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Subpart RR—Geologic Sequestration of Carbon Dioxide

§ 98.440 Definition of the source category.

(a) The geologic sequestration of carbon dioxide (CO2) source category comprises any

well or group of wells that inject a CO2 stream for long-term containment in subsurface geologic 

formations.

(b) This source category includes all wells permitted as Class VI under the Underground 

Injection Control program.

(c) This source category does not include a well or group of wells where a CO2 stream is 

being injected in subsurface geologic formations to enhance the recovery of oil or natural gas 

unless one of the following applies:

(1) The owner or operator injects the CO2 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.

(2) The well is permitted as Class VI under the Underground Injection Control program.

(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.

(1) Process for obtaining an exemption. 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 

information to verify that the project is a research and development project.

(2) Content of submission. A submission in support of an exemption as a research and 

development project must contain the following information:
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(i) The planned duration of CO2 injection for the project.

(ii) The planned annual CO2 injection volumes during this time period.

(iii) The research purposes of the project.

(iv) The source and type of funding for the project.

(v) The class and duration of Underground Injection Control permit or, 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 definition 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 planned duration of CO2 injection for the project and the planned annual 

CO2 injection volumes during the duration of the project are consistent with the purpose of the 

research and development project.

(ii) Any appeal of the Administrator's determination is subject to the provisions of part 78 

of this chapter.

(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.

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

injects any amount of CO2 for long-term containment in subsurface geologic formations. There is 

no threshold.

(b) 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 the Administrator has issued a 

final decision on an owner or operator's request to discontinue reporting.

(1) Timing of request. 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.

(2) Content of request. A request for discontinuation of reporting must contain either 

paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(i) For wells permitted as Class VI under the Underground Injection Control program, a 

copy of the applicable Underground Injection Control program Director's authorization of site 

closure.

(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 CO2 stream is not expected to migrate in the future in a manner likely to 

result in surface leakage.

(3) Notification. The Administrator will issue a final decision on the request to 

discontinue reporting within a reasonable time. Any appeal of the Administrator's final decision 

is subject to the provisions of part 78 of this chapter.
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§ 98.442 GHGs to report.

You must report:

(a) Mass of CO2 received.

(b) Mass of CO2 injected into the subsurface.

(c) Mass of CO2 produced.

(d) Mass of CO2 emitted by surface leakage.

(e) Mass of CO2 emissions from equipment leaks and vented emissions of CO2 from 

surface equipment located between the injection flow meter and the injection wellhead.

(f) Mass of CO2 emissions from equipment leaks and vented emissions of CO2 from 

surface equipment located between the production flow meter and the production wellhead.

(g) Mass of CO2 sequestered in subsurface geologic formations.

(h) Cumulative mass of CO2 reported as sequestered in subsurface geologic formations in 

all years since the facility became subject to reporting requirements under this subpart.

§ 98.443 Calculating CO2 geologic sequestration.

You must calculate the mass of CO2 received using CO2 received equations (Equations 

RR-1 to RR-3 of this section), unless you follow the procedures in § 98.444(a)(4). You must 

calculate CO2 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 this section), and sequestration equations (Equations RR-11 and 

RR-12 of this section). For your first year of reporting, you must calculate CO2 sequestered 

starting from the date set forth in your approved MRV plan.
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(a) You must calculate and report the annual mass of CO2 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.

(1) For a mass flow meter, you must calculate the total annual mass of CO2 in a CO2

stream received in metric tons by multiplying the mass flow by the CO2 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 accordance with § 98.444.

where:

CO2T,r = Net annual mass of CO2 received through flow meter r (metric tons).

Qr,p = Quarterly mass flow through a receiving flow meter r in quarter p (metric 

tons).

Sr,p = 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).

CCO2,p,r = Quarterly CO2 concentration measurement in flow for flow meter r in quarter 

p (wt. percent CO2, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

(2) For a volumetric flow meter, you must calculate the total annual mass of CO2 in a 

CO2 stream received in metric tons by multiplying the volumetric flow at standard conditions by 

the CO2 concentration in the flow and the density of CO2 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.
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where:

CO2T,r = Net annual mass of CO2 received through flow meter r (metric tons).

Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at 

standard conditions (standard cubic meters).

Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered 

to another facility without being injected into your well in quarter p (standard 

cubic meters).

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 

0.0018682.

CCO2,p,r = Quarterly CO2 concentration measurement in flow for flow meter r in quarter 

p (vol. percent CO2, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

(3) If you receive CO2 through more than one flow meter, you must sum the mass of all 

CO2 received in accordance with the procedure specified in Equation RR-3 of this section.

where:

CO2 = Total net annual mass of CO2 received (metric tons).

CO2T,r = Net annual mass of CO2 received (metric tons) as calculated in Equation RR1 or RR-2 for flow meter r.

r = Receiving flow meter.

(b) You must calculate and report the annual mass of CO2 received in containers using 

the procedures in paragraphs (b)(1) or (b)(2) of this section.

(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 CO2 received for injection in containers using Equation 

RR-1 of this section.

where:
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CO2T,r = Net annual mass of CO2 received in containers r (metric tons).

CCO2,p,r = Quarterly CO2 concentration measurement of contents in containers r in 

quarter p (wt. percent CO2, expressed as a decimal fraction).

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

Sr,p = Quarterly volume of contents in containers r redelivered to another facility

without being injected into your well in quarter p (standard cubic meters).

p = Quarter of the year.

r = Containers.

(2) If you are measuring the volume of contents in a container under the provisions of § 

98.444(a)(2)(ii), you must calculate the CO2 received for injection in containers using Equation 

RR-2 of this section.

where:

CO2T,r = Net annual mass of CO2 received in containers r (metric tons).

CCO2,p,r = Quarterly CO2 concentration measurement of contents in containers r in 

quarter p (vol. percent CO2, expressed as a decimal fraction).

Qr,p = Quarterly volume of contents in containers r in quarter p (standard cubic

meters).

Sr,p = Quarterly mass of contents in containers r redelivered to another facility 

without being injected into your well in quarter p (metric tons).

D = Density of the CO2 received in containers at standard conditions (metric tons 

per standard cubic meter):0.0018682.

p = Quarter of the year.

r = Containers.

(c) You must report the annual mass of CO2 injected in accordance with the procedures 

specified in paragraphs (c)(1) through (c)(3) of this section.

(1) If you use a mass flow meter to measure the flow of an injected CO2 stream, you must 

calculate annually the total mass of CO2 (in metric tons) in the CO2 stream injected each year in 

metric tons by multiplying the mass flow by the CO2 concentration in the flow, according to 
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Equation RR-4 of this section. Mass flow and concentration data measurements must be made in 

accordance with § 98.444.

where:

CO2,u = Annual CO2 mass injected (metric tons) as measured by flow meter u.

Qp,u = Quarterly mass flow rate measurement for flow meter u in quarter p (metric 

tons per quarter).

CCO2,p,u = Quarterly CO2 concentration measurement in flow for flow meter u in quarter 

p (wt. percent CO2, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

(2) If you use a volumetric flow meter to measure the flow of an injected CO2 stream, 

you must calculate annually the total mass of CO2 (in metric tons) in the CO2 stream injected 

each year in metric tons by multiplying the volumetric flow at standard conditions by the CO2

concentration in the flow and the density of CO2 at standard conditions, according to Equation 

RR-5 of this section. Volumetric flow and concentration data measurements must be made in 

accordance with § 98.444.

where:

CO2,u = Annual CO2 mass injected (metric tons) as measured by flow meter u.

Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at 

standard conditions (standard cubic meters per quarter).

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 

0.0018682.

CCO2,p,u = CO2 concentration measurement in flow for flow meter u in quarter p (vol. 

percent CO2, expressed as a decimal fraction).
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p = Quarter of the year.

u = Flow meter.

(3) To aggregate injection data for all wells covered under this subpart, you must sum the 

mass of all CO2 injected through all injection wells in accordance with the procedure specified in 

Equation RR-6 of this section.

where:

CO2. = Total annual CO2 mass injected (metric tons) through all injection wells.

CO2,u = Annual CO2 mass injected (metric tons) as measured by flow meter u.

u = Flow meter.

(d) You must calculate the annual mass of CO2 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 account for any CO2 that is produced and not processed through a separator. 

You must account only for wells that produce the CO2 that was injected into the well or wells 

covered by this source category.

(1) For each gas-liquid separator for which flow is measured using a mass flow meter, 

you must calculate annually the total mass of CO2 produced from an oil or other fluid stream in 

metric tons that is separated from the fluid by multiplying the mass gas flow by the CO2

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.
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Where:

CO2,w = Annual CO2 mass produced (metric tons) through separator w.

Qp,w = Quarterly gas mass flow rate measurement for separator w in quarter p 

(metric tons).

CCO2,p,w = Quarterly CO2 concentration measurement in flow for separator w in quarter 

p (wt. percent CO2, expressed as a decimal fraction).

p = Quarter of the year.

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 CO2 produced from an oil or other fluid 

stream in metric tons that is separated from the fluid by multiplying the volumetric gas flow at 

standard conditions by the CO2 concentration in the gas flow and the density of CO2 at standard 

conditions, according to Equation RR-8 of this section. You must collect these data quarterly. 

Volumetric flow and concentration data measurements must be made in accordance with § 

98.444.

Where:

CO2,w = Annual CO2 mass produced (metric tons) through separator w.

Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at 

standard conditions (standard cubic meters).

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 

0.0018682.

CCO2,p,w = CO2 concentration measurement in flow for separator w in quarter p (vol. 

percent CO2, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.
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(3) To aggregate production data, you must sum the mass of all of the CO2 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 CO2 measured at the separator(s) represents a percentage 

of the total CO2 produced. In order to account for the percentage of CO2 produced that is 

estimated to remain with the produced oil or other fluid, you must multiply the quarterly mass of 

CO2 measured at the separator(s) by a percentage estimated using a methodology in your 

approved MRV plan. If fluids containing CO2 from injection wells covered under this source 

category are produced and not processed through a gas-liquid separator, the concentration of CO2

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 CO2 from 

produced fluids for the mass balance equation must be described in your approved MRV plan in 

accordance with § 98.448(a)(5).

Where:

CO2. = Total annual CO2 mass produced (metric tons) through all separators in the 

reporting year.

CO2,w = Annual CO2 mass produced (metric tons) through separator w in the reporting 

year.

X = 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).

w = Separator.

(e) You must report the annual mass of CO2 that is emitted by surface leakage in 

accordance with your approved MRV plan. You must calculate the total annual mass of CO2
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emitted from all leakage pathways in accordance with the procedure specified in Equation RR-10 

of this section.

where:

CO2. = Total annual CO2 mass emitted by surface leakage (metric tons) in the 

reporting year.

CO2,x = Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting 

year.

x = Leakage pathway.

(f) You must report the annual mass of CO2 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.

(1) If you are actively producing oil or natural gas or if you are producing any other 

fluids, you must calculate the annual mass of CO2 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:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric 

tons) at the facility in the reporting year.

CO2. = Total annual CO2 mass injected (metric tons) in the well or group of wells 

covered by this source category in the reporting year.

CO2P = Total annual CO2 mass produced (metric tons) in the reporting year.

CO2. = Total annual CO2 mass emitted (metric tons) by surface leakage in the 

reporting year.

CO2FI = Total annual CO2 mass emitted (metric tons) from equipment leaks and 

vented emissions of CO2 from equipment located on the surface between the 
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flow meter used to measure injection quantity and the injection wellhead, for 

which a calculation procedure is provided in subpart W of this part.

CO2FP = Total annual CO2 mass emitted (metric tons) 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, 

for which a calculation procedure is provided in subpart W of this part.

(2) If you are not actively producing oil or natural gas or any other fluids, you must 

calculate the annual mass of CO2 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:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric 

tons) at the facility in the reporting year.

CO2. = Total annual CO2 mass injected (metric tons) in the well or group of wells 

covered by this source category in the reporting year.

CO2. = Total annual CO2 mass emitted (metric tons) by surface leakage in the 

reporting year.

CO2FI = Total annual CO2 mass emitted (metric tons) 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, for 

which a calculation procedure is provided in subpart W of this part.

§ 98.444 Monitoring and QA/QC requirements.

(a) CO2 received. (1) Except as provided in paragraph (a)(4) of this section, you must 

determine the quarterly flow rate of CO2 received by pipeline by following the most appropriate 

of the following procedures:

(i) You may measure flow rate at the receiving custody transfer meter prior to any

subsequent processing operations at the facility and collect the flow rate quarterly.
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(ii) If you took ownership of the CO2 in a commercial transaction, you may use the 

quarterly flow rate data 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.

(iii) If you inject CO2 received from a production process unit that is part of your facility, 

you may use the quarterly CO2 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 CO2 being transported to an injection 

well to the same degree of accuracy as a meter used for commercial transactions.

(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 CO2 in containers by 

following the most appropriate of the following procedures:

(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 ownership of the CO2 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.

(3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly 

concentration of the CO2 received that is representative of all CO2 received in that quarter by 

following the most appropriate of the following procedures:

(i) You may sample the CO2 stream at least once per quarter at the point of receipt and 

measure its CO2 concentration.
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(ii) If you took ownership of the CO2 in a commercial transaction for which the sales 

contract was contingent on CO2 concentration, and if the supplier of the CO2 sampled the CO2

stream in a quarter and measured its concentration per the sales contract terms, you may use the 

CO2 concentration data from the sales contract for that quarter.

(iii) If you inject CO2 from a production process unit that is part of your facility, you may

report the quarterly CO2 concentration of the CO2 stream supplied that was measured following 

the procedures provided in subpart PP of this part.

(4) If the CO2 you receive is wholly injected and is not mixed with any other supply of 

CO2, you may report the annual mass of CO2 injected that you determined following the 

requirements under paragraph (b) of this section as the total annual mass of CO2 received instead 

of using Equation RR-1 or RR-2 of this subpart to calculate CO2 received.

(5) You must assume that the CO2 you receive meets the definition of a CO2 stream 

unless you can trace it through written records to a source other than a CO2 stream.

(b) CO2 injected. (1) You must select a point or points of measurement at which the CO2

stream(s) is representative of the CO2 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 provisions in your Underground Injection Control permit.

(2) You must measure flow rate of CO2 injected with a flow meter and collect the flow 

rate quarterly.

(3) You must sample the injected CO2 stream at least once per quarter immediately 

upstream or downstream of the flow meter used to measure flow rate of that CO2 stream and 

measure the CO2 concentration of the sample.
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(c) CO2 produced. (1) The point of measurement for the quantity of CO2 produced 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) You must sample the produced gas stream at least once per quarter immediately 

upstream or downstream of the flow meter used to measure flow rate of that gas stream and 

measure the CO2 concentration of the sample.

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

rate quarterly.

(d) CO2 emissions from equipment leaks and vented emissions of CO2. 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.

(e) Measurement devices. (1) All flow meters must be operated continuously except as 

necessary for maintenance and calibration.

(2) You must calibrate all flow meters used to measure quantities reported in § 98.446 

according to the calibration and accuracy requirements in § 98.3(i).

(3) You must operate all measurement devices 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. 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 
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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 performed are National Institute of 

Standards and Technology (NIST) traceable.

(f) General. (1) If you measure the concentration of any CO2 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) You must convert all measured volumes of CO2 to the following standard industry

temperature and pressure conditions for use in Equations 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.

(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available 

monitoring methods 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.

§ 98.445 Procedures for estimating missing data.

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:

(a) A quarterly flow rate of CO2 received that is missing must be estimated as follows:

(1) Another calculation methodology listed in § 98.444(a)(1) must be used if possible.
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(2) If another method listed in § 98.444(a)(1) cannot be used, a quarterly flow rate value 

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 methodology listed in § 98.444(a)(2) must be used if possible.

(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 previous time period.

(c) A quarterly CO2 concentration of a CO2 stream received that is missing must be 

estimated as follows:

(1) Another calculation methodology listed in § 98.444(a)(3) must be used if possible.

(2) If another method listed in § 98.444(a)(3) cannot 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 CO2 injected that is missing must be estimated using a 

representative quantity of CO2 injected from the nearest previous period of time at a similar 

injection pressure.

(e) For any values associated with CO2 emissions from equipment leaks and vented 

emissions of CO2 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.
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(f) The quarterly quantity of CO2 produced from subsurface geologic formations that is 

missing must be estimated using a representative quantity of CO2 produced from the nearest 

previous period of time.

(g) You must estimate the mass of CO2 emitted by surface leakage that is missing as 

required by your approved MRV plan.

(h) You must estimate other missing data as required by your approved MRV plan.

§ 98.446 Data reporting requirements.

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.
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(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.
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(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.
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(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.
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(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.
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(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.
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(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.

(g) Whether the CO2 stream is being injected into subsurface geologic formations to 

enhance the recovery of oil or natural gas.

§ 98.447 Records that must be retained.

(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 records specified in paragraphs (a)(1) 

through (7) of this section, as applicable. You must retain all required records for at least 3 years.

(1) Quarterly records of CO2 received, including mass flow rate of contents of containers 

(mass or volumetric) at standard conditions and operating conditions, operating temperature and 

pressure, and concentration of these streams.

(2) Quarterly records of produced CO2, including mass flow or volumetric flow at 

standard conditions and operating conditions, operating temperature and pressure, and 

concentration of these streams.

(3) Quarterly records of injected CO2 including mass flow or volumetric flow at standard 

conditions and operating conditions, operating temperature and pressure, and concentration of 

these streams.

(4) Annual records of information used to calculate the CO2 emitted by surface leakage 

from leakage pathways.

(5) Annual records of information used to calculate the CO2 emitted 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.
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(6) Annual records of information used to calculate the CO2 emitted 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.

(7) Any other records as specified for retention in your EPA-approved MRV plan.

(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of 

the year you begin collecting data.

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

(a) Contents of MRV plan. 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:

(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.

(2) Identification of potential surface leakage pathways for CO2 in the maximum 

monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO2 through 

these pathways.

(3) A strategy for detecting and quantifying any surface leakage of CO2.

(4) A strategy for establishing the expected baselines for monitoring CO2 surface leakage.

(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 

CO2 emissions from equipment leaks and vented emissions of CO2 between the injection flow 
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meter and injection well and/or the production flow meter and production well, and 

considerations for calculating CO2 in produced fluids.

(6) If a well is permitted under the Underground Injection Control program, for each 

injection 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 the 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 authorizing 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 Drinking Water Act, and are submitting your application for the legal instrument 

authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA 

when the legal instrument authorizing geologic sequestration has been approved.

(7) Proposed 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 detection and 

quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial 

AMA.

(b) Timing. You must submit a proposed MRV plan to EPA according to the following 

schedule:

(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 CO2 into the subsurface 
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on or before December 31, 2010. You will be allowed to request one extension of up to an 

additional 180 days in which to submit your proposed MRV plan.

(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 CO2 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 geologic 

sequestration of CO2. You will be allowed to request one extension of the submittal date of up to 

an additional 180 days.

(3) If you are injecting a CO2 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.

(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.

(c) Final MRV plan. 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.

(d) MRV plan revisions. 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) through (d)(4) of this 

section applies. You must include the reason(s) for the revisions in your submittal.

(1) A material change was made to monitoring and/or operational parameters that was not 

anticipated in the original MRV plan. Examples of material changes include but are not limited 
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to: Large changes in the volume of CO2 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 baseline; 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 monitoring area; or a change in monitoring technology that would result in coverage or 

detection capability different from the MRV plan.

(2) A change in the permit class of your Underground Injection Control permit.

(3) If you are notified by EPA of substantive errors 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. The requirements of paragraph (c) of this section apply to any 

submission of a revised MRV plan. You must continue reporting under your currently approved 

plan while awaiting approval of a revised MRV plan.

(f) Format. Each proposed MRV plan or revision and each annual report must be 

submitted electronically in a format specified by the Administrator.

(g) Certificate 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.

§ 98.449 Definitions.

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.
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Active monitoring area 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:

(1) The area projected to contain the free phase CO2 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) The area projected to contain the free phase CO2 plume at the end of year t+5.

CO2 received means the CO2 stream that you receive to be injected for the first time into 

a well on your facility that is covered by this subpart. CO2 received includes, but is not limited 

to, a CO2 stream from a production process unit inside your facility and a CO2 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 through 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 under this regulation 

and is defined as equal to or greater than the area expected to contain the free phase CO2 plume 

until the CO2 plume has stabilized plus an all-around buffer zone of at least one-half mile.

Research and development project means a project 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 CO2 stream in subsurface geologic 
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formations, including research and short duration CO2 injection tests conducted as a precursor to 

long-term storage.

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 CO2 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 Water 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 CH4 or CO2 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).
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