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Timestamp: 2020-07-15 03:37:13
Document Index: 479021183

Matched Legal Cases: ['art 98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98', '§98']

Title 40 → Chapter I → Subchapter C → Part 98 → Subpart Y
§98.251 Reporting threshold.
§98.254 Monitoring and QA/QC requirements.
§98.255 Procedures for estimating missing data.
§98.257 Records that must be retained.
§98.258 Definitions.
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).
(a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO2 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 analysis of the fuel 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).
(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).
(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 fuel 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.
(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 CO2/CO/O2 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) Determine the mass of petroleum coke as required by Equation Y-13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see §98.7). Calibrate the measurement device according to the procedures specified by NIST handbook 44 (incorporated by reference, see §98.7) or the procedures specified by the manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer.
(i) Determine the carbon content of petroleum coke as required by Equation Y-13 of this subpart using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer.
(1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see §98.7).
(2) 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).
(3) 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).
(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.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79163, Dec. 17, 2010; 81 FR 89263, Dec. 9, 2016]
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 CO2 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 CH4 emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining 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, catalytic reforming unit, and coke calcining unit (calculation method in §98.253(c)(4)).
(18) Value of unit-specific N2O emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining 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, catalytic reforming unit, and coke calcining 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) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (Equation Y-13 of §98.253).
(28) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (Equation Y-13).
(29) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records. For coke calcining units that recycle the collected dust, the mass of coke dust removed from the process is the mass of coke dust collected less the mass of coke dust recycled to the process (metric tons/year) (Equation Y-13).
(30) Average mass fraction carbon content of green coke from facility measurement data (metric tons C per metric ton green coke) (Equation Y-13).
(31) Average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke (Equation Y-13).
(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 CO2 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CO2/MMbbl asphalt blown) (Equation Y-14).
(34) Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CH4/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 CO2 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CO2/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 CH4 from uncontrolled asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons CH4/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 (metric ton/cycle) (Equations Y-18b and Y-18e in §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 (feet) from company records or engineering estimates (Equation Y-18b in §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 CH4 per metric ton of steam; kg CH4/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) Average volumetric flow rate of process gas during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (scf per hour) (Equation Y-19 of §98.253).
(54) Mole fraction of methane in process vent during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (kg-mole CH4/kg-mole gas) (Equation Y-19).
(55) Venting time for the event for each set of coke drums or vessels of the same size (hours) (Equation Y-19).
(56) Molar volume conversion factor for each set of coke drums or vessels of the same size (scf per kg-mole) (Equation Y-19).
(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 CH4/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 CH4 in vent gas from the unstabilized crude oil storage tanks from facility measurements (kg-mole CH4/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)).
[79 FR 63796, Oct. 24, 2014, as amended at 81 FR 89263, Dec. 9, 2016]