['Air Programs']
['Greenhouse Gases']
05/22/2023
Copyright 2024 J. J. Keller & Associate, Inc. For re-use options please contact copyright@jjkeller.com or call 800-558-5011.
...
In addition to the information required by §98.3(c), report the information listed in this section.
(a) If you receive CO2 by pipeline, report the following for each receiving flow meter:
(1) The total net mass of CO2 received (metric tons) annually.
(2) If a volumetric flow meter is used to receive CO2 report the following unless you reported yes to paragraph (a)(4) of this section:
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO2 concentration in the flow (volume percent CO2 expressed as a decimal fraction) in each quarter.
(3) If a mass flow meter is used to receive CO2 report the following unless you reported yes to paragraph (a)(4) of this section:
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO2 concentration in the flow (weight percent CO2 expressed as a decimal fraction) in each quarter.
(4) If the CO2 received is wholly injected and not mixed with any other supply of CO2, report whether you followed the procedures in §98.444(a)(4).
(5) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(7) Whether the flow meter is mass or volumetric.
(8) A numerical identifier for the flow meter.
(b) If you receive CO2 in containers, report:
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter.
(2) The concentration of CO2 of contents in containers (volume or wt. percent CO2 expressed as a decimal fraction) in each quarter.
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net mass of CO2 received (in metric tons) annually.
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the total net mass of CO2 received (metric tons) through all flow meters annually.
(d) The source of the CO2 received according to the following categories:
(1) CO2 production wells.
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e)Report the date that you began collecting data for calculating total amount sequestered according to §98.448(a)(7) of this subpart.
(f) Report the following. If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section.
(1) For each injection flow meter (mass or volumetric), report:
(i) The mass of CO2 injected (metric tons) annually.
(ii) The CO2 concentration in flow (volume or weight percent CO2 expressed as a decimal fraction) in each quarter.
(iii) If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter.
(iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(ix) The location of the flow meter.
(2) The total CO2 injected (metric tons) in the reporting year as calculated in Equation RR-6 of this subpart.
(3) For CO2 emissions from equipment leaks and vented emissions of CO2, report the following:
(i) The mass of CO2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
(ii) The mass of CO2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.
(4) For each separator flow meter (mass or volumetric), report:
(i) CO2 mass produced (metric tons) annually.
(ii) CO2 concentration in flow (volume or weight percent CO2 expressed as a decimal fraction) in each quarter.
(iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter.
(iv) If a mass flow meter, mass flow rate (metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(5) The entrained CO2 in produced oil or other fluid divided by the CO2 separated through all separators in the reporting year (weight percent CO2 expressed as a decimal fraction) used as the value for X in Equation RR-9 of this subpart and as determined according to your EPA-approved MRV plan.
(6) Annual CO2 produced in the reporting year as calculated in Equation RR-9 of this subpart.
(7) For each leakage pathway through which CO2 emissions occurred, report:
(i) A numerical identifier for the leakage pathway.
(ii) The CO2 (metric tons) emitted through that pathway in the reporting year.
(8) Annual CO2 mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR-10 of this subpart.
(9) Annual CO2 (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation RR-11 or RR-12 of this subpart.
(10) Cumulative mass of CO2 (metric tons) reported as sequestered in subsurface geologic formations in all years since the well or group of wells became subject to reporting requirements under this subpart.
(11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.
(12) An annual monitoring report that contains the following components:
(i) A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted.
(ii) A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under §98.448(d).
(iii) A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved.
(iv) A description of any surface leakages of CO2, including a discussion of all methodologies and technologies involved in detecting and quantifying the surface leakages and any assumptions and uncertainties involved in calculating the amount of CO2 emitted.
(13) If a well is permitted under the Underground Injection Control program, for each injection well, report:
(i) The well identification number used for the Underground Injection Control permit.
(ii) The Underground Injection Control permit class.
(14) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.
[75 FR 75083, Dec. 1, 2010; 76 FR 73906, Nov. 29, 2011; 78 FR 71979, Nov. 29, 2013]
READ MORESHOW LESS
['Air Programs']
['Greenhouse Gases']
Load More
J. J. Keller is the trusted source for DOT / Transportation, OSHA / Workplace Safety, Human Resources, Construction Safety and Hazmat / Hazardous Materials regulation compliance products and services. J. J. Keller helps you increase safety awareness, reduce risk, follow best practices, improve safety training, and stay current with changing regulations.
Copyright 2024 J. J. Keller & Associate, Inc. For re-use options please contact copyright@jjkeller.com or call 800-558-5011.