaline feedstock process that directly produces CO 2 .
(b) In the context of the soda ash manufacturing sector, “calcining” means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate.
§ 98.291   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.292   GHGs to report.
You must report:
(a) CO 2 process emissions from each soda ash manufacturing line combined.
(b) CO 2 combustion emissions from each soda ash manufacturing line.
(c) CH 4 and N 2 O combustion emissions from each soda ash manufacturing line. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
(d) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than soda ash manufacturing lines. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
§ 98.293   Calculating GHG emissions.
You must calculate and report the annual process CO 2 emissions from each soda ash manufacturing line using the procedures specified in paragraph (a) or (b) of this section.
(a) For each soda ash manufacturing line that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(b) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process CO 2 emissions from the soda ash manufacturing line by using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) of this section; and the combustion CO 2 emissions using the procedure in paragraph (b)(4) of this section.
(1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO 2 process emissions from each manufacturing line that calcines trona to produce soda ash:
(3) Site-specific emission factor method. Use Equations CC-3, CC-4, and CC-5 of this section to determine annual CO 2 process emissions from manufacturing lines that use the liquid alkaline feedstock process to produce soda ash. You must conduct an annual performance test and measure CO 2 emissions and flow rates at all process vents from the mine water stripper/evaporator for each manufacturing line and calculate CO 2 emissions as described in paragraphs (b)(3)(i) through (b)(3)(iv) of this section.
(i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour.
(ii) Using the test data, you must calculate the hourly CO 2 emission rate using Equation CC-3 of this section:
(iii) Using the test data, you must calculate a CO 2 emission factor for the process using Equation CC-4 of this section:
(iv) You must calculate annual CO 2 process emissions from each manufacturing line using Equation CC-5 of this section:
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 , CH 4 , and N 2 O emissions in the soda ash manufacturing line according to the applicable requirements in subpart C.
§ 98.294   Monitoring and QA/QC requirements.
Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section should be used for the procedure chosen.
(a) If you determine your emissions using § 98.293(b)(2) (Equation CC-1 of this subpart) you must:
(1) Determine the monthly inorganic carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). ASTM E359-00(Reapproved 2005) e1 is designed to measure the total alkalinity in soda ash not in trona. The modified method referred to above adjusts the regular ASTM method to express the results in terms of trona. Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.
(2) Measure the mass of trona input to each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.
(3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed.
(b) If you calculate CO 2 process emissions based on soda ash production (§ 98.293(b)(2) Equation CC-2 of this subpart), you must:
(1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.
(2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes.
(3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced.
(c) If you calculate CO 2 emissions using the site-specific emission factor method in § 98.293(b)(3), you must:
(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.
(2) Sample the stack gas and conduct three emissions test runs of 1 hour each.
(3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate. 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 (c)(3)(i) through (c)(3)(iii) of this section.
(i) Analysis of samples, determination of emissions, and raw data.
(ii) All information and data used to derive the emissions factor(s).
(iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each test and document how it was determined.
(4) You must also determine the annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter).
§ 98.295   Procedures for estimating missing data.
For the emission calculation methodologies in § 98.293(b)(2) and (b)(3), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., inorganic carbon content values, 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 the paragraphs (a) through (d) of this section. You must document and keep records of the procedures used for all such missing value estimates.
(a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following the missing data incident. If no quality-assured data on inorganic carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes.
(c) For each missing value collected during the performance test (hourly CO 2 concentration, stack gas volumetric flow rate, or average process vent flow from mine water stripper/evaporator during performance test), you must repeat the annual performance test following the calculation and monitoring and QA/QC requirements under §§ 98.293(b)(3) and 98.294(c).
(d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the meter can measure.
§ 98.296   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 appropriate for each soda ash manufacturing facility.
(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required under § 98.36 and the following information in this paragraph (a):
(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).
(2) Annual production of soda ash for each manufacturing line (tons).
(3) Annual production capacity of soda ash for each manufacturing line (tons).
(4) Identification number of each manufacturing line.
(b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b):
(1) Identification number of each manufacturing line.
(2) Annual process CO 2 emissions from each soda ash manufacturing line (metric tons).
(3) Annual production of soda ash for each manufacturing line (tons).
(4) Annual production capacity of soda ash for each manufacturing line (tons).
(5)-(7) [Reserved]
(8) Whether CO 2 emissions for each manufacturing line were calculated using a trona input method as described in Equation CC-1 of this subpart, a soda ash output method as described in Equation CC-2 of this subpart, or a site-specific emission factor method as described in Equations CC-3 through CC-5 of this subpart.
(9) Number of manufacturing lines located used to produce soda ash.
(10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§ 98.293(b)(3)) to estimate emissions then you must report the following relevant information for each manufacturing line or stack:
(i) Stack gas volumetric flow rate during performance test (dscfm).
(ii) Hourly CO 2 concentration during performance test (percent CO 2 ).
(iii) CO 2 emission factor (metric tons CO 2 /metric tons of process vent flow from mine water stripper/evaporator).
(iv) CO 2 mass emission rate during performance test (metric tons/hour).
(v) Average process vent flow from mine water stripper/evaporator during performance test (pounds/hour).
(vi) Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour).
(11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11):
(i) Trona or soda ash (number of months).
(ii) Inorganic carbon contents of trona or soda ash (weeks).
(iii) Process vent flow rate from mine water stripper/evaporator (number of months).
§ 98.297   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 for each soda ash manufacturing line.
(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology specified in subpart C of this part and the information listed in this paragraph (a):
(1) Monthly production of soda ash (tons)
(2) Monthly consumption of trona or liquid alkaline feedstock (tons)
(3) Annual operating hours (hours).
(b) If a CEMS is not used to measure emissions, then you must retain records for the information listed in this paragraph (b):
(1) Records of all analyses and calculations conducted for determining all reported data as listed in § 98.296(b).
(2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in § 98.294(b) (percent by weight expressed as a decimal fraction).
(3) Annual operating hours for each manufacturing line used to produce soda ash (hours).
(4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash production measurements including, but not limited to, calibration of weighing equipment 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.
(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method to estimate emissions (§ 98.293(b)(3)) then you must also retain the following relevant information:
(i) Records of performance test results.
(ii) You must document the procedures used to ensure the accuracy of the annual average vent flow measurements including, but not limited to, calibration of flow rate 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.
(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 (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (4) of this section
(1) Inorganic carbon content in trona input, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-1 of § 98.293).
(2) Mass of trona input in month (tons) (Equation CC-1).
(3) Inorganic carbon content in soda ash output, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-2 of § 98.293).
(4) Mass of soda ash output in month (tons) (Equation CC-2).
§ 98.298   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.300   Definition of the source category.
(a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing fluorinated GHGs, including but not limited to sulfur hexafluoride (SF 6 ) and perfluorocarbons (PFCs), used within an electric power system. Electric transmission and distribution equipment and servicing inventory includes, but is not limited to:
(1) Gas-insulated substations.
(2) Circuit breakers.
(3) Switchgear, including closed-pressure and hermetically sealed-pressure switchgear and gas-insulated lines containing fluorinated GHGs, including but not limited to SF 6 and PFCs.
(4) Gas containers such as pressurized cylinders.
(5) Gas carts.
(6) Electric power transformers.
(7) Other containers of fluorinated GHG, including but not limited to SF 6 and PFCs.
(b) [Reserved]
§ 98.301   Reporting threshold.
(a) You must report GHG emissions under this subpart if you are an electric power system as defined in § 98.308 and your facility meets the requirements of § 98.2(a)(1). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO 2 e per year emission threshold in table A-3 to subpart A to this part, you must calculate emissions of each fluorinated GHG that is a component of a reportable insulating gas and then sum the emissions of each fluorinated GHG resulting from the use of electrical transmission and distribution equipment for threshold applicability purposes using equation DD-1 to this section.
(b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in table A-3 or A-4 to subpart A of this part is not required to report emissions under subpart DD of this part unless the total estimated emissions of fluorinated GHGs that are components of reportable insulating gases, as calculated in equation DD-2 to this section, equals or exceeds 25,000 tons CO 2 e.
§ 98.302   GHGs to report.
You must report emissions of each fluorinated GHG, including but not limited to SF 6 and PFCs, from your facility (including emissions from fugitive equipment leaks, installation, servicing, equipment decommissioning and disposal, and from storage cylinders) resulting from the transmission and distribution servicing inventory and equipment listed in § 98.300(a), except you are not required to report emissions of fluorinated GHGs that are components of insulating gases whose weighted average GWPs, as calculated in equation DD-3 to this section, are less than or equal to one. For acquisitions of equipment containing or insulated with fluorinated GHGs, you must report emissions from the equipment after the title to the equipment is transferred to the electric power transmission or distribution entity.
§ 98.303   Calculating GHG emissions.
(a) Calculating GHG emissions. Calculate the annual emissions of each fluorinated GHG that is a component of any reportable insulating gas using the mass-balance approach in equation DD-4 to this section:
(b) Nameplate capacity adjustments. Users of closed-pressure electrical equipment with a voltage capacity greater than 38 kV may measure and adjust the nameplate capacity value specified by the equipment manufacturer on the nameplate attached to that equipment, or within the equipment manufacturer's official product specifications, by following the requirements in paragraphs (b)(1) through (10) of this section. Users of other electrical equipment are not permitted to adjust the nameplate capacity value of the other equipment.
(1) If you elect to measure the nameplate capacity value(s) of one or more pieces of electrical equipment with a voltage capacity greater than 38 kV, you must measure the nameplate capacity values of all the electrical equipment in your facility that has a voltage capacity greater than 38 kV and that is installed or retired in that reporting year and in subsequent reporting years.
(2) You must adopt the measured nameplate capacity value for any piece of equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer equals or exceeds two percent of the nameplate capacity value most recently specified by the manufacturer.
(3) You may adopt the measured nameplate capacity value for equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer, but if you elect to adopt the measured nameplate capacity for that equipment, then you must adopt the measured nameplate capacity value for all of the equipment for which the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer. This applies in the reporting year in which you first adopt the measured nameplate capacity for the equipment and in subsequent reporting years.
(4) Users of electrical equipment measuring the nameplate capacity of any new electrical equipment must:
(i) Record the amount of insulating gas in the equipment at the time the equipment was acquired (pounds), either per information provided by the manufacturer, or by transferring insulating gas from the equipment to a gas container and measuring the amount of insulating gas transferred. The equipment user is responsible for ensuring the gas is accounted for consistent with the methodologies specified in paragraphs (b)(4)(ii) through (iii) and (b)(5) of this section. If no insulating gas was in the device when it was acquired, record this value as zero.
(ii) If insulating gas is added to the equipment subsequent to the acquisition of the equipment to energize it the first time, transfer the insulating gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. Follow the manufacturer-specified procedure to ensure that the measured temperature accurately reflects the temperature of the insulating gas, e.g., by measuring the insulating gas pressure and vessel temperature after allowing appropriate time for the temperature of the transferred gas to equilibrate with the vessel temperature. Measure and calculate the total amount of reportable insulating gas added to the device using one of the methods specified in paragraphs (b)(4)(ii)(A) and (B) of this section.
(A) To determine the amount of reportable insulating gas transferred to the electrical equipment, weigh the gas container being used to fill the device prior to, and after, the addition of the reportable insulating gas to the electrical equipment, and subtract the second value (after-transfer gas container weight) from the first value (prior-to-transfer gas container weight). Account for any gas contained in hoses before and after the transfer.
(B) Connect a mass flow meter between the electrical equipment and a gas cart. Transfer gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. During gas transfer, you must keep the mass flow rate within the range specified by the mass flow meter manufacturer to assure an accurate and precise mass flow meter reading. Close the connection to the GIE from the mass flow meter hose and ensure that the gas trapped in the filling hose returns through the mass flow meter. Calculate the amount of gas transferred from the mass reading on the mass flow meter.
(iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain the measured nameplate capacity for the new equipment.
(5) Electrical equipment users measuring the nameplate capacity of any retiring electrical equipment must:
(i) Measure and record the initial system pressure and vessel temperature prior to removing any insulating gas.
(ii) Compare the initial system pressure and temperature to the equipment manufacturer's temperature/pressure curve for that equipment and insulating gas.
(iii) If the temperature-compensated initial system pressure of the electrical equipment does not match the temperature-compensated design operating pressure specified by the equipment manufacturer, you may either:
(A) Add or remove insulating gas to/from the electrical equipment until the manufacturer-specified value is reached, or
(B) If the temperature-compensated initial system pressure of the electrical equipment is no higher than the temperature-compensated design operating pressure specified by the manufacturer and no lower than five pounds per square inch (5 psi) less than the temperature-compensated design operating pressure specified by the manufacturer, use equation DD-5 to this section to calculate the nameplate capacity based on the mass recorded under paragraph (b)(5)(vi) of this section.
(iv) Weigh the gas container being used to receive the gas and record this value.
(v) Recover insulating gas from the electrical equipment until five minutes after the pressure in the electrical equipment reaches a pressure of at most five pounds per square inch absolute (5 psia).
(vi) Record the amount of insulating gas recovered (pounds) by weighing the gas container that received the gas and subtracting the weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section from this value. Account for any gas contained in hoses before and after the transfer. The amount of gas recovered shall be the measured nameplate capacity for the electrical equipment unless the final temperature-compensated pressure of the electrical equipment exceeds 0.068 psia (3.5 Torr) or the electrical equipment user is calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, in which cases the measured nameplate capacity shall be the result of equation DD-5 to this section.
(vii) If you are calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, use equation DD-5 to this section to do so.
(viii) Record the final system pressure and vessel temperature.
(6) Instead of measuring the nameplate capacity of electrical equipment when it is retired, users may measure the nameplate capacity of electrical equipment during maintenance activities that require opening the gas compartment, but they must follow the procedures set forth in paragraph (b)(5) of this section.
(7) If the electrical equipment will remain energized, and the electrical equipment user is adopting the user-measured nameplate capacity, the electrical equipment user must affix a revised nameplate capacity label, showing the revised nameplate value and the year the nameplate capacity adjustment process was performed, to the device by the end of the calendar year in which the process was completed. The manufacturer's previous nameplate capacity label must remain visible after the revised nameplate capacity label is affixed to the device.
(8) For each piece of electrical equipment whose nameplate capacity was adjusted during the reporting year, the revised nameplate capacity value must be used in all provisions wherein the nameplate capacity is required to be recorded, reported, or used in a calculation in this subpart unless otherwise specified herein.
(9) The nameplate capacity of a piece of electrical equipment may only be adjusted more than once if the physical capacity of the device has changed ( e.g., replacement of bushings) after the initial adjustment was performed, in which case the equipment user must adjust the nameplate capacity pursuant to the provisions of this paragraph (b).
(10) Measuring devices used to measure the nameplate capacity of electrical equipment under this paragraph (b) must meet the following accuracy and precision requirements:
(i) Flow meters must be certified by the manufacturer to be accurate and precise to within one percent of the largest value that the flow meter can, according to the manufacturer's specifications, accurately record.
(ii) Pressure gauges must be certified by the manufacturer to be accurate and precise to within 0.5% of the largest value that the gauge can, according to the manufacturer's specifications, accurately record.
(iii) Temperature gauges must be certified by the manufacturer to be accurate and precise to within ±1.0  °F.
(iv) Scales must be certified by the manufacturer to be accurate and precise to within one percent of the true weight.
§ 98.304   Monitoring and QA/QC requirements.
(a) [Reserved]
(b) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to equation DD-4 to § 98.303 to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in fluorinated GHG Inventory and the Net Increase in Total Nameplate Capacity may be calculated as negative numbers.
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to fluorinated GHG purchased from bulk gas distributors, fluorinated GHG purchased from Original Equipment Manufacturers (OEM) and fluorinated GHG returned to the facility from off-site recycling are also accounted for among the total additions.
(c) Ensure the following QA/QC methods are employed throughout the year:
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ±2 pounds, of residual gas amounts in the cylinders returned to the gas supplier.
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system).
(d) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
§ 98.305   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for fluorinated GHGs, and from similar equipment repair, replacement, and maintenance operations.
§ 98.306   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical:
(a) Nameplate capacity of equipment (pounds) containing each insulating gas:
(1) Existing at the beginning of the year (excluding hermetically sealed-pressure switchgear).
(2) New hermetically sealed-pressure switchgear during the year.
(3) New equipment other than hermetically sealed-pressure switchgear during the year.
(4) Retired hermetically sealed-pressure switchgear during the year.
(5) Retired equipment other than hermetically sealed-pressure switchgear during the year.
(b) Transmission miles (length of lines carrying voltages above 35 kilovolts).
(c) Distribution miles (length of lines carrying voltages at or below 35 kilovolts).
(d) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the beginning of the year.
(e) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the end of the year.
(f) Pounds of each reportable insulating gas purchased or otherwise acquired in bulk from chemical producers, chemical distributors, or other entities.
(g) Pounds of each reportable insulating gas purchased or otherwise acquired from equipment manufacturers, equipment distributors, or other entities with or inside equipment, including hermetically sealed-pressure switchgear, while the equipment was not in use.
(h) Pounds of each reportable insulating gas returned to facility after off-site recycling.
(i) Pounds of each reportable insulating gas acquired inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., through acquisition of all or part of another electric power system.
(j) Pounds of each reportable insulating gas returned to suppliers.
(k) Pounds of each reportable insulating gas that was sold or transferred to other entities in bulk.
(l) Pounds of each reportable insulating gas sent off-site for recycling.
(m) Pounds of each reportable insulating gas sent off-site for destruction.
(n) Pounds of each reportable insulating gas contained in equipment, including hermetically sealed-pressure switchgear, that was sold or transferred to other entities while the equipment was not in use.
(o) Pounds of each reportable insulating gas disbursed inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., through sale of all or part of the electric power system to another electric power system.
(p) State(s) or territory in which the facility lies.
(q) The number of reportable-insulating-gas-containing pieces of equipment in each of the following equipment categories:
(1) New hermetically sealed-pressure switchgear during the year.
(2) New equipment other than hermetically sealed-pressure switchgear during the year.
(3) Retired hermetically sealed-pressure switchgear during the year.
(4) Retired equipment other than hermetically sealed-pressure switchgear during the year.
(r) The total of the nameplate capacity values most recently assigned by the electrical equipment manufacturer(s) to each of the following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(s) The total of the nameplate capacity values measured by the electrical equipment user for each of the following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(t) For each reportable insulating gas reported in paragraphs (a), (d) through (o), and (q) of this section, an ID number or other appropriate descriptor that is unique to that reportable insulating gas.
(u) For each ID number or descriptor reported in paragraph (t) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas.
§ 98.307   Records that must be retained.
(a) In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306.
(b) For each piece of electrical equipment whose nameplate capacity is measured by the equipment user, retain records of the following:
(1) Equipment manufacturer name.
(2) Year equipment was manufactured. If the date year the equipment was manufactured cannot be determined, report a best estimate of the year of manufacture and record how the estimated year was determined.
(3) Manufacturer serial number. For any piece of equipment whose serial number is unknown ( e.g., the serial number does not exist or is not visible), another unique identifier must be recorded as the manufacturer serial number. The electrical equipment user must retain documentation that allows for each electrical equipment to be readily identifiable.
(4) Equipment type ( i.e., closed-pressure vs. hermetically sealed-pressure).
(5) Equipment voltage capacity (in kilovolts).
(6) The name and GWP of each insulating gas used.
(7) Nameplate capacity value (pounds), as specified by the equipment manufacturer. The value must reflect the latest value specified by the manufacturer during the reporting year.
(8) Nameplate capacity value (pounds) measured by the equipment user.
(9) The date the nameplate capacity measurement process was completed.
(10) The measurements and calculations used to calculate the value in paragraph (b)(8) of this section.
(11) The temperature-pressure curve and/or other information used to derive the initial and final temperature-adjusted pressures of the equipment.
(12) Whether or not the nameplate capacity value in paragraph (b)(8) of this section has been adopted for the piece of electrical equipment.