Page 1 of 40
**Subpart RR —**  **Geologic Sequestration of Carbon Dioxide**
(a) The geologic sequestration of carbon dioxide ( CO § 98.440 Definition of the source category.

2 ) source category comprises any well or group of wells that inject

a CO 2

(b) This source category includes all wells permitted as Class VI under the Underground Injection Control program. stream for long

- term containment in subsurface geologic formations.

( c) This source category does not include a well or group of wells where a CO 2

(1) The owner or operator injects th e CO stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies:

2

(2) The well is permitted as Class VI under the U nderground Injection Control program. stream for long

term containment in subsurface geologic formations and has chosen to submit a proposed monitoring, reporting, and verification (MRV) plan to EPA and received an approved plan from EPA.

(d) Exemption for research and development projects
. Research and development projects shall receive an exemption from reporting under this subpart for the duration of the research and development activity.Page 2 of 40
(1) Process for obtaining an exemption

(2) . If you are a research and development project, you must submit the information in paragraph (d)(2) of this section to EPA by the time you would be otherwise required to submit an MRV plan under §98.448. EPA will use this inform ation to verify that the project is a research and development project. Content of submission

(i) The planned duration of CO . A submission in support of an exemption as a research and development project must contain the following information:

2 (ii) The planned annual CO injecti on for the project.

2

(iii) The research purposes of the project. injection volumes during this time period.

(iv) The source and type of funding for the project. (v) The class and duration of Underground Injection Control permit o r, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration. (3) Determination by the Administrator (i) The Administrator shall determine if a project meets the definiti on of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator shall take into account any information you submit demonstrating that the .Page 3 of 40 planned duration of CO 2 injection for the project and the planned annual CO 2

(ii) Any appeal of the Administrator's determination is subject to the provi sions of part 78 of this chapter. injection volumes during the duration of the project are consistent with the purpose of the research and development project.

(iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator's determination. You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan.

(a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO § 98.441 Reporting threshold.

2

(b) for long

term containment in subsurface geologic formations. There is no threshold. Request for discontinuation of reporting
. The requirements of §98.2(i) do not apply to this subpart. Once a well or group of wells is subject to the requirements of this subpart, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports, until thePage 4 of 40
Administrator has issued a final decision on an owner or operator's request to disconti nue reporting. (1) Timing of request

(2) . The owner or operator of a facility may submit a request to discontinue reporting any time after the well or group of wells is plugged and abandoned in accordance with applicable requirements. Content of request

(i) For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control pro gram Director's authorization of site closure. . A request for discontinuation of reporting must contain either paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(ii) For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO 2

(3) stream is not expected to migrate in the future in a manner likely to result in surface leakage. Notification
. The Administrator will issue a final decision on the request to discontinue reporting within a reasonable time. Any appeal of the Administrat or's final decision is subject to the provisions of part 78 of this chapter. § 98.442 GHGs to report.Page 5 of 40
You must report: (a) Mass of CO 2 (b) Mass of CO received.

2 (c) Mass of CO injected into the subsurface.

2 (d) Mass of CO produced.

2 (e) Mass of CO emitted by surface leakage.

2 emissions from equipment leaks and vented emissions of CO 2

(f) Mass of CO from surface equipment located between the injection flow meter and the injection wellhead.

2 emissions from equipment leaks and vented emissions of CO 2

(g) Mass of CO from surface equipment located between the production flow meter and the production wellhead.

2

(h) Cumulative mass of CO sequestered in subsurface geologic formations.

2 reported as sequestered in subsurface geologic formations in all years since the facility became subject to reporting requirements under this subpart. § 98.443 Calculating CO 2 You must calculate the mass of CO geologic sequestration.

2 received using CO 2 received equations (Equations RR

– 1 to RR

– 3 of this section), unless you follow the procedures in §98.444(a)(4). You must calculate CO 2 sequestered using injection equations (Equations
RR

– 4 to RR

– 6 of this section), production/recycling equations (Equations RR

– 7 to RR

– 9 of this section), surface leakage equations (Equation RR

– 10 of th is section), and sequestrationPage 6 of 40 equations (Equations RR

– 11 and RR

– 12 of this section). For your first year of reporting, you must calculate CO 2

(a) You must calculate and report the ann ual mass of CO sequestered starting from the date set forth in your approved MRV plan.

2

(1) For a mass flow meter, you must calculate the total annual mass of CO received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable.

2 in a CO 2 stream received in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation RR

– 1 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordanc e with §98.444.

Where:

CO 2 T,r = Net annual mass of CO 2 Q received through flow meter r (metric tons).

r,p =
S Quarterly mass flow through a receiving flow meter r in quarter p (metric tons).

r,p =

C CO Quarterly mass flow through a receiving flow meter r that is redelivered to another facility without being injected into your well in quarter p (metric tons).

2 , p,r = Quarterly CO 2 concentration measurement in flow for flow meter r in quarter p (wt. percent CO 2
p = Quarter o f the year. , expressed as a decimal fraction).

r = Receiving flow meter.Page 7 of 40 (2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 in a CO 2 stream received in metric tons by multiplying the volumetric flow at standard conditions by the
CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation RR

– 2 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must be made in accordance with §98.444.

Wher e:
CO 2 T,r = Net annual mass of CO 2 Q received through flow meter r (metric tons).

r,p

S = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions (standard cubic meters).

r,p

D = Density of CO = Quarterly volumetric flow through a recei ving flow meter r that is redelivered to another facility without being injected into your well in quarter p (standard cubic meters).

2
C CO at standard conditions (metric tons per standard cubic meter): 0.0018682.

2 , p,r = Quarterly CO 2 concentration measurement in flow for flow meter r in quarter p (vol. percent CO 2 p = Quarter of the year. , expressed as a decimal fraction).

r = Receiving flow meter. (3) If you receive CO 2 through more than one flow meter, you must sum the mass of all CO 2 received in accordance with the procedure specified in Equation RR

– 3 of this section.Page 8 of 40
Where:

CO 2 = Total net annual mass of CO 2
CO received (metric tons).

2 T,r = Net annual mass of CO 2

r = Receiving flow meter. received (metric tons) as calculated in Equation RR

– 1 or RR

– 2 for flow meter r.
(b) You must calculate and report the annual mass of CO 2

(1) If you are measuring the mass of contents in a container under the provisions of §98.444(a)(2)(i), you must calculate the CO received in containers using the procedures in paragraphs (b)(1) or (b)(2) of this section.

2

Where: received for injection in containers using Equation RR

– 1 of this section.

CO 2 T,r = Net annual mass of CO 2
C CO received in containers r (metric tons).

2 , p,r = Quarterly CO 2 concentration measurement of contents in containers r in quarter p (wt. percent CO 2 Q , expressed as a decimal fraction).

r,p
S = Quarterly mass of contents in containers r in quarter p (metric tons).

r,p

p = Quarter of the year. = Quarterly mass of contents in containers r redelivered to another facility without being injected into your well in quarter p (metric tons).

r = Containers. (2) If you are measuring the volume of contents in a container under the provisions of §98.444(a)(2)(ii), you mustPage 9 of 40
calculate the CO 2

Where: receiv ed for injection in containers using Equation RR

– 2 of this section.

CO 2 T,r = Net annual mass of CO 2
C CO received in containers r (metric tons).

2 , p,r = Quarterly CO 2 concentration measurement of contents in containers r in quarter p (vol. percent CO 2 Q , expressed as a decimal fraction).

r,p =
S Quarterly volume of contents in containers r in quarter p (standard cubic meters).

r,p =

D = Density of the CO Quarterly mass volume of contents in containers r redelivered to another facility without being injected into your well in quarter p ( metric tons standard cubic meters ).

2

p = Quarter of the year. received in containers at standard conditions (metric tons per standard cubic meter):0.0018682.

r = Containers. (c) You must report the annual mass of CO 2

(1) If you use a mass flow meter to measure the flow of an injected CO injected in accordance with the procedures specified in paragraphs (c)(1) through (c)(3) of this section.

2 stream, you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation RR

– 4 of this section. Mass flow and concentration data measurements must be made in accordance with §98.444.Page 10 of 40

Where:

CO 2 , u = Annual CO 2 Q mass injected (metric tons) as measured by flow meter u.

p,u

C CO = Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons per quarter).

2 , p,u = Quarterly CO 2 concentration measurement in flow for flow meter u in quarter p (wt. percent CO 2
p = Quarter of the year. , expressed as a decimal fraction).

u = Flow meter. (2) If you use a volumetric flow meter to measure the flow of an injected CO 2 stream, you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation RR

– 5 of this section. Volumetric flow a nd concentration data measurements must be made in accordance with §98.444.

Where:

CO 2 , u = Annual CO 2 Q mass injected (metric tons) as measured by flow meter u.

p,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions (standard cubic meters per quarter).Page 11 of 40

D = Density of CO 2
C CO at standard conditions (metric tons per standard cubic meter): 0.0018682.

2 , p,u = CO 2 concentration measurement in flow for flow meter u in quarter p (vol. percent CO 2
p = Quarter of the year. , expressed as a de cimal fraction).

u = Flow meter. (3) To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO 2 injected through all injection wells in accordance with the procedure specified in Equation RR

– 6 of this section.

Where:

CO 2 I = Total annual CO 2
CO mass injected (metric tons) through all injection wells.

2 , u = Annual CO 2

u = Flow meter. mass injected (metric tons) as measured by flow meter u.

(d) You must calculate the annual mass of CO 2 produced from oil or gas production wells or from other fluid wells for each separator that sends a stream of gas into a recycle or end use system in accordance with the procedures specified in paragraphs (d)(1) through (d)(3) of this section. You must acc ount for any CO 2 that is produced and not processed through a separator. You must account only for wells that produce the CO 2 that was injected into the well or wells covered by this source category.Page 12 of 40 (1) For each gas

- liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO 2 produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the mass gas f low by the CO 2 concentration in the gas flow, according to Equation RR

– 7 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordance with §98.444.

Where:

CO 2 , w = Annual CO 2 Q mass produc ed (metric tons) through separator w.

p,w
C CO = Quarterly gas mass flow rate measurement for separator w in quarter p (metric tons).

2 , p,w = Quarterly CO 2 concentration measurement in flow for separator w in quarter p (wt. percent CO 2
p = Quarter of the year. , expressed as a decim al fraction).

w = Separator. (2) For each gas

- liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO 2 produced from an oil or other fluid stream in metric tons th at is separated from the fluid by multiplying the volumetric gas flow at standard conditions by the CO 2 concentration in the gas flow and the density of CO 2 at standard conditions, according to Equation RR

– 8 of this section.Page 13 of 40 You must collect these data qua rterly. Volumetric flow and concentration data measurements must be made in accordance with §98.444.

Where:

CO 2 , w = Annual CO 2 Q mass produced (metric tons) through separator w.

p,w

D = Density of CO = Volumetric gas flow rate measurement for separator w in quarter p at s tandard conditions (standard cubic meters).

2
C CO at standard conditions (metric tons per standard cubic meter): 0.0018682.

2 , p,w = CO 2 concentration measurement in flow for separator w in quarter p (vol. percent CO 2
p = Quarter of the year. , expressed as a decimal fraction).

w = Separator. (3) To aggregate production data, you must sum the mass of all of the CO 2 separated at each gas

- liquid separator in accordance with the procedure specified in Equation RR

– 9 of this section. You must assume that the total CO 2 measured at the separator(s) represents a percentage of the total CO 2 produced. In order to account for the percentage of CO 2 produced that is estimated to remain with the produced oil or other fluid, you
must mu ltiply the quarterly mass of CO 2 measured at the separator(s) by a percentage estimated using a methodology in your approved MRV plan. If fluids containing CO 2 from injectionPage 14 of 40 wells covered under this source category are produced and not processed through a gas - liquid separator, the concentration of
CO 2 in the produced fluids must be measured at a flow meter located prior to reinjection or reuse using methods in §98.444(f)(1). The considerations you intend to use to calculate
CO 2 from produced fluids for the mass balance equation must be described in your approved MRV plan in accordance with §98.448( d a )(5).

Where:

CO 2 P = Total annual CO 2
CO mass produced (metric tons) through all separators in the reporting year.

2 , w = Annual CO 2
X = Entrained CO mass produced (metric tons) through separator w in the reporting year.

2 in produced oil or other fluid divided by the CO 2 separated through all separators in the reporting year (weight percent CO 2 w = Separator. , expressed as a decimal fraction).
(e) You must report the annual mass of CO 2 that is emitted by surface leakage in accordance with your approved MRV plan. You must calculate the total annual mass of CO 2 emitted from all leakage pathways in accordance with the procedure specified in Equatio n RR

– 10 of this section.

Where:Page 15 of 40

CO 2 E = Total annual CO 2
CO mass emitted by surface leakage (metric tons) in the reporting year.

2 , x = Annual CO 2

x = Leakage pathway. mass emitted (metric tons) at leakage pathway x in the reporting year.
(f) You must rep ort the annual mass of CO 2

(1) If you are actively producing oil or natural gas or if
y ou are producing any other fluids, you must calculate the annual mass of CO that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in paragraphs (f)(1) and (f)(2) of this section.

2 that is sequestered in the underground subsurface formation in the reporting year in accordance with the procedure specified in Equation RR

– 11 of this section.

Where:

CO 2 = To tal annual CO 2

CO mass sequestered in subsurface geologic formations (metric tons) at the facility in the reporting year.

2 I = Total annual CO 2

CO mass injected (metric tons) in the well or group of wells covered by this source category in the reporting year.

2 P = Total annual CO 2
CO mass produced (metric tons) in the reporting year.

2 E = Total annual CO 2
CO mass emitted (metric tons) by surface leakage in the reporting year.

2 FI = Total annual CO 2 mass emitted (metric tons) from equipment leaks and vented emissions of CO 2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead,Page 16 of 40 for which a calculation procedure is provided in subpart W of this part. CO 2 FP = Total annual CO 2 mass emitted (m etric tons) from equipment leaks and vented emissions of CO 2

(2) If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity, for which a calculation procedure is provided in subpart W of this pa rt.

2 that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in Equation RR

– 12 of this section.

Where:

CO 2 = Total annual CO 2

CO mass sequestered in subsurface geologic formations (metric tons) at the facility in the reporting year.

2 I = Total annual CO 2

CO mass injected (metric tons) in the well or group of wells covered by this source category in the reporting year.

2 E = Total annual CO 2
CO mass emitted (metric tons) by surface leakage in the reporting year.

2 FI = Total annual CO 2 mass emitted (metric tons) from equipment leaks and vented emissions of CO 2 from equipment l ocated on the surface between the flow meter used to measure injection quantity and the injection wellhead , for which a calculation procedure is provided in subpart W of this part
.

(a) CO § 98.444 Monitoring and QA/QC requirements.

2 received
.Page 17 of 40 (1) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly flow rate of CO 2

(i) You may measure flow rate at the receiving custody transfe r meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly. received by pipeline by following the most appropriate of the following procedures:

(ii) If you took ownership of the CO 2

(iii) If you inject CO in a commercial transaction, you may use the quarterly flow rate data from the sales contract if it is a one

- ti me transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.

2 received from a production process unit that is part of your facility, you may use the quarterly CO 2 flow rate that was measured at the equivalent of a custody transfer meter following procedures provided in subpart PP of this part. To be the equivalent of a custody transfer meter, a meter must measure the flow of CO 2

(2) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO being transported to an injection well to the same degr ee of accuracy as a meter used for commercial transactions.

2 in containers by following the most app ropriate of the following procedures:Page 18 of 40 (i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells. (ii) You may determine the volume of the contents of containers summed quarterly. (iii) If you took owne rship of the CO 2

(3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one

- time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.

2 received that is representative of all CO 2

(i) You may sample the CO received in that quarter by following the most appropriate of the following procedures:

2 stream at least once per quarter at the point of receipt and measure its CO 2 (ii) If you took ownership of the CO concentration.

2 in a commercial transaction for which the sales contract was contingent on CO 2 concentration, and if the supplier of the CO 2 sampled the CO 2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO 2

(iii) If you inject CO concentration data from the sales contract for that quarter.

2 from a p roduction process unit that is part of your facility, you may report the quarterly CO 2Page 19 of 40
concentration of the CO 2

(4) If the CO stream supplied that was measured following the procedures provided in subpart PP of this part.

2 you receive is wholly injected an d is not mixed with any other supply of CO 2 , you may report the annual mass of CO 2 injected that you determined following the requirements under paragraph (b) of this section as the total annual mass of CO 2 received instead of using Equation RR

– 1 or RR

– 2 o f this subpart to calculate CO 2 (5) You must assume that the CO received.

2 you receive meets the definition of a CO 2 stream unless you can trace it through written records to a source other than a CO 2 (b) CO stream.

2 (1) You must select a point or points of measurement at which the CO injected.

2 stream(s) is representative of the CO 2

(2) You must measure flow rate of CO stream(s) being injected. You may use as the point or points of measurement the location(s) of the flow meter(s) used to comply with the flow monitoring and reporting provisio ns in your Underground Injection Control permit.

2

(3) You must sample the injected CO injected with a flow meter and collect the flow rate quarterly.

2 stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that CO 2 stream and measure the CO 2 concentration of the sample.Page 20 of 40
(c) CO 2 (1) The point of measurement for the quantity of CO produced.

2

(2) You must sample the produced gas stream at least once per quarter immediately upstream or d ownstream of the flow meter used to measure flow rate of that gas stream and measure the CO prod uced from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a stream of gas into a recycle or end use system.

2

(3) You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly. concentration of the sample.

(d) CO 2 emissions from equipment leaks and vented emissions of CO 2

(e)

. If you have equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead or between the flow meter used to measure production quantity and the production wellhead, you must follow the monitoring and QA/QC requirements specified in subpart W of this part for the equipment. Measurement devices (1) All flow meters must be operated continuously except as necessary for maintenance and calibration. .

(2) You must cali brate all flow meters used to measure quantities reported in §98.446 according to the calibration and accuracy requirements in §98.3(i).Page 21 of 40 (3) You must operate all measurement devices according to one of the following. You may use an appropriate standard met hod published by a consensus

- based standards organization if such a method exists or an industry standard practice. Consensus

- based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (4) You must ensure that any flow meter calibrations
p erformed are National Institute of Standards and Technology (NIST) traceable. (f) General (1) If you measure the concentration of any CO .

2

(2) You must convert all measured volumes of CO quantity for reporting, you must measure according to one of the following. You may use an appropriate standard method published by a

consensus - based standards organization if such a method exists or an industry standard practice.

2 to the following standard industry temperature and pressure conditions for use in Equati ons RR

– 2, RR

– 5 and RR

– 8 of this subpart: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere.Page 22 of 40 (3) For 2011, you may follow the provisions of §98.3(d)(1) through (2) for best available monitoring metho ds only for parameters required by paragraphs (a) and (b) of §98.443 rather than follow the monitoring requirements of paragraph (a) of this section. For purposes of this subpart, any reference to the year 2010 in §98.3(d)(1) through (2) shall mean 2011.

A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures: § 98.445 Procedures for estimating missing data.

(a) A quarterly flow rate of CO 2

(1) Another calculation methodology listed in §98.444(a)(1) must be used if possible. received that is missing must be estimated as follows:

(2) If another method listed in §98.444(a)(1) cannot be used, a quarterly flow rate v alue that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) A quarterly mass or volume of contents in containers received that is missing must be estimated as follows: (1) Another calculation met hodology listed in §98.444(a)(2) must be used if possible.Page 2 3 of 40
(2) If another method listed in §98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previou s time period. (c) A quarterly CO 2 concentration of a CO 2

(1) Another calculation methodology listed in §98.444(a)(3) must be used if possible. stream received that is missing must be estimated as follows:

(2) If another method listed in §98.444(a)(3) cann ot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period. (d) A quarterly quantity of CO 2 injected that is missing must be estimated using a representativ e quantity of CO 2

(e) For any values associated with CO injected from the nearest previous period of time at a similar injection
pressure.

2 emissions from equipment leaks and vented emissions of CO 2

(f) The quarterly quantity of CO from surface equipment at the facility that are reported in this subpart, missing data estimation procedures should be followed in accordance with those specified in subpart W of this part.

2 produced from subsurface geologic formations that is missing must be estimated using aPage 24 of 40

re presentative quantity of CO 2

(g) You must estimate the mass of CO produced from the nearest previous period of time.

2

(h) You must estimate other missing data as required by your approved MRV plan. emitted by surface leakage that is missing as required by your approved MRV plan.

In addition to the information required by §98.3(c), report the information listed in this section. § 98.446 Data reporting requirements.

(a) If you receive CO 2

(1) Th e total net mass of CO by pipeline, report the following for each receiving flow meter:

2

(2) If a volumetric flow meter is used to receive CO received (metric tons) annually.

2

(i) The volumetric flow through a receiving flow meter at stand ard conditions (in standard cubic meters) in each quarter. report the following unless you reported yes to paragraph (a)(4) of this section:

(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 CO 2 conce ntration in the flow (volume percent CO 2 expressed as a decimal fraction) in each quarter.Page 25 of 40
(3) If a mass flow meter is used to receive CO 2

(i) The mass flow through a receiving flow meter (in metric tons) in each quarter. report the following unless you reported yes to paragraph (a)(4) of this section:

(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 CO 2 concentration in the flow (weight percent CO 2

(4) If the CO expressed as a decimal fraction) in each quarter.

2 received is wholly injected and not mixed with any other supply of CO 2

(5) The standard or method used to ca lculate each value in paragraphs (a)(2) through (a)(3) of this section. , report whether you followed the procedures in §98.444(a)(4).

(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) Wheth er the flow meter is mass or volumetric. (8) A numerical identifier for the flow meter. (b) If you receive CO 2 (1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers receiv ed in each quarter. in containers, report:Page 26 of 40
(2) The concentration of CO 2 of contents in containers (volume or wt. percent CO 2

(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is red elivered to another facility without being injected into your well in each quarter. expressed as a decimal fraction) in each quarter.

(4) The net mass of CO 2 (5) The standard or method used to calculate each value in paragraphs (b)(1 ) ) , (b)(2), and (b)( 2) 3) of this section. received (in metric tons) annually.

(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 CO 2

(d) The source of the CO received (metric tons) through all flow meters annually.

2

(1) CO received according to the following categories:

2 (2) Electric generating unit. production wells.

(3) Ethanol plant. (4) Pulp and paper mill. (5) Natural gas p rocessing. (6) Gasification operations. (7) Other anthropogenic source.Page 27 of 40 (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 CO 2 (ii) The CO injected (metric tons) annually.

2 concentration in flow (volume or weight percent
CO 2 (iii) If a volumetric flow meter is u sed, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter. expressed as a decimal fraction) 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 me ter is mass or volumetric. (vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.Page 28 of 40 (viii) The number of times in the reporting year for which substitute data procedures were used to calculate values
repo rted in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section. (ix) The location of the flow meter. (2) The total CO 2

(3) For CO injected (metric tons) in the reporting year as calculated in Equation RR

– 6 of this subpart.

2 emissions from equipment leaks and vented emissions of CO 2 (i) The mass of CO , report the following:

2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO 2

(ii) The mass of CO from equipment located on the surface between the flow meter used to measure injection quantity and t he injection wellhead.

2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO 2

(4) For each separator flow meter (mass or volumetric), report: from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.

(i) CO 2 (ii) CO mass produced (metric tons) annually.

2 concentration in flow (volume or weight percent CO 2 expressed as a decimal fraction) in each quarter.Page 29 of 40
(iii) If a volumetric flow meter is us ed, 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 volumetr ic. (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 CO 2 in produced oil or other fluid divided by the CO 2 separated through all separators in the reporting year (weight percent CO 2

(6) Annual CO 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.

2

(7) For each leakage pathway through which CO produced in the reporting year as calculated in Equation RR

– 9 of this subpart.

2

(i) A numerical identifier for the leakage pathway. emissions occurred, report :Page 30 of 40
(ii) The CO 2

(8) Annual CO (metric tons) emitted through that pathway in the reporting year.

2

(9) Annual CO mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR

– 10 of this subpart.

2

(10) Cumulative mass of CO (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation RR

– 11 or RR

– 12 of this subpart.

2

(11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA. (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.

(12) An annual monito ring 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 te sts 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).Page 31 of 40 (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 CO 2 , 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 CO 2 (13) If a well is permitted under the Underground Injection Control program, for each injection well, report: emitted.

(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.

(a) You must follow the record retention requirements specified by §98.3(g). In addition to the records required by §98.3(g), you must retain the rec ords specified in paragraphs (a)(1) through (7) of this section, as applicable. You must retain all required records for at least 3 years. § 98.447 Records that must be retained.Page 32 of 40 (1) Quarterly records of CO 2

(2) Quarterly records of produced CO received, including mass flow rate of contents of containers (mass or volumetric) at sta ndard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.

2

(3) Quarterly records of injected CO , including mass flow or volumetric flow at standard conditions and operating conditions, operating temp erature and pressure, and concentration of these streams.

2

(4) Annual records of information used to calculate the CO including mass flow or volumetric flow at standard conditions and operating conditions, operating temperature and pressure, and concentration of these
streams.

2

(5) Annual records of information used to calculate the CO emitted by surface leakage from leakage pathways.

2 emitted from equipment leaks and vented emissions of CO 2

(6) Annual records of information used to calculate the CO from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.

2 emitted from equipment leaks and vented emissions of CO 2

(7) Any other records as specified for retention in your
EPA

- approved MRV plan. from equipment located on the surface betwee n the production wellhead and the flow meter used to measure production quantity.Page 33 of 40 (b) You must complete your monitoring plans, as described in §98.3(g)(5), by April 1 of the ye ar you begin collecting data.

(a) § 98.448 Geologic sequestration monitoring, reporting, and verification (MRV) plan. Contents of MRV plan

(1) Delineation of the maximum monitoring area and the active monitoring areas. The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than 1 year. . You must develop and submit to the Administrator a proposed MRV plan for monitoring, reporting, and verification of geologic sequestration at your facility. Your proposed MRV plan must contain the following components:

(2) Identification of potential s urface leakage pathways for CO 2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO 2

(3) A strategy for detecting and quantifying any surface leakage of CO through these pathways.

2 (4) A strategy for establishing the expected baselines for monitoring CO .

2 surface leakage.Page 34 of 40 (5) A summary of the considerations you intend to use to calculate site

- specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating CO 2 emissions from equipment leaks and vented emissions of CO 2 be tween the injection flow meter and injection well and/or the production flow meter and production well, and considerations for calculating CO 2 (6) If a well is permitted under the Underground Injection Control program, for each injectio n well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report t he well identification numbers in the permit application. 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 authoriz ing geologic sequestration. If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinki ng Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your in produced fluids.Page 35 of 40 proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved. (7) Propose d date to begin collecting data for calculating total amount sequestered according to equation RR

– 11 or RR

– 12 of this subpart. This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detect ion and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial
AMA. (b) Timing

(1) You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO . You must submit a proposed MRV plan to EPA according to the following schedule:

2

(2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO into the subsurface on or before December 31, 2010. You will be allowed to request one extension of up to an additional 180 days in which to sub mit your proposed MRV plan.

2 into the subsurface. If your facility is an offshore facility not subject to the Safe Drinking Water Act, you must submit a proposed MRV plan to EPA within 180 days of receiving authorization to begin geologicPage 36 of 40 sequestration of CO 2

(3) If you are injecting a CO . You will be allowed to request one extension of the submittal date of up to an additional 180 days
.

2

(4 ) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA. stream in subsurface geologic formations to enhance the recovery of oil or natural gas and you are not permitted as Class VI under the Underground Injection Control program, you may opt to submit an MRV plan at any time.

(c) Final MRV plan

(d) . The Administrator will issue a final MRV plan within a reasonable period of time. The Administrator's final MRV plan is subject to the provisions of part 78 of this chapter. Once the MRV plan is final and no longer subject to administrative appeal under part 78 of this chapter, you must implement the plan starting on the day after the day on which the plan becomes final and is no longer subject to such appeal. MRV plan revisions

(1) A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material change s include but are not . You must revise and submit the MRV plan within 180 days to the Administrator for approval if any of the following in paragraphs (d)(1) throu gh (d)(4) of this section applies. You must include the reason(s) for the revisions in your submittal.Page 37 of 40 limited to: Large changes in the volume of CO 2

(2) A change in the permit class of your Underground Injection Control permit. injected; the construction of new injection wells not identified in the MRV plan; failures of the monitoring system including monitoring system sensitivity, performance, location, or base line; changes to surface land use that affects baseline or operational conditions; observed plume location that differs significantly from the predicted plume area used for developing the MRV plan; a change in the maximum monitoring area or active monitori ng area; or a change in monitoring technology that would result in coverage or detection capability different from the MRV plan.

(3) If you are notified by EPA of substantive er rors in your MRV plan or monitoring report. (4) You choose to revise your MRV plan for any other reason in any reporting year. (e) Revised MRV plan

(f) . The requirements of paragraph (c) of this section apply to any submission of a revised MRV plan. You
must c ontinue reporting under your currently approved plan while awaiting approval of a revised MRV plan.
Format . Each proposed MRV plan or revision and each annual report must be submitted electronically in a format specified by the Administrator.Page 38 of 40 (g) Certi ficate of representation
. You must submit a certificate of representation according to the provisions in §98.4 at least 60 days before submission of your MRV plan, your research and development exemption request, your MRV plan submission extension request, or your initial annual report under this part, whichever is earlier.

Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. § 98.449 Definitions.

Active monitoring area

(1) The area projected to contain the free phase CO is the area that will be monitored over a specific time interval from the first year of the period (n) to the last year in the period (t). The boundary of the active monitoring area is established by superimposing two
areas:

2

(2) The area projected to contain the free phase CO plume at the end of year t, plus an all around buffer zone of one

- half mile or greater if known leakage pathways extend laterally more than one

- half mile.

2 plume at the end of year t+5. CO 2 received means the CO 2 stream that you receive to be injected for the first time into a well on your facility that is covered by this subpart. CO 2 received includes, but is notPage 39 of 40 limited to, a CO 2 stream from a production process unit inside your facility a nd a CO 2 stream that was injected into a well on another facility, removed from a discontinued enhanced oil or natural gas or other production well, and transferred to your facility. Equipment leak means those emissions that could not reasonably pass throu gh a stack, chimney, vent, or other functionally

- equivalent opening. Expected baseline is the anticipated value of a monitored parameter that is compared to the measured monitored parameter. Maximum monitoring area means the area that must be monitored und er this regulation and is defined as equal to or greater than the area expected to contain the free phase CO 2 plume until the CO 2 plume has stabilized plus an all

- around buffer zone of at least one

- half mile. Research and development project means a projec t for the purpose of investigating practices, monitoring techniques, or injection verification, or engaging in other applied research, that will enable safe and effective long

- term containment of a
CO 2 stream in subsurface geologic formations, including re search and short duration CO 2 injection tests conducted as a precursor to long

- term storage.Page 40 of 40
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase. Surface leakage means the movement of the injected CO 2 stream from the injection zone to the surface, and into the atmosphere, indoor air, oceans, or surface water. Underground Injection Control permit means a permit issued under the authority of Part C of the Safe Drinking Wa ter Act at 42 U.S.C. 300h et seq . Underground Injection Control program means the program responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground for storage or disposal for purposes of protecting underground sources of drinking water from endangerment pursuant to Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et
seq . 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).