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 CO2

(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 CO2

(1) The owner or operator injects the 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 Underground 

Injection Control program.

stream for longterm 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 information 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

injection 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 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 

. 
Page 3 of 40

planned duration of CO2 injection for the project and the planned 

annual CO2

(ii) Any appeal of the Administrator's determination is 

subject to the provisions 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 longterm 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 the 
Page 4 of 40

Administrator has issued a final decision on an owner or 

operator's request to discontinue 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 program 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 CO2

(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 Administrator'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 CO2

(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 CO2

(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 CO2

(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 CO2

You must calculate the mass of CO

geologic sequestration.

2 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 
Page 6 of 40

equations (Equations RR–11 and RR–12 of this section). For your 

first year of reporting, you must calculate CO2

(a) You must calculate and report the annual 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 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:

CO2 T,r = Net annual mass of CO2

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 =

CCO

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 CO2 concentration measurement in flow 

for flow meter r in quarter p (wt. percent CO2

p = Quarter of 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 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.

Where:

CO2 T,r = Net annual mass of CO2

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 receiving 

flow meter r that is redelivered to another 

facility without being injected into your well 

in quarter p (standard cubic meters).

2

CCO

at standard conditions (metric 

tons per standard cubic meter): 0.0018682.

2,p,r = Quarterly CO2 concentration measurement in flow 

for flow meter r in quarter p (vol. percent 

CO2

p = Quarter of the year.

, expressed as a decimal fraction).

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.
Page 8 of 40

Where:

CO2 = Total net annual mass of CO2

CO

received (metric 

tons).

2 T,r = Net annual mass of CO2

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 CO2

(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.

CO2 T,r = Net annual mass of CO2

CCO

received in containers r 

(metric tons).

2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (wt. 

percent CO2

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 must 
Page 9 of 40

calculate the CO2

Where:

received for injection in containers using 

Equation RR–2 of this section.

CO2 T,r = Net annual mass of CO2

CCO

received in containers r 

(metric tons).

2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (vol. 

percent CO2

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 massvolume of contents in containers 

r redelivered to another facility without 

being injected into your well in quarter p 

(metric tonsstandard 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 CO2

(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 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 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:

CO2,u = Annual CO2

Q

mass injected (metric tons) as 

measured by flow meter u.

p,u

CCO

= Quarterly mass flow rate measurement for flow 

meter u in quarter p (metric tons per 

quarter).

2,p,u = Quarterly CO2 concentration measurement in flow 

for flow meter u in quarter p (wt. percent CO2

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 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

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 CO2

CCO

at standard conditions (metric 

tons per standard cubic meter): 0.0018682.

2,p,u = CO2 concentration measurement in flow for flow 

meter u in quarter p (vol. percent CO2

p = Quarter of the year.

,

expressed as a decimal fraction).

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 I = Total annual CO2

CO

mass injected (metric tons) 

through all injection wells.

2,u = Annual CO2

u = Flow meter.

mass injected (metric tons) as 

measured by flow meter u.

(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.
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 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.

Where:

CO2,w = Annual CO2

Q

mass produced (metric tons) through 

separator w.

p,w

CCO

= Quarterly gas mass flow rate measurement for 

separator w in quarter p (metric tons).

2,p,w = Quarterly CO2 concentration measurement in flow 

for separator w in quarter p (wt. percent CO2

p = Quarter of the year.

,

expressed as a decimal 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 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. 
Page 13 of 40

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

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 standard 

conditions (standard cubic meters).

2

CCO

at standard conditions (metric 

tons per standard cubic meter): 0.0018682.

2,p,w = CO2 concentration measurement in flow for 

separator w in quarter p (vol. percent CO2

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 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 
Page 14 of 40

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(da)(5).

Where:

CO2 P = Total annual CO2

CO

mass produced (metric tons) 

through all separators in the reporting year.

2,w = Annual CO2

X = Entrained CO

mass produced (metric tons) through 

separator w in the reporting year.

2 in produced oil or other fluid 

divided by the CO2 separated through all 

separators in the reporting year (weight 

percent CO2

w = Separator.

, expressed as a decimal fraction).

(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 emitted from all 

leakage pathways in accordance with the procedure specified in 

Equation RR–10 of this section.

Where:
Page 15 of 40

CO2 E = Total annual CO2

CO

mass emitted by surface 

leakage (metric tons) in the reporting year.

2,x = Annual CO2

x = Leakage pathway.

mass emitted (metric tons) at 

leakage pathway x in the reporting year.

(f) You must report the annual mass of CO2

(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 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:

CO2 = Total annual CO2

CO

mass sequestered in subsurface 

geologic formations (metric tons) at the 

facility in the reporting year.

2 I = Total annual CO2

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 CO2

CO

mass produced (metric tons) in 

the reporting year.

2 E = Total annual CO2

CO

mass emitted (metric tons) by 

surface leakage in the reporting year.

2 FI = 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, 
Page 16 of 40

for which a calculation procedure is provided 

in subpart W of this part.

CO2 FP = Total annual CO2 mass emitted (metric tons) 

from equipment leaks and vented emissions of 

CO2

(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 part.

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:

CO2 = Total annual CO2

CO

mass sequestered in subsurface 

geologic formations (metric tons) at the 

facility in the reporting year.

2 I = Total annual CO2

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 CO2

CO

mass emitted (metric tons) by 

surface leakage in the reporting year.

2 FI = 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.

(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 CO2

(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.

received by 

pipeline by following the most appropriate of the following 

procedures:

(ii) If you took ownership of the CO2

(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-time 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 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

(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 degree of accuracy as a meter used 

for commercial transactions.

2 in containers by following the 

most appropriate 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 ownership of the CO2

(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 CO2

(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 CO2

(ii) If you took ownership of the CO

concentration.

2 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

(iii) If you inject CO

concentration data from the 

sales contract for that quarter.

2 from a production process unit that 

is part of your facility, you may report the quarterly CO2
Page 19 of 40

concentration of the CO2

(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 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

(5) You must assume that the CO

received.

2 you receive meets the 

definition of a CO2 stream unless you can trace it through 

written records to a source other than a CO2

(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 CO2

(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 provisions 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 CO2 stream and measure the CO2

concentration of the sample.
Page 20 of 40

(c) CO2

(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 downstream of the flow meter 

used to measure flow rate of that gas stream and measure the CO

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

(3) You must measure flow rate of gas produced with a flow 

meter and collect the flow rate quarterly.

concentration of the sample.

(d) CO2 emissions from equipment leaks and vented emissions 

of CO2

(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 calibrate 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 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 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 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 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.
Page 22 of 40

(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.

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 CO2

(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 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.
Page 23 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 previous time period.

(c) A quarterly CO2 concentration of a CO2

(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) 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

(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 CO2

(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 a 
Page 24 of 40

representative quantity of CO2

(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 CO2

(1) The 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 

standard 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 CO2 concentration in the flow (volume percent CO2

expressed as a decimal fraction) in each quarter.
Page 25 of 40

(3) If a mass flow meter is used to receive CO2

(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 CO2 concentration in the flow (weight percent CO2

(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 CO2

(5) The standard or method used to calculate 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) Whether the flow meter is mass or volumetric.

(8) A numerical identifier for the flow meter.

(b) If you receive CO2

(1) The mass (in metric tons) or volume at standard 

conditions (in standard cubic meters) of contents in containers 

received in each quarter.

in containers, report:
Page 26 of 40

(2) The concentration of CO2 of contents in containers 

(volume or wt. percent CO2

(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.

expressed as a decimal fraction) in 

each quarter.

(4) The net mass of CO2

(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 CO2

(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 processing.

(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 CO2

(ii) The CO

injected (metric tons) annually.

2 concentration in flow (volume or weight percent 

CO2

(iii) If a volumetric flow meter is used, 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 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.
Page 28 of 40

(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

(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 CO2

(i) The mass of CO

, report the following:

2 emitted (in metric tons) annually from 

equipment leaks and vented emissions of CO2

(ii) The mass of CO

from equipment 

located on the surface between the flow meter used to measure 

injection quantity and the injection wellhead.

2 emitted (in metric tons) annually from 

equipment leaks and vented emissions of CO2

(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) CO2

(ii) CO

mass produced (metric tons) annually.

2 concentration in flow (volume or weight percent CO2

expressed as a decimal fraction) in each quarter.
Page 29 of 40

(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

(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 CO2

(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 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).
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 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

(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 records 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 CO2

(2) Quarterly records of produced CO

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

(3) Quarterly records of injected CO

, including mass flow 

or volumetric flow at standard conditions and operating 

conditions, operating temperature 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 CO2

(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 CO2

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

EPA-approved MRV plan.

from 

equipment located on the surface between 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 year 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 surface leakage pathways 

for CO2 in the maximum monitoring area and the likelihood, 

magnitude, and timing, of surface leakage of CO2

(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 CO2 emissions from equipment leaks and vented 

emissions of CO2 between the injection flow meter and injection 

well and/or the production flow meter and production well, and 

considerations for calculating CO2

(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 

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) 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

(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 submit 

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 geologic 
Page 36 of 40

sequestration of CO2

(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 changes 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) through (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 CO2

(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 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.

(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

(f) 

. 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.

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) 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.

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.

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 
Page 39 of 40

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 formations, including research 

and short duration CO2 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 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).